WELLBORE CEMENTING TOOL HAVING ONE WAY FLOW

Abstract

A stage tool for reverse annular cementing a wellbore, comprising: a main body including a tubular wall with an outer surface and a longitudinal bore extending from a top end to a bottom end; a fluid port through the tubular wall providing fluidic access between the longitudinal bore and the outer surface; and a valve for controlling flow through the fluid port between the outer surface and the inner bore, the valve including a closure for the fluid port and a check valve for permitting one way flow through the fluid 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. The stage tool may be run in closed and opened for cementing by hydraulic actuation of 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. 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 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 of the present invention, there is provided a wellbore assembly including: a tubular string having an upper end, a lower end, a tubular wall, an inner bore within the tubular wall and an outer surface; a packer encircling the outer surface and spaced from the upper end; a fluid port through the tubular wall providing fluidic access between the inner bore and the outer surface; and a valve for controlling flow through the fluid port between the outer surface and the inner bore, the valve permitting only one way flow through the fluid port in a direction from the outer surface to the inner bore.

In accordance with another broad aspect, there is provided a method for cementing a tubing string in a wellbore, the wellbore having a heel transitioning from a substantially vertical section to a substantially horizontal section, the method comprising: running into a wellbore toward bottom hole with a tubing string to a position in the wellbore, an annulus being defined between the tubing string and the wellbore wall; opening a circulation path from the annulus into the tubing string; introducing cement to the annulus to flow down to at least the heel; and closing the circulation path 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 for wellbore annular cementing, comprising: a main body including a tubular wall with an outer surface and a longitudinal bore extending from a top end to a bottom end; a fluid port through the tubular wall providing fluidic access between the longitudinal bore and the outer surface; and a valve for controlling flow through the fluid port between the outer surface and the inner bore, the valve including a closure for the fluid port and a check valve for permitting one way flow through the fluid 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.

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:

FIGS. 1A and 1B are a schematic sectional views through a wellbore with a tubing string installed therein;

FIGS. 2A to 2D 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 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 and FIG. 2D is an axial sectional view of the stage tool of FIG. 2A in a closed position, 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 through a wall of the 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 to be opened for cement circulation through the annulus, FIG. 3C is an axial sectional view of the stage tool of FIG. 3A in an open position for circulation therethrough to permit cementing through the annulus, FIG. 3D is an axial sectional view of the stage tool of FIG. 3A in a position closed by a check valve after dissipation of circulation pressure, and FIG. 3E is an axial sectional view of the stage tool of FIG. 3A in a final closed position, closing against cement circulation.

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, for example, as shown in FIGS. 1A and 1B, generally a surface hole is drilled and surface casing 200 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 201 may be drilled below the surface casing point 200a to reach a formation of interest 203. Sometimes further casing is installed below the surface casing. Where operations are to be conducted using a liner 204, the liner can extend from a point above the lower most casing point, in this case casing point 200a with an active, lower portion of the liner extending out beyond casing point 200a 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 204 to be supported in an extended wellbore 201 by stage cementing below any casing point 200a, 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 204 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 210, which separates the string into an upper portion 204b, 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 one embodiment, FIG. 1A, stage tool 210 is positioned near the end of the liner in the toe of the well, with the upper portion of the string above the stage tool containing active components. In another embodiment, FIG. 1B, stage tool 210 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 208a, 208b, etc. of the liner.

Cement C may be introduced into the annulus 250 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 201a. 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 208a, multistage fracturing components such as sleeve valves, hydraulic ports 208b (i.e. fracing ports) and packers 208c′, 208c for zone isolation, a blow out plug 208d, etc. Various of these components are described in others of applicant's patents such as U.S. Pat. No. 6,907,936, issued Jun. 21, 2005 and U.S. Pat. No. 7,108,067, issued Sep. 19, 2006.

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 204 including below stage tool 210, 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 208a and/or packers 208c, 208c′ 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 2009/132462, published Nov. 5, 2009.

In some frac operations, packers 208c, 208c′ 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 208c′ 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 210 is positioned downhole of uppermost packer 208c′, as shown in FIG. 1A, 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 210 includes one or more ports 222 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 204b from annulus 250.

