US20140110112A1 - Erodable Bridge Plug in Fracturing Applications - Google Patents
Erodable Bridge Plug in Fracturing Applications Download PDFInfo
- Publication number
- US20140110112A1 US20140110112A1 US13/659,641 US201213659641A US2014110112A1 US 20140110112 A1 US20140110112 A1 US 20140110112A1 US 201213659641 A US201213659641 A US 201213659641A US 2014110112 A1 US2014110112 A1 US 2014110112A1
- Authority
- US
- United States
- Prior art keywords
- packer
- mandrel
- way valve
- casing
- erodible material
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
- 239000000463 material Substances 0.000 claims abstract description 38
- 229920000954 Polyglycolide Polymers 0.000 claims abstract description 9
- 239000004633 polyglycolic acid Substances 0.000 claims abstract description 9
- 239000012530 fluid Substances 0.000 claims description 24
- 238000007789 sealing Methods 0.000 claims description 18
- 238000000034 method Methods 0.000 claims description 11
- 239000000835 fiber Substances 0.000 claims description 10
- 229930195733 hydrocarbon Natural products 0.000 claims description 9
- 150000002430 hydrocarbons Chemical class 0.000 claims description 9
- 239000004215 Carbon black (E152) Substances 0.000 claims description 8
- 229920000642 polymer Polymers 0.000 claims description 8
- 238000005086 pumping Methods 0.000 claims description 4
- 229920000049 Carbon (fiber) Polymers 0.000 claims description 3
- 239000004917 carbon fiber Substances 0.000 claims description 3
- 239000003365 glass fiber Substances 0.000 claims description 3
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical group C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims description 3
- 230000003213 activating effect Effects 0.000 abstract description 2
- 239000011230 binding agent Substances 0.000 abstract description 2
- 239000003795 chemical substances by application Substances 0.000 abstract 1
- 230000015572 biosynthetic process Effects 0.000 description 26
- 238000005755 formation reaction Methods 0.000 description 26
- 239000004568 cement Substances 0.000 description 15
- 239000002131 composite material Substances 0.000 description 7
- 238000004519 manufacturing process Methods 0.000 description 6
- 238000003801 milling Methods 0.000 description 3
- 238000007792 addition Methods 0.000 description 2
- 239000000853 adhesive Substances 0.000 description 2
- 230000001070 adhesive effect Effects 0.000 description 2
- 229920001971 elastomer Polymers 0.000 description 2
- 239000000806 elastomer Substances 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 239000007787 solid Substances 0.000 description 2
- 102000004190 Enzymes Human genes 0.000 description 1
- 108090000790 Enzymes Proteins 0.000 description 1
- 241001331845 Equus asinus x caballus Species 0.000 description 1
- 239000002253 acid Substances 0.000 description 1
- 230000000903 blocking effect Effects 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 230000003628 erosive effect Effects 0.000 description 1
- 238000002955 isolation Methods 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 229920000747 poly(lactic acid) Polymers 0.000 description 1
- 239000004626 polylactic acid Substances 0.000 description 1
- 230000000452 restraining effect Effects 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
- E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
- E21B33/1293—Packers; Plugs with mechanical slips for hooking into the casing with means for anchoring against downward and upward movement
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/261—Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation
Definitions
- 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.
- 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.
- 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.
- plug and perforate 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.
- the perforation assembly is lowered into the wellbore until it is located appropriately.
- the packer will be located below the section of a formation is to be completed.
- 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.
- 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.
- 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.
- each packer 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.
- an erodible packer that seals the wellbore to block flow from above the packer to below the packer.
- 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.
- 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.
- the packer's one way valve may be a flapper valve or it could be a ball and seat type valve.
- 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.
- 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.
- 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.
- 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.
- the fiber may be glass fiber or it may be carbon fiber.
- the erodible material may be polyglycolic acid or it may be hydrocarbon soluble.
- 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.
- 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.
- FIG. 1 depicts a previously set packer and perforated casing section and a newly pumped in second bottom hole assembly.
- FIG. 2 depicts an erodible packer with a one way flapper valve.
- FIG. 3 depicts an erodible packer with a one way ball and seat valve.
- FIG. 4 depicts an erodible packer with a one way flapper valve as it erodes in the presence of wellbore fluid.
- 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 .
- 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 .
- a wellbore 10 has been drilled through one or more formation zones 12 .
