Abstract:
Disclosed herein is a seat assembly for use in wellbore servicing systems, comprising a cylindrical baffle with an annular shaped seat with an upward facing seat for receiving an obturator, the seat defining a central passageway. Erosion resistance rings are placed inside of and in front the baffle to protect the baffle and seat from erosion cause by treatment fluids and solids passing through the servicing system.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    Continuation-in-part of U.S. application Ser. No. 13/440,727 filed on Apr. 5, 2012 which is a Continuation-in-part of U.S. application Ser. No. 13/219,790 filed on Aug. 29, 2011. 
     
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
       [0002]    Not applicable. 
       REFERENCE TO A MICROFICHE APPENDIX 
       [0003]    Not applicable. 
       BACKGROUND 
       [0004]    It is common to utilize downhole wellbore equipment with baffles containing seats for use in operating of the equipment. For example, well formations that contain hydrocarbons are sometimes non-homogeneous in their composition along the length of wellbores that extend into such formations. It is sometimes desirable to treat and/or otherwise manage the formation and/or the wellbore differently in response to the differing formation composition. Some wellbore servicing systems and methods allow such treatment, referred to by some as zonal isolation treatments. In these systems, zones can be treated separately. 
         [0005]    In some treatment methods a plurality of spaced tools are installed in a well and selectively operated. For example, in some well treatment systems a plurality of sleeve valves are installed in the well and opened in sequence starting with the bottom most valve. Once treatment through the bottom most valve is completed, the next higher up valve is opened and treatment performed through that valve. 
         [0006]    In obturator actuated systems, an obturator is transported down the wellbore to engage a downhole well tool. The terms, “up”, “upward”, “down” and “downward”, when used to refer to the direction in the well bore without regard to the orientation of the well bore. Up, upward and up hole refer to the direction toward the well head. Down, downward, and down hole refer to a direction away from the well head. In these systems, each downhole well tool typically includes a metallic baffle containing seat to seal against the obturator and activate the tool. 
         [0007]    It is common to perform fracturing formation treatments using multiple sleeve valves spaced along the well. Fracturing necessarily involves pumping large quantities of abrasive materials called proppants at high pressures and high flow rates into the well and through the baffles in these valves. As a frac treatment material flow through the valves their baffles are subject to erosion damage. The potential damage can be more severe when the upper valves in a wellbore are subjected to erosion effects of multiple frac operations accounted with the lower valves. 
         [0008]    Accordingly, there exists a need for erosion resistant for use in systems and methods for treating multiple zones of a wellbore. 
       SUMMARY 
       [0009]    Disclosed herein are wellbore tool baffles for use in abrasive wellbore servicing systems and methods. In the disclosed example the baffle is armored against erosion damage from materials flowing through the tool. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0010]    For a more complete understanding of the present disclosure and the advantages thereof, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description: 
           [0011]      FIG. 1  is a cut-away view of an embodiment of a wellbore servicing system according to the disclosure containing multiple well tools; 
           [0012]      FIG. 2  is a cross-sectional view of a sleeve valve containing an embodiment of the baffle of the present invention for use in the wellbore servicing system of  FIG. 1  showing the sleeve valve in the run-in configuration; 
           [0013]      FIG. 3  is a cross-sectional view of a sleeve valve containing an embodiment of the baffle of the present invention for use in the wellbore servicing system of  FIG. 1  showing the sleeve valve in the actuated baffle configuration; 
           [0014]      FIG. 4  is a cross-sectional view of a sleeve valve containing an embodiment of the baffle of the present invention for use in the wellbore servicing system of  FIG. 1  showing the sleeve valve with the ball landed on the baffle seat configuration; 
           [0015]      FIG. 5  is a cross-sectional view of a sleeve valve containing an embodiment of the baffle of the present invention for use in the wellbore servicing system of  FIG. 1  showing the sleeve valve in the open configuration; 
           [0016]      FIG. 6  is a cross-sectional view of a sleeve valve containing an embodiment of the baffle of the present invention for use in the wellbore servicing system of  FIG. 1  showing the sleeve valve in the open flowback configuration; 
           [0017]      FIG. 7  is an enlarged cross-sectional view of the sleeve valve of  FIG. 2  illustrating details of the electro-hydraulic sleeve lock; 
           [0018]      FIG. 8  is an enlarged section view of the electro-hydraulic actuator of the sleeve system of  FIG. 7 ; 
           [0019]      FIG. 9  is a perspective view of an embodiment of the baffle in the sleeve valve of  FIG. 2 ; and 
           [0020]      FIG. 10  is a top plan view of third alternative embodiment of the seat assembly of the sleeve system of  FIG. 2 ; 
       
    
    
     DETAILED DESCRIPTION OF THE EMBODIMENTS 
       [0021]    In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. 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 elements may not be shown in the interest of clarity and conciseness. 
