Abstract:
A drill bit includes a bit body having a pin end capable of attaching to a drill string, a cutting end having a plurality of blades extending radially therefrom and separated by a plurality of channels therebetween, and a fluid plenum open to receiving drilling fluid from the drill string. The drill bit further includes at least one cutting element in a cutter pocket formed on the plurality of blades, at least one fluid flow passageway extending from the fluid plenum to at least one nozzle bore, at least one nozzle attached to the at least one nozzle bore and having a nozzle face spaced apart from the bit body, and an protruding body having an transition surface extending from the bit body to proximate the nozzle face. A width of the protruding body varies along a height of the protruding body from proximate the bit body to proximate the nozzle face.

Description:
CROSS REFERENCE TO RELATED APPLICATION 
       [0001]    This Application claims the benefit of and priority to U.S. Provisional Application 62/096,473 filed on Dec. 23, 2014, the entirety of which is incorporated herein by reference. 
     
    
     BACKGROUND 
       [0002]    In drilling a borehole, such as for the recovery of hydrocarbons or for other applications, it is conventional practice to connect a drill bit on the lower end of an assembly of drill pipe sections that are connected end-to-end so as to form a drill string. The bit is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating bit engages the earthen formation causing the bit to cut through the formation material by either abrasion, fracturing, or shearing action, or through a combination of one or more of these or other cutting methods, thereby forming a borehole. 
         [0003]    Many different types of drill bits have been developed and found useful in drilling such boreholes. Two predominate types of drill bits are roller cone bits and fixed cutter (or rotary drag) bits. Most fixed cutter bit designs include a plurality of blades angularly spaced about the bit face. The blades project radially outward from the bit body and form flow channels, or junk slots, therebetween. In addition, cutting elements are typically grouped and mounted on several blades in radially extending rows. The configuration or layout of the cutting elements on the blades may vary widely, depending on a number of factors such as the formation to be drilled. 
         [0004]    A conventional drag bit is shown in  FIG. 1 . The drill bit  10  includes a bit body  12  and a plurality of blades  14  extending radially from the bit body  12 . The blades  14  are separated by channels or junk slots  16  that enable drilling fluid to flow between and both clean and cool the blades  14  and cutters  18 . Cutters  18  are held in the blades  14  at set angular orientations and radial locations to present working surfaces  20  with a desired back rake and/or side rake angle against a formation to be drilled. Typically, the working surfaces  20  are generally perpendicular to the axis  19  and side surface  21  of a cylindrical cutter  18 . Thus, the working surface  20  and the side surface  21  meet or intersect to form a circumferential cutting edge  22 . 
         [0005]    Orifices are typically formed in the drill bit body  12  and positioned in the junk slots  16 . The orifices are commonly adapted to accept nozzles  23 . Orifices may also be referred to as nozzle bores. The orifices allow drilling fluid to be discharged through the bit between the cutting blades  14  for lubricating and cooling the drill bit  10 , the blades  14 , and the cutters  18 . The drilling fluid also cleans and removes the cuttings as the drill bit rotates and penetrates the geological formation. Without proper flow characteristics, insufficient cooling of the cutters may result in cutter failure during drilling operations. The junk slots  16 , which may also be referred to as “fluid courses,” are positioned to provide additional flow channels for drilling fluid and to provide a passage for formation cuttings to travel past the drill bit  10  toward the surface of a wellbore. 
         [0006]    The drill bit  10  includes a shank  24  and a crown  26 . The shank  24  is typically formed of steel or a matrix material and includes a threaded pin  28  for attachment to a drill string. The crown  26  has a cutting face  30  and outer side surface  32 . Materials used to form drill bit bodies are selected to provide adequate strength and toughness, while providing good resistance to abrasive and erosive wear. 
