Patent Grant
10494875
The present invention relates generally to impregnated drag bits for drilling earth formations and, more particularly, to the manner in which the blades and fluid channels on the bit are formed and configured.
So-called “impregnated” drag bits are used conventionally for drilling hard and/or abrasive rock formations, such as sandstones. Such conventional impregnated drill bits typically employ a cutting face having blades or inserts comprising superabrasive cutting particles, such as natural or synthetic diamond grit, dispersed within a metal or metal alloy matrix material. As such a bit drills, the matrix material wears away, exposed cutting particles are lost as the surrounding matrix material to which the particles are mechanically and metallurgically bonded is removed, and new cutting particles previously buried within the matrix material become exposed. These diamond particles may be cast integrally with the body of the bit, as in a low-pressure infiltration process to form blades comprising the diamond particles and matrix material, or inserts comprising the diamond particles and matrix material may be preformed separately from the bit body, such as in a hot isostatic press (HIP) sintering process, and the inserts may be attached subsequently to the bit body by brazing. In other processes, such preformed inserts may be placed within a mold in which the bit body is cast using an infiltration process. In such a process, the inserts become bonded to the bit body as the bit body is formed over and around the inserts.
Conventional impregnated bits generally exhibit a poor hydraulics design by employing what is referred to in the industry as a “crow's foot” to distribute drilling fluid across the bit face and providing only minimal flow area. Further, conventional impregnated bits do not drill effectively when the bit encounters softer and less abrasive layers of rock, such as shales. When drilling through shale, or other soft formations, with a conventional impregnated drag bit, the cutting structure tends to quickly clog or “ball up” with formation material, making the drill bit ineffective. The softer formations can also plug up fluid courses formed in the drill bit, causing heat buildup and premature wear of the bit. Therefore, when shale-type formations are encountered, a more aggressive bit is desired to achieve a higher rate of penetration (ROP). It follows, therefore, that selection of a bit for use in a particular drilling operation becomes more complicated when it is expected that formations of more than one type will be encountered during the drilling operation.
In some embodiments of the present disclosure, an impregnated bit for forming a wellbore in an earth formation includes a bit body having a proximal end, a distal end, and a longitudinal axis. A bit face is located at the distal end and extends between the longitudinal axis and a gage. The bit face comprises at least one blade extending radially outward from the longitudinal axis toward the gage and comprising an outer surface to engage formation material. The outer surface of the at least one blade extends substantially linearly from a distalmost point of the bit face coincident with the longitudinal axis and at an acute angle relative to a line perpendicular to the longitudinal axis of the bit body.
In additional embodiments of the present disclosure, an impregnated bit for forming a wellbore in an earth formation includes a bit body having a proximal end, a distal end, and a longitudinal axis. A bit face is located at the distal end and extends between the longitudinal axis and a gage. The bit face comprises at least one blade extending radially outward from the longitudinal axis toward the gage and comprising an outer surface to engage formation material. The bit face further comprises a first fluid channel recessed within the bit face adjacent the at least one blade and extending radially across the bit face from a radially innermost portion proximate to the longitudinal axis to the gage and a second fluid channel recessed within the bit face adjacent the at least one blade and extending radially across a portion of the bit face from a radially innermost portion located further from the longitudinal axis relative to the radially innermost portion of the first fluid channel to the gage. The bottoms of the first fluid channel and the second fluid channel are recessed equidistant from the outer surface of the at least one blade.
In yet further embodiments of the present disclosure, an impregnated bit for forming a wellbore in an earth formation includes a bit body having a bit face extending between a longitudinal axis and a gage. The bit face comprises a plurality of blades extending radially outward from the longitudinal axis and axially along the gage, wherein the plurality of blades comprises a plurality of pairs of blades circumferentially spaced about the longitudinal axis. The bit face further comprises a first fluid channel extending between circumferentially adjacent pairs of blades and radially across the bit face from a radially innermost portion proximate to the longitudinal axis to the gage and a second fluid channel extending between each blade of the pairs of blades and radially across a portion of the bit face from a radially innermost portion located further from the longitudinal axis relative to the radially innermost portion of the first fluid channel to the gage.
