Burst plug assembly with choke insert, fracturing tool and method of fracturing with same

A burst plug assembly for use in the fluid port of tubular fracturing tools to provide erosion resistance. The assembly has a body with an annular side wall and a closing wall closing the central bore of the annular side wall. A choke insert is retained in the central bore of the body to line the inner surface of the central bore. A groove in a face of the closing wall circumscribes a core in the bottom wall, and is sized and located so that a largest dimension of the core is no greater than a diameter of the inner bore of the choke insert, such that when a prescribed threshold hydraulic pressure level of the treatment fluid is applied to the closing wall the core disengages from the closing wall along the groove in a bursting action and passes through the inner bore of the choke insert.

FIELD OF THE INVENTION

The present invention relates to methods and fracturing tools for hydraulic fracturing of a wellbore, and more particularly to a burst plug assembly with a choke insert and to fracturing tools and methods of fracturing using same.

BACKGROUND

Hydraulic fracturing is a stimulation treatment which consists of propagating fractures in rock layers by the introduction of a pressurized treatment fluid. The treatment fluid is pumped at high pressure into the hydrocarbon bearing area of a wellbore that extends into the target reservoir. The high pressure fluid when hydraulically injected into the wellbore causes cracks or fractures which extend outwardly and away from the wellbore into the surrounding rock formation.

Depending on the nature of the reservoir and the particular rock formation, acid, chemicals, sand or other proppants are selectively mixed into the treatment fluid to improve or enhance the recovery of hydrocarbons within the formation.

There have been a number of recent developments with respect to wellbore treatment tools including the development of tubular fracturing strings for staged well treatment. Such fracturing strings are predicated on creating a series of isolated zones within a wellbore using packers. Within each zone there are one or more fluid ports that can be selectively opened from the surface by the operator. A common mechanism includes a sliding sub actuated by a ball and seat system, the movement of which is used to open fluid ports. By sizing the seats and balls in a complimentary manner, increasingly larger balls may be used to selectively activate a particular sliding sub allowing the operator to stimulate specific target areas.

Further development and refinement has resulted in fracturing strings having multiple fluid ports within each isolated zone. The seats and balls are sized such that one ball may be used to actuate a series of sliding subs within an isolated zone or a series of sliding subs in different isolated zones. This is achieved using seats that expand or deform to allow the ball to pass. The ball is deployed from the surface, travels down the well bore, and becomes lodged on the deformable seat to form a temporary seal. The fluid pressure on the ball and seat actuates the sliding sub from its initial, first position into its second position, and in the process opens the fluid port. With continued fluid pressure, the seat eventually deforms, allowing the ball to pass through the seat and down to the next sliding sub, where it actuates the next sliding sub in the same manner. The last or lowest seat in the isolated zone is sized such that the ball will not pass, thus forming a seal to prevent the flow of treatment fluid to any lower zones that may have already been actuated and treated. The use of multiple fluid ports allows multiple stages within the isolated zone to be stimulated with one surface treatment. This type of fracturing method is generally termed limited entry fracturing.

When using a fracturing string with multiple deformable seats and a single ball, as described above, the operator may encounter difficulties in fracturing the lower regions of the formation within the isolated zone. The reason for this problem is that the seats are designed so that greater fluid pressure is needed to push the ball past the lower situated seats than the higher situated seats. This greater fluid pressure may be sufficient to force the fluid from the fracturing string into the well bore and to fracture the formation surrounding the already opened higher fluid ports. This results in a loss of fluid which is counterproductive to increasing fluid pressure in the fracturing string. Accordingly, the operator may be unable to achieve sufficient fluid pressure to push the ball past the seats and actuate the sliding subs situated in the lower regions of the formation. Even if the operator can achieve sufficient pressure to activate the subs in the lower regions of the formation, the pressure may still be sub-optimal for stimulating the lower regions of the formation. Prior art solutions have enjoyed limited success and are relatively complicated.

More recent developments in fracturing have suggested the use of rupture disks or burst disks within the fracturing tools. For example, U.S. Patent Publication No. 2011/0192613 to Garcia et al., and U.S. Patent Publication No. 2015/0260012 to Themig describe fracturing tools having fluid ports covered with temporary port covers which are designed to gradually tear or erode to an open position with the use of erosive and/or corrosive treatment fluids. This can cause problems with the fracturing operation, since initial pumping rates to gradually erode or corrode the fluid covers are low and less predictable until the fluid cover is fully eroded to open the fluid ports. Low flow rates of fracturing fluids are generally not desirable since the treatment fluid is carrying sand, and “sanding off” or plugging of the fluid ports and other equipment can occur at low flow rates. As well, there is less precision in directing the treatment fluid to the desired area to be fractured while the treatment fluid is being pumped at low flow rates.

Applicant's earlier patent application, U.S. Patent Publication No. 2014/0102709 to Arabskyy, describes a fracturing tool and method in which the fluid ports of a fracturing tool are closed by a burst plug which is designed to allow treatment fluid to flow through the fluid port in response to a prescribed threshold hydraulic pressure level of the treatment fluid. Particularly for limited entry fracturing processes, this fracturing tool and method allows for greater reliability and precision for operators, since the opening pressure of the fluid ports is a prescribed threshold pressure that can be set considerably higher than the pressure needed to shift the sliding subs in a series of fracturing tools. Thus, the operator can be confident that the fluid ports are not opened below the prescribed threshold pressure of the burst plugs, thus preventing the escape of treatment fluids from the fluid ports within an isolated zone until the treatment fluid pressure has been raised to the level required for hydraulic fracturing.

More recent patents and patent applications describing fracturing tools with burst plugs include PCT Patent Publications WO 2015/095950, WO 2015/117221 and WO 2015/117224, all to Arabsky et al., and U.S. Pat. No. 9,228,421 to Kent et al.

