Abstract:
A downhole bypass valve utilizes a stationary sleeve defining an interior ball-seat. When a dropped ball is seated, fluid differential pressure is diverted to an annular area adjacent a first sliding sleeve. The sleeve slides in response to the pressure differential upon shearing of a shear pin, or similar, and opens ports to the wellbore annulus. Treatment or maintenance operations can then occur through the ports, which can be fitted with nozzles. A second sliding sleeve, independent from the first, is operated in response to dropping a second ball into the device. The second ball diverts fluid differential pressure to an annular area adjacent the second sleeve and movement occurs when a shear pin shears. The second sleeve covers the ports to the wellbore annulus and closes the valve. After a sliding sleeve shifts, pressure across the sleeve is equalized, allowing reverse flow without risk of accidental sleeve actuation.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     None. 
     FIELD OF INVENTION 
     Methods and apparatus are presented for selective treatment of a wellbore or formation. More specifically, the inventions relate to methods and apparatus for selective fluid communication between a work string and wellbore utilizing a sliding-sleeve, bypass valve device. 
     BACKGROUND OF INVENTION 
     The present inventions relate, generally, to apparatus and methods used in well servicing and treatment operations. More specifically, these inventions relate to downhole apparatus used to selectively provide a flow passage from a tubular string into the wellbore annulus between the tubular string and the casing (or open hole) in which it is run. 
     As is common in the art, nozzles or ports can be utilized to inject fluid into the annulus surrounding a tubing string to clean various components in the wellbore. For example, cleaning of subsea surfaces and profiles of subsea wellheads, blowout preventers (BOPs) and the like, lifting fluid above liner tops and the like to increase annular flow, etc. In other applications, fluids are injected into the annulus to assist circulation. In a staged fracturing operation, multiple zones of a formation need to be isolated sequentially for treatment. Fracturing valves typically employ sliding sleeves, usually ball-actuated. The sleeves can be one-way valves or can be capable of shifting closed after opening. Initially, operators run the string in the wellbore with the sliding sleeves closed. A setting ball close the interior passageway of the string by seating on a ball seat. This seals off the tubing string so, for example, packers can be hydraulically set. At this point, fracturing surface equipment pumps fluid to open a pressure actuated sleeve so a first zone can be treated. As the operation continues, successively larger balls are dropped down the string to open separate zones for treatment. 
     Despite the general effectiveness of such assemblies, practical limitations restrict the number of balls that can be run in a single tubing string. Moreover, depending on the formation and the zones to be treated, operators may need a more versatile assembly that can suit their immediate needs. Further, staged sliding sleeves can tend to “skip” positions in response to raised tubing pressure, creating issues with opening a zone to treatment, etc. 
     SUMMARY OF THE INVENTION 
     The disclosed downhole bypass valve utilizes a stationary sleeve defining an interior ball-seat. When a dropped ball is seated, fluid differential pressure is diverted to an annular area adjacent a first sliding sleeve. The sleeve slides in response to the pressure differential upon shearing of a shear pin, or similar, and opens ports to the wellbore annulus. Treatment or maintenance operations can then occur through the ports, which can be fitted with nozzles. A second sliding sleeve, independent from the first, is operated in response to dropping a second ball into the device. The second ball diverts fluid differential pressure to an annular area adjacent the second sleeve and movement occurs when a shear pin shears. The second sleeve covers the ports to the wellbore annulus and closes the valve. After a sliding sleeve shifts, pressure across the sleeve is equalized, allowing reverse flow without risk of accidental sleeve actuation. Accidental shifting or “skipping” of sleeve positions is reduced as the sleeves are independently operated. 
     The tool is limited to one full cycle (close-open-close), however, different diameter inner sleeves and ball seats can be used to accept different ball sizes, allowing multiple tools to be stacked vertically for additional cycles. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more complete understanding of the features and advantages of the present invention, reference is now made to the detailed description of the invention along with the accompanying figures in which corresponding numerals in the different figures refer to corresponding parts and in which: 
         FIG. 1  is a schematic view of an exemplary embodiment of a work string having a plurality of valve assemblies thereon according to an aspect of the invention; 
         FIG. 2  is a cross-sectional schematic of an exemplary valve device according to an aspect of the invention with the valve in an initial closed, or run-in, position; 
         FIG. 3  is a cross-sectional schematic of the exemplary valve device of  FIG. 2 , with the valve in an actuated open position; 
         FIG. 4  is a cross-sectional schematic of the exemplary valve device of  FIG. 2 , with the valve in a final closed position. 
