Patent Grant
11859451
Wellbores are commonly drilled using rotary drill bits at the end of a drill string. One common type of drill bit is a fixed cutter drill bit having a plurality of cutters secured at fixed location and cutting orientations to a bit body. Drilling generally requires applying a downward force on the drill bit to engage the cutters with the formation, in combination with rotation of the drill bit to cut the formation. However, contact between the cutting elements and downhole formations generates friction and other forces that can result in prematurely worn or damaged cutting elements and scrapped bits. Therefore, depth-of-cut control (DOCC) elements are sometimes secured to the bit body to limit a depth of cut of the cutters, such as to prevent over-engagement of the cutting elements with the formation.
These drawings illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the method.
Disclosed are depth of cut control (DOCC) assemblies for a drill bit that have moveable DOCC elements to change their exposure and the corresponding engagement of cutters during drilling. Changing the engagement of the DOCC elements may change the bit aggressiveness. For example, it may be desirable to have a less aggressive bit in some applications where there is more need for directional control or that otherwise may entail slower drilling, and then transition to a more aggressive bit by backing off the DOCC elements where more weight on bit is used to drill faster. Rather than moving back and forth between exposure positions, the DOCC elements in at least some embodiments are activated or deactivated once during drilling. This serves various drilling applications for which it is desirable for cutters to have one depth of engagement during part of the drill bit run, and another depth of engagement in a subsequent part of the drill bit run. For example, in forming a multilateral wellbore, DOCC elements may be set with a higher initial exposure (relative to the cutter profile) for curve runs to prevent the bit from over-engaging, but transition to a lower exposure once in the lateral wellbore, so as not limit rate of penetration (ROP). Such one-time activation or de-activation and one-way change in exposure height may reduce costs and increase reliability.
Numerous example embodiments are given that provide one-way movement of DOCC elements from a first exposure position to a second exposure position. The examples discussed primarily use rolling DOCC elements, but non-rolling DOCC elements may also be used. One or more embodiments include a DOCC element rotatably positioned in a retainer pocket along the blade to limit a depth of cut of one of the fixed cutters. A retention member initially retains the DOCC element within the retainer pocket at a first exposure position. The retention member is configured to release the DOCC element downhole to allow one-way movement of the DOCC element to a second exposure position. The retention member may comprise, in some examples, one or more burst discs, pins, shelves, bearing elements, or caps that initially retain the DOCC element in the first exposure position. The retainer elements may be configured to yield, fail, displace, and/or disintegrate, such as by melting, liquifying, dissolving, abrading, or wearing, in response to a threshold force, pressure, or temperature, or contact with a solvent or abrasive fluid, as non-limiting examples. The retainer elements may also comprise a plurality of retainer elements corresponding to different exposure positions so that the DOCC element may successively move from one exposure position to the next during drilling. These and other examples are further understood with respect to the figures discussed below.
The BHA 22 may include the drill bit 40 and any number of other BHA components, schematically depicted at 22a, 22b and 22c, coupled to the drill string 20 above the drill bit 40. The BHA components 22a, 22b and 22c may include, but are not limited to, drill collars, rotary steering tools, directional drilling tools, downhole drilling motors, reamers, hole enlargers, stabilizers etc. The number and types of BHA components 22a, 22b and 22c may depend on anticipated downhole drilling conditions and the type of wellbore 14 that will be formed by drill string 20 and rotary drill bit 40. The BHA 22 may also include various types of well logging tools (not expressly shown) and other downhole tools associated with directional drilling of a wellbore. Examples of logging tools and/or directional drilling tools may include, but are not limited to, acoustic, neutron, gamma ray, density, photoelectric, nuclear magnetic resonance, rotary steering tools and/or any other commercially available well tool. The BHA components 22a, 22b and 22c may also include a downhole motor capable of rotating the drill bit 40 with respect to an upper portion of the drill string 20. The wellbore 14 may be drilled by engaging the drill bit 40 with the formation while rotating the drill bit 40, such as by rotating the entire drill string 20 from the surface and/or by rotating the drill bit 40 with the mud motor.
