Abstract:
A method of treating a subterranean formation surrounding a wellbore, according to which a tool inserted into the wellbore for performing a function in the wellbore is fabricated of a material that breaks up upon detonation of an explosive mounted on the tool, thus allowing the pieces of the tool to fall to the bottom of the wellbore.

Description:
BACKGROUND  
         [0001]    This disclosure relates to a system and method for treating a subterranean formation surrounding a wellbore, and, more particularly, to such a system and method for removing downhole tools that are inserted into the wellbore to perform various operations in connection with recovering hydrocarbons from the formation.  
           [0002]    Various types of downhole tools are inserted into a well in connection with producing hydrocarbons from the formation surrounding the well. For example, tools for plugging, or sealing, different zones of the formation are often inserted in the wellbore to isolate particular zones in the formation. After the operation is complete, the plugging or sealing tools must be removed from the wellbore which can be accomplished by inserting a drilling tool, mud motor, or the like into the wellbore and mechanically breaking up the tools by drilling, milling, or the like. However this removal process requires multiple trips in and out of the hole, is expensive, and time consuming.  
           [0003]    The present invention is directed to a system and method for removing tools from a wellbore that is an improvement over the above techniques.  
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0004]    [0004]FIG. 1 is a partial elevational/partial sectional view, not necessarily to scale, depicting a well and a system for recovering oil and gas from an underground formation.  
         [0005]    [0005]FIG. 2 is a sectional view of an example of a tool that is inserted in the well of FIG. 1 then removed according to an embodiment of the present invention.  
         [0006]    [0006]FIGS. 3-5 are enlarged sectional views of the well of FIG. 1 illustrating several steps of inserting and removing the tool of FIG. 2 according to the above embodiment. 
     
    
     DESCRIPTION OF THE PREFERRED EMBODIMENTS  
       [0007]    Referring to FIG. 1, the reference numeral  10  refers to a wellbore penetrating a subterranean formation F for the purpose of recovering hydrocarbons from the formation. To this end, and for the purpose of carrying out a specific operation to be described, a downhole tool  12  is lowered into the wellbore  10  to a predetermined depth, by a string  14 , in the form of wireline, coiled tubing, jointed tubing, or the like, which is connected to the upper end of the tool  12 . The tool  12  is shown generally in FIG. 1 but will be described in detail later. The string  14  extends from a rig  16  that is located above ground and extends over the wellbore  10 . The rig  16  is conventional and, as such, includes support structure, a motor driven winch, and other associated equipment for receiving and supporting the tool  12  and lowering it into the wellbore  10  by unwinding the string  14  from a reel, or the like, provided on the rig  16 .  
         [0008]    At least a portion of the wellbore  10  can be lined with a casing  20 , and the casing  20  is cemented in the wellbore  10  by introducing cement  22  in an annulus formed between the inner surface of the wellbore  10  and the outer surface of the casing  20 , all in a convention manner. A production tubing  26  having a diameter greater than that of the tool  12 , but less than that of the casing  20 , is installed in the wellbore  10  in a conventional manner and extends from the ground surface to a predetermined depth in the casing  20 .  
         [0009]    For the purpose of example only, it will be assumed that the tool  12  is in the form of a plug that is used in a stimulation/fracturing operation to be described. To this end, and with reference to FIG. 2, the tool  12  includes an elongated tubular body member  32  having a continuous axial bore extending through its length for passing fluids in a manner to be described. A cage  34  is formed at the upper end of the body member  32  for receiving a ball valve  36  which prevents fluid flow downwardly through the body member  32 , as viewed in FIG. 1, but permits fluid flow upwardly through the body member  32 .  
         [0010]    A packer  40  extends around the body member  32  and can be formed by a plurality of angularly spaced sealing elements. A plurality of angularly spaced slips  42  are mounted around the body member  32  just below the packer  40 . A tapered shoe  44  is provided at the lower end of the body member  32  for the purpose of guiding and protecting the tool  12  as it is lowered into the wellbore  10 . An explosive device  46  is mounted on the body member  32 . The explosive device  46  can be in the form of any type of conventional explosive sheet, detonation cord, or the like.  
