Patent Grant
7861809
This application claims the benefit of U.S. Provisional Patent Application Ser. No. 60/897,457 filed Jan. 25, 2007, for “ROTARY DRAG BIT,” the entire disclosure of which is hereby incorporated herein by this reference.
This application is also related to U.S. patent application Ser. No. 11/862,440, filed Sep. 27, 2007, for ROTARY DRAG BITS HAVING A PILOT CUTTER CONFIGURATION AND METHOD TO PRE-FRACTURE SUBTERRANEAN FORMATIONS THEREWITH, which claims the benefit of U.S. Provisional Patent Application Ser. No. 60/873,349, filed Dec. 7, 2006, for “ROTARY DRAG BITS HAVING A PILOT CUTTER CONFIGURATION AND METHOD TO PRE-FRACTURE SUBTERRANEAN FORMATIONS THEREWITH. This application is also related to U.S. patent application Ser. No. 12/020,399, filed Jan. 25, 2008, for ROTARY DRAG BIT AND METHODS THEREFOR, which claims the benefit of U.S. Provisional Patent Application Ser. No. 60/897,457 filed Jan. 25, 2007, for ROTARY DRAG BIT. This application is also related to U.S. patent application Ser. No. 12/020,492, filed Jan. 25, 2008, for ROTARY DRAG BIT AND METHODS THERFOR, which claims the benefit of U.S. Provisional Patent Application Ser. No. 60/897,457 filed Jan. 25, 2007, for ROTARY DRAG BIT.
The present invention in several embodiments, relates generally to a rotary drag bit for drilling subterranean formations and, more particularly, to rotary drag bits having select cutter configurations in multiple groupings configured to enhance cutter life and performance. Further, the invention, in other embodiments, relates to a rotary drag bit having a relatively higher blade cutting structure count on a lower blade count bit.
Rotary drag bits have been used for subterranean drilling for many decades, and various sizes, shapes and patterns of natural and synthetic diamonds have been used on drag bit crowns as cutting elements. A drag bit can provide an improved rate of penetration (ROP) over a tri-cone bit in many formations.
Over the past few decades, rotary drag bit performance has been improved with the use of a polycrystalline diamond compact (PDC) cutting element or cutter, comprising a planar diamond cutting element or table formed onto a tungsten carbide substrate under high temperature and high pressure conditions. The PDC cutters are formed into a myriad of shapes including circular, semicircular or tombstone, which are the most commonly used configurations. Typically, the PDC diamond tables are formed so the edges of the table are coplanar with the supporting tungsten carbide substrate or the table may overhang or be undercut slightly, forming a “lip” at the trailing edge of the table in order to improve the cutting effectiveness and wear life of the cutter as it comes into formations being drilled. Bits carrying PDC cutters, which for example, may be brazed into pockets in the bit face, pockets in blades extending from the face, or mounted to studs inserted into the bit body, have proven very effective in achieving a ROP in drilling subterranean formations exhibiting low to medium compressive strengths. The PDC cutters have provided drill bit designers with a wide variety of improved cutter deployments and orientations, crown configurations, nozzle placements and other design alternatives previously not possible with the use of small natural diamond or synthetic diamond cutters. While the PDC cutting element improves drill hit efficiency in drilling many subterranean formations, the PDC cutting element is nonetheless prone to wear when exposed to certain drilling conditions, resulting in a shortened life of a rotary drag bit using such cutting elements.
Thermally stable diamond (TSP) is another type of synthetic diamond, PDC material which can be used as a cutting element or cutter for a rotary drag bit. TSP cutters, which have had catalyst used to promote formation of diamond-to-diamond bonds in the structure removed therefrom, have improved thermal performance over PDC cutters. The high frictional heating associated with hard and abrasive rock drilling applications, creates cutting edge temperatures that exceed the thermal stability of PDC, whereas TSP cutters remain stable at higher operating temperatures. This characteristic also enables them to be furnaced into the face of a matrix-type rotary drag bit.
While the PDC or TSP cutting elements provide better ROP and manifest less wear during drilling as compared to some other cutting element types, it is still desirable to further the life of rotary drag bits and improve cutter life regardless of the cutter type used. Researchers in the industry have long recognized that as the cutting elements wear, i.e., wearflat surfaces develop and are formed on each cutting element coming in contact with the subterranean formation during drilling, the penetration rate (or ROP) decreases. The decrease in the penetration rate is a manifestation that the cutting elements of the rotary drag bit are wearing out, particularly when other drilling parameters remain constant. Various drilling parameters include formation type, weight on bit (WOB), cutter position, cutter rake angle, cutter count, cutter density, drilling temperature and drill string RPM, for example, without limitation, and further include other parameters understood by those of ordinary skill in the subterranean drilling art.
