Patent Application
20160237752
The present disclosure relates in general to subsurface drilling tools and cutting elements for drill bits or other tools incorporating the same. More specifically, embodiments disclosed herein relate generally to rotatable cutting elements for rotary drill bits for deep well drilling.
Drill bits used to drill wellbores through earth formations generally are made within one of two broad categories of bit structures. Depending on the application/formation to be drilled, the appropriate type of drill bit may be selected based on the cutting action type for the bit and its appropriateness for use in the particular formation. Drill bits in the category generally known as “roller cone” bits, include a bit body having one or more roller cones rotatably mounted to the bit body. The bit body is typically formed from steel or another high strength material. The roller cones are also typically formed from steel or other high strength material and include a plurality of cutting elements disposed at selected positions about the cones. The cutting elements may be formed from the same base material as is the cone. These bits are typically referred to as “milled tooth” bits. Other roller cone bits include “insert” cutting elements that are press (interference) fit into holes formed and/or machined into the roller cones. The inserts may be formed from, for example, tungsten carbide, natural or synthetic diamond, boron nitride, or any one or combination of hard or superhard materials.
Drill bits of the category typically referred to as “fixed cutter” or “drag” bits, include bits that have cutting elements attached to the bit body. Drag bits may generally be defined as bits that have no moving parts. However, there are different types and methods of forming drag bits that are known in the art. For example, drag bits having abrasive material, such as diamond, impregnated into the surface of the material which forms the bit body are commonly referred to as “impreg” bits. Drag bits having cutting elements made of an ultra-hard cutting surface layer or “table” (typically made of polycrystalline diamond material or polycrystalline boron nitride material) deposited onto or otherwise bonded to a substrate are known in the art as polycrystalline diamond compact (“PDC”) bits. PDC bits drill soft formations easily, but they are frequently used to drill moderately hard or abrasive formations. They cut rock formations with a shearing action using small cutters that do not penetrate deeply into the formation. Because the penetration depth is shallow, high rates of penetration are achieved through relatively high bit rotational velocities.
PDC cutters have been used in industrial applications including rock drilling and metal machining for many years. In PDC bits, PDC cutters are received within cutter pockets, which are formed within blades extending from a bit body, and are typically bonded to the blades by brazing to the inner surfaces of the cutter pockets. The PDC cutters are positioned along the leading edges of the bit body blades so that as the bit body is rotated, the PDC cutters engage and drill the earth formation. In use, high forces may be exerted on the PDC cutters, particularly in the forward-to-rear direction. Additionally, the bit and the PDC cutters may be subjected to substantial abrasive forces. In some instances, impact, vibration and erosive forces have caused drill bit failure due to loss of one or more cutters, or due to breakage of the blades.
In a typical PDC cutter, a compact of polycrystalline diamond (“PCD”) (or other superhard material, such as polycrystalline cubic boron nitride) is bonded to a substrate material, which is typically a sintered metal-carbide to form a cutting structure. PCD comprises a polycrystalline mass of diamond grains or crystals that are bonded together to form an integral, tough, high-strength mass or lattice. The resulting PCD structure produces enhanced properties of wear resistance and hardness, making PCD materials extremely useful in aggressive wear and cutting applications where high levels of wear resistance and hardness are desired.
A significant factor in determining the longevity of PDC cutters is the exposure of the cutter to heat. Conventional polycrystalline diamond is stable at temperatures of up to 700-750° Celsius in air, above which observed increases in temperature may result in permanent damage to and structural failure of polycrystalline diamond. This deterioration in polycrystalline diamond is due to the significant difference in the coefficient of thermal expansion of the binder material, cobalt, as compared to diamond. Upon heating of polycrystalline diamond, the cobalt and the diamond lattice will expand at different rates, which may cause cracks to form in the diamond lattice structure and result in deterioration of the polycrystalline diamond. Damage may also be due to graphite formation at diamond-diamond necks leading to loss of microstructural integrity and strength loss, at extremely high temperatures.
Exposure to heat (through brazing or through frictional heat generated from the contact of the cutter with the formation) can cause thermal damage to the diamond table and eventually result in the formation of cracks (due to differences in thermal expansion coefficients) which can lead to spalling of the polycrystalline diamond layer, delamination between the polycrystalline diamond and substrate, and conversion of the diamond back into graphite causing rapid abrasive wear. As a cutting element contacts the formation, a wear flat develops and frictional heat is induced. As the cutting element is continued to be used, the wear flat will increase in size and further induce frictional heat. The heat may build-up that may cause failure of the cutting element due to thermal miss-match between diamond and catalyst discussed above. This is particularly true for cutters that are immovably attached to the drill bit, as conventional in the art. Accordingly, there exists a continuing need to develop ways to extend the life of a cutting element and improve the drilling process.