In fracturing operations, reliable opening of the flow ports in the fracturing tools is important. Operators prefer reliable and predictable flow restrictions (i.e., flow area and diameter) at the flow ports when pumping fluid downhole. Erosion of the fluid ports, whether or not closed with burst plugs, remains problematic in fracturing operations, particularly in view of the erosive and/or corrosive nature of the treatment fluids.

SUMMARY OF THE INVENTION

A burst plug assembly is provided for use in a fluid port formed in a side wall of a tubular fracturing tool, the fluid port extending from an inner surface of a central bore of the fracturing tool to an outer surface of the fracturing tool. The burst plug assembly includes a body having an annular side wall and a closing wall. The side wall has an inner surface and an outer surface, the outer surface being adapted to retain and seal the body in the fluid port of the fracturing tool, and the inner surface forming an outwardly opened central bore which is closed by the closing wall. The closing wall has opposed inner and outer faces, with the outer face facing the central bore of the body. A choke insert is retained in the central bore of the body and lines the inner surface of the annular side wall along the central bore. The choke insert forms an inner bore which extends through the choke insert. The choke insert is formed of a wear resistant material. A groove formed in one or both of the inner and outer faces of the closing wall circumscribes a core in the closing wall. The groove is sized and located so that a largest dimension of the core is no greater than a diameter of the inner bore, such that when a prescribed threshold hydraulic pressure level of a treatment fluid is applied to the closing wall, the core disengages from the closing wall along the groove in a bursting action and passes through the inner bore of the choke insert, so that the treatment fluid can be pumped under pressure through the inner bore with limited erosion of the inner bore of the choke insert.

In some embodiments of the burst plug assembly, the core is circular and the diameter of the groove and the diameter of the inner bore are sized such that the inner bore is fully open after the core disengages, so that continued pumping of the treatment fluid through the inner bore maintains a prescribed flow rate of the treatment fluid sufficient for fracturing a wellbore adjacent the burst plug assembly without significant variation due to erosion of the inner bore of the choke insert.

In some embodiments of the burst plug assembly, the closing wall is a bottom wall formed integrally with the annular side wall at an inward end portion of the side wall. In some embodiments, the inner surface of the annular side wall and an outer surface of the choke insert are formed with engaging threads to retain the choke insert in the central bore and to provide a metal to metal seal between the body and the choke insert. In some embodiments, the groove is formed in the inner face of the bottom wall, and a portion of the bottom wall extending between the annular side wall and the groove forms a seat for the choke insert, so that after the circular core disengages, the groove forms a lip to direct the treatment fluid into the inner bore while preventing the treatment fluid from penetrating the engaging threads between the choke insert and the body. In some embodiments, the choke insert extends along the entire inner surface of the annular side wall.

Also broadly provided is a fracturing tool for use in a fracturing string for hydraulically fracturing a wellbore with treatment fluid using a prescribed threshold hydraulic pressure level. The fracturing tool includes a tubular housing extending longitudinally between opposing first and second ends arranged for connection in series with the fracturing string. The tubular housing has an inner surface defining a central bore extending through the tubular housing from the first end to the second end, and a fluid port extending from the inner surface to an outer surface of the tubular housing for fluid communication between the central bore and the wellbore. A burst plug assembly as set out above is retained and sealed in the fluid port. The burst plug assembly is operable from a closed condition, in which the burst plug assembly maintains a fluid seal to prevent the treatment fluid flowing through the fluid port below the prescribed threshold hydraulic pressure level, to an open condition, in which the core passes through the inner bore and the burst plug assembly is opened in response to the prescribed threshold hydraulic pressure level of the treatment fluid to allow the treatment fluid to flow through the inner bore of the burst plug assembly. A closure member is supported within the central bore of the tubular housing and is operable between a first position in which the burst plug assembly is covered by the closure member and a second position in which the burst plug assembly is substantially unobstructed by the closure member.

In some embodiments, the fracturing tool includes a plurality of fluid ports circumferentially spaced about the tubular housing and oriented substantially perpendicularly to a longitudinal axis of the tubular housing, and the burst plug assembly is retained and sealed in each of the plurality of fluid ports.

In some embodiments, the closure member is a sliding sleeve having a seat formed therein and operable to shift from the first position to the second position when the actuating member is seated and sealed on the seat.

In some embodiments, particularly for limited entry, multi-fracturing operations, the fracturing tool includes a closure member which includes a sleeve member supported within the central bore of the tubular housing so as to be longitudinally slidable relative to the tubular housing between the first position in which the burst plug assembly is covered by the sleeve member and the second position in which the burst plug assembly is substantially unobstructed by the sleeve member. The sleeve member includes a central passageway extending longitudinally therethrough, and a deformable seat disposed in the central passageway. The deformable seat is operable between a first condition in which the deformable seat is adapted to receive the actuating member seated thereon and a second condition in which the deformable seat is adapted to allow the actuating member to pass through the central passageway. The deformable seat is operable from the first condition to the second condition only upon displacement of the sleeve member into the second position. Seals are operatively supported between the sleeve member and the tubular housing to prevent leaking of the treatment fluid from the tubular housing to the at least one fluid port in the first position of the sleeve member.

Also broadly provided is a method of hydraulically fracturing an isolated zone in a wellbore using a treatment fluid which can achieve a prescribed threshold hydraulic pressure level. The isolated zone may be isolated with a cement liner or with a plurality of packers. The method includes the following steps:

i) providing a fracturing tool in a fracturing string spanning the isolated zone of the wellbore, the fracturing tool comprising:a tubular housing having an inner surface defining a central bore and a fluid port extending through a side wall of the tubular housing,a burst plug assembly retained and sealed in the fluid port, the burst plug assembly being operable from a closed condition, in which the burst plug assembly maintains a fluid seal to prevent the treatment fluid flowing through the fluid port below the prescribed threshold hydraulic pressure level, to an open condition, in which the burst plug assembly is opened in response to the prescribed threshold hydraulic pressure level of the treatment fluid, the burst plug assembly having a choke insert formed with an inner bore such that, in the open condition the treatment fluid flows through the inner bore, the choke insert being formed of a wear resistant material; anda closure member supported within the central bore of the tubular housing operable between a first position in which the burst plug assembly is covered by the closure member and a second position in which the burst plug assembly is substantially unobstructed by the closure member;

ii) locating the fracturing tool in a fracturing string spanning the isolated zone of the wellbore with the closure member in the first position;

iii) moving the closure member to the second position;

iv) pumping the treatment fluid to achieve the prescribed threshold hydraulic pressure level to open the burst plug assembly in the fluid port; and

v) continuing pumping the treatment fluid under pressure through the inner bore of the burst plug assembly at a prescribed flow rate sufficient for hydraulically fracturing the isolated zone adjacent the burst plug assembly without significant variation due to erosion of the inner bore of the burst plug assembly.