The wellbore 14 may be defined in part by a casing string 24 that may be cemented in place, extending along at least a portion of the wellbore 14. Portions of the wellbore 14 that do not include casing string 24 may be described as “open hole.” Various types of drilling fluid, or “mud,” may be pumped from the surface 12 through drill string 20. The drilling fluid may be expelled from the drill string 20 through nozzles passing through the drill bit 40. The drilling fluid may be circulated back to surface 12 through an annulus 26 defined between an outside diameter of the drill string 20 and a surrounding structure. Along an open hole portion, the annulus 26 is defined between the drill string 20 and an inside diameter of the wellbore 14a. The inside diameter may be referred to as the sidewall of the wellbore 14a. Along a cased portion, the annulus 26 may be defined between the drill string 20 and an inside diameter of the casing string 24.
The drill bit 40 may rotate with respect to a bit rotational axis 44 in a direction defined by directional arrow 45. As the drill bit 40 is rotated, the cutters, which may include fixed cutters and/or rolling cutters, may engage and cut the formation. As discussed below, a plurality of DOCC elements may be provided on the drill bit 40 to limit the engagement of the cutters. The cutters may cut by scraping, gouging, shearing, or otherwise disintegrating the formations surrounding wellbores 14. The resulting cuttings may be continuously removed by the drilling fluid circulated through the drill string 20 back to the surface 12, where the cuttings may be removed from the drilling fluid by surface equipment.
The drill bit 100 may be categorized as a fixed cutter drill bit, in that its cutting structure comprises a plurality of cutters 116 secured at fixed cutting orientations to drill into the earthen formation under an applied weight-on-bit (WOB). The plurality of fixed cutters 116 may be secured to the blades 104 within corresponding cutter pockets sized and shaped to receive the fixed cutters 116. Each cutter 116, in this example, comprises a fixed cutter secured within its corresponding cutter pocket via brazing, threading, shrink-fitting, press-fitting, snap rings, or any combination thereof. The fixed cutting orientation at which the fixed cutters 116 are held in blades 104 and respective cutter pockets may comprise predetermined angular orientations and radial locations, and may present the fixed cutters 116 with a desired back rake angle against the formation being drilled. As the drill bit 100 is rotated on the drill string about the bit axis 107, the fixed cutters 116 sweep three dimensional (3D) cutting profiles. During drilling, the fixed cutters 116 are driven through the rock by the combined forces of the weight-on-bit and the torque applied to the drill bit 100. During drilling, the fixed cutters 116 may experience a variety of forces, such as drag forces, axial forces, reactive moment forces, or the like, due to the interaction with the underlying formation being drilled as drill bit 100 rotates.
Each fixed cutter 116 may include a generally cylindrical substrate made of a hard material, such as tungsten carbide (WC), and a cutting element secured to the substrate. The working surface of the cutting element is typically flat or planar, but may also exhibit a curved or otherwise non-planar exposed surface that defines a cutting edge oriented for cutting into an earthen formation. The cutting element may include one or more layers of an ultra-hard material, such as polycrystalline diamond (PCD), polycrystalline cubic boron nitride, impregnated diamond, etc., which generally forms a cutting edge and the working surface for each fixed cutter 116. In some cases, a PCD cutting element may be formed and bonded together with the substrate in a high-temperature, high-pressure press cycle, with the resulting cutter referred to as a polycrystalline diamond compact (PDC). When using polycrystalline diamond as the ultra-hard material, fixed cutter 116 may be referred to as a polycrystalline diamond compact cutter or PDC cutter, and drill bits made using such PDC fixed cutters 116 are generally known as PDC bits.
