Downhole tool with exposable and openable flow-back vents

[0001] This is related to U.S. patent application Ser. No. 11/800,448, filed May 3, 2007; which is hereby incorporated by reference.

[0002] This is related to U.S. Provisional Patent Application Ser. No. 61/089,302, filed Aug. 15, 2008; which is hereby incorporated by reference.

[0003] This is related to U.S. patent application Ser. No. 12/253,337, filed Oct. 17, 2008, entitled “Combination Anvil and Coupling for Bridge and Fracture Plugs”; which is hereby incorporated by reference.

[0004] 1. Field of the Invention

[0005] The present invention relates generally to well completion devices and methods for completing wells, such as natural gas and oil wells. More particularly, this invention relates to a well completion plug, method and/or kit, that includes flow-back vents.

[0006] 2. Related Art

[0007] Just prior to beginning production, oil and natural gas wells are completed using a complex process called “fracturing.” This process involves securing the steel casing pipe in place in the well bore with cement. The steel and cement barrier is then perforated with shaped explosive charges. The surrounding oil or gas reservoir is stimulated or “fractured” in order to start the flow of gas and oil into the well casing and up to the well head. This fracturing process can be repeated several times in a given well depending on various geological factors of the well, such as the depth of the well, size and active levels in the reservoir, reservoir pressure, and the like. Because of these factors, some wells may be fractured at only a few elevations along the well bore and others may be fractured at as many as 30 or more elevations.

[0008] As the well is prepared for fracturing at each desired level or zone of the well, a temporary plug is set in the bore of the steel well casing pipe just below the level where the fracturing will perforate the steel and cement barrier. When the barrier is perforated, “frac fluids” and sand are pumped down to the perforations, and into the reservoir. At least a portion of the fluids and sand are then drawn back out of the reservoir in order to stimulate movement of the gas or oil at the perforation level. Use of the temporary plug prevents contaminating the already fractured levels below.

[0009] This process is repeated several times, as the “frac” operation moves up the well bore until all the desired levels have been stimulated. At each level, the temporary plugs are usually left in place, so that they can all be drilled out at the end of the process, in a single, but often time-consuming drilling operation. One reason the drilling operation has been time intensive is that the temporary plugs have been made of cast iron which has generally required many hours and, occasionally, several passes of the drilling apparatus to completely drill out the plug. To reduce the drill out time, another type of down hole plug has been developed that is made of a composite material. Composite plugs are usually made of, or partially made of, a fiber and resin mixture, such as fiberglass and high performance plastics. Due to the nature of the composite material, composite plugs can be easily and quickly drilled out of a well bore in a single pass drilling operation. Alternatively, it has been proposed to combust or burn the plug or a portion thereof in order to eliminate its obstruction in the well casing.

[0010] Temporary well plugs used in the fracturing operation described above, whether made of cast iron or composite materials, often come in two varieties, bridge plugs and frac plugs. Bridge plugs restrict fluid movement in the upward and downward direction. Bridge plugs are used to temporarily or permanently seal off a level of the well bore. Frac plugs generally behave as one-way valves that restrict fluid movement down the well bore, but allow fluid movement up the well bore.

[0011] In use, when frac fluids and sand are pumped down to a newly perforated level of the well bore, a frac plug set in the well bore just below the perforation level can restrict the frac fluids and sand from traveling farther down the well bore and contaminating lower fractured levels. However, when the frac fluid and sand mixture is pumped back up the well to stimulate the reservoir at the newly fractured level, the one-way valve of the frac plug can open and allow gas and oil from lower levels to be pumped to the well head. This is advantageous to the well owner because it provides immediate revenue even while the well is still being completed. This upward flow can also assist in drilling out the plugs.

[0012] The improvement of well completion methods and devices is an ongoing endeavor. It has been recognized that it would be advantageous to develop a plug with back flow vents that are concealed or protected during setting of the plug to avoid contamination, damage and/or fouling of vents; but that are openable subsequent to setting of the plug. In addition, it has been recognized that it would be advantageous to develop a plug that is combustible and better suited for use with a burn device that causes combustion of some or all of the plug components.

