Downhole tool with exposable and openable flow-back vents

A down hole flow control tool for use in a well bore, such as a bridge or frac plug, includes back-flow vent holes in a central mandrel and initially covered by a member on the mandrel, such as a lower slip or a lower cone. In a subsequent, set configuration, the member moves away from the vent hole allowing back flow of well fluids.

BACKGROUND

1. Field of the Invention

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.

2. Related Art

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.

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.

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.

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.

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.

SUMMARY OF THE INVENTION

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.

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.

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.

DETAILED DESCRIPTION OF EXAMPLE EMBODIMENT(S)

As illustrated inFIGS. 1a-4, a remotely deployable, disposable, consumable down hole flow control device, indicated generally at10, 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 device10can 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 device10can be disposed is by drilling or machining the device out of the well bore after deployment. Another way the down hole flow control device10can be disposed is by combusting or burning all or some of the components thereof using a burn device. Thus, the down hole flow control device10can be used as a down hole tool such as a frac plug, indicated generally at6and shown inFIGS. 3 and 4, a bridge plug, indicated generally at8and shown inFIGS. 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 device10includes a central mandrel20with a hollow24that 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 plug6. Alternatively, the hollow24may not extend the length of the mandrel20.

A burn device12can be attached to, or operatively associated with, the down hole flow control device10to 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 device10. The burn device12can be attached to a bottom of the mandrel20, and can be inserted into the hollow24or otherwise cover a bottom of the hollow. The down hole flow control device10can include back-flow vents, such as back-flow vent holes4, to allow the flow of well fluids around the burn device, through the vent holes4, through the hollow24, and up the well bore. It will be appreciated that such holes can become damaged or clogged during positioning and setting of the device10. Therefore, in one aspect of the present invention, the back-flow vent holes4can 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 mandrel20to cover the vent holes4before the device is set, and movable to expose the vent holes4after it is set.

The central mandrel20can be sized and shaped to fit within a well bore, tube or casing for an oil or gas well. The central mandrel20can have a cylindrical body22with a hollow24or hollow center that can be open on a proximal end26. The body22can 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 mandrel20can also have a cylindrical anvil or bottom stop28on a distal end30. The anvil or bottom stop28can 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 stop28can 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.

The proximal end26can be angled with respect to the longitudinal axis, indicated by a dashed line at32, of the central mandrel (as shown inFIG. 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 end26can 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.

The central mandrel20can 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 mandrel20is 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 mandrel20can be formed of material that is combustible, such as magnesium, aluminum or the like.

One or more members are disposed on the central mandrel20and movable with respect to the central mandrel along a longitudinal axis32of 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.

A compressible packer ring40can be disposed on the mandrel20or cylindrical body22(FIG. 2a) of the central mandrel20. The packer ring40can have an outer diameter just slightly smaller than the diameter of the well bore and can correspond in size with the anvil or bottom stop28of the central mandrel. The packer ring40can be compressible along the longitudinal axis32of the central mandrel20and radially expandable in order to form a seal between the central mandrel20and the well bore. The packer ring40can be formed of an elastomeric polymer that can conform to the shape of the well bore or casing and the central mandrel20.

In one aspect, the packer ring40can be formed of three rings, including a central ring42and two outer rings44and46on either side of the central ring. In this case, each of the three rings42,44, and46can 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 ring40can 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.

An upper slip ring60and a lower slip ring80can also be disposed on the central mandrel20with the upper slip ring60disposed above the packer ring40and the lower slip ring80disposed below the packer ring40. Each of the upper and lower slip rings60and80can include a plurality of slip segments62and82, respectively, that can be joined together by fracture regions64and84respectively, to form the rings62and82. The fracture regions64and84can facilitate longitudinal fractures to break the slip rings60and80into the plurality of slip segments62and82. Each of the plurality of slip segments can be configured to be displaceable radially to secure the down hole flow control device10in the well bore.

The upper and lower slip rings60and80can have a plurality of raised ridges66and86, respectively, that extend circumferentially around the outer diameter of each of the rings. The ridges66and86can be sized and shaped to bite into the well bore wall or casing. Thus, when an outward radial force is exerted on the slip rings60and80, the fracture regions64and84can break the slip rings into the separable slip segments62and82that 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 segments62and82can secure or anchor the down hole flow control device10in a desired location in the well bore.

The upper and lower slip rings60and80can 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 rings60and80can be formed of a cast iron or composite material. Additionally, the fracture regions64and84can 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.

In one aspect, the upper and lower slip rings60and80can 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.

In another aspect, the upper and lower slip rings60and80can 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 slots70and90in 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 rings60and80can be formed of a material that is combustible.

In yet another aspect, the upper and lower slip rings60and80can also have different fracture regions64and84from one another. For example, the fracture regions64and84can include longitudinal slots spaced circumferentially around the ring, the longitudinal slots90of the lower slip ring80can be larger than the slots70of the upper slip ring60. Thus, the fracture regions84of the lower slip ring80can include less material than the fracture regions64of the upper slip ring60. In this way, the lower slip ring80can be designed to fracture before the upper slip ring60so as to induce sequential fracturing with respect to the upper and lower slip rings60and80when an axial load is applied to both the upper slip ring and the lower slip ring.