While researchers continue to develop and seek out improvements for longer lasting cutters or generalized improvements to cutter performance, they fail to accommodate or implement an engineered approach to achieving longer drag bit life by maintaining or increasing ROP by taking advantage of cutting element wear rates. In this regard, while ROP is many times a key attribute in identifying aspects of the drill bit performance, it would be desirable to utilize or take advantage of the nature of cutting element wear in extending or improving the life of the drag bit.
One approach to enhancing bit life is to use the so-called “backup” cutter to extend the life of a primary cutter of the drag bit particularly when subjected to dysfunctional energy or harder, more abrasive, material in the subterranean formation. Conventionally, the backup cutter is positioned in a second cutter row, rotationally following in the path of a primary cutter, so as to engage the formation should the primary cutter fail or wear beyond an appreciable amount. The use of backup cutters has proven to be a convenient technique for extending the life of a bit, while enhancing stability without the necessity of designing the bit with additional blades to carry more cutters which might resultantly decrease ROP and which potentially compromises bit hydraulics due to reduced available fluid flow area over the bit face and less-than-optimum fluid flow due to unfavorable placement of nozzles in the bit face. Conventionally, it is understood by a person of skill in the art that a drag bit will experience less wear as the blade count is increased and undesirably will have slower ROP, while a drag bit with a lower blade count, with its faster ROP, is subjected to greater wear. Also, it is believed that conventional backup cutters in combination with their associated primary cutters may undesirably lead to balling of the blade area with formation material. Accordingly, it would be desirable to utilize or take advantage of the use of backup cutters to increase the durability of the drag bit while providing increased ROP and without compromising bit hydraulics and formation cuttings removal. It would also be desirable to provide a drag bit having an improved, less restricted, flow area by further decreasing the number of blades conventionally required in order to achieve a more durable blade. Durability may be quantified in terms of cutter placement, and may further be considered in terms of the ability to maintain the sharpness of each cutter for a longer period of time while drilling. In this sense, “sharpness” of each cutter involves improving wear of the diamond table, including less chipping or damage to the diamond table caused by point loading, dysfunctional energy or drill string bounce.
Conventional wisdom is that providing backup cutters may cause the blade of the bit to ball with formation material because of either reduced flow area or because of physical limitations associated with each blade, even though the backup cutters may increase the life and overall performance to the drag bit. Accordingly, it would be desirable to overcome the physical limitations associated with blade number, placement and configuration to provide an improved drag bit. There is a further desire to improve the fluid flow over the bit face, increase the flow area and to decrease the number of blades while maintaining or enhancing the drag bit performance.
A three bladed conventional bit will not last as long as a six bladed conventional bit because the former has fewer primary cutters. Conventionally, in order to drill faster, a lighter blade set, i.e., fewer blades, are desired. However, in order to drill further with conventional bits, more primary cutters are needed, which necessitates the use of more blades. Because it is desirable to provide a drag bit that will drill further irrespective of the drilling speed, it is also desirable to provide a drag bit with a lighter blade set while achieving further drilling distances. In this respect, it is desirable to provide a drag bit that drills faster and further compared with conventional drag bits.
Accordingly, there is an ongoing desire to improve or extend rotary drag bit life and performance regardless of the subterranean formation type being drilled. There is a further desire to extend the life of a rotary drag bit by beneficially orienting and positioning cutters upon the bit body.
Accordingly, embodiments of a rotary drag bit include a primary cutter row comprising at least one primary cutter and a multiple backup cutter group comprising first and second trailing cutter rows, each comprising at least one cutter positioned to follow the at least one primary cutter is provided. The rotary drag bit life is extended by the multiple backup cutter group, making the bit more durable and extending the life of the cutters. Further, the cutters of the multiple backup cutter group are configured to selectively engage and fracture a subterranean formation material being drilled, providing improved bit life and reduced stress upon the cutters.
In an embodiment of the invention, a rotary drag bit includes a primary cutter row comprising at least one primary cutter and a multiple backup cutter group comprising at least one multiple cutter set positioned so as to substantially follow the at least one primary cutter along a cutting path.
In another embodiment of the invention, a rotary drag bit includes a primary cutter row comprising at least one primary cutter, a first trailing cutter row comprising at least one first cutter and a second trailing cutter row comprising at least one second cutter, the first cutter and the second cutter are positioned so as to substantially follow the primary cutter.
In a further embodiment of the invention, a rotary drag bit includes an inline cutter set comprising a primary cutter, a first backup cutter and a second backup cutter coupled to one blade of the bit.
In yet another embodiment of the invention, a rotary drag bit includes a staggered cutter set comprising a primary cutter and a first backup cutter coupled to one blade of the bit.