     
    
    
     It should be understood by those skilled in the art that the use of directional terms such as above, below, upper, lower, upward, downward and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure. Where this is not the case and a term is being used to indicate a required orientation, the Specification will state or make such clear. 
     DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS 
     While the making and using of various embodiments of the present invention are discussed in detail below, a practitioner of the art will appreciate that the present invention provides applicable inventive concepts which can be embodied in a variety of specific contexts. The specific embodiments discussed herein are illustrative of specific ways to make and use the invention and do not limit the scope of the present invention. The description is provided with reference to a horizontal wellbore. However, the inventions disclosed herein can be used in horizontal, vertical, or deviated wellbores. As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. The terms “uphole,” “downhole,” and the like, refer to movement or direction closer and farther, respectively, from the wellhead, irrespective of whether used in reference to a vertical, horizontal or deviated borehole. The terms “upstream” and “downstream” refer to the relative position or direction in relation to fluid flow, again irrespective of the borehole orientation. Those of skill in the art will recognize where the inventions disclosed herein can be used in conjunction with jointed tubing string, coiled tubing, or wireline. The inventions herein can also be used with on-shore rigs, off-shore rigs, subsea and deep-sea rigs, etc. 
       FIG. 1  is a schematic view of a typical tubing string positioned in a subterranean wellbore. As used herein, “tubing string,” “work string,” and the like are used interchangeably and are to be construed as inclusive of various types of string or strings for various operations, such as work strings, work-overs, servicing, production, injection, stimulation, etc. The tool can also be used as a jetting and bypass tool in various operations, including BOP jetting, bore cleaning, fluid displacements, drilling and displacement boosting, as a drain sub, etc. The apparatus is useful for stimulation of a formation, using stimulation fluids, such as for example, acid, gelled acid, gelled water, gelled oil, nitrogen, or proppant laden fluids. The apparatus may also be useful to open the tubing string to production fluids. Further, the device can be used in injection, fracturing, staged fracturing, and other treatment operations. 
       FIG. 1  shows a well system  10  having a wellbore  12  extending through one or more subterranean formations or zones  11 . A work string  14  is positioned in the wellbore and has a plurality of sliding sleeve-operated valve devices  16 . Other string configurations, varying numbers and spacing of devices, etc., can be used, as will be apparent to those of skill in the art. In the assembly illustrated, the sleeves are used to control fluid flow through the string and into selected zones  11  through the wellbore  12 . Tubing string  14  includes a plurality of spaced-apart, selectively operable, sliding sleeve valve devices  16  each having a plurality of ports  17  extending through the tubing wall to selectively permit fluid flow between the tubing string inner bore and the annulus between the work string and wellbore  12 . Any number of devices  16  can be used in each interval, grouped adjacent one or more target zones, etc. A plurality of annular sealing devices  20  is mounted on the string between sliding sleeve devices  16 . Exemplary annular sealing devices include mechanically, hydraulically, electromechanically, chemically, or temperature-activated packers, plugs, etc., as are known in the art. The annular sealing devices can be used to isolate formation zones, or sections of wellbore, for interval treatment, etc. The packers are disposed about the tubing string and selected to seal the annulus between the tubing string and the wellbore wall, when the assembly is disposed in the wellbore. The packers divide the wellbore into isolated sections so that fluid can be applied to selected sections of the well, but prevented from passing through the annulus into adjacent segments. As will be appreciated, the packers can be spaced in any way relative to the ported intervals to achieve a desired interval length or number of ported intervals per segment. 
