WO2016106447A1

WO2016106447A1 - Closable frac sleeve

Info

Publication number: WO2016106447A1
Application number: PCT/CA2015/000610
Authority: WO
Inventors: John Hughes; James W. Schmidt
Original assignee: Resource Completion Systems, Inc.
Priority date: 2014-12-30
Filing date: 2015-12-30
Publication date: 2016-07-07
Also published as: CA2916474A1

Abstract

A frac sleeve is taught that automatically shifts to the closed position after a frac. An intervention tool is used to assist both opening the sleeve and fracking the formation, and is the same tool that automatically controls the closing of the sleeve without employing the use of additional mechanism, either mechanical or hydraulic.

Description

CLOSABLE FRAC SLEEVE

Field of the Invention

This invention relates to frac sleeves that are closable after opening.

Background of the Invention Fracturing operations are often used in multi-stage horizontal wells whenever one or more opening are required for the purpose of injecting fluid from inside the casing or liner into the surrounding formation. After the stimulation fluid has been injected into the formation, it is often desirable to prevent injecting fluids and sand from immediately flowing unintended back into the wellbore thereby allowing the fractures to settle and properly cure. To do so, the frac sleeves or valves used in the multi-stage process must be closed. At a time afterwards, it may be desirable for such frac sleeves to be re-opened to establish communication between the formation and inside diameter of the casing or liner, such as for example, when the well is brought on production and hydrocarbons are to be produced from the formation into the casing or liner. In some cases, for any number of reasons it may be desirable to close the sleeve, if for example the well begins to produce water at a particular location. It may further be desirable to open some sleeves, while leaving other others closes, depending the production characteristics of adjacent stages.

Non-closable sleeves commonly used in the art are necessarily installed such that they are positioned far enough apart that the fracs will not connect. The frac pumped at stage number two for example should not break through the formation and connect with the fractures of stage number one. If they did connect, proppant would be pumped into the casing or liner through the frac ports of the first stage frac sleeve. In some wells it may be needed or desirable to reduce the spacing between stages is reduced. In the use of closable sleeves, stages can be placed closer together. If the fractures connect, proppant will not get pumped back into the liner as the frac ports may be closed on the sleeve adjacent to the lower stage.

As a field matures, secondary recovery methods are often used to extend the life of the wells. One method of secondary recover is water flood. As the natural drive mechanism for this reservoir becomes depleted, injected water is used to sweep the remaining recoverable hydro carbons from the formation towards a producing well. In such cases, it is preferable that closable frac sleeves can be re-opened or closed to maintain a controlled advance of the reservoir drive mechanism reducing the possibility of water coming into the producing wells. While some prior art frac sleeves may open and close, they do so by direct contact between the sleeve and the intervention tool and by an added physical movement.

To maximize flexibility and efficiency of fracking operations a need exists for closable sleeves that can be opened and closed automatically as the well is fractured and produced.

Summary of the Invention A frac sleeve is provided for use in fracturing and producing a subsurface formation. The frac sleeve comprises one or more frac ports; a valve moveable between a closed position in which the valve prevents fluid flow through said one or more frac ports and an open position in which the sleeve allows fluid flow through said one or more frac ports; an inlet port in

communication with an inside of the frac sleeve and with a first end of the valve; an outlet port in communication with an inside of the frac sleeve and with a second end of the valve; a removable isolation means positionable between the inlet port and the outlet port to isolate the inlet port from the outlet port to shift the valve to the open position, and removable to remove isolation between the inlet port and the outlet port and automatic valve closure means automatically operable to shift the valve to the closed position as the removable isolation means is removed. A method is further provided of fracturing and producing a subsurface formation. The said method comprises the steps of providing a frac sleeve having one or more fac ports and a valve; providing an inlet port in communication with an inside of the frac sleeve and with a first end of the valve and an outlet port in communication with an inside of the frac sleeve and with a second end of the valve; isolating the inlet port from the outlet port to create a differential pressure across the valve; shifting the valve to the open position; removing isolation between the inlet port and the outlet port; and automatically shifting the valve to the closed position.

Brief Description of the Drawings

The present invention will now be described in greater detail, with reference to the following drawings, in which:

Figure 1 is cross-sectional elevation view of a first embodiment of a frac sleeve of the present invention;

Figure 2 is a cross-sectional elevation view of a second embodiment of a frac sleeve of the present invention; Figure 3a is a cross sectional elevation view of one embodiment of an intervention tool of the present invention;

Figure 3b is a detailed cross sectional elevation view of one embodiment of an intervention tool of the present invention

Figure 4a is detailed cross-sectional view of the second embodiment of the present frac sleeve in a frac port closed position;

Figure 4a is detailed cross-sectional view of the second embodiment of the present frac sleeve in a frac port opened position;

Figures 5A to 5F are cross-sectional elevation views of one embodiment of the frac sleeve and intervention tool of the present invention, at various stages of operation, wherein: Figure 5A shows the intervention tool set inside the closable frac sleeve when the valve is in the closed run-in hole position; Figure 5B shows the valve sleeve shifted open during the stimulation treatment;

Figure 5C shows the valve sleeve shifted automatically to the closed position, post frac, after pressure equalization across the packer;

Figure 5D shows the re-introduction of the intervention tool to shift the valve to the open position;

Figure 5E shows the valve sleeve in the locked open position, when applied pressure has been bled off and pressure is equalized across the packer;

Figure 5F shows the valve sleeve in the closed position after pressure has been applied then bled off; Figure 6 is an illustration of one example of a J-Slot for use in the present invention;