The drill bit 100 also has rolling element assemblies 118a, 118b secured to the bit body 102. The orientation of a rolling element in each rolling element assembly 118a, 118b determines, at least in part, whether the rolling element operates as a cutter, a rolling depth of cut control (DOCC) element, or a hybrid of both. In this example the rolling cutter assemblies 118a are configured as rolling cutters and the rolling cutter assemblies 118b are configured as rolling depth of cut controllers (rolling DOCC). The rolling cutters 118a include rolling elements that, like the fixed cutters 116, have cutting edges oriented for cutting into an earthen formation while drilling. In the design of the drill bit 100, the desired back rake and side rake angles may be selected and otherwise optimized with respect to fixed cutters 116 and/or rolling cutters 118a. The rolling depth of cut controllers 118b include rolling DOCC elements positioned to instead roll against the formation, limiting a depth of cut of one or more of the fixed cutters 116 and/or rolling cutters 118a. Rolling DOCC elements may prove advantageous in allowing for additional weight-on-bit to enhance directional drilling applications without over engagement of the fixed cutters 116. Effective depth of cut control also limits fluctuations in torque and minimizes stick-slip, which can cause damage to fixed cutters 116.
At least some of the rolling element assemblies 118a, 118b have rolling elements whose exposure positions (e.g., exposure height of a rolling element relative to the cutting profiles of adjacent cutters whose depth is limited thereby) may change during drilling, which may change how aggressively the drill bit 100 drills. Those rolling elements are initially retained at a first exposure position, such as while drilling a first portion of the wellbore, and then released downhole to allow movement of the DOCC element to a second exposure position. The movement from the first exposure position to the second exposure position may be one-way, so that at some point during drilling the drill bit may become more aggressive or the drill bit may become less aggressive. For example, the DOCC elements may initially be set with a higher exposure (i.e., greater engagement) for curve applications to prevent the cutters from over-engaging, but transition to a lower exposure in a lateral wellbore so as not limit rate of penetration (ROP).
Several example configurations are discussed below and conceptually illustrated in subsequent figures that enable this one-way movement from a first exposure position to a second exposure position. In some examples, the DOCC elements move inwardly to achieve a one-time deactivation, thereby providing a less aggressive, shallower initial depth of cut that subsequently increases for more aggressive drilling. In other examples, the DOCC elements may instead be configured to move outwardly for a one-time activation during drilling, thereby providing a more aggressive drilling initially, followed by a shallower depth of cut later in the drilling.
Each rolling element 122 has a rotational axis A, a Z-axis that is perpendicular to the blade profile, and a Y-axis that is orthogonal to both the rotational and Z-axes. As shown, the exposed portion of each rolling element 122 may be constant with respect to the position along the rotational axis A of the rolling element, in either the DOCC or the cutter orientation.
A rolling element may be considered a rolling cutter or a rolling DOCC element depending on its position and orientation. If, for example, the rotational axis A of a rolling element 122 is substantially parallel to a tangent to outer surface 119 of the blade profile, that rolling element assembly 118b may generally operate as a rolling DOCC element. For example, if the rotational axis A of the rolling element 122 passes through or lies on a plane that passes through the longitudinal bit axis 107 (
Another design consideration is the placement of the rolling element assemblies 118a, 118b relative to the fixed cutters 116. In this example, the fixed cutters 116 form part of a primary cutting structure 115, and the rolling cutter 118a is positioned on the blade 104 as a backup or secondary cutter to the fixed cutter 116a most directly ahead of the rolling cutter 118, towards the leading face 106 of the same blade 104. Although not required, the rolling cutter 118a may be positioned directly behind the primary cutter 116a. Alternatively, the rolling cutter 118a may be staggered laterally (in the Y direction) with respect to that primary cutter 116a so their respective cutting profiles only partially overlap. As another example, the placement of the rolling cutter 118a on the blade 104 may instead be selected relative to the cutter on another blade (not shown), such as to align the path of the rolling cutter 118a behind the path of the cutter on the other blade as they rotate about the bit axis.
Placement of the rolling DOCC 118b may be selected to limit the depth of cut of one or more of the fixed cutters 116. Typically, the rolling DOCC 118b would limit the depth of cut of an adjacent or nearest fixed cutter, and typically (although not necessarily) on the same blade 104. Although the rolling DOCC 118b could at least indirectly affect the depth of cut of other cutters, other fixed or rolling DOCCs could be positioned nearer to such other cutters to more directly affect their respective depth of cut. In this example, the rolling DOCC 118b is placed to limit the depth of cut of the fixed cutter 116b most directly ahead of the rolling DOCC 118b.