- a casing 14 may be run into the wellbore 10 .
- 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.
- 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 .
- 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 .
- 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 .
- 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 .
- 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.
- 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 .
- 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 .
- 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.
- 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 .
- a slip 110 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.
- 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 .
- 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 .
- the setting tool 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 .
- 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 .
- 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.
- 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 .
- the ball 170 will land on the seat 172 to prevent any flow through the interior 150 of the mandrel 102 .
- 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 .
- 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 .
- 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 .
- 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.
- an activating chemical or enzyme such as a hydrocarbon could be utilized.
- polyglycolic acid could be mixed with polylactic acid or other polymers.
- 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.
- 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 .
- 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.
Abstract
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.
Description
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- It is desirable to be able to remove the packers from the casing without milling out each packer.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
-
FIG. 1 depicts a previously set packer and perforated casing section and a newly pumped in second bottom hole assembly. -
FIG. 2 depicts an erodible packer with a one way flapper valve. -
FIG. 3 depicts an erodible packer with a one way ball and seat valve. -
FIG. 4 depicts an erodible packer with a one way flapper valve as it erodes in the presence of wellbore fluid. - 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.
-
FIG. 1 depicts a completion where a bottom hole assembly 40 has already been pumped into the casing 14 acomposite packer 44 has been set and left in position near the bottom of the casing and the casing perforated by amulti-stage perforating gun 46. As the initial bottom hole assembly 40 was pumped into thecasing 14 the fluid in the casing ws pushed ahead of the bottom hole assembly 40 and out of thecasing 14 and into the adjacent formation via thewet shoe 16. A second bottom hole assembly 40 is shown on location in thecasing 14 located just above theperforations 52 in thecasing 14. - A
wellbore 10 has been drilled through one ormore formation zones 12. Acasing 14 may be run into thewellbore 10. Typically the casing is assembled on thesurface 20 with awet shoe 16 on the lower end of thecasing 14. Thecasing 14 andwet shoe 16 are then lowered into thewellbore 10 by therig 30 until the desired depth is reached. - Upon reaching the desired
depth cement 22 is pumped from thesurface 20 through the interior of thecasing 14 out of thewet shoe 16 and into the annular area 24 formed between thecasing 14 and thewellbore 10. Once a predetermined amount ofcement 22 is pumped in thecasing 14 at the surface 20 a wiper plug may be pumped down through the casing to push the entire amount of cement out of thecasing 14 and into the annular area 24. Upon setting or curing thecement 22 may anchor thecasing 14 into position as well as longitudinally isolating thevarious formations 12 or portions of aformation 12 fromother formations 12 or portions offormations 12. - 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 one-line 50. The bottom hole assembly 40, typically has acomposite plug 42 on the lower end, asetting tool 44 just above thecomposite plug 42, and amulti-stage perforating gun 46 just above thesetting tool 44. Once the bottom hole assembly 40 is properly located power is supplied via the e-line 50 to thesetting tool 44 to set thecomposite plug 42 thereby blocking the low of fluid past thecomposite plug 42 is either direction. - The
setting tool 44 is then disconnected from thecomposite plug 42 so that the remainder of the bottom hole assembly 40, thesetting tool 44 and themulti-stage perforating gun 46 may be raised to the desired location and power supplied to the first stage of themulti-stage perforating gun 46 so that the first stage may be discharged to formports 52 through thecasing 14. Themulti-stage perforating gun 46 may then be moved some distance and the next stage of themulti-stage perforating gun 46 is discharged. The process may be repeated until all of the stages of themulti-stage perforating gun 46 have been discharged. - Typically, once all of the stages of the
multi-stage perforating gun 46 have been discharged thesetting tool 42 and the now discharged multi-stage perforatinggun 46 are raised to thesurface 20. A new or rebuilt bottom hole assembly 40 may then be pumped back down through thecasing 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 thecasing 14 through theports 52 and into theformation 12. - Usually upon completion of the perforating and fracturing operations the operator will pull the last