Figure 7 is a cross sectional view of a further embodiment of the present fac sleeve and intervention tool;

Figures 8a to 8e are cross sectional views of the frac sleeve and intervention tools of Figure 7 at different sleeve open and sleeve closed stages; Figures 9a and 9b are cross sectional views of the frac sleeve of Figure 7 and a straddle tool for use with some embodiments of the present invention;

Figure 10 is a cross sectional view of a further embodiment of the frac sleeve and intervention tool of the present invention;

Figure 11 is a cross sectional view of one configuration of the frac sleeve and intervention tool of Figure 10 in a valve opened position;

Figure 12 is a cross sectional view of another configuration of the frac sleeve and intervention tool of Figure 10 in an alternate valve opened position;

Figure 13 is a cross sectional view of the configuration of the frac sleeve and intervention tool of Figure 12, in a valve closed position; Figure 14 is a detailed cross sectional vie of the intervention tool of Figure 10;

Figure 15 is a detailed cross sectional view of the frac sleeve of Figure 10; and Figure 16 is a process flow diagram of one method of the present invention.

Description of the preferred embodiments:

The present frac sleeve shifts to the closed position after a frac. The closing of the present sleeve happens automatically.

The present frac sleeve can be opened in a number of ways. In some embodiments, the frac sleeve may be opened by use of mechanical force. In other embodiments, the frac sleeve is opened by applied pressure. In all cases, the sleeve closes automatically, without the need to take separate steps or the need for external mechanisms to close the sleeve. In the case of using mechanic force to open the sleeve, a number of means may be utilized to accomplish this. In one embodiment, an intervention tool, run on a deployment string, may comprise a means of physically engaging the frac sleeve and applying mechanical force to a moving part of the frac sleeve in order to force it opened. When the mechanical force is removed, the present frac sleeve provides means for automatically closing. In another embodiment, a ball receiving seat may be installed in the frac sleeve and connected to the moving part. Seating of a ball upon the seat, moves the seat and the moving part to shift the frac sleeve to the open position. When the ball is pumped or otherwise moved off of the seat, or when the ball is drilled through, the present invention provides means for

automatically closing the sleeve. In the case of opening the sleeve by applied pressure, a pressure differential is created across a moving part of the frac sleeve by isolating a first end of the moving part from a second end of the moving part. With hydraulic pressure applied to the first end and low pressure experienced on the second end, the moving part is caused to shift to the open position. The pressure differential can be created by any number of means well known in the art, and any means of isolating pressure experienced by the first end from pressure experienced at the second end is encompassed by the present invention. When isolation is removed between the first end and the second end, the present invention provides means of automatically closing.

In a further preferred embodiment, the moving part is a valve and hydraulic pressure is applied to a first end of the valve via an inlet port communicating fluid from an inside of the frac sleeve. An outlet port at the second end of the valve allows fluid to be vented or displaced when the valve is moved from a closed position to an open position. When the inlet port is isolated from the outlet port, a pressure differential is created and the valve can be shifted open. When the isolation is removed, the inlet port and outlet port are pressure balanced and the valve closes. The present invention provides a means for automatically shifting the valve to the closed or locked open positions when isolation is removed.

For example, a pressure differential may be created by means of a seat positioned in the frac sleeve between the inlet port and the outlet port. Seating of a ball upon the seat allows fluid to enter the inlet port and hydraulic pressure to be applied to the first end of the valve. Lower pressure experienced on the isolated second end creates a pressure differential that acts to move the valve to shift the frac sleeve to the open position and fluid displaced by the moving valve is vented through the outlet port. When the ball is pumped or otherwise moved off of the seat, or when the ball is drilled through, the isolation between the inlet port and the outlet port is removed and present invention provides means for automatically closing the sleeve.

Other means of isolating the inlet port from the outlet port include pumping down any form of obstacle between the inlet and outlet ports, including plugs, cement. Alternatively, a profile may be formed on an inner surface of the frac sleeve and a blanking plug may be run downhole on wireline until it locates and engages with the profile to isolate the inlet port from the outlet port. In a further alternative embodiment, a bridge plug or a dissolvable bridge plug can be run downhole on a wireline, an electric wireline or a deployment string and set with a hydraulic setting tool to isolate inlet port from the outlet port. Furthermore, a small amount of cement may be pumped down to block the sleeve between the inlet and outlet ports. Such obstacles can be removed by any known means in the art including pumping off, drilling out, dissolving, degrading, breaking up, wearing away and other means that would be understood by a person of skill in the art and encompassed by the scope of the present invention.

In one embodiment of the present invention an intervention tool is used to assist both opening the sleeve and fracking the formation, and may aid in automatically closing the sleeve without employing the use of additional mechanism, either mechanical or hydraulic. In one

embodiment of the intervention tool, whenever the intervention tool is shifted to an equalized pressure position, the frac sleeve closes.

The force required to close the sleeve may be stored in a compressed spring acting against the valve or the force may be generated by a force imbalance within the sleeve created by hydrostatic pressure working against a biased piston. Alternatively any means of removing isolation between the inlet and outlet ports may also be used to automatically close the valve. Any other mechanism that creates a force to urge the sleeve closed or to the locked open position is included within the scope of the present invention.

