Patent Application
20160177630
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.
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.
A conventional drag bit is shown in
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.
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.
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.
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.
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.
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.
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.
Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.
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.
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.
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.
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'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.
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
Referring now to
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
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.
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.
Referring back to
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.
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.
Referring to
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.
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.
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.
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.
| Number | Date | Country | |
|---|---|---|---|
| 62096473 | Dec 2014 | US |