[0013] The invention provides a down hole flow control device for use in a well bore, such as a bridge plug or a frac plug. The device includes one or more back-flow vent holes disposed radially in a central mandrel and extending radially from a hollow of the central mandrel to an exterior of the mandrel. One or more members can be disposed on the mandrel, such as packers, slips, cones, etc. One or more of the members can cover the vent holes in an initial, unset configuration. In the initial, set configuration, the vent holes remain covered. In both the frac and bridge plug configurations, when the pressure above exceeds the pressure from below the mandrel strokes downward. In a subsequent, set configuration, the members can compress and the mandrel can stroke downwardly with respect to the members exposing the vent holes, allowing back flow of well fluids. In the case of a bridge plug, if the pressure from below exceeds the pressure above, the mandrel can stroke upward and the vent holes become covered.

[0014] In one aspect of the present invention, the device includes a central mandrel sized and shaped to fit within a well bore and including a hollow therein. At least one member is disposed on the central mandrel and movable with respect to the central mandrel along a longitudinal axis of the central mandrel. The at least one member includes a packer ring compressible along the longitudinal axis of the central mandrel to form a seal between the central mandrel and the well bore. At least one back-flow vent hole is disposed radially in the central mandrel and extends radially from the hollow of the central mandrel to an exterior of the central mandrel. The at least one member is disposed over the at least one back-flow vent hole in an initial, unset configuration of the device, and disposed away from the at least one back-flow vent hole in a subsequent, set configuration of the device.

[0025] Reference will now be made to the exemplary embodiments illustrated, and specific language will be used herein to describe the same. It will nevertheless be understood that no limitation of the scope of the invention is thereby intended.

[0026] Reference will now be made to the exemplary embodiments illustrated in the drawings, and specific language will be used herein to describe the same. It will nevertheless be understood that no limitation of the scope of the invention is thereby intended. Alterations and further modifications of the inventive features illustrated herein, and additional applications of the principles of the inventions as illustrated herein, which would occur to one skilled in the relevant art and having possession of this disclosure, are to be considered within the scope of the invention.

[0027] As illustrated in FIGS. 1a-4, a remotely deployable, disposable, consumable down hole flow control device, indicated generally at 10, in accordance with an embodiment of the present invention is shown for use in a well bore as a down hole tool or plug. The down hole flow control device 10 can be remotely deployable at the surface of a well and can be disposable so as to eliminate the need to retrieve the device. One way the down hole flow control device 10 can be disposed is by drilling or machining the device out of the well bore after deployment. Another way the down hole flow control device 10 can be disposed is by combusting or burning all or some of the components thereof using a burn device. Thus, the down hole flow control device 10 can be used as a down hole tool such as a frac plug, indicated generally at 6 and shown in FIGS. 3 and 4, a bridge plug, indicated generally at 8 and shown in FIGS. 1a-d, a cement retainer (not shown), well packer (not shown), a kill plug (not shown), and the like in a well bore as used in a gas or oil well. The down hole flow control device 10 includes a central mandrel 20 with a hollow 24 that can extend axially, or along a longitudinal axis of the mandrel, throughout a length of the device to form a flow path for well fluids depending on the use of the device, such as when configured as a frac plug 6. Alternatively, the hollow 24 may not extend the length of the mandrel 20.

[0028] A burn device 12 can be attached to, or operatively associated with, the down hole flow control device 10 to selectively cause the device or various components to burn and fall down the well bore to the “rat hole.” The burn device can include fuel, oxygen, an igniter and a control or activation system that allow the burn device to combust the flow control device 10. The burn device 12 can be attached to a bottom of the mandrel 20, and can be inserted into the hollow 24 or otherwise cover a bottom of the hollow. The down hole flow control device 10 can include back-flow vents, such as back-flow vent holes 4, to allow the flow of well fluids around the burn device, through the vent holes 4, through the hollow 24, and up the well bore. It will be appreciated that such holes can become damaged or clogged during positioning and setting of the device 10. Therefore, in one aspect of the present invention, the back-flow vent holes 4 can be covered while positioning and setting of the device to protect the holes, and subsequently uncovered for use, as described more fully below. One or more members can be disposable on the mandrel 20 to cover the vent holes 4 before the device is set, and movable to expose the vent holes 4 after it is set.

