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BACKGROUND 
       [0001]    In the course of producing oil and gas wells, typically after the well is drilled the well may be completed. In many instances, in order to complete the well the well may be cased. In certain instances the process of installing casing into the wellbore may begin with a wet shoe placed at the lowest section of the casing. The casing may then be run into the wellbore. 
         [0002]    Once the casing is located at the appropriate position in the wellbore cement may be pumped into down the interior of the casing. The cement may both anchor the casing into position as well as isolate the hydrocarbon bearing formation from another section of the same formation or from other formations that are penetrated by the same wellbore. Once the cement reaches the wet shoe the cement flows out of the casing and then into the annular area outside of the casing between the casing and the wellbore. The cement is forced into the annular area generally until the annular area is filled with cement. Once an appropriate amount of cement is pumped into the casing a wiper plug may then be used push the cement out of the casing and to eliminate as much of the remaining cement as possible from the interior of the casing. 
         [0003]    Generally the next step in completing the well, after the cement is allowed to set or cure is to form ports in the casing to allow the fluids from the formation into the interior of the casing. One of the current methods of forming the ports in the casing is known as plug and perforate. Typically, to plug and perforate a casing a perforation assembly consisting of a packer, a setting tool, and a perforation gun are run into the casing together on an electric line. The perforation gun will typically have several sections or perforating charges on the same gun so that the perforation gun may be discharged multiple times, five sections per gun is usual. 
         [0004]    The perforation assembly is lowered into the wellbore until it is located appropriately. Usually the packer will be located below the section of a formation is to be completed. With the packer in place the setting tool is activated to lock the packer into position and to seal the casing below the packer from the wellbore above the packer. The perforation gun and setting tool are then disconnected from the packer and may be moved uphole some distance where the first section of the perforating gun is discharged to form ports in the casing and through the cement to the formation. The perforating gun and setting tool are again moved some distance up the casing and the perforating gun is again activated. The process may be repeated until all of the perforating gun&#39;s sections have been utilized. 
         [0005]    Once the perforating gun&#39;s sections been expended the perforating gun and the setting tool are removed from the casing. The formation may then be fractured and otherwise treated with the packer that was placed into the casing isolating the casing below the packer and allowing only the portion of the formation that was accessed by the perforating gun to be fractured. 
         [0006]    After fracturing the formation a new perforation assembly is run into the casing where the new packer is set above the section previously perforated and the entire process is repeated until the desired number of perforations has been completed and the associated portions of the formations have been fractured and treated. 
         [0007]    Once the process is complete the packers must be removed, typically by milling or drilling out each packer. It is not unusual for there to be ten or more packers that must be removed before the well may be produced. Removing each packer by milling it out takes a substantial amount of rig time incurring substantial cost. 
         [0008]    It is desirable to be able to remove the packers from the casing without milling out each packer. 
       SUMMARY 
       [0009]    In an embodiment of the present invention an erodible packer that seals the wellbore to block flow from above the packer to below the packer. 
         [0010]    A first embodiment may consist of an easily erodible packer containing components that allow the packer to be anchored in place while allowing pressure isolation in one direction. The easily erodible packer may allow flow from below the packer to pass through the packer once the well is put on production. The flow from the formation into the casing and to the surface may carry the packer out of the well as it erodes eventually leading to full bore production from the well. 
         [0011]    A packer deployed in a wellbore comprising a mandrel having an interior throughbore and an exterior. A one way valve may be in the interior throughbore of the mandrel. The one way valve may be closed to prevent fluid from above the valve from passing the one way valve and may be opened to allow fluid from below the valve to pass the one way valve. The packer has a sealing element is attached to the exterior of the mandrel and the packer has an anchor where the anchor fixes the mandrel in place longitudinally. 
         [0012]    The packer&#39;s one way valve may be a flapper valve or it could be a ball and seat type valve. In some instances the mandrel is at least partially an erodible material, a combination of at least the erodible material and a polymer, or even a combination of at least the erodible material and a fiber. The erodible material may be polyglycolic acid or hydrocarbon soluble. 