With reference to Figures 1 and 2, two embodiments of the present sleeve 100 are shown, which are described generally here and individually in more detail below. Each sleeve comprises an outer mandrel 2 and an inner mandrel 4 and valve 6 or sleeve slidable in a chamber there between. The sleeve 100 further comprises a threaded top sub 8 and a threaded bottom sub 10 to connect the frac sleeve 100 to a casing or liner. Both the outer mandrel 2 and inner mandrel 4 have frac portsl2 aligned with one another. The frac ports 12 are isolated from each other by the valve 6 when the valve 6 is in closed position. When the valve 6 is in the open position, the inner and outer frac ports 12 are in fluid communication with one another.

The valve 6 remains in the closed position while the tool is being deployed into the wellbore and is preferably moved by applied pressure. Communication ports 28a and 28b in the inner mandrel 4 ensures that the valve 6 remains pressure balanced so long as port 28a is not isolated from port 28b. The closed valve 6 restricts communication from the inside of the casing or liner with the formation.

The valve 6 is preferably held in closed position with shear screws 30. With reference to Figures 3a and 3b, as well as Figure 5, an intervention tool 14, which is also known as a bottom hole assembly, or BHA may be used to create isolation between ports 28a and 28b. The intervention tool 14 is run on coiled tubing or any other kind of deployment string well known in the art, is inserted inside the inner mandrel 4, as seen in Figure 5A.

Preferably, one or more locating profiles 31 machined on an inner surface of the bottom sub 10 of the frac sleeve 100 matches with one or more locator blocks 36 on the intervention tool 14 to ensure that the intervention tool 14 locates precisely inside the closable frac sleeve 100.

Further preferably, the present intervention tool provides a triple locate feature in the form of an upset 37 on each of the locator blocks 36. The locator blocks are more preferably resiliently biased radially outwardly from the intervention tool 14, to ensure that they catch against locating profile 31. In a first feature, the intervention tool 14 is lowered until locator blocks 36 contact the bottom sub 10 of the sleeve 100. This action provides the coil tubing operator with an indication to stop the coil. However due to reaction time and pipe stretch commonly seen in coil tubing deployment, the end of the coil attached to the intervention tool 14 tends to continue at least some travel downhole. When this latter travel occurs, in a second feature, the locator block 36 travels further down bottom sub 10 until it engages a first groove 31a machined at locating profile 31. This first groove 31a acts as a stop and allows the intervention tool 14 to locate in the correct location inside the closable sleeve 100.

In the event that there is still further kinetic energy remaining in the coil tubing string and the intervention tool 14 is caused to move further downstream, in a third feature of the present intervention tooll4, the locator blocks 36 will snap out of the first groove 31a and travel downhole to snap into a second groove 31b. In this position, the upset 37 on the locator blocks 36 contacts a flank surface 39 on the second groove 31b which catches the upset 37 and provides resistance to stop the coil tubing string and the intervention tool 14 from moving any further. The second groove 31b further preferably strategically locates the intervention tool 14 inside the closable sleeve 100 in the correct location for actuation of the sleeve. The triple locate feature performs multiple tasks. It locates the closable sleeve 100 within the downhole string and then ensures the coil tubing and intervention tool 14 stop in the correct location. However, it is not enough to merely locate the closable sleeve 100; the intervention tool 14 must also remain in the correct place. The triple locate features ensure that the intervention tool 14 stays correctly positioned within the closable sleeve 100 in spite of a tendency for the coil tubing to stretch and continue some movement.

The present triple locate feature allows the present closable sleeve 10 to be manufactured in a shorter more compact format that prior art sleeves. This is because without a triple locate feature, closable sleeves need to be made long enough to allow the coil tubing and intervention too to travel far enough to remove all the stretch from the coil, while still locating within the sleeve.

When the intervention tool 14 locates the locating profiles 31 machined on the inner surface of the bottom sub 10 of the closable frac sleeve 100, reciprocation of the coil tubing indexes the intervention tool 14 to the set position. Other locating means are also encompassed by the scope of the present invention, including locating dogs or by estimating the location of the frac sleeve 100 in the wellbore and feeding a predetermined length of deployment string to reach the frac sleeve 100. A compressive force on the coil tubing sets the slips 16 of the intervention tool 14 and packs off the elastomeric sealing elements such as one or more packers 18 on the intervention tool 14 against the inner mandrel 4, to hydraulically isolate an uphole section of the inner mandrel from a downhole section of the inner mandrel and isolate port 28a from port 28b. At this time, a bypass valve 20 internal to the intervention tool 14 closes on seat 34. Fluid is pumped down either the annulus 22 between the intervention tool 14 and the frac sleeve 100, or inside the intervention tool 14 and through central bore 26 in the intervention tool 14. Fluid enters communication port 28a and fluid pressure builds up until shear screws 30 shear. Pressure differential from the fluid pressure uphole of the packers 18 and no fluid pressure downhole of the packers 18 moves the sleeve 6 from a closed to an open position. Fluid displaced by moving valve 6 in chamber 40 is vented through port 28b. One or more sealing members 60 ensure a fluid seal between the valve 6 and the outer mandrel 2 and inner mandrel 4 to prevent fluid leaks. The frac ports 12 are then in communication with the inside diameter of the casing or liner and the formation.