     Sliding sleeve devices  16  are disposed along the tubing string to selectively control the opening and closing of the ports. A sliding sleeve is mounted to control flow through each ported valve. In a preferred embodiment, the valve devices are closed during run-in and can be opened, and later closed, to allow and stop fluid flow into the wellbore. The assembly is run-in and positioned downhole with the sliding sleeve devices in closed positions. The sleeves are selectively moved to an open position when the tubing string is ready for use in fluid treatment of the wellbore. The sliding sleeve valve devices  16  for each isolated section can be opened individually and sequentially to permit fluid flow to the wellbore. 
     The sliding sleeve valve devices are each moveable between closed and open positions by selective application of tubing pressure and without having to run a line for manipulation. The valve devices are actuated by a dropped ball (not shown). The term “ball” as used herein includes alternates such as darts, bars, or other plugging device, which can be conveyed by gravity or fluid flow through the tubing string. The dropped ball engages a seat positioned in the valve device and plugs fluid flow through the interior bore of the string. When pressure is applied through the tubing string bore, the ball creates a pressure differential across the valve. This pressure differential is used to operate the valve, sliding a sleeve in the valve and opening the associated ports. Fluid flows into the wellbore annulus and into contact with the formation. 
     Multiple sliding sleeve valve devices  16  can be used by dropping sequentially larger diameter balls which mate with sequentially larger ball seats. In particular, the lower-most device has the smallest diameter seat and each device progressively closer to surface has a larger diameter seat. The preferred embodiment disclosed herein also provides for the selective closing of the sliding sleeve valve device by dropping of a subsequent ball. 
     At the surface is an appropriate rig,  15  derrick or the like, and various other surface equipment  19 , such as pumping equipment, etc., as in known in the art for well servicing and treatment operations. 
     The lower end  28  of the tubing string  14  can be open, closed, or fitted in various ways, depending on the operational characteristics of the tubing string that are desired. Further components and tools can be used in conjunction with the tubing string, such as additional sealing devices, connection joints, measuring and sensing equipment, downhole pumps, valves, tool actuators, communication lines, transmission devices, etc., as those of skill in the art will recognize. 
       FIG. 2  is a cross-sectional schematic of an exemplary valve device according to an aspect of the invention with the valve in an initial closed, or run-in, position.  FIG. 3  is a cross-sectional schematic of the exemplary valve device of  FIG. 2 , with the valve in an actuated open position.  FIG. 4  is a cross-sectional schematic of the exemplary valve device of  FIG. 2 , with the valve in a final closed position. The figures will be discussed together with specific references to particular figures as necessary. The exemplary embodiment shown here is of particular use in jetting and bypass operations, such as BOP jetting, bore cleaning, etc. Variations known in the art to practitioners can be employed for use of the device for fluid displacements, drilling and displacement boosting, as a drain sub, stimulation, fracturing, production, etc. 
     The tool embodiment shown is a downhole, ball-actuated, jetting or bypass valve. The valve is ball-actuated and provides for one complete cycle (closed-open-closed). The tool preferably has four sleeves positioned in a tool body or housing: two sliding or shifting sleeves, one for opening the valve and one for closing the valve, a stationary ball-seat sleeve, and a retaining sleeve. When a dropped or pumped ball lands on the seat in the seat sleeve, a pressure differential is created on an upwardly-facing annular area of the first sliding sleeve. When the differential is high enough, a shear pin is sheared and the first sliding sleeve shifts, uncovering ports and opening the tool to fluid flow into the wellbore annulus. Similarly, dropping a second ball acts on the second sliding sleeve, shifting the second sleeve to a closed position and shutting off flow to the wellbore annulus. 
     Both opening and closing sleeves are fully independent, eliminating any concerns of double-shifting or “skipping” the open position. Following activation and deactivation, both shifting sleeves are pressure equalized, meaning full reverse circulation can occur without concerns of reverting back to a previous position. Internal sleeves can be assembled outside of the main body for ease of assembly. Flow area after activation is preferably equal to or greater than before activation. The open-bore design allows wireline tools to be run in conjunction with, and through, the device prior to activation. 
