Well Bore Tool With Ball Seat Assembly

Abstract

Tools for a well tubular comprising a ball seat assembly. The ball seat assembly comprises first and second ball seats. The first ball seat is adapted to receive a ball deployed into the tool, transition to a second state and release the ball. The first ball seat is operatively engaged with the second ball seat such that as it transitions to its second state it causes the second ball seat to transition from a first state of increased clearance to a second state having reduced clearance. The second seat then is adapted to receive the ball after it is released by the first seat. The second ball seat is adapted to actuate the tool, transition to a third state, and release the ball. The clearance through the second ball seat in its second state is less than the clearance through the first ball seat in its first state.

Description

FIELD OF THE INVENTION

The present invention relates to tools used in oil and gas wells and, more particularly to improved ball seat tools and methods of using ball seat tools. The novel tools and methods are particularly suited for use in fracturing hydrocarbon bearing formations and in other methods for simultaneously stimulating production of hydrocarbons in multiple zones in a well bore.

BACKGROUND OF THE INVENTION

Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer, and thus, the porous layer forms a reservoir in which hydrocarbons are able to collect. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well.

In what is perhaps the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the well bore. This fluid serves to lubricate the bit and carry cuttings from the drilling process back to the surface. As the drilling progresses downward, the drill string is extended by adding more pipe sections.

When the drill bit has reached the desired depth, larger diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. Cement is introduced through a work string. As it flows out the bottom of the work string, fluids already in the well, so-called “returns,” are displaced up the annulus between the casing and the borehole and are collected at the surface.

Once the casing is cemented in place, it is perforated at the level of the oil bearing formation to create openings through which oil can enter the cased well. Production tubing, valves, and other equipment are installed in the well so that the hydrocarbons may flow in a controlled manner from the formation, into the cased well bore, and through the production tubing up to the surface for storage or transport.

This simplified drilling and completion process, however, is rarely possible in the real world. Hydrocarbon bearing formations may be quite deep or otherwise difficult to access. Thus, many wells today are drilled in stages. An initial section is drilled, cased, and cemented. Drilling then proceeds with a somewhat smaller well bore which is lined with somewhat smaller casings or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A seal also is typically established between the liner and the casing and, like the original casing, the liner is cemented in the well. That process then may be repeated to further extend the well and install additional liners. In essence, then, a modern oil well typically includes a number of tubes wholly or partially within other tubes.

Moreover, hydrocarbons are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons are able to flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and stimulating production from formations. In particular, various techniques are available for increasing production from formations which are relatively nonporous.

One technique involves drilling a well in a more or less horizontal direction, so that the borehole extends along a formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Another technique involves creating fractures in a formation which will allow hydrocarbons to flow more easily. Indeed, the combination of horizontal drilling and fracturing, or “frac'ing” or “fracking” as it is known in the industry, is presently the only commercially viable way of producing natural gas from the vast majority of North American gas reserves.

Formations are fractured most commonly by pumping a fluid, usually water, into the formation at high pressure and flow rates. The fluid will cause the formation to fracture and create flow paths to the well. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the frac fluid and are carried into the fractures. The proppant serves to prevent fractures from closing when pumping is stopped.

A formation usually is fractured at various locations. The formation is rarely fractured all at once, but multiple locations within the wellbore may be fractured simultaneously. Especially in a typical horizontal well, the formation usually is fractured at a number of different locations or clusters of locations along, the bore in a series of operations or stages. For example, an initial stage may fracture the formation near the bottom of a well. The frac job then would be completed by conducting additional fracturing stages in succession up the well, each stage fracturing a particular location or cluster of locations.

Fracturing typically involves installing a production liner in the portion of the well bore which passes through the hydrocarbon bearing formation. In shallow wells, the production liner may actually be the casing suspended from the well surface. In either event, the production liner is provided with openings at predetermined locations along its length. The openings will allow fluid to be diverted from the liner into the formation. They most commonly are provided by perforating the liner, i.e., forming holes through the liner, or by installing a series of valves in the liner.

Frac valves typically include a cylindrical housing that may be threaded into and forms a part of a production liner. The housing defines a central conduit through which frac fluids and other well fluids may flow. Ports are provided in the housing to allow fluid to flow out of the liner and into the formation. The ports may be opened by actuating a sliding sleeve. The sliding sleeves usually are actuated either by creating hydraulic pressure behind the sleeve itself or by dropping a ball on a ball seat which is connected to the sleeve. Hydraulic pressure then is built up behind the ball to actuate the sleeve. Typical multi-stage fracking systems will incorporate both types of valves.

Halliburton's RapidSuite sleeve system and Schlumberger's Falcon series sleeves, for example, utilize a hydraulically actuated “initiator” valve and a series of ball-drop valves. The production liner is provided with a hydraulically actuated sliding sleeve valve which, when the liner is run into the well, will be located near the bottom of the well bore in the first fracture zone. The production liner also includes a series of ball-drop valves which will be positioned in the various other fracture zones extending uphole from the first zone.

A frac job will be initiated by increasing fluid pressure in the production liner. The increasing pressure will actuate the sleeve in the bottom, hydraulic valve, opening the ports and allowing fluid to flow into the first fracture zone. Once the first zone is fractured, a ball is dropped into the well and allowed to land on the ball seat of the ball-drop valve immediately uphole of the first zone. The seated ball isolates the lower portion of the production liner and prevents the flow of additional frac fluid into the first zone. Continued pumping will shift the seat downward, along with the sliding sleeve, opening the ports and allowing fluid to flow into the second fracture zone. The process then is repeated with each ball-drop valve uphole from the second zone until all zones in the formation are fractured.

It will be appreciated that those systems are designed to fracture one zone at a time. Fracturing a single zone in each stage, other factors being equal, can allow for greater control over the process and will require less pumping capacity, especially when the formation is relatively hard and nonporous. On the other hand, for certain formations and well designs, operators may prefer to fracture multiple zones in a single stage. By fracturing clusters of zones in a single stage, the entire formation can be fractured more quickly.

When the well bore will be fractured in clusters, the production liner will incorporate a series of “static” valves, one thr each cluster. Many static valves are ball-drop valves similar to the valves discussed above. They incorporate a ball seat that not only enables the valve to be opened, but once opened, allows a ball seated thereon to restrict the flow of fluid through the valve and into downhole zones that have already been fractured. Instead, fluid is forced out of the valve into the adjacent formation so that it may be fractured.

When a cluster of zones will be fractured in a single stage, the production liner also will incorporate one or more cluster valves uphole from each static valve. The cluster valves commonly are ball-drop valves as well. The ball seats in the cluster valves, however, are designed to catch and release a ball. That is the ball seat has an initial ball-catch state where a ball will lodge against the seat. Once the ball is seated, hydraulic pressure applied above the ball will drive the valve sleeve downward to open the ports. Once the ports are opened, however, the seat will transition to a ball-pass state which releases the ball and allows it to travel through the valve. Once the ball exits the cluster valve, it will travel down the liner to actuate either another cluster valve or the static value.

Thus, an operator may be able to fracture a number of clustered zones in a single stage. A ball deployed into the liner will travel through each cluster valve in the cluster and open them in succession. It then will land in the static valve at the bottom of the cluster, opening it and forcing fluid to be diverted out of the static valve and all the cluster valves associated with it. By fracturing multiple zones in a single stage, an operator may be able to complete fracturing, of the well more quickly and efficiently.

Ball-drop valves have been widely used in many well completions, and in both single-zone stages and in clustered-zone stages. The series of valves avoids the time consuming process of running and setting perf guns and plugs. Instead, the valves are installed in the liner and a series of balls are dropped into the well to successively open the valves and isolate downhole zones. Even where it may be necessary to drill out the liner to remove the balls and seats prior to production, such systems can be more cost efficient than plug and perf completions. Unlike plug and perf jobs, however, there is a practical limit to the number of stages or zones that can be fractured.