         [0007]    The combined plurality of surfaces  20  of the cutters  18  effectively forms the cutting face  30  of the drill bit  10 . Once the crown  26  is formed, the cutters  18  are positioned in the cutter pockets  34  and affixed by any suitable method, such as brazing, adhesive, mechanical means such as interference fit, or the like. The design depicted provides the cutter pockets  34  inclined with respect to the surface of the crown  26 . The cutter pockets  34  are inclined such that cutters  18  are oriented with the working face  20  at a desired rake angle in the direction of rotation of the bit  10  so as to enhance cutting. 
       SUMMARY 
       [0008]    This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. 
         [0009]    In one aspect, embodiments disclosed herein relate to a drill bit that includes a bit body, a cutting end having a plurality of blades extending radially therefrom and separated by a plurality of channels therebetween, and a fluid plenum configured to receive drilling fluid. The drill bit further includes at least one cutting element on one of the plurality of blades, at least one fluid flow passageway extending from the fluid plenum to at least one nozzle bore, at least one nozzle attached to the at least one nozzle bore and having a nozzle face, and a raised body defining a transition surface extending from the bit body to proximate the nozzle face. A width of the raised body varies along a height of the transition surface from proximate the bit body to proximate the nozzle face. 
         [0010]    In another aspect, embodiments disclosed herein relate to a drill bit that includes a bit body, a cutting end having a plurality of blades extending radially therefrom and separated by a plurality of channels therebetween, and a fluid plenum configured to receive drilling fluid. The drill bit further includes at least one cutting element on one of the plurality of blades, at least one fluid flow passageway extending from the fluid plenum to at least one nozzle bore disposed in the cutting end allowing drilling fluid to be discharged from the drill bit, and at least one nozzle. The at least one nozzle includes a lower portion attached to the at least one nozzle bore below an outer surface of the bit body, and an upper portion extending beyond the outer surface of the bit body. 
         [0011]    In yet another aspect, embodiments disclosed herein relate to a method of drilling a formation that includes inserting a drill bit into a wellbore through a formation to engage the formation. The drill bit includes a bit body having a pin end capable of attaching to a drill string, a cutting end having a plurality of blades extending radially therefrom and separated by a plurality of channels therebetween, and a fluid plenum configured to receive drilling fluid from the drill string. The drill bit further includes at least one cutting element disposed in a cutter pocket formed on the plurality of blades, at least one fluid flow passageway extending from the fluid plenum to at least one nozzle bore disposed in the cutting end allowing drilling fluid to be discharged from the drill bit, and at least one nozzle attached to the at least one nozzle bore and extending a distance from an outer surface of the bit body. The method further includes rotating the drill bit, and while rotating, pumping drilling fluid through the drill string and the drill bit. 
         [0012]    Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims. 
     
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         [0013]      FIG. 1  shows a conventional PDC drill bit. 
           [0014]      FIG. 2  shows a top view of a PDC drill bit according to embodiments of the present disclosure. 
           [0015]      FIG. 3  shows a side view of a PDC drill bit according to embodiments of the present disclosure. 
           [0016]      FIG. 4  shows a partial cross-sectional view of a drill bit according to embodiments of the present disclosure. 
           [0017]      FIG. 5  shows a partial cross-sectional view of a drill bit according to embodiments of the present disclosure. 
           [0018]      FIG. 6  shows a partial cross-sectional view of a drill bit according to embodiments of the present disclosure. 
       
    
    
     DETAILED DESCRIPTION 
       [0019]    In one aspect, embodiments disclosed herein relate to the use of extended or raised nozzles in PDC fixed cutter drill bits. For example, such extended or raised nozzles may terminate at a distance away or removed from the bit body surface from which the nozzles extend. One or more embodiments disclosed herein relate to increasing the proximity of a nozzle outlet to the cutting structure of a drill bit for increased cutting element cooling and increased cleaning of the bit face. Such embodiments may be suitable for drill bits having tall blades. Methods for extending or raising nozzles in PDC drill bits and the location and sizing of such extended or raised nozzles are also disclosed. 