In some embodiments, of the method, the closure member comprises a sleeve member sealed within the central bore of the tubular housing so as to be longitudinally slidable relative to the tubular housing, in response to an actuating member being seated within the sleeve member, between the first position in which the burst plug assembly is covered by the sleeve member and the second position in which the burst plug assembly is substantially unobstructed by the sleeve member. The sleeve member is moved to the second position by directing the actuating member through the tubing string to seat in the sleeve member to displace the sleeve member into the second position, and to seal against the flow of the treatment fluid past the sleeve member at an actuation hydraulic pressure level of the treatment fluid which is less than the prescribed threshold hydraulic pressure level of the treatment fluid.

In some embodiments of the method, the fluid port is one of a plurality of fluid ports circumferentially spaced about the tubular housing and oriented substantially perpendicularly to a longitudinal axis of the tubular housing, with the burst plug assembly as set forth above retained and sealed in each of the plurality of fluid ports. In such embodiments, continued pumping of the treatment fluid under pressure is continued through the inner bore of each burst plug assembly at the prescribed flow rate without significant variation due to erosion of the inner bore of any one of the burst plug assemblies.

In some embodiments, the method is adapted for hydraulically fracturing multiple stages within a lower isolated zone in the wellbore with the treatment fluid which can achieve a prescribed threshold hydraulic pressure level. The method includes the following steps:

a) providing a plurality of the fracturing tools, each of the plurality of the fracturing tools being connected in series with one another in a fracturing string spanning the lower isolated zone such that each of the plurality of the fracturing tools is associated with a respective stage of the lower isolated zone, wherein the closure member of each of the plurality of fracturing tools comprises:a sleeve member supported within the central bore of the tubular housing so as to be longitudinally slidable relative to the tubular housing between the first position in which the burst plug assembly is covered by the sleeve member and the second position in which the burst plug assembly is substantially unobstructed by the sleeve member, the sleeve member comprising:a central passageway extending longitudinally therethrough; anda deformable seat disposed in the central passageway so as to be operable between a first condition in which the deformable seat is adapted to receive the actuating member seated thereon and a second condition in which the deformable seat is adapted to allow the actuating member to pass through the central passageway, the deformable seat being operable from the first condition to the second condition only upon displacement of the sleeve member into the second position; and

seals operatively supported between the sleeve member and the tubular housing to prevent leaking of the treatment fluid from the tubular housing to the at least one fluid port in the first position of the sleeve member;

b) providing a lowermost of the fracturing tools in the fracturing string below the plurality of the fracturing tools, the closure member of the lowermost fracturing tool comprising a sliding sleeve having a seat formed therein and operable to shift from the first position to the second position when the actuating member is seated and sealed on the seat;

c) providing one of the actuating members to be associated with the plurality of fracturing tools and the lowermost fracturing tool associated with the lower isolated zone;

d) directing the actuating member associated with the lower zone downwardly through the fracturing string to sequentially displace the sleeve member of each of the plurality of the fracturing tools associated with the lower isolated zone into the second position at an actuation hydraulic pressure level of treatment fluid which is less than the prescribed threshold hydraulic pressure level of treatment fluid;

e) locating and seating the actuating member within the lowermost fracturing tool associated with the lower isolated zone so as to shift the sliding sleeve to the second position and to form a seal against a flow of the treatment fluid;

f) pumping the treatment fluid to achieve the prescribed threshold hydraulic pressure level to open the burst plug assembly in the fluid port of the plurality of the fracturing tools and the lowermost fracturing tool associated with the lower isolated zone; and

g) continuing pumping the treatment fluid under pressure through the inner bore of each burst plug assembly of the plurality of the fracturing tools and of the lowermost fracturing tool associated with the lower isolated zone at a prescribed flow rate sufficient for hydraulically fracturing the lower isolated zone adjacent each of the burst plug assemblies without significant variation due to erosion of the inner bore of any one of the burst plug assemblies.

In some embodiments of the method of fracturing multiple stages, the fluid port is one of a plurality of fluid ports circumferentially spaced about the tubular housing of each of the plurality of fracturing tools and the lowermost tool, and oriented substantially perpendicularly to a longitudinal axis of the tubular housing, with a burst plug assembly as set forth above retained and sealed in each of the plurality of fluid ports.

In some embodiments of the method of fracturing multiple stages, the method further includes hydraulically fracturing multiple stages within an upper isolated zone above the lower isolated zone by the steps of:

h) providing the plurality of the fracturing tools as set forth above, each of the plurality of the fracturing tools being connected in series with one another in a fracturing string spanning the upper isolated zone such that each of the plurality of fracturing tools is associated with a respective stage of the upper isolated zone;

i) providing the lowermost fracturing tool as set forth above in the fracturing string below the plurality of the fracturing tools of step h);

j) providing one of the actuating members to be associated with the plurality of the fracturing tools and the lowermost fracturing tool associated with the upper isolated zone;

k) repeating steps d) to g), but adapted to hydraulically fracture the wellbore within the upper isolated zone.

