Abstract:
Methods for preparing a wellbore casing for stimulation operations comprise the steps of cementing a wellbore casing in a wellbore, the wellbore casing having a downhole tool comprising a valve and an apparatus for restricting fluid flow through the valve, such as a ball seat, disposed above the valve. Actuation of the valve opens the valve to establish fluid communication between the wellbore casing and the formation. A plug element is disposed on a seat of the ball seat and a casing pressure test is performed. The plug element then dissolves or disintegrates over time increasing fluid communication between the wellbore casing and the formation, thereby preparing the wellbore casing for stimulation operations without additional wellbore intervention after the casing pressure test. In certain embodiments, during or after dissolution of the plug element, clean-out of the bore of the valve is performed by the plug element.

Description:
BACKGROUND 
     1. Field of Invention 
     The present invention is directed to methods of preparing a cased wellbore for stimulation operations and, in particular, to interventionless methods for preparing the cased wellbore for stimulation operations using pressure actuated sleeves and apparatuses for temporarily restricting fluid flow through the wellbore casing to prepare the wellbore casing for stimulation operations as opposed to using additional wellbore intervention methods such as tubing conveyed perforation. 
     2. Description of Art 
     Ball seats are generally known in the art. For example, typical ball seats have a bore or passageway that is restricted by a seat. The ball or plug element is disposed on the seat, preventing or restricting fluid from flowing through the bore of the ball seat and, thus, isolating the tubing or conduit section in which the ball seat is disposed. As force is applied to the ball or plug element, the conduit can be pressurized for tubing testing or tool actuation or manipulation, such as in setting a packer. Ball seats are used in cased hole completions, liner hangers, flow diverters, fracturing systems, acid-stimulation systems, and flow control equipment and other systems. 
     Although the terms “ball seat” and “ball” are used herein, it is to be understood that a drop plug or other shaped plugging device or element may be used with the “ball seats” disclosed and discussed herein. For simplicity it is to be understood that the terms “ball” and “plug element” include and encompass all shapes and sizes of plugs, balls, darts, or drop plugs unless the specific shape or design of the “ball” is expressly discussed. 
     Stimulating, which as used herein includes fracturing or “fracing,” a wellbore using stimulation systems or tools also are known in the art. In general, stimulating systems or tools are used in oil and gas wells for completing and increasing the production rate from the well. In deviated wellbores, particularly those having longer lengths, fluid, such as acid or fracturing fluids, can be expected to be introduced into the linear, or horizontal, end portion of the well to stimulate the production zone to open up production fissures and pores there-through. For example, hydraulic fracturing is a method of using pump rate and hydraulic pressure created by fracturing fluids to fracture or crack a subterranean formation, or the wellbore environment. 
     Prior to stimulating a wellbore, a stimulation tool is cemented into the wellbore. Thereafter, a pressure test of the wellbore casing containing the stimulation tool is performed. To perform this step, the pathway through the stimulation tool must be closed off. After the casing test establishes the integrity of the wellbore casing, fluid communication of the pathway through the stimulation tool is reestablished so that the stimulation fluid can be pumped down through the stimulation tool and into the formation. Currently, the steps involved in reestablishing fluid flow through the stimulation tool require additional wellbore intervention such as by using tubing conveyed perforation. 
     SUMMARY OF INVENTION 
     Broadly, the methods for preparing a wellbore for stimulation operations disclosed herein comprise the steps of cementing into a wellbore casing a downhole tool comprising a valve having an apparatus for restricting fluid flow through the valve, such as a ball seat, disposed above the valve. The valve is actuated to its opened position to establish fluid flow between the casing bore and the formation or wellbore environment. Thereafter, a plug element is disposed on the seat of the ball seat and a casing pressure test is performed. The plug element then dissolves or disintegrates over time thereby increasing fluid communication between the formation and the wellbore casing through the valve, thereby placing the wellbore casing in condition for stimulation operations without additional wellbore intervention after the casing test. 
     In one specific embodiment, the plug element also functions as a wiper member to facilitate additional clean-up of the bore of the valve after the pressure test has been performed. The plug element dissolves into a predetermined shape that, when pushed through the seat and the bore of the valve, the plug element wipes away debris within the bore of the valve. 
    
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         FIG. 1  is a cross-sectional view of one specific embodiment of the downhole tool disclosed herein showing an exemplary valve in its closed position. 
         FIG. 2  is a cross-sectional view of the downhole tool of  FIG. 1  showing the valve in one of its opened positions. 
         FIG. 3  is a cross-sectional view of the downhole tool of  FIG. 1  showing a plug element landed on a seat above the valve so that a casing test can be performed. 