         [0020]    PDC bits having tall blades, which may be present, for example, on drill bits having a highly sloped bit body, that may be referred to as a “bullet body,” (such as the type disclosed in U.S. Patent Publication No. 2013/0341101, which is herein incorporated by reference in its entirety), may be designed for drilling through soft formations. However, the use of taller blades may space the outlet of the nozzles (conventionally flush with or recessed within the bit body) further from the cutting elements located on the blades due to the increased blade height, which may create inadequate cleaning (and cooling) of such cutting elements (particularly those in the shoulder region of the bit where the blade height may be the greatest). Specifically, as a result of the increased blade height, the drilling fluid exiting the nozzles may have a lower velocity when impacting the cutting face of the blades, resulting in poor cutter cleaning and cooling. However, use of the nozzles that spaces the outlet away from the bit body surface (e.g., raises it above the bit body surface), as disclosed herein, may allow for an increased fluid velocity when the fluid hits the cutting elements, as compared to fluid that exits a nozzle outlet that is flush with or recessed within the bit body surface. 
         [0021]    A PDC bit cutting face as defined by the cutters on the blades (e.g., cutting profile) may generally be divided into three regions: a cone region, a shoulder region, and a gage region. The cone region includes the radially innermost region of the PDC bit extending generally from the bit axis to the shoulder region. A cone region is generally concave. Adjacent to the cone region is the shoulder (or the upturned curve) region. In most conventional fixed cutter bits, the shoulder region is generally convex. Moving radially outward, adjacent to the shoulder region is the gage region which extends parallel to the bit axis at the outer radial periphery of the bit. The axially lowermost point of the convex shoulder region defines a nose. At the nose, the slope of a tangent line to the convex shoulder region is zero. 
         [0022]      FIGS. 2 and 3  show a top view and side view, respectively, of a PDC drill bit according to embodiments of the present disclosure. The drill bit  200  has a bit body  210  with a longitudinal axis L extending therethrough. A plurality of blades  220  extends from the bit body  210 , radially from the bit body surface and axially along the bit body surface from a bit cutting face  202  towards a bit connection end. Each blade  220  has a formation facing surface  222  and side walls  224 . As shown, the side walls  224  of the blades  220  extend a height from the bit body  210  to the formation facing surface  222 . Blade side walls  224  may have a sloped or curved transition into the formation facing surface  222 , as well as a sloped or curved transition into bit body  210 . In some embodiments, a blade side wall  224  may intersect the formation facing surface  222  substantially perpendicularly, optionally with a radiused transition. Side walls  224  that face in the rotational direction of the bit may often be referred to as the blade leading face  225 , while side walls  224  that face opposite the rotational direction of the bit may often be referred to as a trailing face  226 . Additionally, a blade side wall  224  may face other directions, such as toward the center of the bit, or longitudinal axis L, at the most radially interior portion of blade  220 , represented by  227 . 
         [0023]    Cutting elements known in the art may be disposed on the plurality of blades  220  at the blade leading face  225 , for example. For example, a plurality of polycrystalline diamond compact (“PDC”) cutters  228  (i.e., cutting elements having a PDC table forming a cutting face mounted to a substrate) may be disposed along a blade leading face  225 , such that the cutting faces of the PDC cutters face in the direction of the bit&#39;s rotation. Thus, as the bit rotates, the cutting faces of the PDC cutters may contact and cut the earthen formation to be drilled. However, the present disclosure is not so limited and may include cutting elements spaced rearward of the leading face  225  in one or more embodiments. 