[0029] The central mandrel 20 can be sized and shaped to fit within a well bore, tube or casing for an oil or gas well. The central mandrel 20 can have a cylindrical body 22 with a hollow 24 or hollow center that can be open on a proximal end 26. The body 22 can be sized and shaped to fit within a well bore and have a predetermined clearance distance from the well bore wall or casing. The central mandrel 20 can also have a cylindrical anvil or bottom stop 28 on a distal end 30. The anvil or bottom stop 28 can be sized and shaped to fit within the well bore and substantially fill the cross sectional area of the well bore. In one aspect, the diameter of the anvil or bottom stop 28 can be smaller than the diameter of the well bore or casing such that well fluids can flow around the bottom stop between the bottom stop and well casing.

[0030] The proximal end 26 can be angled with respect to the longitudinal axis, indicated by a dashed line at 32, of the central mandrel (as shown in FIG. 3) or can have teeth or lugs so as to accommodate placement in the well bore adjacent other down hole tools or flow control devices or burn devices. The angle of the end 26 can correspond and match with an angled end or mate with teeth or lugs of the adjacent down hole tool or flow control device or burn device so as to rotationally secure the two devices together, thereby restricting rotation of any one device in the well bore with respect to other devices in the well bore.

[0031] The central mandrel 20 can be formed of a material that is easily drilled or machined, such as cast iron, fiber and resin composite, and the like. In the case where the central mandrel 20 is made of a composite material, the fiber can be rotationally wound in plies having predetermined ply angles with respect to one another and the resin can have polymeric properties suitable for extreme environments, as known in the art. In one aspect, the composite article can include an epoxy resin with a curing agent. Additionally, other types of resin devices, such as bismaleimide, phenolic, thermoplastic, and the like can be used. The fibers can be E-type and ECR type glass fibers as well as carbon fibers. It will be appreciated that other types of mineral fibers, such as silica, basalt, and the like, can be used for high temperature applications. Alternatively, the mandrel 20 can be formed of material that is combustible, such as magnesium, aluminum or the like.

[0032] One or more members are disposed on the central mandrel 20 and movable with respect to the central mandrel along a longitudinal axis 32 of the central mandrel. The members can include at least one packer ring (or a set of packer rings) that are compressible along the axis and expandable radially to form a seal between the mandrel and the well bore; at least one fracturable slip ring (or a pair of slip rings) to fracture and displace radially to secure the plug in the well bore; at least one cone (or a pair of cones) to slid between the slip ring and the mandrel to cause the slip ring to fracture and displace radially; etc.

[0033] A compressible packer ring 40 can be disposed on the mandrel 20 or cylindrical body 22 (FIG. 2a) of the central mandrel 20. The packer ring 40 can have an outer diameter just slightly smaller than the diameter of the well bore and can correspond in size with the anvil or bottom stop 28 of the central mandrel. The packer ring 40 can be compressible along the longitudinal axis 32 of the central mandrel 20 and radially expandable in order to form a seal between the central mandrel 20 and the well bore. The packer ring 40 can be formed of an elastomeric polymer that can conform to the shape of the well bore or casing and the central mandrel 20.

[0034] In one aspect, the packer ring 40 can be formed of three rings, including a central ring 42 and two outer rings 44 and 46 on either side of the central ring. In this case, each of the three rings 42, 44, and 46 can be formed of an elastomeric material having different physical properties from one another, such as durometer, glass transition temperatures, melting points, and elastic modulii, from the other rings. In this way, each of the rings forming the packer ring 40 can withstand different environmental conditions, such as temperature or pressure, so as to maintain the seal between the well bore or casing over a wide variety of environmental conditions.