In still another embodiment of the invention, a rotary drag bit includes a first cutter row comprising a plurality of first cutters, a second cutter row comprising a plurality of second cutters and a third cutter row comprising a plurality of third cutters, each third cutter positioned so as to substantially follow one of the first cutters and the second cutters of the second cutter row underexposed with respect to the first cutters of the first cutter row.
In yet a further embodiment of the invention, a rotary drag bit includes a first cutter row comprising at least one first primary cutter having a first cutting path and a second cutter row rotationally following the first cutter row, the second cutter row comprising at least one second primary cutter having a second cutting path where the second cutting path is rotationally distinct from the first cutting path.
In still a further embodiment of the invention, a rotary drag bit includes a primary cutter row comprising a plurality of primary cutters and a second cutter row comprising a plurality of second cutters positioned so as to substantially follow one of the first cutters along a cutting path and one of the second cutters being variably underexposed with respect to another one of the plurality of second cutters.
Other advantages and features of the present invention will become apparent when viewed in light of the detailed description of the various embodiments of the invention when taken in conjunction with the attached drawings and appended claims.
In embodiments of the invention to be described below, rotary drag bits are provided that may drill further, may drill faster or may be more durable than rotary drag bits of conventional design. In this respect, each drag bit is believed to offer improved life and greater performance regardless of the subterranean formation material being drilled.
The rotary drag bit 110 as viewed by looking upwardly at its face or leading end 112 as if the viewer were positioned at the bottom of a bore hole. Drag bit 110 includes a plurality of cutting elements or cutters 114 bonded, as by brazing, into pockets 116 (as representatively shown) located in the blades 131, 132, 133 extending above the face 112 of the drag bit 110. While the cutters 114 are bonded to the pockets 116 by brazing, other attachment techniques may be used as is well known to those of ordinary skill in the art. The cutters 114 coupled to their respective pockets 116 are generally represented upon the drag bit 110, but specific cutters, including their attributes, will be called out by different reference numerals below to provide a more detailed presentation of the invention. The drag bit 110 in this embodiment is a so-called “matrix” body bit. Optionally, the bit may also be a steel or other bit type, such as a sintered metal carbide. “Matrix” bits include a mass of metal powder, such as tungsten carbide particles, infiltrated with a molten, subsequently hardenable binder, such as a copper-based alloy. Steel bits are generally made from a forging or billet and machined to a final shape. The invention is not limited by the type of bit body employed for implementation of any embodiment thereof.
Fluid courses 120 lie between blades 131, 132, 133 and are provided with drilling fluid by ports 122 being at the end of passages leading from a plenum extending into a bit body 111 from a tubular shank at the upper, or trailing, end of the drag bit 110. The ports 122 may include nozzles (not shown) secured thereto for enhancing and controlling flow of the drilling fluid. Fluid courses 120 extend to junk slots 126 extending upwardly along the longitudinal side 124 of drag bit 110 between blades 131, 132, 133. Gage pads (not shown) comprise longitudinally upward extensions of blades 131, 132, 133 and may have wear-resistant inserts or coatings on radially outer surfaces 121 thereof as known in the art. Formation cuttings are swept away from the cutters 114 by drilling fluid (not shown) emanating from ports 122 and which moves generally radially outwardly through fluid courses 120 and then upwardly through junk slots 126 to an annulus between the drill string from which the drag bit 110 is suspended and supported. Advantageously, the drilling fluid provides cooling to the cutters 114 during drilling and clears formation cuttings from the bit face 112.
Each of the cutters 114 in this embodiment are PDC cutters. However, it is recognized that any other suitable type of cutting element may be utilized with the embodiments of the invention presented. For clarity in the various embodiments of the invention, the cutters are shown as unitary structures in order to better describe and present the invention. However, it is recognized that the cutters 114 may comprise layers of materials. In this regard, the PDC cutters 114 of the current embodiment each comprise a diamond table bonded to a supporting substrate, as previously described. The PDC cutters 114 remove material from the underlying subterranean formations by a shearing action as the drag bit 110 is rotated by contacting the formation with cutting edges 113 of the cutters 114. As the formation is cut, the flow of drilling fluid comminutes the formation cuttings and suspends and carries the particulate mix away through the junk slots 126 mentioned above.
