Patent Application
20120152617
Not applicable.
Not applicable.
1. Field of the Invention
The inventions disclosed and taught herein relate generally to drill bits for drilling wells; and more specifically relate to monitoring the wear of drill bits for drilling wells in earth formations.
2. Description of the Related Art
U.S. Pat. No. 4,655,300 teaches “a method and apparatus for detecting excessive wear of a rotatable bit used in drilling. In particular, the apparatus can detect loss of gauge or bearing failure in a bit. The method is accomplished by connecting a restricting means in the drill bit that can be manipulated to reduce the flow of drilling fluid through at least one port in the drill bit. A wire is connected between a sensor which senses wear and the restriction means to cause the restriction means to reduce the flow of drilling fluid and thereby signal the surface by the reduced flow as an indication of wear.”
U.S. Pat. No. 4,694,686 teaches a “method and apparatus by which the degree of wear and useful life limitations of a drill, end mill or other types of metal removal tools can be detected. The method is based on the short circuit current, open circuit voltage and/or power that is generated during metal removal by the utilization of an insulated rotary tool bit to which electrical contact is made by a non-rotating conductor and an insulated or non-insulated workpiece, with an external circuit connecting the tool and workpiece through a measuring device. The generated current, voltage or power shows a sharp increase or change in slope upon considerable tool wear and/or at the point of failure.”
U.S. Pat. No. 4,785,894 teaches an “earth drilling bit incorporating a bit wear indicator. The bit wear indicator includes: a sensor to detect wear at a selected point on the bit; a device for altering the resistance of the bit to receiving drilling fluid from the drill string; and, a tensioned linkage extending between the wear sensor and the flow resistance altering means. On detecting a predetermined degree of wear, the wear sensor releases the tension in the tensioned linkage. This activates the flow resistance altering device, causing the flow rate and/or pumping pressure of the drilling fluid to change. This serves as a signal that the predetermined wear condition has been achieved. The bit wear indicator can be adapted to monitor many different types of bit wear, including bearing wear in roller-cone type bits and gauge wear in all types of bits.”
U.S. Pat. No. 4,785,895 teaches an “earth drilling bit incorporating a tensioned linkage type bit wear indicator. A tensioned linkage extends through the bit between a wear sensor and a device for altering the resistance of the bit to receiving drilling fluid from the drill string. On detecting a predetermined degree of wear, the wear sensor releases the tension in the tensioned linkage. This activates the flow resistance altering device, causing the flow rate and/or pumping pressure of the drilling fluid to change. The tensioned linkage passes through two intersecting passageways in the bit. A guide element is inserted at the intersection of the two intersecting passageways. The guide element routes the tensioned linkage between the two passageways.”
U.S. Pat. No. 4,786,220 teaches a “method and apparatus by which the degree of wear and useful life limitations of a drill, end mill or other types of metal removal tools can be detected. The method is based on the short circuit current, open circuit voltage and/or power that is generated during metal removal by the utilization of an insulated rotary tool bit to which electrical contact is made by a non-rotating conductor and an insulated or non-insulated workpiece, with an external circuit connecting the tool and workpiece through a measuring device. The generated current, voltage or power shows a sharp increase or change in slope upon considerable tool wear and/or at the point of failure.”
U.S. Pat. No. 4,928,521 teaches a “method is provided for determining the state of wear of a multicone drill bit. Vibrations generated by the working drill bit are detected and converted into a time oscillatory signal from which a frequency spectrum is derived. The periodicity of the frequency spectrum is extracted. The rate of rotation of at least one cone is determined from the periodicity and the state of wear of the drill bit is derived from the rate of cone rotation. The oscillatory signal represents the variation in amplitude of the vertical or torsional force applied to the drill bit. To extract periodicity, a set of harmonics in the frequency spectrum is given prominence by computing the cepstrum of the frequency spectrum or by obtaining an harmonic-enhanced spectrum. The fundamental frequency in the set of harmonics is determined and the rate of cone rotation is derived from the fundamental frequency.”
U.S. Pat. No. 5,216,917 teaches “a new model describing the drilling process of a drag bit and concerns a method of determining the drilling conditions associated with the drilling of a borehole through subterranean formations, each one corresponding to a particular lithology, the borehole being drilled with a rotary drag bit, the method comprising the steps of: measuring the weight W applied on the bit, the bit torque T, the angular rotation speed Ω of the bit and the rate of penetration N of the bit to obtain sets of data (Wi, Ti, Ni, Ωi) corresponding to different depths; calculating the specific energy Ei and the drilling strength Si from the data (Wi, Ti, Ni, Ωi); identifying at least one linear cluster of values (Ei, Si), said cluster corresponding to a particular lithology; and determining the drilling conditions from said linear cluster. The slope of the linear cluster is determined, from which the internal friction angle φ of the formation is estimated. The intrinsic specific energy E of the formation and the drilling efficiency are also determined. Change of lithology, wear of the bit and bit balling can be detected.”