         [0013]    A downhole assembly may be a packer having a mandrel, a one way valve, a sealing element, and an anchor. The mandrel may have an interior throughbore and an exterior. A one way valve may be in the interior throughbore of the mandrel. The one way valve may be closed to prevent fluid from above the valve from passing the one way valve and may be opened to allow fluid from below the valve to pass the one way valve. A sealing element may be attached to the exterior of the mandrel; and the anchor may fix the mandrel in place longitudinally. The packer&#39;s one way valve may be a flapper valve or it may be a ball and seat type of valve. 
         [0014]    A downhole assembly may be a packer having a mandrel, a sealing element, and an anchor. The mandrel may have an interior throughbore and an exterior. The sealing element may be attached to the exterior of the mandrel. The anchor may fix the mandrel in place longitudinally. The packer may be at least partially constructed of an erodible material. 
         [0015]    The packer may be at least partially a combination of the erodible material and a polymer, a combination of the erodible material and a fiber. In certain instances the fiber may be glass fiber or it may be carbon fiber. While the erodible material may be polyglycolic acid or it may be hydrocarbon soluble. 
         [0016]    A method of completing a well may have the steps of pumping a bottom hole assembly into a well, setting a packer, perforating the well, pumping in at least a second bottomhole assembly, setting the second packer, and producing the well. The packer may have a mandrel having a throughbore and a one way valve may be located in the throughbore. The second packer has a second mandrel having a second throughbore with a second one way valve in the second throughbore. 
         [0017]    In many instances the one way valve may be a flapper valve or it may be a ball and seat type of valve. The mandrel may be at least partially an erodible material, a combination of at least the erodible material and a polymer, or a combination of at least the erodible material and a fiber. The erodible material may be polyglycolic acid or it may be hydrocarbon soluble. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0018]      FIG. 1  depicts a previously set packer and perforated casing section and a newly pumped in second bottom hole assembly. 
           [0019]      FIG. 2  depicts an erodible packer with a one way flapper valve. 
           [0020]      FIG. 3  depicts an erodible packer with a one way ball and seat valve. 
           [0021]      FIG. 4  depicts an erodible packer with a one way flapper valve as it erodes in the presence of wellbore fluid. 
       
    
    
     DETAILED DESCRIPTION 
       [0022]    The description that follows includes exemplary apparatus, methods, techniques, and instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details. 
         [0023]      FIG. 1  depicts a completion where a bottom hole assembly  40  has already been pumped into the casing  14  a composite packer  44  has been set and left in position near the bottom of the casing and the casing perforated by a multi-stage perforating gun  46 . As the initial bottom hole assembly  40  was pumped into the casing  14  the fluid in the casing ws pushed ahead of the bottom hole assembly  40  and out of the casing  14  and into the adjacent formation via the wet shoe  16 . A second bottom hole assembly  40  is shown on location in the casing  14  located just above the perforations  52  in the casing  14 . 
         [0024]    A wellbore  10  has been drilled through one or more formation zones  12 . A casing  14  may be run into the wellbore  10 . Typically the casing is assembled on the surface  20  with a wet shoe  16  on the lower end of the casing  14 . The casing  14  and wet shoe  16  are then lowered into the wellbore  10  by the rig  30  until the desired depth is reached. 
         [0025]    Upon reaching the desired depth cement  22  is pumped from the surface  20  through the interior of the casing  14  out of the wet shoe  16  and into the annular area  24  formed between the casing  14  and the wellbore  10 . Once a predetermined amount of cement  22  is pumped in the casing  14  at the surface  20  a wiper plug may be pumped down through the casing to push the entire amount of cement out of the casing  14  and into the annular area  24 . Upon setting or curing the cement  22  may anchor the casing  14  into position as well as longitudinally isolating the various formations  12  or portions of a formation  12  from other formations  12  or portions of formations  12 . 
         [0026]    Typically after the casing has been cemented or the various zones otherwise isolated from one another a bottom hole assembly may be run into the casing  14  on e-line  50 . The bottom hole assembly  40 , typically has a composite plug  42  on the lower end, a setting tool  44  just above the composite plug  42 , and a multi-stage perforating gun  46  just above the setting tool  44 . Once the bottom hole assembly  40  is properly located power is supplied via the e-line  50  to the setting tool  44  to set the composite plug  42  thereby blocking the low of fluid past the composite plug  42  is either direction. 