The following
The retainer pocket 127 could alternatively be defined by the blade 104 itself, without including a distinct or structurally separate housing. The burst disc 132 is incorporated into the retainer housing 124, beneath the rolling element 122. This creates a gap between the burst disc 132 and the floor 126 of the retainer pocket 127. The burst disc 132 is rated to rupture (i.e., burst) at a specified loading, such as if the weight on bit loading (FWOB) reaches a threshold.
The rolling element 122 limits depth of cut of a fixed cutter 116 in the first exposure position illustrated in
This movement of the rolling element 122 from the first exposure position to the second exposure position upon bursting of the burst disc 132 is considered one-way, in that the rolling element 122 is not biased back toward the first exposure position while drilling. For so long as FWOB is applied, the rolling element 122 may remain at the floor 126 of the retainer housing 124. If FWOB is released such as with WOB removed, it may be possible for the rolling element 122 to have some vertical play in the retainer cavity 127, such as to wobble or move back up toward the first exposure position. However, some sort of intervention would be required, such as to restore or replace the burst disc with another burst disc or some other retention member, to retain the rolling element 122 back in the first exposure position.
The burst discs may be selected to have the desired burst rating for each. The burst ratings may be the same or different. In one example, each burst disc has the same burst rating, but fails at different (e.g., progressively larger) loading FWOB due to the increased engagement of the fixed cutter 116 (and associated WOB required) at the successive exposure positions of the rolling element 122. In another example, the burst ratings of the burst discs 132A, 132B, 132C may be progressively larger.
Each movement of the rolling element 122 from one exposure position to the next upon bursting of the respective burst disc may be one-way. For example, the rolling element 122 changes exposure position upon bursting of the first burst disc 132A, again upon bursting of the second burst disc 132B, and again upon bursting of the third burst disc 132C. After each change in exposure position, the rolling element 122 is not biased back toward the previous exposure position in a way that would again reduce engagement of the fixed cutter 116. Similarly, the overall movement from the first exposure position (all burst discs intact) to when the rolling element 122 bottoms out on the floor 126 (all burst discs failed) is also considered one-way.
The shelf 152 is configured to yield at a specified loading, such as if the weight on bit loading (FWOB) reaches a threshold. The shelf 152 in this configuration comprises a yield zone 154 contacted by the rolling element 122. The yield zone 154 may comprise a tapered or otherwise thinned portion of the shelf 152 that is thinner than the shelf 152 is at the periphery where it is coupled to the retainer housing 124. Thus, the yield zone 154 may preferentially yield while a periphery of the shelf 152 remains intact. The yield zone 154 may be sufficiently strong to retain the rolling element 122 in the first exposure position up until the specified loading, at which point the yield zone 154 may yield or otherwise fail, allowing the rolling element 122 to move down to the second exposure position. This movement may be one-way, as was described in reference to the prior embodiments of
The shelves may be selected to have the desired yield rating for each. The yield ratings may be the same or different. In one example, each shelf has the same yield rating, but fails at different (e.g., progressively larger) loading FWOB due to the increased engagement of the fixed cutter 116 (and associated WOB required) at the successive exposure positions of the rolling element 122. In another example, the yield ratings of the shelves 152A, 152B, 152C may be progressively larger.
As with the configuration of
The shear pins 172 are configured to fail, typically by shearing and/or yielding at a specified loading, such as if the weight on bit loading (FWOB) reaches a threshold. The shear pins 172 may be sufficiently strong to retain the rolling element 122 in the first exposure position up until the specified loading, at which point the shear pins 172 shear, yield, or otherwise fail, allowing the rolling element 122 to move down to the second exposure position. This movement may be one-way, as was described in reference to prior embodiments.