     An exemplary sliding sleeve device  30  is attached to, and forms part of, a work string. The work string has a fluid flow passageway  32 , typically a central bore, for passing fluid between downhole locations and the surface. The fluid flow passageway includes a fluid passageway  34  defined in the device  30 . Fluid can be flowed through the device to locations downhole or uphole when the device is in its run-in or initial position, as seen in  FIG. 2 . 
     The device  30  has a generally tubular housing  36  which is attachable to a work string by methods known in the art. A plurality of radial ports  38  extend through the housing, providing fluid communication between the wellbore annulus and the interior of the device. The ports  38  are shown extending radially at a right angle to the longitudinal axis of the device, although alternate orientations can be used. The ports  38  can be altered or designed for the specific use of the device. For example, as shown, the ports  38  are fitted with jetting nozzles  40 , which can be selected based on expected use and which are preferably exchangeable for different nozzles  40  of varying size, for more or less flow splitting, for jetting velocity and spray pattern, etc. In a preferred embodiment, the nozzles  40  are inserted through aligned holes or ports  38  and  54  in the housing  36  and retaining sleeve  42 , serving to orient the internal parts of the device and to lock the housing and retaining sleeve axially and radially. 
     The exemplary valve device  30  has a retaining sleeve  42  and a stationary internal sleeve or ball-seat sleeve  44 . Defined between, and preferably by the surfaces of, the retaining sleeve  42  and ball-seat sleeve  44  is an annular space  46  for two sliding sleeves, a first or lower sliding sleeve  48  and a second or upper sliding sleeve  50 . The retaining sleeve  42  is positioned in the housing and remains stationary in use. The retaining sleeve can be attached to the housing by means known in the art. Similarly, the interior ball-seat sleeve  44  remains stationary in use and can be attached to the housing, the retaining sleeve, or both, by means known in the art. In the embodiment shown, the lower end of the ball-seat sleeve abuts a shoulder  52  defined by the housing. The retaining sleeve has radial ports  54  which align with ports  38  of the housing to allow fluid communication radially across the retaining sleeve. Where nozzles  40  are employed, they can extend into and attach to the ports  54 , align the ports  54  and  38 , and position and/or lock the retaining sleeve radially and axially to the housing. 
     The inner sleeve  44  has a generally open interior passageway  34  and defines several radial ports extending through the sleeve wall and providing fluid communication between the passageway and the exterior of the sleeve. As best seen in  FIG. 2 , the various ports include upper pressure ports  56 , lower pressure ports  58 , flow ports  60 , and pressure equalization ports  62 . The upper pressure ports  56  provide fluid communication between the interior passageway  34  and the upper annular chamber  64 . Lower pressure ports  58  provide fluid communication between the interior passageway and the central annular chamber  66 . Flow ports  60  provide fluid communication between the interior passageway and the lower annular chamber  68 . Finally, the pressure equalization ports  62  provide fluid communication between the interior passageway and the lower annular chamber  68 . 
     The inner sleeve  44  has, or defines, a ball seat  70  operable to catch an appropriately sized ball. That is, the ball seat has a diameter slightly smaller than the cooperating ball diameter. The inner sleeve can also have a second ball seat defined therein (not shown) for catching a second ball of slightly larger size. In the preferred embodiment, a second ball seat is unnecessary as the first dropped ball  72  acts to “catch” or stop the second dropped ball  74 . 
     The lower sliding sleeve  48  moves between an initial or closed position, as seen in  FIG. 2 , and an actuated or open position, as seen in  FIG. 3 . The lower sliding sleeve is initially held in place by one or more selective release mechanisms, such as a shear ring, shear pin, snap-ring, etc. In a preferred embodiment, the sleeve is held in place by shear pin  76 . 
     The upper sliding sleeve  50  moves between an initial or first position, as seen in  FIG. 3 , and an actuated or closed position, as seen in  FIG. 4 . The lower sliding sleeve is initially held in place by one or more selective release mechanisms, such as a shear ring, shear pin, snap-ring, etc. In a preferred embodiment, the sleeve is held in place by shear pin  78 . 