         [0022]    Unless otherwise specified, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ” Reference to up or down will be made for purposes of description with “up,” “upper,” “upward,” or “upstream” meaning toward the surface of the wellbore and with “down,” “lower,” “downward,” or “downstream” meaning toward the terminal end of the well, regardless of the wellbore orientation. The term “zone” or “pay zone” as used herein refers to separate parts of the wellbore designated for treatment or production and may refer to an entire hydrocarbon formation or separate portions of a single formation such as horizontally and/or vertically spaced portions of the same formation. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art with the aid of this disclosure upon reading the following detailed description of the embodiments and by referring to the accompanying drawings. 
         [0023]    Disclosed herein are improved components, more specifically, an improved baffle assembly with erosion resistance characteristics, for use in downhole tools. Such a baffle may be employed alone or in combination with other components. 
         [0024]    Referring to  FIG. 1 , an embodiment of a wellbore servicing system  100  is shown in an example of an operating environment. As depicted, the operating environment comprises a rig  106  (e.g., a drilling, completion, or workover rig) positioned on the earth&#39;s surface  104  over a wellbore  114  that penetrates a subterranean formation  102  for the purpose of recovering hydrocarbons. The wellbore  114  may be drilled into the subterranean formation  102  using any suitable drilling technique. The wellbore  114  extends substantially vertically away from the earth&#39;s surface  104  over a vertical wellbore portion  116 , deviates from vertical relative to the earth&#39;s surface  104  over a deviated wellbore portion  136 , and transitions to a horizontal wellbore portion  118 . In alternative operating environments, all or portions of a wellbore may be vertical, deviated at any suitable angle, horizontal, and/or curved. 
         [0025]    At least a portion of the vertical wellbore portion  116  is lined with a casing  120  that is secured into position against the subterranean formation  102  in a conventional manner using cement  122 . In alternative operating environments, a horizontal wellbore portion may be cased and cemented and/or portions of the wellbore may be uncased. The rig  106  comprises a derrick  108  with a rig floor  110  through which a tubing or work string  112  (e.g., cable, wireline, E-line, Z-line, jointed pipe, coiled tubing, casing, or liner string, etc.) extends downward from the servicing rig  106  into the wellbore  114  and defines an annulus  128  between the work string  112  and the wellbore  114 . The work string  112  delivers the wellbore servicing system  100  to a selected depth within the wellbore  114  to perform an operation such as perforating the casing  120  and/or subterranean formation  102 , creating perforation tunnels and/or fractures (e.g., dominant fractures, micro-fractures, etc.) within the subterranean formation  102 , producing hydrocarbons from the subterranean formation  102 , and/or other completion operations. The servicing rig  106  comprises a motor driven winch and other associated equipment for extending the work string  112  into the wellbore  114  to position the wellbore servicing system  100  at the selected depth. 
         [0026]    While the operating environment depicted in  FIG. 1  refers to a stationary servicing rig  106  for lowering and setting the wellbore servicing system  100  within a land-based wellbore  114 , in alternative embodiments, mobile workover rigs, wellbore servicing units (such as coiled tubing units), and the like may be used to lower a wellbore servicing system into a wellbore. It should be understood that a wellbore servicing system may alternatively be used in other operational environments, such as within an offshore wellbore operational environment. 
         [0027]    The subterranean formation  102  comprises a zone  150  associated with deviated wellbore portion  136 . The subterranean formation  102  further comprises first, second, third, fourth, and fifth horizontal zones,  150   a,    150   b,    150   c,    150   d,    150   e,  respectively, associated with the horizontal wellbore portion  118 . In this embodiment, the zones  150 ,  150   a,    150   b,    150   c,    150   d ,  150   e  are offset from each other along the length of the wellbore  114  in the following order of increasingly downhole location:  150 ,  150   e,    150   d,    150   c,    150   b,  and  150   a.  In this embodiment, stimulation and production sleeve systems  200 , comprising sleeve valves  200   a,    200   b,    200   c ,  200   d,    200   e,  and  200   f  are located within wellbore  114  in the work string  112  and are associated with zones  150 ,  150   a,    150   b,    150   c,    150   d,  and  150   e,  respectively. It will be appreciated that zone isolation devices such as annular isolation devices (e.g., annular packers and/or swellpackers) may be selectively disposed within wellbore  114  in a manner that restricts fluid communication between spaces immediately uphole and downhole of each annular isolation device. 
