WO2011137112A2

WO2011137112A2 - Downhole barrier device

Info

Publication number: WO2011137112A2
Application number: PCT/US2011/033930
Authority: WO
Inventors: Henning Hansen
Original assignee: Hansen Energy Solutions Llc
Priority date: 2010-04-30
Filing date: 2011-04-26
Publication date: 2011-11-03
Also published as: WO2011137112A3

Abstract

A barrier for use in a wellbore tubular string (1) includes a barrier housing (3A) sealingly engageable with an interior of the tubular string. A receptacle for a fluid sealing element is disposed in the housing. A sealing element (17) is inserted into the housing to operate a valve operator axially movable with respect to the housing by application of pressure to the wellbore above the barrier housing after insertion of the sealing element. A valve (7, 9) is coupled to the valve operator, wherein the valve operator is repeatedly movable axially to operate the valve by applying selected fluid pressure in the wellbore above the sealing element.

Description

DOWNHOLE BARRIER DEVICE

Background of the Invention

Field of the Invention

[0001] The invention relates generally to the field of downhole barriers in hydrocarbon producing wells. More specifically, the invention relates to a plug mechanism that can be repeatably opened and closed as needed. Also the invention relates to a safe barrier downhole in a wellbore that can be used when installing into or retrieving equipment from the wellbore disposed above such barrier. Such equipment may, for example, be an upper well completion system, an insert gas lift system or a downhole pump, where the well needs to be secured (closed) prior to installation of such devices, as well as when the insert system needs to be retrieved for maintenance, repair, reconfiguration, etc.

Background Art

[0002] A number of plugs and valves exist for wellbore use, where these are typically set and retrieved by wireline or other suitable wellbore intervention method. Such devices normally require a wellbore intervention run, for example by wireline, to seal off or open the barrier (e.g., plug or valve) for hydrocarbon bypass.

[0003] Also devices exist where dropping a ball into the wellbore, followed by this ball engaging into a proper seat in a downhole device causes the device to open or close fluid communication across such device. However, devices that can be opened and closed without having to retrieve the device to surface do not exist. Neither do such devices exist where the device can be repeatedly opened and closed. Thus, there exists a need for devices which can isolate a portion of a wellbore and be operated repeatedly without the need to retrieve the device from the wellbore.

Summary of the Invention

[0004] A barrier for use in a wellbore tubular string according to one aspect of the invention includes a barrier housing sealingly engageable with an interior of the tubular string. A receptacle for a fluid sealing element is disposed in the housing. A sealing element is inserted into the housing to operate a valve operator axially movable with respect to the housing by application of pressure to the wellbore above the barrier housing after insertion of the sealing element. A valve is coupled to the valve operator, wherein the valve operator is repeatedly movable axially to operate the valve by applying selected fluid pressure in the wellbore above the sealing element.

[0005] The invention covers various methods and devices for opening and closing a downhole barrier, where such barrier can be used for example to secure a well towards blow-out during installation of equipment, replacement of valves and similar higher up in the wellbore.

[0006] The solutions provided by the invention allow for the avoidance of repeated wellbore intervention runs to close and open the barrier, which can result in cost savings, less lost production and enhanced safety for personnel and equipment. Also the solution presented by the invention provides abilities to open/close a downhole barrier where wellbore intervention is not possible.

[0007] The downhole barriers as described herein can be retrofitted into an existing wellbore tubular by wireline, coiled tubing or other well intervention methodology. However, the barriers can also be incorporated as a component in a well completion system when the completion system is installed into a wellbore.

[0008] Other aspects and advantages of the invention will be apparent from the following description and the appended claims.

Brief Description of the Drawings

[0009] FIG. 1 illustrates a wellbore tubular with a barrier valve installed. The valve is in the open position, allowing well production fluid to flow to the surface.

[0010] FIG. 2 illustrates the barrier in FIG. 1, where a ball is dropped into the barrier. By pressurizing the wellbore above the barrier, a plug will move down and shift the barrier from closed to open position or the reverse. [0011] FIG. 3 illustrates a barrier shifted to the closed position, where wellbore fluids cannot flow from below to above the barrier.

[0012] FIG. 4 illustrates another variation of a downhole barrier installed in a wellbore tubular, where the barrier consist of a flapper or ball valve, similar to the constructions used in downhole safety valves. Also, the closing mechanism can be a sliding sleeve or ported cylinder.