multi-stage perforating gun 46 and thesetting tool 44 out of thecasing 14. However, the well cannot be produced as in inflow of fluids including hydrocarbons from theformation 12 throughports 52 into thecasing 14 and to the surface is blocked by thepackers 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 theindividual packers 42 that remain in the well and block fluid flow to the surface. Such an operation takes time and is correspondingly expensive. -
FIG. 2 depicts thepacker 42 described above is replaced with an embodiment of the current invention. The bottom hole assembly described above has apacker 100. Thepacker 100 has amandrel 102. Themandrel 102 has aninterior bore 150 extending the length of themandrel 102. In the interior bore 150 of themandrel 102 is a oneway valve 160. The one way valve may be a flapper type valve having aseat 162, aflapper 164, and a bias device such as aspring 166. Typically thespring 166 will bias theflapper 164 in a closed condition so that any fluid from above the oneway valve 160 will not be allowed to pass through theinterior 150 of thepacker 100 once thepacker 100 is set. - At the lower end of the
mandrel 100 is anangled mule shoe 104 that may be secured to themandrel 102 bypins 106, in some instance themuleshoe 106 may be secured by adhesives or may be manufactured as integral to themandrel 102. Just above themuleshoe 106 is aslip 110. Theslip 110 has an angledinner surface 112 that cooperates with theangled exterior surface 114 of theslip wedge 116. Theslip 110 has grippingteeth 120 to bite into or otherwise grip thecasing 14. The grippingteeth 120 may be buttons as shown or may be integral to theslip 110. Theslip 110 may be a frangible solid or it could be made of a multitude of individual segments. Typically just above theslip wedge 116 is a sealingelement 122. The sealingelement 122 may be an elastomer or any other material that may be relatively easily deformed. Above the sealingelement 122 may be asecond slip wedge 124. Thesecond sip wedge 124 has an angledexterior surface 126 that cooperates with the angledinner surface 130 of thesecond slip 132. Thesecond slip 132 has grippingteeth 134 to bite into or otherwise grip thecasing 14. The grippingteeth 134 may be buttons as shown or may be integral to thesecond slip 132. Thesecond slip 132 may be a frangible solid or it could be made of a multitude of individual segments. Above thesecond slip 132 may be apush ring 136. - Each of the
slip 110, theslip wedge 116, the sealingelement 122, thesecond slip wedge 124, the second slip, and thepush ring 136 are slidably mounted on themandrel 102. - When the
packer 100 is in position the setting tool is secured to themandrel 100 and applies force in the direction ofarrow 140 to thepush ring 136. As thepush ring 136 is forced downwards along themandrel 102 each of the slidably mounted components are also moved longitudinally downwards. Thesecond slip 132 is pushed towards thesecond slip wedge 124 so that theangled exterior surface 126 that cooperates with the angledinner surface 130 of thesecond slip 132 force thesecond slip 132 to move radially outwards causing the grippingteeth 134 to bite into thecasing 14. Theslip 110 is pushed towards theslip wedge 116 so that theangled exterior surface 114 cooperates with the angledinner surface 112 of theslip 110 to force theslip 110 to move radially outwards causing the grippingteeth 120 to bite into thecasing 14. At the same time as the sealingelement 122 is longitudinally compressed it is force to expand radially outwards to seal against both themandrel 102 and thecasing 14 sealing the exterior of themandrel 102 to fluid flow in either direction. - While one embodiment of a packer, a double slip type, is depicted the invention may be utilized with any style packer.
-
FIG. 3 depicts apacker 200 having ball type oneway valve 168. Aball 170 may land on theseat 172 which may be attached to the mandrel by screws, pins, adhesives, manufactured as integral to themandrel 102 or otherwise fixed in place in theinterior 150 of themandrel 102 by known means. Apin 174 or other restraining device will trap theball 170 in the vicinity of the seat when fluid flows from the bottom of thepacker 100 towards the top of the packer such as when thepacker 100 is being run into thecasing 14 or when the well is put on production and fluid flows from the formation through theports 52 into thecasing 14 and to thesurface 20. However when fluid flows from thesurface 20 towards the bottom of thecasing 14 such as when the formation is being fractured theball 170 will land on theseat 172 to prevent any flow through theinterior 150 of themandrel 102. -
FIG. 4 depicts thepacker 100 ofFIG. 2 with a one wayflapper type valve 160 as it erodes or degrades in thecasing 14. Typically after theformations 12 have been treated or fractured the well may be put on production utilizing a oneway valve 160 to allow the formation fluid to flow through theports 12 into thecasing 14, through the oneway valve 160 inpacker 100 and then to thesurface 20. While the oneway valve 160 allows the well to be put on production quickly many operators prefer the full bore of the interior,diameter 202 of thecasing 14 to be utilized when the well is on production in order to maximize fluid flow from theformation 12 to thesurface 20. Previously the operator would have had to mill or drill thepackers 100 out of thecasing 14 in order to allow full bore,diameter 202, access to theformation 20. In the embodiment depicted inFIG. 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 apacker 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 sealingelement 122. An extensive use of erodible material would allow theformation fluid 206 to erode thepacker 100 as they pass through thepacker 100 formingeddy currents 204 accelerating the erosion of thepacker 100 and thereafter carry the pieces of thepacker 100 to thesurface 20. - 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.