U.S. Pat. No. 6,631,772 teaches a “system and method for detecting the wear of a roller bit bearing between a roller drill bit body and a roller bit rotatably attached to the roller drill bit body. A valve-plug is placed between the roller drill bit body and roller bit such that the valve-plug is removably fitted in a drilling fluid outlet in the roller drill bit body, and the valve-plug extends into a channel in the roller bit whereby uneven rotation or vibration of the roller bit causes the valve-plug to impact the sides of the channel which removes the valve-plug from the drilling fluid outlet to cause drilling fluid to flow through the drilling fluid outlet. The drop in pressure from the drilling fluid flowing through the drilling fluid outlet indicates that the roller bit is worn and may fail.”
U.S. Pat. No. 6,634,441 teaches a “system and method for detecting the wear of a roller bit bearing on a roller drill bit body where the roller element has a plurality of cutting elements and is rotatably attached to the roller drill bit body at the bearing. In the invention, a rotation impeder is in between the roller element and roller drill bit body and upon uneven rotation of the roller element which indicates that the roller element bearing may fail, the rotation impeder impedes the rotation of the roller element. The drill rig operator at the surface can cease drilling operations upon detection of the cessation of rotation of the roller element. The rotation impeder can also be seated in a drilling fluid outlet and cause a detectable loss in drilling fluid pressure when dislodged to otherwise cease rotation of the roller drill bit.”
The inventions disclosed and taught herein are directed to an improved method of monitoring the wear of drill bits for drilling wells in earth formations.
The invention relates to a method of monitoring the wear of drill bits for drilling wells in earth formations, several embodiments of an improved drill bit for drilling a well in an earth formation, and methods of manufacture. In one embodiment, the bit is assembled by forming the bit, including a bit body and a plurality of cutting components; embedding one or more electrical circuits into the bit; and providing a module to monitor the circuits and generate an indication of bit wear and/or formation changes. The electrical circuit that may experience a change in resistance or conductivity due to wear of the bit and/or formation changes. The bit wear and/or formation changes may be displayed for an operator.
A drill bit assembly, according to the present invention, may comprise a drill bit including a bit body and a plurality of cutting components; one or more electrical circuits within the drill bit; and a module to monitor the electrical circuits and generate an indication of bit wear and/or formation changes. The electrical circuits that may experience a change in resistance or conductivity due to wear of the bit and/or formation changes. The bit wear and/or formation changes may be displayed for an operator on a surface computer.
The Figures described above and the written description of specific structures and functions below are not presented to limit the scope of what Applicants have invented or the scope of the appended claims. Rather, the Figures and written description are provided to teach any person skilled in the art to make and use the inventions for which patent protection is sought. Those skilled in the art will appreciate that not all features of a commercial embodiment of the inventions are described or shown for the sake of clarity and understanding. Persons of skill in this art will also appreciate that the development of an actual commercial embodiment incorporating aspects of the present inventions will require numerous implementation-specific decisions to achieve the developer's ultimate goal for the commercial embodiment. Such implementation-specific decisions may include, and likely are not limited to, compliance with system-related, business-related, government-related and other constraints, which may vary by specific implementation, location and from time to time. While a developer's efforts might be complex and time-consuming in an absolute sense, such efforts would be, nevertheless, a routine undertaking for those of skill this art having benefit of this disclosure. It must be understood that the inventions disclosed and taught herein are susceptible to numerous and various modifications and alternative forms. Lastly, the use of a singular term, such as, but not limited to, “a,” is not intended as limiting of the number of items. Also, the use of relational terms, such as, but not limited to, “top,” “bottom,” “left,” “right,” “upper,” “lower,” “down,” “up,” “side,” and the like are used in the written description for clarity in specific reference to the Figures and are not intended to limit the scope of the invention or the appended claims.
Particular embodiments of the invention may be described below with reference to block diagrams and/or operational illustrations of methods. In some alternate implementations, the functions/actions/structures noted in the figures may occur out of the order noted in the block diagrams and/or operational illustrations. For example, two operations shown as occurring in succession, in fact, may be executed substantially concurrently or the operations may be executed in the reverse order, depending upon the functionality/acts/structure involved.
