Patent Grant
7913778
Not applicable.
1. Field of the Invention
The present invention relates generally to roller cone rock bits that operate in “drilling mud.” More specifically, the invention relates to roller cone rock bits having nozzle arrangements configured to provide enhanced cutting structure cleaning while offering the potential to reduce cone erosion.
2. Background of the Invention
Rotary cone rock bits are used for drilling boreholes in various earth formations. Roller cone bits are conventionally manufactured using a segmented arc construction method. This method utilizes three 120° arcuate leg segments, each comprising one-third of the drill bit body and an individual leg portion with a bearing journal thereon. The three arcuate sections are usually forged and then machined to form the bearing surfaces on the bearing journals and the mating surfaces along each edge where the three sections are welded together. Prior to joining the three arcuate sections to form a bit body, the cutter assembly with bearings and retention means are mounted on the inwardly projecting bearing journals due to space limitations and associated difficulties of mounting the cutters after the three arcuate sections have been welded together. After the bearing assemblies and cutters are mounted on the machined bearing journals, the three leg segments are then placed in a welding jig and welded to each other to form the bit body. After welding has occurred a tapered thread is machined on the upper end of the bit, commonly referred to as the “pin” end, and the bit is ready for use.
To aid in the removal of drilling cuttings from the bottom of the borehole, mud or other fluids are introduced to the bottom of the borehole through nozzles or jet assemblies positioned in bores formed in the bit body. The fluid or mud pumped through the bit body also serves to remove heat from the rock bit. In general, as the efficiency of the cutting removal is increased, the cutting efficiency and associated rate of penetration (ROP) are also increased.
To efficiently remove cuttings from the borehole, the fluid or mud must carry the cuttings radially outward on the borehole bottom and then upward through the annulus (i.e., the annular space formed between the bit body and drill string, and the borehole). A fluid flow that will carry the cuttings radially outward from the center of the borehole and up the annulus may be created by introducing a downward fluid flow on the cutting structure of the bit. As the fluid flows past the cutting structure, the fluid impacts the borehole bottom and spreads radially outward to the annulus.
The amount of energy available at the bit is generally dictated by factors external to the bit such as the drilling rigs' available hydraulic energy, drill pipe type, bottom hole assembly (BHA) configuration and drill depth. However, once the available energy for the rock bit is determined, properly configuring the hydraulics of the bit for the specific application can significantly affect the rate of penetration (ROP) of the bit in the formation.
When drilling softer formations and plastic formations, there is a strong tendency for cuttings to adhere to the teeth or inserts of bits. The adhesion of formation to teeth or inserts is commonly referred to as “bit balling”. As is known in the art, bit balling describes the packing of formation between the cones and bit body, or between the cutting elements on the bit, during drilling. When bit balling occurs, the cutting elements may be sufficiently packed off such that they are limited in their ability to effectively penetrate into the formation, thereby tending to slow the ROP of the drill bit. Thus, cuttings must be removed efficiently during drilling to maintain reasonable penetration rates.
In harder clays and shales, cuttings can become impacted or “balled up” between the teeth or inserts of the cutting structures. When formation sticks to cones or is impacted between cutting elements it limits the ability of the cutting element to penetrate the formation. Also, formation packed against the cone-shell constricts the flow channels needed to carry cuttings away. This promotes premature bit wear. In either instance, having sufficient drilling fluid directed toward the cones can help to clean the inserts and cones, allowing them to penetrate to a greater depth, thus maintaining the ROP of the bit. Furthermore, bit durability may be improved, even as the inserts begin to wear down since the cleaned inserts will continue to penetrate the formation even in their reduced state.
To combat bit balling and to allow for larger cones, the cutting elements on adjacent rolling cones are often arranged to intermesh. As a cutting element of a first cone intermeshes between two rows of cutting elements of a second cone, it dislodges formation packed between the two rows of cutting elements. Having the cutting elements intermesh also allows the diameter of the cones to be larger, providing for a larger bearing surface which results in a more durable cone.