Stimulation fluid can be pumped down the inside of the intervention tool 14 or in the annular 22 between the intervention tool 14 and the frac sleeve 100. The embodiments of the intervention tool 14 illustrated in Figure 5 show an optional ball 72 and cage 74 at the uphole end of the tool 14. This embodiment is used in an annular frac in which fluid is pumped down the annular space 22 between the intervention tool 14 and the frac sleeve 100. It would be well understood by a person of skill in the art that the ball 72 and cage 74 could be removed from the intervention tool for the purposes of fracking down the deployment string and inside the intervention tool 14. Alternatively, the ball 72 may be present in the intervention tool 14, and sand jet perforator may be used to perforate one or more holes in the casing of the wellbore, with ball 72 blocking the inside of the deployment string and ensuring that pressure builds up sufficiently for the perforation. Then ball 72 may be pumped out of the deployment string and collected back up at surface, and then stimulation fluid can be pumped down inside the intervention tool 14. When the fracking is done, the intervention tool 14 may be pulled back out of the fracking sleeve 100 and moved upstream to the next stage of the formation to be fracked, as seen in Figure 3C, where the intervention tool 14 is starting to be pulled back up the string.

The present frac sleeve 100 is advantageously automatically closable after it has been opened.

In a first embodiment of the automatic closing means of the present invention, depicted in Figure 1, the present valve 6 is connected at a downhole end to a spring 32 which is biased to close the valve 6. Pressure differential of fluid flowing through the frac sleeve ports 12 overcomes the spring force and causes the valve 6 to open. It is to be noted that Figures 5A to 5F depict a second embodiment of the closable sleeve 100 of the present invention. However, for the purposes of describing specifically the various positions of bypass valve 20 of the intervention tool 14 only, Figures 5A to 5F are also referred to below in connection with the operation of the first embodiment of the closable sleeve 100 of Figure 1. It would be well understood by a person of skill in the art that the intervention tool 14 of the present invention could be used with any number of embodiments of the closable sleeve 100 of the present invention and the bypass valve 20 would work in a similar manner for all embodiments of the closable sleeve 100.

In the case of the embodiment of Figure 1, when fracking is complete, the intervention tool 14 is pulled out of the inner mandrel 4. As it is pulled up, bypass valve 20 is also automatically lifted uphole and off of its seat 34, as can be seen in the difference in position of the bypass valve 20 between Figures 5B (seated) and 5C (unseated), and high pressure wellbore fluid is allowed to flow from the annulus between 108 the intervention tool 14 and the frac sleeve 100 to inside 24 the intervention tool 14, out a downhole end 41 of the intervention tool 14 and into chamber 40 via port 28b, such that there is no longer isolation of port 28a from port 28b. As the fluid pressure is equalized on either side of the valve 6, the spring 32 urges the valve 6 back to a closed position, as seen in Figure 5C.

In the arrangement of intervention tool 14 shown in Figures 3 and 5, in order to close or open one frac sleeve 100 in a multi-stage string of multiple frac sleeves it is necessary for frac sleeves uphole of the present frac sleeve 100 to be closed, so that stimulation fluid is directed to the frac sleeve to be closed or opened, and not out to the formation via open uphole frac sleeves. As an alternative to closing all uphole frac sleeves, the present invention further contemplates that the intervention tool 14 of the present invention includes a cup style packer (not shown) uphole of port 28 to isolate the valve 6 not only from a downhole section of the string, but also from an uphole section. In this embodiment, stimulation fluid is pumped down the deployment string, into intervention tool 14 and out to close or open the valve 6.

Further alternatively, it may be desirable to close all of the frac sleeves in multi-stage system and selectively open on frac sleeve, to see what is being produced at that particular stage. This may be helpful in determining location of water zones in any of the stages and selectively deciding to close off such stages from production.

With reference to Figures 2, 4 and 5, as an alternate to a spring 32 that biases the sleeve 6 to a closed position, it is also possible to have an low chamber 54 as a means of biasing the valve 6 in a closed position. Fluid enters through the injection port 28a and shifts the valve 6 to the open position. Displaced fluid exits through the vent port 28b. When the valve 6 shifts to the open position due to applied pressure of fluid being pumped down either the annulus 22 or down the intervention tool inner bore 26, a low pressure chamber 54 is created as shown in Figure 4 B. When fluid is not being pumped down the annulus 22 or the inner bore 26 of the intervention tool 14, or when the intervention tool is not inserted, hydrostatic pressure generated by well bore fluid communicates with a downhole end the valve 6 via vent port 28b and pushes the valve 6 against the low pressure chamber 54 to shift the valve 6 back to a closed position.

Applied pressure after the intervention tool 14 is set pushes the valve 6 to the open position. A difference in piston areas working on each ends of the valve 6 ensures the movement of the valve 6 in the desired direction to open or close the frac sleeve 100. The piston area on the uphole end of the valve is smaller than the piston area on the downhole end. This imbalance in piston areas permits the creation of the low pressure chamber 54. It also causes the valve 6 to shift back to the closed position whenever downhole pressures are balanced between inlet port 28a and vent port 28b, for example, whenever the intervention tool 14 packers 18 are released.

As described above, any means may be applied inside the closable sleeve 100 to isolate port 28a from port 28b, and applied fluid pressure through communication port 28a and against an uphole end of the valve 6 pushes the valve 6 to the open position.

In one embodiment, the means of isolation takes the form of the intervention tool 14 installed inside the closable sleeve 100 to isolate port 28a from 28b. In such embodiment, opening the bypass valve 20 of the intervention tool 14, as described before introduces fluid into port 28b to balance hydraulic pressure on either side of valve 6 and the biased piston surface created by o-rings 60a and 60b causes valve 6 back to move to the closed or locked open position, which is further urged back to the closed or locked open position by the action of chamber 54 as it returns to wellbore pressure.