Applicants have created a method of monitoring the wear of drill bits for drilling wells in earth formations, several embodiments of an improved drill bit for drilling a well in an earth formation, and methods of manufacture. In one embodiment, the bit is assembled by forming the bit, including a bit body and a plurality of cutting components; embedding one or more electrical circuits into the bit; and providing a module to monitor the electrical circuits and generate an indication of bit wear and/or formation changes. The electrical circuits that may experience a change in resistance or conductivity due to wear of the bit and/or formation changes. The bit wear and/or formation changes may be displayed for an operator.
The drill bit 10, and select components thereof, are preferably similar to those disclosed in U.S. Pat. No. 7,048,081, which is incorporated herein by specific reference. In any case, the drill bit 10 preferably includes a plurality of blades 16 each projecting outwardly from a face 18. The drill bit 10 also preferably includes a row of cutters, or cutting elements, 20 secured to the blades 16. The drill bit 10 also preferably includes a plurality of nozzles 22 to distribute drilling fluid to cool and lubricate the drill bit 10 and remove cuttings. As customary in the art, gage 24 is the maximum diameter which the drill bit 10 is to have about its periphery. The gage 24 will thus determine the minimum diameter of the resulting bore hole that the drill bit 10 will produce when placed into service. The gage 24 of a small drill bit may be as small as a few centimeters and the gage 24 of an extremely large drill bit may approach a meter, or more. Between each blade 16, the drill bit 10 preferably has fluid slots, or passages, 26 into with the drilling fluid is fed by the nozzles 22.
An exemplary cutting element 20 of the present invention, as shown in
In accordance with the present invention, the super-abrasive table 28 preferably comprises a heterogeneous conglomerate type of PDC layer or diamond matrix in which at least two different nominal sizes and wear characteristics of super-abrasive particles, such as diamonds of differing grains, or sizes, are included to ultimately develop a rough, or rough cut, cutting face 30, particularly with respect to the cutting face side 30B and most particularly with respect to the cutting edge 30C. In one embodiment, larger diamonds may range upwards of approximately 600 μm, with a preferred range of approximately 100 μm to approximately 600 μm, and smaller diamonds, or super-abrasive particles, may preferably range from about 15 μm to about 100 μm. In another embodiment, larger diamonds may range upwards of approximately 500 μm, with a preferred range of approximately 100 μm to approximately 250 μm, and smaller diamonds, or super-abrasive particles, may preferably range from about 15 μm to about 40 μm.
The specific grit size of larger diamonds, the specific grit size of smaller diamonds, the thickness of the cutting face 30 of the super-abrasive table 28, the amount and type of sintering agent, as well as the respective large and small diamond volume fractions, may be adjusted to optimize the cutter 20 for cutting particular formations exhibiting particular hardness and particular abrasiveness characteristics. The relative, desirable particle size relationship of larger diamonds and smaller diamonds may be characterized as a tradeoff between strength and cutter aggressiveness. On the one hand, the desirability of the super-abrasive table 28 holding on to the larger particles during drilling would dictate a relatively smaller difference in average particle size between the smaller and larger diamonds. On the other hand, the desirability of providing a rough cutting surface would dictate a relatively larger difference in average particle size between the smaller and larger diamonds. Furthermore, the immediately preceding factors may be adjusted to optimize the cutter 20 for the average rotational speed at which the cutting element 20 will engage the formation as well as for the magnitude of normal force and torque to which each cutter 20 will be subjected while in service as a result of the rotational speeds and the amount of weight, or longitudinal force, likely to be placed on the drill bit 10 during drilling.
The blades 16 and or the bit body 12 may be made from an alloy matrix, such as a matrix of tungsten carbide powder impregnated with a copper alloy binder during a casting process. For example, the drill bit 10 may be constructed as a matrix style drill bit using an infiltration casting process whereby the copper alloy binder is heated past its melting temperature and allowed to flow, under the influence of gravity, into a matrix of carbide powder packed into, and shaped by, a graphite mold. The mold preferably contains the shapes of the blades 16 and slots 26 of the drill bit 10, creating a form for the drill bit 10. Other features may be made from clay and/or sand and attached to the mold.