[0013] FIG. 5 illustrates a barrier as shown in FIG. 4, where a tubing string with a ported weight sub has been positioned above the barrier. A stinger with a ported engagement tool in the lower end, which can be moved down in/from the weight sub, latches into a sleeve within the barrier where pushing the sleeve down opens the barrier valve.

[0014] FIG. 6 illustrates the ported engagement tool described in FIG. 5, where FIG.6 shows production fluid bypass ports.

[0015] FIG. 7 illustrates the same barrier type as described in FIG. 5, with the difference being a hydraulically operated piston that drives the stinger and the ported engagement tool down to operate the barrier valve.

[0016] FIG. 8 illustrates a downhole barrier similar to FIG. 4, with the difference being that the inner cylinder (18) opening the lower valve is constructed with a reduced inner diameter, so that a ball or dart dropped into the device will open or close the valve. This valve construction can be based on a flapper valve, a ball valve or a sliding sleeve valve.

[0017] FIG. 9 illustrates a ball dropped into the downhole barrier as described in FIG.8, where the barrier is moved to the open position so that wellbore fluids can flow through the barrier. Also, a dart that can be used as an alternative to a ball is illustrated.

[0018] FIG. 10 shows an example dart that may be used with the example of FIGS. 7 and

8.

[0019] FIG. 11 shows another example of barrier that uses flapper valves.

[0020] FIGS. 12-14 show another example of barrier that uses s stem type valve and a flapper valve to operate the stem type valve. Detailed Description

[0021] Various examples of a barrier explained in more detail below may be generally described as having a housing insertable into a wellbore tubular, or as an integrated device installed together with the wellbore tubular. The housing includes a receptacle for a sealing element. The sealing element is arranged such that when pressure is applied to the well from above the barrier, a valve operator is moved. The valve operator opens or closes a valve disposed in the barrier housing. Operation of the valve operator may be performed repeatedly without having to retrieve the barrier to surface between operations as will be better understood by detailed explanation of the various examples.

[0022] FIG. 1 shows a wellbore tubular (1) that can be production tubing, wellbore casing or a similar pipe string installed in a subsurface wellbore. A downhole barrier, which may also referred to as a valve or plug, is installed in the tubular (1). The barrier is used to open or close to allow or stop produced fluids (2) from flowing between a reservoir located below the barrier and the wellbore above the barrier. The illustration shows the barrier in the open position enabling flow of fluids (2). The components of the example barrier may be better understood with reference to the following description.

[0023] The barrier and its components may be contained within a housing (3A). The housing (3 A) can be locked in place in the tubular (1) by, for example, a wireline intervention, coiled tubing intervention, semi stiff spoolable rod intervention or jointed tubing intervention, where an industry standard running tool (not illustrated) is attached to the upper section (3) of the barrier housing (3A). The barrier can then be locked in place by so-called "dogs" or slips (4) in a suitable receptacle in the wellbore tubular (1). A seal stack (5) placed externally on the upper barrier section (3) provides a seal preventing wellbore fluids from flowing between the barrier and the wellbore tubular (1). In the lower section of the barrier housing (3A), a fastening arrangement (14) may provide a guide for the barrier when installing the barrier into the tubular (1). Also this guide section (14) can contain an internally threaded section (14A) so that the inner mechanism of a valve system for the barrier can be mounted herein. [0024] Within the barrier housing (3 A) a reduced inside diameter ball guide section (6) with a seal bore (7) provides a guide for dropping a ball or similar closure element into the barrier to open or close the barrier. In the center of the barrier, a ball-receiving prong

(8) is attached to a shuttle (16) having a seal stack (9) in the upper section thereof.

[0025] The ball-receiving prong (8) has lugs or pins (10) mounted that engage into so- called "J-slot" profiles (12) in a shuttle housing (11). A so-called J-slot is described in U.S. Patent No. 4,355,685 issued to H.K. Beck and entitled, "Ball operated J-slot". Such J-slots (12) cause the shuttle (16) to rotate when it is moved axially and stop at predetermined axial (up/down) positions within the shuttle housing (11). Such a function provides the means to shift the shuttle (16) to various axial positions, to perform various operations such as opening and closing the barrier.