DETAILED DESCRIPTION

The invention relates to a burst plug assembly22, a fracturing tool10, and methods for hydraulic fracturing within an isolated zone in a wellbore. As generally shown in the Figures, the fracturing tool10includes:

i) a tubular housing12which may be connected in series with a fracturing string with one or more fluid ports20communicating between a central bore18of the housing12and the wellbore,

ii) a burst plug assembly22disposed in each fluid port20,

iii) a closure member such as a sleeve member24operable within the housing between a first position covering the fluid ports20and a second position in which the burst plug assemblies22are exposed.

For multi-frac methods, the closure member is typically a sleeve member24which include a deformable seat26defined by dogs34disposed within a central passageway32in the sleeve member24. However, other closure members actuable mechanically or by pressure between a position covering the ports and a position in which the ports are uncovered, may be included, as are well known for fracturing operations.

The deformable seat26is operable from a first condition arranged to receive an actuating member36seated thereon to a second condition in which the actuating member36is arranged to pass through the tool10only once the sleeve member24has been displaced from the first position to the second position. Once the sleeve member24is in the second position and the deformable seat26is displaced into the second condition, the actuating member36is free to pass through the tool10to the next tool in the fracturing string in a series of tools associated with an isolated zone.

The actuating member36may be directed downwardly through the fracturing string, or tubing string, to be seated on the deformable seats26of respective tools10by various methods including mechanical actuation and pressure actuation. In the instance of mechanical actuation, the actuating member36can be supported at the bottom end of a tubing string so as to be displaced downwardly through the fracturing string to actuate respective fracturing tools10by injecting the tubing string into the fracturing string. When multiple different diameter actuating members36are provided for being associated with different isolated zones respectively, the tubing string used to convey the actuating member36has an outer diameter which is less than a smallest diameter actuating member36being used. In addition to different methods of actuation, the configuration of the actuating member36itself may take various different forms as described below.

An embodiment of a pressure actuated fracturing tool10is shown inFIGS. 1 to 6, in whichFIG. 1is an external perspective view of one embodiment of the tool10of the present invention, whileFIGS. 5 and 6show cross-sectional side views. The tool10includes the tubular housing12extending longitudinally between a first end14and an opposing second end16arranged for connection in series within the fracturing string. The tubular housing12has an inner surface13and an outer surface15, the inner surface13defining a central bore18extending along the longitudinal axis of the tubular housing12from its first end14to its second end16. Both the first end14and the second end16of the tubular housing12are configured to attach to a fracturing string such that the tool10may be installed into a fracturing string.

The tubular housing12has at least one fluid port20extending from the outer surface15to the inner surface13of the tubular housing12from the central bore18in an orientation that is substantially perpendicular to the longitudinal axis of the tubular housing12. The fluid ports20allow fluid communication between the central bore18of the tubular housing12and the wellbore. In some embodiments a plurality of fluid ports20are positioned circumferentially around the tubular housing12as shown inFIG. 1. Each fluid port has a burst plug assembly22disposed therein. In some embodiments the burst plug assembly22is retained in the fluid port20by a threaded connection. In other embodiments the burst plug assembly is retained by a retaining ring, such as a snap ring.

The burst plug assemblies22are described in greater detail below. In general, each burst plug assembly is operable from a closed condition in which the burst plug assembly22prevents the treatment fluid flowing through the respective fluid port to an open condition in which the burst plug assembly22is arranged to allow treatment fluid flowing through the respective fluid port20. The burst plug assemblies22are opened from the closed condition in response to the treatment fluid reaching a prescribed threshold hydraulic pressure level. In some embodiments, the burst plug assemblies include a body200formed from a material with consistent mechanical properties, for example a metal such as brass, bronze or aluminum, which is arranged to burst in response to the prescribed threshold hydraulic pressure level of the treatment fluid.

In the closed condition, the burst plug assembly22acts as a barrier preventing fluid communication between the central bore18and the wellbore. The burst plug assemblies22are configured to maintain their physical integrity, and thereby maintain a fluid seal, up to a certain threshold fluid pressure level. When the threshold fluid pressure is reached within the central bore18of the tubular housing12, the burst plug assemblies22open, in a bursting action, and the flow of fluid from the central bore18to the wellbore through the fluid ports20occurs. For example, in some embodiments, the burst plug assemblies22open at a fluid pressure of approximately 4000 psi (pounds per square inch).

In this instance, pressure in the treatment fluid can be gradually pumped up to the threshold fluid pressure level prior to the burst plug assemblies22being opened, so as to store considerable potential energy in the fluid. By arranging all of the burst plug assemblies22within one tool10, or a series or tools, spanning one isolated zone in a fracturing string to open at substantially the same threshold fluid pressure level, the stored energy can be quickly or suddenly discharged throughout all of the isolated zone to improve frac initiation throughout the isolated zone.

The sleeve member24provides a tubular sleeve having a central fluid passageway25and is slidably mounted within the central bore18of the tubular housing12such that the central fluid passageway25of the sleeve24is orientated in the same manner as the central bore18of the tubular housing12, and such that the tubular housing12and the sleeve24share a common longitudinal axis.

For multi-frac operations, the sleeve24is includes a deformable seat26and an interconnected upper collar28. In one embodiment, the upper collar28and the seat26attach by means of complimentary, engaging threads. The sleeve24slides along the longitudinal axis of the tubular housing12in a direction towards the second end16of the tubular housing12.

The sleeve24is moveable between a first position shown inFIG. 5whereby the collar28is positioned such that it covers the fluid ports20blocking the flow of fluid from the central bore18to the fluid ports20, and a second position shown inFIG. 6whereby the collar28no longer covers the fluid ports20and the fluid ports20are exposed to fluid in the central bore18.

In some embodiments, shear pins30are utilized to releasably hold the sleeve24in its first position pending actuation as will be described below. One skilled in the art will understand that other suitable means as commonly employed in the industry may also be used to releasably hold the sleeve24pending actuation.

The seat26is shaped to form a constriction32in the central passage25. A plurality of dogs34are mounted within machined bores formed in the constriction32and orientated in a direction that is substantially perpendicular to the longitudinal axis of the central bore18and central passageway25. As shown in the cross sectional end view shown inFIG. 2, the dogs34extend into the central passageway25.