To further facilitate cuttings removal, jets or nozzles are positioned on the bit to wash cuttings from the cutting structure and/or borehole bottom. Conventional nozzle arrangements include the placement of a nozzle between each of the cones proximal the outer periphery of the bit. In many applications, a jet may also be located at the center of the bit to channel fluid flow directly to the borehole bottom. For example, U.S. Pat. No. 5,853,055 describes an extended center jet on a bit to reduce diffusion and provide a substantially uninterrupted fluid flow that strikes the borehole bottom with maximum impact energy. U.S. Pat. No. 6,290,006 describes special nozzles that can be used to provide collimated streams of high velocity drilling fluid that strike different areas of the bottomhole with maximum energy for enhanced bottomhole cleaning. An alternative nozzle arrangement involves a jet positioned between each of the cones near the periphery of the bit body. U.S. Pat. No. 4,611,673 proposes orienting nozzles toward one of the adjacent cones so that the jet of fluid exiting the nozzle will strike the cutting elements on the cone. However, these arrangements may not be desirable in applications where bit balling is a concern because they do not provide cleaning along interior rows of cutting elements on the cones, and further, a concentrated flow of drilling fluid directed toward and impacting a cone shell may result in excessive erosion of the cones and premature loss of cutting elements from the cones.
To avoid balling problems, bits have been designed with additional nozzles positioned over each of the cones which direct a jet stream of fluid directly on top of the cones in the dome region. One problem with these designs is that the impact of fluid directly on top of the cones often results in severe erosion of the cone shell and a premature loss of cutting elements from the cones. The placement of these nozzles has been restricted in the prior art to nozzle bores where the nozzles are installed through the pin due to limited access to the dome region from the journal side of the forging to drill the required nozzle bores.
In the prior art, a cast bit body was proposed that allowed for the machining and installation of nozzles before the leg portions were attached to the body. Unfortunately, the method requires a cast body formed separately from the leg portions. In practice, this type of cast body method is not typically used, and is generally limited to the manufacture of extremely large bits. Further, these designs may require insertion of the nozzles in the bit body prior to assembly of the legs on the bit. In practice, nozzles are typically inserted in the field after assembly of the bit based on rig specifications and drilling requirements particular to a specific application.
Numerous efforts have been made by drill bit designers to solve the problem of bit balling yet the problem persists. Accordingly, there is a need in the art for bits having an improved nozzle configuration that provides sufficient cleaning for cutting elements along the inner rows and outer rows of the cones to minimize bit balling. Such bits with improved nozzle configurations would be particularly well received if they reduced impingement of the cone shell with drilling fluid, thereby offering the potential to reduce the likelihood of cone shell erosion and associated premature loss of cutting elements.
These and other needs in the art are addressed in one embodiment by a drill bit for drilling through an earthen formation to form a borehole with a radius R, a bottom and a sidewall, the drill bit having a full gage diameter with the radius R. In an embodiment, the drill bit comprises a bit body having a central bit axis and including a pin end, an internal plenum, and a dome side generally opposite the pin end. The dome side includes a central dome region extending from the bit axis to about 10% of the radius R, an annular intermediate dome region extending from the central region to about 50% of the radius R, and an annular outer dome region extending from the intermediate region to about 90% of the radius R. In addition, the drill bit comprises an intermediate receptacle having a central axis and extending through the intermediate dome region to the plenum. Further, the drill bit comprises a first and a second rolling cone, each cone being mounted to the bit body and adapted for rotation about a different cone axis. Each cone comprises a nose proximal the bit axis, a generally planar backface distal the bit axis, an inner cone region extending axially relative to the cone axis from the nose to an intermediate cone region, and an outer cone region extending axially relative to the cone axis from the backface to the intermediate region. A plurality of cutting elements are mounted to the inner region, the intermediate region, and the outer region of each cone, wherein the cutting elements mounted to the inner cone region of each cone are positioned to contact the borehole bottom between the bit axis and about 25% of the radius R, the cutting elements mounted to the intermediate cone region of each cone are positioned to contact the borehole bottom between about 25% and 75% of the radius R, and the cutting elements mounted to the outer cone region of each cone are positioned to contact the borehole bottom between about 75% and 100% of the radius R. Moreover, wherein a projection of the central axis passes between the intermediate region of the first cone and the intermediate region of the second cone.