Alternatively, the bit 10 may be similar to those disclosed in U.S. Pat. No. 6,843,333, the disclosure of which is incorporated herein by specific reference in its entirety. Referring now to
The bit 10 may include conventional impregnated bit cutting structures and/or discrete, impregnated cutting structures 44 comprising posts extending upwardly from the blades 38 on the bit face 36. The cutting structures 44 may be formed as an integral part of the matrix-type blades 38 projecting from the matrix-type bit body 12 by hand-packing diamond grit-impregnated matrix material in mold cavities on the interior of a bit mold defining locations of the cutting structures 44 and blades 38. Thus, each blade 38 and associated cutting structure 44 may define a unitary structure. It is noted that the cutting structures 44 may be placed directly on the bit face 36, dispensing with the blades. It is also noted that, while discussed in terms of being integrally formed with the bit 10, the cutting structures 44 may be formed as discrete individual segments, such as by hot isostatic pressing, and subsequently brazed or furnaced onto the bit 10.
The discrete cutting structures 44 may be mutually separate from each other to promote drilling fluid flow therearound for enhanced cooling and clearing of formation material removed by the diamond grit. The discrete cutting structures 44 may be generally of a round or circular transverse cross-section at their substantially flat, outermost ends, but become more oval with decreasing distance from the face of the blades 38 and thus provide wider or more elongated (in the direction of bit rotation) bases for greater strength and durability. As the discrete cutting structures 44 wear, the exposed cross-section of the posts increases, providing progressively increasing contact area for the diamond grit with the formation material. As the cutting structures wear down, the bit 10 takes on the configuration of a heavier-set bit more adept at penetrating harder, more abrasive formations. Even if discrete cutting structures 44 wear completely away, the diamond-impregnated blades 38 will provide some cutting action, reducing the possibility of ring-out and having to pull the bit 10.
While the cutting structures 44 are illustrated as exhibiting posts of circular outer ends and oval shaped bases, other geometries are also contemplated. For example, the outermost ends of the cutting structures may be configured as ovals having a major diameter and a minor diameter. The base portion adjacent the blade 38 might also be oval, having a major and a minor diameter, wherein the base has a larger minor diameter than the outermost end of the cutting structure 44. As the cutting structure 44 wears towards the blade 38, the minor diameter increases, resulting in a larger surface area. Furthermore, the ends of the cutting structures 44 need not be flat, but may employ sloped geometries. In other words, the cutting structures 44 may change cross-sections at multiple intervals, and tip geometry may be separate from the general cross-section of the cutting structure. Other shapes or geometries may be configured similarly. It is also noted that the spacing between individual cutting structures 44, as well as the magnitude of the taper from the outermost ends to the blades 38, may be varied to change the overall aggressiveness of the bit 10 or to change the rate at which the bit is transformed from a light-set bit to a heavy-set bit during operation. It is further contemplated that one or more of such cutting structures 44 may be formed to have substantially constant cross-sections if so desired depending on the anticipated application of the bit 10.
Discrete cutting structures 44 may comprise a synthetic diamond grit, such as, for example, DSN-47 Synthetic diamond grit, commercially available from DeBeers of Shannon, Ireland, which has demonstrated toughness superior to natural diamond grit. The tungsten carbide matrix material with which the diamond grit is mixed to form discrete cutting structures 44 and supporting blades 38 may desirably include a fine grain carbide, such as, for example, DM2001 powder commercially available from Kennametal Inc., of Latrobe, Pa. Such a carbide powder, when infiltrated, provides increased exposure of the diamond grit particles in comparison to conventional matrix materials due to its relatively soft, abradable nature. The base of each blade 38 may desirably be formed of, for example, a more durable 121 matrix material, obtained from Firth MPD of Houston, Tex. Use of the more durable material in this region helps to prevent ring-out even if all of the discrete cutting structures 44 are abraded away and the majority of each blade 38 is worn.
It is noted, however, that alternative particulate abrasive materials may be suitably substituted for those discussed above. For example, the discrete cutting structures 44 may include natural diamond grit, or a combination of synthetic and natural diamond grit. Alternatively, the cutting structures may include synthetic diamond pins. Additionally, the particulate abrasive material may be coated with a single layer or multiple layers of a refractory material, as known in the art and disclosed in U.S. Pat. Nos. 4,943,488 and 5,049,164, the disclosures of each of which are hereby incorporated herein by reference in their entirety. Such refractory materials may include, for example, a refractory metal, a refractory metal carbide or a refractory metal oxide. In one embodiment, the coating may exhibit a thickness of approximately 1 to 10 microns. In another embodiment, the coating may exhibit a thickness of approximately 2 to 6 microns. In yet another embodiment, the coating may exhibit a thickness of less than 1 micron.