That is, the seat in each valve must be big enough to allow passage of the balls required to actuate every valve below it. Conversely, the ball used to actuate a particular valve must be smaller than the balls used to actuate every valve above it. Each valve running up the liner will have an incrementally larger seat and be activated by an incrementally larger ball. Given the size constraints of even the largest diameter production liners, therefore, only so many different ball and seat sizes may be accommodated. Halliburton's RapidStage ball-drop valves, for example, only allow for fracking of up to twenty zones. While that capability is not insignificant, operators may prefer to perform an even greater number of stages using a single liner installation.

The incremental difference in sizing between the valves is determined in part by the difference between the size of the ball and the clearance through the seat upon which it will land. As that difference becomes larger, the incremental difference between seats in, and balls actuating a series of valves becomes larger, and fewer valves may be incorporated into a series. As that difference becomes smaller, the incremental difference may be made smaller and more valves may be incorporated into a series.

At the same time, however, the size of the ball and clearance through the seat must be coordinated so that there is sufficient interference or contact area between the ball and the seat. The ball and the seat must maintain their structural integrity as required pressures are built up behind the ball. The ball must not be extruded through the seat, nor should the ball or seat otherwise fail and allow flow through the seat to a degree that will interfere with operation of the valve. The problem is more acute in larger balls and seats, and obviously depends as well upon the materials from which the ball and seat are fabricated and other factors. Other factors being equal, however, the difference between the size, i.e., the outer diameter of the ball and the size, i.e., the inner diameter of the seat will determine the load at which failure occurs. As the interference between the ball and the seat is reduced, the load capacity of the seat will be reduced, and the seated ball will fail at progressively smaller loads.

Thus, given the pressures required to fracture formations and the typical design and construction of balls and seats, there has been a lower limit to the incremental difference in size that may incorporated into a series of ball-drop valves. Halliburton's RapidStage ball-drop valves, for example, are sized in increments of at least one-eighth of an inch. That is, the valve above a particular valve typically will have a seat having a clearance of at least ⅛ of an inch larger than the valve below it, and will be actuated by a ball at least ⅛ of an inch larger than the ball activating the lower valve.

Baker Hughes, however, has developed its FracPoint Ex-C Frac Sleeve system which provides ball-drop valves sized in increments as small as 1/16 inch. The valves have a ball seat assembly which comprises a ball seat and a split-c support ring. The ball seat is incorporated into the upper sub of a two-part valve sleeve. The two-part valve sleeve incorporates springs which bias the upper valve sub and the lower valve sub apart from each other. The support ring is carried under compression within the upper valve sub, just above the lower valve sub. When the tool is run into a well, the inner diameter of the ball seat and the inner diameter of the support ring are the same, and will allow balls of smaller diameter to pass through the valve.

When a ball of the appropriate size is landed on the seat and hydraulic pressure is applied, the upper valve sub will be urged downward against the resistance of the springs. As it travels downward, the upper valve sub eventually shoulders out on the lower valve sub and, in the process, compresses the support ring. When compressed, the support ring is displaced radially inward toward the central axis of the tool such that its inner diameter has been reduced, and the support ring now supports portions of the ball projecting through and below the ball seat. The ball at this point is supported on both the ball seat and the support ring, and continued pressure applied through the ball will cause the upper and lower valve subs to travel down the valve together and eventually uncover the valve ports.

Once the valve is opened and pressure is no longer applied to the seated ball, the spring biasing the valve subs apart will urge the upper valve sub upward relative to the HS lower valve sub. As that happens, the support ring is allowed to expand back to its original dimensions, thus allowing flow back of balls that were passed through the valve to actuate downhole valves.

It will be appreciated that the ball seats in the FracPoint Ex-C Frac Sleeve systems are not required to provide all of the load capacity required to operate the valve. The ball seat also is supported by the support ring, and the overall load capacity of the seat assembly is increased over that provided by the seat alone. In turn, the interference between the seat and ball may be reduced to allow sizing of a series of ball-drop valves in increments as small as 1/16 of an inch instead of the more typical ⅛ inch minimum increments.

U.S. Pat. No. 8,668,006 to Y. Xu, which is assigned to Baker Hughes, discloses a similar mechanism for increasing the load capacity of a seat assembly. The ball seat assembly disclosed there includes a seat and a collet. When the tool is run into a well, the inner diameter of the seat and the collet are the same. When a ball is landed on the seat, it is urged downward. That downward movement compresses the collet fingers, urging them radially inward into a position where they, along with the ball seat, will support the ball. The collet fingers also serve to bias the seat assembly in an upward position. Thus, when pressure is no longer applied to a landed ball, the seat assembly will shift back upwards allowing the collet fingers to return to their original position and inner diameter. Such assemblies also appear to allow a seat with a relatively larger inner diameter and a lower load capacity to be used given the extra support provided by the collet fingers.

When several zones will be clustered and fractured in a single stage, additional concerns may be present. That is, as the number of cluster valves in a cluster is increased, ensuring that all valves in a cluster are fully opened may become more problematic. When the top cluster valve is opened, hydraulic fluid is able to begin flowing out of the valve before the lower cluster valves and the bottom static valve are opened. Any diversion of fluid out the top valve will cause the amount of fluid flowing down the liner and the hydraulic pressure in the liner to fluctuate. The next cluster valve opened will present additional paths for fluid to flow out of the liner. Thus, as a ball travels through a set of clustered valves, it may become progressively more difficult to adjust and control pumping of fluid into the liner so as to ensure that all valves in the cluster are opened completely.

The ability to selectively inject fluid into various zones in a well bore is important not only in fracturing, but also in other processes for stimulating hydrocarbon production. Aqueous acids such as hydrochloric acid may be injected into a formation to clean up the formation. Water or other fluids may be injected into a formation from a “stimulation” well to drive hydrocarbons toward a production well. The ability to selectively flow fluids out a series of valves may improve the efficiency and efficacy of those stimulation processes. Moreover, as in fracturing a well, an operator may prefer to stimulate one zone at a time or to stimulate clusters of zones simultaneously.

The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved sliding sleeve cluster stimulation valves and for new and improved methods for fracking or otherwise stimulating formations using sliding sleeve cluster valves. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention.

SUMMARY OF THE INVENTION

The subject invention, in its various aspects and embodiments, is directed generally to improved ball seat tools used in oil and gas wells and to methods of using those tools. They have particular applicability in sliding, sleeve valves and other tools as are used in fracturing hydrocarbon bearing formations and in other methods for simultaneously stimulating production of hydrocarbons in multiple zones in a well bore. They also are particularly suitable for simultaneously fracturing or otherwise stimulating production from multiple zones in a well bore.

Broader embodiments of the invention provide for stimulation valves and other tools for well tubulars which comprise a cylindrical housing and a ball seat assembly. The housing is adapted for assembly into a tubular for a well and defines a conduit for passage of fluids through the housing. The ball seat assembly comprises first and second ball seats mounted in the conduit. The first ball seat has a first state in which it is adapted to receive a ball deployed into the conduit. It is adapted to transition to a second state in response to receiving the ball, in which second state it is adapted to release the ball. The first ball seat is operatively engaged with the second ball seat such that as the first ball seat transitions to its second state it causes the second ball seat to transition from a first state having increased clearance to a second state having reduced clearance. In the second state the second seat is adapted to receive the ball for actuation of the tool after the ball is released by the first seat. The second ball seat is adapted to actuate the tool and transition to a third state in response to receiving the ball, in which third state it is adapted to release the ball. The clearance through the second ball seat in its second state is less than the clearance through the first ball seat in its first state.

Other broad aspects and embodiments provide such stimulation valves and other well tubular tools wherein the load capacity of the first ball seat in its first state is less than the load capacity of the second ball seat in its second state.