The blades 131, 132, 133 are each considered to be primary blades. The blade 131, as with blades 132, 133, in general terms of a primary blade, includes a body portion 134 that extends (longitudinally and radially projects) from the face 112 and is part of the bit body 111 (the bit body 111 is also known as the “frame” of the drag bit 110). Reference may also be made to
The drag bit 110 in this embodiment of the invention includes three primary blades 131, 132, 133, but does not include any secondary or tertiary blades as are known by a person of skill in the art. A secondary blade or a tertiary blade provides additional support structure in order to increase the cutter density of the drag bit 110 by receiving additional primary cutters 114 thereon. A secondary or a tertiary blade is defined much like a primary blade, but radially extends toward the gage region generally from a nose region 162, a flank region 163 or a shoulder region 164 of the drag bit 110. In this regard, a secondary blade or a tertiary blade is defined between leading and trailing fluid courses 120 in fluid communication with at least one of the ports 122. Also, a secondary blade or a tertiary blade, or a combination of secondary and tertiary blades may be provided between primary blades. However, the presence of secondary or tertiary blades decreases the available volume of the adjacent fluid courses 120, providing less clearing action of the formation cuttings or cleaning of the cutters 114. Optionally, a drag bit 110 in accordance with an embodiment of the invention may include one or more secondary or tertiary blades when needed or desired to implement particular drilling characteristics of the drag bit.
The three cutter rows 141, 142, 143 are arranged upon the three blades 131, 132, 133, respectively. Each cutter row 141, 142, 143 is a primary cutter row as is understood by a person having ordinary skill in the art. Rotationally trailing each of the primary cutter rows 141, 142, 143 on each of the blades 131, 132, 133 are multiple backup cutter groups 151, 152, 153, respectively. While each blade includes a primary cutter row rotationally followed by a multiple backup cutter group in this embodiment, the drag bit 110 may have a multiple backup cutter group selectively placed behind a primary cutter row on at least one of the blades of the bit body 111. Further, the drag bit 110 may have a multiple backup cutter group selectively placed on multiple blades of the bit body 111.
Each of the multiple backup cutter groups 151, 152, and 153 may have one or more multiple backup cutter sets. For example, without limitation, the multiple backup cutter group 152 includes three multiple backup cutter sets 152′, 152″, 152′″. While, multiple backup cutter group 152 includes three multiple backup cutter sets 152′, 152″, 152′″, it is contemplated that the drag bit 110 may include one multiple backup cutter set or a plurality of backup cutter sets in each multiple backup cutter group greater or less than the three illustrated.
Each of the multiple backup cutter sets 152′, 152″, 152′″, in this embodiment of the invention, comprises a first trailing cutter row 154, a second trailing cutter row 155, and a third trailing cutter row 156. Each of the cutter rows 141, 142, 143, 154, 155, 156 includes a plurality of cutters 114 positionally coupled to the blades 131, 132, 133. Optionally, each row may comprise one or more cutters 114. A cutter row may be determined by a radial path extending from the centerline C/L (the centerline is extending out of
The primary cutter row 142 of blade 132 comprises cutters 3, 6, 11, 19, 28, 37, 46, 50. Each of the multiple backup cutter sets 152′, 152″, 152′″ respectively include cutters 12, 20, 29, 38 from the first trailing cutter row 154, cutters 21, 30, 39 from the second trailing cutter row 155, and cutters 57, 58, 59 from the third trailing cutter row 156. The first trailing cutter row 154 rotationally trails the primary cutter row 142 and rotationally leads the second trailing cutter row 155, which rotationally leads the third trailing cutter row 156. While each multiple backup cutter sets 152′, 152″, 152′″ of this embodiment includes cutters 114 in trailing cutter rows 154, 155, 156, they may have a first cutter row rotationally followed by one or more additional cutter rows only being limited by the available blade surface 135 on the blade 132. In this regard, the multiple backup cutter set 152′ includes three cutters 20, 21, 57 from three trailing cutter rows 154, 155, 156, respectively. While three cutters 20, 21, 57 are included in the multiple backup cutter set 152′, it is contemplated that each multiple backup cutter set may include cutters from a plurality of trailing cutter rows.
The blade and cutter profile of
The cutters 12, 20, 29, 38, 47 of the first trailing cutter row 154 each rotationally trail the cutters 11, 19, 28, 37, 46 of the primary cutter row 142, respectively, and are considered to be backup cutters in this embodiment. Backup cutters rotationally follow a primary cutter in substantially the same rotational path, at substantially the same radius from the centerline C/L in order to increase the durability and life of the drag bit 110 should a primary cutter fail or wear beyond its usefulness. However, the cutters 12, 20, 29, 38, 47 of the first trailing cutter row 154 may be any assortment or combination of primary, secondary and backup cutters. While the present embodiment does not include any secondary cutters, a secondary cutter may rotationally follow primary cutters in adjacent rotational paths, at varying radiuses from the centerline C/L in order to remove larger kerfs between primary cutters providing increased rate of penetration and durability of the drag bit 110. Depending upon the cutter assortment, the cutters 12, 20, 29, 38, 47 may be spaced along their rotational paths at various radial positions in order to enhance cutter performance when engaging the material of a particular subterranean formation. Further, the cutters 12, 20, 29, 38, 47, rotationally trailing the cutters 11, 19, 28, 37, 46, are underexposed with respect to the cutters 11, 19, 28, 37, 46. Specifically, the cutters 12, 20, 29, 38, 47 are underexposed by twenty-five thousandths of an inch (0.025).