         [0011]    With the exception of the ball valve  36  and any elastomers or other sealing elements utilized in the packer  40 , all of the above components, as well as many other components making up the tool  12  which are not shown and described above, are fabricated from cast iron, i.e. a hard, brittle, nonmalleable iron-carbon alloy. As a non-limiting example, the cast iron can be an iron-carbon alloy containing 2 to 4.5 percent carbon, 0.5 to 3 percent silicon, and lesser amounts of sulfur, manganese, and phosphorus. The cast iron is relatively high in strength yet fractures, shatters, or otherwise breaks up under detonation exposure due to its brittle nature, for reasons to be described. Otherwise, the tool  12  is conventional and therefore will not be described in further detail.  
         [0012]    [0012]FIGS. 3-5 depict the application of the tool  12  in an operation for recovering hydrocarbons from the formation F. In particular, and referring to FIG. 3, a lower producing zone A, an intermediate producing zone B, and an upper producing zone C, are all formed in the formation F. A plurality of perforations  20   a  and  22   a  are initially made in the casing  20  and the cement  22 , respectively, adjacent the zone A. This can be done in a conventional manner, such as by lowering a perforating tool (not shown) into the wellbore  10 , performing the perforating operation, and then pulling the tool from the wellbore  10 .  
         [0013]    The area of the formation F adjacent the perforations  20   a  and  22   a  can then be treated by introducing a conventional stimulation/fracturing fluid into the wellbore  10 , so that it passes through the perforations  20   a  and  22   a  and into the formation F. This stimulation/fracturing fluid can be introduced into the wellbore  10  in any conventional manner, such as by lowering a tool containing discharge nozzles or jets for discharging the fluid at a relatively high pressure, or by passing the stimulation/fracturing fluid from the rig  16  directly into the wellbore  10 . In either case, the stimulation/fracturing fluid passes through the perforations  20   a  and  22   a  and into the zone A for stimulating the recovery of production fluids, in the form of oil and/or gas containing hydrocarbons. The production fluids pass from the zone A, through the perforations  20   a  and  22   a,  and up the wellbore  10  to the production tubing  26  for recovery at the rig  16 . If the stimulation/fracturing fluid is discharged through a downhole tool as described above, the latter tool is then removed from the wellbore  10 .  
         [0014]    The tool  12  is then lowered by the string  14  into the wellbore  10  to a position where its lower end portion formed by the shoe  44  is just above the perforations  20   a  and  22   a,  as shown in FIG. 4. The packer  40  is set to seal the interface between the tool  12  and the casing  20  and thus isolate the zone A. The string  14  is disconnected from the tool  12  and returned to the rig  16 . The production fluids from the zone A then pass through the perforations  20   a  and  22   a,  into the wellbore  10 , and through the aforementioned bore in the body member  32  of the tool  12 , before flowing up the wellbore  10  to the production tubing  26  for recovery at the rig  16 .  
         [0015]    A second set of perforations  20   b  and  22   b  are then formed, in the manner discussed above, through the casing  20  and the cement  22 , respectively, adjacent the zone B just above the upper end of the tool  12 . The zone B can then be treated by the stimulation/fracturing fluid, in the manner discussed above, causing the recovered fluids from the zone B to pass through the perforations  20   b  and  22   b  and into the wellbore  10  where they mix with the recovered fluids from the zone A before flowing up the wellbore  10  to the production tubing  26  for recovery at the ground surface.  
         [0016]    As shown in FIG. 5, another tool  12 ′ is provided, which is identical to the tool  12  and thus includes identical components as the tool  12 , which components are given the same reference numerals. The tool  12 ′ is lowered by the string  14  into the wellbore  10  to a position where its lower end portion formed by the shoe  44  is just above the perforations  20   b  and  22   b.  The packer  40  of the tool  12 ′ is set to seal the interface between the tool  12 ′ and the casing  20  and thus isolate the zone B. The string  14  is then disconnected from the tool  12 ′ and returned to the rig  16 .  
