GB2522264A

GB2522264A - Sliding Sleeve Tool

Info

Publication number: GB2522264A
Application number: GB1400960.9A
Authority: GB
Inventors: Duncan Harper
Original assignee: Swellfix BV
Current assignee: Swellfix BV
Priority date: 2014-01-21
Filing date: 2014-01-21
Publication date: 2015-07-22
Also published as: WO2015110463A2; GB201400960D0; WO2015110463A3

Abstract

A sliding sleeve tool 20 comprises a tubular housing 23 having one or more flow ports 21. A first sleeve22 is slidably connected with the first sleeve a tubular housing, wherein the first sleeve may be moved from a first run in position covering the one or more flow ports to a second position to uncover the one or more flow ports. The tool further comprises a second sleeve 27 slidably connected with the tubular housing, the second sleeve being movable from a first position wherein the sleeve doses not interfere with the operations of the first sleeve to a second position that covers the one or more ports of the outer tubular to prevent fluid flow. The first sleeve may be retained in its first position by a shear pin or push back pin or the like and shifter by means of a drop ball mechanism.

Description

Sliding Sleeve Tool

FIELD OF INVENTION

The present invention relates to a sliding sleeve tool and uses thereof in oil and gas operations such as well stimulation treatment and production.

BACKGROUND

Sliding sleeve tools are run as part of a well pipe in wellbore completions.

Heretofore sliding sleeve tools typically include an outer housing that has a plurality of flow ports. A sleeve is disposed within the housing and is axially moveable in relation to the housing between a first position, wherein the sleeve blocks the flow ports and a second position wherein the flow ports at open.

In multizone well operations the well pipe may comprise a plurality of sliding sleeve tools to allow well treatment of or production from different zones. Opening a sleeve permits injection of fluids into a selected zone of the well. After treatment of a zone, the sleeve may function as a standard production device allowing well fluids to flow into the well pipe.

Well stimulation treatments such as fracing and acidising are used extensively to improve the permeability of reservoirs and enhance well production. Fracing involves injecting water or other fluids at high pressure to create small fractures around a wellbore to allow fluids such as gas or oil to migrate into the wellbore. Various chemicals and small particles such as sand known as proppants may also be added to keep the fractures open. Acidising involves the injection of acidic fluids into the well to create holes into the well by dissolving certain rocks. Well stimulation treatments may be used with all types of wells. However, well stimulation may be particularly useful with unconventional well environments such as shale gas, coal bed methane, tight gas, shale oil, and hard rock.

It is not uncommon during stimulation treatment of wells especially during fracing or acidising operations employing highly pressurised fluids, abrasive proppants and corrosive chemicals for the sleeve to be damaged. Moreover, most existing sliding sleeve designs employ a drop-ball shifting mechanism that may be used only once. If well operations require that the sleeve be reclosed, then the well pipe may have to be retrieved in order to repair the defective sleeve or refurbish the well pipe with a new sliding sleeve tool. Retrieval of the well pipe is expensive as it requires cessation of operations.

SUMMARY OF THE INVENTION

An aspect of the present invention relates to a downhole sliding sleeve tool. The sliding sleeve tool comprises: a tubular housing having one or more flow ports; a first sleeve slidably mounted with the tubular housing, wherein the first sleeve may be moved from a first position covering the one or more flow ports to a second position to uncover the one or more flow ports to permit fluid flow between the wellbore and the interior of the tubular housing; and a second sleeve slidably mounted with the tubular housing, the second sleeve being moveable from a first position wherein the second sleeve does not interfere with the operation of the flow ports to a second position that at least partially covers the one or more pods to modify fluid flow.

In use, the sliding sleeve tool may be deployed within the wellbore as part of a well pipe such as a completion. The well pipe may comprise one or more sliding sleeve tools according to an aspect of the invention, for example depending on whether the wellbore comprises one or more zones. When deploying the well pipe into the wellbore, the first sleeve may be in a first position covering the one or more flow ports also referred to hereinafter as a run in hole position or configuration. When the well pipe is in the desired location within the wellbore and an operation is about to begin the first sleeve may be moved from the first position to the second position to uncover the one or more flow ports to permit fluid flow between the wellbore and the interior of the tubular housing. For example, in this configuration, a well treatment, such as fracing fluid may be injected through the open flow pods into the surrounding formation.