The actuating member36in this instance comprises a ball. When an appropriately sized ball36is discharged into the fracturing string with treatment fluid, it moves down the string until it becomes lodged on the dogs34of the seat26as shown inFIG. 3. The ball36blocks the constriction32in the central passageway25and reduces the flow of fluid through the central fluid passageway25. The pressurized treatment fluid exerts a hydraulic force on the ball36and seat26, breaking the shear pins30and causing the slidable seat26and attached collar28to move towards the second end16of the tubular housing12. It is not necessary that the ball36and the seat26create a perfect seal against the flow of fluid. Rather, the ball36and the seat26need only reduce the flow of fluid to create a sufficient pressure differential upstream and downstream of the ball36so that the resultant force is sufficient to actuate sleeve24and, as discussed below, drive the ball through the sleeve26.

The tubular housing12is machined such that there is a recess38in the inner wall of the tubular housing12that allows the expansion of the dogs34. As the sleeve24slides towards the second end18of the tubular housing12the dogs34meet and expand into the recess38as shown inFIG. 4. As the dogs34expand outwardly into the recess38, they retract slightly from the central passageway25. This retraction allows the ball36to pass, as shown inFIGS. 4 and 6. At the same time as the dogs34expand into the recess38, a machined groove40in the seat26mates with a projection42on the inner surface13of the tubular housing12, to lock the sleeve24into its second actuated position.

As can be seen inFIG. 6, at this point, the collar28no longer covers the fluid port20, so that the fluid port20and the burst plug assembly22are exposed to treatment fluid within the central bore18. Although the embodiment described above uses dogs34to form the deformable seat, such suggestion is not intended to be limiting and one skilled in the art will appreciate that other ball and seat mechanisms commonly employed in the industry may be used instead.

In this manner, one actuating member36can be used to actuate a series of tools10having the same sized seat26. The tools10may be placed in series in the string and are isolated by conventional isolating means, such as packers or cement, to define the isolated zone to be stimulated. The last, or lowermost, fracturing tool in the zone has a seat within a sliding sleeve sized such that, even after actuation into its second position, the ball36is not able to pass through the seat26, but instead seals on the seat26. This prevents the flow of fluid to lower zones. It can be understood that by using balls of increasing diameter, and starting with a ball having the smallest diameter, a series of isolated zones, starting with the one furthest from the well head, may be sequentially activated. For example, two to ten tools may be placed in each isolated zone. Thus, a fracturing string having ten packer isolated zones, with each zone containing ten tools, will allow an operator to stimulate one hundred stages, with just ten surface treatments.

As can be seen in the Figures, a series of seals44are positioned throughout the tool10so as to be operatively supported between the sleeve member24and the tubular housing12, and straddling the flow ports20, such that the sleeves24prevent the leak of treatment fluid from the tubular housing to the fluid ports20in the first position of the sleeve member24which would impair the ability maintain elevated hydraulic pressures.

Operation of the tool10in a method of fracturing will now be described. A tubing string with one or more of the present tools10is lowered into the wellbore. Conventional isolation means, such as packers mounted on the string or a cement lining, are used to create isolated treatment zones.

Each isolated treatment zone may contain one or more of the present tools10. According to the embodiment ofFIGS. 1 through 6, a ball36is placed into the treatment fluid and is introduced to the string. The ball passes through the string until it becomes lodged on the seat26of a tool in the target isolated zone. The operator increases the pressure of the treatment fluid. In one embodiment, the pressure is increased to approximately 2000 psi. The ball36is pressed against the dogs34urging the sleeve24into its second position, and displacing the dogs34radially outward into the recesses38so that the ball36may pass through the sleeve24. The fluid ports20on the actuated tool10are now exposed to the treatment fluid passing down the string and through the central bore18, but the burst plug assembly22prevents fluid communication with the wellbore. The same process is repeated for each respective tool10located in the selected zone until the ball36reaches the final tool10which is sized to prevent its passage even after the sleeve24is moved into its second position. At this point, the fluid ports20of all of the actuated tools10are uncovered, but not yet open. The operator then pressurizes the treatment fluid to the level needed to hydraulically fracture the well bore. Upon reaching the threshold pressure, in one embodiment 4000 psi, the burst plugs22all open at generally the same time and the opened fluid ports20allow fluid communication with the wellbore. There is no compromise in the pressure of the treatment fluid and all of the stages within the isolated zone are exposed to treatment fluid at the desired high pressure levels.

The use of fluid ports20covered by a collar28and each having a burst plug assembly22, is simple, effective and relatively economic. The burst plugs22prevent fluid communication with the well bore until the treatment fluid has been pressured to the levels needed to hydraulically fracture the wellbore. Furthermore, the burst plugs22facilitate simultaneous fluid communication with the wellbore through all opened fluid ports in the isolated zone.

The tool10ofFIGS. 1-6can also be milled out increase production. The ball36flows back up the fracturing string during the recovery phase of the fracturing operation.

Turning now to the second embodiment ofFIGS. 7 through 10, a further example of a pressure actuated fracturing tool10will now be described in further detail. The second embodiment differs from the first embodiment primarily with regard to the configuration of the deformable seat26and the configuration of the actuating member36arranged to be seated on the deformable seat26as described below.

In the second embodiment, the configuration of the tubular housing12is substantially identical in that there is provided a central bore18defined by the inner surface13extending longitudinally between the opposing first end14and second end16arranged for connection in series with the fracturing string. The fluid ports20are similarly circumferentially spaced about the tubular housing12so as to extend radially from the inner surface13to the outer surface15for fluid communication between the central bore18and the wellbore. A burst plug assembly22is disposed in each fluid port20to prevent the treatment fluid flowing through the fluid port20until the burst plug assembly is opened by exposure to the prescribed threshold hydraulic pressure level of the treatment fluid.

