Patent Abstract:
A straddle packer tool for treatment of wells has a tool body supporting sealing elements in spaced relation for defining a sealed annulus zone within a wellbore. The tool body defines a treatment fluid passage having treatment ports that open to the sealed annulus zone for formation fracturing or other well treatment. The tool body has a bypass passage therethrough which is isolated from the treatment fluid passage and communicates with the wellbore above and below the sealed annulus zone. A check valve permits downward flow of well fluid from the bypass passage into the wellbore below the tool and prevents upward flow of fluid into the bypass passage. Bypass ports conduct fluid flow to and from the bypass passage and the wellbore above and below the sealed annulus zone. A packer actuated bypass valve is opened or closed to control the flow of well fluid within the bypass passage.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATION  
       [0001]    This application claims priority from United States Provisional Application No. 60/284,590, filed on Apr. 18, 2001, which Provisional Application is incorporated herein by reference for all purposes. 
     
    
     
       BACKGROUND OF THE INVENTION  
         [0002]    1. Field of the Invention  
           [0003]    This invention relates generally to formation interval straddle packer tools that are used in casing lined wellbores for formation zone fracturing or other formation treating operations. More particularly, the present invention concerns a straddle packer tool having a valving system which permits bypass of well fluid below the tool to the wellbore above the tool, permits well formation treatment, such as formation fracturing, to be accomplished, and permits bypass of well fluid above the tool to the wellbore below the tool.  
           [0004]    2. Description of Related Art  
           [0005]    After a wellbore has been drilled, various completion operations are typically performed to enable production of wellbore fluids. Examples of such completion operations include the installation of casing, production tubing, and various packers to define or isolate zones within the wellbore. Also, a perforating string is lowered into the wellbore and fired to create perforations in the surrounding casing lining the wellbore and to extend the perforations into the surrounding formation.  
           [0006]    To further enhance the productivity of the formation, fracturing of the formation may be performed. Typically, fracturing fluid is pumped into the wellbore to fracture the formation so that fluid flow conductivity in the formation is improved to provide enhanced fluid flow into the wellbore.  
           [0007]    A typical fracturing string includes an assembly carried by tubing, which may be coiled tubing, or jointed tubing such as drill pipe, with the assembly including a straddle packer tool having sealing elements to define a sealed interval into which fracturing fluids may be pumped for communication with the surrounding formation. The fracturing fluid is pumped down the tubing and through one or more ports in the straddle packer tool into the sealed interval.  
           [0008]    Straddle packer tools used for fracturing typically incorporate one or more bypass passages to permit fluid communication between zones above and below the tool. Such bypass passages facilitate run-in of the tool by allowing fluid in the wellbore to move upwardly through the tool as it is run into the well. Likewise, such bypass passages also facilitate pulling the tool out of the well, especially from deep treating depths, without experiencing excessive pulling loads.  
           [0009]    However, despite the advantages of bypass passages, they also present a major disadvantage in that they permit pressurized wellbore fluids from below the sealed interval to migrate through the straddle packer tool during fracturing. The presence of such pressurized fluids in the wellbore above the straddle packer tool may make it impossible for the operator controlling the fracturing process to identify problems with the process, such as the breakthrough of fracturing fluids through the formation and into the wellbore above the straddle packer tool.  
           [0010]    Additionally, as sand and debris above the straddle packer tool can potentially stick the tool in the well, bypass passages may have screens over their inlet openings to prevent sand and wellbore debris from flowing from the lower zones to the upper zones above the straddle packer tool.  
           [0011]    Therefore, a method and apparatus is needed for bypassing wellbore fluids through straddle packers during run-in and pull-out while preventing fluid bypass during fracturing and other well treating operations.  
         BRIEF SUMMARY OF THE INVENTION  
         [0012]    The present invention relates to the use of a check valve in a straddle packer tool bypass passage that prevents flow from the lower zone to the upper zone through the bypass passage during fracturing operations. However, free flow is allowed through the check valve from the upper zone to the lower zone when the straddle packer tool is pulled out of the wellbore. This invention thus allows easy pulling from deep treating depths since displaced fluid can flow from the upper zone to the lower zone through the bypass passage and check valve carrying with it any sand and debris which may have accumulated above the tool.  