         [0027]    The setting tool  44  is then disconnected from the composite plug  42  so that the remainder of the bottom hole assembly  40 , the setting tool  44  and the multi-stage perforating gun  46  may be raised to the desired location and power supplied to the first stage of the multi-stage perforating gun  46  so that the first stage may be discharged to form ports  52  through the casing  14 . The multi-stage perforating gun  46  may then be moved some distance and the next stage of the multi-stage perforating gun  46  is discharged. The process may be repeated until all of the stages of the multi-stage perforating gun  46  have been discharged. 
         [0028]    Typically, once all of the stages of the multi-stage perforating gun  46  have been discharged the setting tool  42  and the now discharged multi-stage perforating gun  46  are raised to the surface  20 . A new or rebuilt bottom hole assembly  40  may then be pumped back down through the casing  14 . As the bottom hole assembly  40  is pumped down the casing any fluid in the casing is pushed ahead of the bottom hole assembly  40  and out of the casing  14  through the ports  52  and into the formation  12 . 
         [0029]    Usually upon completion of the perforating and fracturing operations the operator will pull the last multi-stage perforating gun  46  and the setting tool  44  out of the casing  14 . However, the well cannot be produced as in inflow of fluids including hydrocarbons from the formation  12  through ports  52  into the casing  14  and to the surface is blocked by the packers  42  that remain in well and block fluid flow in both directions. The operator will typically run back into the casing with a drill or mill and proceed to drill out each of the individual packers  42  that remain in the well and block fluid flow to the surface. Such an operation takes time and is correspondingly expensive. 
         [0030]      FIG. 2  depicts the packer  42  described above is replaced with an embodiment of the current invention. The bottom hole assembly described above has a packer  100 . The packer  100  has a mandrel  102 . The mandrel  102  has an interior bore  150  extending the length of the mandrel  102 . In the interior bore  150  of the mandrel  102  is a one way valve  160 . The one way valve may be a flapper type valve having a seat  162 , a flapper  164 , and a bias device such as a spring  166 . Typically the spring  166  will bias the flapper  164  in a closed condition so that any fluid from above the one way valve  160  will not be allowed to pass through the interior  150  of the packer  100  once the packer  100  is set. 
         [0031]    At the lower end of the mandrel  100  is an angled mule shoe  104  that may be secured to the mandrel  102  by pins  106 , in some instance the muleshoe  106  may be secured by adhesives or may be manufactured as integral to the mandrel  102 . Just above the muleshoe  106  is a slip  110 . The slip  110  has an angled inner surface  112  that cooperates with the angled exterior surface  114  of the slip wedge  116 . The slip  110  has gripping teeth  120  to bite into or otherwise grip the casing  14 . The gripping teeth  120  may be buttons as shown or may be integral to the slip  110 . The slip  110  may be a frangible solid or it could be made of a multitude of individual segments. Typically just above the slip wedge  116  is a sealing element  122 . The sealing element  122  may be an elastomer or any other material that may be relatively easily deformed. Above the sealing element  122  may be a second slip wedge  124 . The second sip wedge  124  has an angled exterior surface  126  that cooperates with the angled inner surface  130  of the second slip  132 . The second slip  132  has gripping teeth  134  to bite into or otherwise grip the casing  14 . The gripping teeth  134  may be buttons as shown or may be integral to the second slip  132 . The second slip  132  may be a frangible solid or it could be made of a multitude of individual segments. Above the second slip  132  may be a push ring  136 . 
         [0032]    Each of the slip  110 , the slip wedge  116 , the sealing element  122 , the second slip wedge  124 , the second slip, and the push ring  136  are slidably mounted on the mandrel  102 . 