         FIG. 4  is a cross-sectional view of the downhole tool of  FIG. 1  showing the downhole tool in position for stimulation operations after the pressure test has been performed and the plug element shown in  FIG. 3  dissolved. 
         FIG. 5  is a cross-sectional view of a specific embodiment of a plug element as disclosed herein. 
         FIG. 6  is a side view of the wiper member shown in  FIG. 5 . 
     
    
    
     While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to that embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims. 
     DETAILED DESCRIPTION OF INVENTION 
     Referring now to  FIGS. 1-4 , in one specific embodiment, downhole tool  30  comprises valve  40  and bore restriction apparatus  70 , shown as a ball seat in  FIGS. 1-4 .  FIG. 1  shows valve  40  in a closed position, and  FIGS. 2-4  show valve  40  actuated to an open position. 
     Valve  40  includes lower ported housing  44  having fluid communication ports  46 , and upper body  48 . Pressure integrity of valve  40  is maintained by body seals  41 . Body set screws  47  keep the body connection threads  43  from backing out during installation. Captured between lower ported housing  44  and upper body  48  is inner shifting sleeve  50 . Inner shifting sleeve  50  has several diameters that create piston areas that generate shifting forces to open valve  40 . Port isolation seals  45  located on the lower end of inner shifting sleeve  50  and lower internal bore piston seals  65  above fluid communication ports  46  both act to isolate the inside of valve  40  during and after cementation. Port isolation seals  45  and lower internal bore piston seals  65  operate within their respective polished bores  55 ,  57  within lower ported housing  44 . The larger intermediate internal bore piston seals  52  are used to drive up inner shifting sleeve  50  along the upper internal polished bore  53  within lower ported housing  44  after burst disc  42  is ruptured. 
     Upper external rod piston seals  59  located within upper body  48  act to prevent cement from entering upper atmospheric chamber  62  and wipe the outside diameter of upper sleeve polished bore  61  during opening of valve  40 . Inner shifting sleeve  50  also has shoulder  54  that shears shear screw  56  during the opening shift of inner shifting sleeve  50 . External sleeve lock ring retention groove  63  is located between internal bore seals  52  and upper sleeve polished bore  61  diameter. Lock ring retention groove  63  accepts sleeve lock ring  69  that is retained by lock ring retainer  67  after valve  40  has been fully opened. Thus, sleeve lock ring  69  prevents inner shifting sleeve  50  from closing after valve  40  has been opened ( FIGS. 2-4 ). 
     Located between lower internal bore piston seals  65  and intermediate bore piston seals  52  is lower atmospheric chamber  58  which contains air that can be independently tested through lower pressure test port  60 . Located between intermediate internal bore piston seals  52  and upper external rod piston seals  59  is upper atmospheric chamber  62  which also contains air that can be independently tested through upper pressure testing port  64 . A rupture or burst disc  42  is held in place within a port located on the outside of inner shifting sleeve  50  by load ring  66  and load nut  68 . Burst disc load nut  68  is sized to allow significant torque and load to be transferred into burst disc  42  prior to installation of inner shifting sleeve  50  within valve  40 . 
     Those skilled in the art will appreciate that the use of the rupture disc for piston access is simply the preferred way and generally more accurate than relying exclusively on shearing a shear pin. A pressure regulation valve can also be used for such selective access as well as a chemically responsive barrier that goes away in the presence of a predetermined substance or energy field, temperature downhole or other well condition for example, to move the sleeve. Burst or rupture discs  42  also can be replaced by any other pressure control plug known in the art such as those disclosed and taught in U.S. patent application Ser. No. 13/286,775, filed Nov. 1, 2011, entitled “Frangible Pressure Control Plug, Actuatable Tool, Including Plug, and Method Thereof” which is hereby incorporated by reference in its entirety. 
     After burst disc  42  is ruptured, lower chamber  58  is under absolute downhole pressure so wall flexure at that location is minimized. Even before burst disc  42  breaks, the size of lower chamber  58  is sufficiently small to avoid sleeve wall flexing in that region. The use of a large boss to support intermediate internal bore piston seals  52  also strengthens inner shifting sleeve  50  immediately below upper chamber  62 , thus at least reducing flexing or bending that could put inner shifting sleeve  50  in a bind before it is fully shifted. The slightly larger dimension of external rod piston seals  59  as compared to port isolation seals  45  that hold inner shifting sleeve  50  closed initially also allows a greater wall thickness for inner shifting sleeve  50  near the upper chamber  62  to further at least reducing flexing or bending to allow inner shifting sleeve  50  to fully shift without getting into a bind. 