While the specification concludes with claims particularly pointing out and distinctly claiming what are regarded as embodiments of the present disclosure, various features and advantages of embodiments of the disclosure may be more readily ascertained from the following description of example embodiments of the disclosure when read in conjunction with the accompanying drawings, in which:
The illustrations presented herein are not meant to be actual views of any particular drill bit or component thereof, but are merely idealized representations that are employed to describe embodiments of the present disclosure.
As used herein, the term “substantially” in reference to a given parameter, property, or condition means and includes to a degree that one of ordinary skill in the art would understand that the given parameter, property, or condition is met with a degree of variance, such as within acceptable manufacturing tolerances. By way of example, depending on the particular parameter, property, or condition that is substantially met, the parameter, property, or condition may be at least 90.0% met, at least 95.0% met, at least 99.0% met, or even at least 99.9% met.
As used herein, the term “about” in reference to a given parameter is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the given parameter).
As used herein, the term “and/or” includes any and all combinations of one or more of the associated listed items.
In operation, the bit 100 is extended into the wellbore by a drill string connected to a drilling rig located at a surface of the earth formation in which the wellbore is formed. Thus, the bit 100 is inverted from the view of
With continued reference to
In some embodiments, the cutting elements 114 may comprise polycrystalline diamond compact (PDC) cutting elements. The polycrystalline diamond cutting elements 114 may each comprise a supporting substrate 119 having a diamond table 117 thereon. The cutting elements 114 may be oriented to remove material from the underlying earth formation by a shearing action as the drill bit 100 is rotated about the longitudinal axis 102 and by contacting the formation material with cutting edges and cutting surfaces of the cutting elements 114. In some embodiments, the cutting elements 114 may comprise PDC cutting elements offered by DiaroTech SA that include a diamond table and an impregnated substrate. The impregnated substrate may comprise a matrix material having a plurality of abrasive particles including, but not limited to, diamond particles dispersed therein. In operation, the impregnated substrate may provide additional cutting action when the diamond table has at least partially worn away. For example, the impregnated substrate may be self-sharpening such that, as the matrix material of the substrate wears away, superabrasive particles disposed and held therein may be shed and fresh, unworn abrasive particles may be exposed. In such embodiments, the useful life of the cutting elements 114 may be extended by providing cutting action by the substrate in addition to the shearing action provided by the diamond table. Nonetheless, it is recognized that any other suitable type of cutting element, including without limitation natural diamonds, may be utilized in embodiments of the present disclosure.
In operation, the bit 100 may be run into a wellbore and “broken-in” or “sharpened” by drilling into an earth formation at a selected weight-on-bit (WOB) as the bit 100 is rotated about the longitudinal axis 102. In the initial stages of penetration of the earth formation, the bit 100 may be run into the wellbore at an increased rate of penetration (ROP) to wear away the matrix material of the bit 100 and expose the abrasive particles disposed therein. The bit 100 may be “sharpened” when the abrasive particles are sufficiently exposed to cut the earth formation. Once the bit 100 is “sharpened,” the ROP stabilizes.
In some embodiments, the rotationally trailing edges 115 of the blades 112 may be provided with a large radius of curvature R115 compared to conventional impregnated drill bits. In some embodiments, the rotationally trailing edges 115 may exhibit a radius of curvature R115 greater than 0.1 inch and less than or equal to about 0.5 inch. By virtue of the curved rotationally trailing edge 115, an initial area of an outer surface 132 of the blade 112 that engages and cuts formation material is smaller than the final area of the outer surface 132 of the blade 112 that engages the formation after wear of the bit. As the matrix material of the crown 108 continues to wear away, the area of the outer surface 132 of the blades 112 that engages the formation increases. The blades 112 of the bit 100 may be “broken-in” or “sharpened” when the curved rotationally trailing surface 115 has worn entirely away. When the bit 100 is sharpened the ROP of the bit 100 may stabilize as the bit 100 continues to wear away from contact with the formation material. In view of the foregoing, the bit 100 may wear to a sharpened state at an increased rate over conventional impregnated bits lacking a large radius of curvature along a rotationally trailing edge of the blades thereof.