During the treatment operation the second sleeve may be in its first position wherein the second sleeve does not interfere with the operation of the flow ports. Upon completion of treatment, the second sleeve may then be moved to its second position to fully or partially the flow pods as may be needed. The second sleeve may be designed to move between its first and second positions multiple times. For, instance upon completion of sequential treatment of two or more well zones the sliding sleeve tools may be used for producing the well fluids from one or more of the well zones. The second sleeve may allow for full or partial closing or opening of the flow ports to allow for optimizing well production from the various zones. For instance, if a particular zone may commence to produce water the flow ports of the sliding sleeve tool controlling production for that zone may be partially or fully closed as desired.

The second sleeve may be disposed initially at a sufficient distance from the one or more flow ports to prevent or minimize damage from the flow of fluids through the one or more flow ports or other operations relating to the first sleeve.

For instance, during treatment, such as fracing and/or acidising operations it is not uncommon that the first sleeve, and/or associated components thereof such as seals, may be damaged because of its proximity to the flow ports and exposure to highly pressurized abrasive proppants and/or other chemicals. By positioning the second sleeve away from the flow ports when the ports are used, the present inventor has found that any abrasive and corrosive effects may be substantially reduced resulting in proper functioning of the second sleeve for multiple subsequent operations.

Moreover, having a second sleeve allows other protective measures and or devices to be employed. For example, a protective screen or sheath may be employed if additional protection of the second sleeve is desired. The protective screen or sheath may be made of a material that is resistant to certain chemicals used in well stimulation treatments. For instance a ceramic or plastic material that is resistant to acidic liquids may be used to protect damage of the second sleeve during acidising operations.

The sliding sleeve tool may comprise a retaining mechanism to hold the first sleeve in its first position. Many different types of retaining mechanisms may be used.

For example, one or more retainers could be used such as shear pins or pushback pins. The retainers may be positioned on the tubular housing or alternatively may be placed on an annular ring positioned within the tubular housing. The first sleeve may contain one or more corresponding recesses to receive the pins. The first sleeve may be held in place by some other retaining mechanism such as a spring and clasp combination.

The sliding sleeve tool may comprise a first shifting mechanism for permitting shifting of the first sleeve from the first position to second position to uncover the one or more ports.

The first shifting mechanism may comprise a seat that may be shaped and sized to be engaged by an object that can be deployed within the well pipe from surface. For example, the first shifting mechanism may comprise a seat and drop object mechanism. The drop object may comprise one or more of a ball, dart or the like. The seat may be shaped and sized to engage a drop object. The seat may be an integral pad of the first annular sliding sleeve. Thus, once the well pipe is in the desired place within a wellbore before initiating a well treatment operation such as fracing, or acidizing of a selected zone of the well, an object having the appropriate size may be dropped to engage the seat. Then, by applying sufficient pressure or force on the object, and/or by the momentum of the object, the retaining mechanism may be overcome and the first sleeve may be released and shifted from the first position to the second position. For instance, when the retaining mechanism comprises one or more shear pins, the shear pins may fail and the first sleeve may then be released and shifted to its second position to uncover the one or more flow pods.

The seat and drop object mechanism may allow for the sequential treatment of different zones of a multizone well by employing multiple shifting sleeve tools with seats with decreasing diameter. For example, the seats may decrease in diameter in a direction towards the toe of the well. Then, the smallest object may be dropped first and allowed to pass through all the larger seats until it lands on a mating seat closest to the toe of the well. Once the first zone has been treated, successively larger objects may then be dropped to initiate treatment for each subsequent zone.

Other shifting mechanisms may be used for the first sleeve in addition or instead of the seat and drop object mechanism without departing from the scope of the present invention. For example, the first sleeve may comprise a shifting profile for connecting to a corresponding mating surface of a shifting tool that can be used to shift the first sleeve. The shifting tool may be operated mechanically via a conveyance such as coiled tubing, jointed tubing, wireline, slickline or the like. It will be appreciated by those skilled in this ad that for deviated wells coiled tubing or jointed tubing may be preferred.

The first shifting mechanism may be operated hydraulically.

The first shifting mechanism may be operated electrically.

The first shifting mechanism may comprise an actuator configured to be operated to shift the first sleeve. The actuator may be configured to be operated upon receipt of an actuation signal. The actuation signal may be provided or transmitted from surface and/or from a downhole location. The actuation signal may comprise a mechanical actuation signal, for example from a drop object or the like. The actuation signal may comprise an electrical or electromagnetic signal, for example as might be transmitted via a conductor, wirelessley or the like. The actuation signal may comprise a radio frequency signal. Such a radio frequency signal may be transmitted via a tag dropped through the tool.