Still other broad aspects and embodiments provide such stimulation valves and other well tubular tools which comprise a ball seat assembly comprising first and second split rings. The first split ring is operatively engaged with a first drive sleeve, and the first split ring and first drive sleeve are adapted for downward linear movement through the conduit. That downward movement causes the first split ring to transition from a compressed state in which it forms a ball seat sized to receive a ball deployed into the conduit to an expanded state in which it is sized to release the ball. The second split ring is adapted for downward linear movement though the conduit. That downward movement causing the second split ring to transition from an expanded state to a compressed state in which it forms a ball seat sized to receive the ball. The first split ring is adapted to move down the conduit and transition to its expanded state in response to receiving the ball thereon. The first drive sleeve operatively engages the second split ring as the first split ring moves down the conduit and causes the second split ring to move down the conduit and transition to its compressed state, whereby the second split ring is adapted to receive the ball after the ball is released by the first split ring. The clearance through the ball seat formed by the second split ring in its compressed state is less than the clearance through the ball seat formed by the first split ring in its compressed state.

Further aspects provide stimulation valves for well tubulars. The stimulation valves comprise a cylindrical housing, a valve body, and a ball seat assembly. The housing is adapted for assembly into a tubular for a well and defines a conduit for passage of fluids through the housing and one or more ports allowing fluid communication between the conduit and the exterior of the housing. The valve body is adapted for movement from a closed position restricting, fluid communication through the ports to an open position allowing fluid communication through the ports. The ball seat assembly comprises first and second ball seats mounted in the conduit. The first ball seat has a first state in which it is adapted to receive a ball deployed into the conduit and is adapted to transition to a second state in response to receiving the ball, in which second state it is adapted to release the ball. The first ball seat is operatively engaged with the second ball seat such that as the first ball seat transitions to its second state it causes the second ball seat to transition from a first state having increased clearance to a second state having reduced clearance, in which second state the second seat is adapted to receive the ball for actuation of the valve body after the ball is released by the first seat. The second ball seat is adapted to transition to a third state in response to receiving the ball, in which third state it is adapted to release the ball. The second hall seat is operatively engaged with the valve body such that as the second seat transitions to its third state it causes the valve body to move from its closed position to its open position. The clearance through the second ball seat in its second state is less than the clearance through the first ball seat in its first state or the load capacity. The load capacity of the first ball seat in its first state is less than the load capacity of the second ball seat in its second state.

One aspect of the invention provides such tools where the clearances through the first ball seat in its second state and through the second ball seat in its third state are sized to allow backflow of the ball through the seats with production fluids from the well.

Other aspects provide such tools where the first ball seat is adapted to remain its second state after releasing the ball.

Yet other aspects and embodiments provide such tools where the first ball seat comprises a split ring, the first split ring being compressed in the first state and being expanded in the second state and wherein the second ball seat comprises a split ring, the second split ring being expanded in the first state, compressed in the second state, and expanded in the third state.

Still other aspects provide such tools where the first ball seat is in its first state when the tool is configured for assembly into the tubular and run into the well.

The invention in other aspects and embodiments also provides for such tools where the second ball seat is mounted in the conduit below the first ball seat.

Further embodiments also provide such tools where the first ball seat is mounted in the conduit for downward linear movement relative to the housing, the first ball seat adapted to cause the second seat to transition to its second state as the first ball seat moves down the conduit and where the first ball seat is carried, in an area of reduced diameter in its first state and is adapted to move down the conduit into an area of enlarged diameter, whereby the first ball seat transitions to its the second state by radial displacement outward into the enlarged diameter area.

Another aspect of the invention provides such tools where the second ball seat is mounted in the conduit for downward linear movement relative to the housing, the second ball seat adapted to transition to its second and third states as the second ball seat moves down the conduit, where the second ball seat is carried in an area of enlarged diameter in its first state and is adapted to move down the conduit into an area of reduced diameter, whereby the second ball seat transitions to its the second state by being displaced radially inward by the reduced diameter area, and where the second ball seat is adapted to move down the conduit from the reduced diameter area to another area of enlarged diameter, whereby the second ball seat transitions to its the third state by radial displacement outward into the enlarged diameter area.

Yet other aspects and embodiments provide such valves where the ball seat assembly is mounted in the conduit above the ports and where the valves comprise a third ball seat mounted below the ports, the third ball seat being adapted to receive a ball to restrict fluid flow through the conduit.

The subject invention in other aspects and embodiments is directed to production liners and other tubulars for oil and gas wells and, especially, tubulars that allow fracturing or other stimulation of a formation after the tubular has been installed. Thus, other aspects provide for a liner or other tubular that is adapted for installation in a well and which comprises one or more of the novel tools in any of their various embodiments, as well as methods of using the tubulars.

Other embodiments include methods of lining a well that comprise installing a tubular comprising one or more of the novel tools in a well.

Yet other aspects provide methods of stimulating a formation in a well having a tubular comprising one or more of the novel valves, such as an uphole valve and a downhole valve. The uphole valve is opened by pumping a ball through the uphole valve. The pumped ball causes the first ball seat in the uphole stimulation valve to transition to its second the state and the second ball seat in the uphole stimulation valve to transition to its third the state. The downhole valve is opened by pumping the ball through the downhole valve. The pumped ball causing the first ball seat in the downhole stimulation valve to transition to its second the state and the second ball seat in the uphole stimulation valve to transition to its third the state. Fluid is pumped through the tubular and out the opened valves to stimulate the formation adjacent to the valves.

Thus, the present invention in its various aspects and embodiments comprises a combination of features and characteristics that are directed to overcoming various shortcomings of the prior art. The various features and characteristics described above, as well as other features and characteristics, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments and by reference to the appended drawings.

Since the description and drawings that follow are directed to particular embodiments, however, they shall not be understood as limiting the scope of the invention. They are included to provide a better understanding of the invention and the manner in which it may be practiced. The subject invention encompasses other embodiments consistent with the claims set forth herein.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a schematic illustration of a preferred embodiment 2 of the tubular assemblies of the subject invention showing an initial stage of a frac job in which three clustered zones 9 have been fractured simultaneously;

FIG. 1B is a schematic illustration of novel liner assembly 2 shown in FIG. 1A showing completion of the frac job;

FIG. 2A is a cross-sectional view taken along the central axis of a preferred embodiment 10 of stimulation valves of the subject invention showing cluster frac valve 10 in its run-in position with a ball B landed on a setting ball seat 41;

FIG. 2B is an axial cross-sectional view similar to the view of FIG. 2A showing novel cluster frac valve 10 with ball B landed on an actuation ball seat 51;

FIG. 2C is an axial cross-sectional view similar to the view of FIGS. 2A-B showing novel, cluster frac valve 10 in its open position with ball B having, passed through setting ball seat 41 and actuation ball seat 51;

FIG. 3A is an enlarged, detailed view of portion 3A of the view shown in FIG. 2A;

FIG. 3B is an enlarged, detailed view of portion JR of the view shown in FIG. 2B; and

FIG. 3C is an enlarged, detailed view of portion 3C of the view shown in FIG. 2C.

In the drawings and description that follows, like parts are identified by the same reference numerals. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional design and construction may not be shown in the interest of clarity and conciseness.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

The present invention generally relates to ball seat tools used in oil and gas wells and to methods of using those tools, and especially to stimulation valves used in completing oil and gas wells. In broader aspects the novel tools have a staged ball seat assembly including two ball seats. One ball seat is used to set a second ball seat which then may be employed to actuate the tool in one fashion or another. The setting seat may have greater clearance and a lower load capacity relative to the actuation seat once it has been set insofar as the force required to set the actuation seat may be significantly less than the force that must be transmitted through the actuation seat to actuate the tool.

Broader embodiments of the novel tools comprise a cylindrical housing adapted for assembly into a tubular for a well. The housing generally defines a conduit for passage of well fluids through the housing. In other embodiments, the novel tools further comprise one or more ports allowing fluid communication between the conduit and the exterior of the housing. A valve body is provided, which can move from a closed position restricting fluid communication the ports to an open position allowing fluid communication through the ports.