The cutters 21, 30, 39 of the second trailing cutter row 155 each rotationally trail the cutters 19, 28, 37 of the primary cutter row 142, respectively, and are also considered to be backup cutters to the primary cutter row 142 in this embodiment. Optionally, the cutters 21, 30, 39 may be backup cutters to the cutters 20, 29, 38 of the first trailing cutter row 154 or a combination of the first trailing cutter row 154 and the primary cutter row 142. While the cutters 21, 30, 39 are backup cutters, the cutters 21, 30, 39 of the second trailing cutter row 55 may be any assortment or combination of primary, secondary and backup cutters. Further, the cutters 21, 30, 39, rotationally trailing the cutters 19, 28, 37, are underexposed with respect to the cutters 19, 28, 37. Specifically, the cutters 21, 30, 39 are underexposed by fifty thousandths of an inch (0.050).
The cutters 57, 58, 59 of the third trailing cutter row 156 each rotationally trail the cutters 19, 28, 37 of the primary cutter row 142, respectively, and are also backup cutters to the primary cutter row 142 in this embodiment. Optionally, the cutters 57, 58, 59 may be backup cutters to the cutters 21, 30, 39 of the second trailing cutter row 155 or a combination of the second trailing cutter row 155, the first trailing cutter row 154 and the primary cutter row 142. While the cutters 57, 58, 59 are backup cutters, the cutters 57, 58, 59 of the third trailing cutter row 156 may be any assortment or combination of primary, secondary and backup cutters. Further, the cutters 57, 58, 59, rotationally trailing the cutters 19, 28, 37, are underexposed with respect to the cutters 19, 28, 37. Specifically, the cutters 57, 58, 59 are underexposed by seventy-five thousandths of an inch (0.075).
Optionally, in embodiments of the invention to be further described below, each of the cutters 12, 20, 29, 38, 47, 21, 30, 39, 57, 58, 59 may have different underexposures or little to no underexposure with respect the cutters 114 of the primary cutter row 142 irrespective of each of the other cutters 12, 20, 29, 38, 47, 21, 30, 39, 57, 58, 59.
The cutters 114 of the first trailing cutter row 154, the second trailing cutter row 155 and the third trailing cutter row 156 are smaller than the cutters 114 of the primary cutter rows 141, 142, 143. The smaller cutters 114 of the cutter rows 154, 155, 156 are able to provide backup support for the primary cutter rows 141, 142, 143 when needed, but also provide reduced rotational contact resistance with the material of a formation when the cutters 114 are not needed. While the smaller cutters 114 of the first trailing cutter row 154, the second trailing cutter row 155 and the third trailing cutter row 156 are all the same size, it is contemplated that each cutter size may be greater or smaller than that illustrated. Also, while the cutters 114 of each cutter row 154, 155, 156 are all the same size, it is contemplated that the cutter size of each cutter row may be greater or smaller than the other cutter rows.
In an embodiment of the invention, one or more additional backup cutter rows may be included on a blade of a rotary drag bit rotationally following and in further addition to a primary cutter row and a backup cutter row. The one or more additional backup cutter rows in this aspect of the invention are not a second cutter row, a third cutter row or an nth cutter row located on subsequent blades of the drag bit. Each of the one or more additional backup cutter rows, the backup cutter row and the primary cutter row include one or more cutting elements or cutters on the same blade. Each of the cutters of the one or more additional backup cutter rows may align or substantially align in a concentrically rotational path with the cutters of the row that rotationally leads it. Optionally, each cutter may radially follow slightly off-center from the rotational path of the cutters located in the backup cutter row and the primary cutter row.
In embodiments of the invention, each additional backup cutter row may have a specific exposure with respect to a preceding cutter row on a blade of a drag bit. For example, each cutter row may incrementally step-down in values from a preceding cutter row, in this respect each cutter row is progressively underexposed with respect to a prior cutter row. Optionally, each subsequent cutter row may have an underexposure to a greater or lesser extent from the cutter row preceding it. By adjusting the amount of underexposure for the cutter rows, the cutters of the backup cutter rows may be engineered to come into contact with the material of the formation as the wear flat area of the primary cutters increases. In this respect, the cutters of the backup cutter rows are designed to engage the formation as the primary cutters wear in order to increase the life of the drag bit. Generally, a primary cutter is located typically on the front of a blade to provide the majority of the cutting work load, particularly when the cutters are less worn. As the primary cutters of the drag bit are subjected to dynamic dysfunctional energy or as the cutters wear, the backup cutters in the backup cutter rows begin to engage the formation and begin to take on or share the work from the primary cutters in order to better remove the material of the formation.
