METHOD FOR LAUNCHING REPLACEMENT BALLS

Abstract

A method for successively releasing balls into a wellbore during wellbore operations is disclosed. The method includes providing at least a first ball injector for storing at least a primary set of primary balls and at least a second set of redundant balls, releasing a ball from the at least primary set of primary balls and determining if the released ball properly seats and engages its intended corresponding downhole tool. If it is determined that the released ball did not properly engage and actuate its intended corresponding tool, a redundant ball from the second set of redundant balls can be released without interrupting wellbore operations. In an alternate embodiment, the first ball injector can be a primary ball injector for storing and releasing the at least primary set of primary balls, and a second ball injector for storing and releasing the at least second set of redundant balls, the first and second ball injectors arranged in parallel.

Description

CROSS-RELATED APPLICATIONS

This application claims the benefits under 35 U.S.C. 119(e) of U.S. Provisional Application Ser. No. 61/714,176, filed Oct. 15, 2012, the entirety of which is incorporated fully herein by reference.

FIELD

This invention relates generally to a method for injecting subsequent balls into a wellbore for interacting with downhole tools, such as activating tools that allow select zones or zone intervals in the wellbore to be stimulated, more particularly for injecting a redundant or replacement ball when a previously injected ball does not properly actuate its intended tool.

BACKGROUND

It is known to conduct fracturing or other stimulation procedures in a wellbore by isolating zones of interest, or intervals within a zone, using packers and the like. The isolated zone is subjected to treatment fluids, including liquids and gases, at treatment pressures. In a typical fracturing procedure for a cased wellbore, for example, the casing of the well is perforated to admit oil and/or gas into the wellbore and fracturing fluid is then pumped into the wellbore and through the perforations into the formation. Such treatment opens and/or enlarges drainage channels in the formation, enhancing the producing ability of the well.

It is typically desired to stimulate multiple zones in a single stimulation treatment, typically using on-site stimulation, fluid pumping equipment. A tubular string conveying series of spaced packers, in a packer arrangement, is inserted into the wellbore, each of the packers located for corresponding with intervals for isolating one zone from an adjacent zone. It is known to introduce a ball into the wellbore to selectively engage an actuator for one of the packers in order to block fluid flow therethrough, creating an isolated zone for subsequent treatment or stimulation. Once the isolated zone has been stimulated, a subsequent ball is dropped to block off a subsequent packer, uphole of the previously actuated packer, for isolation and stimulation thereabove. The process is continued until all the desired zones have been stimulated. Typically the balls range in diameter from a smallest ball, suitable to block the most downhole packer, to the largest diameter, suitable for blocking the most uphole packer. Similarly, the balls can actuate successive sliding sleeves in a completion string.

At surface, the wellbore is fit with a wellhead including valves and a pipeline connection block, such as a frachead, which provides fluid connections for introducing stimulation fluids, including sand, gels and acid treatments, into the wellbore.

There are a variety of surface tools for introducing balls into the wellbore. It is known to feed a plurality of perforation-sealing balls using an automated device as set forth in U.S. Pat. No. 4,132,243 to Kuus. Same-sized balls are used for sealing perforations and are able to be fed one by one from a stack of balls. The apparatus appears limited to same-sized balls and there is no positive identification whether a ball was successfully indexed from the stack for injection.

In another prior art arrangement, such as that set forth in FIG. 1, a vertically stacked manifold of pre-loaded balls is oriented in a bore above the wellbore of a wellhead and frachead. Each ball is temporarily supported by a rod or finger. Each finger is sequentially actuated to withdraw from the bore when required to release or launch the next largest ball. As the balls are already stacked in the bore, the lowest ball (closest to the wellbore) is necessarily the smallest ball. There are no options for changing the sequence or order of ball drop.

As shown in FIG. 2 and extracted from US Published Patent Application Serial No. US 2012/0279717 to Young et al., another type of vertical ball injector is shown which stores and drops successive balls from a ball cartridge. A ball rail forms a tapered hopper within the cartridge for storing a small ball at the apex and ever larger balls thereabove within the cartridge. The hopper forms an aperture at a bottom end thereof, the ball rail and aperture being actuable to open just enough to allow the bottom, smallest ball in turn to drop into the wellbore.