When the means of isolating port 28a from 28b is removed by any known means and fluid flows into chamber 70 through port 28b, to equalize pressure on either ends of the valve 6. The difference in diameter between o-ring 60a and 60b creates a piston surface, acted on by the fluid to cause the valve 6 to shift back to the either closed position or to a locked open position, described in more detail below. Furthermore, the valve 6 is pulled back to the closed or to the locked open position, by the biasing action of the chamber 54 contracting from a low pressure to wellbore pressure,. Optionally, a j-latch assembly comprising preferably a J-slot 44 and j-pins 46 of the j-ring 42 may ensure that the open, closed and locked open positions are held until another pressure differential is applied.

With reference to Figures 2, 5 and 6, a continuous jay slot having multiple jay pin positions preferably determines the mode of the closable sleeve 100. Optionally, a j-ring 42, with a j-slot profile 44 and a j-pin 46 may be incorporated to ensure that the valve 6 stays in the open position until the means of isolating port 28a from 28b is removed by any known means and pressure is equalized on both sides of the valve 6. Further preferably, a bearing 62 positioned between the j-ring 42 and the valve 6, allows the j-ring 42 to both rotate and reciprocate within the j-slot 44, without causing rotation of the sleeve 6. A collet 68 may or may not be provided to lock the valve 6 to j-ring 42 to ensure that they move together with a single stroke.

When the sleeve 6 is moved to the open position, a low pressure is created in chamber 54. Correspondingly, a downhole end of valve 6 abuts against shoulder 66. Shoulder 66 may also serve to prevent the j-ring 42 from hitting, with any force the end of the j-slot 44, should a j- latch assembly be used, thereby avoiding damage of the j-ring 42 and j-slot 44. Fluid in chamber 70, adjacent the second end of the valve is vented out through port 28b.

With every movement of the valve 6 from an open to a closed or to a locked open position, the J-pin 46 is moved into a specific series of positions in the J-slot 44. Each position aligns with an open or closed or locked open position, but does not allow the valve 6 to reciprocate back and forth unless there is an application or removal of pressure differential.

Whenever the valve 6 is shifted to the open position, the j-pins 46 navigate through the continuous j-slot 44 and ensure the j-ring 42 indexes to a position. Preferably one or more contact shoulders 48 of the j-ring 42 abut against a contact shoulder 50 machined onto an outer surface of the inner mandrel 4. The compressive load applied to the valve 6 is transferred into the shoulders 48, 50 thereby isolating the j-pins 46 from the compressive load. Since both the j-pins 46 and the j-slot 44 do not experience any direct force, they are isolated from any force that could cause surface deformation. This is desirable to avoid malfunction of the valve 6, which could prevent it from closing automatically.

After the stimulation treatment is complete, the intervention tool is pulled upwards and the bypass valve 20 is opened. As pressure equalizes on both downhole and uphole sides of the packers 18, wellbore pressure causes fluid to enter chamber 70 through vent port 28b and causes low pressure chamber 54 to return to wellbore pressure, thereby generating the force required to shift the valve 6 to the closed position. J-pins 46 navigate through this continuous j- slot 44 and index the j-ring 42 to the next position. The intervention tool 14 can then be removed from the closed frac sleeve 100 and moved to the next sleeve, while maintaining the desired closed position.

In a further preferred embodiment, an internal upset 52 machined on an outside surface of the inner mandrel 4 acts as a contact shoulder whenever the valve 6 shifts to the closed position. This internal upset 52 isolates both the j-pins 46 and j-slot 44 from forces that could cause surface deformation to the j-pins 46 or the j-slot 44. Surface deformation to either of these components could cause the valve 6 to malfunction and not shift properly.

With reference to Figures 5D and 5D, the present invention, intervention tool 14 can also be positioned inside a closed frac sleeve 100 that had previously been fracked. The intervention tool 14 can then be set as previously described. Applied pressure shifts the valve 6 to the open position. Whenever the pressure across the valve 6 is equalized by the removal of the intervention tool 14, the bypass valve 20 is pulled off of seat 34, allowing fluid to enter the downhole side of the frac sleeve 100 and equalize pressure, causing the valve 6 to be opened. Then, hydrocarbons from the producing formation can flow through the frac ports and into the well. Indexes to another position that locks the valve sleeve in the open position. The J-slot 44 also allows the frac sleeve 100 to open again after fracking, as seen in Figures 5D and 5E and closed again (Figure 5F). With reference to Figures 5E and 5D, if required, the present frac sleeve 100 can be shifted to the closed position again by deploying the

intervention tool 14 on the deployment string, locating and setting the intervention tool 14 inside the inner mandrel 4 of the frac sleeve 100 as previously mentioned. Applied pressure followed by pressure equalization index the valve 100 from the locked open position to the closed position.

The flat development of the continuous j-slot 44 shown on Figure 6 illustrates one set of examples of the position of the j-pin 46 relative to the jay slots that match the positions illustrated in Figures 5A through to 5F. In this particular example, the positions illustrated as "A" and "F" are the same on the j-slot 44.