After the stage tool's circulation ports are opened, cement may be pumped by fluid circulation as provided through ports 222. In the illustrated embodiment, cement is pumped from above down through the annulus 250 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 200a to the stage tool, to the uppermost packer 208c′ or having passed all the way to stage tool and perhaps even through ports 222 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 222.

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 222 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. Pressuring up may include launching a ball to land in a seat to create a pressure-drivable piston in the string. Pressuring up may include landing a ball in a seat to move a component of the valve.

In one embodiment, holding the cement in the annulus includes actuating 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 pressuring up on the inner diameter of the string. In another 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.

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.

In one embodiment, the valve may include a closure that can be closed to seal the cement in the annulus.

Referring to FIGS. 2A to 2D, a stage tool 310 for use to stage cement a wellbore liner is shown. The stage tool may be installed in a tubular string. Stage tool 310 may include a tubular body including a wall 311 with an outer surface 312, an inner bore 314 defined by an inner surface 316 of the wall, a first end 318 and a second end 320. A port 322 extends through the wall and is openable (FIG. 2C) and closable (FIGS. 2A, 2B and 2D) to open and close, respectively, the stage tool to circulation from the outer surface to the inner bore.

Stage tool 310 may be intended for use in wellbore applications for actuation to permit cementing of a section of the annulus behind a borehole liner through ports in the liner wall along a length of the liner. 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 314 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 318, 320 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 sleeve 324 is positioned to act as a closure for port 322 and is moveable relative to the port to manipulate it between the open and the closed positions. Sleeve 324 may carry (as shown) or ride over seals 323 that provide a pressure seal between sleeve 324 and inner surface 316 of the wall. Sleeve 324 may be moved by fluid pressure to open and close, which avoids the need to run in a manipulation string or line.

Stage tool 310 further includes one or more check valves to control fluid flow through bore 314 between ends 318, 320. In the illustrated embodiment, there are two check valves 326, 328, one positioned below ports 322 and one positioned above ports 322. The first check valve 326 is configured to allow fluid flow down through bore 314 from end 318 to end 320, but stops reverse flow therethrough. This check valve allows circulation down through the string but acts as a float in the string to prevent backflow from the wellbore into the liner to facilitate liner installation and tubing control. The other check valve 328 is configured to act in an opposite fashion to valve 326. In particular, fluid can pass through valve 328 upwardly, for example through the bore from end 320 to end 318, but valve 328 resists reverse flow (downwardly) through the stage tool. This check valve permits the formation of a piston face and allows pressure actuation of components of the stage tool, remotely without running in any tools. Thus, valve 326 holds pressure from below and valve 328 holds pressure from above. While other types of check valves are useful as well, the illustrated check valves are poppet style, normally closed, spring-biased valves each including a poppet biased by a spring against a seat.

Valve 328 cannot act on fluid flows until it is activated to do so. For example, a bypass is provided around valve 328 so that fluid can be pumped down the string and through bore 314 from end 318 to end 320, for example to permit circulation during run in. In this embodiment, valve 328 is installed in an inner diameter 329 of an inner tube 330 and an annular space 332 is opened between inner wall surface 316 and the inner tube, which forms a bypass around the valve. When the bypass is open through annular space 332, fluid can flow therethrough and avoid valve 328. If the bypass is closed, fluid flows are controlled by valve 328 and, for example, are prevented from flowing down through the tool.

A mechanism can be provided to actuate the bypass from an open to a closed position when it is desired to expose the tubing string to the effect of valve 328. In one embodiment, actuation can be made remotely from surface operations. For example, in the illustrated embodiment, the mechanism for closing the bypass is operated by landing a ball 336 (FIG. 2B) thereon and pressuring up behind the ball to cause the mechanism to shift from an open bypass to a closed bypass. In this embodiment, for example, the mechanism for closing the bypass includes a plurality of shiftable members that in one arrangement provide open access through the path through bypass and can be shifted by force applied by landing ball to close the bypass. This may include installing inner tube 330 to be axially movable within the housing and with openings 338 to annular space 332 at the upper end of inner tube and openings 340 from annular space at the bottom end of the inner tube, which openings can be closed by axially moving the inner tube by landing ball 336 to generate a piston face through which fluid pressure can act to apply force.