In one embodiment, one or more of the blades 38 carry cutting elements, such as PDC cutters 20, in conventional orientations, with cutting faces oriented generally facing the direction of bit rotation. In one embodiment, the cutters 20 are located within the cone portion 34 of the bit face 36. The cone portion 34 is the portion of the bit face 36 wherein the profile is defined as a generally cone-shaped section about the centerline of intended rotation of the drill bit 10. Alternatively, or additionally, the cutters 20 may be located across the blades 38 and elsewhere on the bit 10.
This cutter design provides enhanced abrasion resistance to the hard and/or abrasive formations typically drilled by impregnated bits, in combination with enhanced performance, or rate of penetration (ROP), in softer, nonabrasive formation layers interbedded with such hard formations. It is noted, however, that alternative cutter designs may be implemented. For example, the cutters 20 may be configured of various shapes, sizes, or materials as known by those of skill in the art. Also, other types of cutting elements may be formed within the cone portion 34 of, and elsewhere across, the bit 10 depending on the anticipated application of the bit 10. For example, the cutting elements 20 may include cutters formed of thermally stable diamond product (TSP), natural diamond material, or impregnated diamond.
As shown in
The nose represents the lowest point on a drill bit. Therefore, the nose cutter is typically the leading most cutter. The nose section is roughly defined by a nose radius. A larger nose radius provides more area to place cutters in the nose section. The nose section begins where the cone section ends, where the curvature of the blade begins, and extends to the shoulder section. More specifically, the nose section extends where the blade profile substantially matches a circle formed by the nose radius. The nose section experiences much more, and more rapid, relative movement than does the cone section. Additionally, the nose section typically takes more weight than the other sections. As such, the nose section commonly experiences much more wear than does the cone section. Therefore, the nose section preferably has a higher distribution, concentration, or density of cutting structures 44 and/or cutters 20.
The shoulder section begins where the blade profile departs from the nose radius and continues outwardly on each blade 18,38 to a point where a slope of the blade is essentially completely vertical, at the gage section. The shoulder section experiences much more, and more rapid, relative movement than does the cone section. Additionally, the shoulder section typically takes the brunt of abuse from dynamic dysfunction, such as bit whirl. As such, the shoulder section experiences much more wear than does the cone section. The shoulder section is also a more significant contributor to rate of penetration and drilling efficiency than the cone section. Therefore, the shoulder section preferably has a higher distribution, concentration, or density of cutting structures 44 and/or cutters 20. Depending on application, the nose section or the shoulder section may experience the most wear, and therefore either the nose section or the shoulder section may have the highest distribution, concentration, or density of cutting structures 44 and/or cutters 20.
The gage section begins where the shoulder section ends. More specifically, the gage section begins where the slope of the blade is predominantly vertical. The gage section continues outwardly to an outer perimeter or gauge of the drill bit 10. The gage section experiences the most, and most rapid, relative movement with respect to the earth formation. However, at least partially because of the high, substantially vertical, slope of the blade 18,38 in the gage section, the gage section does not typically experience as much wear as does the shoulder section and/or the nose section. The gage section does, however, typically experience more wear than the cone section. Therefore, the gage section preferably has a higher distribution of cutting structures 44 and/or cutters 20 than the cone section, but may have a lower distribution of cutting structures 44 and/or cutters 20 than the shoulder section and/or nose section.
As shown in
The module 52 preferably monitors the wire 50, such as by continuously and/or periodically checking continuity of the wire 50. If the wire 50 breaks, such that continuity is lost for example, the module 52 notifies the surface computer 54 through the communications link 56. An operator at the surface is then notified that the bit 10 has experienced significant wear and needs to be replaced. This notification can be by any one or more of multiple means, such as an audible alarm, and/or visual indication. In some embodiments, which will be discussed in greater detail below, the operator is presented with a depiction of the bit 10 showing its real time condition, as determined by the module 52 using the wires 50. These advancements allow the operator to make better decisions, eliminating needless trips out of the hole, thereby greatly increasing drilling efficiency.
More specifically, as the bit 10 is used, the cutters 20 experience wear and eventually fail. The formation through which the bit 10 is drilling then begins to abrade the blades 16. As the blades 16 are abraded, the wire 50 is eventually exposed and abraded as well, thereby breaking a circuit formed by the wire 50 and the module 52. The module 52 senses this open circuit and notifies the surface computer 54 through the communications link 56. Thus, the operator can trip the bore hole assembly (BHA) or drill string to the surface and replace the bit 10 only when necessary while still avoiding a ring-out or other excessive wear condition.