           [0013]    At times, the lower sealing member of the tool is defined by two oppositely directed lower cup packers. In this case, the lower cup packer is oriented with its open end directed downwardly and prevents flow from zones below the tool from carrying sand and debris to the sealed annulus zone or interval between the upper and lower sealing members. When such a packer arrangement is used, a sleeve valve is used to allow fluid to bypass the check valve when running the tool into the well, thus permitting well fluid displaced by the tool to be displaced through the tool to the wellbore above the tool. The sleeve valve is energized for movement to its closed position by lower packer movement responsive to increase of treatment fluid pressure within the sealed annulus zone. Since the treatment fluid passage and the bypass passage of the tool are not in communication, any treatment fluid within the treatment fluid passage is not compromised in any manner whatever by the bypassed well fluid. When interval pressure is applied during fracturing, the cup packers cause the sleeve valve to close and prevent further flow of fluid through the bypass passage of the tool from lower to upper zones. The sleeve valve remains closed when the straddle packer tool is pulled out of the well and the check valve opens to allow downward flow of well fluids through the bypass passage of the tool and into the wellbore below the tool.  
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0014]    So that the manner in which the above recited features, advantages and objects of the present invention are attained and may be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the preferred embodiment thereof which is illustrated in the appended drawings, which drawings are incorporated as a part hereof.  
         [0015]    It is to be noted however, that the appended drawings illustrate only a typical embodiment of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.  
         [0016]    In the Drawings:  
         [0017]    [0017]FIG. 1 is a schematic representation of an example embodiment of a fracturing tool string in a wellbore;  
         [0018]    FIGS.  2 A- 2 C are vertical cross-sectional views illustrating a straddle packer tool having a valve assembly in accordance with an embodiment used with the fracturing string of FIG. 1;  
         [0019]    [0019]FIG. 3 is a cross-sectional view showing the check valve assembly of FIG. 2C in greater detail;  
         [0020]    [0020]FIG. 4 is a cross-sectional view of the check valve assembly of FIG. 3 taken along the line  4 - 4 ; and  
         [0021]    [0021]FIG. 5 is a vertical cross-sectional view showing an alternative embodiment of the sliding sleeve valve assembly of FIG. 2C. 
     
    
     DETAILED DESCRIPTION OF THE INVENTION  
       [0022]    In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations and modifications from the described embodiments may be possible. For example, although reference is made to a fracturing string in the described embodiments, other types of tools may be employed in further embodiments without departing from the spirit and scope of the present invention.  
         [0023]    As used herein, the terms “up” and “down”; “upward” and “downward”; “upstream” and “downstream”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to “left to right” or “right to left”, or other relationship as appropriate.  
         [0024]    Referring now to the drawings and first to FIG. 1, a fracturing tool string is positioned in a wellbore shown generally at  10 . The wellbore  10  is typically lined with casing  12  and extends through an earth formation  18  that has been perforated to form perforations  20 . To perform a fracturing operation, a straddle packer tool  22  carried on a tubing  14  (e.g., a continuous tubing such as coiled tubing or a jointed tubing such as drill pipe or any other type of jointed tubing or pipe) is run into the wellbore  10  to a depth adjacent the perforated earth formation  18 . The straddle packer tool  22  includes upper and lower sealing elements (e.g., packers)  28  and  30 . When set, the sealing elements  28  and  30  define a sealed annulus zone  32  outside the housing of the straddle packer tool  22 . The sealing elements  28  and  30  are carried on a ported sub  27  that has one or more ports  24  to enable communication of fracturing fluids pumped down the tubing  14  to the sealed annulus zone  32 . The straddle packer tool  22  further includes a bypass passage defined in part by bypass channels  29  to facilitate running the tool into the well by enabling the displacement of fluid through the tool as it moves downward.  
         [0025]    In accordance with an embodiment of the present invention, a valve assembly  26  is connected below the ported sub  27 . When the straddle packer tool  22  is run into the well in preparation for a well treatment operation such as formation fracturing, the valve assembly  26  is open to permit displaced well fluid to be bypassed upwardly through the bypass passage of the tool.  