In one example, a shiftable member 334 is positioned in an axially moveable fashion in housing above inner tube 330 and includes a ball seat 342 on its upper surface, a nipple 344 at its lower surface and a fluid channel 346 that extends from the ball seat 342 to open at the end of the nipple. While fluid channel is normally open to fluid flow from ball seat and out through nipple 344, it can be closed by landing ball 336 in the seat. This creates a piston face across the shiftable member and the ball seated therein and allows fluid pressure to act to move the shiftable member. When the bypass is open, shiftable member 334 is spaced above tube 330 and forms a gap between the nipple and the tube that creates opening 338. To close the bypass, shiftable member 334 can be shifted to insert nipple 344 into the inner diameter 329 of the inner tube, which closes access from channel 346 to the annular space 332 and instead opens channel 346 directly into the inner diameter of the inner tube. Seals 348 may be provided between the tube and the nipple to resist leakage between channel 346/inner diameter 329 and annular space 332. If desired, a stop 350 may be provided to limit the axial movement of the shiftable member. A lock, such as a ratcheted surface 351a, 351b may be provided such that shiftable member 334 cannot move back up once it has shifted down.

While sleeve 324 may be moveable by various means, in one embodiment as illustrated, the closing mechanism for the bypass can be linked to the movement of sleeve 324. In this embodiment, the closing of the bypass simultaneously moves sleeve 324 to open ports 322 to communication to inner bore 314. For example, inner tube 330 may be connected at its bottom end to sleeve 324 and movement of tube 330 is communicated to the sleeve to likewise cause movement thereof. The inner tube may be configured, for example, such that when shiftable member 334 lands against and causes tube 330 to move down, this movement, in addition to closing the bypass through space 332, drives the tube 330 against sleeve 324 and causes the sleeve to move to open port 322.

In one embodiment, however, it may be useful to secure the inner tube releasably to sleeve 324, such that the parts can be disengaged from simultaneous movement with each other, when it is appropriate to do so. For example, in one embodiment, communication between valve 328 and ports 322 may be closed by movement of tube 330 to close openings 340 while sleeve 324 remains stationary. Movement of tube 330 may be by application of fluid pressure through bore 314 from surface back against valve 328, which closes valve 328 and generates a piston effect across the valve to move tube 330. Meanwhile, sleeve 324 can be stopped against a stop 352 such that tube 330 moves relative to the sleeve to overlap or further overlap with the sleeve such that any openings 340 therebetween are closed. The tube and the sleeve may be secured together by a frictional member such as close fitting surface or shear pins such that while the tube and the sleeve initially move together, they can be separated for independent movement. A stop 356 may be provided to limit the degree of overlap that can be achieved between tube 330 and sleeve 324. Seals 354 may be provided to seal against leakage between the parts.

Having thus described the components of the example stage tool 310, the operation of that stage tool will be described. Stage tool 310 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-open position (FIG. 2C) and a third, cement port-closed position (FIG. 2D).

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 a condition shown in FIG. 2C for stage cementing. Stage tool 310 allows cement to be introduced through the annulus and allows reverse circulation of annular fluids from the annulus into the tubing string though inner bore 314 and then back up toward surface. After the introduction of cement to an annulus 250 formed between the tool and the wellbore wall down to a selected level, the tool may be manipulated to a condition shown in FIG. 2D to close off communication between the annulus and the inner bore of the tool.

In summary, the stage tool, installed in a tubing string, is run into the wellbore with the port closed by a removable closure, in this embodiment sleeve 324. Once in position, port 322 is opened, as by hydraulic actuation of the removable closure, to provide fluid communication between the annulus about the tool and inner bore 314. The stage tool can be located at various positions along the tubing string, for example, most often near the distal end, below any packers or frac ports (such as shown in FIG. 1A) or sometimes just above an uppermost packer on a treatment string (such as shown in FIG. 1B) or anywhere in between, such that annulus 250 can be cemented between the upper end of the string and the location of stage tool for example, in one embodiment, from the upper end of the string down to 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 322 and into inner bore 314. When sufficient cement is introduced to fill the annulus along a selected length, the ports are closed to stop circulation from the annulus into bore 314. 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 314.