The actuation signal may comprise an optical signal.

The actuation signal may comprise an acoustic signal.

The actuation signal may comprise a pressure pulse signal.

The first shifting and retaining mechanisms may allow multiple trips between the first and second positions for the first sleeve.

The sliding sleeve tool may comprise a second shifting mechanism that enables shifting the second sleeve from its first position to a second position whereby the second sleeve covers the flow ports fully or partially as may be needed. For example, the second sleeve may comprise a seat and drop object mechanism. The second sleeve may comprise a shifting mechanism that may allow for multiple operations. For example, the second sleeve may comprise a shifting profile that permits a shifting tool having a mating profile to engage and shift the second sleeve from its first to its second position. The shifting profile mechanism may be in addition or instead of the seat and drop object mechanism.

Other shifting mechanisms may be used for selectively moving the second sleeve between the first and second positions. The second shifting mechanism may be operated mechanically, hydraulically, electrically or the like, or any suitable combination thereof.

The second shifting mechanism may comprise an actuator configured to be operated to shift the second sleeve. The actuator may be configured to be operated upon receipt of an actuation signal. The actuation signal may be provided or transmitted from surface and/or from a downhole location. The actuation signal may comprise a mechanical actuation signal, for example from a drop object or the like.

The actuation signal may comprise an electrical or electromagnetic signal, for example as might be transmitted via a conductor, wirelessly or the like. The actuation signal may comprise a radio frequency signal. Such a radio frequency signal may be transmitted via a tag dropped through the tool.

The actuation signal may comprise an optical signal.

The actuation signal may comprise an acoustic signal.

The actuation signal may comprise a pressure pulse signal.

The second shifting mechanism may allow multiple movements of the second sleeve between the first and second positions.

The tubular housing may comprise a second retainer mechanism for holding the second sleeve in its first position. The second retainer mechanism may comprise one or more shear pins, pushback pins, a spring and clasp combination, or the like. Other retainer mechanisms may also be used without departing from the scope of the present invention.

The second shifting and retaining mechanisms may allow multiple trips between the first and second positions for the second sleeve.

The second retainer mechanism may be of a type that can be used multiple times. For example, the tubular housing may comprise one or more pushback pins disposed on an interior surface of the tubular housing to engage corresponding recesses of the second sleeve. The pushback pins may also be disposed on an annular ring positioned within the tubular housing.

The tool may comprise a sealing assembly for providing sealing between one or both of the first and second sleeves and the tubular housing. Such a sealing assembly may comprise one or more 0-rings or the like.

The tubular housing may have threaded connections at one or both ends for connection to a well pipe, however, any type of suitable connections may be used.

The tubular housing may be made of a single piece of pipe or may comprise two or more parts suitably connected together. For instance the tubular housing may comprise a first tubular housing for housing the first sleeve and the one or more flow ports, and a second tubular housing for housing the second sleeve.

The two parts of the tubular housing may be threaded or bolted together or securely connected using other type of connectors that are well known in the art.

The first and second sleeves may comprise a solid surface without any flow ports.

The first and second sleeves may comprise one or more pods depending on the design of the sliding sleeve tool. For example, if the first sleeve comprises one or more flow ports, in that case the first sleeve may be shifted so that the flow ports of the tubular housing are aligned with the flow ports of the first sleeve when fluid communication is desired between the interior of the sliding sleeve tool and the wellbore. Alignment may be achieved by various well known shifting mechanisms including longitudinal shifting and/or annular rotation of the first sleeve.

The first and second sleeves may be made of any suitable material including steel alloys that are typically used in oil and gas downhole applications.

The second sleeve may be made from a different material than the first sleeve.

The first and second sleeves may be disposed within the tubular housing.

The first and second sleeves may be disposed outside the tubular housing. If, one or both of the first and second sleeves are disposed on an outside surface of the tubular housing, care must be taken so that the overall diameter of the tool may not exceed the diameter of the well pipe. For, example one or both of the first and second sleeves may be slidably disposed within a suitably sized recess formed at the external surface of the tubular housing so that the overall tool diameter may not exceed the diameter of the well pipe.