- 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.
Claims (26)
1. A packer deployed in a wellbore comprising:
a mandrel having an interior throughbore and an exterior;
a one way valve in the interior throughbore of the mandrel;
wherein the one way valve is closed to prevent fluid above the valve from passing the one way valve and is opened to allow fluid from below the valve to pass the one way valve;
a sealing element;
wherein the sealing element is attached to the exterior of the mandrel; and
an anchor;
wherein the anchor fixes the mandrel in place longitudinally.
2. The packer of claim 1 wherein the one way valve is a flapper valve.
3. The packer of claim 1 wherein the one way valve is a ball and seat.
4. The packer of claim 1 wherein the mandrel is at least partially an erodible material.
5. The packer of claim 4 wherein the mandrel is a combination of at least the erodible material and a polymer.
6. The packer of claim 4 wherein the mandrel is a combination of at least the erodible material and a fiber.
7. The packer of claim 4 wherein the erodible material is polyglycolic acid.
8. The packer of claim 4 wherein the erodible material is hydrocarbon soluble.
9. A downhole assembly comprising:
a packer having a mandrel, a one way valve, a sealing element, and an anchor;
wherein the mandrel has an interior throughbore and an exterior;
wherein the one way valve is in the interior throughbore of the mandrel;
further wherein the one way valve is closed to prevent fluid above the valve from passing the one way valve and is opened to allow fluid from below the valve to pass the one way valve;
wherein the a sealing element is attached to the exterior of the mandrel; and
wherein the anchor fixes the mandrel in place longitudinally.
10. The packer of claim 9 wherein the one way valve is a flapper valve.
11. The packer of claim 9 wherein the one way valve is a ball and seat.
12. A downhole assembly comprising:
a packer having a mandrel, a sealing element, and an anchor;
wherein the mandrel has an interior throughbore and an exterior;
wherein the sealing element is attached to the exterior of the mandrel;
wherein the anchor fixes the mandrel in place longitudinally; and
wherein the packer is at least partially an erodible material
13. The packer of claim 12 wherein the packer is at least partially a combination of the erodible material and a polymer.
14. The packer of claim 12 wherein the packer is at least partially a combination of the erodible material and a fiber.
15. The packer of claim 14 wherein the fiber is glass fiber.
16. The packer of claim 14 wherein the fiber is carbon fiber.
17. The packer of claim 12 wherein the erodible material is polyglycolic acid.
18. The packer of claim 12 wherein the erodible material is hydrocarbon soluble.
19. A method of completing a well comprising:
pumping a bottom hole assembly into a well;
setting a packer;
wherein the packer has a mandrel having a throughbore;
further wherein a one way valve is located in the throughbore;
perforating the well
pumping in at least a second bottomhole assembly;
setting the second packer;
wherein the second packer has a second mandrel having a second throughbore with a second one way valve in the second throughbore; and
producing the well.