For use, the stage tool may be installed in a tubing string. For example, tool 310 is installed in a tubular string with its inner bore 314 in communication with the inner diameter of the tubing string. The tool will be run into the wellbore with ports 322 closed. Once in position, the process to set the tubing string in the hole is initiated. FIG. 2A shows the position of the components of stage tool 310 during run in and immediately after the string is in position in the well. Bypass through space 332 is open such that valve 328 has no effect on the flow of fluids through the stage tool. To facilitate run in, fluid can be circulated, arrows R, down through the string into bore 314, through channel 346, opening 338, space 332 and openings 340 to valve 326. Although valve 326 is normally closed, circulation pressures are sufficient to open valve 326 and fluid can pass through the stage tool to lower parts of the string. This fluid communication can be used to clean and condition the well, facilitate advancement of the string and/or set tools such as packers 208c. Valve 326 also permits the string to be floated into the well.

When it is desired to begin stage cementing, sleeve 324 can be moved to open ports 322. To move the sleeve, ball 336 can be launched (FIG. 2B) to land on seat 342. This converts shiftable member 334 to a piston form and pressure P can be applied to force the shiftable member down. As shiftable member 334 is moved, sleeve 324, which is attached, also moves to expose ports 322 to inner bore 314 (FIG. 2C). The movement of shiftable member 334 is stopped when it contacts stop 350. Also at this point locking surfaces 351a, 351b lock up to resist reverse movement of shiftable member. Movement of shiftable member 334 also closes the bypass through space 332 such that all fluid flow between ports 322 and upper end 318 must pass through valve 328. The bypass is closed when the pressure pushes shiftable member 334 to close opening 338. In particular, nipple 344 is pushed into the upper end of inner tube 330 and against the seals 348.

Once ports 322 are opened cement can be pumped down the annulus 250, arrows C. The fluid that is in the annulus 250 in front of the cement displaces while the cement is being pumped down the annulus (FIG. 2C). When the fluid circulates into the stage tool, the fluid moves past the check valve 328 and is returned toward surface through the liner. Ball 336 is moved with the circulating fluid and is removed from seat 342. Valve 328 opens to allow circulation from the space between the valves and valve remains closed, as the pressure is equalized about it. Once the correct amount of cement is pumped down the annulus, pressure may be applied to the tubing above shiftable member 334, which closes check valve 328 and converts inner tube 330 and valve 328 therein to a piston. Check valve 328, being closed, permits the development of a force by fluid pressure that pushes the inner tube 330 down closing openings 340 (FIG. 2D). In particular, while shiftable member 334 and sleeve 324 are stopped against their stops 350 and 352, respectively, inner tube 330 remains connected to, but axially moveable between, shiftable member 334 and sleeve 324. Thus, when valve 328 is closed and inner tube 330 acts as a piston, the inner tube may be driven axially down and, while remaining sealed with shiftable member 334, may be telescopically driven into sleeve 324, until openings 340 and seals 354 overlap, and become sealed against, the sleeve.

After closing openings 340, the fluid, including cement in the annulus, is now trapped from moving in either direction past the stage tool. The cement will then set to cement the annulus. In the method, to facilitate reentry and/or fluid communication past tool 310, the process is controlled to prevent cement from actually entering the tubing string. There will be non-cementious liquid moving ahead of the cement, for example, simply the amount of residual liquid in the well. In addition, an introduced plug of liquid may be pumped ahead of the cement. The leading plug may, for example, include mud, water, etc. The volumes pumped may be selected such that, the cement is introduced down to a selected point in the well and it is likely that any fluid entering the string may be devoid of settable cement.

The process to set the tubing string in the well may further include setting of packers, slips, etc. Since the placement of cement in the annulus requires annular flow to the stage tool, the timing of the setting of the packers may depend on the location of the stage tool: whether the stage tool is positioned uphole or downhole from the packers. If the stage tool is positioned uphole of the packers, the packers may be set before or after placement of the cement. If no annular flow can be achieved past the packers and the stage tool is positioned downhole of the packers, the packers may be set after placement of the cement.