Another ball injector, as shown in FIG. 3, is that disclosed in U.S. Pat. No. 8,136,585 to Applicant, the entirety of which is incorporated fully herein by reference, discloses a radial ball injector comprising a plurality of vertically stacked radial ball arrays, with each ball array having one or more radial bores housing a ball cartridge. Each ball cartridge can be loaded with a ball of graduated sized, each cartridge being misaligned with the wellbore for storing the ball and operationally aligned for dropping or releasing a selected ball into the wellbore.

Despite improvements to providing successive balls, there are still operational events that require greater surface control and flexibility for dropping balls down a wellbore. For example, it is not uncommon for a ball to be damaged or to disintegrate upon arrival at the downhole tool requiring a replacement ball or one of the same diameter to be reloaded and launched again. Further, damaged or scarred packer balls can fail to isolate the zone requiring an operator to then drop an identical ball down the bore of the ball injector. Further still, an initial packer ball may not seat or engage its intended downhole tool properly, if at all, and may not actuate its intended downhole tool. In such circumstances, a replacement or redundant ball of the same size must be dropped into the wellbore.

In the prior art apparatus of FIGS. 1 and 2, the injector must be depressurized, removed and reloaded to get a replacement smaller ball under the remaining loaded balls. This requires time consuming and properly managed procedures to maintain safe control in a hazardous environment and to complete testing and re-pressurization procedures upon reinstallation to the wellhead. This is extremely inefficient, time consuming, costly and can adversely compromise the treatment and health of the wellbore.

Another option can be to manually introduce a redundant ball into the system through a bypass system. However, such manual introduction of a redundant ball still requires a shutdown of the operations which can cause many problems including settling of sand, failure of the stage to ever again resulting in abandonment and hours or even days of delay which is very expensive.

There remains a need for a safe, efficient and remotely operated apparatus and mechanism for introducing successive balls to a wellbore without interrupting downhole operations.

SUMMARY

The present invention teaches a method of successively launching or injecting balls into a wellbore without interrupting wellbore operations, regardless of failure of a primary ball corresponding to a specified downhole tool.

Should a ball of the required size for the particular step in the wellbore operation be lost or damaged for some reason or fails to properly engage its intended downhole tool for any reason, a redundant ball can be provided without isolating or removing the ball injecting apparatus from the wellhead structure, or otherwise interrupting wellbore operations. As operations are ongoing, a replacement or redundant ball can be dropped or released into the wellbore for engaging its intended downhole tool.

In a broad aspect of the invention, a method of successively dropping two or more balls into a wellbore for engaging and actuating a corresponding downhole tool involves providing at least a first ball injector, storing at least a primary set of primary balls in the at least first ball injector, storing at least a second set of redundant balls in the at least first ball injector which can be the same or at least a second ball injector, releasing a stored primary ball from the at least first set of primary balls into the wellbore, determining if the corresponding downhole tool was actuated by the primary ball, and if actuated, then repeating the releasing a subsequent or successive primary ball from the at least first set of primary balls, or if the corresponding tool is not actuated, then, releasing a redundant ball from the at least a second set of redundant balls, corresponding to the primary ball.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is schematic view of a prior art apparatus implementing a plurality of pre-loaded balls, the balls supported on a plurality of finger actuators for bottom-up release;

FIG. 2 is a side cross-sectional view of another prior art apparatus implementing a plurality of pre-loaded balls an actuable hopper for bottom-up injection;

FIG. 3 is an overall schematic representation of Applicant's own prior art ball injector disclosed in U.S. Pat. No. 8,136,585, including a partial side cross-sectional view of Applicant's ball injector housing discrete balls for unique downhole tools;

FIGS. 4A to 4C are side cross-sectional views of an embodiment of Applicant's ball injector disclosed in U.S. Pat. No. 8,136,585, illustrating a sequence of steps for releasing a redundant ball into a wellbore;

FIG. 5A is a flow chart and single array of one embodiment of the redundant ball operation using a radial injector according to FIG. 3, the flow chart illustrating a method of deploying a subsequent ball to replace a previously deployed, yet failed primary ball of the same size, both primary and redundant balls stored within the same array of the ball injector;

FIG. 5B is a side view of a radial injector, the structure of which corresponds to Applicant's radial injector of FIG. 3; each array storing pairs of primary and redundant balls;

FIG. 6 is a side view of an embodiment illustrating two ball injectors fluidly connected to a wellbore in parallel fashion using two or more fluid wellbores, a first injector for releasing primary balls from a first set of balls, and the second injector for releasing redundant balls of a second set of balls, as necessary; and

FIG. 7 is a side view of an embodiment illustrating a radial injector fluidly connected to a fracturing head, the fracturing head receiving a treatment fluid and the radial injector receiving a displacement fluid for positively displacing a ball from the injector.