The crown 108 may also comprise a plurality of fluid channels between and recessed from the blades 112 and extending to junk slots 120 in the gage 116. The plurality of fluid channels may include at least one long channel 122 and at least one short channel 124. As best illustrated in
Each of the plurality of long channels 122 may comprise a nozzle port 126. The nozzle port 126 may be located proximate to or within the radially innermost portion 123 of the long channel 122. In some embodiments, the nozzle port 126 may be located proximate to at least one of the cutting elements 114. Each of the plurality of short channels 124 may also comprise a nozzle port 128. The nozzle ports 126, 128 communicate drilling fluid flow from an interior of the crown 108 and over the bit face 110. Some or all of the nozzle ports 126, 128 may include a nozzle 170 (
The bit 100 may comprise a reduced number of blades 112 as compared to conventional impregnated bits according to some embodiments of the present disclosure. For example, the bit 100 may comprise a smaller number of blades 112 than bits offered by Baker Hughes Inc. under the trademark IREV®, which commonly includes at least twelve blades and as many as fifty blades. In some embodiments, the bit 100 may comprise eight blades 112, as illustrated in
Each of the channels 122, 124 may increase in width as the channels 122, 124 extend radially outward across the bit face 110 such that the channels 122, 124 may be generally wedge-shaped in the view of
Like the long channel 122, the short channel 124 may have a minimum width measured at the radially innermost portion 125 adjacent the nozzle port 128. The short channel 124 may have a maximum width measured adjacent to a radially outer surface 127 within the channel 124. In some embodiments, the width of the short channel 124 may be tailored based on the earth formation in which the bit 100 is intended for use. For example, as illustrated in
In some embodiments, the crown 108 may comprise a plurality of short channels 124 each having radially innermost portions 125 located equidistant from the longitudinal axis 102. In other words, the radially innermost portion 125 of each short channel 124 may be located circumferentially about the longitudinal axis 102 at substantially the same radial distance from the longitudinal axis 102. In such embodiments, each short channel 124 may have substantially the same length measured from the radially innermost portion 125 to the gage 116. In other embodiments, the radially innermost portion 125 of at least one short channel 124 may be located at a radial distance from the longitudinal axis 102 different than the radially innermost portion 125 of at least one other short channel 124. In other words, the short channels 124 may vary in length measured from the radially innermost portion 125 to the gage 116.
The openings of the nozzle ports 126, 128 may vary in size and/or shape. In some embodiments, each of the nozzle ports 126, 128 may comprise a round opening flush with or slightly recessed from the bit face 110. The openings may be circular, oval, or the like. In some embodiments, the nozzle ports 128 located in the short channels 124 may be of a larger size than the nozzle ports 126 located in the long channels 122. In other words, a diameter of the nozzle ports 126 may be less than a diameter of the nozzle ports 128. In other embodiments, the nozzle ports 128 located in the short channels 124 be substantially equal in size to the nozzle ports 126 in the long channels 122. The size of the nozzle ports 126, 128 may be varied to increase or decrease the fluid pressure within the respective fluid channels 122, 124.
As illustrated in
The cone region 144 may be located near a centerline of the conventional bit, such as near the longitudinal axis 137. The outer surface 138 of the blade in the cone region 144 may extend in a generally planar manner as indicated by a line 152 tangent to the outer surface 138 of the blade. The tangent line 152 may extend at an angle relative to a line 154 perpendicular to the longitudinal axis 137. The angle α may be measured between the tangent line 152 and line 154 with negative angles being measured in the counterclockwise direction relative to the line 154 and positive angles being measured in the clockwise direction relative to the line 154. In conventional bits, the angle α of the outer surface 138 may extend at a positive acute angle α between about 15° to about 25° and, more particularly, about 20° relative to the line 154. As illustrated in
The nose region 146 includes the most radially distal surfaces on a face of the bit and the uppermost surface in the view of
The shoulder region 148 extends between the nose region 146 until the outer surface 138 of the blade is essentially vertical in the gage region 150. The shoulder region 148 may experience a greater amount of and most rapid movement of the bit relative to the earth formation. As a result, the shoulder region 148 experiences much greater wear than the cone region 144. Thus, the shoulder region 148 and/or nose region 146 may experience the greatest wear as compared to any other region of the bit.