As shown in
As shown in
As discussed above, these loops 50a-50d may have direct and independent connections to the module 52. Additionally, and/or alternatively, the loops 50a-50d may share connections to the module 52, as shown. To allow the module 52 and/or the computer 54 to differentiate between them, the loops 50a-50d may include electrical and/or electronic components. For example, the loops 50a-50d may include resistive elements 58a-58d. Additionally, and/or alternatively, the loops 50a-50d may include capacitive and/or inductive elements. Furthermore, the loops 50a-50d may include electronic elements, such as microchips identifying each loop to the module 52 and/or computer 54.
More specifically, as shown in
Of course, the modules 52 may be able to differentiate between the loops 50a-50d without discrete electrical and/or electronic components. For example, different lengths of resistive wire may be used as the loops themselves. The module 52 might detect and analyze the capacitance between the loops. The module 52 might detect and analyze inductive coupling between the loops.
As shown in
While, in one embodiment, the conductors 50 are bare, routed through the non-conductive bit body 12, blades 16, and/or other components of the bit 10, the conductors 50 may be insulated. This may be helpful where several conductors are used in each blade 16 and/or may enable the use of blades 16 and/or a bit-body 12 made of conductive material, such as steel. One or more of the wires 50 may also be routed through the cutters 20 and/or cutting structures 44 themselves, as shown in
Alternatively, and/or additionally, any part of the circuitry described above may be provided by the bit body 12, blades 16, and/or other components of the bit 10 directly. For example, rather than simply running the wires 50 through the cutters 20, the cutters 20 and/or cutting structures 44 could form part of the conductivity path 50, as shown in
Rather than merely changing the conductivity of portions of the drill bit 10, the witness materials may additionally, or alternatively, change other characteristics of the bit 10. For example, the witness material may be used to indicate wear by altering a traditional bit's response to acoustic, optical, electrical, magnetic, and/or electromagnetic excitation. Such alternations would preferably change, in response to wear of the bit 10 or portion thereof.
Referring also to
For example, if 1000, 2000, 3000, and 4000 ohm resistors were used in the cone, nose, shoulder, and gage loops 50a-50d, respectively, then the initial resistance detected by the module 52 should be approximately 480 ohms. If the shoulder section were to experience wear abrading the shoulder loop 50c, the changed resistance checked by the module 52 should be approximately 571 ohms, indicating the loss of the 3000 ohm resistor caused by the open circuit in the shoulder loop 50c. Alternatively, if the nose section were to experience wear abrading the nose loop 50b, the changed resistance checked by the module 52 should be approximately 632 ohms, indicating the loss of the 2000 ohm resistor caused by the open circuit in the nose loop 50b. If the bit 10 experienced more significant wear, such as to both the nose and shoulder sections the changed resistance checked by the module 52 should be approximately 800 ohms, indicating the loss of the 2000 and 3000 ohm resistors caused by the open circuits in the nose and shoulder loops 50b,50c. In this manner, the module 52 can determine which section(s) have experienced wear and how much wear, as shown in step 100d.
Once the wear has been detected, by whatever method, it is reported, as shown in step 100e. The wear my be reported directly to an operator at the surface. For example, the operator may be shown a depiction of the bit 10. Wear may be indicated by discoloration of the portion of the bit 10 determined to have experienced wear. Alternatively, the portion of the bit 10 determined to have experienced wear may be removed from the display. How much is removed and/or discolored may depend on the degree of wear determined by the module 52. This display may be updated in substantially real-time, periodically, and/or on demand. The wear may also be reported to a control system, which may take warn the operator, log the wear report, and/or take corrective action automatically.
Rather than monitoring the presence of the witness material 62 on the bit 10, bit body 12, blade 16, and/or cutter 20 or cutting structure 44, as discussed above, the module 52 and/or computer 54 could sense the witness material 62 after it has been separated from the bit 10. For example, as shown in
More specifically, as shown in
In an alternative embodiment, discusses above, the cutters 20 are doped with a material such as boron, phosphorous, gallium, or other material, thereby transforming portions of the cutters 20 themselves into witness materials 62. In one embodiment, the diamond cutting tables 28 may be transformed into semiconductors. More specifically, during actual drilling operations, heat is naturally generated, thereby activating the doping material and transforming the doped cutting tables 28 into semiconductors.