[0035] An upper slip ring 60 and a lower slip ring 80 can also be disposed on the central mandrel 20 with the upper slip ring 60 disposed above the packer ring 40 and the lower slip ring 80 disposed below the packer ring 40. Each of the upper and lower slip rings 60 and 80 can include a plurality of slip segments 62 and 82, respectively, that can be joined together by fracture regions 64 and 84 respectively, to form the rings 62 and 82. The fracture regions 64 and 84 can facilitate longitudinal fractures to break the slip rings 60 and 80 into the plurality of slip segments 62 and 82. Each of the plurality of slip segments can be configured to be displaceable radially to secure the down hole flow control device 10 in the well bore.

[0036] The upper and lower slip rings 60 and 80 can have a plurality of raised ridges 66 and 86, respectively, that extend circumferentially around the outer diameter of each of the rings. The ridges 66 and 86 can be sized and shaped to bite into the well bore wall or casing. Thus, when an outward radial force is exerted on the slip rings 60 and 80, the fracture regions 64 and 84 can break the slip rings into the separable slip segments 62 and 82 that can bite into the well bore or casing wall and wedge between the down hole flow control device and the well bore. In this way, the upper and lower slip segments 62 and 82 can secure or anchor the down hole flow control device 10 in a desired location in the well bore.

[0037] The upper and lower slip rings 60 and 80 can be formed of a material that is easily drilled or machined so as to facilitate easy removal of the down hole flow control device from a well bore. For example, the upper and lower slip rings 60 and 80 can be formed of a cast iron or composite material. Additionally, the fracture regions 64 and 84 can be formed by stress concentrators, stress risers, material flaws, notches, slots, variations in material properties, and the like, that can produce a weaker region in the slip ring.

[0038] In one aspect, the upper and lower slip rings 60 and 80 can be formed of a composite material including fiber windings, fiber mats, chopped fibers, or the like, and a resin material. In this case, the fracture regions can be formed by a disruption in the fiber matrix, or introduction of gaps in the fiber matrix at predetermined locations around the ring. In this way, the material difference in the composite article can form the fracture region that results in longitudinal fractures of the ring at the locations of the fracture regions.

[0039] In another aspect, the upper and lower slip rings 60 and 80 can be formed of a cast material such as cast iron. The cast iron can be machined at desired locations around the slip ring to produce materially thinner regions such as notches or longitudinal slots 70 and 90 in the slip ring that will fracture under an applied load. In this way, the thinner regions in the cast iron ring can form the fracture region that results in longitudinal fractures of the ring at the locations of the fracture regions. In another aspect, the upper and lower slip rings 60 and 80 can be formed of a material that is combustible.

[0040] In yet another aspect, the upper and lower slip rings 60 and 80 can also have different fracture regions 64 and 84 from one another. For example, the fracture regions 64 and 84 can include longitudinal slots spaced circumferentially around the ring, the longitudinal slots 90 of the lower slip ring 80 can be larger than the slots 70 of the upper slip ring 60. Thus, the fracture regions 84 of the lower slip ring 80 can include less material than the fracture regions 64 of the upper slip ring 60. In this way, the lower slip ring 80 can be designed to fracture before the upper slip ring 60 so as to induce sequential fracturing with respect to the upper and lower slip rings 60 and 80 when an axial load is applied to both the upper slip ring and the lower slip ring.

[0041] It will be appreciated that compression of the packer ring 40 can occur when the distance between the upper and lower slip rings 60 and 80 is decreased such that the upper and lower slip rings 60 and 80 squeeze or compress the packer ring 40 between them. Thus, if the slip rings fracture under the same load, or at the same approximate time during the compression operation, the distance between the two rings 60 and 80 may not be small enough to have sufficiently compressed the packer ring 40 so as to form an adequate seal between the central mandrel 20 and the well bore or casing wall. In contrast, the sequential fracturing mechanism of the down hole flow control device 10 described above advantageously allows the lower slip ring 80 to set first, while the upper slip ring 60 can continue to move longitudinally along the central mandrel 20 until the upper slip ring 60 compresses the packer ring 40 against the lower slip ring 80. In this way, the lower slip ring 80 sets and anchors the tool to the well bore or casing wall and the upper ring 60 can be pushed downward toward the lower ring 80, thereby squeezing or compressing the packer ring 40 that is sandwiched between the upper and lower slip rings 60 and 80.