[0026] The shuttle (16) can be axially biased by a spring (13) located below the shuttle

(16). Below the spring (13), a ported adapter (15) may be threadedly engaged into the threaded portion (14A) of the lower section (14) of the housing (3A). The ported adapter (15) provides the support for the valve system containing the shuttle housing (11). When the valve is open (i.e., when the shuttle (16) is in an axial position such that the seal stack

(9) is disengaged from the seal bore (7), wellbore fluids can pass across the barrier valve via the ports in the ported adapter (15) and the annulus between the shuttle housing (16) and the barrier housing (3A). Thereafter, the wellbore fluids can pass through the inner section of the ball guide section (6).

[0027] FIG. 2 shows the barrier as illustrated in FIG. 1, where a ball (17) is dropped into the barrier to operate the shuttle (16) by pressurizing the wellbore above the barrier. Such pressure will cause the ball (17) to seal against the ball guide (6), where the ball (17) will force the ball-receiving prong (8) and the shuttle (16) downward against the bias force of the spring (13). Axial motion of the shuttle (16) causes the J-slot mechanism (10, 12) to shift the shuttle (16) into a position where the seal stack (9) is: (i) either retained and protected within the shuttle housing (11) as shown in FIG. 2; or (ii) where the seal stack (9) is located within the seal bore (7 of FIG. 1) of the ball guide (6). In this way, the barrier is maintained in the open or closed position. [0028] FIG. 3 shows the shuttle (16) moved to the upper position, where it is shutting off fluid communication through the barrier by forcing the seal stack (9) in the seal bore (7). The ball (17) can be left in place as illustrated, or a ball manufactured from a material that dissolves downhole within hours or days can be used.

[0029] Such dissolving or also called "soluble" balls are now commonly used to operate so called fracturing sleeves, and example of such balls are sold under the trademark BIO BALLS by Santrol Proppants, 50 Sugar Creek Center Boulevard, Sugar Land, Texas, USA 77478.

[0030] In the example of FIGS 1, 2, and 3, reopening the valve after it is closed only requires pressurizing the well from the surface to move the seal assembly (9) out of the ball seal area (7). The pressure from above the barrier acting against the ball (17) dropped into the wellbore and landed on top of the ball-receiving prong (8) will push the shuttle (16) downward. The J-slot mechanism (10, 12) will lock the shuttle (16) in place so that the seal stack assembly (9) is disengaged from the ball seal area (7). The foregoing operation of the opening and closing the valve components in the barrier may be repeated as many times as is needed.

[0031] FIG. 4 illustrates another example downhole barrier installed in a wellbore tubular

(1), where the barrier housing (3 A) is locked in place by "dogs" or slips (4A) and where an external seal stack (5) prevents fluid passage between the valve assembly and the wellbore tubular (1).

[0032] The barrier will typically consist of main components being a valve opening and sliding sleeve (18) which interacts with a spring (13) that provides upward thrust causing a valve (19) to be closed. The valve (19) may be for example be a flapper type, a ball valve type or a sliding sleeve, or any similar valve that can be operated by a sliding sleeve. The valve (19) will remain in the closed position until a tool, explained below with reference to FIG. 5, is inserted into the sliding sleeve (18) where it is pushed downwards.

[0033] FIG. 5 illustrates the barrier as described in FIG. 4, but in FIG. 5 it can be observed that an additional tubular (20) is placed into the wellbore tubular (1) above the valve (19). Near the lower end of the additional tubular (20), a weight sub (31) can be attached. The weight sub (31) has longitudinal ports (21) for providing fluid communication across the weight sub (31). Within the weight sub (31), there is a ratchet mechanism (22), which can be formed, for example, by machining threads along the section requiring such a ratchet function. A piston (23) with a stinger (24) and a ported engagement tool (25) is mounted within the weight sub (31), and for well installation this assembly will be placed in the upper position of the weight sub (31). To latch into the valve opening and operate the sliding sleeve (18), the described stinger (24) is pushed down within the weight sub (31) by pressurizing the additional tubular (20) or by entering the wellbore with wireline, slickline or other wellbore intervention device within the additional tubular (20), landing onto top of the stinger (24) assembly and then jarring down.