         [0026]    Referring now to the vertical cross-sectional views of FIGS. 2A, 2B and  2 C, which respectively show in detail the upper, intermediate, and lower sections of a straddle packer tool, shown in detail generally at  22 , which embodies the principles of the present invention and represents the preferred embodiment. The straddle packer tool  22  incorporates an upper connector section or mandrel  34  having an internally threaded connector receptacle  36  for receiving a tubing connector of a tubing string that is employed for running and retrieving the straddle packer tool  22  and for conducting pressurized treatment fluid such as fracturing slurry to a treatment fluid passage  38  of the upper connector section  34 . The upper connector section  34  also defines a conductor receptacle  40  within which is received the upper end  42  of a fluid conductor conduit  44  which defines a treatment fluid passage  46  for conducting fracturing slurry or other treatment fluid into the straddle packer tool  22 . The upper end  42  of the fluid conductor conduit  44  is sealed with respect to the upper connector section  34  by an annular seal  48 . An upper packer mandrel  50  is provided, having its tubular upper connector end  52  received in threaded engagement within an internally threaded receptacle  54  at the lower end of the upper connector section  34 . The upper packer mandrel  50  has an elongate tubular section  56  to which is mounted an upper sealing element  58  having a seal retainer  60  with a flexible cup packer  62  seated within the seal retainer. The cup packer  62  has a closed end which is mounted to the seal retainer  60  and a larger annular open end which is oriented to face a source of fluid pressure. The upper sealing element  58  is thus of the cup packer variety which is expanded by pressure exposed to its larger open resilient or flexible end for expanding to establish sealing engagement within the wellbore or well casing by fluid pressure that enters an annulus  64  between the open end of the flexible cup packer  62  and a cylindrical outer surface  66  of the elongate tubular section  56  of the upper packer mandrel  50 .  
         [0027]    The upper packer mandrel  50  defines an internal surface  68  which is of greater dimension as compared with the dimension of an external surface  70  of the fluid conductor conduit  44 , thus providing an annular space or annulus  72  which defines a flow passage which constitutes a portion of a bypass passage extending through the tool. This flow passage is in communication with fluid transfer ports  74  that are defined in the upper connector section  34 . As will be explained in greater detail below, fluid within the annulus between the tool and the well casing and above the upper sealing element  58  can be conducted through the tool such as during pull-out or retrieval of the tool following a fracturing operation or other treatment that is conducted within the well.  
         [0028]    At its lower end, the upper packer mandrel  50  is provided with an externally threaded connector section  76  which is received in threaded engagement with an internally threaded connector section  78  of a tubular bypass mandrel  80 . Seals  82  are carried within external seal grooves of a tubular extension  84  of the upper packer mandrel  50  and establish sealing with an internal surface of the tubular bypass mandrel  80 . Likewise, the tubular bypass mandrel  80  is provided with an externally threaded connector section  86  that is received in threaded engagement with an internally threaded connector section  88  of a treatment mandrel  90 . Seals  92  are carried within external seal grooves of a tubular extension  94  of the tubular bypass mandrel  80  and establish sealing with an internal surface of the treatment mandrel  90 . The treatment mandrel  90  defines a thick walled central section  96  having treatment ports  98  that are in communication with a fluid passage section  100  that is located centrally of the thick walled central section  96  and is in fluid communicating registry with the treatment fluid passage  46 . The lower end  102  of the fluid conductor conduit  44  is located within a receptacle  104  of the thick walled central section  96  and is sealed with respect thereto by an annular sealing member  106 . The treatment fluid passage  46  of the fluid conductor conduit  44  is open to the fluid passage section  100  for communication of treatment fluid to the treatment ports  98 . Below the treatment ports the fluid passage section  100  is closed by a plug member  108  which is sealed with respect to the internal wall of the fluid passage section  100  by an annular sealing element  110 . The plug member  108  may simply be a blind plug member for closure of the fluid passage section  100 , and may be threaded to or otherwise retained within the fluid passage section  100 . Alternatively, the plug member  108  may take the form of an electronic memory device having the capability of detecting and recording various well treatment parameters such as, for example, injection pressure, volume of fluid flow, well fluid pressure below the straddle packer tool. The treatment mandrel  90  is provided with an externally threaded connector extension  118  which is received by an internally threaded connector section  122  of a lower packer and valve mandrel  120 .  
         [0029]    As mentioned above, it is desirable, to achieve appropriate treatment of the well, to flow displaced well fluid through the straddle packer tool during run-in and to drain well fluid through the tool during run-out. To accomplish this feature the thick-walled central section  96  of the treatment mandrel  90  defines a plurality of bypass passages  112  having their upper ends in communication with an annulus  114  between the fluid conductor conduit  44  and the internal wall surface of the tubular bypass mandrel  80 . The annulus  114  defines a portion of a bypass passage through the straddle packer tool  22  and is in communication with the annular space or annulus  72  between the fluid conductor conduit  44  and the upper packer mandrel  50 . The bypass passages  112  are also in communication with an annulus  116  located below the thick walled central section  96  of the treatment mandrel  90  and being defined between the plug member  108  and the tubular connection extension  118  of the treatment mandrel  90 . The annulus  116  and the central passage  128  below the plug member  108  also define portions of a bypass passage through the tool.  