         [0028]    The stimulation and production sleeve systems  200  illustrated in  FIG. 1  each sleeve valve comprises one or more sleeves which can be moved to selectively open ports spaced along the wall of the work string  112  to provide a fluid paths between the interior of the work string and the surrounding formation. In the stimulation and production sleeve systems  200  illustrated in  FIG. 1  the sleeve valves  200   a - 200   f  can be opened in sequence starting with opening the ports associated bottom most sleeve valve  200   a.  Sleeve valve  200   a  is opened by inserting an obturator into the well to contact a seat on a baffle in the valve. With the valve  200   a  open horizontal zone  150   a  can be treated by pumping fluids into the zone through the ports opened by valve  200   a.  Once valve  200   a  is opened and treatment through this bottom most valve  200   a  is completed, the next higher up valve  200   b  is opened and treatment performed through that valve. Next the valve  200   b  is opened to treat zone  150   b.  The valves  200   b - 200   f  each also comprises a baffle with seat which with the obturator block or seals off the interior of the work string  112  below the valve. This sequence can be repeated for each of the sleeve valves  200   c - 200   f  until the uppermost sleeve valve  200   f  is actuated and used to treat zone  150   f.    
         [0029]    Referring now to  FIG. 2 , a cross-sectional view of an embodiment of sleeve valve  200   a  of the stimulation and production sleeve system  200  (hereinafter referred to as “sleeve system”  200 ) is shown. Valve  200   a  is typical of the construction of the valves  200   b - 200   f.  Many of the components of sleeve valve  200   a  lie substantially coaxial with a central axis  202  of sleeve valve  200   a.    
         [0030]    Sleeve valve  200   a  comprises an upper adapter  204 , a lower adapter  206 , and a ported case assembly  208 . The ported case assembly  208  is joined between the upper adapter  204  and the lower adapter  206 . Together, inner surfaces of the upper adapter  204 , the lower adapter  206 , and the ported case assembly  208 , respectively, substantially define a sleeve flow bore  216 . The upper adapter  204  comprises a collar configured for attachment to an element of work string  112 . The lower adapter  206  is configured for attachment to an element of work string  112 . The upper and lower adapters comprise threads for connecting to the ported case assembly  208  and work string  112 . 
         [0031]    The ported case assembly  208  is substantially tubular in shape and comprises an upper sleeve portion  230  and a lower baffle portion  240 . The sleeve portion  230 , baffle portion  240 , upper adapter  204  and lower adapter  206  each have substantially the same inner and outer diameters. The upper sleeve portion  230  further comprises ports  232 . As will be explained in further detail below, ports  232  are through holes extending radially through the upper sleeve portion  230  and are selectively used to provide fluid communication between sleeve flow bore  216  and the annulus  128  immediately exterior to the upper sleeve portion  230 . 
         [0032]    The upper sleeve portion  230  comprises a sleeve  234  mounted to slide axially within the sleeve portion  232  selectively block and open ports  232 . As is illustrated  FIG. 2  and in detail in  FIGS. 7 and 8 , sleeve  234  is hydraulically locked in the upper or run in position illustrated in  FIG. 2 . In  FIGS. 2, 7 and 8 , the upper or uphole direction is to the left sides of each figure. Sleeve  234  is held in this position by filling annular chamber  236  with a hydraulic fluid. Chamber  236  extends from sleeve portion  230  and into baffle portion  240 . Chamber  236  can be filled with hydraulic fluid using removable plug  242 . A rupture disk  244  closes off the lower end of chamber  236 . When rupture disk  244  is pierced or broken, hydraulic fluid in chamber  236  is vented, the position of sleeve  234  is unlocked, allowing sleeve  234  to axially slide in the downhole direction (to the right side of the page). 