[0034] When the stinger's (24) ported engagement tool (25) latches into a profile (26) of the sliding sleeve (18), continued downward force will move the sliding sleeve (18) downward so that the valve (19) is opened. Ports (27) through the engagement tool (25) ensure wellbore production fluids can flow through the engagement tool (25) toward the surface. The ratchet mechanism (22) will ensure that the stinger assembly (24) is kept in the lower position. Alternatively, a locking collet (not shown) can be implemented in the sliding sleeve (18) or the location for the ratchet mechanism (22).

[0035] FIG. 6 shows a top view of the ported engagement tool (25) observed from the top, where the stinger (24) is connected to the center of the engagement tool (25). The engagement tool (25) has fluid bypass ports (27) around it.

[0036] FIG. 7 illustrates a configuration similar to the one described with reference to

FIG. 5, with the difference being that the stinger system (24) is moved up and down by hydraulic pressure acting on a hydraulic piston (30) attached to a pack-off (29). Hydraulic pressure can be delivered from the surface via one or several control lines (28) attached to a deployment tubular (20). The hydraulic piston (30) will push downward onto the spring loaded piston (23) where the stinger system (24) is attached underneath. Applying pressure to the hydraulic piston system (30) will allow manipulation of the barrier valve system below. Those skilled in the technical field of this invention will understand that the hydraulic piston (30) also can be coupled directly to the stinger (24), where the spring loaded piston (23) would not be required.

[0037] FIG. 8 illustrates a downhole barrier similar to FIG. 4, with the difference being that the sliding sleeve (18) used to open the lower valve (19) is constructed with a reduced inner diameter near the upper longitudinal end, so that a ball or dart dropped into the device will open or close the valve (19) when pressure is applied to the tubular (1) from the surface. This valve construction can be based on a flapper valve, a ball valve or a sliding sleeve valve, just as the example shown in FIG. 4.

[0038] A J-slot mechanism as described for FIG. 1 may be incorporated in the sleeve

(18) and the outer housing (3 A) of the barrier. Moving the sleeve (18) axially (down and up) will place the sliding sleeve (18) at different axial locations within the valve system, where these locations can result in the valve (19) remaining open or closed. The sliding sleeve (18) is biased by a spring (13) where the force of the spring (13) will bias the sleeve (18) upwards, causing the valve (19) to close when such operation is desired. As explained with reference to FIG. 2, the ball may be made from a material that dissolves in a selected time. In the example of FIGS 7 and 8 only dropping a new ball and pressurizing the well from the surface is required to re -operate the valve (19).

[0039] FIG. 9 illustrates the valve system described in FIG. 8, wherein the ball (17) is dropped into the valve. The diameter of the ball is larger than the diameter of a ball seat (the reduced diameter portion) in the sliding sleeve (18) in the upper section of the inner cylinder (18), resulting in the ball (17) pushing the inner cylinder (18) downward when pressure is applied in the wellbore above the barrier. An alternative to a ball can be a dart (33) as shown in FIG. 10. The ball (17) or dart (33 in FIG. 10) can either be produced to surface after a completed valve opening sequence, or the ball (17) can be manufactured using a material that dissolves within a few hours or days as described with reference to FIG. 3. Pumping down on the ball (17) or dart (33 in FIG. 10) by applying pressure from above the barrier will change the axial position of the sleeve (18) by operation of the J- slot mechanism as described with reference to FIG. 8, so that the valve (19) will remain in the open or closed position. The dart (33 in FIG. 10) can also be wireline deployed and retrieved or dropped and wireline retrieved to the surface if required, using, for example, a standard wireline retrieving tool.

[0040] Yet another example implementation will now be explained with reference to

FIG. 11. A sliding sleeve (18) biased by a spring (18) with respect to the barrier housing (3 A) can be used as in the previously described embodiments. The sliding sleeve (18) may have external pins as shown to engage J-slots in the tool housing as explained with reference to FIG. 1 so that the sleeve (18) may be locked in selected axial positions with each axial movement. The present example may have a flapper valve (50) that is opened by moving the sliding sleeve (18) downward and closed by upward movement of the sleeve (18). To perform such operation to close the flapper valve (50) the well may be shut in so as to stop flow of fluids upward in the well. A second flapper valve (43) on the upper part of the sliding sleeve (18) will then drop closed. The well may then be pressurized from the surface, moving the sliding sleeve (18) downward against the bias force of the spring (13) to open the flapper valve (50). Releasing pressure at the surface enables fluid pressure from below the second flapper valve (43) to open, allowing fluids to move from the production zone below the barrier device upward in the wellbore. The sliding sleeve (18) will remain in position by the action of the J-slot mechanism. The foregoing operation may be repeated to close the flapper valve (50) as required.