After the cement is installed and set, wellbore operations may proceed. For example, wellbore operations may include wellbore fluid treatments such as stimulation including fracturing. For example, fluid treatment ports may be opened 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. During fracturing fluids under pressure may be introduced through the tubing string, and injecting the fluids under pressure out from the tubing string through ports. In some instances, string manipulations may be conducted including pressuring up the string inner bore. In some instances, tools, free or connected to strings, must be passed through the string inner bore. As will be appreciated, then, depending on the location of the stage tool some wellbore operations may require access past the stage tool. In some embodiments, therefore, the string may be milled out to ensure full bore access through the string. However, if the stage tool is positioned downhole of liner components used in these wellbore processes, such milling may not be required.

Referring to FIGS. 3A to 3D, another stage tool 410 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 one way check valve over a port, used to open the port to fluid flow therethrough in response to reverse circulation, a releasable lock that holds the one-way check valve in an inoperable position until activated, and a 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, a one way check valve over the port such as a spring loaded sleeve, used to open the port to fluid flow therethrough in response to reverse circulation (from the outer surface to the inner diameter), a hydraulic actuating sleeve to initially releasably lock the check valve in the closed position but hydraulically actuable to release the check valve for operation, and a hydraulic closing sleeve operable to close the port by pressure actuation thereof.

Stage tool 410 may include a tubular body including a wall 411 with an outer surface 412, an inner bore 414 defined by an inner surface 416 of the wall, a first end 418 and a second end 420. A port 422 extends through the wall and is openable (FIG. 3C) and closable (FIGS. 3A, 3B, 3D and 3E) to open and close, respectively, the stage tool to circulation from the outer surface to the inner bore.

Stage tool 410 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 414 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 418, 420 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 sleeve 424 is positioned to act as a closure for port 422 and is moveable relative to the port to manipulate it between the open and the closed positions. Sleeve 424 may carry or ride over seals 423 that provide a pressure seal between sleeve 424 and the wall to seal against migration of fluid through port 422 past the sleeve.

Sleeve 424 acts as a one way check valve and may be moved by fluid pressure to open and close, which avoids the need to run in a manipulation string or line to open or close it. Sleeve 424 includes a biasing spring 428 such that it is normally in a position closing port 422, but can be opened by when the annular pressure P1 is greater than the tubing pressure P2. Thus, sleeve 424 may be opened by reverse flow from the annulus to the tubing string such that fluid can pass through port 422 inwardly from annulus 250 to inner bore 414, with sleeve 424 acting as a one way check valve and resisting flow outwardly through the ports of the stage tool.

Sleeve 424 is normally inactive, for example, during run in of the tool such that it is not effected by pressure differentials. However, the valving operation of sleeve 424 may be activated when its operation is required. For example, sleeve 424 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, a lock sleeve 430 is provided for sleeve 424. The lock sleeve normally holds sleeve 424 in a position closing port 422, but movement of the lock sleeve can release sleeve 424 for check valve operation. Lock sleeve 430 for example, can hold, as by overlying, a lock protrusion 431 (i.e. pin, ball or ring) in a lock notch 432 of sleeve 424, but can be moved to release the protrusion from the notch and thereby allow movement of the sleeve 424. Lock sleeve 430, for example, may include a recess 436 normally offset from protrusion 431 but moveable with sleeve 430 into alignment with the protrusion. Lock sleeve 430 may be responsive to pressure conditions in inner bore 414 of the stage tool. For example, lock sleeve 430 may include a piston face 430a acting between tubing pressure P2 and annulus pressure P1 through port 433 and chamber 434 and can be moved when P2 is greater than P1 sufficient to overcome the holding force of a shear pin 435.

Lock sleeve 430 may include seals 438 to ensure that pressure differentials are sensed across face 430a and to prevent fluid leakage between outer surface 412 and bore 414. A locking structure such as a snap ring 440 may be provided to resist further movement of the lock sleeve, such as when P1 becomes greater than P2.

While lock sleeve 430 may be moveable by various means, hydraulic means permits the activation of sleeve 424 entirely remotely, simply by pressuring up on the inner bore 414.