Theses and other needs in the art are addressed in another embodiment by a drill bit for drilling through an earthen formation to form a borehole with a radius R, a bottom and a sidewall, the drill bit having a full gage diameter with the radius R. In an embodiment, the drill bit comprises a bit body having a central bit axis and including a pin end, an internal plenum, a dome side generally opposite the pin end, a first leg, and a second leg circumferentially spaced from the first leg, each leg including a journal. The dome side includes a central dome region extending from the bit axis to about 10% of the radius R, an annular intermediate dome region extending from the central region to about 50% of the radius R, and an annular outer dome region extending from the intermediate region to about 90% of the radius R. In addition, the drill bit comprises an intermediate receptacle having a central axis and extending through the intermediate dome region to the plenum. Further, the drill bit comprises a first rolling cone mounted to the journal of the first leg and adapted for rotation about a first cone axis. Still further, the drill bit comprises a second rolling cone mounted to the journal of the second leg and adapted for rotation about a second cone axis. A reference plane parallel to and passing through the bit axis is positioned at the circumferential midpoint between the first leg and the second leg. A first boundary plane parallel to and passing through the bit axis is oriented at a boundary angle β1 relative to the reference plane. A second boundary plane parallel to and passing through the bit axis is oriented at a boundary angle β2 relative to the reference plane. The first boundary plane and the second boundary plane are disposed on opposite sides of the reference plane. The first boundary angle β1 and the second boundary angle β2 are each less than 30°. Moreover, a projection of the central axis of the intermediate receptacle is circumferentially bounded by the first boundary plane and the second boundary plane between the dome side and the borehole bottom.
Theses and other needs in the art are addressed in another embodiment by a drill bit for drilling an earthen formation to form a borehole with a radius R. In an embodiment, the drill bit comprises a bit body having a central axis and a dome side. The dome side includes a central dome region extending from the bit axis to about 10% of the radius R, an annular intermediate dome region extending from the central region to about 50% of the radius R, and an annular outer dome region extending from the intermediate region to about 90% of the radius R. In addition, the drill bit comprises a plurality of rolling cones, each of the cone cutters being mounted to the bit body and adapted for rotation about a different cone axis. Further, the drill bit comprises a plurality of intermeshing cutting elements mounted to each of the cones. Still further, the drill bit comprises a plurality of intermediate receptacles in the bit body. Each intermediate receptacle has a central axis and extends through the intermediate dome region to the plenum. One intermediate receptacle is circumferentially positioned between the cone axes of each pair of adjacent cones. Moreover, a projection of the central axis of each intermediate receptacle passes through the intermeshing cutting elements between each pair of adjacent cone cutters.
Thus, embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments, and by referring to the accompanying drawings.
For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
The following discussion is directed to various embodiments of the invention. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment.
Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing Figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices and connections.
Referring first to
Bit 10 includes lubricant reservoirs 17 that supply lubricant to the bearings that support each of the cone cutters 1-3. Bit legs 19 include a shirttail portion 16 that serves to protect the cone bearings and cone seals from damage caused by cuttings and debris entering between leg 19 and its respective cone cutter.
Referring now to both
As best shown in
Referring still to
Extending between heel surface 44 and nose 42 is a generally conical cone surface 46 adapted for supporting cutting elements that gouge or crush the borehole bottom 7 as the cone cutters rotate about the borehole. Frustoconical heel surface 44 and conical surface 46 converge in a circumferential edge or shoulder 50. Although referred to herein as an “edge” or “shoulder,” it should be understood that shoulder 50 may be contoured, such as by a radius, to various degrees such that shoulder 50 will define a contoured zone of convergence between frustoconical heel surface 44 and the conical surface 46. Conical surface 46 is divided into a plurality of generally frustoconical regions 48, generally referred to as “lands”, which are employed to support and secure the cutting elements as described in more detail below. Grooves 49 are formed in cone surface 46 between adjacent lands 48.
In the bit shown in
Heel inserts 60 generally function to scrape or ream the borehole sidewall 5 to maintain the borehole at full gage and prevent erosion and abrasion of the heel surface 44. Gage inserts 80 function primarily to cut the corner of the borehole. Binary row inserts 70 function primarily to scrape the borehole wall and limit the scraping action of gage inserts 80 thereby preventing gage inserts 80 from wearing as rapidly as might otherwise occur. Inner row cutter elements 81, 82, 83 of inner rows 81a, 82a, 83a are employed to gouge and remove formation material from the remainder of the borehole bottom 7, and thus, may also be referred to here in as “bottomhole” cutting elements.