For example, a preferred frac valve 10 is illustrated in FIGS. 1-3. Frac valve 10 is a cluster frac valve. That is, it is a valve that is intended to be clustered with a static valve and, if desired, additional cluster valves, so as to allow multiple zones to be fractured in a single stage. Thus, as may be seen in the schematic representations of FIG. 1, a number of cluster frac valves 10 and a number of static frac valves 11 may be incorporated into production liner 2 which forms part of a typical oil and gas well 1. Well 1 is serviced by a derrick 3 and various other surface equipment (not shown). The upper portion of well 1 is provided with a casing 4. Production liner 2 has been installed in the lower portion of casing 4 via a liner hanger 5. It will be noted that the lower part of well 1 extends generally horizontally through a hydrocarbon bearing formation 6 and that liner 2 has been cemented in place. That is, cement 7 has been introduced into the annular space between liner 2 and the well bore 8.

As discussed in greater detail below, a typical frac job will generally proceed from the lowermost zone in a well to the uppermost zone. The zones may be fractured individually, or multiple zones may be clustered and fractured simultaneously in a single stage. FIG. 1A, therefore, shows the well bore after the initial stage has been completed. Fractures 9 have been established adjacent a static valve 11a and adjacent cluster valves 10a in the first three zones near the bottom of well 1. Zones further uphole in well 1 will be fractured in successive stages until, as shown in FIG. 1B, all stages of the frac job have been completed and fractures 9 have been established in all zones, it also will be noted that production liner 2 is shown only in part as such liners may extend for a substantial distance. The portion of liner 2 not shown also will incorporate a number of valves 10 and 11, and well 1 will be provided with additional fractures 9 in the area not shown in FIG. 1.

Preferred novel cluster frac valve 10 is shown in greater detail in FIGS. 2-3. As shown in overview in FIG. 2, cluster valve 10 generally comprises a housing 20, an insert sleeve 30, a setting ball seat 41, an upper drive sleeve 40, an actuation ball seat 51, as a lower drive sleeve 50, and a valve sleeve 60. Housing 20, as is typical of many downhole tools, is generally cylindrical and serves as the frame to which the other valve components are mounted, directly or indirectly. Housing 20 and other components collectively define an axial, central conduit 21 through which well fluids may pass. Housing 20 also has ports 22 which, when valve sleeve 60 is in an open position, allow fluid to pass from conduit 21 to the exterior of housing 20, as may be seen in FIG. 2C.

More particularly, housing 20 generally comprises an upper housing, sub 23, an intermediate housing sub 24, and a lower housing sub 25, each of which are generally cylindrically shaped, tubular components. Subs 23, 24, and 25 are threaded together or otherwise assembled by means common in the art, such as threaded connections. Upper housing sub 23 and lower housing sub 25 also are adapted for assembly into liner joints and other tubulars. Thus, for example, the upper end of upper housing sub 23 and the lower end of lower housing sub 25 are provided with threads so that valve 10 may be threaded into production liner 2. The inner diameters of the lower portion of upper housing sub 23 and of intermediate housing sub 24 are generally enlarged somewhat relative to the inner diameter of the upper portions of upper housing sub 23 and lower housing sub 25 to accommodate the other valve components, such as insert sleeve 30, setting ball seat 41, upper drive sleeve 40, actuation ball seat 51, lower drive sleeve 50, and valve sleeve 60.

The housing of the novel valves has one or more ports therein that allows passage of well fluids. Preferably, as in preferred cluster valve 10 and seen best in FIG. 2, they are provided with a plurality of ports, such as flow ports 22. Flow ports 22 may be arranged radially around a portion of intermediate housing sub 24. It will be noted that intermediate housing sub 24 includes three longitudinally spaced sets of radially arranged ports 22. The precise number and arrangement of flow ports 22, however, and their cross section, in general are not critical to practicing, the invention. They may be varied as desired to provide whatever flow capacity or pattern as may be desired for the novel valves.

The valve body of the novel stimulation valves is adapted to shut off or to allow fluid flow through the ports in the valve housing. Thus, for example, valve sleeve 60 in valve 10 is a generally cylindrical sleeve mounted within intermediate housing sub 24, as may be seen in FIG. 2. As shown therein, valve sleeve 60 has a number of ports 62. The arrangement and size of ports 62 are generally coordinated with ports 22 in intermediate housing sub 24. Thus, valve sleeve 60 is provided with three longitudinally spaced sets of radially arranged ports 62.

When valve sleeve 60 is in its initial, run-in position as shown in FIG. 2A, valve ports 62 are offset from flow ports 22 in intermediate housing sub 24. Fluid flow between central conduit 21 to the exterior of housing 20 is shut off. When ball B is deployed into valve 10 to actuate it, as described in further detail below, valve sleeve 60 is shifted downward such that ports 62 in valve sleeve 60 align with flow ports 22 in intermediate housing sub 24. Fluids may thereafter flow from central conduit 21 through ports 22 and 62 to the exterior of valve 10.

The staged ball seat assembly includes a setting ball seat and an actuation ball seat. The setting ball seat has a first state in which it is adapted to receive a ball deployed into the tool conduit and a second state in which it is adapted to release the ball. In effect, as a ball is deployed through the tool, the setting ball seat will first catch and then release the ball, allowing it to travel further down or out the tool. In some embodiments, the setting ball seat will catch and release a ball to actuate a drive sleeve which in turn is adapted to engage and set the actuation ball seat.

In any event, the setting ball seat is operatively engaged with the actuation ball seat. As the setting ball seat catches and then releases the ball, it will set the actuation ball seat. That is, as the setting ball seat transitions to its second state, it will cause the actuation ball seat to transition from a first state to a second state in which it is adapted to receive the ball released by the setting ball seat. The actuation ball seat thus is able to catch the ball released by the setting ball seat, whereupon hydraulic pressure may be applied to the seated ball to actuate the tool. In some embodiments, the actuation seat will transition to a third state where it is adapted to release the ball, allowing it to continue traveling through the tool.

For example, in cluster valve 10 the ball seat assembly generally comprises insert sleeve 30, setting ball seat 41, upper drive sleeve 40, actuation ball seat 51, and lower drive sleeve 50. As may be seen in FIG. 2, the various components of the ball seat assembly are situated near the upper portion of valve 10 and above ports 22. Sleeve insert 30 is a generally cylindrical sleeve mounted, for example, by threaded connections at its upper end, into an enlarged diameter portion at the lower end of upper housing sub 23 and extending into intermediate housing sub 24. As seen best in the enlarged views of FIG. 3, sleeve insert 30 defines various areas of reduced and enlarged diameters and ramped surfaces which, as described below, control the operation of setting ball seat 41, upper drive sleeve 40, actuation ball seat 51, and lower drive sleeve 50.

Setting ball seat 41 and upper drive sleeve 40 are mounted for linear movement within sleeve insert 30. As may be seen best in FIG. 3A, when cluster valve 10 is in its initial, run-in position, setting, ball seat 41 and upper drive sleeve 40 are both in their upward-most positions, with setting ball seat 41 abutting, a reduced diameter portion of upper housing sub 23 on one side and abutting, the upper end of upper drive sleeve 40 on the other. Upper drive sleeve 40 is a generally cylindrical sleeve, and preferably it is initially secured in place, e.g., by shearable pins or other shear members, so that setting ball seat 41 is substantially retained between the reduced diameter portion of upper housing sub 23 and upper drive sleeve 40.

Actuation ball seat 51 is also mounted for linear movement within insert sleeve 30 and, when cluster valve 10 is in its run-in position as shown in FIG. 3A, abuts the lower end of upper drive sleeve 40 and is retained in place by upper drive sleeve 40 and an area of reduced diameter in insert sleeve 30. Lower drive sleeve 50 is a generally cylindrical sleeve mounted for linear movement within the lower portion of sleeve insert 30 and the upper portion of intermediate housing sub 24. The upper end of lower drive sleeve 50 extends around the lower end of a downwardly extending, reduced diameter skirt provided on actuation ball seat 50, but otherwise is spaced somewhat from actuation ball seat 51. The lower end of lower drive sleeve 50 engages the upper end of valve sleeve 60.