DETAILED DESCRIPTION

In the prior art, in instances where no such indication of proper engagement of a ball or actuation of a downhole tool is received, pumping operations can be temporarily stopped, and a redundant ball of similar size is manually dropped into the bore of a ball injector. Then the pumping operation is recommenced to deploy the redundant ball downhole to the corresponding non-actuated tool. However, interruption and stoppage of the pumping operations can cause many problems, and in some cases, that particular stage may not open at all requiring the abandonment of that stage. Other problems can arise because the wellbore and conveyance string need to be completely flushed of sand before the redundant ball is deployed. Further, if the surface equipment requires complete bleed out, if using gases such as propane, butane, carbon dioxide or nitrogen, corrosive pumping fluids, such as acids, must also be completely flushed before redundant balls are introduced. The flushing of the system also requires additional pumping of fluid and sand which can also increase operational costs. Each shut down of pumping operations could mean an extra day, or at the very least several extra hours of delay which can lead to increasing operational costs.

Accordingly, with reference to known ball injectors of FIGS. 3 and 4A through 4C, the injector 10 is illustrated according to U.S. Pat. No. 8,136,585 to Applicant. As shown, two radial ball arrays 60,60 are shown for staging eight different sized balls. Treatment fluid is arranged for flow through the axial bore 70 and effectively carrying an injected ball downhole to a treatment or downhole tool. As shown in FIG. 4A, a first ball 100a is operationally aligned with the bore with the cartridge oriented downhole for release into the bore. The ball 100a falls through an open isolation valve 50 and is carried downhole.

As shown in FIG. 4B, if the ball is not successful in actuating its respective tool, then it has been known to close the isolation valve 50 to enable safe access to the bore 70 of the injector 10. Cartridge 90, for the failed ball release, is misaligned from the bore 70. A replacement ball 110a of same size is manually inserted into the bore, bypassing the cartridge 90 for staging atop the isolation valve 50.

Turning to FIG. 4C, the isolation valve 50 is opened and the replacement ball 110a is conveyed downhole. As discussed, the closing of the isolation valve 50 and interruption of the fluid flow may be undesirable.

In detail in FIG. 3, the ball injecting apparatus or injector 10 receives and releases balls, including drop balls, frac balls, packer balls, and the like, for isolating zones of interest during wellbore operations such as fracturing, and is supported on a wellhead structure 20 having a wellbore 30. The wellhead structure 20 can include a high pressure wellhead or a frac head 40 and an isolation gate valve 50. Although the injector 10 can be any apparatus for injecting balls into the wellbore, in a preferred embodiment, the injector 10 can be the radial ball injector as disclosed in Applicant's issued patent U.S. Pat. No. 8,136,585, the entirety of which is incorporated fully herein by reference. As shown, the preferred radial ball injector 10 can comprise at least one radial ball array 60 having an axial bore 70 extending therethrough and two or more radial bores 80 extending radially away from the axial bore 70, the axial bore 70 in fluid communication with the wellbore 30. Housed within each radial bore 80 is a ball cartridge 90, for storing a ball therein, which is either operably misaligned with the wellbore 30 for storing the ball, or operably aligned with the wellbore 30 for releasing the ball into the wellbore 30.

Redundant Ball Configuration—Radial Array

Turning to FIGS. 5A and 5B, and in a base embodiment for an injector that avoids wellbore interruption, two of the radial bores 80 of the radial array 60 of FIG. 3 can be loaded with at least two primary balls 100a,100b for specified tools A and B, and two others of the radial bores 80 are loaded providing redundant balls 110a,110b should either of the primary balls fail to perform their tool actuating function when released. Each of the radial bores 80 house a ball cartridge 90 for storing and deploying its respective ball.

As shown, two radial bores of the same radial housing are loaded with balls 100a,110a of the same size, one for serving as the primary ball 100a for the specified tool A, and another serving as a redundant or replacement ball 110a in cases where the dropped ball does not properly actuate the downhole tool A. Another pair of the two ball cartridges can also each be loaded with balls 100b, 110b of the same size as each other, yet different from the first pair 100a,110a so as to act as specified successive balls for actuating successive tool B. Again, the successive and redundant ball 110b serves as a replacement ball for the primary ball 100b in case the dropped successive ball does not seat, engage or otherwise actuate the downhole tool B.