In any case, the cutters 20, according to certain aspects of the present invention, may exhibit a mesh-like structure comprising nodes of the isotope or doping material. The module 52 can determine wear using wired, wireless, acoustic, or other sensors to detect the presence or absence of the witness material 62. The wear can be displayed to an operator at the surface in real-time through, for example a modem, mud pulse telemetry, M-30 bus, or other transmission means. Alternatively, or additionally, the wear data may be stored in a memory of the module 52. The display may show an representation of actual wear of the bit 10 and/or cutters 20. For example, as shown in
It should be noted that only one blade 16 of a PDC bit is depicted in
The wires 50, components 58a-d, and/or witness material 62 may be introduced into the bit 10 after substantial manufacturing of the bit 10. Alternatively, the wires 50, components 58a-d, and/or witness material 62 are preferably formed during manufacturing of the bit 10. for example, the wires 50, components 58a-d, and/or witness material 62 may be pre-loaded into the mold during casting of the bit 10. In any case, the wires 50, components 58a-d, circuitry 60, and/or witness material 62 may be collectively referred to as a wear detector and/or components thereof.
The module 52 may be similar to that described in U.S. Patent Application publication No. 20080060848, the disclosure of which is incorporated herein by reference. For example,
The end-cap 270 includes a cap bore 276 formed therethrough, such that the drilling mud may flow through the end cap, through the central bore 280 of the shank 210 to the other side of the shank 210, and then into the body of drill bit. In addition, the end-cap 270 includes a first flange including a first sealing ring 272, near the lower end of the end-cap 270, and a second flange including a second sealing ring 274, near the upper end of the end-cap 270.
The electronics module 290 may be configured as a flex-circuit board, enabling the formation of the electronics module 290 into the annular ring suitable for disposition about the end-cap 270 and into the central bore 280. This flex-circuit board embodiment of the electronics module 290 is shown in a flat uncurled configuration in
The electronics module 290 may be configured to perform a variety of functions. One exemplary electronics module 290 may be configured as a data analysis module, which is configured for sampling data in different sampling modes, sampling data at different sampling frequencies, and analyzing data.
An exemplary data analysis module 300 is illustrated in
The plurality of accelerometers 340A may include three accelerometers 340A configured in a Cartesian coordinate arrangement. Similarly, the plurality of magnetometers 340M may include three magnetometers 340M configured in a Cartesian coordinate arrangement. While any coordinate system may be defined within the scope of the present invention, an exemplary Cartesian coordinate system, shown in
The accelerometers 340A of the
The magnetometers 340M of the
The temperature sensor 340T may be used to gather data relating to the temperature of the drill bit, and the temperature near the accelerometers 340A, magnetometers 340M, and other sensors 340. Temperature data may be useful for calibrating the accelerometers 340A and magnetometers 340M to be more accurate at a variety of temperatures.
Other optional sensors 340 may be included as part of the data analysis module 300. Some exemplary sensors that may be useful in the present invention are strain sensors at various locations of the drill bit, temperature sensors at various locations of the drill bit, mud (drilling fluid) pressure sensors to measure mud pressure internal to the drill bit, and borehole pressure sensors to measure hydrostatic pressure external to the drill bit. These optional sensors 340 may include sensors 340 that are integrated with and configured as part of the data analysis module 300. These sensors 340 may also include optional remote sensors 340 placed in other areas of the drill bit 10, or above the drill bit in the BHA. The optional sensors 340 may communicate using a direct-wired connection, or through an optional sensor receiver 360. The sensor receiver 360 is configured to enable wireless remote sensor communication across limited distances in a drilling environment as are known by those of ordinary skill in the art.
One or more of these optional sensors may be used as an initiation sensor 370. The initiation sensor 370 may be configured for detecting at least one initiation parameter, such as, for example, turbidity of the mud, and generating a power enable signal 372 responsive to the at least one initiation parameter. A power gating module 374 coupled between the power supply 310, and the data analysis module 300 may be used to control the application of power to the data analysis module 300 when the power enable signal 372 is asserted. The initiation sensor 370 may have its own independent power source, such as a small battery, for powering the initiation sensor 370 during times when the data analysis module 300 is not powered. As with the other optional sensors 340, some exemplary parameter sensors that may be used for enabling power to the data analysis module 300 are sensors configured to sample; strain at various locations of the drill bit, temperature at various locations of the drill bit, vibration, acceleration, centripetal acceleration, fluid pressure internal to the drill bit, fluid pressure external to the drill bit, fluid flow in the drill bit, fluid impedance, and fluid turbidity. In addition, at least some of these sensors may be configured to generate any required power for operation such that the independent power source is self-generated in the sensor. By way of example, and not limitation, a vibration sensor may generate sufficient power to sense the vibration and transmit the power enable signal 372 simply from the mechanical vibration.