The setting ball seat of the novel tools is adapted to catch and release balls pumped into the valve so as to set the actuation seat. Thus, for example, setting ball seat 41 and actuation ball seat 51 in cluster valve 10 are both split rings mounted under compression within insert sleeve 30, as may be best appreciated from FIG. 3. More particularly, both split rings have tapered upper portions and a discontinuous annular body, the body being discontinuous in the sense that a gap is provided therein. The gap allows the body of the split rings to be radially compressed, and when compressed, the gap preferably is closed allowing the body to form a continuous seat. The body also preferably is configured to provide a gap which angles through the body instead of directly across it. An angled gap allows the creation of a more effective seal when the body is compressed into a continuous seat. In any event, by providing a gap in their otherwise annular body, setting ball seat 41 and actuation ball seat 51 can be compressed to receive a ball of a defined diameter that would pass through them in their expanded state.

When setting ball seat 41 and drive sleeve 40 are in their initial upward position as shown, for example, in FIG. 3A, setting ball seat 41 is radially compressed within insert sleeve 30. Being in a sufficiently compressed state, actuation seat 41 will catch a ball pumped into valve 10, such as ball B. Continued pumping of fluid into liner 2 will create hydraulic pressure above ball B which shears any shear members present and urges setting ball seat 41 and upper drive sleeve 40 downward relative to insert sleeve 30 and housing 20.

As they travel axially downward, i.e., downward along the central axis of the tool, setting ball seat 41 will shift into a shouldered area of enlarged diameter in insert sleeve 30 located just below its starting a position, as may be seen best in the enlarged view of FIG. 3B. As it does, setting ball seat 41 will be able to expand radially outward, increasing its inner clearance or size. As setting ball seat 41 expands, it will release ball B, that is, it will be of sufficient size to allow ball B to pass through it and to continue traveling downward through valve 10.

As setting ball seat 41 first catches and then releases ball B, it will set actuation ball seat 51. More particularly, setting ball seat 41 will drive upper drive sleeve 40 downward, which in turn will drive actuation ball seat 51 downward and up onto a reduced diameter portion of insert sleeve 30. Preferably, as in cluster valve 10, actuation ball seat 51 and the reduced diameter portion of insert sleeve 30 will be provided with mating ramped surfaces to facilitate that action. In any event, as actuation ball seat 51 is driven onto the reduced diameter portion of insert sleeve 30, it will be compressed radially inward, diminishing its size, such that it is able to catch ball B when it is released by setting ball seat 41, as seen best in the enlarged view of FIG. 3B.

As it is shifted downward and radially compressed, and in any event upon receiving ball B, actuation ball seat 51 will shoulder out on lower drive sleeve 50. Continuing pressure applied to ball B will cause both actuation ball seat 51 and lower drive sleeve 50 to travel downward. Drive sleeve 50 in turn urges valve sleeve 60 downward into its open position to allow flow through ports 22. As shown in FIG. 3C, actuation ball seat 51 then, and preferably after drive sleeve 50 has traveled downward a distance sufficient to move valve sleeve 60 to its fully open position, will shift into another shouldered, enlarged portion of insert sleeve 30 and will relax and expand radially. Once it has expanded, actuation ball seat 51 will release ball B, allowing ball B to pass through valve 10 and continue traveling down through liner 2, as shown in FIG. 2C.

Both setting seat 41 and actuation seat 51 typically will be mounted within valve 10 such that they are always under a certain degree of compression, even in positions where they are described as relaxed and expanded. It will be understood that references to compressed states or positions, therefore, typically will references states of increased compression relative to states or positions where they may be more relaxed, more expanded, and less compressed, and not necessarily to states where the are under no compression.

It will be appreciated that the force required to urge setting, ball seat downward and set actuation ball seat typically will be significantly less than the force that must be transmitted through actuation ball seat to actuate a valve or other tool. Thus, by providing a staged ball seat assembly, a valve or other tool may be provided with greater effective clearance through the tool than might otherwise be required to provide the load capacity required for actuating the tool. That is, by coordinating the relative sizing and load capacities of the setting ball seat and the actuation ball seat in their various positions it is possible to actuate a valve or other tool while providing a larger effective internal diameter and greater internal clearance through the tool so that larger balls may be passed through the tool. In particular, the size or clearance through the actuation ball seat, when it receives an actuation ball, will be less than the size or clearance through the setting ball seat. Alternately, the load capacity of the actuation ball seat, upon receiving an actuation ball, will be greater than the load capacity of the setting ball seat when it receives the ball.

For example, cluster valve 10 may have an internal clearance equal to a value x as dictated by the clearance through setting ball seat 41 and actuation ball seat 51. The internal diameter of or clearance through setting ball seat 41 when it is in its initial or run-in position will be x. Similarly, the clearance through actuation ball seat 51 when it is in its initial or run-in position will be at least x. Thus, valve 10 will allow balls with a diameter less than x to pass through it and will be actuated by balls having a somewhat larger diameter, such a x+y.

After setting, ball seat 41 has caught and released ball B and, in turn, actuation ball seat 51 has been set, the clearances through seats 41 and 51 have been, respectively, increased and decreased by certain amounts, either the same or different amounts. Setting ball seat 41, for example, now has an increased clearance of, for example, x+z (which is equal to or greater than the clearance required for passage of ball B, i.e., z>y). Actuation ball seat 51 has a diminished clearance of, for example, x−z. After actuation ball seat 51 has caught and released ball 1 and valve sleeve 60 has been actuated, the clearance through actuation ball seat 51 will have increased to at least x+z.

Other factors being equal, the load capacity of the setting ball seat and actuation ball seat will depend on the degree to which they provide interference with a ball landed on those seats. Load capacity, in this sense, will be understood as the load that may be applied to a given ball before failure of either the ball or seat, such that force may no longer be effectively transmitted through the ball and seat. The relative load capacity of the seats will be determined by reference to identical balls being seated thereon.

In valve 10, for example, the load capacity of actuation ball seat 51, since it has a relatively reduced clearance once it has been set and provides greater interference when ball B lands on it, will have a higher load capacity than setting ball seat 41. The load capacity of actuation ball seat 51 once it has been set, of course, must be greater than the force required to actuate valve sleeve 60. The load capacity required for setting ball seat 41, however, can and will be significantly less than that required for actuation ball seat 51, since the force required to set actuation ball seat 51 is significantly less than that required to actuate valve sleeve 60.

Thus, valve 10 may be provided with greater clearance for balls which must pass through it, but at the same time will provide sufficiently high load capacity for actuation of valve 10. Clearance through valve 10 will be determined by the interference required to provide setting ball seat 41 with the load capacity required to set actuation ball seat 51, not the interference required to provide actuation ball seat 51 with the load capacity to actuate valve sleeve 60. For example, valve 10 may be provided with a clearance of x instead of x−z, even if a clearance of x−z is required to provide sufficient load capacity for actuation. Once set, actuation ball seat 51 will provide the load capacity required for actuation of valve sleeve 60.

The compressible, split rings used to provide setting seat 41 and actuation seat 51 in valve 10 provide a simple, effective mechanism for allowing the selective catch and release of a ball. They also provide an effective seat which allows a captured ball to substantially shut off flow through the seat, which in turn allows hydraulic force to be efficiently created and effectively transferred to a drive member. Any number of similar mechanisms, however, may be used to provide ball seats in the novel tools.

A plurality of radially displaceable ring segments or dogs may be used and mounted, for example, in suitably configured slots in drive sleeves 40 and 50. For example, such segments and dogs would be mounted such that they are displaced radially inward when drive sleeve 40 is in its upper, initial position, and allowed to be displaced outward when drive sleeve 40 has set actuation seat 51. Drive sleeve 40 or 50 also may be provided with resilient collet fingers that could be compressed to capture a hall and allowed to relax to pass a ball.