It will be appreciated that compression of the packer ring40can occur when the distance between the upper and lower slip rings60and80is decreased such that the upper and lower slip rings60and80squeeze or compress the packer ring40between 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 rings60and80may not be small enough to have sufficiently compressed the packer ring40so as to form an adequate seal between the central mandrel20and the well bore or casing wall. In contrast, the sequential fracturing mechanism of the down hole flow control device10described above advantageously allows the lower slip ring80to set first, while the upper slip ring60can continue to move longitudinally along the central mandrel20until the upper slip ring60compresses the packer ring40against the lower slip ring80. In this way, the lower slip ring80sets and anchors the tool to the well bore or casing wall and the upper ring60can be pushed downward toward the lower ring80, thereby squeezing or compressing the packer ring40that is sandwiched between the upper and lower slip rings60and80.

The down hole flow control device10can also include a top stop190disposed about the central mandrel20adjacent the upper slip ring. The top stop190can be secured to the mandrel20to resist the mandrel20from sliding out of the packer40when 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 ring60toward the lower slip ring80, thereby inducing the axial load in the upper and lower slip rings and the compressible packer ring40. In this way, the compressible packer ring40can be compressed to form the seal between the well bore all or casing and the central mandrel20.

The down hole flow control device10can also include an upper cone100and a lower cone110that can be disposed on the central mandrel20adjacent the upper and lower slip rings60and80. Each of the upper and lower cones100and110can be sized and shaped to fit under the upper and lower slip rings60and80so as to induce stress into the upper or lower slip ring60and80, respectively. The upper and lower cones100and110can induce stress into the upper or lower slip rings60and80by redirecting the axial load pushing the upper and lower slip rings together against the anvil28and the packer ring40to 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 rings60and80to fracture into slip segments62and82when the axial load is applied and moves the upper slip ring60toward the lower slip ring80.

The upper and lower cones100and110can 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 cones100and110can 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 device10from a well bore after the slip segments have engaged the well bore wall or casing. Alternatively, the upper and lower cones100and110can be formed of a combustible material, such as magnesium or aluminum or the like.

The upper and lower cones100and110can also include a plurality of stress inducers102and112disposed about the upper and lower cones. The stress inducers102and112can be pins that can be set into holes in the conical faces of the upper and lower cones60and80, 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 regions64and84(or the slots) of the upper and lower slip rings60and80. In this way, each stress inducer102and112can be positioned adjacent a corresponding respective fracture region64or84, respectively, in the upper and lower slip rings. Advantageously, the stress inducers102and112can be sized and shaped to transfer an applied load from the upper or lower cone100and110to the fracture regions64and84of the upper or lower slip rings60or80, 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 inducers102and112can help to move the individual slip segments into substantially uniformly spaced circumferential positions around the upper and lower cones100and110, respectively. In this way the stress inducers102and112can promote fracturing of the upper and lower slip rings60and80into substantially similarly sized and shaped slip segments62and82.

The down hole flow control device10can also have an upper backing ring130and a lower backing ring150disposed on the central mandrel20between the packer ring40and the upper and lower slip rings60and80, respectively. In one aspect, the upper and lower backing rings130and150can be disposed on the central mandrel20between the packer ring40and the upper and lower cones100and110, respectively. The upper and lower backing rings130and lower150can be sized so as to bind and retain opposite ends44and46of the packer ring40.

It will be appreciated that the down hole flow control device10described herein can be used with a variety of down hole tools. Thus, as indicated above,FIGS. 3 and 4show the down hole flow control device10used with a frac plug, indicated generally at6, andFIGS. 1a-dshow the down hole flow control device10used with a bridge plug, indicated generally at8. Referring toFIGS. 3 and 4the down hole flow control device, indicated generally at10can secure or anchor the central mandrel20to the well bore wall or casing so that a one way check valve204, 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 toFIGS. 1a-d, the down hole flow control device, indicated generally at10, can secure or anchor the central mandrel to the well bore wall or casing so that a solid plug208can 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 device10described herein can be used for securing other down hole tools such as cement retainers, well packers, and the like.

As described above, one or more back-flow vent holes4can be disposed radially in the central mandrel20and extending radially from the hollow24of the central mandrel to an exterior of the central mandrel. One or more members, such as the lower slip80and/or lower cone110, can be disposed on the mandrel20and disposed over the at least one back-flow vent hole4in an initial, unset configuration of the device, as shown inFIGS. 1band1d, and disposed away from the at least one back-flow vent hole in a subsequent, set configuration, as shown inFIG. 4. The vent holes4can be disposed near a bottom of the mandrel20, near or adjacent the bottom stop28. In the initial, unset configuration shown inFIGS. 1band1d, the various members, such as the packer40, slips60and80, cones100and110, etc. can be held uncompressed between the top stop190and the bottom stop28. In the subsequent, set configuration shown inFIG. 3, the various members are compressed between the top stop190and the bottom stop28. Pressure from above the device can cause the mandrel20to stroke downwardly such that the various members, compressed between the top and bottom stops, move upwardly with respect to the mandrel20, exposing the vent holes4, as shown inFIG. 4. With the vent holes4exposed, well fluids, such as oil, gas, etc. can pass through the vent holes4and up the hollow24as shown by the arrows. As described above, the burn device12can be secured to a bottom of the mandrel20.

The mandrel20can include a bottom bore212in which the burn device12is secured. For example, the bottom bore212can be threaded and the burn device can include a threaded portion so that the burn device can be threaded onto the mandrel. With the device10configured as a frac plug6, and the burn device12secured to the bottom bore, the fluid flow passage through the hollow24is blocked, and the exposed vent holes4allow back flow of well fluids and operation of the device as a frac plug.

In use, a down hole flow control device is lowered into a well bore. A downward force is applied on the upper slip60to 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.

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.