20. The packer of claim 19 wherein the one way valve is a flapper valve.
21. The packer of claim 19 wherein the one way valve is a ball and seat.
22. The packer of claim 19 wherein the mandrel is at least partially an erodible material.
23. The packer of claim 22 wherein the mandrel is a combination of at least the erodible material and a polymer.
24. The packer of claim 22 wherein the mandrel is a combination of at least the erodible material and a fiber.
25. The packer of claim 22 wherein the erodible material is polyglycolic acid.
26. The packer of claim 22 wherein the erodible material is hydrocarbon soluble.
Priority Applications (3)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/659,641 US20140110112A1 (en) | 2012-10-24 | 2012-10-24 | Erodable Bridge Plug in Fracturing Applications |
PCT/US2013/064467 WO2014066064A1 (en) | 2012-10-24 | 2013-10-11 | Erodable bridge plug in fracturing applications |
CA2887221A CA2887221A1 (en) | 2012-10-24 | 2013-10-11 | Erodable bridge plug in fracturing applications |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/659,641 US20140110112A1 (en) | 2012-10-24 | 2012-10-24 | Erodable Bridge Plug in Fracturing Applications |
Publications (1)
Publication Number | Publication Date |
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US20140110112A1 true US20140110112A1 (en) | 2014-04-24 |
Family
ID=50484290
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US13/659,641 Abandoned US20140110112A1 (en) | 2012-10-24 | 2012-10-24 | Erodable Bridge Plug in Fracturing Applications |
Country Status (3)
Country | Link |
---|---|
US (1) | US20140110112A1 (en) |
CA (1) | CA2887221A1 (en) |
WO (1) | WO2014066064A1 (en) |
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US20150211324A1 (en) * | 2014-01-24 | 2015-07-30 | Baker Hughes Incorporated | Disintegrating Agglomerated Sand Frack Plug |
US20150247376A1 (en) * | 2014-02-28 | 2015-09-03 | Randy C. Tolman | Corrodible Wellbore Plugs and Systems and Methods Including the Same |
USRE46028E1 (en) | 2003-05-15 | 2016-06-14 | Kureha Corporation | Method and apparatus for delayed flow or pressure change in wells |
US9708878B2 (en) | 2003-05-15 | 2017-07-18 | Kureha Corporation | Applications of degradable polymer for delayed mechanical changes in wells |
US10119358B2 (en) | 2014-08-14 | 2018-11-06 | Halliburton Energy Services, Inc. | Degradable wellbore isolation devices with varying degradation rates |
US10240419B2 (en) | 2009-12-08 | 2019-03-26 | Baker Hughes, A Ge Company, Llc | Downhole flow inhibition tool and method of unplugging a seat |
US10301909B2 (en) | 2011-08-17 | 2019-05-28 | Baker Hughes, A Ge Company, Llc | Selectively degradable passage restriction |
US10337274B2 (en) * | 2013-09-03 | 2019-07-02 | Baker Hughes, A Ge Company, Llc | Plug reception assembly and method of reducing restriction in a borehole |
US10364642B1 (en) | 2015-08-19 | 2019-07-30 | Bubbletight, LLC | Degradable downhole tools and components |
US10378303B2 (en) | 2015-03-05 | 2019-08-13 | Baker Hughes, A Ge Company, Llc | Downhole tool and method of forming the same |
US10526868B2 (en) * | 2014-08-14 | 2020-01-07 | Halliburton Energy Services, Inc. | Degradable wellbore isolation devices with varying fabrication methods |
US10697266B2 (en) | 2011-07-22 | 2020-06-30 | Baker Hughes, A Ge Company, Llc | Intermetallic metallic composite, method of manufacture thereof and articles comprising the same |
US10767439B1 (en) | 2015-08-19 | 2020-09-08 | Bubbletight, LLC | Downhole tool having a sealing element constructed from a polyvinyl alcohol compound |
US10876374B2 (en) | 2018-11-16 | 2020-12-29 | Weatherford Technology Holdings, Llc | Degradable plugs |
US11090719B2 (en) | 2011-08-30 | 2021-08-17 | Baker Hughes, A Ge Company, Llc | Aluminum alloy powder metal compact |
US11167343B2 (en) | 2014-02-21 | 2021-11-09 | Terves, Llc | Galvanically-active in situ formed particles for controlled rate dissolving tools |
CN114060004A (en) * | 2021-11-11 | 2022-02-18 | 西南石油大学 | Glass clamping model based on microscopic displacement experiment and experiment method |
US11255151B2 (en) * | 2019-08-23 | 2022-02-22 | Halliburton Energy Services, Inc. | Flapper on frac plug that allows pumping down a new plug |
US11365164B2 (en) | 2014-02-21 | 2022-06-21 | Terves, Llc | Fluid activated disintegrating metal system |