Debris associated with the drilling process are removed through the well with the use of fluids. In particular, fluid is pumped through a drill string and drill bit to not only lubricate the cutting area, but also urge debris upwardly outside of the drilling string. As the depth of the wellbore increases, the amount of debris and the hydrostatic pressure of the fluid increase. In fact, sufficient backpressure created by the debris and fluid can effectively exceed the pressure provided to the wellbore by a pump, causing a “reversal” of the fluid delivery system. Further, the greater the clearance between the drill bit and the drill bore provides for greater backpressure, as the fluid and debris will occupy greater volume at any particular depth. Therefore, a need exists in the art for a drill bit with an improved profile to minimize clearance between the bit and the drill bore and improve the efficiency of debris removal.
Directional drilling is well developed in the art. Among other things, directional drilling permits the drill bore to be vertical, angled, or even horizontal. While drilling on an angle, and especially horizontal, the drill bit can wobble within the drill bore. This can be caused by, among other things, the drilling end of the drill bit having a wider profile than the pin end closest to the drill string. The wobble can decrease drilling efficiency and increase wear on the shank of the drill bit. Therefore, a need exists in the art for a drill bit configured to minimize and/or prevent wobble within the wellbore.
In addition to typical wellbore drilling, an additional application of particular interest is cased-hole drilling. In cased-hole drilling, casing strings comprised of elongated tubular members are inserted into a borehole and cemented in place. The casing provides several advantages, including providing a smooth internal bore, preventing fluid loss, preventing contamination of fresh water well zones, and permitting zonal isolation. To isolate zones of different pressures or fluids, bridge plugs are commonly used to hydraulically isolate respective zones. For example, during fracturing of a well, a zone of interest should be hydraulically isolated from a lower pressure zone.
During the completion process of a well, bridge plugs, including composite bridge plugs, need to be removed from the well casing. Removal of the bridge plugs are associated with several technological shortcomings. One preferred method of removing bridge plugs is through milling as described in U.S. Pat. No. 8,127,851 to Misselbrook, which is herein incorporated by reference in its entirety. However, bridge plugs are often constructed from brittle metals such as cast iron, which is not particularly conducive to milling. The milling of the plugs can result in undesirably large chunks of the plug, which can become lodged in the lateral of the casing. Further, milling produces undesirably high levels of torque. Another method of removing bridge plugs is through drilling with a tri-cone bit. In addition to not being designed for the application, the tri-cone drill bit can mechanically fail, after which one of the three cones may become lodged in the wellbore. The speed with which the motor can drive the tri-cone bit and the weight that can be applied to the bit is limited due to the use of ball bearings in a tri-cone bit. Therefore, a further need exists in the art for an improved drill bit capable of more effectively removing bridge plugs.
Therefore, it is a principal object, feature, and/or advantage of the present disclosure to overcome the aforementioned deficiencies in the art and provide a new and improved subsurface drilling tool that will efficiently drill hard rock formations.
It is another object, feature, and/or advantage of the present disclosure to provide a subsurface drilling bit with new and improved alternating rotating cones having hard inserts embedded therein and protruding therefrom to crush hard rock formation.
It is still another object, feature, and/or advantage of the present disclosure to provide a subsurface drilling bit that eliminates or minimizes sticky clay or shale drill cuttings from preferentially adhering to and “balling-up” a drill bit cutting face while drilling in a borehole.
It is yet another object, feature, and/or advantage of the present disclosure to provide a subsurface drilling bit that has replaceable hard inserts embedded therein for easy access and increased efficiency.
It is another object, feature, and/or advantage of the present disclosure to drill in three dimensions to shear, puncture, pulverize, twist and chisel both rock formation and bridge plugs in cased-well drilling. An exemplary drill bit of the present disclosure can degrade bridge plugs into pieces of approximately one-eighth inch or less to more easily enter the flow of fluid, reducing costly wiper trips. The spherical-like cutting structure can produce smaller plug cuttings than mills and tri-cone bits. Further, the spherical-like cutting structure can often include an effective surface cutting area of at least two times greater than similarly dimensioned tri-cone bits.