Thus, redundant balls 110a, 110b . . . are readily available for each size of released primary ball 100a, 100b . . . that fails to properly actuate its intended downhole tool, thereby, providing a quick and efficient method for safely deploying replacement balls without the need to temporarily shut down pumping operations.

As shown, in instances where there is an indication that the primary released ball 100a, 100b . . . properly actuated its intended downhole tool, such as a by a pressure spike in the supplied treatment fluid, an operator can simply continue with pumping operations and deploy the successive ball for actuation of the successive tool, the redundant ball remaining in its redundant bore for removal after the conclusion of the operation. In embodiments, the wellbore 30 is monitored for proper seating or engagement of a dropped ball with its intended corresponding downhole tool, such as is often indicated by a pressure spike, ranging from about 1000 to 2000 psi for example. However, where the ball fails, the operator can quickly and efficiently select a redundant or replacement ball 110a, 110b . . . from the same or other radial ball array 60 for operation.

The deployment of the redundant ball does not require the shutdown of pumping of treatment fluids and can proceed without interruption of operations.

As shown in FIG. 5B, a stack of four radial arrays, with complete redundancy, enables eight stages of operation, housing eight primary balls. In the cross-sectional view, four primary balls are visible 100a,100c,100e and 100g, for actuating four downhole tools (not shown). Further, four redundant balls 110a,110c,110e and 110g, are visible, paired or corresponding to a primary ball 100a,100c,100e,100g, having the same size and characteristics as an operational replacement therefore. Four additional primary balls (b,d,f,h) and corresponding redundant balls (b,d,f,h) are not shown, being oriented into the page of the drawing.

Redundant Ball Configuration—Parallel Bore

With reference to FIG. 6, in another embodiment, the wellhead structure 20 can comprise a multi-injector connector 300 having two or more fluid axial wellbores 71,72 arranged in parallel for supporting at least two injectors, a first or primary injector 11 and at least a second injector 12. As shown, two axial wellbores 71,72 form a “Y”-shaped multi-injector connector 300 between the ball injectors 11,12 and the wellbore 30. The first axial wellbore 71 is fit with the first injector 11 and the second axial wellbore 72 is fit with the second injector 12. The first injector 11 is pre-loaded with the at least first set of primary balls 100a,100b,100c,100d for corresponding downhole tools 250a,250b,250c and 250d respectively, and the second ball injector 12 is pre-loaded with a second set of redundant balls 110a,110b,110c,110d.

Each injector 11,12 can be selected from a range of known ball injectors, shown here as a radial ball injector of the type illustrated in FIG. 3. Each ball injector 11,12 has at least one radial ball array 60, each array having two or more radial bores 80 extending radially away from the axial wellbore 71,72 and in fluid communication therewith, each axial wellbore 71,72 being in fluid communication with the wellbore 30. The first injector 11 stores a primary set of balls having two or more primary balls 100a,100b . . . the second injector 12 stores a redundant set of two or more balls redundant balls 110a,110b.

In operation, a stored primary ball from the primary set of balls is released from the first injector 11 for actuating its intended corresponding downhole tool. As operations dictate, one repeats the release and dropping into the wellbore successive primary balls from first set of primary balls for actuating successive tools. Accordingly, the balance of the primary set of balls can be operated in sequence to introduce or release each successively larger, right sized ball at the correct time in the operation. In an embodiment, to ensure that a ball has left the injector and exited its respective axial wellbore 71,72, a displacement fluid, such as the treatment fluid itself, can be pumped through the ball injector 11,12 in use.

Again, if a dropped ball were to fail to actuate its intended corresponding downhole tool, the primary ball injector 11 need not be isolated nor disassembled from the wellhead structure. The second ball injector 12 can be actuated to provide a replacement or redundant ball corresponding to the failed primary ball. For example, if primary ball 100c fails, then redundant ball 110c is released from the second injector 12. As shown, for simplicity, the arrangement of the redundant balls 110a,110b,110c,110d loaded in the second ball injector 12 are substantially similar to the arrangement of the primary balls 100a,100b,100c,100d loaded in the primary ball injector 10.