The sliding sleeve tool may comprise other devices that are well known in the art such as a screen or sheath used to protect the internal mechanism of the sliding sleeve tool from exposure to extraneous or corrosive materials such as cement during cementing of downhole completions, or fracing fluids. A screen or sheath may be disposed between the sleeves and the tubular housing. In situations where the sliding sleeve tool is used in a production environment to flow production fluids through the flow ports, a sand screen may be used to prevent sand from entering the well pipe.

It will be appreciated by those skilled in their art that the sliding sleeve tool may be used in a variety of downhole environments and operations. The sliding sleeve tool allows partially or fully closing the flow ports. Moreover, the sliding sleeve tool allows multiple openings and closing of the flow ports. In a situation, wherein the first sleeve may not be reused either because of its design or because it has been damaged, the second sleeve may still be used to partially or fully close the flow ports once or multiple times as may be desired. For example, when the sliding sleeve tool is used in fracing or acidizing operations, the first sleeve or components thereof, such as seals, may be damaged because of the abrasive and or corrosive nature of the fluids and proppants employed rendering closing of the first sleeve and/or the flow ports problematic. For instance, there may be situations where after a severe operation the first may be partially damaged and still movable to cover the flow ports but without a sufficient seal.

In some embodiments, operation of the first sleeve may require that the first sleeve is locked in place after uncovering the flow ports to prevent interference with the flow operation. After locking the first sleeve in its second position, unlocking may be undesirable, for example to minimise complexity of the tool. For instance, when a seat and drop object shifting mechanism is used for the shifting of the first sleeve, the object may need to be drilled out in order to establish fluid communication between adjacent sections of the well pipe. During drilling of the object the first sleeve may also be compromised.

In yet other embodiments, the shifting mechanism of the first sleeve may be such that does not allow reshifting of the sleeve to its original configuration. Having a second sleeve that may be used to fully or partially close the flow ports is advantageous and offers greater flexibility in operations.

The sliding sleeve tool may permit closing the flow ports in situations where the first sleeve comprises a drop object shifting mechanism that does not allow reclosing of the sleeve after the first sleeve has been used once.

Moreover, having the second sleeve placed away from the flow ports during abrasive or corrosive flow operations may protect the second sleeve from damage and allow employing the second sleeve to shutting off zones later on in the life of a well.

The first and second sleeves may be complete annular members covering the whole surface of the tubular housing. However, the first and second sleeves may also be annular segments covering only that portion of the surface of the tubular housing that contains the one or more flow ports.

A second aspect of the present invention is directed to the use of a sliding sleeve tool in a downhole operation.

The downhole operation may comprise: deploying a well pipe within a wellbore, the well pipe comprising a sliding sleeve tool as in any other aspect. The downhole operation may further comprise moving a first sleeve of the sliding sleeve tool from a first position to a second position wherein one or more fluid ports of the sliding sleeve tool are uncovered to permit fluid communication between the interior of the sliding sleeve tool and the wellbore. A fluid may be flown through the uncovered fluid ports. When it is desired to terminate the fluid operation, a second sleeve may be moved from a first position to a second position to fully or partially cover the fluid pods to modify fluid communication between the interior of the sliding sleeve tool and the wellbore.

Yet another aspect of the present invention is directed to a downhole well pipe comprising one or more sliding sleeve tools as in any other aspect.

The downhole well pipe may be part of a completion in a vertical or deviated well such as a horizontal well.

Yet another aspect of the present invention relates to a method for controlling fluid communication between a wellbore and a well pipe, the method comprising: deploying a well pipe within a wellbore, the well pipe comprising a sliding sleeve tool; moving a first sleeve of the sliding sleeve tool from a first run in hole configuration to a second configuration wherein one or more fluid ports are uncovered permitting fluid communication between the interior of the sliding sleeve tool and the wellbore; flowing a fluid through the fluid ports; and moving a second sleeve of the sliding sleeve tool from a first run in hole configuration to a second configuration to at least partially cover the fluid ports to modify fluid communication between the interior of the sliding sleeve tool and the wellbore.

The well pipe may comprise a plurality of sliding sleeve tools for controlling fluid communication between a plurality of well zones and the interior of the well pipe. The method may be used in well treatment, production or any combination thereof.