     The intermediate internal bore piston seals  52  can be integral to inner shifting sleeve  50  or a separate structure. Upper chamber  62  has an initial pressure of atmospheric or a predetermined value less than the anticipated hydrostatic pressure within inner shifting sleeve  50 . The volume of upper chamber  62  decreases and its internal pressure rises as inner shifting sleeve  50  moves to open ports  46 . 
     Ball seat  70  is secured to the upper end of valve  40  through any known device or method in the art, such as a threaded connection. Ball seat  70  comprises upper end  71 , lower end  72  which is secured to valve  40 , and inner wall surface  73  defining bore  74 . Seat  75  is disposed along inner wall surface  73  for receiving a plug element such as ball  80  shown in  FIG. 3 . 
     In operation, downhole tool  30  is connected to casing at its upper and lower ends and run in open-hole cementable completions just above float equipment. After being disposed within the wellbore at the desired location, downhole tool  30  is cemented into place within the well. 
     After cementation, a clean-out operation is performed to remove debris from the flow path through valve  40 . The clean-out operation can be performed by pumping fluid through downhole tool  30  to clean up any debris remaining from the cementing operations. In addition, or alternatively, a wiper plug can be transported down the bore of the casing, past seat  75  to and through the bore of valve  40  to wipe away and debris, including residual cement. 
     After the cement has set on the outside of valve  40 , it is ready to be opened with a combination of high hydrostatic and applied pressure. Upon reaching the critical pressure, burst disc  42  is fractured and opens lower atmospheric chamber  58  to the absolute downhole pressure. This pressure acts on the piston area created by lower internal bore piston seals  65  and the larger internal bore piston seals  52  and drives inner shifting sleeve  50  upward compressing the air within upper atmospheric chamber  62  and opening fluid communication ports  46  on the ported housing  44 . Thus, the volume of upper chamber  62  decreases and its internal pressure rises as inner shifting sleeve  50  moves to open ports  46 . 
     After inner shifting sleeve  50  is completely shifted and in contact with the downward facing shoulder on lock ring retainer  67 , sleeve lock ring  69  falls into sleeve lock retention groove  63  on inner shifting sleeve  50  preventing valve  40  from subsequently closing. 
     After burst disc  42  is fractured, absolute downhole pressure acts on piston seals  52  and piston seals  65  continuously pushing sleeve  50  upward acting as a redundant locking feature preventing valve  40  from subsequently closing. 
     Upon opening valve  40 , fluid communication between the bore of downhole tool  30  and, thus, the wellbore casing string, and the wellbore formation or wellbore environment is established. Thereafter, a pressure test of the casing can be performed. To do so, plug element  80  is transported down the casing string and landed on seat  75  of ball seat  70  ( FIG. 3 ). Afterwards, a pressure test is performed. Presuming the pressure test is successful, then the wellbore is capable of having stimulation operations performed. However, the plug element  80  remains on seat  75 . Plug element  80  is removed from seat  75  over time due to the dissolution of at least a portion of plug element  80 . After plug element  80  sufficiently dissolves such that fluid pressure acting downward on plug element  80  can push plug element  80  through seat  75  and through the bore of valve  40 , fluid communication between the casing string and the formation is increased so that stimulation operations can be performed. Thus, after landing plug element  80  on seat  75  and the pressure test is performed, no additional wellbore intervention is required to place the casing string in condition for stimulation operations. 
     In certain embodiments, plug element  80  completely dissolves. In other embodiments, plug element  80  partially dissolves before passing through seat  75  and through the bore of valve  40 . In still other embodiments, a portion of plug element  80  is formed from a material that is not dissolvable. Dissolution of a portion, or all of plug element  80 , can be accomplished by having plug element  80  formed at least in part by a dissolvable material. “Dissolvable” means that the material is capable of dissolution in a fluid or solvent disposed within the wellbore casing. “Dissolvable” is understood to encompass the terms degradable and disintegrable. Likewise, the terms “dissolved” and “dissolution” also are interpreted to include “degraded” and “disintegrated,” and “degradation” and “disintegration,” respectively. The dissolvable material may be any material known to persons of ordinary skill in the art that can be dissolved, degraded, or disintegrated over an amount of time by a temperature or fluid such as water-based drilling fluids, hydrocarbon-based drilling fluids, or natural gas, and that can be calibrated such that the amount of time necessary for the dissolvable material to dissolve is known or easily determinable without undue experimentation. Suitable dissolvable materials include controlled electrolytic metallic nano-structured materials such as those disclosed in U.S. patent application Ser. No. 12/633,682, filed Dec. 8, 2009 (U.S. Patent Publication No. 2011/0132143), U.S. patent application Ser. No. 12/633,686, filed Dec. 8, 2009 (U.S. Patent Publication No. 2011/0135953), U.S. patent application Ser. No. 12/633,678, filed Dec. 8, 2009 (U.S. Patent Publication No. 2011/0136707), U.S. patent application Ser. No. 12/633,683, filed Dec. 8, 2009 (U.S. Patent Publication No. 2011/0132612), U.S. patent application Ser. No. 12/633,668, filed Dec. 8, 2009 (U.S. Patent Publication No. 2011/0132620), U.S. patent application Ser. No. 12/633,677, filed Dec. 8, 2009 (U.S. Patent Publication No. 2011/0132621), and U.S. patent application Ser. No. 12/633,662, filed Dec. 8, 2009 (U.S. Patent Publication No. 2011/0132619), all of which are hereby incorporated by reference in their entirety. 