In accordance with embodiments of the invention,
In accordance with embodiments of the invention,
In accordance with embodiments of the invention, a cutter set may include a plurality of cutters 214 having at least one cutter radially staggered or offset from the other cutters 214 and at least one cutter rotationally inline with a preceding cutter.
In order to improve the life of the drag bit 210, each of the cutters 214 of the second cutter rows 251 may be oriented inline, offset, underexposed, or staggered, or a combination thereof, for example, without limitation, relative to each of their respective cutters 214 of the first cutter row 241. In this regard, a cutter 214 of a second cutter row 251 may assist and support a cutter 214 of the first cutter row 241 by removing material from the formation and still provide backup support should the cutter 214 of the first cutter row 214 fail. In this embodiment of the invention, the second cutter rows 251 include cutters 214 that are inline, offset, staggered, and underexposed on each of the blades 231, 231′, 232, 232′, 233, 233′. Discussion of the second cutter rows 251 of the blades 231, 231′, 232, 232′, 233, 233′ will now be taken in turn.
As shown in
As shown in
As shown in
As shown in
In accordance with embodiments of the invention, a plurality of staggered cutters may have uniform underexposure or may be uniformly staggered with respect to primary cutters. In this regard, the staggered cutters may have substantially the same underexposure or amount of offset, i.e., staggering, with respect to each of the other staggered cutters. Also, it is contemplated that one or more staggered cutter rows may be provided beyond the second cutter row 251 illustrated, the one or more staggered cutter rows may include non-uniformly distributed staggered cutters having different underexposures with respect to other staggered cutters within the second cutter row 251. Further contemplated, the second cutter row 251 may include cutters 214 having underexposures non-linearly distributed along a staggered cutter row extending radially outward from the centerline C/L of the drag bit 210.
The cutters 314 in cutter rows 341, 342, 343 are fully exposed cutters as shown in
Specific cutter profiles for each of the blades 331, 332, 333 are shown in
The cutters 314 are inclined, i.e., have a backrake angle, at 15 degrees backset from the normal direction with respect to the rotational path each cutter travels in the drag bit 310 as would be understood by a person having ordinary skill in the art. It is anticipated that each of the cutters 314 may have more or less aggressive backrake angles for particular applications different from the 15 degree backrake angle illustrated.
As shown in
The multi-layer cutter group 352 of blade 332 comprises three inline cutter sets 371, 373, 374 and three staggered cutter sets 381, 383, 385 as shown in
As shown in
In embodiments of the invention, a drag bit may include one or more multi-layer cutter groups to improve the life and performance of the bit. Specifically, a multi-layer cutter group may be included on one or more blades of a bit body, and further include one or more multi-exposure cutter rows, one or more staggered cutter sets, or one or more inline cutter sets, in any combination without limitation.
In embodiments of the invention, a multi-layer cutter groups may include cutter sets or cutter rows having different cutter sizes in order to improve, by reducing, the resistance experienced by a drag bit when a backup cutter follows a primary cutter. In this regard, a smaller backup cutter is better suited for following a primary cutter that is larger in diameter in order to provide a smooth concentric motion as a drag bit rotates. In one aspect, by decreasing the diameter size of each backup cutter from a ⅝ inch cutter diameter of the primary cutter to ½ inch, 11 millimeters, or ⅜ inch cutter, for example, without limitation, there is less interfering contact with the formation while removing material in a rotational path created by primary cutters. In another aspect, by providing backup cutters with smaller cutter size, there is decreased formation contact with the non-cutting surfaces of the backup cutters, which improves the ROP of the drag bit.
In embodiments of the invention, a cutter of a backup cutter row may have a backrake angle that is more or less aggressive than a backrake angle of a cutter on a primary cutter row. Conventionally, in order to maintain the durability of a primary cutter a less aggressive backrake angle is utilized; while giving up cutter performance, the less aggressive backrake angle made the primary cutter more durable and less likely to chip when subjected to dysfunctional energy or string bounce. By providing backup cutters in embodiments of the invention, a more aggressive backrake angle may be utilized on the backup cutters, the primary cutters or on both. The combined cutters provide improved durability allowing the backrake angle to be aggressively selected in order to improve the overall performance of the cutters with less wear or chip potential caused by vibrational effects when drilling.