[0041] A similar upper flapper valve (43) operating system will be explained with reference to another embodiment shown in FIGS. 12, 13 and 14. In FIG. 12, a sliding sleeve (18) and spring (13) may be included in the barrier housing (3A) as in the previously described example. The upper part of the sliding sleeve (18) may include a flapper valve (43) as in the previous example. The sliding sleeve (18) may be coupled to a stem type valve (40) below. Downward movement of the sliding sleeve (18) will open the stem type valve (40). As in the previous example, and referring to FIG. 13, closing the well to flow will allow the flapper valve (43) to close. Pressure may then be applied to the well above the barrier device, and the pressure will move the sliding sleeve (18) downward against the spring (13) force. A seal assembly (42) on the valve stem will be disengaged from a seal surface (41) in the barrier housing, thus enabling flow from below the barrier device. As pressure from the surface is released, the flapper (43) will open, allowing flow to the surface from the formation below the barrier device, as shown in FIG. 13. The stem valve (40 in FIG. 12) may be closed by shutting in the well from the surface and repeating controlled pressurization to move the sliding sleeve (18) to a different axial position by means of the J-slots (FIG. 1). The elements required to lock the housing (3 A) and seal the housing (3 A) in the tubular (1) may be as explained with reference to the other examples herein.

[0042] In all of the foregoing examples where the valve operator engages the respective housing using a J-slot mechanism, it is possible to configure the J-slots to provide axial positioning of the valve operator in more than the "valve open" and "valve closed" positions. That is, the J-slot mechanism may be configured to include axial valve operator positions such that the valve is only partially open to a selected amount. Thus, the valve operator may operate the valve to act as a choke or similar flow restriction as well as being fully opened to flow or fully closed to flow.

[0043] A wellbore barrier according to the various aspects of the invention may enable repeated opening and closing of a valve in the wellbore without the need to retrieve the barrier.

[0044] While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Claims

Claims What is claimed is:

1. A barrier for use in a wellbore tubular string, comprising:

a barrier housing sealingly engageable with an interior of the tubular string;

a receptacle for a fluid sealing element disposed in the housing;

a sealing element;

a valve operator axially movable with respect to the housing by application of pressure to the wellbore above the barrier housing after insertion of the sealing element; and a valve coupled to the valve operator, wherein the valve operator is repeatedly movable axially to operate the valve by applying selected fluid pressure in the wellbore above the sealing element.

2. The barrier according to claim 1 wherein the fluid sealing element comprises a ball.

3. The barrier according to claim 2 wherein the ball is manufactured in a material that dissolves in the wellbore after a predetermined time.

4. The barrier according to claim 1 wherein the fluid sealing element comprises a dart.

5. The barrier according to claim 4 where the dart is manufactured in a material that dissolves in the wellbore after a predetermined time.

6. The barrier according to claim 4 wherein the dart is configured to be retrieved from the wellbore by a wireline conveyed retrieval instrument.

7. The barrier according to claim 1 wherein the housing is insertable into the tubular by wellbore intervention by wireline, coiled or jointed service tubing.

8. The barrier according to claim 1 wherein the housing is inserted into the tubualar as an integrated part of a well completion.

9. The barrier according to claim 1 wherein the sealing element is enabled to be pumped through a fluid sealing element receptacle in the housing after having shifted an axial position of the valve operator.

10. The barrier according to claim 1 wherein the sealing element comprises a flapper valve.

11. The barrier according to claim 1 wherein the valve operator comprises a sliding sleeve.

12. The barrier according to claim 1 wherein the sliding sleeve is engaged with an interior of the housing by a pin and J-slot mechanism such that axial movement of the valve operator locks the valve operator at selected axial positions within the housing.

13. The barrier according to claim 1 wherein the valve operator is configured to be locked in selected axial positions intermediate having the valve fully closed and the valve fully open, thereby enabling partial opening of the valve to restrict flow across the barrier by a selected amount.