[0042] The down hole flow control device 10 can also include a top stop 190 disposed about the central mandrel 20 adjacent the upper slip ring. The top stop 190 can be secured to the mandrel 20 to resist the mandrel 20 from sliding out of the packer 40 when the mandrel strokes down under pressure from above. Alternatively, the top stop can move along the longitudinal axis of the central mandrel such that the top stop can be pushed downward along the central mandrel to move the upper slip ring 60 toward the lower slip ring 80, thereby inducing the axial load in the upper and lower slip rings and the compressible packer ring 40. In this way, the compressible packer ring 40 can be compressed to form the seal between the well bore all or casing and the central mandrel 20.

[0043] The down hole flow control device 10 can also include an upper cone 100 and a lower cone 110 that can be disposed on the central mandrel 20 adjacent the upper and lower slip rings 60 and 80. Each of the upper and lower cones 100 and 110 can be sized and shaped to fit under the upper and lower slip rings 60 and 80 so as to induce stress into the upper or lower slip ring 60 and 80, respectively. The upper and lower cones 100 and 110 can induce stress into the upper or lower slip rings 60 and 80 by redirecting the axial load pushing the upper and lower slip rings together against the anvil 28 and the packer ring 40 to a radial load that can push radially outward from under the upper and lower slip rings. This outward radial loading can cause the upper and lower slip rings 60 and 80 to fracture into slip segments 62 and 82 when the axial load is applied and moves the upper slip ring 60 toward the lower slip ring 80.

[0044] The upper and lower cones 100 and 110 can be formed from a material that is easily drilled or machined such as cast iron or a composite material. In one aspect the upper and lower cones 100 and 110 can be fabricated from a fiber and resin composite material with fiber windings, fiber mats, or chopped fibers infused with a resin material. Advantageously, the composite material can be easily drilled or machined so as to facilitate removal of the down hole flow control device 10 from a well bore after the slip segments have engaged the well bore wall or casing. Alternatively, the upper and lower cones 100 and 110 can be formed of a combustible material, such as magnesium or aluminum or the like.

[0045] The upper and lower cones 100 and 110 can also include a plurality of stress inducers 102 and 112 disposed about the upper and lower cones. The stress inducers 102 and 112 can be pins that can be set into holes in the conical faces of the upper and lower cones 60 and 80, and dispersed around the circumference of the conical faces. The location of the pins around the circumference of the cones can correspond to the location of the fracture regions 64 and 84 (or the slots) of the upper and lower slip rings 60 and 80. In this way, each stress inducer 102 and 112 can be positioned adjacent a corresponding respective fracture region 64 or 84, respectively, in the upper and lower slip rings. Advantageously, the stress inducers 102 and 112 can be sized and shaped to transfer an applied load from the upper or lower cone 100 and 110 to the fracture regions 64 and 84 of the upper or lower slip rings 60 or 80, respectively, in order to cause fracturing of the slip ring at the fracture region and to reduce uneven or unwanted fracturing of the slip rings at locations other than the fracture regions. Additionally, the stress inducers 102 and 112 can help to move the individual slip segments into substantially uniformly spaced circumferential positions around the upper and lower cones 100 and 110, respectively. In this way the stress inducers 102 and 112 can promote fracturing of the upper and lower slip rings 60 and 80 into substantially similarly sized and shaped slip segments 62 and 82.

[0046] The down hole flow control device 10 can also have an upper backing ring 130 and a lower backing ring 150 disposed on the central mandrel 20 between the packer ring 40 and the upper and lower slip rings 60 and 80, respectively. In one aspect, the upper and lower backing rings 130 and 150 can be disposed on the central mandrel 20 between the packer ring 40 and the upper and lower cones 100 and 110, respectively. The upper and lower backing rings 130 and lower 150 can be sized so as to bind and retain opposite ends 44 and 46 of the packer ring 40.