In embodiments of the invention, a cutter of a backup cutter row may have a chamfer that is more or less aggressive than a chamfer of a cutter on a primary cutter row. Conventionally, in order to maintain the durability of a primary cutter a longer chamfer was utilized, particularly when a more aggressive backrake angle was used on a primary cutter. While giving up cutter performance, the longer chamfer made the primary cutter more durable and less likely to fracture when subjected to dysfunctional energy while cutting. By providing backup cutters, a more aggressive, i.e., shorter, chamfer may be utilized on the backup cutters, the primary cutters or on both in order to increase the cutting rate of the bit. The combined cutters provide improved durability allowing the chamfer lengths to be more or less aggressive in order to improve the overall performance of the cutters with less fracture potential also caused by vibrational effects when drilling.
In embodiments of the invention, a drag bit may include a cutter coupled to a cutter pocket of a blade, the cutter having a siderake angle with respect to the rotational path of the cutter. In one example,
In embodiments of the invention, a cutting structure may be coupled to a blade of a drag bit, providing a larger diameter primary cutter placed at a front of the blade followed by one or more multiple rows of smaller diameter cutters either in substantially the same helical path or some other variation of cutter rotational tracking. The smaller diameter cutters, that rotationally follow the primary cutter, may be underexposed to different levels related to depth-of-cut or wear characteristics of the primary cutter so that the smaller cutters may engage the material of the formation at a specific depth of cut or after some worn state is achieved on the primary cutter. Depth of cut control features as described in U.S. Pat. No. 7,096,978 entitled “Drill Bits With Reduced Exposure of Cutters,” the disclosure of which is incorporated herein by this reference, may be utilized in embodiments of the invention.
In
The drag bit 404 comprises three blades and three rows of cutters on each blade. The first row of cutters is a primary row of cutters rotationally followed by two staggered cutter rows, in which the cutters of the first staggered cutter row are underexposed by twenty-five thousandths of an inch (0.025) and the cutters of the second staggered cutter row are underexposed by fifty thousandths of an inch (0.050).
The drag bit 405 comprises three blades and three rows of cutters on each blade. The first row of cutters is a primary row of cutters rotationally followed by two inline cutter rows, in which the cutters of the first inline cutter row are underexposed by fifty thousandths of an inch (0.050) and the cutters of the second inline cutter row are underexposed by fifty thousandths of an inch (0.050).
The drag bit 406 comprises three blades and three rows of cutters on each blade. The first row of cutters is a primary row of cutters rotationally followed by two inline cutter rows, in which the cutters of the first inline cutter row are underexposed by twenty-five thousandths of an inch (0.025) and the cutters of the second inline cutter row are underexposed by twenty-five thousandths of an inch (0.025).
Conventional drag bit 407 comprises six blades and a single row of primary cutters on each of the blades. Conventional drag bit 408 comprises four blades with a primary row of cutters and a backup row of cutters on each of the blades. Conventional drag bit 409 comprises five blades and a single row of primary cutters on each of the blades. Conventional drag bit 410 comprises three blades with a primary row of cutter and a backup row of cutters on each of the blades.
Comparing
Optionally, while the fourth embodiment of the invention includes three blades 531, 532, 533, the drag bit may include one or more primary blades on the drag bit. Also, one or more additional or backup cutter rows may be provided that include secondary, backup or multiple backup cutters upon at least one of the blades 531, 532, 533 beyond the first cutter rows 541, 542, 543 and the second cutter rows 544, 545, 546, respectively, as illustrated. In this respect, the fourth embodiment of the invention may include aspects of other embodiments of the invention.
The cutters 514 in cutter rows 541, 542, 543, 544, 545, 546 are fully exposed primary cutters as shown in
Each of cutters 514 are inclined, i.e., have a backrake angle, ranging between about 15 and about 30 degrees backward rotation from the normal direction with respect to the rotational path each cutter travels in the drag bit 510 as would be understood by a person having ordinary skill in the art. It is contemplated that each of the cutters 514 may have more or less aggressive backrake angles for particular applications different from the backrake angle illustrated. In another aspect, it is also contemplated that the backrake angle for the cutters 514 coupled substantially on each blade surface 535 in the second cutter rows 544, 545, 546 may have more or less aggressive backrake angles relative to the cutters 514 of the first cutter rows 541, 542, 543 which are coupled substantially toward a leading face 534 and subjected to more dysfunctional energy during formation drilling.