It also will be appreciated that the description references drop balls. Spherical balls are preferred, as they generally will be transported though well tubulars and into engagement with downhole components with greater reliability and lower tolerances. Other conventional plugs, darts, and the like which do not have a spherical shape, however, also may be used to index and actuate the novel tools. The configuration of the “ball” seats necessarily would be coordinated with the geometry of such devices. “Balls” as used herein, therefore, will be understood to include any of the various conventional plug and actuating devices that are commonly deployed into a well to mechanically actuate mechanisms, even if such devices are not spherical. “Ball” seats is used in a similar manner.

Once they are opened, the novel valves preferably will stay open to allow hydrocarbons to flow from the formation into the liner once stimulation has been completed and the well is ready for production. For example, valve 10 is provided with a split lock-ring 55 which is initially disposed in a somewhat expanded state in a groove in the inner surface of the lower end of valve sleeve 60. As valve sleeve 60 completes its down stroke, lock-ring 55 will align with a groove 26 in lower housing sub 25 and expand partially out of the groove in valve sleeve 60 and into groove 26. That engagement between lock-ring 55, the groove in valve sleeve 60, and groove 26 will hold valve sleeve 60 in its lower, open position, thus ensuring that once fracturing is completed, hydrocarbons flowing from the formation will be able to pass through ports 22 and 62 and flow up liner 2 to the surface.

While lock-ring 55 provides a simple, effective mechanism for preventing valve sleeve 60 from moving back to its closed position and ensuring that valve 10 remains open, other mechanisms may be incorporated into the novel valves to reduce the likelihood that the valve sleeve will move out of its open position. For example, a lock-ring could be mounted in the housing under compression and then expand out into a groove in inner surface of the valve sleeve. A ratchet ring may be disposed in a groove on the outer surface of the valve sleeve and mating detents provided on the inner surface of the valve housing, or vice versa, to preclude movement of valve sleeve back toward its closed position once it has been opened. The lower end of valve sleeve also may be configured to shoulder out on a stop provided on the valve housing. Dogs or collet mechanisms also may be provided on the valve sleeve or in the valve housing such that the dogs or flexible fingers latch into grooves or recesses and restrict relative movement between the valve sleeve and the valve housing.

Given the connection between valve sleeve 60 and lower drive sleeve 50, locking of valve sleeve 60 in its open position also precludes upward movement of lower drive sleeve 50 which might otherwise urge actuation seat 51 back onto the area of reduced diameter in insert sleeve 30 and cause it to compress radially. Actuation seat 51 thus is effectively retained between a reduced diameter area of insert sleeve 30 and the upper end of lower drive sleeve 50. Similarly, setting seat 41 is effectively retained in a groove or an area of enlarged reduced diameter in insert sleeve 30, and upper drive sleeve 40 is retained between setting seat 41 and an area of reduced diameter in insert sleeve 30. Thus, both setting seat 41 and actuation seat 51 will remain in their expanded states after valve sleeve 60 has been actuated and valve 10 opened. That in turn ensures that the balls used to actuate valve 10 during fracturing are able to travel back through valve 10 as production fluids flow upward through liner 2. Other mechanisms for ensuring that seats 41 and 51 remain in their expanded, ball-pass state, however, may be used if desired.

Static frac valve 11 is an example of a second preferred embodiment of the novel frac valves. Static valve 11 is designed and constructed substantially the same as cluster valve 10 except that it comprises an isolation seat mounted within valve 11 below flow ports 22. Isolation seat is configured to capture a ball deployed into valve 11. The ball will be caught by the actuation seat 51 in valve 11 to open flow ports 22 in valve 11 and then released, allowing it to seat on the isolation seat. Once seated thereon, the ball will substantially shut off fluid flow through valve 11 to lower portions of liner 2, substantially isolating, any downhole valves 10 and 11 from fluid pumped into liner 2 and forcing fluid out flow ports 22 of static valve 11 and the opened cluster valves 10 above it.

For example, the isolation seat may comprise a split ring, similar to the split rings provided in setting ball seat 41 and actuation ball seat 51, which is adapted for compression by valve sleeve 60 as it is moved to its open position. The isolation seat would transition from a clearance at least as large as the initial clearance through setting ball seat 41 and actuation ball seat 51 to a clearance providing sufficient load capacity for isolating downhole portions of liner 2. The isolation seat then may be adapted for upward displacement into areas of enlarged diameter by balls backflowed through the valve with production fluids flowing, such displacement allowing the isolation seat to relax and expand and allow backflow of balls through the valve. Such mechanisms for setting and displacing isolation seats are disclosed in applicant's co-pending applications, U.S. Ser. No. 13/987,053, filed Jun. 28, 2013, and U.S. Ser. No. 14/229,362, filed Mar. 28, 2014, the disclosures of which are incorporated herein in their entirety.

As noted above, the advantages derived from the novel valves perhaps are best appreciated in the context of large, multi-stage fracking operations. Embodiments of the subject invention, therefore, also are directed to methods of fracturing formations in a well bore using the novel frac valves.

A typical multi-stage fracking operation will start by making up a production liner containing, a series of valves. The novel valves make it possible to incorporate a relatively large number of valves into a production liner or other tubular and, therefore, to fracture a formation in a relatively large number of zones. Thus, as will be appreciated from FIG. 1, a number of cluster valves 10 and static valves 11 may be incorporated into production liner 2 just upstream of an initiator valve (not shown) situated in production liner 2 near the toe of well bore 8. The valves are grouped into a series of clustered valves including one or more cluster valves 10 and a static valve 11. For example, as shown in FIG. 1, liner 2 includes clustered valves 10a and 11a to 10n and 11n (not all of which are shown), each set of clustered valves including two cluster valves 10 and a static valve 11.

The setting, seat 41 and actuation seat 51 in the first set of clustered valves 10a and 11a all are the same size so that cluster valves 10a and static valve 11a may be actuated by balls of the same size. Likewise, the isolation seat in static valve 11a is sized to receive balls of the same size. Cluster valves 10b and static valve 11b also share a common-sized setting seats 41, actuation seats 51 and isolation seats, but those seats are sized to catch and release or to catch, respectively, a slightly larger ball than that which is used to actuate valves 10a and 11a. The other sets of clustered valves are similarly configured to share common-sized seats, with cluster valves 10n and static valve 11n having the largest seats among the sets of clustered valves 10 and 11.

By incorporating a staged ball seat assembly, however, it will be appreciated that the incremental difference between the seats in, and the balls actuating a series of tools may be reduced. In valve 10, per the examples recited above, when actuation seat 51 is set it has a clearance of x-z as required to provide the load capacity required for actuation of valve sleeve 60. In conventional ball-drop tools lacking a staged ball seat assembly, that would mean that the next lower valve (or cluster of valves) in the series would be sized to actuate a ball no larger than that which would pass through an actuation seat having a clearance of x-z. The clearance through tool 10, however, is determined by the clearance through setting seat 41, which is x, and the next lower valve (or cluster of valves) may be actuated by larger balls, balls which may not pass through a clearance of x-z, but can pass through a clearance of x.

The incremental difference between valves in a series depends in part on the size or clearance through the valves. Valves with larger clearances will require somewhat larger incremental differences. In practice, however, the staved ball seat assemblies will allow minimum incremental differences on the order of 1/16″ where conventional ball-drop tools might have minimum incremental differences of ⅛″.

In any event, liner 2 then may be run into a well bore and installed near the lower end of host casing 4, for example, by a liner hanger 5. Valves 10 and 11 will be in their closed, run in position. If the frac job will be performed on an open hole, the production liner also will incorporate a series of packers that will be set to seal off and isolate various zones in the well bore. If not, the liner will be cemented in place by pumping a plug of cement down the production liner, out the bottom of the liner, and into the annulus between the liner and well bore. The cement will be allowed to harden and encase the liner, for example, as shown in FIG. 1, where cement 7 has encased production liner 2.

Installing a liner or other well tubular with the novel frac valves may be performed by conventional methods and utilizing any number of widely available tools and supplies as are used in installing conventional liners and tubulars. Many such designs are known and are commercially available. The novel valves typically will not be used as initiator valves, but may be when a ball may be deployed into the valve without pumping. Otherwise, a wide variety of conventional initiator valves are known and may be used with the novel valves in a liner assembly.