         [0033]    When the packer  100  is in position the setting tool is secured to the mandrel  100  and applies force in the direction of arrow  140  to the push ring  136 . As the push ring  136  is forced downwards along the mandrel  102  each of the slidably mounted components are also moved longitudinally downwards. The second slip  132  is pushed towards the second slip wedge  124  so that the angled exterior surface  126  that cooperates with the angled inner surface  130  of the second slip  132  force the second slip  132  to move radially outwards causing the gripping teeth  134  to bite into the casing  14 . The slip  110  is pushed towards the slip wedge  116  so that the angled exterior surface  114  cooperates with the angled inner surface  112  of the slip  110  to force the slip  110  to move radially outwards causing the gripping teeth  120  to bite into the casing  14 . At the same time as the sealing element  122  is longitudinally compressed it is force to expand radially outwards to seal against both the mandrel  102  and the casing  14  sealing the exterior of the mandrel  102  to fluid flow in either direction. 
         [0034]    While one embodiment of a packer, a double slip type, is depicted the invention may be utilized with any style packer. 
         [0035]      FIG. 3  depicts a packer  200  having ball type one way valve  168 . A ball  170  may land on the seat  172  which may be attached to the mandrel by screws, pins, adhesives, manufactured as integral to the mandrel  102  or otherwise fixed in place in the interior  150  of the mandrel  102  by known means. A pin  174  or other restraining device will trap the ball  170  in the vicinity of the seat when fluid flows from the bottom of the packer  100  towards the top of the packer such as when the packer  100  is being run into the casing  14  or when the well is put on production and fluid flows from the formation through the ports  52  into the casing  14  and to the surface  20 . However when fluid flows from the surface  20  towards the bottom of the casing  14  such as when the formation is being fractured the ball  170  will land on the seat  172  to prevent any flow through the interior  150  of the mandrel  102 . 
         [0036]      FIG. 4  depicts the packer  100  of  FIG. 2  with a one way flapper type valve  160  as it erodes or degrades in the casing  14 . Typically after the formations  12  have been treated or fractured the well may be put on production utilizing a one way valve  160  to allow the formation fluid to flow through the ports  12  into the casing  14 , through the one way valve  160  in packer  100  and then to the surface  20 . While the one way valve  160  allows the well to be put on production quickly many operators prefer the full bore of the interior, diameter  202  of the casing  14  to be utilized when the well is on production in order to maximize fluid flow from the formation  12  to the surface  20 . Previously the operator would have had to mill or drill the packers  100  out of the casing  14  in order to allow full bore, diameter  202 , access to the formation  20 . In the embodiment depicted in  FIG. 4  the packer may be at least partially constructed of an erodible material, such as ployglycolic acid, although any material that is biodegradable, erodes over time, or in the presence of an activating chemical or enzyme, such as a hydrocarbon could be utilized. In certain instances it may be desirable to at least partially construct a packer  100  using a mixture of the erodible material, such as polyglycolic acid, with another material that may not be erodible. For instance, polyglycolic acid could be mixed with polylactic acid or other polymers. Additionally, the erodible material could be utilized as a binder in combination with a fiber such as carbon fiber or glass fiber to create an erodible composite packer. The erodible material may not be utilized to create the entire packer but it could be used to create most portions of the packer depending upon the relative strength of the materials required. When mixed with the appropriate elastomer or polymer the erodible material could be used as the sealing element  122 . An extensive use of erodible material would allow the formation fluid  206  to erode the packer  100  as they pass through the packer  100  forming eddy currents  204  accelerating the erosion of the packer  100  and thereafter carry the pieces of the packer  100  to the surface  20 . 
         [0037]    Bottom, lower, or downward denotes the end of the well or device away from the surface, including movement away from the surface. Top, upwards, raised, or higher denotes the end of the well or the device towards the surface, including movement towards the surface. While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible. 
         [0038]    Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.

Summary:
In order to overcome the need to remove each packer after a plug and perforate operation in order to produce a well it is desirable to utilize an erodible packer that may allow one way flow. An erodible packer may be constructed of a material such as polyglycolic acid as a binder. The same packer may also allow one way flow past the packer, such as flow from the casing below the packer to the casing above the packer. The packer may erode upon the expiration of a predetermined period of time or upon exposure to an activating agent.