Once released from its locked position, sleeve 424 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 446 to act as a back-up seal for port 422. Final closing sleeve 446, may be normally offset from port 422 but is moveable to cover the port. Final closing sleeve 446 may be responsive to pressure conditions in inner bore 414 of the stage tool. For example, sleeve 446 may include a piston face 446a acting between tubing pressure P2 and annulus pressure P1 through port 448 and chamber 450 and can be moved when P2 is greater than P1 sufficient to overcome the holding force of a shear pin 452. Shear pin 452 has a holding force greater than shear pin 435 to ensure that pin 435 fails first to unlock sleeve 424. Final closing sleeve 446 may include seals 458 to ensure that pressure differentials are sensed across face 446a and act to seal the interface between sleeve 446 and wall 416 to prevent leaks therebetween. A lock 447, such as a body lock ring or ratchet, may be employed between sleeve 446 and wall 416 to lock it against movement towards reopening.

Having thus described the components of the example stage tool 410, the operation of that stage tool will be described. Stage tool 410 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. 3A), a second, cementing port-openable position (FIGS. 3B to 3D) and a third, cementing port-closed position (FIG. 3D).

The stage tool may be run into and set in the hole in a condition as shown in FIG. 3A and may be manipulated as shown in FIG. 3B to an active condition shown in FIGS. 3C and 3D for stage cementing. Stage tool 410 allows cement to be introduced through the annulus and allows reverse circulation of annular fluids from the annulus into the tubing string though inner bore 414 and then back up toward surface. After the introduction of cement to an annulus 250 formed between the tool and the wellbore wall down to a selected level, the tool may be manipulated to a condition shown in FIG. 3E to close off communication between the annulus and the inner bore of the tool.

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 sleeve 424. Once in position, port 422 is rendered openable, as by hydraulic actuation of the removable closure, to provide fluid communication between the annulus about the tool and inner bore 414. The stage tool can be located just above an uppermost packer on a treatment string, such that annulus 250 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 422 and into inner bore 414. When sufficient cement is introduced to fill the annulus along a selected length, the ports are closed to stop circulation from the annulus into bore 414. 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 414.

Tool 410 may be installed in a tubular string with its inner bore 414 in communication with the inner diameter of the tubing string. The tool will be run into the wellbore with ports 422 closed. FIG. 3A shows the position of the components of stage tool 410 during run in. Once in position, sleeve 424 can be activated to operate as a check valve by removing its 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 sleeve may occur together. 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 sleeve 424 by moving lock sleeve 430 (FIG. 3B).

After the stage tool is activated, cement can be pumped down the annulus which creates a pressure P1>P2 sufficient to overcome the check valve and, in particular, to move sleeve 424 against the bias of spring 438 to permit circulation, arrows C, through port 422 and into bore 414 toward surface.

Sleeve 424 resists reverse flow through port 422 due to the effect on face and the bias in spring 438. Once the annulus pressure P1 is reduced, FIG. 3D, such as when the cement job is completed, the sleeve 424 shuts. This prevents further flow through port 424, unless pressure is increased again in annulus 250. The bias in spring 438 is sufficient to resist the opening of sleeve 424 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 422 into inner bore 414. 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 is stopped before the cement begins to pass through the ports.

If desired, after the cementing job is done, final closing sleeve 446 can be moved over port 422 to prevent further flow through the port in either direction and to act as a back-up for sleeve 424. This may include pressuring up the string to hydraulically actuate the final closing sleeve 446 to move to a cementing port-closed position (FIG. 3E).

After the cement is installed and set, wellbore operations may proceed. In the embodiment of FIG. 3, the tubing string inner bore is open and by selection of the inner diameters of the sleeves 430 and 446 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 414 of tool 410, 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 414 of the stage tool. In some instances, tools, free or connected to strings, must be passed through the string inner bore including bore 414 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”.

Claims

1. A wellbore assembly comprising: a tubular string having an upper end, a lower end and a tubular wall with an inner bore defined within the tubular wall and an outer surface; a packer encircling the outer surface and spaced from the upper end; a fluid port through the tubular wall providing fluidic access between the inner bore and the outer surface; and a valve for controlling flow through the fluid port between the outer surface and the inner bore, the valve permitting only one way flow through the fluid port in a direction from the outer surface to the inner bore.