In a further alternate embodiment of the present invention, it is possible for the present frac sleeve to be hydraulically opened and hydraulically, automatically closed. With reference to Figure 7, in this embodiment, the present frac sleeve 100 may comprise a first port 80, second port 82 and a third port 84. The sleeve also comprises a first upper locating profile 86 and a second lower locating profile 88. Instead of just one valve, the present embodiment of the frac sleeve 100 comprises an opening valve 90 and a closing valve 92, with second port preferably formed therebetween. With reference to Figure 8A, this shows the intervention tool 14 locating within the frac sleeve 100 in the second lower locating profile 88. In Figure 8B, the intervention tool 14 is pushed downhole to set the slips 16 and packing elements of the packer 18. In the intervention tool set position, the first port 80 and the second port 82 are exposed to applied pressure, while the third port 84 is isolated from the applied pressure. In Figure 8C, the frac sleeve 100 is shown with the opening valve 90 being pumped to the open position due to applied pressure entering through the second port 82. Displaced fluid can flow through the third port 84 and the closing valve 92 is pressure balanced due to both the first port 80 and the second port 82, which are on either side of the closing valve 92, being exposed to equal applied pressure. With reference to Figure 8D, this figure shows the intervention tool 14 re-positioned into the first upper locating profile 86. In this position of the intervention tool, the first port 80 is exposed to applied pressure while the second port 82 and third port 84 are isolated from applied pressure. In Figure 8E, the closing valve 92 is now pumped downhole by applied pressure to close the frac ports.

At this stage, the intervention tool 14 can be removed from the well. All the ports have been opened, fraced then closed. Another intervention tool, preferably in the form of a straddle tool 94 (Figure 9) can be run back into the well to shift the valves opened again if desired. In such preferred embodiment, cups on the straddle tool would preferably be positioned between the first port 80 and the second port 82, with a lower sealing element of the straddle tool set between the second port 82 and the third port 84.

With reference to Figure 9A, the straddle tool 94 can be positioned in the second lower locating profile 88. Pressure is applied down the coil tubing string between an upper cup 96 and lower packing element 98. Figure 9B illustrates the closing valve 92 of the frac sleeve 100 being pumped into the open position by applied pressure to establish communication with the formation.

In a further alternate embodiment, the present frac sleeve 100 can be hydraulically opened and mechanically closed. With reference to Figure 10, the intervention tool 14 is located and set inside the closable frac sleeve 100. In Figure 11, applied pressure through the intervention tool 14 or the annulus, opens valve 6 and the wellbore is fraced. With reference to Figure 12, the intervention tool 14 is released from its position in Figure 11 and pulled uphole until one or more closing dogs 102 on the intervention tool 14 engage one or more corresponding closing profiles 104 on valve 6. With reference to Figure 13, with the one or more closing dogs 102 physically engaging the valve 6, it is possible to pull the valve 6 to the closed position by simply pulling up on the intervention tool. Figure 14 shows a number of features in detail of this embodiment of the intervention tool 14 and Figure 15 shows a number of detailed features of this embodiment of the frac sleeve.

After the valve 6 is closed, the coil tubing and intervention tool can be reciprocated to release the one or more closing dogs 102 from the respective one or more closing profiles 104 on the valve 6, and the intervention tool can then be pulled uphole to a next sleeve.

As with all previous embodiments of the present closable frac sleeve, a j-latch assembly is preferably used to control and maintain the position of the valve 6 until it is desired to move it. In the case of the embodiment of Figures 10-15, there are four positions on the jay-latch to control which position the intervention tool 14 is in; in a first compression neutral position the intervention tool 14 is correctly located into the frac sleeve but not engaged; in a second compression position, the slips and pack-off element are set; in a third, tension neutral position in which the intervention tool is pulled back uphole, and in a fourth tension position in which the lower cone 106 is pulled under closing dogs 102 to cause the closing dogs 102 to engage inside closing profile 104.

The present closable frac sleeve 100 can be run in a cemented in application or it may be run with open hole packers when cement is not desired. Regardless of the method of installation, the sleeve 100 functions the same.

In a preferred embodiment, frangible inserts 56 may be placed in the outer frac ports 12 to eliminate cement from settling in the ports 12. In a further preferred embodiment, one or more fins (not shown) may be positioned around each of the one or more ports 12, and protrude radially from the outer mandrel 2 to reduce the thickness of the cement sheath proximal the ports 12, that the frac must penetrate before reaching the formation.

In the foregoing specification, the invention has been described with a specific embodiment thereof; however, it will be evident that various modifications and changes may be made thereto without departing from the broader scope of the invention.

Claims

Claims:

1. A frac sleeve for use in fracturing and producing a subsurface formation comprising; a. one or more frac ports; b. at least one valve moveable between a closed position in which the valve prevents fluid flow through said one or more frac ports and an open position in which the sleeve allows fluid flow through said one or more frac ports; c. an inlet port in communication with an inside of the frac sleeve and with a first end of the valve; d. an outlet port in communication with an inside of the frac sleeve and with a second end of the valve; e. opening means; and f. automatic valve closure means automatically operable to shift the valve to the closed position.

2. The frac sleeve of claim 1, wherein the opening means comprise a removable isolation means positionable between the inlet port and the outlet port to isolate the inlet port from the outlet port to create a hydraulic pressure differential and shift the valve to the open position.

3. The frac sleeve sleeve of claim 2, wherein the automatic valve closure means comprises a hydraulic means.

4. The frac sleeve sleeve of claim 3, wherein the automatic valve closure means a low

pressure chamber formed adjacent the valve.

5. The frac sleeve of claim 4, wherein said low pressure chamber is created when the

removable isolation means is positioned to isolate the inlet port from the outlet port to shift the valve to the open position.

6. The frac sleeve of claim 5, wherein the low pressure chamber is automatically compressible to shift the valve to the closed position when hydraulic pressure differential is removed between the inlet port and the outlet port.

7. The frac sleeve of claim 6, wherein said valve provides a difference in piston areas at each end thereof to form the low pressure chamber and to cause the valve to automatically shift to the closed position when pressure is balanced between the inlet port and the outlet port.