It is another object, feature, and/or advantage of the present disclosure to limit and/or remove moving parts such as ball bearings. As a result, more weight-on-bit can be applied to the bit, and the bit can operate without failure at higher revolutions per minute (RPMs). In fact, upwards of three times or greater of weight-on-bit can often be applied to an exemplary drill bit than similarly dimensioned tri-coned bits.
It is another object, feature, and/or advantage of the present disclosure to provide a drill bit with an improved profile to minimize clearance between the bit and the borehole to improve the efficiency of debris removal. The profile of an exemplary embodiment closely approximates that of a circle, which generally contours to the borehole being drilled. Further, reverse jets associated with the fluid course provide additional force to the debris opposite to the drilling direction.
These and/or other objects, features, and/or advantages of the present disclosure will be apparent to those skilled in the art. The present disclosure is not to be limited to or by these objects, features, and advantages. No single aspect need provide each and every object, feature, or advantage.
According to one aspect of the present disclosure, a subsurface drilling tool, particularly a drill bit, is provided. The drill bit includes a bit body or shank, wherein the shank comprises a pin end and an opposite cutting end. The pin end is open and comprises a fluid course extending longitudinally from the open pin end, through the shank, and through the cutting end for drilling fluid to transfer through the shank. The pin end includes a pin, screw, threads, or other means standard in the industry for attaching a drill bit to a drill stem. The cutting end comprises a plurality of ear portions configured to form the shape of a socket, wherein a ball shaped cutting tool fits inside the socket and is rotatably attached to the plurality of ear portions via an axle. The ball shaped cutting tool comprises a plurality of cones, preferably two, shaped like half-domes and placed adjacent to one another to form the ball shape. The drilling or cutting is caused by a plurality of blade inserts, preferably metal-carbide, that fit inside and protrude therefrom a plurality of holes covering the exterior of the ball shaped cutting tool, wherein each blade insert comprises a cutting face and a trailing face. The plurality of cones and, consequently, the ball shaped cutting tool may be locked in place via a locking pin through the axle. The drill bit of the present disclosure further includes a series of milling courses extending longitudinally along the outside length of the shank for milling and particles of formation to flow to the surface through the borehole.
According to another aspect of the present disclosure, a method of subsurface drilling using a drill bit includes providing a drill and a drill bit. The drill bit includes a bit body or shank, wherein the shank comprises a pin end and an opposite cutting end. The pin end is open and comprises a fluid course extending longitudinally from the open pin end, through the shank, and through the cutting end for drilling fluid to transfer through the shank. The pin end includes a pin, screw, threads, or other means standard in the industry for attaching a drill bit to a drill. The cutting end comprises a plurality of ear portions configured to form the shape of a socket, wherein a ball shaped cutting tool fits inside the socket and is rotatably attached to the plurality of ear portions via an axle. The ball shaped cutting tool comprises a plurality of cones, preferably two, shaped like half-domes and placed adjacent to one another to form the ball shape. The drilling or cutting is caused by a plurality of blade inserts, preferably metal-carbide, that fit inside and protrude therefrom a plurality of holes covering the exterior of the ball shaped cutting tool, wherein each blade insert comprises a cutting face and a trailing face. The plurality of cones and, consequently, the ball shaped cutting tool may be locked in place via a locking pin through the axle. The drill bit of the present disclosure further includes a series of milling courses extending longitudinally along the outside length of the shank for milling and particles of formation to flow to the surface through the borehole. The method subsequently involves attaching the drill bit to the drill, inserting the drill bit into the ground, and starting to drill.
According to still another aspect of the present disclosure, a drill bit configured to drill a drill bore includes a shank having a first end configured to operably connect to a drill string. Two ear portions are integrally formed to and extending from a second end of the shank. Each of the two ear portions can have an arcuate outer surface. Two rolling cutters are disposed between the two ear portions, each of the two rolling cutters having an arcuate face. A plurality of cutting elements is operably connected to each of the two rolling cutters. Each of the plurality of cutting elements has a cutting edge. The cutting edges of a portion of the plurality of cutting elements define a circle or circular configuration. The circular configuration can be further defined by the arcuate outer surfaces of the two ear portions.
The circular configuration can correspond to a circumference of the drill bore and configured to prevent backflow of drilling debris.
The drill bit can further include a plurality of protrusions extending outwardly from the shank. The plurality of protrusions can further define the circle or circular configuration. Further, the plurality of protrusions is configured to prevent wobble of the drill bit in operation. An exposed surface of each of the plurality of protrusions can be hemispherical.