These and other aspects of the present invention will now be described, by way of non-limiting examples, in reference to the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWNGS

Figure 1 is a diagrammatic illustration of a well completion deployed inside a horizontal well and comprising one or more sliding sleeve tools according to an embodiment of the present invention; Figure 2A is a diagrammatic illustration of a sliding sleeve tool shown in a run in hole position according to an embodiment of the present invention; Figure 2B is a diagrammatic illustration of a sleeve shifting mechanism used according to an embodiment of the present invention; Figure 20 is a diagrammatic illustration of a sliding sleeve tool shown in an open position according to an embodiment of the present invention.

Figure 2D is a diagrammatic illustration of a sliding sleeve tool shown in a closed position according an embodiment of the present invention.

DETAILED DESCRIPTION OF THE DRAW NGS

An aspect of the present invention is directed to a sliding sleeve tool. In some embodiments such a sliding sleeve tool may be used in downhole completions for allowing multiple well operations of single or multiple well zones in many different types of wells and well environments. For example, embodiments of the sliding sleeve tool may be used in open-hole or cased-hole completions for vertical, deviated or horizontal wellbores. Embodiments of the sliding sleeve tool may be used for production and/or well treatment operations, such as stimulation treatment operations of conventional reservoirs or unconventional reservoirs. The invention may by particularly useful in unconventional reservoirs, such as shale gas, coal bed methane, tight gas, shale oil, and hard rock that may require multiple tracing and or acidising treatments with abrasive and corrosive proppants and or chemicals.

Referring now to Figure 1, an exemplary embodiment of a sliding sleeve tool will be described in relation to a horizontal open-hole completion. However, as pointed out earlier, the invention may be used in all types of completions and wells. Figure 1, is a diagrammatic view of a well pipe 10 comprising a plurality of sliding sleeve tools 20 deployed inside a horizontal wellbore 30.

An upper end of the well pipe 10 includes an upper anchoring tool 70 such as a liner hanger and packer that can be actuated to hang the well pipe 10 from a liner hanger 80 within the wellbore 30. At its leading end or toe ba the well pipe 10 has a guide shoe 90 that guides the well pipe toward the centre of the hole as the casing is lowered into the well. Adjacent to the guide shoe 90 there is a lower anchoring tool 92 for securing the lower part of the well pipe 10 to the wellbore 30. Different wellbore anchoring tools may be used that are well known in the art. Other tools 94, such as a flapper valve, may also be positioned in the well pipe 10 adjacent the guide shoe 90, in either side of the anchoring tool 92.

The well pipe 10 is divided into zones, (zones ito 2) corresponding to the areas or zones of the formation to be treated with the help of a plurality of packers 40.

However, it should be understood that the present invention may work equally well with one or more zones as may be required dependent upon the particular application.

Packers 40 may be of any type suitable to isolate the zones such as mechanical and/or swellable packers.

Each zone of the well pipe 10 comprises a sliding sleeve tool 20. Each zone may also comprise other tools such as a production tool 50, and/or a valve 60.

Referring now to Figures 2A to 2C, the sliding sleeve tool 20, used in the well pipe 10 of Figure 1 is further described.

Figure 2A is a diagrammatic illustration of one embodiment of the sliding sleeve tool 20 shown in a configuration when being deployed into the wellbore 30. This configuration is referred to also as a run in hole configuration.

The sliding sleeve tool 20 comprises an outer tubular housing 23 comprising one or more lateral flow ports 21 that may be selectively uncovered to provide a fluid path between the interior of the sliding sleeve tool 20 and the exterior of the well pipe 10. First and second annular sleeves 22 and 27 are positioned within the outer tubular housing 23. Wien the well pipe 10 is being deployed inside the wellbore 30 the sliding sleeve tool 20 is in its run in hole configuration, i.e. with the flow ports 21 covered by the first sleeve 22. In the present embodiment, the sliding sleeve tool 20 comprises one or more shear pins 25 that hold the sleeve 22 in this run in hole position. Other types of retainers could be used such as for example pushback pins, a spring and clasp combination, or the like. The shear pins 25 are designed to shear in the case of a mechanical overload permitting the first sleeve 22 to move.

In the present embodiment, the sliding sleeve tool 20 comprises a shifting mechanism for shifting the first sleeve 22 from a first position that covers flow pods 21 (as shown in Figure 2A) to a second position that uncovers the pods 21 (as shown in Figure 20).

The shifting mechanism comprises a ball seat 24 that is shaped and sized to engage a drop ball 26 as shown in Figure 28. Other objects could be used such as a dad.