         [0024]    The drill bit  200  also has at least one junk slot or fluid course  230 . Each junk slot  230  is defined by the bit body surface  210  and the side walls  224  of adjacent blades  220 . In effect, the junk slots  230  form passages or channels between the blades  220  that may be used to direct drilling fluids and any cuttings from drilling an earthen formation between the blades and up the wellbore. For example, drilling fluid may be directed through the junk slots to evacuate the cuttings from drilling and to cool the bit cutting elements. Additionally, at least one nozzle bore  240  is formed in the bit body  210 , within a junk slot area  230 . Each nozzle bore  240  has an intersecting surface  245  formed between the bit body surface  210  of a junk slot  230  and an inner surface of the nozzle bore  240 , such that intersecting surface  245  extends axially away from the bit body  210  to the outlet of the nozzle bore  240 , adjacent the nozzle face. Intersecting surface  245  is defined by the bit body shape and nozzle bore size and orientation. Further, as shown in  FIG. 2 , a nozzle  246  may be disposed within a nozzle bore  240 , and have a nozzle face  247  exposed to the environment. The nozzle  246  may be used to direct drilling fluid through the junk slots  230 . 
         [0025]    Referring now to  FIG. 4 , a partial cross-sectional view of a drill bit  400  according to embodiments of the present disclosure is shown. As shown in  FIG. 4 , the bit body  410  contains a fluid plenum  425  (e.g., fluid reservoir or fluid channel) therein to allow drilling fluid through the bit  400  that is pumped down the drill string. From the fluid plenum  425 , fluid flows through a fluid flow passageway  430  extending from the fluid plenum  425  to at least one nozzle bore  440  to exit the bit. In one or more embodiments, the drill bit  400  may include at least one raised nozzle  446  retained within a nozzle bore  440 . The distal end of or outlet of nozzle  446  and nozzle bore  440  extend beyond the surrounding bit body  410 . Nozzle  446  is illustrated as being threadedly retained within bore  440  at the proximal end of nozzle bore  440 , however other mechanisms and relative locations of retention may also be used. Nozzle face  447  is at the distal end of nozzle  446 , and in various embodiments, may be slightly exposed, flush with, or recessed within the distal end of nozzle bore  440 . As mentioned, raised nozzle  446  extends a distance beyond the surrounding bit body  410 , with the transition between the bit body  410  and the distal end of the nozzle bore  440  being defined by a transition surface  445  (e.g., intersecting surface), resulting in a raised body portion. Transition surface  445  surrounding the nozzle bore  440  may be built up or raised, as shown in  FIG. 4 , such that the at least one nozzle  446  is closer to the cutting end  402  of the bit than the bit body  410  surface. Further, as illustrated, the nozzle face  447  may be substantially flush with the distal end of the nozzle bore or recessed by up to approximately 0.25 inches therefrom or other amounts within the range of 0 to approximately 0.25 inches. The transition surface  445  and raised body portion may be formed integral with the bit or formed separately from the bit and attached thereto using welding or other methods known in the art to attach elements to a drill bit. For example, the transition surface and raised body portion could also be formed as a separate insert piece that is threaded into an oversized nozzle bore, and the nozzle may then be threaded into the transition surface. If the transition surface  445  and raised body portion is formed separately from the bit, the transition surface may be formed from a material similar to the bit body  410  material, for example, the transition surface  445  may be formed from a steel or matrix material (e.g., tungsten carbide matrix material). The amount of material forming transition surface  445  and other characteristics of the material forming transition surface  445  (i.e., shape, elongation, diameter, slope) may be determined using tools such as computational fluid dynamics (CFD), finite element analysis (FEA), or other methods known in the art to analyze elements of a drill bit during simulation or operation in various applications. For example, the shape and slope may be selected so as to reduce the impact on the flow of fluid and cuttings through the junk slot. 
         [0026]    Raising a nozzle above the bit body  410  surface may place the nozzle face closer to the cutting end of the bit and thus decrease the distance traveled by the drilling fluid from the nozzle to the cutting elements. By decreasing the distance between a nozzle and the cutting elements, the drilling fluid may have a higher velocity when contacting the cutting end of the bit and therefore increase the cleaning and cooling of the cutting end features of the bit. As shown in  FIG. 4 , the material underlying the transition surface  445  and surrounding the nozzle  446  that extends away from surrounding surface of the bit body  410 , e.g., the raised body portion, may have a varying width (w) along its height (h), such that the thickness tapers towards the distal end of the nozzle bore  440 . For example, height may be defined as the height of the portion that protrudes above the bit face and the width may be the width of the material between the bore and the transition surface above the bit face. In some embodiments, the height (h) and the width (w) may range from about a 3:1 to about a 1:3 ratio. In such embodiments, this raised portion width may vary continuously (e.g., at a linear slope or at an exponential slope) or incrementally (e.g., stepwise at several different slopes) along its height, and may be symmetrical or asymmetrical about a nozzle longitudinal axis. 