US11649526B2 (en) | 2017-07-27 | 2023-05-16 | Terves, Llc | Degradable metal matrix composite |
US11828131B1 (en) | 2020-03-09 | 2023-11-28 | Workover Solutions, Inc. | Downhole plug with integrated slip cover and expansion element |
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US9708878B2 (en) | 2003-05-15 | 2017-07-18 | Kureha Corporation | Applications of degradable polymer for delayed mechanical changes in wells |
US10280703B2 (en) | 2003-05-15 | 2019-05-07 | Kureha Corporation | Applications of degradable polymer for delayed mechanical changes in wells |
USRE46028E1 (en) | 2003-05-15 | 2016-06-14 | Kureha Corporation | Method and apparatus for delayed flow or pressure change in wells |
US10669797B2 (en) | 2009-12-08 | 2020-06-02 | Baker Hughes, A Ge Company, Llc | Tool configured to dissolve in a selected subsurface environment |
US10240419B2 (en) | 2009-12-08 | 2019-03-26 | Baker Hughes, A Ge Company, Llc | Downhole flow inhibition tool and method of unplugging a seat |
US10697266B2 (en) | 2011-07-22 | 2020-06-30 | Baker Hughes, A Ge Company, Llc | Intermetallic metallic composite, method of manufacture thereof and articles comprising the same |
US10301909B2 (en) | 2011-08-17 | 2019-05-28 | Baker Hughes, A Ge Company, Llc | Selectively degradable passage restriction |
US11090719B2 (en) | 2011-08-30 | 2021-08-17 | Baker Hughes, A Ge Company, Llc | Aluminum alloy powder metal compact |
US10337274B2 (en) * | 2013-09-03 | 2019-07-02 | Baker Hughes, A Ge Company, Llc | Plug reception assembly and method of reducing restriction in a borehole |
US10018010B2 (en) * | 2014-01-24 | 2018-07-10 | Baker Hughes, A Ge Company, Llc | Disintegrating agglomerated sand frack plug |
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US11613952B2 (en) | 2014-02-21 | 2023-03-28 | Terves, Llc | Fluid activated disintegrating metal system |
US11365164B2 (en) | 2014-02-21 | 2022-06-21 | Terves, Llc | Fluid activated disintegrating metal system |
US11167343B2 (en) | 2014-02-21 | 2021-11-09 | Terves, Llc | Galvanically-active in situ formed particles for controlled rate dissolving tools |
US9790762B2 (en) * | 2014-02-28 | 2017-10-17 | Exxonmobil Upstream Research Company | Corrodible wellbore plugs and systems and methods including the same |
US20150247376A1 (en) * | 2014-02-28 | 2015-09-03 | Randy C. Tolman | Corrodible Wellbore Plugs and Systems and Methods Including the Same |
US10526868B2 (en) * | 2014-08-14 | 2020-01-07 | Halliburton Energy Services, Inc. | Degradable wellbore isolation devices with varying fabrication methods |
US10119358B2 (en) | 2014-08-14 | 2018-11-06 | Halliburton Energy Services, Inc. | Degradable wellbore isolation devices with varying degradation rates |
US10378303B2 (en) | 2015-03-05 | 2019-08-13 | Baker Hughes, A Ge Company, Llc | Downhole tool and method of forming the same |
US10767439B1 (en) | 2015-08-19 | 2020-09-08 | Bubbletight, LLC | Downhole tool having a sealing element constructed from a polyvinyl alcohol compound |
US10669808B1 (en) | 2015-08-19 | 2020-06-02 | Bubbletight, LLC | Degradable downhole tools and components |
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US11255151B2 (en) * | 2019-08-23 | 2022-02-22 | Halliburton Energy Services, Inc. | Flapper on frac plug that allows pumping down a new plug |
US11828131B1 (en) | 2020-03-09 | 2023-11-28 | Workover Solutions, Inc. | Downhole plug with integrated slip cover and expansion element |
CN114060004A (en) * | 2021-11-11 | 2022-02-18 | 西南石油大学 | Glass clamping model based on microscopic displacement experiment and experiment method |
Also Published As
Publication number | Publication date |
---|---|
WO2014066064A1 (en) | 2014-05-01 |
CA2887221A1 (en) | 2014-05-01 |
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Legal Events
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AS | Assignment |
Owner name: DOWNHOLE INNOVATIONS LLC, TEXAS Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:JORDAN, HENRY JOE, JR.;REEL/FRAME:031078/0992 Effective date: 20130103 |
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STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |
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AS | Assignment |
Owner name: GR ENERGY SERVICES MANAGEMENT, LP, TEXAS Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:DOWNHOLE INNOVATIONS, LLC;REEL/FRAME:062430/0490 Effective date: 20220810 |