Insert rows 81a, 82a, 83a are arranged and spaced on rolling cone cutter 1 so as not to interfere with rows of inner row cutter elements on the other cone cutters 2, 3. Cone 1 is further provided with relatively small “ridge cutter” cutter elements 84 in nose region 42 which tend to prevent formation build-up between the cutting paths followed by adjacent rows of the more aggressive, primary inner row cutter elements from different cone cutters. Cone cutters 2 and 3 have heel, gage and inner row cutter elements and ridge cutters that are similarly, although not identically, arranged as compared to cone 1. The arrangement of cutter elements differs between the three cones in order to maximize borehole bottom coverage, and also to provide clearance for the cutter elements on the adjacent cone cutters.
In the embodiment shown, inserts 60, 70, 80-83 each includes a generally cylindrical base portion, a central axis, and a cutting portion that extends from the base portion, and further includes a cutting surface for cutting the formation material. The base portion is secured by interference fit into a mating socket drilled into the surface of the cone cutter. In general, the cutting surface of an insert refers to the surface of the insert that extends beyond the surface of the cone cutter.
As shown in
In some drilling applications, such as the drilling of carbonates in the Middle East, the relatively close spacing of cutting elements 80, 81 on cones 1-3 causes rows 80a, 81a to experience “balling” or “balling-up” of cuttings between them. Balling also tends to occur on other places on cones 1-3, such as between inner rows 81a, 82a, 83a. When bit balling occurs, it impedes the progress and ROP of the bit by preventing the cutting elements from penetrating completely into the earth formation, thereby tending to reduce the rate of penetration.
To address bit balling in these and other applications, nozzles have been typically placed along the outer periphery of the bit between each pair of cones to clean cuttings from the cones and/or the borehole bottom. In some cases, an additional nozzle is also positioned at the center of the bit in the dome region to direct fluid flow on top of the cones near the center of the bit. While these configurations have led to reduced bit balling, bit balling still frequently occurs between the cutting elements of the inner rows due to insufficient cleaning along the inner rows. To further address bit balling, a new nozzle arrangement was proposed which replaced the conventional center jet in the dome region with three smaller nozzles which were closely spaced near the center of the dome, each nozzle positioned above a cone to direct a jet of fluid on top of inner rows of the cone. While this configuration has been shown to provide enhanced cleaning of the cones it has also resulted in severe erosion of cone shell surfaces and premature loss of cutting elements from the cones.
The location, spacing, and orientation of these additional nozzles in the dome region have traditionally been restricted because nozzle boreholes are conventionally drilled through the pin side of the bit (e.g., through passage 24 from pin end 14). In particular, due to limited access to the interior dome region of the bit once the bit is assembled, for bit designs comprising multiple rows of cutting elements intermeshing between the cones, the conventional approach has been to (a) drill the nozzle bores or receptacles in the interior the dome through the pin side of the bit and (b) install the nozzles from the pin side.
Referring briefly to
Referring briefly to
Referring now to
The intermeshing arrangement of cones 1-3 is also desirable to reduce balling. As a row of cutting elements of one cone intermesh between the rows of cutting elements of another cone, it dislodges balling between the rows of cutting elements on the adjacent cone. As shown in
Moreover, having intermesh allows the diameter of the cones to be larger, providing for a larger bearing surface which results in a more durable cone. In general, performance expectations of rolling cone bits typically require that the cone cutters be as large as possible within the borehole diameter so as to allow use of the maximum possible bearing size and to provide a retention depth adequate to secure the cutter element base within the cone steel. Intermeshing cutting elements of adjacent cones offers the potential to achieve maximum cone cutter diameter and still have acceptable insert retention and protrusion.
As best shown in
Intermediate cone region 103 has an associated cone shell surface 103a, and in this embodiment, generally includes all of the intermeshing cutting elements (e.g., cutting elements 82, 83). Inner cone region 102 has an associated cone shell surface 102a including nose 42, and in this embodiment, generally includes the radially inner (relative to bit axis 11) non-intermeshing cutting elements (e.g., cutting elements 84). Outer cone region 104 has an associated cone shell surface 104a, and in this embodiment, generally includes the radially outer (relative to bit axis 11) non-intermeshing cutting elements (e.g., gage cutting elements 80 and first inner row cutting elements 81).