In an embodiment, and with reference to FIG. 7, the ball injector 10 can be fluidly connected to a wellhead structure 20, such as a fracturing head 40 for receiving treatment fluid therein. The wellhead structure 20 can further have an isolation gate valve 50 for isolating the ball injector 10 from the wellbore 30, providing further operator control of the launching of balls. Accordingly, the ball injector 10 can be isolated from the wellbore 30, but downhole operations can continue without interruption as treatment fluid can be continuously injected downhole through the fracturing head 40. Thus, with the ball injector 10 isolated from the wellbore 30, a ball can be dropped onto the isolation valve 50 without the ball immediately being released into the wellbore 30. At an appropriate time, the gate valve 50 can be opened to release the dropped ball into the wellbore 30.

In such an embodiment, and as shown, the ball injector 10 can further be adapted to receive displacement fluid for positively displacing the ball from the injector 10. In an embodiment, and as shown, the displacement fluid can be from a separate source or in an alternate embodiment (not shown), the displacement fluid can be treatment fluid fluidly communicated to the ball injector 10 via a bypass fluid line.

Further still, in another embodiment, redundant balls can be used for different stages of a downhole operation, and not necessarily be limited to use as a redundant ball for a particular stage where a primary ball has failed to actuate its intended corresponding downhole tool.

Claims

1. A method of successively releasing one or more balls into a fluid wellbore for engaging and actuating an intended downhole tool corresponding thereto comprising:

storing at least a primary set of primary balls;

storing at least a second set of redundant balls;

releasing a primary ball for actuating a corresponding downhole tool; and

determining if the corresponding downhole tool was actuated by the primary ball, and

if actuated, then releasing a successive primary ball from the at least primary set of primary balls, or

if not actuated, releasing a redundant ball from the second set of redundant balls, the redundant ball corresponding to the primary ball.

2. The method of claim 1, wherein the releasing a primary ball for actuating a corresponding downhole tool further comprises releasing a primary ball from the at least primary set of primary balls stored in at least a first ball injector, and

storing the at least second set of redundant balls further comprises storing the at least second set of redundant balls in the at least first ball injector.

3. The method of claim 2, wherein the at least first ball injector further comprises a radial ball injector having at least one radial array having an axial bore in fluid communication with the wellbore, and two or more radial bores extending radially away from the axial bore for storing the at least primary set of primary balls and the at least second set of redundant balls.

4. The method of claim 3, wherein at least one primary ball and one redundant ball are stored in the at least one radial array.

5. The method of claim 4, wherein each radial array of a stack of radial arrays contains a primary ball and a corresponding redundant ball.

6. The method of claim 1 wherein the at least first ball injector further comprises a first ball injector and at least a second ball injector and the fluid wellbore comprises a multi-injector connector having two or more fluid axial wellbores arranged in parallel and each in fluid communication with the fluid wellbore, each of the two or more axial wellbores supporting the first ball injector and the at least a second ball injector,

the first ball injector housing the at least primary set of primary balls; and

the at least second ball injector housing the at least second set of redundant balls.

7. The method of claim 6, further comprising concurrently pumping displacement fluid through each of the first and second ball injectors for positively displacing any balls operably aligned with the axial bore.

8. The method of claim 1, wherein determining the corresponding downhole tool has been actuated by a primary ball further comprises monitoring a pressure in the wellbore wherein an increase in the pressure is indicative of actuation.

9. A system for successively releasing one or more balls into a fluid wellbore for engaging and actuating an intended downhole corresponding thereto comprising:

a primary set of primary balls fluidly connected to the fluid wellbore;

at least a second set of redundant balls fluidly connected to the fluid wellbore; and

at least a first ball injector for injecting the primary set of primary balls and the at least second set of redundant balls into the fluid wellbore.

10. The system of claim 9, wherein the at least a first ball injector further comprises a first ball injector having a first axial wellbore and for storing and releasing the at least primary set of primary balls, and at least a second ball injector having a second axial wellbore and for storing and releasing the at least second set of redundant balls.

11. The system of claim 10 further comprising a multi-injector connector for fluidly arranging the first and the second axial wellbores in parallel and for fluidly connecting the first and second axial wellbores with the fluid wellbore.

12. The system of claim 11 further comprising an isolation gate valve between the multi-injector connector and a wellhead structure.

13. The system of claim 12 wherein the wellhead structure further comprises a fracturing head.