2. The wellbore assembly of claim 1 further comprising an activating mechanism for maintaining the valve in an inoperative position until activated.

3. The wellbore assembly of claim 2 further comprising a bypass about the valve and the activating mechanism is operable to close the bypass to activate the valve.

4. The wellbore assembly of claim 1 wherein the activating mechanism is triggerable to activate the valve when the fluid port is opened.

5. The wellbore assembly of claim 2 further comprising an opening mechanism for the fluid port and wherein the activating mechanism and the fluid port opening mechanism are responsive to hydraulic pressure applied through the tubing string from surface.

6. The wellbore assembly of claim 5 further comprising a shiftable member including a ball seat and wherein the valve is activated and the fluid port is opened by launching a ball to land in the shiftable member to create a piston face drivable by hydraulic pressure.

7. The wellbore assembly of claim 5 wherein the activating mechanism and the fluid port opening mechanism are linked such that the valve is activated and the fluid port is opened simultaneously.

8. The wellbore assembly of claim 1 further comprising a second valve positioned along the tubing string between the fluid port and the lower end, wherein the second valve holds pressure from below.

9. The wellbore assembly of claim 8 wherein the fluid port is positioned between the valve and the second valve.

10. The wellbore assembly of claim 2 wherein the activating mechanism is responsive to pressuring up the inner bore of the stage tool to be greater than an annular pressure at the outer surface.

11. The wellbore assembly of claim 10 further comprising a packer setting mechanism and wherein the activating mechanism and the packer setting mechanism operate in response to the pressuring up the tubing string.

12. The wellbore assembly of claim 10 wherein the valve, when activated, activates a check valve for the fluid port, the check valve being openable to reverse flow through the fluid port from the outer surface to the inner bore.

13. The wellbore assembly of claim 10 further comprising a final closing sleeve moveable to close the fluid port.

14. The wellbore assembly of claim 13 wherein the final closing sleeve is moveable by hydraulic pressure.

15. The wellbore assembly of claim 1 further comprising a frac port in the tubing string, the frac port extending through the tubular wall and positioned between the packer and the lower end.

16. A stage tool for wellbore annular cementing, comprising:

a main body including a tubular wall with an outer surface and a longitudinal bore extending from a top end to a bottom end; a fluid port through the tubular wall providing fluidic access between the longitudinal bore and the outer surface; and a valve for controlling flow through the fluid port between the outer surface and the inner bore, the valve including a closure for the fluid port and a check valve for permitting one way flow through the fluid 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.

17. The stage tool of claim 16 further comprising an activation mechanism for the check valve and wherein the activation mechanism is responsive to movement of the closure from a closed to an open condition.

18. The stage tool of claim 17 wherein the activating mechanism is triggerable to activate the check valve when the fluid port is opened.

19. The stage tool of claim 17 further comprising a bypass about the check valve and wherein the activating mechanism closes the bypass to activate the check valve.

20. The stage tool of claim 17 further comprising an opening mechanism for the closure and wherein the activating mechanism and the fluid port opening mechanism are hydraulically activated.

21. The stage tool of claim 17 further comprising a shiftable member including a ball seat and wherein the check valve is activated and the fluid port is opened by launching a ball to land in the shiftable member to create a piston face drivable by hydraulic pressure.

22. The stage tool of claim 20 wherein the activating mechanism and the fluid port opening mechanism are linked such that the check valve is activated and the fluid port is opened simultaneously.

23. The stage tool of claim 16 further comprising a second valve positioned between the fluid port and the bottom end.

24. The stage tool of claim 23 wherein the fluid port is positioned between the check valve and the second valve.

25. The stage tool of claim 16 wherein the stage tool is configurable in at least three positions:

a. a run in position, wherein the closure is in a position closing the fluid port and the check valve is inactive;

b. a cementing position, wherein the closure is open allowing fluid flow through the fluid port and the check valve is active to permit only one way flow through the fluid port; and

c. a cement retaining position, wherein the closure is in a position closing the fluid port.