         [0027]      FIG. 5  illustrates a partial cross-sectional view of a drill bit  500  according to embodiments of the present disclosure. As shown in  FIG. 5 , the bit body  510  contains a fluid plenum  525  within to allow drilling fluid from the drill string to flow through the bit via at least one fluid flow passageway  530  extending from the fluid plenum  525  to at least one nozzle bore  540 . In contrast to the embodiment illustrated in  FIG. 4 , nozzle bore  540  is entirely recessed within the bit body  510  and does not extend beyond the surrounding surface of bit body  510 . However, as illustrated in  FIG. 5 , the drill bit  500  may include at least one raised nozzle  546  retained within recessed nozzle bore  540 , and raised nozzle  546  extends beyond the surface of bit body  510 . That is, nozzle  546  includes a lower portion  551  and an upper portion  553 . In such embodiments, the lower portion  551  attaches to the nozzle bore  540  and extends upwards to a surface of the bit body  510 , and the upper portion  553  extends from an outer surface of the bit body  510  to the nozzle face  547  (the distal end of the nozzle  546 ) and extends outward beyond the diameter of the nozzle bore. The lower portion  551  may be secured in the nozzle bore by a threaded attachment, welding, or other methods to secure a nozzle in a bit body known in the art. As shown in  FIG. 5 , the upper portion  553  may have a varying width (w) along its height (h), wherein the width may vary gradually or incrementally along its height. In some embodiments, the height (h) and the width (w) may range from about a 3:1 to about a 1:3 ratio. In such embodiments, the raised portion may be symmetrical or asymmetrical about a nozzle longitudinal axis. Alternatively, in some embodiments, the nozzle may simply extend upward from the bit face and not have a width wider than the nozzle bore width. 
         [0028]    In embodiments of the present disclosure, including either of the illustrated embodiments, the nozzle face  447 ,  547  may extend at least about 0.25 inches, at least about 0.5 inches, or at least about 0.75 inches from the bit body surface. For example, the nozzle face  447 ,  547  may extend about 0.25 inches to about 4 inches, about 0.25 inches to about 2 inches, about 0.5 inches to about 1 inches, or about 0.5 inches to about 0.75 inches from the bit body surface. In some embodiments, the nozzle face  447 ,  547  may extend a distance such that the nozzle face  447 ,  547  is within about 2.5 inches, about 1.5 inches, or about 0.75 inches from a point on the bottom of the borehole determined by the intersection of the nozzle longitudinal axis and the bottom of the borehole as defined by the cutting profile of the bit. For example, the nozzle face  447 ,  547  may extend a distance such that the nozzle face  447 ,  547  is within about 0.25 inches and about 2.5 inches, about 0.5 inches and about 2 inches, or about 0.75 inches and about 1.5 inches from a point on the bottom of the borehole determined by the intersection of the nozzle longitudinal axis and the bottom of the borehole as defined by the cutting profile of the bit. In other embodiments, the nozzle face  447 ,  547  may extend an axial distance from the bit body surface ranging from 0 to about 80% (e.g., about 10% to about 70%, about 20% to about 60%, about 30% to about 50%) of the distance from the bit body surface to the nose of adjacent blades. 