Referring now to Figure 2B, once the well pipe 10 is in the desired place within the wellbore 30 and well treatment is to be initiated, a ball 26 is dropped to engage ball seat 24. Once a sufficient pressure or force is applied on the ball to break the shear pins 25, the sleeve 22 is released and shifts on to a second position (as shown in Figure 20) to uncover flow pods 21.

Other shifting mechanisms may also be used without departing from the scope of the present invention. For example, the sleeve 22 may comprise a shifting profile (not shown) for connecting to a shifting tool (not shown) for moving the first sleeve 22.

The shifting tool may be operated mechanically via a conveyance such as coiled tubing, slickline or wireline. In yet another embodiment the shifting mechanism may be operated hydraulically, electrically or the like.

Treatment fluids may then be pumped downhole through the well pipe 10 and into the surrounding formation through the flow pods 21. Treatment fluids may comprise water in high pressure containing sand or other proppants, other chemicals and or acidizing liquids depending upon the treatment procedure used for the particular zone.

In order to sequentially treat different zones of a multizone well, the ball seats 24 may decrease in diameter from the heel to the toe of the well. The smallest ball is dropped first and passes through all the larger ball seats until it lands on the seat closest to the toe of the well. Once the first zone has been treated, successively larger balls may then be dropped to initiate treatment for each subsequent zone.

The sliding sleeve tool 20 comprises a second sleeve 27 that is positioned within the outer tubular housing 23. The second sleeve 27 comprises a shifting profile 28 that permits a shifting tool (not shown) having a mating profile to engage the second sleeve 27 and shift it from a first position, as shown in Figures 2A to 2C, to a second position as shown in Figure 2D, whereby the second sleeve 27 covers the flow ports 21. The shifting tool may be deployed in and out of the well pipe to the desired position to engage the second sleeve 27 via a conveyance such as coiled tubing, wireline or slickline. In another embodiment, the flow ports 21 may be partially closed with the second sleeve 27 (not shown). Such partial closing of the flow ports may be advantageous both in well treatment as well as in production operations by allowing optimizing the overall design.

Other shifting mechanisms may be used for selectively moving the second sleeve 27 between the first and second positions. The shifting mechanism for the second sleeve may be operated mechanically or hydraulically. The shifting mechanism may allow multiple movements of the second sleeve 27 between its first and second positions.

The outer tubular housing 23 comprises a second retainer mechanism (not shown) for holding the second sleeve 27 in the first position. The second retainer mechanism may comprise one or more shear pins, pushback pins, a spring and clasp combination, or the like. Other retainer mechanisms may also be used without departing from the scope of the present invention.

The second retainer mechanism may be of a type that can be used multiple times. For example, the second retainer mechanism may comprise a plurality pushback pins, latch pins or the like.

The outer tubular housing 23 may have threaded or bolted connections at one or both ends for connection to a well pipe. Any type of suitable connections may be used.

The first and the second sleeves 22, 27 as described in the present exemplary embodiment shown in Figures 2A to 2D are made of solid surfaces without any flow ports. However, it should be understood that either sleeve may have one or more flow ports without departing from the scope of the present invention. For example, it will be appreciated by those skilled in the art that the sleeve 22 may comprise one or more ports depending on the design of the sliding sleeve tool 20. When the sleeve 22 is designed to contain one or more flow ports (not shown) the sleeve 22 may be shifted so that the flow ports 21 are aligned with the flow ports of the sleeve 22 to permit fluid communication between the interior of the sliding sleeve tool 20 and the wellbore 30.

Alignment may be achieved by various well known mechanisms including longitudinal shifting and/or annular rotation of the sleeve 22.

The outer tubular housing 23 may be made out of a single piece of pipe or may comprise two or more parts suitably connected together. For example, a first outer tubular part may house the first sleeve 22 and the one or more flow ports 21, while a second outer tubular part may house the second sleeve 23. The two parts of the outer tubular housing may be threaded or bolted together.

The sleeves 22 and 27 may be disposed within the outer tubular housing 23 as shown in Figures 2A to 2D. However, it should be understood that other configurations may also be employed. For instance, one or both of the sleeves 22 and 27 may be disposed outside the housing 23. The sleeves 22, 27 may be disposed within a suitably sized annular recess (not shown) formed at the exterior of the housing 23.

The sliding sleeve tool 20 may comprise other devices that are well known in the art such as for example a screen or sheath disposed between the sleeves 22 and the outer tubular housing 23. Such screens or sheaths may be used to protect the internal mechanism of the sliding sleeve tool 20 from exposure to extraneous or corrosive materials such as cement used during cementing operations, or acidic fluids used during acidizing operations.