The gage region 150 including the gage 142 of the bit also experiences more wear than the cone region 144 because the gage region 150 experiences the most, and most rapid, relative rotational movement with respect to the earth formation. However, due to the substantially vertical slope of the blade in the gage region 150 contacting the wellbore wall, the gage region 150 experiences less wear than the nose region 146 and/or shoulder region 148. In view of the foregoing, the conventional bit experiences an inconsistent rate of wear across the blade profile 136.
As further illustrated in
As previously described with reference to
In some embodiments, the outer surface 132 of the blade 112 may be formed at an acute angle β relative to a line 158 perpendicular to the longitudinal axis 102 of the bit 100 on the bit face 110 of the bit 100. The angle β may be measured between the tangent line 156 and line 158 with negative angles being measured in the counterclockwise direction relative to the line 158 and positive angles being measured in the clockwise directive relative to the line 158. As illustrated in
Without being bound by any particular theory, the blade profile 130 may experience substantially even wear over the bit face 110 by virtue of the substantially planar blade profile 130 across the bit face 110. For example, the outer surface 132 of the blades 112 may experience a substantially even amount of movement of the bit 100 relative to the earth formation and a substantially even force from the earth formation may be exerted against the bit face 110 as compared to the conventional bit described above. As a result, the blade profile 130 may experience a more consistent rate of wear across the bit face 110 region. In view of the foregoing, the bit 100 may have a reduced likelihood of balling, a more stable ROP throughout the life of the bit, and an extended bit life relative to conventional bits described above.
The indent angle γ may be measured relative to a line 162 tangent to a radially outermost point 164 of the gage 116 and extending parallel to the longitudinal axis 102 of the bit 100. In other words, the indent angle γ may be measured between a surface of the gage 116 along the blade 112 and the tangent line 162 with negative angles being measured in the counterclockwise direction relative to the line 162 and positive angles being measured in the clockwise directive relative to the line 162. In some embodiments, the indent angle γ may be greater than 0° and less than or equal to about 7°. More particularly, the indent angle γ may be greater than 0° and less than or equal to about 3°.
In operation, the bit 100 may be suitable to drill deviated wellbores in earth formations, which include a generally vertical borehole drilled from an earth surface into the formation to culminate in a more horizontal portion or portions within a particular rock formation layer. A curved portion of the wellbore may extend between the vertical portion and horizontal portion thereof. The ability of a drill bit, such as the bit 100, to deviate from the linear path of the vertical portion to the horizontal portion may be defined by its potential radius of curvature. By forming the gage 116 to extend away from the earth formation and radially inward toward the longitudinal axis 102 at the indent angle γ, the amount of contact between the gage 116 and the formation may be reduced, which enables the bit 100 to deviate between the vertical portion and horizontal portion of the wellbore over a shorter distance. In other words, the indent angle γ of the gage 116 may shorten the minimum radius of curvature of the wellbore trajectory that may be drilled by the bit 100. For example, the bit 100 according to some embodiments may deviate (for example) between a vertical portion and horizontal portion of the wellbore over a distance of about 300 feet (about 91 meters) and, more particularly, about 100 feet (about 30.5 meters) or less.
While the disclosed structures and methods are susceptible to various modifications and alternative forms in implementation thereof, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the present disclosure is not limited to the particular forms disclosed. Rather, the present invention encompasses all modifications, combinations, equivalents, variations, and alternatives falling within the scope of the present disclosure as defined by the following appended claims and their legal equivalents.
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