According to another aspect of the present disclosure a drill bit includes a generally cylindrical bit body having a first end configured to operably connect to a drill string. Two ear portions are associated with the bit body, each of the two ear portions having a planar inner surface. An axle extends between the two ear portions. Two rotatable cutters disposed on the axle. Each of the two rotatable cutters having a planar inner surface, a planar outer surface, and an arcuate face extending between the inner surface and the outer surface. The outer surface of each of the two rotatable cutters can directly abut the inner surface of one of the two ear portions. The inner surface of each of the two rotatable cutters can directly abut one another.
The two rotatable cutters can have an on-load configuration. In the on-load configuration, a gap is disposed between the outer surface of each of the two rotatable cutters and one of the ear portions, and the inner surfaces of each of the two rotatable cutters are in contact. The on-load configuration can be associated with pulverization of rock within a drill bore. Alternatively, the two rotatable cutters can have an off-load configuration. In the off-load configuration, a gap is disposed between the inner surfaces of each of the two rotatable cutters, and the outer surface of each of the two rotatable cutters and one of the ear portions are in contact. Centripetal forces force the outer surface of each of the two rotatable cutters into contact with one of the ear portions in the off-load configuration.
According to still another aspect of the present disclosure, a drill bit is configured to drill a drill bore and includes a shank having a first end configured to operably connect to a drill string. Two ear portions are integrally formed to and extending from a second end of the shank, and an axle extends between the two ear portions. Two rolling cutters are disposed between the two ear portions and operably mounted on the axle. Each of the two rolling cutters having an arcuate cutting face between an inner surface and an outer surface.
A plurality of cutting elements can be operably connected to the arcuate cutting faces of each of the two rolling cutters, wherein the plurality of cutting elements are arranged about more than one circumference of each of the arcuate cutting faces. The plurality of cutting elements can be equally spaced. In another embodiment, each of the rolling cutters includes a plurality of ridges and a plurality of grooves in an alternating configuration, associated with the arcuate cutting face, and extending between the inner surface and the outer surface of each of the two rolling cutters. One or more notches can be disposed within the plurality of ridges. In still another embodiment, each of the two rolling cutters further comprises a plurality of three-sided cutting elements and a plurality of four-sided cutting elements associated with the arcuate cutting face.
The drill bit can further include a fluid course extending axially within the shank. The fluid course can have an inlet proximate to the first end of the shank and at least one outlet proximate to the second end of the shank. Fluid exiting the outlet of the fluid course can contact the two rolling cutters opposite a drill face of the drill bore. The fluid course can further include a bifurcated portion comprising two fluid pathways in fluid communication with the inlet. At least one outlet comprises two outlets, each of the two outlets being associated with one of the two fluid pathways of the bifurcated portion. One or more reverse jets can be within the shank and in fluid communication with the fluid course. The one or more reverse jets are configured to urge drilling debris in a direction opposite a cutting direction of the drill bit within the drill bore. The drill bit can further include a plurality of cutting elements disposed on the shank.
Different aspects may meet different objects of the disclosure. Other objectives and advantages of this disclosure will be more apparent in the following detailed description taken in conjunction with the figures. The present disclosure is not to be limited by or to these objects or aspects.
Illustrated embodiments of the disclosure are described in detail below with reference to the attached figures, which are incorporated by reference herein, and where:
The cutting end (14) comprises a plurality of ear portions (16), preferably two, located opposite one another on both sides of the shank (10). Moreover, the ear portions (16) extend beyond the shank (10) to assist in forming the cutting end (14) of the shank (10). For instance, the ear portions (16) are configured to form the shape of a socket (18), wherein a ball shaped cutting tool (20) fits inside the socket (18) and is rotatably attached to the plurality of ear portions (16) via an axle (24). Comprising the ball shaped cutting tool (20) is a plurality of cones (22), preferably two, shaped like half-domes and located adjacent to one another to form the ball shape as illustrated in
As further illustrated in
The arrangement of the plurality of cones (22) is such that the cones will crush substantially the entire area of the bottom of the borehole. Moreover, the plurality of cones (22) is of such composition and so manufactured as to have an extremely high compressive strength, and to be extremely resistant to transverse rupture and to abrasion. For example the plurality of cones (22) may be made of a composition of tungsten, cobalt, iron and carbon processed to produce the desired properties just referred to. The plurality of cones (22) forming the ball shaped cutting tool (20) will take the extreme loads required in drilling hard rock. No bending moment is imposed upon the hard metal of which the plurality of cones (22) is made. The plurality of cones (22) will take loads imposed upon them from any direction under operating conditions. The plurality of cones (22) forming the ball shaped cutting tool (20) eliminates sharp corners in the shank (10) from which cracks might start, thus, effectively increasing the life of the drill bit. Also, it has been found that the use of the plurality of cones (22) in forming the ball shaped cutting tool (20) not only simplifies and reduces the cost of manufacture, but also facilitates final assembly and repair of the drill bit of the present disclosure.