The levels of shear pins may be selected to have the desired failure rating for each. The failure ratings may be the same or different. In one example, each level of shear pins has the same failure rating, but fails at different (e.g., progressively larger) loading FWOB due to the increased engagement of the fixed cutter 116 (and associated WOB required) at the successive exposure positions of the rolling element 122. In another example, the failure ratings of the levels of shear pins 172A, 172B, 172C may be progressively larger.
As with other configurations, the movement of the rolling element 122 in
In another embodiment, a shape memory material could be used as a retainer element. Instead of failing or yielding like the burst discs, shelves, or pins, the shape memory material could change shape in response to a change in temperature. For example, a retainer element may be formed having an arched shape, similar to the example shape of burst discs above, except that the arched shape may increase with temperature. Even if the shape change is reversible by reducing temperature (e.g., when removing the drill bit from the well), the movement of the retainer element in response to temperature may still be considered one-way in the context of drilling, since temperature increases with depth.
A variety of materials may be selected for retention members designed to wear in response to rolling contact by the rolling element 122. Such materials could be softer than the rolling element, such as steel, Inconel, titanium, or another metal with the desired hardness. The material could be one of various grades of carbide with differing cobalt contents to more precisely control the krevs/footage needed to displace the rolling element. The material could be steel with a carbide coating, such as laser-deposited carbide or HVOF, to vary the rate at which the roller begins to lose exposure. The material could be a matrix or ceramic material. The thickness of the bearing element or housing wall can be varied in addition to the material to control the krevs/footage drilled before the element disengages with formation. The roller could instead be made of a softer material than the retainer, such that is wears down enough that it no longer can be held by the retainer and escapes during the run.
Foregoing embodiments provide examples of “deactivation” of the rolling element 122, whereby the rolling element 122 initially limits the engagement of the cutting element to the formation and the corresponding depth of cut, and then moves inward to increase the engagement and depth of cut. Thus, the second exposure position is inward of the first exposure position. The rolling element 122 may move far enough inward so as to not appreciably limit depth of cut in the second exposure position. This deactivation of the rolling DOCC element is considered a “one-time deactivation” if the movement is one-way.
Embodiments may also be constructed that provide “activation” of the rolling element downhole, wherein the rolling element 122 moves outwardly instead of inwardly. Thus, the second exposure position is outward of the first exposure position. By moving outwardly, the rolling element 122 limits depth of cut more in the second exposure position than in the first exposure position. This movement may also be one-way, in which case it may be considered a one-time activation of the rolling element.
Accordingly, the present disclosure encompasses depth of cut control assemblies for a drill bit that have moveable and optionally rolling DOCC elements to change their exposure and the corresponding engagement of cutters during drilling. Rather than moving back and forth between exposure positions, the DOCC elements in at least some embodiments are activated or deactivated once during drilling, with one-way changes in exposure. Related drill bits, drilling systems, and drilling methods incorporating the depth of cut control assemblies are also provided. Multiple embodiments are disclosed, while other embodiments may be formed from any suitable combination of the collective features of the multiple embodiments disclosed, including one or more of the following statements.
Statement 1. A drill bit comprising: a bit body securable to a drill string; a plurality of blades extending from the bit body; a plurality of fixed cutters secured to the blades; at least one depth of cut control (DOCC) element positioned in a retainer pocket along the blade to limit a depth of cut of one of the fixed cutters; and a retention member initially retaining the DOCC element within the retainer pocket at a first exposure position, the retention member configured to release the DOCC element downhole to allow one-way movement of the DOCC element to a second exposure position.
Statement 2. The drill bit of Statement 1, further comprising a one-time deactivation configuration wherein the one-way movement of the DOCC element from the first exposure position to the second exposure position increases the depth of cut allowed by the DOCC element.
Statement 3. The drill bit of Statement 1 or 2, further comprising a one-time activation configuration wherein the one-way movement of the DOCC element from the first exposure position to the second exposure position decreases the depth of cut allowed by the DOCC element.
Statement 4. The drill bit of Statement 3, further comprising: a biasing element configured for biasing the DOCC element from the first exposure position to the second exposure position in response to the release of the DOCC element by the retention member.