     When the lower sleeve is in the closed position, fluid flow through the ports  38  is blocked. When the lower sliding sleeve is moved to the open position (and the upper sleeve remains in its initial position), as in  FIG. 3 , fluid is free to flow from interior passageway  34 , through lower pressure ports  58 , through annular chamber  66 , and exit the device and work string into the wellbore annulus through ports  38  and, if present, nozzles  40 . When the upper sleeve is moved to its closed position,  FIG. 4 , fluid is once again blocked from flowing from the interior passageway to the wellbore annulus. 
     In use, the valve device is attached to a work (or other) string and run-in to the wellbore hole. Typically, the device is run-in in a closed position, such that fluid is blocked from flowing from the interior passageway to the exterior of the device. Once positioned where desired and, if necessary, after other operations have occurred, such as setting isolation devices, etc., the device is ready for use. Fluid flows through the interior passageway  34  which makes up a part of a longer interior passageway  32  of the string. Fluid can be flowed downhole or uphole through the passageway  34  without actuating either sliding sleeve at this point. Further, the interior passageway  34  is sufficiently free of obstructions to allow use of wireline conveyed tools. 
     When it is desired to open the valve device, a ball (or other similar object) is dropped or flowed into the interior passageway. The ball seats on a cooperating ball seat  70  defined in the interior passageway  34  of the device, preferably on the interior surface of the inner or ball-seat sleeve. The seated ball  72  remains stationary, as does the inner sleeve  44 , and blocks or restricts fluid flow through the passageway  34  and creates a pressure differential across the ball. The differential pressure is diverted by the blockage of the passageway, through the pressure ports  58  in the inner sleeve  44 , to annular chamber  66 , where the pressure acts with downward force on an upper surface of the lower sliding sleeve  48 . The sliding sleeve  48 , slidingly positioned between the inner sleeve  44  and the retaining sleeve  42 , is forced downward, shearing the shear pin  76 . Upon shearing of the pin  76 , the lower sliding sleeve  48  moves from its initial position, wherein the sleeve blocks fluid flow through ports  38  to the wellbore annulus exterior to the device, to an open position, wherein such flow is allowed. Fluid can now flow from the interior passageway  35  above the first ball  72 , through lower pressure ports  58 , along annular chamber  66 , and through the external ports  38 . Fluid is flowed or jetted out of the device through ports  38  and nozzles  40  (if present). Flow can also be allowed from the annular chamber  66  through the flow ports  60  and back into the interior passageway  34  below the first ball  72 . Additionally, in a preferred embodiment, flow is allowed between the inner passageway  34  and an annular chamber  68  defined below the lower sliding sleeve  48 , through pressure equalization ports  62 , such that pressure is equalized across the lower sliding sleeve. 
     Various wellbore operations can then be performed. For example, nozzles  40 , positioned in or adjacent ports  38 , can be used for BOP jetting, bore cleaning, and the like. The open ports can be used for fluid displacements, drilling and displacement boosting, as a drain sub, for stimulation, injection, fracturing, production, etc., operations. 
     When it is desired to close the device, a second ball  74  is dropped into the passageway and seats itself on, or is stopped by contact with, the first ball  72 . The second ball  74  blocks fluid flow from the interior passageway  34  through the lower pressure ports  58 . As a differential pressure is built across the second ball, the pressure is diverted through the upper pressure ports  56  to annular chamber  64 . The seated and stationary ball  72  blocks fluid flow across the device, creating a pressure differential across the device. The differential pressure is diverted through the upper pressure ports  56  in the inner sleeve  44 , to annular chamber  64 , where the pressure acts with downward force on an upwardly facing surface  80  of the upper sliding sleeve  50 . The sliding sleeve  50 , slidingly positioned between the inner sleeve  44  and the retaining sleeve  42 , is forced downward, shearing the shear pin  78 . Upon shearing of the pin  78 , the upper sliding sleeve  50  moves from its initial position, wherein the sleeve does not block fluid flow through ports  38  to the wellbore annulus exterior to the device, to a closed position, wherein such flow is blocked. Fluid can now flow from the interior passageway  34  above the second ball  74 , through upper pressure ports  56 , along annular chamber  64 , and through the flow ports  60  back into the interior passageway  34  below the first ball  72 . Additionally, in a preferred embodiment, fluid is allowed between the inner passageway  34  and annular chamber  66  (now defined between adjacent upper and lower sliding sleeves), such as through flow ports  60 , such that pressure is equalized across the upper sliding sleeve. 