Referring still to
Referring now to
As best shown in
Referring again to
In general, each leg 19 may be formed by conventional manufacturing techniques. Once leg 19 is formed, sleeve receptacles 25, 35 may be drilled or bored into leg 19. It should be appreciated that intermediate sleeve receptacles 25 are in close proximity to finished journal pin 20. Consequently, the drilling or boring operation to form receptacles 25 is preferably performed with great care and attention to avoid damaging the journal surface.
In this embodiment, each receptacle 15, 25, 35 is a substantially straight, cylindrical bore having a single central axis 15′, 25′, 35′, respectively. However, in other embodiments, one or more receptacles (e.g., receptacles 15, 25, 35) may include a turn or bend. In other words, in other embodiments, one or more receptacles may have a first or upstream section extending along a first central axis and a second or downstream section extending along a second central axis that is skewed relative to the first central axis as described in U.S. patent application Ser. No. 12/104,856 filed Apr. 17, 2008, and entitled “Rock Bit with Vectored Hydraulic Nozzle Sleeves”, which is hereby incorporated herein by reference in its entirety.
Although a central sleeve receptacle (e.g., central sleeve receptacle 15) is included in this embodiment, in other embodiments, the central sleeve receptacle may be omitted. Inclusion of a central sleeve receptacle may be dictated by a variety of factors including, without limitation, the size of the bit. For example, in relatively larger bits (e.g., bits a diameter greater than about 20.00 inches), there may be sufficient space on the underside (e.g., dome 21) for a central sleeve receptacle, intermediate sleeve receptacles (e.g., intermediate sleeve receptacles 25), and outer sleeve receptacles (e.g., outer sleeve receptacles 35). However, as the bit diameter decreases (e.g., bits having a diameter less than 20.00 inches), the intermediate sleeve receptacles are often moved radially inward toward the bit axis. If the intermediate sleeve receptacles are moved sufficiently inward, there may not be adequate space to include a central sleeve receptacle.
As best shown in
Referring now to
As best shown in
As previously described, central sleeve receptacle 15 is radially positioned within central dome region 92, outer sleeve receptacles 35 are each radially positioned within outer dome region 96, and intermediate sleeve receptacles 25 are each radially positioned within intermediate dome region 94. More specifically, as best shown in
Prior to drilling, a jet or nozzle (not shown) is disposed in the downstream end of each sleeve 15a, 25a, 35a. Consequently, each sleeve 15a, 25a, 35a may also be referred to as “nozzle retention sleeve.” In general, each nozzle may be secured within the downstream end of its mating nozzle retention sleeve (e.g., sleeve 15a, 25a, 35a) by any suitable means including, without limitation, mating threads, press-fitting, welding, snap rings, or combinations thereof. Each nozzle is preferably releasably received by its mating nozzle retention sleeve such that the nozzles may be replaced or changed in the field depending on the desired flow rate through each nozzle and desired flow pattern. In some embodiments, one or more of the sleeves (e.g., central sleeve 15a) may be “blanked,” such that the downstream end of the sleeve is completely closed off, thereby preventing the flow of drilling fluid through the sleeve.