The memory 330 may be used for storing sensor data, signal processing results, long-term data storage, and computer instructions for execution by the processor 320. Portions of the memory 330 may be located external to the processor 320 and portions may be located within the processor 320. The memory 330 may be Dynamic Random Access Memory (DRAM), Static Random Access Memory (SRAM), Read Only Memory (ROM), Nonvolatile Random Access Memory (NVRAM), such as Flash memory, Electrically Erasable Programmable ROM (EEPROM), or combinations thereof. In the
In one embodiment, the data analysis module 300 uses battery power as the operational power supply 310. Battery power enables operation without consideration of connection to another power source while in a drilling environment. However, with battery power, power conservation may become a significant consideration in the present invention. As a result, a low power processor 320 and low power memory 330 may enable longer battery life. Similarly, other power conservation techniques may be significant in the present invention.
Additionally, one or more power controllers 316 may be used for gating the application of power to the memory 330, the accelerometers 340A, the magnetometers 340M, and other components of the data analysis module 300. Using these power controllers 316, software running on the processor 320 may manage a power control bus 326 including control signals for individually enabling a voltage signal 314 to each component connected to the power control bus 326. While the voltage signal 314 is shown in
The above described circuitry 60, or any portion thereof, may be located entirely on, within, and/or adjacent the bit 10. Alternatively, some portion, such as the module 52, may be located remotely from the bit 10 or even the BHA. For example, the module 52, and/or certain functionality of the module 52, may be combined with the computer 54 at or near the surface. This may not be a preferred embodiment, in some applications, because of the exposure of the wires 50 that would result. However, armored cable and/or even a wireless communications link may be employed to control such risks.
In one embodiment, one or more of the resistive elements 58a-58d may provide temperature information as well. For example, one or more of the resistive elements 58a-58d may be resistive temperature devices (RTD), or other temperature sensitive resistive elements. Such RTDs 58a-58d could be dispersed about the bit 10, such as the blades 16, in any one or more of loops 50a-50d. Such an embodiment would provide resistive, continuity, and/or temperature information from locations dispersed about the bit 10. As discussed above, the electronics module 290 and/or data analysis module 300 may monitor the elements 58a-58d, as well as the other sensors. In doing so, the electronics module 290 and/or data analysis module 300 is able to combine the resistive, continuity, and/or temperature information with information from the other sensors to determine whether detected changes in the bit 10 itself, or performance of the bit 10, are due to changes in the earth formation or problems with the bit 10.
For example, loss continuity by itself, would potentially indicate that at least a portion of the bit 10 has worn away in the vicinity of the portion of the circuit formed by the wires 50 indicating the loss continuity. A relatively abrupt change in resistivity may also indicate wear in the portion of the bit 10 the vicinity of the portion of the circuit formed by the wires 50 indicating the abrupt change in resistivity. Alternatively, a relatively gradual change in resistivity, especially a reduction in resistivity, would instead likely indicate increased friction in that portion of the bit 10, which may be due to changes in the formation in the vicinity of the bit 10, and may indicate future excessive wear of the bit 10.
Other and further embodiments utilizing one or more aspects of the inventions described above can be devised without departing from the spirit of Applicant's invention. For example, the various methods and embodiments of the drill bit 10 can be included in combination with each other to produce variations of the disclosed methods and embodiments. Discussion of singular elements can include plural elements and vice-versa.
The order of steps can occur in a variety of sequences unless otherwise specifically limited. The various steps described herein can be combined with other steps, interlineated with the stated steps, and/or split into multiple steps. Similarly, elements have been described functionally and can be embodied as separate components or can be combined into components having multiple functions.
The inventions have been described in the context of preferred and other embodiments and not every embodiment of the invention has been described. Obvious modifications and alterations to the described embodiments are available to those of ordinary skill in the art. The disclosed and undisclosed embodiments are not intended to limit or restrict the scope or applicability of the invention conceived of by the Applicants, but rather, in conformity with the patent laws, Applicants intend to fully protect all such modifications and improvements that come within the scope or range of equivalent of the following claims.
This application contains similar subject matter as that disclosed in U.S. patent application Ser. No. 12/327,925 entitled, “Method of Monitoring Wear of Rock Bit Cutters”, filed on Dec. 4, 2008. This application is a continuation-in-part of U.S. patent application Ser. No. 12/332,107 entitled, “Method And System for Detecting Drill Bit Wear”, filed on Dec. 10, 2008. Both of these applications are incorporated herein by specific reference.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 12332107 | Dec 2008 | US |
| Child | 13237754 | US |