The sleeve member24of the second embodiment is also similarly supported within the central bore18of the tubular housing12so as to be longitudinally slidable relative to the tubular housing12between the first position in which the fluid ports20are covered by the sleeve member24and the second position in which the fluid ports20are substantially unobstructed by the sleeve member24.

As in the previous embodiment, the tubular housing12includes a central portion of increased internal diameter which receives the sleeve member24therein. The sleeve member24is again formed of an upper collar28and a lower collar threadably connected to the upper collar28to define the deformable seat26. The upper collar28and the lower collar are arranged so that they have a common outer diameter received within the central portion of the tubular housing12so as to be longitudinally slidable therein. An inner diameter of both the upper and lower collars forming the sleeve member24in this embodiment is constant across the full length of the sleeve member24in the longitudinal direction of the string in which the inner diameter is substantially identical to the inner diameter of the inner surface13of the tubular housing12at end portions at both axially opposed ends of the central portion receiving the sleeve member24therein.

The constant inner diameter of the sleeve member24defines the central passageway25extending longitudinally through the sleeve member between the axially opposing ends thereof. The deformable seat26disposed within the central passageway25again comprises dogs34which extend inwardly into the central passageway25in a first condition such that the resulting inner diameter of the central passageway25at the dogs34is reduced. As in the previous embodiment, when the sleeve member24is displaced to the second position, the dogs34align with the recess38to allow the dogs to be expanded outwardly from the first condition to the second condition. In the second condition, the inner diameter at the dogs34is the same as the remainder of the sleeve member24and the tubular housing12at opposing ends of the central portion receiving the sleeve member24therein.

A similar configuration of projections42received in a machined groove40retains each sleeve member24in the second position once displaced from the first position.

Though different in configuration than the previous embodiment, a single actuating member36is again associated with a series of fracturing tools associated with a single isolated zone of a fracturing string spanning multiple zones. The actuating member36in this instance comprises both a generally cylindrical shuttle member100and a ball102which cooperates with the shuttle member100as described in the following. The shuttle member100has an outer diameter which is substantially equal to a prescribed inner diameter of the central passageway25of the sleeve member24and the end portions of the central bore18through the tubular housing12so as to be suited for longitudinally sliding of the shuttle member100through a series of tools in the fracturing string associated with a respective zone. The shuttle member100is thus arranged to be seated on the deformable seat26of each tool of the respective isolated zone in the first condition of the seat26, but the deformable seat26is adapted in the second condition to allow the actuating member100,102to pass through the central passageway25and through the tool for actuating a subsequent tool therebelow.

The shuttle member100comprises a sleeve having a central passage104extending longitudinally therethrough between opposing first and second ends. The central passage104has a constriction106wherein the internal diameter is reduced to define a ball seat108disposed in the central passage of the actuating member. The ball seat108is arranged to receive the ball102and form a seal against flow of treatment fluid when a ball is seated on the ball seat.

In a typical multi-frac operation, a plurality of the fracturing tools of similar configuration are connected in series with one another in a fracturing string spanning a plurality of isolated zones having multiple stages associated with each zone such that each fracturing tool is associated with a respective stage of a respective isolated zone. Each isolated zone includes a respective shuttle member100and cooperating ball102associated therewith so that the resulting actuating member comprised of the shuttle member100and ball102seated thereon is arranged to sequentially actuate all of the fracturing tools within the respective isolated zone. A lowermost one of the fracturing tools within each isolated zone is arranged to prevent displacement of the actuating member through the fracturing string beyond a bottom end of the respective isolated zone.

The ball of each isolated zone is arranged to pass through the shuttle member of each fracturing tool associated with one of the isolated zones above the respective isolated zone without actuating the shuttle member and without displacing the sleeve members of the respective fracturing tools into the second position. Within the respective zone however, the shuttle member100is arranged to be seated on the deformable seat26of each fracturing tool10in the first condition of the seat.

When there is provided a lower isolated zone and an upper isolated zone, each comprised of multiple stages for example, the ball of the lower isolated zone has a prescribed diameter which is arranged to be seated on the ball seat of the shuttle member of the lower isolated zone. The constriction106in the shuttle member100of the upper zone has a greater inner diameter than the constriction106of the lower zone such that the diameter of the lower ball102is arranged to pass through the ball seat of the shuttle member of the upper isolated zone without being seated thereon and without displacing the shuttle member of the upper isolated zone to be seated on the various deformable seats26of the tools of the upper zone. The ball of the upper isolated zone however has a prescribed diameter which is greater than the ball of the lower zone so as to be arranged to be seated on the ball seat108of the shuttle member of the upper isolated zone.

The use of the fracturing tools10according to the second embodiment involves providing a fracturing tool10associated with each stage of a plurality of zones comprising multiple stages per zone. Each zone includes a single actuating member associated with all tools in that zone. The shuttle member100is initially positioned within the fracturing string above the uppermost tool of the respective zone and all sleeve members are initially in the first position.

A lowermost zone is initially isolated by directing the ball associated with that zone downwardly through the fracturing string to be seated within the respective shuttle member by pumping the treatment fluid downwardly through the fracturing string. Once the ball is seated on the shuttle member, continued pumping of treatment fluid directs the shuttle member downwardly to be sequentially seated on the deformable seats of the associated tools to sequentially displace the sleeve member of each fracturing tool associated with the lower isolated zone into the second position. Once the shuttle member and associated ball are located within a lowermost one of the fracturing tools associated with the lower isolated zone, further downward movement is prevented so as to form a seal against a flow of the treatment fluid. Continued pumping of the treatment fluid to achieve the threshold hydraulic pressure level then opens the burst plugs in the fluid ports of the lower isolated zone to hydraulically fracture the well bore within the lower isolated zone.