For purposes of the following explanation, the nozzles secured within outer sleeves 35a will be referred to as “outer nozzles,” the nozzles secured within intermediate sleeves 25a will be referred to as “intermediate nozzles,” and the nozzle secured within central sleeve 15a will be referred to as the “central nozzle.” In general, the outer nozzles, the intermediate nozzles, and the central nozzle may be any suitable type of nozzle including, without limitation, straight bore nozzles, multistage nozzles, diffusing nozzles, etc. In a straight bore nozzle, the area of the nozzle throat is generally the same size as the nozzle outlet. In a multistage nozzle, the upstream portion of the nozzle has a converging section and the downstream end includes a distributor having a plurality of exit holes, usually three exit holes. Drilling fluid flowing through a multistage nozzle is accelerated towards the distributor, where the fluid flow is divided into multiple streams by the distributor, which may target different areas of the bit and/or borehole. Due to impingement with the distributor, streams of drilling fluid exiting a multistage nozzle tend to have lower velocities and energy, and thus, generally present a reduced likelihood of causing cone erosion. A variety of multistage nozzles are described in U.S. Pat. Nos. 6,585,063 and 7,188,682, each of which is incorporated herein by reference in its entirety. In a diffusing nozzle, the outlet portion diverges from a smaller diameter portion within the orifice. Consequently, drilling fluid exiting a diffuser nozzles diffuses and diverges so as to potentially cover an increased target cleaning area. A variety of diffusion nozzles are described in U.S. Pat. No. 5,601,153, which is hereby incorporated herein by reference in its entirety. Since cone shell erosion and associated premature loss of cutting elements is more likely with streamlined or culminated flow, the outer nozzles and intermediate nozzles are preferably diffuser nozzles, and the central nozzle is preferably a diffuser nozzle or multistage nozzle. Each nozzle is preferably formed of a wear resistant material such as cemented tungsten carbide.
Without being limited by this or any particular theory, the greater the nozzle orifice diameter (or the sum of the orifice diameters in a multistage nozzle), the greater the total drilling fluid volumetric flow through the nozzle. Thus, the orifice diameters of the nozzles may be sized or selected to provide the desired drilling fluid flow allocation through the plurality of nozzles. In this embodiment, each outer nozzle has an orifice of a selected minimum diameter D, and each intermediate nozzle has an orifice of a selected minimum diameter d that is less than diameter D. Consequently, a drilling fluid volumetric flow through the outer nozzles is greater than the drilling fluid volumetric flow through the intermediate nozzles. In one embodiment, the nozzle orifice diameters D, d are preferably selected to provide a drilling fluid volumetric flow allocation ranging from 45% to 80% through the outer nozzles and from 20% to 55% through the intermediate nozzles, and more preferably a drilling fluid volumetric flow of 55% to 70% through the outer nozzles and 30 to 45% through the intermediate nozzles. In embodiments including a center nozzle, preferably at least 10% of the drilling fluid volumetric flow rate is directed through the center nozzle to alleviate bit balling near the center of the cones and/or to ensure that the fluid or mud flow carrying cuttings will flow radially outward from the center of the borehole and up the annulus formed between the bit and the borehole.
As indicated by each centerline 35c, outer sleeves 35a and associated outer nozzles are generally positioned and oriented to direct drilling fluid generally downward toward the cutting elements between outer regions 104 of each pair of adjacent cones 1-3. More specifically, the stream of drilling fluid represented by centerline 35c first strikes the tips of gage cutting elements 80 and inner row cutter elements 81 in outer regions 104 as they rotate between cones 1-3 to wash cuttings from therefrom (
As indicated by centerlines 25c, intermediate sleeves 25a and associated intermediate nozzles are generally positioned and oriented to direct drilling fluid generally downward toward the cutting elements between intermediate regions 103 of each pair of adjacent cones 1-3. More specifically, the stream of drilling fluid represented by centerline 25c first strikes cutting elements 82, 83 in inner rows 82a, 83a in intermediate regions 103 as they rotate between cones 1-3 to wash cuttings therefrom (
As best shown in
As best shown in
Although intermediate sleeve receptacles 25 and intermediate sleeves 25a are described as being positioned and oriented to direct drilling fluid toward the cutting elements between each pair of adjacent cones 1-3 to reduce the potential for cone erosion, in other embodiments, the intermediate receptacles (e.g., intermediate sleeve receptacles 25) and associated intermediate sleeves (e.g., intermediate sleeves 25a) may be positioned and oriented to direct drilling fluid toward the cone shell surface (e.g., cone shell surface 102a, 103a, 104a) of one of the cone cutters between which the intermediate sleeve is disposed. For example, in cases of extreme bit balling, it may be desirable to increase the hydraulic energy on the cone shell surface to enhance the cone cleaning capabilities. Consequently, the intermediate receptacle, intermediate sleeve, and associated nozzle may be positioned and oriented to direct drilling fluid towards the cone shell surface of one of the adjacent cones in order to disburse significantly more hydraulic energy on that cone shell surface than the adjacent cone shell surface. This offers the potential for increased cone cleaning in applications with extreme balling tendencies. The bit designer may determine how much energy to project onto a given cone shell based on a variety of factors including, without limitation, the abrasiveness of the application, the amount of hydraulic energy that will be expended thru the bit hydraulic system and the number of hours the bit will be run. For such embodiments where some cone shell impingement is desired, each boundary angle β1, β2 may be as great as 50°.