     Note that in a preferred embodiment, the flow area (which governs flow rate) available after the lower sliding sleeve shift is the same or even greater than the flow area available in the initial or run-in position. The counter-bored portion of the housing  36  and the movement of the sleeve to its open position, opens up an annular flow area between the inner sleeve  44  and retaining sleeve  42 . Similarly, after the second ball  74  is dropped and the upper sliding sleeve  50  is shifted, closing (blocking) the ports  38 , an annular flow area is opened which is, preferably, as large as or larger than the initial flow area through the passageway  34 . The annular flow area is defined between the inner sleeve  44  and the interior surface of the upper sliding sleeve  50 . (Alternately, the annular area can be defined in part by the retaining sleeve.) The upper sliding sleeve  50  can have a radially enlarged annular area defined on its upper inner surface for this purpose. These relatively large annular flow areas allow for a greater flow rate through the device than is typical in such bypass valves of similar diameter. 
     The valve device is limited to a single closed-open-closed cycle. However, multiple devices can be stacked along the work string, with successive uphole devices having successively larger diameter ball seats for use with cooperating dropped balls. In this manner, multiple cycles along a single isolated section is possible, or multiple isolated zones can be treated sequentially. 
     Upon closure of the valve device, fluid can be flowed and reverse flowed through the device passageway. The upper and lower sliding sleeves will not shift positions as they are pressure balanced. For example, fluid can be produced from the formation into the tubing string, the wellbore can be drained or flushed of fluids, etc. It is also possible to provide for locking of the sliding sleeves in their activated positions, such as by cooperating profiles, snap rings, etc. 
     Also note that the device is designed such that a valve assembly, comprising the retaining sleeve, two sliding sleeves and inner sleeve, can be assembled into a unit, and then inserted into (or removed from) a counter-bored housing. This eases assembly, disassembly, allows for interchangeable units of varying diameter seats, etc. 
     For further disclosure regarding bypass valves and the like, see the following references, all of which are incorporated herein by reference in their entirety for all purposes: U.S. Pat. No. 8,215,411 to Flores, et al.; U.S. Pat. No. 7,201,232 to Turner, et al.; U.S. Pat. Nos. 7,150,326; 6,877,566; 6,467,546 to Allamon, et al.; U.S. Pat. Nos. 6,253,861; and 6,065,541; and U.S. Pat. App. Pub. No. 2011/0278017 to Themig, et al. Also see, for example, commercial bypass valve tools, such as the Jet Tech (trade name) tool available commercially from Halliburton Energy Services, Inc., and Bico Drilling Tools, Inc., Multiple Activation Bypass Tool (see, on-line literature at bicodrilling.com, Multiple Activation Bypass Tool, etc.) also available commercially. 
     In the preferred and exemplary methods presented hereinabove, various method steps are disclosed, where the steps listed are not exclusive, can sometimes be skipped, or performed simultaneously, sequentially, or in varying or alternate orders with other steps (i.e., steps XYZ can be performed as XZY, YXZ, YZX, ZXY, etc.) (unless otherwise indicated), and wherein the order and performance of the steps is disclosed additionally by the claims appended hereto, which are incorporated by reference in their entirety into this specification for all purposes (including support of the claims) and/or which form a part of this specification, the method steps presented in the following text. Exemplary methods of use of the invention are described, with the understanding that the invention is determined and limited only by the claims. Those of skill in the art will recognize additional steps, different order of steps, and that not all steps need be performed to practice the inventive methods described. 
     While this invention has been described with reference to illustrative embodiments, this description is not intended to be construed in a limiting sense. Various modifications and combinations of the illustrative embodiments as well as other embodiments of the invention, will be apparent to person skilled in the art upon reference to the description. It is, therefore, intended that the appended claims encompass any such modifications or embodiments.