         [0029]    It is also within the scope of the present disclosure that the nozzle face  447 ,  547  may be located such that it extends the aforementioned distance from the bit body surface and also be within the aforementioned distance from the bottom of the borehole. According to some embodiments, bit sizes ranging from 5 to 30 inches may have raised nozzles  446 ,  546  such that nozzle face  447 ,  547  extends away from the bit body surface a distance, which may be measured based on the axial distance from the nozzle face and the nose of adjacent blades (defined as being the axially lowermost point along the blade, where the slope of the tangent line is zero). Such axial distance between the nozzle face and nose of the blade may range from less than 10 inches, 8 inches, 4 inches, 2 inches or 1 inch, and in some embodiments, greater than 0.25 inches, 0.5 inches, 1 inch, 2 inches, or 4 inches, where any lower limit can be used in combination with any upper limit. 
         [0030]    Referring back to  FIGS. 2 and 3 , nozzle bores  240  may be formed at various locations on the bit. For example, nozzle bores  240  may be formed proximate to the radial center of the bit cutting end, or bit longitudinal axis L, as shown by nozzle bore  242  in  FIGS. 2 and 3 . In such embodiments, nozzle bores  240  may be located in a radial position corresponding to the cone and/or nose region of the bit. Other nozzle bores  240  may be formed, for example, distant from the radial center of the cutting end, such as shown by nozzle bore  244  in  FIG. 2 . In such embodiments, nozzle bores  240  may be located in a radial position corresponding to the nose and/or shoulder region of the bit. 
         [0031]    According to one or more embodiments, nozzle bores  240  may be formed in the bit body  210  proximate to an adjacent blade, distant from an adjacent blade, or equidistant between adjacent blades. The positions of nozzles and nozzle bores may be designed to optimize the flow of cuttings and/or drilling fluids through the blades and away from the bit. For example, as stated above, nozzle bores may be disposed at various locations within the junk slot areas. As another example, nozzles may be oriented in particular directions such that the nozzle faces  247  form selected angles with respect to the immediately surrounding bit body  210  surface. That is, the nozzles may be angled to point toward the adjacent leading blade face. 
         [0032]    In some embodiments, at least one nozzle bore  240  may be disposed in the bit body  210  adjacent to the trailing face  226  of the plurality of blades  220  and/or in the trailing face  226  of the plurality of blades  220 , where the at least one nozzle bore  240  is oriented towards the cutting elements of the nearest blade. In other embodiments, at least one nozzle bore  240  may be disposed in the bit body  210  adjacent to the leading face  225  of the plurality of blades  220  and/or in the leading face  225  of the plurality of blades  220 , where the at least one nozzle bore  240  is oriented towards the cutting elements of the nearest blade. 
         [0033]    Referring to  FIG. 6 , a partial cross-sectional view of a drill bit  600  according to embodiments of the present disclosure is shown. According to some embodiments, a raised nozzle may impede the flow of drilling fluids and any cuttings from drilling an earthen formation between blades through the junk slots or fluid flow passageways due to its location and/or geometry. In such embodiments, as shown in  FIG. 6 , a flow diverter  610  protruding from bit body  510  may be positioned such that it shields the raised nozzle  546  from drilling fluid and cutting flow  620  flowing through junk slot or fluid flow passageway  630  and diverts the drilling fluid and cutting flow  620  around the raised nozzle  546 . In some embodiments, the flow diverter  610  may have a sloped side  612  to allow the drilling fluid and cutting flow  620  to smoothly flow over a top and/or a side of the flow diverter  610 . The flow diverter  610  may be formed integral with the bit or formed separately from the bit and attached thereto using welding or other methods known in the art to attach elements to a drill bit. If the flow diverter  610  is formed separately from the bit and attached thereto, the flow diverter  610  may be either attached directly to the raised nozzle  546 , attached to the bit body  510  such that the flow diverter  610  is flush with the raised nozzle  546 , or attached to the bit body  510  such that there is a distance between the flow diverter  610  and the raised nozzle  546 . The geometry of the flow diverter  610  may be determined using tools such as computational fluid dynamics (CFD), finite element analysis (FEA), or other methods known in the art to analyze elements of a drill bit during simulation or operation in various applications 
         [0034]    The articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements in the preceding descriptions. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value. 
         [0035]    Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements. 
         [0036]    A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.