         [0030]    Lower packer mandrel  120  is provided with an upper tubular, internally threaded connector section  122  within which is received an externally threaded connector section  124  of the treatment mandrel  90 . Seals  126  establish sealing of the tubular connection extension  118  of the treatment mandrel  90  within the upper end of the lower packer mandrel  120 . The lower packer mandrel  120  defines an elongate reduced diameter tubular section  130  which defines an external cylindrical surface  132 . A lower sealing element, which may be a double packer assembly shown generally at  134 , is movably mounted on the elongate reduced diameter tubular section  130  for movement relative to the external cylindrical surface  132 . The double packer assembly  134  is of the oppositely directed double cup variety having an upper flexible sealing cup  136  composed of rubber or any other rubber-like or elastic material which is supported by a cup retainer  138 . Another cup retainer  140  is located immediately below the cup retainer  138  and provides support for a lower flexible sealing cup  142 . Since the flexible sealing cups  136  and  142  are oppositely directed, collectively, the lower sealing element  134  is capable of pressure energized sealing by upstream pressure from the sealed annulus zone  32  or pressure within the well below the double sealing assembly  134 . It should be borne in mind that although a double sealing assembly  134  may be used, such is not mandatory. It may be desirable to employ a single sealing member in place of the double sealing assembly  134 . Also, although cup-type packers are illustrated in the embodiment shown in FIGS.  2 A- 2 C, other types of sealing members or packers may be employed without departing from the spirit and scope of the present invention. It is only necessary that the lower sealing element  134  be movable in response to fluid treatment pressure within the sealed annulus zone for closing a bypass valve as described below.  
         [0031]    As mentioned above, during tool run-in it is desirable to bypass displaced well fluid below the straddle packer tool through the tool and into the wellbore above the tool. Also, during tool pull-out or extraction, it is desirable to bypass well fluid above the tool through the tool and into the wellbore below the tool to thereby minimize the weight of the tubing string and straddle packer tool and thus minimize the force that is required for tool run-out or extraction. During well treatment it is desirable to prevent treatment fluids from previously treated zones from flowing upwardly through the straddle packer tool into the wellbore above the tool. This is accomplished by a sliding sleeve valve  144  and check valve assembly  165 . The sliding sleeve valve  144  has a lower annular end  145  that forms a closure for the bypass ports  148  of the tubular section  130  of the lower packer mandrel  120 . An annular stop ring  146  is positioned in encircling relation about a lower portion of the external cylindrical surface  132  and rests on the upper annular shoulder  147  of a drain housing  150 , with its upper end located below the bypass ports  148 . When the sliding sleeve valve  144  has moved downwardly to its maximum extent, blocking flow through the bypass ports  148 , its downward movement will be stopped by the upper end of the stop ring  146 .  
         [0032]    The lower end section of the straddle packer tool  22  is defined by drain housing  150  having drain ports  152  for draining fluid from the wellbore above the straddle packer tool  22  into the wellbore below the lower seal assembly  134 . For draining fluid into a conduit that may be connected to the lower end of the tool, a drain port  154  is located centrally of the drain housing  150  to permit fluid to be drained into a receptacle  156  which is defined by a lower tubular extension  158  of the drain housing  150 . The lower tubular extension  158  is provided with an internally threaded connector section  160  that, if desired, is adapted to receive a conduit for conducting the fluid downwardly within the well while maintaining the fluid substantially isolated from the annulus between the straddle packer tool  22  and the well casing immediately below the tool. The lower end of the tubular section  130  of the lower packer mandrel  120  is provided with an externally threaded connector section  162  which is threaded into the internally threaded upper end  164  of the drain housing  150 . The various interconnected mandrels of the tool collectively define an elongate tool body of generally tubular construction, with the body and its internal tubular components defining the bypass passage and the treatment fluid passage of the tool.  