         [0033]    The structure for piercing the rupture disk  244  is best illustrated in reference to  FIGS. 7 and 8  and various embodiments are disclosed in U.S. Pat. No. 8,322,426 and U.S. Publications 2013/0048290 and 2013/0048291, which are incorporated herein by reference for all purposes. The piercing structure comprises a cutter  246 , actuator  248  and electronic package  250 . In the illustrated embodiment the actuator  248  comprises an explosive charge which when ignited by the electronic package  250  drives the cutter  246  in the uphold direction to pierce rupture disk  244 . Electronic package  250  comprises means for sensing and recording the passage along the sleeve bore  216  of obturators passing through the sleeve valve  200   a.  When a set number of obturators pass through the valve  200   a,  electronic package  258  initiates the actuator  248 . Porting  252  provides a path for the hydraulic fluid to vent from chamber  236  into flow bore  216 . 
         [0034]    The baffle portion  240  ( 240  also encloses the electronics, batteries, thruster, and rupture disc) comprises an annular baffle assembly  260  mounted in the bore of the baffle portion  242  to slide axially in the flow bore  216 . The details of construction of the baffle assembly will be described in more detail by reference to  FIGS. 8 and 9 . The baffle assembly  260  comprises a sleeve  262  and a C-ring baffle  264  having an uphole facing seat  266 . Sleeve  262  is held in axial position in the baffle  240  illustrated in  FIG. 7  by a releasable mechanism such as a shear pin or snap ring (not shown). As will be described, baffle  264  is illustrated in its expanded condition where in its internal diameter is substantially the same as sleeve  262  and the gap  263  is present in the C-ring structure. In the position illustrated in  FIG. 10  the seal ring comprising baffle  264  is spring-loaded are resiliently urged radially outward to engage sleeve  262 . Baffle  264  has tabs  267  which lock into a groove in sleeve  266 ; this axially holds the baffle  264  in position. (they are locked together axially only in the state where the baffle is expanded). As will be described in more detail, when baffle  264  and sleeve  266  are forced together (by axial forces Fs and Fb) baffle  264  will climb up (should this read down?) the ramp services and tabs  267  to a point where the gap  263  in the C-ring structure of baffle  264  is closed and the internal diameter of the baffle  264  is less than the internal diameter of the sleeve  262 . When the baffle  264  is in the expanded position illustrated in  FIG. 10 , an obturator with an external diameter less than that of the sleeve  266  will pass through the baffles  264  without engaging it. It should be appreciated that when the baffle  264  contracts, that it can be of a sufficiently small internal diameter to engage an obturator. 
         [0035]    To protect the baffle  264  and the seat  266  against erosion from flowing treatment materials, a baffle erosion buffer or shield is provided. This shield allows the system to be used to treat a greater number of treatment zones (treatment stages). In the illustrated embodiment, the shield comprises a nose cone ring  268  and a seat abutting ring  270 . The nose cone ring  268  as substantially the same into your an exterior diameters as the sleeve  262  and baffle  264  when arranged as illustrated in  FIGS. 2, 7 and 10 . The annular surface of the ring  268  facing in the upward direction is tapered or rounded or angled to reduce flow turbulence. Turbulent flow has a more erosive impact on the components; an angled or rounded face reduces flow turbulence. Ring  268  can be formed from an erosion resistant material such as carbide, hard steel or the like. 
         [0036]    The seat abutting ring  270  is located downhole of the nose cone ring  268  and inside of the baffle  264 . Ring  268  has a section  272  that covers the gap  263  to provide a continuous cylindrical surface on the interior of the baffle assembly  260  to reduce turbulence and the erosion of fact a flow there through. In this embodiment the seat abutting ring  270  is made from a frangible material, such as, ceramic, cast-iron, phenolic are similar brittle erosion (abrading affect or particle impact affect which erode/corrode the material) resistant materials. 
         [0037]    The operation sleeve system  200  will be described by reference to  FIGS. 2-8 . The system  200  is of the type which is used in conjunction with an obturator  280  comprising magnetic material. In the present embodiment, the obturator  280  is a spherical ball formed from the nonmagnetic material with a number of cylindrical magnets installed in the outer diameter of the obturator  282  created a magnetic field around the outer diameter. 
         [0038]    Prior to running the sleeve system  200  into the well, the electronic package of each of the stimulation and production sleeve valves  200   a - 200   f  is programmed to count a certain number of obturators  280  passing through the valve. The run-in condition of valve  200   a  is illustrated in  FIG. 2  with the baffle  264  in the expanded our pass through condition. The run-in and operation of valve  200   a  is typical of the run in operation of valves  200   b - 200   f.    