The upper zone is subsequently isolated for fracturing by directing the ball of the upper isolated zone downwardly through the fracturing string such that the ball is seated on the shuttle member of the upper isolated zone and the sleeve members in the upper isolated zone are sequentially displaced into the second position. Once the ball and shuttle member of the upper isolated zone are located within a lowermost one of the fracturing tools associated with the upper isolated zone, the ball and actuating member are prevented from further downward displacement so as to form a seal against a flow of the treatment fluid. Continued pumping of the treatment fluid to achieve the threshold hydraulic pressure level then opens the burst plug assemblies in the fluid ports and hydraulically fractures the well bore within the upper isolated zone.

As in the previous embodiment, by uncovering all burst plug assemblies in an isolated zone prior to opening the burst plugs, pressure in the treatment fluid can be gradually pumped up to the threshold fluid pressure so as to store considerable potential energy in the fluid. By further arranging all of the burst plug assemblies within one tool or a series or tools spanning one isolated zone in a fracturing string to open at substantially the same threshold fluid pressure level, the stored energy can be quickly or suddenly discharged throughout all of the isolated zone to improve frac initiation throughout the isolated zone.

One embodiment of the burst plug assembly22adapted to be retained in each fluid port20of the fracturing tools ofFIGS. 1-10, is shown in greater detail inFIGS. 11-13. The burst plug assembly22includes a body200having an annular side wall202and a closing wall204. The side wall202and closing wall204are preferably formed integrally in a single piece, from a metal material such as bronze, brass and aluminum, such that at least the closing wall204has consistent properties for bursting under pressure. The closing wall204is generally perpendicular to the side wall202. The side wall202has an inner surface206and an outer surface208. In the Figures, the outer surface208is adapted to retain and seal the body200in the fluid port20of the fracturing tool10, with a circumferential groove209that holds a seal, such as an O-ring, for sealing to the fluid port. The side wall202may be retained in the fluid port20by alternate retaining means, such as a retaining ring (ex. snap ring), or with threads. The inner surface206of the side wall202forms a central bore210, which in one embodiment is adapted to be outwardly opening, and wellbore facing, when the burst plug assembly22is retained in the fluid port20. An optional debris cover may be retained in the fluid port between the burst plug assembly and the wellbore to prevent cement or other debris from entering the central bore210, for example during cementing operations.

InFIGS. 11-13, the closing wall204is shown as a bottom wall, such that the central bore210is closed at an inward end portion212of the side wall202by the bottom wall204. The bottom wall204is a solid wall, formed without apertures or perforations so as to prevent fluid flow through the fluid port20in the closed condition. The bottom wall204has opposed inner and outer faces214,216which are preferably planar and generally parallel one with another. In some embodiments, when retained in the fluid port20, the outer face216is wellbore-facing when located in a wellbore, while the inner face214faces the central bore of the fracturing tool. The outer face216generally faces the central bore210of the body200. In some embodiments, the burst plug assembly22may be oriented in a reverse or flipped manner in the fluid port20, such that the outer face216faces the central bore of the fracturing tool and the inner face214faces the wellbore.

A choke insert218is retained in the central bore210of the body200and lines the inner surface206of the annular side wall202along the central bore210. Preferably, the choke insert218extends along the entire inner surface206of the annular side wall202, as shown inFIGS. 12 and 13, with the top wall portion219of the choke insert218flush with the top wall portion203of the body200. The choke insert218is seated within the central bore210, preferably against the bottom wall204. The choke insert218forms an inner bore220extending through the choke insert218. The choke insert218is formed of a wear resistant material such as tungsten carbide, a wear resistant ceramic material, and a hardened, high strength steel or metal alloy. Hardened, carbide steel is an exemplary material.

A groove222, preferably continuous, is formed in one or both of the inner and outer faces214,216of the bottom wall204and circumscribes the periphery of a core224in the bottom wall204. InFIG. 2, the core224is shown as circular, and the groove is formed in the inner face214of the bottom wall204. The groove222is sized and located so that the largest dimension of the core224is no greater than the diameter of the inner bore220, such that when a prescribed threshold hydraulic pressure level of the treatment fluid is applied to the inner face214of the bottom wall204the core224disengages from the bottom wall204along the groove222in a bursting action and passes through the inner bore220of the choke insert218, so that the treatment fluid can be pumped under pressure through the inner bore220with limited erosion of the inner bore220of the choke insert218, and thus of the burst plug assembly22itself. A circular core224is preferred, with the groove22and the core224having a diameter no greater than that of the inner bore220. This ensures that the core224readily passes through the inner bore220once it disengages from the bottom wall204.

In preferred embodiments, the diameter of the groove222and of the inner bore220are sized such that the inner bore220is fully open immediately after the core224disengages and passes through the inner bore220, so that continued pumping of the treatment fluid through the inner bore220maintains a prescribed flow rate of the treatment fluid sufficient for fracturing a wellbore adjacent the burst plug assembly without significant variation due to erosion of the inner bore220of the choke insert218. In such embodiments, the prescribed flow rate may be calculated and set by the operator based on the fixed size of the orifice through each and all of the burst plug assemblies being the full diameter of the inner bore of the choke insert in each and all of the burst plug assemblies22.

In some embodiments, the inner surface206of the annular side wall202and an outer surface226of the choke insert218are formed with engaging threads228to retain the choke insert218in the central bore210of the body200, and to provide a metal to metal seal between the body200and the choke insert218. In some embodiments, the choke insert218may be retained in the central bore210by alternate retaining means such as a snap ring or a threaded retaining ring. Retaining with the engaging threads228is preferred in order to provide the metal to metal seal and to avoid the need for elastomeric seals such as O-rings within the central bore210. The erosive and/or corrosive nature of the treatment fluid can damage elastomeric seals. Furthermore, using the threads228to retain the choke insert218has the advantage of securely seating the choke insert218directly against the bottom wall204in a manner which resists inward and/or outward movement of the choke insert218. In this manner, when treatment fluid is pumped up to the prescribed threshold hydraulic pressure level sufficient to disengage the core224from the bottom wall204, the portion of the choke insert218which is securely seated directly against the bottom wall204, namely lower wall portion230of the choke insert218, is held securely by the threads228, so that the choke insert218resists ballooning of the bottom wall204under pressure. Thus, the choke insert218assists in ensuring that the core224bursts and disengages in a single core piece, and with greater precision and reliability, along the groove222.