In situations where the sliding sleeve tool 20 is used in a production environment to flow production fluids through ports 21, a sand screen or sheath may be used to prevent sand entering the well pipe 10.

It will be appreciated by those skilled in their art that the sliding sleeve tool 20 may be used in a variety of downhole environments and operations. The sliding sleeve tool 20 allows closing the flow ports 21 in a situation where the first sleeve 22 may not be reused either because it is designed for a single trip operation such as for example when it uses a drop-ball shifting mechanism, or because it may be damaged. For example, when the sliding sleeve tool 20 is used in fracing, or acidizing operations the first sleeve 22 may be damaged because of the corrosive nature of the fluids and proppants and other chemicals employed, rendering closing of the first sleeve and/or flow ports 21 problematic.

Often times the operation of the first sleeve 22 may require that the first sleeve is locked in place after uncovering flow ports 21 to prevent interference with the flow operation. After locking the first sleeve in its second position, unlocking it may be difficult, or impossible. For instance, when a ball seat and drop ball shifting mechanism is used for the shifting of the sleeve 22, the ball may need to be drilled out in order to establish fluid communication between adjacent sections of the well pipe. During drilling of the ball the sleeve 22 may also be damaged.

In yet other embodiments, the shifting mechanism of the sleeve 22 may be such that doesn't allow re-shifting of the sleeve 22 to its original run in hole configuration.

Having a second sleeve 27 that may be used to close the flow ports is advantageous and offers greater flexibility in operations. Preferably, the second sleeve may include shifting and retaining mechanisms that may be used multiple times.

Having the second sleeve 27 placed away from the flow ports 21 during abrasive flow operations such as fracing, stimulation, or production protects the second sleeve 27 from damage and allows employing the second sleeve 27 to shutting off zones later on in the life of a well.

The sliding sleeve tool 20 as shown in Figures 24 to 20 is made of a single outer tubular 23. However, it should be understood that the sliding sleeve tool 20 may be made of two or more parts that are affixed together. For example, two outer tubular housings 23 may be used. A first tubular housing may house a first sleeve 22 and the one or more ports 2land a second tubular housing may house the second sleeve 27.

It should be understood that the embodiments described herein are merely exemplary and that various other modifications may be made thereto without departing from the scope of the invention.