         [0033]    Check valve assembly  165  including a check valve housing  166 , shown in FIG. 2C and in greater detail in FIGS. 3 and 4, is located within the lower end of the tubular section  130  and defines an internal annular valve seat  167  (FIG. 3) which is normally engaged by a check valve element  172 . The check valve element  172  may be in the form of a ball type check valve as shown or it may have any other suitable check valve configuration. The check valve element  172  is urged to its closed position in engagement with the sharp cornered annular valve seat  167  by a compression spring  174 . For centering of the compression spring  174  within the check valve housing  166  the lower end of the compression spring  174  is engaged within a spring receptacle  175  of a spring positioning element  176  that is seated on the lower ported closure member  168 . The lower ported closure member  168  defines a plurality of drain ports  169  for draining fluid that enters the check valve housing  166  past the check valve element  172 . The lower end of the check valve housing  166  defines a retainer flange  178  which is positioned on a retainer flange  180  of the lower ported closure member  168 . The check valve assembly  165  is retained within the lower end of the tubular section  130  by the lower end of the externally threaded connector section  162  of the tubular section  130 , which secures the retainer flanges  178  and  180  against an upwardly facing annular shoulder  182  of the upper valve retainer section  170  of the drain housing  150 . Downward movement of the check valve element  172  is limited by a centrally located stop post  184  which projects upwardly from the central region of the lower ported closure member  168 . To ensure controlled pressure responsive movement of the check valve element  172  and to ensure against lateral buckling of the compression spring, a plurality of valve and spring guide posts  186  are mounted within apertures of the spring positioning element  176  and serve to maintain substantially centralization of the check valve element  172  and the compression spring  174  during pressure responsive check valve movement.  
       OPERATION  
       [0034]    The straddle packer tool of FIGS.  2 A- 2 C is connected at its upper end to a string of tubing such as coiled tubing, or jointed tubing, such as drill pipe. The tool is run into a well by the tubing with the sliding sleeve valve  144  open, as shown in FIG. 2C, thus permitting well fluid displaced by the tool to flow through the open bypass ports  148  and into the central passage  128 , with the check valve assembly  165  remaining closed. The displaced well fluid bypasses the treatment ports by flowing upwardly through the bypass passages  112 , which are not in communication with the treatment fluid passage  46  or the treatment ports  98 . The displaced well fluid exits the tool at fluid transfer ports  74  and flows into the wellbore above the tool. During running of the tool into the well, differential pressure across the double sealing assembly  134  assists in maintaining the sliding sleeve valve  144  in the open position. When the straddle packer tool  22  has reached its treatment depth within the well, treatment fluid is supplied under pressure via the tubing string  14  which is in communication with the treatment fluid passage  46 , with the treatment fluid exiting the treatment ports  98  and flowing into the annulus between the tool and the wellbore or well casing and between the upper and lower sealing assemblies or packers of the tool. Since the lower sealing assembly  134  is movable downwardly by pressure actuation, initial pressuring within the annulus between the tool and the wellbore or well casing and between the upper and lower sealing assemblies causes the lower sealing assembly to be moved downwardly, causing downward or closing movement of the sliding sleeve valve  144 . At this point, pressure of the well treatment fluid within the sealed annulus zone  32  is raised to the appropriate treatment pressure.  
         [0035]    After the well treatment has been completed, treatment fluid pressurization within the sealed annulus zone is discontinued. With the sliding sleeve valve  144  remaining closed, the straddle packer tool  22  is moved upwardly within the well by application of upward force to the tubing. As the tool is moved upwardly, the hydrostatic pressure of well fluid above the tool acts on the check valve assembly  165 , thus opening the check valve and permitting the well fluid above the tool to bypass through the tool and exit the tool past the check valve. This fluid bypass arrangement allows easy pulling of tools from deep treating depths since the bypassing well fluid does not require lifting of a substantial volume of fluid along with the tool. Additionally, as the tool is moved upwardly, differential pressure across the double sealing assembly  134  assists in maintaining the sliding sleeve valve  144  in the closed position.  
         [0036]    An alternative embodiment of the sliding sleeve valve  144  is illustrated in FIG. 5 which shows the lower section of a straddle packer tool  22  as shown in FIG. 2C. Like parts in FIGS. 2C and 5 are indicated by like reference numerals. To ensure that sliding sleeve valve  144  remains in the closed position after actuation, sliding sleeve valve  144  and valve stop ring  146  have interfitting locking tapers  141  and  143  on their mating ends.  
         [0037]    In view of the foregoing it is evident that the present invention is one well adapted to attain all of the objects and features hereinabove set forth, together with other objects and features which are inherent in the apparatus disclosed herein.  
         [0038]    As will be readily apparent to those skilled in the art, the present invention may easily be produced in other specific forms without departing from its spirit or essential characteristics. The present embodiment is, therefore, to be considered as merely illustrative and not restrictive, the scope of the invention being indicated by the claims rather than the foregoing description, and all changes which come within the meaning and range of equivalence of the claims are therefore intended to be embraced therein.

Technology Classification (CPC): 4