In any event, once liner 2 has been installed, hydraulic pressure will be increased in production liner 2 to open the initiator frac valve, fracture the first zone near the toe of well bore 8, and to established flow into production liner 2. Cluster valves 10 and static valves 11 then may be actuated by deploying balls through production liner 2. More specifically, a first ball B is deployed into production liner 2. Since it is too small to be captured in setting seat 41 of the upper sets of clustered valves (valves 10n and 11n to valves 10b and 11b), it will pass through those valves without actuating them. As it continues down production liner 2, however, it first lands on setting seat 41 and sets actuation seat 51 of upper cluster valve 10a, which it turn causes ports 22 therein to be opened. Actuation seat 51 in upper cluster valve 10a then will release first ball B, allowing it to continue down liner 2. First ball B then will land on setting seat 41 of the lower cluster valve 10a, setting actuation seat 51 and ultimately causing ports 22 therein to be opened. First ball B then will be released, and it will travel down into static valve 11b and open ports 22 therein. It then will come to rest on the isolation seat in static valve 11b.

At this point, ports 22 in cluster valves 10a and static valve 11a are all opened. The zones adjacent valves 10a and 11a then can be fractured simultaneously. Once that stage is complete, a second, slightly larger ball B will be deployed to open clustered is valves 10b and 11b. The zones adjacent those valves 10b and 11b then will be fractured simultaneously. Successively larger balls B then will be deployed to complete all stages and to fracture the zones adjacent clustered valves 10c and 11c to 10n and 11n. Given that setting, seat 41 and actuation seat 51 have remained in their expanded positions after releasing ball B, balls B used to actuated each series of valves 10 and 11 will be able to backflow up through those valves with production fluids after fracturing, has been completed.

Valves in a production liner will be designed to open above certain pressure thresholds, and operators typically will target flow rates and pressures which are intended to optimize fracturing of a formation. Thus, it is necessary, but not always easy to control the pumps at the surface to ensure that the proper amount of fluid is pumped into a liner. One complicating factor arises from opening the valves, especially a set of clustered valves.

When top cluster valve 10a is opened, for example, hydraulic fluid is able to flow out liner 2 via ports 22. To the extent that fluid is diverted out of liner 2, and absent adjustment of pump rates, hydraulic pressure in liner 2 will drop. Since setting seat 41 and actuation seat 51 are located above flow ports 22, however, any such pressure drop cannot complicate or prevent complete opening of top cluster valve 10a. That is, any such pressure drop will occur only after valve sleeve 60 has been driven downward and flow ports 22 have been fully opened.

Similarly, while bottom cluster valve 10a may experience a pressure drop due to the opening of top cluster valve 10a, it will not experience any pressure drop associated with it being opened. Any pressure drop caused by opening bottom cluster valve 10a will only occur after it has been completely opened. Static valve 11b also will not experience any pressure drop associated with its opening. Setting seat 41 and actuation seat 51 in static valve 11b also are located above flow ports 22. Thus, each valve 10a and 11a downhole in the cluster will experience less of pressure drop and the likelihood that they will not be completely opened will be diminished.

When installed near the upper end of a series of valves, the seats in the ball seat assembly have a much greater clearance and may not restrict flow through a liner to a significant degree. As the series of valves extend progressively downhole, however, the seats will become progressively smaller, thus restricting flow through the liner to a greater degree. After the fracturing operation is complete, an operator may want to enhance the flow capacity of a liner to allow greater production of hydrocarbons through the liner.

Thus, restriction sleeve 30 and actuation seat 41 may be fabricated from materials that are more easily drilled out than the relatively hard steel alloys typically used to fabricate downhole tool components. Such drillable materials include softer metals and alloys such as cast iron and aluminum. They also may include even more easily drilled materials such as polyurethane or composite materials, the latter including filament wound, fiberglass cloth wound, and molded fiberglass composites employing epoxy, phenolic, polyamide or other common resins.

It will be appreciated, therefore, that while they may be used in wells where only a few zones will be fractured, the novel frac valves are particularly suited for incorporation into production liners or other tubulars where a large number of zones will be fractured in multiple stages. As described above, three zones may be fractured in a single stage, and a single liner may allow for a number of stages by coordinating the relative size of the actuation seats in each set of clustered valves. Additional cluster valves may be provided in each set of clustered valves, however, to allow even more zones to be fractured. Each set of clustered valves may be provided with the same, or a different number of cluster valves. Thus, the novel valves not only allow fracturing to proceed over an extended distance in a large number of zones, but they allow great flexibility in fracturing the well.

It will be appreciated that valves 10 and 11 and other embodiments of the novel valves typically will incorporate various shear screws, wires, and the like to immobilize components during assembly, shipping, or run-in of the valve. Shear screws, for example, typically will be employed to immobilize the drive sleeve or valve sleeve of valves 10 and 11. O-rings, for example, may be provided between housing subs and around flow ports to provide pressure tight connections. Pin or screws may be provided for engagement with slots or other features so as to rotationally lock various components of the tools. Similarly, reverse threads may be provided to lock components against rotation of the tool or a bit in the tool in a particular direction. Such features are shown to a certain degree in the figures, but their design and use in tools such as the novel valves is well known and well within the skill of workers in the art. In large part, therefore, discussion of such features is omitted from this description of preferred embodiments.

The various valves 10 and 11 have been described as being incorporated into a liner and, more specifically, a production liner used to fracture a well in various zones along the well bore. A “liner,” however, can have a fairly specific meaning within the industry, as do “casing” and “tubing.” in its narrow sense, a “casing” is generally considered to be a relatively large tubular conduit, usually greater than 4.5″ in diameter, that extends into a well from the surface. A “liner” is generally considered to be a relatively large tubular conduit that does not extend from the surface of the well, and instead is supported within an existing casing or another liner. It is, in essence, a “casing” that does not extend from the surface. “Tubing” refers to a smaller tubular conduit, usually less that 4.5″ in diameter. The novel valves, however, are not limited in their application to liners as that term may be understood in its narrow sense. They may be used to advantage in liners, casings, tubing, and other tubular conduits or “tubulars” as are commonly employed in oil and gas wells.

Likewise, while the exemplified valves are particularly useful in fracturing a formation and have been exemplified in that context, they may be used advantageously in other processes for stimulating production from a well. For example, an aqueous acid such as hydrochloric acid may be injected into a formation to clean up the formation and ultimately increase the flow of hydrocarbons into a well. In other cases, “stimulation” wells may be drilled in the vicinity of a “production” well. Water or other fluids then would be injected into the formation through the stimulation wells to drive hydrocarbons toward the production well. The novel valves may be used in all such stimulation processes where it may be desirable to create and control fluid flow in defined zones through a well bore. Though fracturing a well bore is a common and important stimulation process, the novel valves are not limited thereto.

Exemplified valves 10 and 11 have been disclosed and described as being assembled from a number of separate components. Workers in the art will appreciate that various of those components and other tool components may be fabricated as separate components, or may be combined and fabricated as a single component if desired. For example, housing 20 in valve 10 is assembled from three major components, but upper housing sub 23 and intermediate housing sub 24 could be fabricated as a single component. Similarly, lower drive sleeve 50 and valve sleeve 60 are separate components, but could be single component. Insert sleeve 30 also could be fabricated with upper housing sub 23 as a single component. Other modifications of this type are within the skill of workers in the art and may be made to facilitate fabrication, assembly, or servicing, of the valves or to enhance its adaptability in the field.

Otherwise, the valves of the subject invention may be made of materials and by methods commonly employed in the manufacture of oil well tools in general and valves in particular. Typically, the various major components will be machined from relatively hard, high yield steel and other ferrous alloys by techniques commonly employed for tools of this type. As noted above, however, components may also be made of somewhat softer, more easily drilled materials where the component will be drilled out after completion of a stimulation operation.