         [0039]    In  FIG. 3 , the baffle  264  has been activated by the electronic package  250  sensing the passage of a set number of obturators  280  through the sleeve valve  200   a.  If for example, electronic package  250  of valve  200   a  has been programed to release the hydraulic lock on sleeve  234  after the passage of a single obturator  280 , then sleeve  234  moves in a downhole direction to contact the baffle assembly  260 . This movement of sleeve  234  causes the baffle  264  to ride down the ramp services and tabs  267  and contract to assume the obturator catching position illustrated in  FIG. 3 . As the baffle  264  contracts the frangible seat abutting ring  270  breaks apart and fall down the wellbore. It is to be noted that at this point, that even though the sleeve  234  has moved downward the ports  230  remain blocked. 
         [0040]    The next step in the operation of valve  200   a  is illustrated in  FIG. 4 . In this step, the next obturator  280  moving down the wellbore engages baffle  264  and seals against the seat  266 . With the obturator  280  in this position, the lower portion of the work string  212  below valve  200   a  is sealed off. In this step, sleeve  262  is held in axial position by the shear pins, are the light (not shown). 
         [0041]    With the obturator  280  landed on the baffle  264 , pressure in the work string  212  is raised to the point where the force on the sleeve  262  causes the shear pins to release. With the pins shared sleeve  262  and sleeve  234  move in a downhole direction to the position illustrated in  FIG. 5 . In this position sleeve  234  has moved away from ports  230  opening up a flow pathway between a flow bore  216  and annulus  128 . In this position treatment? fluid can be pumped down the work string  112  to treat the horizontal zone  150   a.  The obturator  280  and baffle seat  266  block are prevent flow of treatment fluids from passing downhole through the valve  200   a.    
         [0042]    The above-described process is then repeated for all of the sleeve valves  200   b - 200   f.  Once the treatments are completed, the pressure in work string  112  is reduced, flow back from the various zones will force the balls to flow back up the well to the rig  106  where they are recovered from the well. As the balls flow up the work string  112 , the balls will contact the baffles  264  and force them into the expanded position illustrated in  FIG. 6 . Expanding the baffles  264  eliminates the flow restriction resulting from the contracted baffle position illustrated in  FIG. 5 . 
         [0043]    In some embodiments, operating a wellbore servicing system such as wellbore servicing system  100  may comprise providing a first sleeve system (e.g., of the type of sleeve systems  200 ) in a wellbore and providing wellbore servicing pumps and/or other equipment to produce a fluid flow through the sleeve flow bores of the sleeve system. Subsequently, an obturator may be introduced into the fluid flow so that the obturator travels downhole and into engagement with the seat of a baffle in first sleeve valve. When the obturator contacts the seat, fluid pressure may be increased to cause the first sleeve system to open ports to provide treatment paths. 
         [0044]    In the described embodiments, a method of performing a wellbore servicing operation may comprise providing a work string comprising a plurality of sleeve systems in a configuration as described above and positioning the work string within the wellbore such that one or more of the plurality of sleeve systems is positioned proximate and/or substantially adjacent to one or more of the zones. The zones may be isolated, for example, by actuating one or more packers or similar isolation devices. 
         [0045]    In the described embodiments, a method of performing a wellbore servicing operation may comprise providing well casing comprising a plurality of sleeve systems in a configuration as described above and positioning the casing such that one or more of the plurality of sleeve systems is positioned proximate and/or substantially adjacent to one or more of the zones. The zones may be isolated, for example, by actuating one or more packers or similar isolation devices 
         [0046]    One of skill in the art will appreciate that the servicing fluid communicated to the zone may be selected dependent upon the servicing operation to be performed. Nonlimiting examples of such servicing fluids include a fracturing fluid, a hydrajetting or perforating fluid, an acidizing, an injection fluid, a fluid loss fluid, a sealant composition, or the like. 
         [0047]    Use of broader terms such as comprises, includes, and having should be understood to provide support for narrower terms such as consisting of, consisting essentially of, and comprised substantially of. Accordingly, the scope of protection is not limited by the description set out above but is defined by the claims that follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated as further disclosure into the specification and the claims are embodiment(s) of the present invention.