In some embodiments, the portion of the bottom wall204extending between the annular side wall202and the groove222forms an annular seat232for the choke insert218. After the circular core224disengages from the bottom wall204, as shown inFIG. 13, the annular seat232provides an annular lip234, to direct the treatment fluid into the inner bore220while preventing the treatment fluid from penetrating the engaging threads228between the choke insert218and the body200. When the groove222is generally V-shaped in cross section, as shown inFIG. 12, the annular lip234formed after the core224is ejected is generally inwardly tapered to assist in directing the treatment fluid into the inner bore220.

When the burst plug assembly22is used in fracturing operations, once the core224disengages from the bottom wall204, by achieving the prescribed threshold hydraulic pressure level of the treatment fluid, the operator may continue pumping the treatment fluid under pressure through the inner bore220of the burst plug assembly22at a prescribed flow rate sufficient for hydraulically fracturing the isolated zone adjacent the burst plug assembly without significant variation due to erosion of the inner bore220, and thus of the burst plug assembly22. The choke insert218of the burst plug assembly22of this invention, provides a reliable and predictable flow restriction, i.e., a fixed choking restriction, at each fluid ports for the continued pumping of treatment fluid through the inner bore220of choke insert218. Particularly for multi-frac operations, erosion at the flow ports is minimized with burst plug according to this invention, so that the flow port restriction is not enlarged and/or washed out at the high fracturing pressures. This results in more predictable and reliable flow rates at each and every burst plug assembly, without significant variation in the orifice size due to erosion of the inner bore220at any one or more of the burst plug assemblies.

In fracturing operations, a reliable opening of the flow ports in the fracturing tools is important. The fracturing operators prefer a reliable and predictable flow restriction (i.e., flow area and orifice diameter) at the flow ports when pumping fluid downhole. Prior to this invention, erosion of the fluid ports, whether or not closed with burst plugs, has remained problematic in fracturing operations, particularly in view of the erosive and/or corrosive nature of the treatment fluids used for fracturing. In prior art multi-frac operations, erosion at the flow ports of the fracturing tools has enlarged and/or washed out one or more of the flow ports. This resulted in unpredictable, unreliable and uneven injection into the wellbore at each of the multi-frac sites. The burst plug assembly of this invention, with choke inserts, addresses the issues of erosion and in a manner that allows the operator to maintain prescribed flow rates sufficient for fracturing at each of the burst plug assemblies without variation due to erosion of the inner bore of the choke insert. By limiting erosion of the inner bore of the choke inserts, a fixed diameter orifice is maintained at each burst plug assembly for the duration of the fracturing operation.

The inclusion of the choke inserts in the burst plug assemblies of this invention thus avoids issues of some prior art fracturing tools, where low pumping rates were needed to slowly erode or corrode fluid port covers. As noted above, low pumping rates can cause sanding off at one or more of the fluid ports. As well, the choke inserts and the burst plug assemblies of this invention address prior art issues of total or selective erosion at one or more of the fluid ports. In the present invention, by preventing or minimizing erosion of the inner bore of the choke inserts in each burst plug assembly, the prescribed flow rate sufficient for fracturing can be achieved instantly upon bursting of the burst plug assemblies, and this prescribed flow rate, without significant pressure drop, can be maintained by the operator with confidence that treatment fluid continues to flow through each of the burst plug assemblies, without selective erosion at one or more of the burst plug assemblies interfering with, and causing, variation in the prescribed flow rate due to erosion at eroded burst plugs.

Terms relating to position or orientation, such as “upper”, “lower”, “top”, “bottom”, “inner”, “outer”, “inward” and “outward” are used for convenience of description and relative positioning for features as shown in the figures but, unless otherwise stated, such terms are not intended to limit the features of the invention to a particular position or orientation.

As used herein and in the claims, the term “treatment fluid” includes any pumpable liquid fluid delivered to an isolated zone of a wellbore to stimulate production including, but not limited to, fracturing fluid, acid, gel, foam or other stimulating fluid, and which may carry solids including, but not limited to, sand.

As used herein and in the claims, the terms “tubing string” and “fracturing string” may be used interchangeably, and may refer to a “casing”, a “tubing”, a “liner” or other connected tubular members, as is generally understood in fracturing operations.

As used herein and in the claims, the word “comprising” is used in its non-limiting sense to mean that items following the word in the sentence are included and that items not specifically mentioned are not excluded. The use of the indefinite article “a” in the claims before an element means that one of the elements is specified, but does not specifically exclude others of the elements being present, unless the context clearly requires that there be one and only one of the elements.

All references mentioned in this specification are indicative of the level of skill in the art of this invention. All references are herein incorporated by reference in their entirety to the same extent as if each reference was specifically and individually indicated to be incorporated by reference. However, if any inconsistency arises between a cited reference and the present disclosure, the present disclosure takes precedence. Some references provided herein are incorporated by reference herein to provide details concerning the state of the art prior to the filing of this application, other references may be cited to provide additional or alternative device elements, additional or alternative materials, additional or alternative methods of analysis or application of the invention.

The terms and expressions used are, unless otherwise defined herein, used as terms of description and not limitation. There is no intention, in using such terms and expressions, of excluding equivalents of the features illustrated and described, it being recognized that the scope of the invention is defined and limited only by the claims which follow. Although the description herein contains many specifics, these should not be construed as limiting the scope of the invention, but as merely providing illustrations of some of the embodiments of the invention.

One of ordinary skill in the art will appreciate that elements and materials other than those specifically exemplified can be employed in the practice of the invention without resort to undue experimentation. All art-known functional equivalents, of any such elements and materials are intended to be included in this invention. The invention illustratively described herein suitably may be practised in the absence of any element or elements, limitation or limitations which is not specifically disclosed herein.