26. The stage tool of claim 16 wherein the closure and the check valve are the same member.

27. The stage tool of claim 16 wherein a sliding sleeve operates as the closure and is biased to act as the check valve.

28. The stage tool of claim 17 wherein the activating mechanism is responsive to pressuring up the inner bore of the stage tool to be greater than an annular pressure at the outer surface.

29. The stage tool of claim 17 wherein the check valve, when activated, is openable to reverse flow through the fluid port from the outer surface to the inner bore.

30. The stage tool of claim 27 further comprising a final closing sleeve moveable to close the fluid port.

31. The stage tool of claim 30 wherein the final closing sleeve is moveable by hydraulic pressure.

32. The stage tool of claim 27 wherein the sliding sleeve moves along the outer surface.

33. The stage tool of claim 27 wherein the stage tool is configurable in at least three positions:

a. a run in position, wherein the sliding sleeve is locked in a positioned over the fluid port;

b. a cementing position, wherein the sliding sleeve is moveable relative to the fluid port and is biased into a position over the fluid port but is moveable by application of a pressure at the outer surface greater than the pressure in the inner bore; and

c. a cement retaining position, wherein the sliding sleeve is biased into a position over the fluid port.

34. The stage tool of claim 33 wherein the cement retaining position further includes a final closing sleeve positioned over the fluid port.

35. A method for cementing a tubing string in a wellbore, the wellbore having a heel transitioning from a substantially vertical section to a substantially horizontal section, the method comprising: running into a wellbore toward bottom hole with a tubing string to a position in the wellbore, an annulus being defined between the tubing string and the wellbore wall; opening a circulation path from the annulus into the tubing string; introducing cement to the annulus to flow down to at least the heel; and closing the circulation path to hold the cement in the annulus to provide time for the cement to set.

36. The method of claim 35 wherein the circulation path is opened through a fluid port in a stage tool, the stage tool including a valve for controlling flow through the fluid port between the outer surface and the inner bore, the valve permitting only one way flow through the fluid port in a direction from the outer surface to the inner bore and the valve is maintained in an inoperative position until activated.

37. The method of claim 36 wherein the valve is activated when the fluid port is opened.

38. The method of claim 36 wherein the valve is activated and the fluid port is opened by hydraulic pressure applied through the tubing string from surface.

39. The method of claim 36 wherein the valve is activated and the fluid port is opened by launching a ball to land in a shiftable member and create a piston face drivable by hydraulic pressure.

40. The method of claim 36 wherein the valve is activated and the fluid port is opened simultaneously.

41. The method of claim 36 further comprising a second valve positioned in the tubing string between the fluid port and the lower end.

42. The method of claim 41 wherein the fluid port is positioned between the valve and the second valve.

43. The method of claim 36 wherein the valve is activated by pressuring up the inner bore of the stage tool to be greater than an annular pressure at the outer surface.

44. The method of claim 43 wherein pressuring up the inner bore also sets a packer carried on the tubing string downhole of the stage tool.

45. The method of claim 43 wherein the valve, when activated, renders the fluid port openable by reverse flow through the fluid port from the outer surface to the inner bore.

46. The method of claim 36 further comprising moving a final closing sleeve to close the fluid port as a redundant closure.

47. The method of claim 46 wherein moving includes pressuring up the string relative to the annulus.

48. The method of claim 35 further introducing a frac treatment through the string after the cement sets.

49. The method of claim 35, further comprising setting a packer in the wellbore annulus.

50. The method of claim 35 wherein the tubing string includes a tool-actuated mechanism and the method further comprises, after closing the circulation path, launching a tool to pass down and actuate the tool-actuated mechanism.

51. The method of claim 35 further comprising after closing the circulation path, fracturing a formation accessed by the wellbore below the cement.

52. The method of claim 35 wherein positioning includes placing a cementing port adjacent an open hole region of the wellbore and introducing cement introduces sufficient cement to extend upwardly from the open hole region to a casing point in the wellbore.

53. The method of claim 35 wherein closing the circulation path occurs before the cement passes from the annulus into the tubing string.