Illustrated in
The plurality of blade inserts (30) according to embodiments of the present disclosure may be formed of material including, for example, metal, carbides, such as tungsten carbide, tantalum carbide, or titanium carbide, nitrides, ceramics and diamond, such as polycrystalline diamond, or a combination of substrates thereof. For instance, a carbide substrate utilized in the present disclosure may include metal carbide grains, such as tungsten carbide, supported by a matrix of a metal binder. Various binding metals may be present in the substrate, such as cobalt, nickel, iron, alloys thereof, or mixtures, thereof. In a particular embodiment, the substrate may be formed of a sintered tungsten carbide composite structure of tungsten carbide and cobalt. However, it is known that various metal carbide compositions and binders may be used in addition to tungsten carbide and cobalt. Thus, references to the use of tungsten carbide and cobalt are for illustrative purposes only, and no limitation on the type of carbide or binder use is intended. Further, diamond composites, such as diamond/silicon or diamond/carbide composites, may be used to form the plurality of blade inserts (30).
According to a further aspect of the present disclosure, a method of subsurface drilling using a drilling tool, particularly a drill bit, is provided. Illustrated in
Referring to
With reference to
Thus, the arcuate outer surface (54) of each of the ear portions (16) and the axle (24) collectively have an arcuate profile generally contoured to the circular configuration (52), as illustrated in
Further, each of the rolling cutters (22) includes an arcuate face (56). With reference to
With continued reference to
Further, the plurality of protrusions (44), also known as “wobble control,” further define the circular (and/or cylindrical) configuration (52), as illustrated in
Still further, at least one milling course (36) is disposed on the shank body (10) in a manner to provide channels (60) for the fluid and debris to escape in a direction opposite the cutting direction. As illustrated in
Referring to
Each of the rotatable cutters (20) includes a bore (72) through which the axle (24) is operably connected. The rotatable cutters (20) can operably be connected to the axle (24) without any intervening structures such as ball bearings, roller bearings, bushings, and the like. Based on the material selection and manufacturing of the rotatable cutters (22) and the axle (24), wear is sufficiently low such that the two metal components can be in contact. As a result, more weight-on-bit can be applied to the bit, and the bit can operate without failure at higher RPMs than similarly dimensioned tri-coned bits.
Similarly, based on the material selection and manufacturing of the rotatable cutters (20) and the ear portions (16), wear is sufficiently low such that the two metal components can be in contact. To that end, the outer surface (70) of each the rotatable cutters (22) is adjacent to, abuts, directly abuts, and/or is in contact with the inner surface (66) of the ear portions (16). Further, the inner surfaces (68) of the rotatable cutters (22) is adjacent to, abut, directly abut, and/or are in contact with one another. Taken together, the tolerances between the rotatable cutters (22) and the ear portions (16) are sufficiently small such that cutting debris is generally unable to enter a space between the outer surface (70) of the rotatable cutters (22) and inner surface (66) of the ear portions (16) and/or the inner surfaces (68) of the rotatable cutters (22).
While the tolerances between the rotatable cutters (22) and the ear portions (16) are sufficiently small, the present disclosure contemplates that relatively small gaps can exist between the same such that the rotatable cutters (22) can slide laterally on the axle (24) based on, at least in part, whether the drill bit is in use or not. More particularly, in an on-load configuration (i.e., the drill bit has weight-on-bit and spinning), centripetal and other forces can slide the rotatable cutters (22) slightly towards one another such that the inner surfaces (68) of the rotatable cutters (22) are in contact and/or direct contact. In the on-load configuration, a gap can result between the outer surface (70) of each of the two rotatable cutters (22) and the inner surface (66) of the ear portions (16). Similarly, in an off-load configuration (i.e., the drill bit has no weight-on-bit and is spinning), centripetal and other forces can slide the rotatable cutters (22) slightly away from one another such that the outer surfaces (70) of the rotatable cutters (22) are in contact and/or direct contact with the inner surface (66) of the ear portions (16). The design removes the need for washers, spacers, and/or additional components. Further, the unique design significantly improves life of the axle (24) by preventing wear from cutting debris and the like.