Claims

CLAIMS: 1. A sliding sleeve tool comprising: a tubular housing having one or more flow ports; a first sleeve slidably mounted with the tubular housing, wherein the first sleeve is moveable from a first position covering the one or more flow ports to a second position to uncover the one or more flow ports; and a second sleeve slidably mounted with the tubular housing, the second sleeve being movable from a first position wherein the second sleeve does not interfere with the operations of the first sleeve to a second position that at least partially covers the one or more ports to modify fluid flow.
2. The sliding sleeve tool according to claim 1, wherein the second sleeve is disposed initially at a sufficient distance from the one or more flow ports to prevent or minimize damage from operations relating to the first sleeve.
3. The sliding sleeve tool according to any of the preceding claims, further comprising a first retainer mechanism for holding the first sleeve in its first position.
4. The sliding sleeve tool according to claim 3, wherein the first retainer mechanism comprises one or more shear pins, push back pins, a spring and clasp combination, or a combination thereof
5. The sliding sleeve tool according to any of the preceding claims, further comprising a first shifting mechanism for moving the first sleeve from its first position to its second position permitting fluid flow.
6. The sliding sleeve tool according to claim 5, wherein the first shifting mechanism comprises a seat and mating object mechanism.
7. The sliding sleeve tool according to claim 5 or 6, wherein the first shifting mechanism comprises a ball seat and drop ball mechanism.
8. The sliding sleeve tool according to claim 5, 6 or 7, wherein the first shifting mechanism comprises a shifting profile for connecting with a mating shifting tool.
9. The sliding sleeve tool according to any one of claims 5 to 8, wherein the first shifting mechanism comprises an actuator configured to be operated to shift the first sleeve upon receipt of an actuation signal.
10. The sliding sleeve tool according to claim 9, wherein the actuation signal comprises at least one of a mechanical actuation signal, electromagnetic actuation signal, optical actuation signal, hydraulic actuation signal and acoustic actuation signal.
11. The sliding sleeve tool according to any of the preceding claims, further comprising a second shifting mechanism for shifting the second sleeve from its first position to its second position.
12. The sliding sleeve tool according to claim 11, wherein the second shifting mechanism comprises a sleeve and mating object mechanism.
13. The sliding sleeve tool according to claim 11 or 12, wherein the second shifting mechanism comprises a ball seat and drop ball mechanism.
14. The sliding sleeve tool according to claim 11, 12 or 13, wherein the second shifting mechanism comprises a shifting profile for connecting with a mating shifting tool.
15. The sliding sleeve tool according to any one of claims 11 to 14, wherein the second shifting mechanism comprises an actuator configured to be operated to shift the second sleeve upon receipt of an actuation signal.
16. The sliding sleeve tool according to claim 15, wherein the actuation signal comprises at least one of a mechanical actuation signal, electromagnetic actuation signal, optical actuation signal, hydraulic actuation signal and acoustic actuation signal.
17. The sliding sleeve tool according to any of the preceding claims, further comprising a second retainer mechanism for holding the second sleeve in its first position.
18. The sliding sleeve tool according to claim 17, wherein the second retainer mechanism comprises one or more shear pins, push back pins, a spring and clasp, or a combination thereof.
19. The sliding sleeve tool according to any of the preceding claims, wherein the first and second sleeves are annular.
20. The sliding sleeve tool according to any of the preceding claims, wherein at least one of the first sleeve and the second sleeve is mounted within the tubular housing.
21. The sliding sleeve tool according to any of the preceding claims, wherein at least one of the first sleeve and the second sleeve is mounted at an external surface of the tubular housing.
22. The sliding sleeve tool according to any of the preceding claims, comprising a sealing arrangement for providing sealing between at least one of the first sleeve and the second sleeve and the tubular housing.
23. The sliding sleeve tool according to any of the preceding claims, wherein the tubular housing comprises a unitary component.
24. The sliding sleeve tool according to any one of claims 1 to 22, wherein the tubular housing comprises two tubular parts that are connectable together.
25. The sliding sleeve tool according to claim 24, wherein the tubular housing comprises a first and a second tubular part that are connected together, the first tubular pad housing the one or more flow pods and the first sleeve, and the second tubular pad housing the second sleeve.
26. The sliding sleeve tool according to any of the preceding claims, further comprising a protective screen.
27. The sliding sleeve tool according to any preceding claim, wherein the second sleeve is movable to its second position to only partially cover the one or more pods to restrict fluid flow.
28. The sliding sleeve tool according to any preceding claim, wherein the second sleeve is movable to its second position to completely cover the one or more pods to prevent fluid flow.
29. The use of a sliding sleeve tool according to any of the preceding claims in a downhole operation.
30. The use of a sliding sleeve tool according to any of the claims 1 to 28, in a fracing, acidising, production operation or a combination thereof.
31. The use of a sliding sleeve tool comprising: deploying a well pipe within a wellbore, the well pipe comprising a sliding sleeve tool; moving a first sleeve of the sliding sleeve tool from a first configuration to a second configuration wherein one or more fluid pods are uncovered permitting fluid communication between the interior of the sliding sleeve tool and the wellbore; flowing a fluid through the fluid ports; and moving a second sleeve from a first configuration to a second configuration to at least partially cover the fluid pods to modify fluid communication between the interior of the sliding sleeve tool and the wellbore.
32. A downhole well system comprising a sliding sleeve tool according to any of the claims ito 28.
33. A method for controlling fluid communication between a wellbore and a well system within the wellbore, the method comprising: deploying a well system within a wellbore, the well system comprising a sliding sleeve tool; moving a first sleeve of the sliding sleeve tool from a first configuration to a second configuration wherein one or more fluid pods within the well system are uncovered permitting fluid communication between the well system and the wellbore; flowing a fluid through the fluid ports; and moving a second sleeve of the sliding sleeve tool from a first configuration to a second configuration to at least partially cover the fluid pods to modify fluid communication between the well system and the wellbore.
34. The method according to claim 33, comprising moving the second sleeve to only partially cover the one or more pods to restrict fluid flow.
35. The method according to claim 33 or 34, comprising moving the second sleeve to completely cover the one or more ports to prevent fluid flow.
36. The method according to claim 33, 34 or 35, wherein the well system comprises a plurality of sliding sleeve tools for controlling fluid communication between a plurality of well zones and the well system.