Statement 5. The drill bit of Statement 1, wherein the retention member is engaged by the DOCC element to release the DOCC element downhole by yielding in response to a threshold force applied to the DOCC element.
Statement 6. The drill bit of any of Statements 1 to 5, wherein the retention member comprises a disintegrating material to release the DOCC element downhole by disintegrating downhole in response to an increase in temperature or exposure to a downhole fluid.
Statement 7. The drill bit of any of Statements 1 to 6, wherein the DOCC element is rotatably secured by the retainer pocket when in one or both of the first exposure position and the second exposure position.
Statement 8. The drill bit of Statement 7, wherein the retention member comprises a wearable material to release the DOCC element to the second exposure position in response to rolling of the DOCC element against the wearable material while drilling.
Statement 9. The drill bit of Statement 8, wherein the wearable material comprises an outer layer of harder wearable material over an inner layer of softer wearable material.
Statement 10. The drill bit of any of Statements 7 to 9, wherein the DOCC element is trailing the one of the fixed cutters.
Statement 11. The drill bit of any of Statements 7 to 10, further comprising: a main cutting structure comprising a plurality of fixed cutters secured along the blades; and wherein the DOCC element is configured for cutting as part of the main cutting structure in at least the first exposure position.
Statement 12. The drill bit of any of Statements 1 to 11, wherein the retention member comprises a shape memory material configured to release the DOCC element downhole by changing shape in response to reaching a threshold temperature.
Statement 13. The drill bit of any of Statements 1 to 12, wherein the retention member comprises a shear member configured to shear in response to a threshold force or a burst disc configured to burst in response to a threshold pressure.
Statement 14. A method, comprising: drilling a wellbore by engaging an earthen formation with a drill bit comprising a plurality of fixed cutters secured to blades extending from a bit body, by rotating the bit body around a bit axis to cut the earthen formation with the plurality of fixed cutters; limiting a depth of cut of at least one of the fixed cutters by engaging the formation with a depth of cut control (DOCC) element spaced from the one of the fixed cutters while initially retaining the DOCC element at a first exposure position; and releasing the DOCC element downhole to move the DOCC element to a second exposure position.
Statement 15. The method of Statement 14, further comprising a one-time deactivation wherein moving the DOCC element from the first exposure position to the second exposure position comprises increasing the depth of cut allowed by the DOCC element.
Statement 16. The method of Statement 14 or 15, further comprising a one-time activation wherein moving the DOCC element from the first exposure position to the second exposure position comprises decreasing the depth of cut allowed by the DOCC element.
Statement 17. The method of any of Statements 14 to 16, further comprising: rotating the DOCC element relative to the bit body while rotating the drill bit around the bit axis in one or both of the first exposure position and the second exposure position.
Statement 18. The method of Statement 17, further comprising: rolling the DOCC element against an outer layer of wearable material to wear though the outer layer of wearable material to an inner layer of wearable material while drilling a first portion of the wellbore; and rolling the DOCC element against the inner layer of wearable material while drilling a second portion of the wellbore.
Statement 19. The method of any of Statements 14 to 18, further comprising: cutting the formation with the DOCC element along with the plurality of fixed cutters while the DOCC element is in the first exposure position; and using the DOCC element to limit the depth of cut of the one of the fixed cutters after moving the DOCC element to the second exposure position.
Statement 20. A drilling system, comprising: a drill string; a drill bit comprising a bit body secured to a lower end of the drill string and rotatable about a bit axis, the drill bit including a plurality of blades extending from the bit body, a plurality of fixed cutters secured to the blades, and a plurality of depth of cut control (DOCC) elements positioned in respective retainer pockets along the blades to limit a depth of cut of the fixed cutters; and a retention member initially retaining each DOCC element within the respective retainer pocket at a first exposure position, the retention member configured to release the DOCC element after drilling to a depth downhole to allow one-way movement of the DOCC element to a second exposure position.
To facilitate a better understanding of the present invention, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the entire scope of the disclosure.
For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.
Therefore, the present embodiments are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present embodiments may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual embodiments are discussed, all combinations of each embodiment are contemplated and covered by the disclosure. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure.
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