8. The frac sleeve of claim 2, wherein the removable isolation means is an intervention tool run on a deployment string and comprising one or more sealing members to provide isolation between the inlet port and the outlet port and wherein removal of the intervention tool causes the valve to shift automatically to the closed position.

9. The frac sleeve of claim 8, wherein hydraulic pressure is applied to the first end of the valve via an annulus between the frac sleeve and the intervention tool.

10. The frac sleeve of claim 8, wherein hydraulic pressure is applied to the first end of the valve via an inner bore of the intervention tool.

11. The frac sleeve of claim 8, wherein said intervention tool comprises one or more locator blocks for locating within one or more corresponding locator profiles formed on an inner surface of said frac sleeve wherein said one or more locator blocks are resiliently biased radially outwardly from a body of the intervention tool and wherein said one or more locator blocks each further comprise an upset formed thereon.

12. The frac sleeve of claim 11, wherein the one or more locator profiles of the frac sleeve comprise a pair of grooves axially spaced from one another along the inner surface of the frac sleeve, wherein a first of said pair of grooves receives said upset as the intervention tool is located in the frac sleeve and the second of said pair of grooves receives said upset as the intervention tool moves further downhole due to pipe stretch and reaction time.

13. The frac sleeve of claim 12, wherein the second of said pair of grooves comprises a flank surface engageable with said upset to prevent further downhole movement of the intervention tool.

14. The frac sleeve of claim 13, wherein engagement of the upset within the second of said pair of grooves locates the intervention tool sealing members between the inlet port and the outlet port of the frac sleeve.

15. The frac sleeve of claim 8, wherein said intervention tool comprises a bypass valve in an inner bore thereof, said bypass valve moveable from a first seated position in which applied hydraulic pressure is blocked from passing through said inner bore and applies hydraulic pressure to the first end of the valve; and a second unseated position in which applied hydraulic pressure is free to pass through the inner bore and serves to balance pressure between the inlet port and the outlet port to automatically shift the valve to the closed position.

16. The frac sleeve of claim 2 further comprising a j-latch assembly in moveable connection with said valve to maintain said valve in an open, closed or locked open position until application or removal of the pressure differential causes the valve to shift.

17. The frac sleeve of claim 16 wherein the j-latch assembly comprises a j-ring rotatably connected to the second end of the valve, said j-ring comprising a j-slot and one or more j-pins moveable to specific locations within said j-slot for maintaining specific positions of the valve.

18. The frac sleeve of claim 17, wherein when the J-pin is unmoveable in the specific position in the J-slot 44, until an application or removal of pressure differential occurs.

19. The frac sleeve of claim 18, wherein the j-ring comprises a first contact shoulders for abutment against a second contact shoulder machined into an inner mandrel of the frac sleeve to isolate one or more the j-pins from compressive loads

20. The frac sleeve of claim 19 comprising a third shoulder for abutment of the second end of the valve as it moves to the open position, to isolate the j-slot from impactive forces.

21. The frac sleeve of claim 20 further comprising an internal upset machined on an outside surface of the inner mandrel of the frac sleeve for abutment of the first end of the valve as it automatically shifts to the closed position, to isolate the one or more j-pins and the j-slot from impactive forces.

22. The frac sleeve of claim 1, wherein frac sleeve is re-openable after automatically closing by reintroduction of the isolation means between inlet port and the outlet port and application of pressure to the first end of the valve via the inlet port.

23. The frac sleeve of claim 22, wherein the frac sleeve is automatically closable after reopening by removal of the isolation means between the inlet port and the outlet port.

24. The frac sleeve of claim 2, wherein the at least one valve comprises an opening valve and a closing valve uphole from the opening valve, and further comprising: a. a third port in communication with the inside of the frac sleeve and located between the opening valve and the closing valve and also between the inlet port and the outlet port; wherein the isolation means is moveable from a first position in which the inlet port and the third port are isolated from the outlet port and differential pressure shifts the opening valve to the open position while the closing valve remains pressure balanced; and a second position in which the isolation means is moved to create a pressure differential across the closing valve to shift the closing valve automatically to close the port.

25. The frac sleeve of claim 24, further comprising: a. a first upper locating profile formed on an inner surface of the frac sleeve uphole of both the closing valve and the third port, and a second lower locating profile formed on an inner surface of the frac sleeve, downhole of the outlet port; and wherein the isolation means is an intervention tool, said intervention tool moving from the first position locating in the second lower locating profile to the second position locating into the first upper locating profile by which a pressure differential is created between the inlet port and the third port to shift the closing valve to close the frac ports.

26. The frac sleeve of claim 25 further comprising a second intervention tool in the form of a straddle tool deployable into the frac sleeve to shift the closing valve to an open position again after automatic closing.

27. The frac sleeve of claim 26, wherein the straddle tool comprises cups positionable

between the inlet port and the third port and a lower sealing element settable between the third port and the outlet port.

28. The frac sleeve of claim 1, wherein the automatic valve closure means comprises

mechanical means.

29. The frac sleeve of claim 28, wherein the isolation means comprises an intervention tool comprising one or more closing dogs, wherein the intervention tool is movable from a first position to isolate the inlet port from the outlet port were applied pressure on the first end of the valve through the inlet port shifts the valve to the open position; and a second position where the intervention tool is shiftable uphole until the one or more closing dogs engage one or more corresponding closing profiles on the valve, wherein removal of the intervention tool from the frac sleeve automatically pulls the valve to the closed position.

30. The frac sleeve of claim 29 wherein the intervention tool reciprocatable to release the one or more closing dogs from the one or more closing profiles such that the

intervention tool can be pulled uphole to a next sleeve.