         [0017]    A third set of perforations  20   c  and  22   c  are then formed in the casing  20  and the cement  22  adjacent the zone C and just above the upper end of the tool  12 ′, in the manner discussed above. The zone C can then be treated by the stimulation/fracturing fluid, also in the manner discussed above, causing the recovered fluids from the zone C to pass through the perforations  20   c  and  22   c  and into the wellbore  10  where they mix with the recovered fluids from the zones A and B before passing up the wellbore  10  to the production tubing  26  for recovery at the ground surface.  
         [0018]    It can be appreciated that additional producing zones, similar to the zones A, B, and C, can be provided above the zone C, in which case the above operations would also be applied to these additional zones.  
         [0019]    After the above fluid recovery operations are terminated, the tools remaining in the wellbore  10 , which in the above example are tools  12  and  12 ′, must be removed from the wellbore  10 . In this context, and as stated above, many of the components making up the tools  12  and  12 ′ are fabricated from cast iron. Therefore upon detonation of the explosive device  46 , the cast iron components of the tools  12  and  12 ′ fracture, shatter, or otherwise break up into many relatively small pieces which will fall to the bottom of the wellbore  10 . The above detonation of the explosive device  46  can be initiated by a timer (not shown) built into the tools  12  and  12 ′, and the detonations can either be simultaneously or sequentially.  
         [0020]    According to an alternate embodiment, many of the above components making up the tools  12  and  12 ′, with the exception of the ball valve  36  and any elastomers or other sealing elements utilized in the tools  12  and  12 ′, are fabricated from any conventional ceramic material which, in general, can consist of any of various hard, brittle, heat-resistant and corrosion-resistant materials made by shaping and then firing a nonmetallic mineral, such as clay, at a high temperature. The ceramic material offers relatively high strength and high chemical resistance, yet fractures, shatters, or otherwise breaks up relatively easily under detonation exposure due to its brittle nature.  
         [0021]    Thus, upon detonation of the explosive device  46 , the ceramic components of the tools  12  and  12 ′ will fracture, shatter, or otherwise break up into many relatively small pieces which will fall to the bottom of the wellbore  10 . As in the previous embodiment, the above detonation of the explosive device  46  can be initiated by a timer (not shown) built into the tools  12  and  12 ′ and the detonations can either be simultaneously or sequentially. Therefore this alternative embodiment enjoys all of the advantages of the first embodiment.  
         [0022]    Thus, according to each of the above embodiments, the downhole tool(s)  12  and  12 ′ can be easily and quickly removed with a minimum of time and expense.  
       Variations and Alternates  
       [0023]    (1) The type of downhole tools, or portions of downhole tools, utilized and fractured, shattered, or otherwise broken up the above manner can be varied.  
         [0024]    (2) The entire portion of the downhole tools  12  and  12 ′ can be fabricated from cast iron or ceramic.  
         [0025]    (3) The explosive device  46  on the downhole tools  12  and  12 ′ can be detonated in any know manner other than by a timer.  
         [0026]    (4) The number of downhole tools broken up in the above manner can vary.  
         [0027]    (5) The casing  20 , and therefore the cement  22 , can be eliminated.  
         [0028]    (6) The type of material forming the downhole tools  12  and  12 ′, or the components of the tools discussed above, can vary as long as the material fractures, shatters, or otherwise breaks up upon detonation of the explosive device  46 .  
         [0029]    (7) The foregoing descriptions of specific embodiments of the present invention have been presented for purposes of illustration and description and are not intended to be exhaustive or to limit the invention to the precise forms disclosed, and obviously many other modifications and variations are possible in light of the above teaching. The embodiments were chosen and described in order to best explain the principles of the invention and its practical application, to thereby enable others skilled in the art to best utilize the invention and various embodiments with various modifications as are suited to the particular use contemplated. It is intended that the scope of the invention be defined by the claims appended hereto and their equivalents.