A chamfer 515 is included on a cutting edge 513 of each of the cutters 514. The chamfer 515 for each cutter may vary between a very shallow, almost imperceptible surface for a more aggressive cutting structure up to a depth of ten thousandths of an inch (0.010) or sixteen thousandths of an inch (0.016), or even deeper for a less aggressive cutting structure as would be understood by a person having ordinary skill in the art. It is contemplated that each chamfer 515 may have more or less aggressive width for particular radial placement of each cutter 514, i.e., cutter placement in a cone region 560 a nose region 562, a flank region 563, a shoulder region 564 or a gage region 565 of the drag bit 510 (see
Faster penetration rate, or ROP, is obtained when drilling a formation with the drag bit 510. Conventional drag bits experience more wear upon cutters as the blade count decreases and the ROP increases. By providing the drag bit 510 with the number of blades decreased from a conventional higher bladed bit, such as six blades, to the three blades 531, 532, 533 as illustrated, there is a performance increase in cutter wear and ROP. The lower blade count allows the blade surface 535 of each blade 531, 532, 533 to be widened, which provides space for increasing the cutter density or volume upon each blade, i.e., achieving an equivalent cutter density of a six bladed drag bit upon a three bladed drag bit. By increasing the cutter density or volume of primary cutters 514 on each blade 531, 532, 533, particularly in certain radial locations where the workload on each cutter is more pronounced, the cutters 514 wear at a slower rate for a faster ROP. Also, by providing the decreased number of blades 531, 532, 533 more nozzles for providing increased fluid flow may be provide for each blade in order to handle more cuttings created from the material of the formation being drilled. By increasing the hydraulic horsepower provided from the nozzles to the blades to clean the cutters 514, the ROP is further increased. Moreover, by providing a drag bit 510 with fewer blades and multiple rows of primary cutters, the hydraulic cleaning of the drag bit 510 is enhanced to provide increased ROP while obtaining the durability of the conventional heavier bladed drag bit without the resultant lower ROP.
In one aspect of the fourth embodiment of the invention, a cutting structure of an X bladed drag bit is placed upon a Y bladed drag bit, where Y is less than X and the cutters 514 of the cutting structure are each coupled to the Y bladed drag bit on adjacent or partially overlapping rotational or helical paths. By providing the cutting structure of the X bladed drag bit upon the Y bladed drag bit, the durability of the X bladed drag bit is achieved on the Y bladed drag bit while achieving the higher penetration rate or efficiency of the Y bladed drag bit.
In order to improve the life of the drag hit 610, each of the cutters 614 of the second cutter rows 651 may be oriented inline, offset, underexposed, or staggered, or a combination thereof, for example, without limitation, relative to each of their respective cutters 614 of the first cutter row 641. In this regard, a cutter 614 of a second cutter row 651 may assist and support a cutter 614 of the first cutter row 641 by removing material from the formation and still provide backup support should the primary cutter 614 of the first cutter row 641 fail.
In this embodiment of the invention, the second cutter rows 651 include cutters 614 that are variably underexposed on each of the blades 631, 631′, 632, 632′, 633, 633′. By providing the cutters 614 that are variably underexposed, each cutter 614 may engage material of the formation at different wear states of the primary cutters 614 of the first cutter rows 641 while providing backup support therefore. Discussion of the second cutter rows 651 of the blades 631, 631′, 632, 632′, 633, 633′ will now be taken in turn.
As shown in
As shown in
As shown in
As shown in
In accordance with embodiments of the invention, a plurality of secondary cutting elements may be variably underexposed in one or more backup cutter rows radially extending outward from the centerline C/L of the drag bit 610 in order to provide a staged engagement of the cutting elements with the material of a formation as a function of the wear of a plurality of primary cutting elements. Also, the secondary cutting elements may be variably underexposed in one or more backup cutter rows to provide backup coverage to the primary cutters in the event of primary cutter failure.
In
In the embodiments of the invention described above, select cutter configurations for placement upon a rotary drag bit have been explored. The select cutter configurations may be optimized to have placement based upon optimizing depth of cut and rock removal strategy. Such a strategy would enable design of a cutting structure having the most optimal load sharing and vibration mitigation between select primary and backup cutters. Conventionally, backup cutters are placed upon a drag bit at a set distance behind with a uniform underexposure with respect to their primary cutters that they follow. By implementing a rock removal strategy, the placement of the primary cutters and secondary cutters may be optimized to effectively balance the load and rock removal of the drag bit for improved performance and life. Essentially, the placement of each cutter in cutter rows upon a blade of a drag bit is optimized to provide the optimal siderake, cutter placement, cutter size, backrake, exposure, chamfer or spacing with respect to the other cutters in order to facilitate the optimization of the drag bit for drilling faster further.
In the embodiments of the invention described above, select backup cutters for placement upon a rotary drag bit have been explored. Particularly, select backup cutters placed upon the same blade of the rotary drag bit as with the primary or secondary cutters to which they are associated. It is recognized that a backup cutter may, optionally, be placed upon a blade different from the blade to which the primary or secondary cutter is associated. In this respect, a primary or a secondary cutter may be placed upon one blade and a backup cutter may be placed upon another blade.
While particular embodiments of the invention have been shown and described, numerous variations and alternate embodiments will occur to those skilled in the art. Accordingly, it is intended that the invention be limited only in terms of the appended claims and their legal equivalents.
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