31. The frac sleeve of claim 30 further comprising a j-latch assembly in moveable connection with said valve to maintain said valve in an open, closed or locked open position until application or removal of the pressure differential causes the valve to shift.

32. The fract sleeve of claim 31 wherein jay-latch assembly maintains the intervention tool in a position selected from a first compression neutral position locating the intervention tool into the frac sleeve; a second compression position setting one or more slips and sealing members of the intervention tool; a third, tension neutral position in which the intervention tool is movable back uphole, and a fourth tension position in which the closing dogs engage inside the closing profile.

33. A method of fracturing and producing a subsurface formation; said method comprising the steps of: a. providing a frac sleeve having one or more fac ports and at least one valve; b. providing an inlet port in communication with an inside of the frac sleeve and with a first end of the valve and an outlet port in communication with an inside of the frac sleeve and with a second end of the valve ; c. shifting the valve to the open position; and d. automatically shifting the valve to the closed position.

34. The method of claim 33 wherein shifting the valve to the open position comprises

isolating the inlet port from the outlet port to create a hydraulic differential pressure across the valve.

35. The method of claim 34, wherein automatically shifting the valve to the closed position comprises removing isolation between the inlet port and the outlet port.

36. The method of claim 35, further comprising creating a low pressure chamber adjacent the valve when the valve is shifted to the open position.

37. The method of claim 36, further comprising compressing the low pressure chamber when the isolation means is removed from between the inlet port and the outlet port, to automatically shift the valve to the closed position.

38. The method of claim 34, wherein isolating the inlet port from the outlet port comprises locating an intervention tool within the frac sleeve, said intervention tool comprising sealing means for isolating the inlet port from the outlet port.

39. The method of claim 38 wherein locating the intervention tool within the frac sleeve comprises: a. deploying the intervention tool downhole until a downhole end of the

intervention tool contacts the frac sleelve; b. lowering the intervention tool within the frac sleeve until an upset formed on each of one or more locator blocks formed on an outer surface of the intervention tool engages within a first of a pair of grooves formed on each of one or more locator profiles formed on an inner surface of said frac sleeve, wherein said one or more locator blocks are resiliently biased radially outwardly from a body of the intervention tool; c. allowing pipe stretch to deploy the intervention tool further downhole until the upset engages a second of said pair of grooves; d. catching said upset within said second of said pair of grooves to prevent further downhole movement of the intervention tool.

40. The method of claim 38 wherein isolating the inlet port from the outlet port further comprises seating a bypass valve within an inner bore of the internvention tool to prevent applied hydraulic pressure from passing through said inner bore.

41. The method of claim 40 removing isolation betwwn the inlet port and the outlet port comprises unseating the bypass vavle to allow applied hydraulic pressure to pass through the inner bore of the intervention tool and balance pressure between the inlet port and the outlet port to automatically shift the valve to the closed position.

42. The method of claim 34 further comprising maintaining said valve in an open, closed or locked open position until application or removal of the pressure differential causes the valve to shift.

43. The method of claim 42 wherein maintaining valve position comprises indexing one or more j-pins within a j-slot of a j-ring rotatably connected to the second end of the valve, wherein said one or more j-pins index to specific locations within said j-slot for maintaining specific positions of the valve.

44. The method of claim 35, further comprising shifting the valve to the open position after automatic closing by reintroducing the isolation means between inlet port and the outlet port and applying hydrualic pressure to the first end of the valve via the inlet port.

45. The method of claim 44, further comprising removal of the isolation means between the inlet port and the outlet port to automatically close the valve after re-opening.

46. The method of claim 35, further comprising providing, as the at least one valve, an

opening valve and a closing valve uphole from the opening valve, and a third port located between the closing valve and the opening valve and between the inlet port and the outlet port, and further comprising the steps of: a. moving the isolation means to a first position in which the inlet port and the third port are isolated from the outlet port and differential pressure shifts the opening valve to the open position while the closing valve remains pressure balanced; and b. moving the isolation means to a second position in which the isolation means creates a pressure differential across the closing valve to shift the closing valve automatically to close the port.

47. The method of claim 46, further comprising shifting the closing valve to an open

position again after automatic closing by deploying a second intervention tool in the form of a straddle tool into the frac sleeve.

48. The method of claim 47, wherein the straddle tool comprises cups positionable between the inlet port and the third port and a lower sealing element settable between the third port and the outlet port.

49. The method of claim 34, wherein automatically shifting the valve to the closed position comprises mechanically shifting the valve.

50. The method of claim 49, wherein isolating the inlet port from the outlet port comprises deploying and setting an intervention tool into said frac to isolate the inlet port from the outlet port; and further comprising: a. shifting the intervention tool uphole until one or more closing dogs formed on an outer surface of the intervention tool engage one or more corresponding closing profiles on the valve, b. removing the intervention tool from the frac sleeve to automatically pull the valve to the closed position.

51. The method of claim 50 further comprising reciprocating the intervention tool to release the one or more closing dogs from the one or more closing profiles.

52. The method of claim 50 further comprising maintaining said valve in a specific position until application or removal of the pressure differential causes the valve to shift.

53. The method of claim 52 wherein said specific position is selected from a first

compression neutral position locating the intervention tool into the frac sleeve; a second compression position setting one or more slips and sealing members of the intervention tool; a third, tension neutral position in which the intervention tool is movable back uphole, and a fourth tension position in which the closing dogs engage inside the closing profile.