BACKGROUND

[oooi] 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's sections have been utilized.

[0005] Once the perforating gun'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.

[ooio] 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.

[ooii] 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'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'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

Figure 1 depicts a previously set packer and perforated casing section and a newly pumped in second bottom hole assembly. Figure 2 depicts an erodible packer with a one way flapper valve.

Figure 3 depicts an erodible packer with a one way ball and seat valve.

Figure 4 depicts an erodible packer with a one way flapper valve as it erodes in the presence of wellbore fluid.

DETAILED DESCRIPTION

[0015] 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.

[0016] Figure 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.

[0017] 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.

[0018] 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 formations12.

[0019] 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.

[0020] 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.

[0021] Typically, once all of the stages of the multi-stage perforating gun 46 have been discharged the setting tool 42 and the now discharged multistage 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. [0022] 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.

[0023] Figure 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.

[0024] 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 1 10. The slip 1 10 has an angled inner surface 1 12 that cooperates with the angled exterior surface 1 14 of the slip wedge 1 16. The slip 1 10 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 1 10. The slip 1 10 may be a frangible solid or it could be made of a multitude of individual segments. Typically just above the slip wedge 1 16 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.

[0025] Each of the slip 1 10, the slip wedge 1 16, the sealing element 122, the second slip wedge 124, the second slip, and the push ring 136 are slidably mounted on the mandrel 102.

[0026] 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 1 10 is pushed towards the slip wedge 1 16 so that the angled exterior surface 1 14 cooperates with the angled inner surface 1 12 of the slip 1 10 to force the slip 1 10 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.

[0027] While one embodiment of a packer, a double slip type, is depicted the invention may be utilized with any style packer.

[0028] Figure 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.

[0029] Figure 4 depicts the packer 100 of Figure 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 Figure 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.

[0030] 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.

[0031] 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.