It also will be appreciated that various other downhole tools employ ball seats, and may incorporate ball seats that must selectively capture a ball or allow it to pass. Such tools include cement diverters, circulation diverters, and surge diverters. The novel ball seat assemblies disclosed herein may be used to advantage in such tools as well. Likewise, the novel ball seat assemblies may be used in frac plugs and plugs used in other stimulation or other well operations.

While this invention has been disclosed and discussed primarily in terms of specific embodiments thereof, it is not intended to be limited thereto. Other modifications and embodiments will be apparent to the worker in the art.

Claims

1. A tool for a well tubular, said tool comprising:

(a) a cylindrical housing adapted for assembly into a tubular for a well and defining a conduit for passage of fluids through said housing;

(b) a ball seat assembly, said ball seat assembly comprising first and second ball seats mounted in said conduit, wherein: i) said first ball seat has a first state in which it is adapted to receive a ball deployed into said conduit and is adapted to transition to a second state in response to receiving said ball, in which second state it is adapted to release said ball; ii) said first ball seat is operatively engaged with said second ball seat such that as said first ball seat transitions to its second state it causes said second ball seat to transition from a first state having increased clearance to a second state having reduced clearance, in which second state said second seat is adapted to receive said ball for actuation of said tool after said ball is released by said first seat; iii) said second ball seat is adapted to actuate said tool and transition to a third state in response to receiving said ball, in which third state it is adapted to release said ball; and iv) wherein the clearance through said second ball seat in its second state is less than the clearance through said first ball seat in its first state.

2. The tool of claim 1, wherein the clearances through said first ball seat in its second state and through said second ball seat in its third state are sized to allow backflow of said ball through said seats with production fluids from said well.

3. The tool of claim 1, wherein said first ball seat is adapted to remain in its second state after releasing said ball.

4. The tool of claim 1, wherein, said first ball seat comprises a split ring, said first split ring being compressed in said first state and being expanded in said second state and wherein said second ball seat comprises a split ring, said second split ring being expanded in said first state, compressed in said second state, and expanded in said third state.

5. The tool of claim 1, wherein said first ball seat is in its first state when said tool is configured for assembly into said tubular and run into said well.

6. The tool of claim 1, wherein said second ball seat is mounted in said conduit below said first ball seat.

7. The tool of claim 1, wherein said first ball seat is mounted in said conduit for downward linear movement relative to said housing, said first ball seat adapted to cause said second seat to transition to its second state as said first ball seat moves down said conduit.

8. The tool of claim 7, wherein said first ball seat is carried in an area of reduced diameter in its first state and is adapted to move down said conduit into an area of enlarged diameter, whereby said first ball seat transitions to its said second state by radial displacement outward into said enlarged diameter area.

9. The tool of claim 1, wherein said second ball seat is mounted in said conduit for downward linear movement relative to said housing, said second ball seat adapted to transition to its second and third states as said second ball seat moves down said conduit.

10. The tool of claim 9, wherein said second ball seat is carried in an area of enlarged diameter in its first state and is adapted to move down said conduit into an area of reduced diameter, whereby said second ball seat transitions to its said second state by being displaced radially inward by said reduced diameter area.

11. The tool of claim 10, wherein said second ball seat is adapted to move down said conduit from said reduced diameter area to another area of enlarged diameter, whereby said second ball seat transitions to its said third state by radial displacement outward into said enlarged diameter area.

12. A tool for a well tubular, said tool comprising:

(a) a cylindrical housing adapted for assembly into a tubular for a well and defining a conduit for passage of fluids through said housing;

(b) a ball seat assembly, said ball seat assembly comprising first and second ball seats mounted in said conduit, wherein: i) said first ball seat has a first state in which it is adapted to receive a ball deployed into said conduit and is adapted to transition to a second state in response to receiving said ball, in which second state it is adapted to release said ball; ii) said first ball seat is operatively engaged with said second ball seat such that as said first ball seat transitions to its second state it causes said second ball seat to transition from a first state having reduced load capacity to a second state having increased load capacity, in which second state said second seat is adapted to receive said ball after said ball is released by said first seat; iii) said second ball seat is adapted to transition to a third state in response to receiving said ball, in which third state it is adapted to release said ball; and iv) wherein the load capacity of said first ball seat in its first state is less than the load capacity of said second ball seat in its second state.

13. A tool for a well tubular, said tool comprising:

(a) a cylindrical housing adapted for assembly into a tubular for a well and defining a conduit for passage of fluids through said housing; and

(b) a ball seat assembly, said ball seat assembly comprising: i) a first split ring operatively engaged with a first drive sleeve, said first split ring and first drive sleeve being adapted for downward linear movement through said conduit, said downward movement causing said first split ring to transition from a compressed state in which it forms a ball seat sized to receive a ball deployed into said conduit to an expanded state in which it is sized to release said ball; ii) a second split ring adapted for downward linear movement though said conduit, said downward movement causing said second split ring to transition from an expanded state to a compressed state in which it forms a ball seat sized to receive said ball; iii) wherein said first split ring is adapted to move down said conduit and transition to its expanded state in response to receiving said ball thereon; iv) wherein said first drive sleeve operatively engages said second split ring as said first split ring moves down said conduit and causes said second split ring to move down said conduit and transition to its compressed state, whereby said second split ring, is adapted to receive said ball after said ball is released by said first split ring; v) wherein the clearance through said ball seat formed by said second split ring in its compressed state is less than the clearance through said ball seat formed by said first split ring in its compressed state.

14. The tool of claim 13, wherein said second split ring is adapted to move down said conduit after receiving said ball and transition back to an expanded state in which it is sized to release said ball.

15. A stimulation valve for a well tubular, said stimulation valve comprising:

(a) a cylindrical housing adapted for assembly into a tubular for a well and defining a conduit for passage of fluids through said housing and one or more ports allowing fluid communication between said conduit and the exterior of said housing;

(b) a valve body adapted for movement from a closed position restricting fluid communication through said ports to an open position allowing fluid communication through said ports; and

(c) a ball seat assembly, said ball seat assembly comprising first and second ball seats mounted in said conduit, wherein: i) said first ball seat has a first state in which it is adapted to receive a ball deployed into said conduit and is adapted to transition to a second state in response to receiving said ball, in which second state it is adapted to release said ball; ii) said first ball seat is operatively engaged with said second ball seat such that as said first ball seat transitions to its second state it causes said second ball seat to transition from a first state having increased clearance to a second state having reduced clearance, in which second state said second seat is adapted to receive said ball for actuation of said valve body after said ball is released by said first seat; iii) said second ball seat is adapted to transition to a third state in response to receiving said ball, in which third state it is adapted to release said ball; iv) wherein said second ball seat is operatively engaged with said valve body such that as said second seat transitions to its third state it causes said valve body to move from its closed position to its open position; and v) wherein the clearance through said second ball seat in its second state is less than the clearance through said first ball seat in its first state.

16. The stimulation valve of claim 15, wherein said ball seat assembly is mounted in said conduit above said ports.

17. The stimulation valve of claim 15, wherein said valve comprises a third ball seat mounted below said ports, said third ball seat being adapted to receive a ball to restrict fluid flow through said conduit.

18. A tubular adapted for installation in a well comprising the tool of claim 1.

19. A tubular adapted for installation in a well comprising an uphole tool and a downhole tool, said tools comprising the tools of claim 1.

20. A method of lining a well, the method comprising installing a tubular comprising the tool of claim 1.

21. A method of stimulating a formation in a well having a tubular comprising an uphole stimulation valve and a downhole stimulation valve, said stimulation valves comprising the stimulation valves of claim 15, said method comprising:

(a) opening said uphole valve by pumping a ball through said uphole valve, said pumped ball causing said first ball seat in said uphole stimulation valve to transition to its second said state and said second ball seat in said uphole stimulation valve to transition to its third said state;

(b) opening said downhole valve by pumping said ball through said downhole valve, said pumped ball causing said first ball seat in said downhole stimulation valve to transition to its second said state and said second ball seat in said uphole stimulation valve to transition to its third said state; and

(c) pumping fluid through said tubular and out said opened valves to stimulate said formation adjacent to said valves.