[0047] It will be appreciated that the down hole flow control device 10 described herein can be used with a variety of down hole tools. Thus, as indicated above, FIGS. 3 and 4 show the down hole flow control device 10 used with a frac plug, indicated generally at 6, and FIGS. 1a-d show the down hole flow control device 10 used with a bridge plug, indicated generally at 8. Referring to FIGS. 3 and 4 the down hole flow control device, indicated generally at 10 can secure or anchor the central mandrel 20 to the well bore wall or casing so that a one way check valve 204, such as a ball valve, can allow flow of fluids from below the plug while isolating the zone below the plug from fluids from above the plug. Referring to FIGS. 1a-d, the down hole flow control device, indicated generally at 10, can secure or anchor the central mandrel to the well bore wall or casing so that a solid plug 208 can resist pressure from either above or below the plug in order to isolate the a zone in the well bore. Advantageously, the down hole flow control device 10 described herein can be used for securing other down hole tools such as cement retainers, well packers, and the like.

[0048] As described above, one or more back-flow vent holes 4 can be disposed radially in the central mandrel 20 and extending radially from the hollow 24 of the central mandrel to an exterior of the central mandrel. One or more members, such as the lower slip 80 and/or lower cone 110, can be disposed on the mandrel 20 and disposed over the at least one back-flow vent hole 4 in an initial, unset configuration of the device, as shown in FIGS. 1b and 1d, and disposed away from the at least one back-flow vent hole in a subsequent, set configuration, as shown in FIG. 4. The vent holes 4 can be disposed near a bottom of the mandrel 20, near or adjacent the bottom stop 28. In the initial, unset configuration shown in FIGS. 1b and 1d, the various members, such as the packer 40, slips 60 and 80, cones 100 and 110, etc. can be held uncompressed between the top stop 190 and the bottom stop 28. In the subsequent, set configuration shown in FIG. 3, the various members are compressed between the top stop 190 and the bottom stop 28. Pressure from above the device can cause the mandrel 20 to stroke downwardly such that the various members, compressed between the top and bottom stops, move upwardly with respect to the mandrel 20, exposing the vent holes 4, as shown in FIG. 4. With the vent holes 4 exposed, well fluids, such as oil, gas, etc. can pass through the vent holes 4 and up the hollow 24 as shown by the arrows. As described above, the burn device 12 can be secured to a bottom of the mandrel 20.

[0049] The mandrel 20 can include a bottom bore 212 in which the burn device 12 is secured. For example, the bottom bore 212 can be threaded and the burn device can include a threaded portion so that the burn device can be threaded onto the mandrel. With the device 10 configured as a frac plug 6, and the burn device 12 secured to the bottom bore, the fluid flow passage through the hollow 24 is blocked, and the exposed vent holes 4 allow back flow of well fluids and operation of the device as a frac plug.

[0050] In use, a down hole flow control device is lowered into a well bore. A downward force is applied on the upper slip 60 to compress the upper and lower slip rings and the packer ring so as to break the lower slip ring into slip segments to secure the flow control device to the well bore, to form a seal between the central mandrel and the well bore by compressing the packer ring, and to break the upper slip ring into slip segments to further secure the flow control device to the well bore after the packer ring has been compressed to form the seal. After use, the device can be drilled out or combusted.

[0051] Although the above description and embodiments in the drawings show the plug configured for use with a burn device, it will be appreciated that the plug of the present invention can be used without a burn device.

[0052] While the forgoing examples are illustrative of the principles of the present invention in one or more particular applications, it will be apparent to those of ordinary skill in the art that numerous modifications in form, usage and details of implementation can be made without the exercise of inventive faculty, and without departing from the principles and concepts of the invention. Accordingly, it is not intended that the invention be limited, except as by the claims set forth below.