The drill bit can also include an improved fluid delivery system (74), as illustrated in
The primary fluid passageways (76) are in fluid communication with primary fluid outlets (78) disposed on a lower face (82) of the shank (10) between the two ear portions (16). The primary fluid outlets (78) and the lower face (82) can be considered to be on a second end (84) of the shank (10) opposite a first end, (86), wherein the first end (86) is the pin end (12). In such nomenclature, the second end (84) of the shank (10) can include the lowermost portion of the same not including the ear portions (16). The primary fluid outlets (78) on the lower face (82) are configured to provide fluid to the rolling cutters (22) on a side opposite a drill face of the drill bore. In other words, the fluid exiting the primary fluid passageways (76) (and the primary fluid outlets (78)) contact the rolling cutters (22) on a portion not in contact with the drill face of the drill bore. This can advantageously flush away any debris on the cutting elements (30) from the previous cutting iteration of the rolling cutters (22) and/or provide better lubrication for the cutting elements (30) during the next cutting iteration. Furthermore, the primary fluid outlets (78) can be offset from a first axis (88) (
The fluid delivery system (74) can further be divided into more than one secondary fluid passageways (92). As illustrated in
The fluid delivery system (74) can still further include reverse fluid passageways (96). The reverse fluid passageways (96) are in fluid communication with the fluid course (40) and the reverse jet outlets (50) disposed on the angled surface (48), as illustrated in
Referring to
Another exemplary cutting tool (104) includes two rotatable cutters (20) that operate as previously expressed herein, one of which is illustrated in
Another exemplary cutting tool (112) is illustrated in
Each of the three-sided cutting elements (114) and/or the four-sided cutting elements (116) can be comprised of a plurality of teeth (120, 122) separated by a groove (124). The exemplary embodiment illustrated in
Referring to
The plurality of platforms (128) can include four generally upright sides (132). One or more of the upright sides (132) can be sloped inwardly such that the sides are trapezoidal in shape. As illustrated in
An exemplary cutting tool (140) is illustrated in
Certain features from the exemplary embodiments discussed herein can be selectively combined based, at least in part, on the needs of the application. For example, the cutting tool (156) illustrated in
Furthermore, the present disclosure contemplates that the two rotatable cutters (22) need not be matching counterparts. Rather, one of the rotatable cutters (22), can for example, be similar to those illustrated in
The disclosure is not to be limited to the particular embodiments described herein. The subsurface drilling tool of the present disclosure and method of drilling using the subsurface drilling tool are universally applicable to drilling apparatuses of all shapes and sizes, makes, models, and manufacturers. Furthermore, while intended for large subsurface drilling operations, the drilling tool of the present disclosure may be used for drilling in all manner of uses, large and small. The foregoing description has been presented for purposes of illustration and description. It is not intended to be an exhaustive list or limit any of the disclosure to the precise forms disclosed. It is contemplated that other alternatives or exemplary aspects are considered included in the disclosure. The description is merely examples of embodiments, processes or methods of the disclosure. It is understood that other modifications, substitutions, and/or additions can be made, which are within the intended spirit and scope of the disclosure. For the foregoing, it can be seen that the disclosure accomplishes at least all that is intended.
The previous detailed description is of a small number of embodiments for implementing the disclosure and is not intended to be limiting in scope. The following claims set forth a number of the embodiments of the disclosure with greater particularity.
This application is a continuation-in-part application of U.S. application Ser. No. 14/290,597, filed on May 29, 2014, which claims the benefit of U.S. Provisional Appl. No. 61/879,131, filed on Sep. 17, 2013; and a continuation-in-part application of U.S. application Ser. No. 14/465,907, filed on Aug. 22, 2014, which claims the benefit of U.S. application Ser. No. 14/290,597 and U.S. Provisional Appl. No. 61/879,131, all of which are incorporated by reference herein in their entireties.
| Number | Date | Country | |
|---|---|---|---|
| 61879131 | Sep 2013 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 14465907 | Aug 2014 | US |
| Child | 15138909 | US | |
| Parent | 14290597 | May 2014 | US |
| Child | 14465907 | US |