     Additional suitable dissolvable materials include polymers and biodegradable polymers, for example, polyvinyl-alcohol based polymers such as the polymer HYDROCENE™ available from Idroplax, S.r.l. located in Altopascia, Italy, polylactide (“PLA”) polymer 4060D from Nature-Works™, a division of Cargill Dow LLC; TLF-6267 polyglycolic acid (“PGA”) from DuPont Specialty Chemicals; polycaprolactams and mixtures of PLA and PGA; solid acids, such as sulfamic acid, trichloroacetic acid, and citric acid, held together with a wax or other suitable binder material; polyethylene homopolymers and paraffin waxes; polyalkylene oxides, such as polyethylene oxides, and polyalkylene glycols, such as polyethylene glycols. These polymers may be preferred in water-based drilling fluids because they are slowly soluble in water. 
     In calibrating the rate of dissolution of dissolvable material, generally the rate is dependent on the molecular weight of the polymers. Acceptable dissolution rates can be achieved with a molecular weight range of 100,000 to 7,000,000. Thus, dissolution rates for a temperature range of 50° C. to 250° C. can be designed with the appropriate molecular weight or mixture of molecular weights. 
     Referring now to  FIGS. 5-6 , in an alternative embodiment, plug element  180  comprises an initial shape ( FIG. 5 ) that is capable of landing on seat  75  to restrict fluid flow through seat  75 , and a new or second shape ( FIG. 6 ) that is sufficient to act as a wiper member as it passes through seat  75  and/or through the bore of valve  40  and/or the bore of inner shifting sleeve  50  upon partial or complete dissolution of the dissolvable material  181  of plug element  180 . In this embodiment, plug element  180  includes wiper member  190  encapsulated by dissolvable material  181 . Wiper member  190  can be formed out of a material  191  that can be a non-dissolvable material or a second dissolvable material that dissolves at a slower rate compared to dissolvable material  181 . Upon sufficient dissolution of dissolvable material  181 , wiper member  190  is capable of being pushed through seat  75  and/or through the bore of valve  40  and/or the bore of inner shifting sleeve  50 . In so doing, wiper member  190  wipes or cleans away debris disposed along these surfaces. Thus, a mechanical clean-out of the valve can be performed after the pressure test without additional wellbore intervention. 
     As discussed above, plug elements  80 ,  180  can be formed completely out of one or more dissolvable materials or plug elements  80 ,  180  can be formed partially out of one or more dissolvable materials. In the former embodiment, plug elements  80 ,  180  will completely dissolve and fluid flow through valve  40  in the wellbore environment will be increased. In the latter embodiment, upon dissolution, plug elements  80 ,  180  can have a new or second shape that is different from the initial shape of plug element  80  that provided restriction of fluid flow through seat  75 . The new shape of plug element  80  can either fall through valve  40  as debris, or it can facilitate wiping or cleaning of the bore of valve  40  by the remaining portion(s) of plug elements  80 ,  180 . Thus, plug elements  80 ,  180  can remove debris disposed within the valve bore as fluid communication between the wellbore casing and the wellbore environment is increased. In these embodiments, both increase of fluid communication between the wellbore casing and the wellbore environment after removal of plug elements  80 ,  180 , and mechanical clean-out of the valve bore, occur without further wellbore intervention. 
     It is to be understood that the invention is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. For example, the wiper member can have any shape desired or necessary to pass through the valve to remove debris disposed within the bore of the valve and/or inner shifting sleeve. In addition, the wiper can be formed out of a non-dissolvable material or another dissolvable material. Moreover, the valve is not required to have the structures disclosed herein, nor is the valve required to operate as disclosed herein. Further, the ball seats disclosed herein can be modified as desired or necessary to restrict fluid flow through the wellbore casing. Additionally, dissolvable materials not disclosed herein can be used in place of those that are disclosed herein. Accordingly, the invention is therefore to be limited only by the scope of the appended claims.