In general, the column of exiting drilling fluid tends to increase in diameter with distance from the nozzle exit. Thus, one or more of the outer nozzle exits, intermediate nozzle exits, or combinations thereof may be extended or retracted relative to dome 21 through different nozzle designs or sleeve designs as desired to provide a fluid flow that impacts the cutting structure and borehole bottom with a desired amount of energy. For example, one or more sleeves (e.g., intermediate sleeves 25a, outer sleeves 35a, etc.) may extend from dome 21 to a point below a highest horizontal plane perpendicular to bit axis 11 intersected by the rolling cone cutters (e.g., cones 1-3). Generally, this highest plane is the plane intersected by the gage rows of inserts when positioned in an uppermost position. As shown in
Receptacles 25, 35, sleeves 25a, 35a, and associated intermediate and outer nozzles, respectively, are positioned and oriented to direct drilling fluid flow between adjacent cones 1-3 in a generally downward direction toward borehole bottom 7, thereby minimizing impingement of cone shells 36. As a result, embodiments described herein offer the potential to provide improved cleaning of both radially inner and radially outer cutter elements, and reduced likelihood of undesirable erosion of cone shells 36. In addition, by reducing impingement of cone shells 36, embodiments described herein also offer the potential to enhance the energy and impact force of the drilling fluid flowing across the cutting elements to borehole bottom 7. To further reduce the potential for cone erosion, in some embodiments, one or more of the intermediate and/or outer nozzles may comprise a diffuser nozzle which diffuses fluid flow exiting the nozzle outlet. The diffuser nozzle reduces the fluid velocity at the nozzle exit which aids in reducing cone shell erosion, and also increases the surface area of cutting elements are cleaned as the fluid flows downward toward the borehole bottom.
Although sleeves 25a, 35a, and intermediate and outer nozzles, respectively, are described as being positioned and oriented to direct drilling fluid generally downward between adjacent cones 1-3, they may be slightly angled toward one of the two adjacent cones they are disposed between in order to direct drilling fluid closer to the leading side or trailing side of one of the adjacent cones. For instance, in this embodiment, each outer sleeves 35a and associated outer nozzles (and hence centerlines 35c) are slightly angled toward the leading side of cones 1-3. As used herein, the phrase “leading side” may be used to refer to the side of a cone cutter that is rotating towards and into the formation, whereas the term “trailing side” may be used to refer to the side of a cone cutter that is rotating out of and away from the formation.
Moreover, although each centerline 25c is oriented similarly relative to its adjacent journal axes 22, cones 1-3 and associated cutting elements, in other embodiments, the receptacles, sleeves, and/or associated nozzles may be positioned and oriented such that one or more of the drilling fluid trajectory centerlines (e.g., centerlines 25, 35) is oriented differently. This selective positioning and orienting of receptacles, sleeves, and nozzles may be done to provide an optimized flow regime for a given bit design based on a Computational Fluid Dynamic (“CFD”) analysis of the fluid flow around the bit and bottomhole during drilling.
Referring now to
The positioning and orientation of nozzle sleeves 15a, 25a, 35a and associated nozzles previously described offers the potential to increase the ROP and durability of bit 10 by enhancing cutting element cleaning and reducing cone shell impingement. Although preferred locations and orientations of the receptacles (e.g., receptacles 15, 25, 35), the sleeves (e.g., sleeves 15a, 25a, 35a), and the associated nozzles may have been described, the optimal positioning and orientation of each receptacle, sleeve, and nozzle may be varied depending on a variety of factors including, without limitation, the bit size, the formation being drilled, and the hydraulic energy provided to the bit from the surface. Thus, it should be appreciated that in other embodiments, the size, location, and orientation of each receptacle, sleeve, and nozzle may be different than that shown.
Embodiments described herein including three outer receptacles (e.g., outer sleeve receptacles 35), three intermediate receptacles (e.g., intermediate sleeve receptacles 25), and a center receptacle (e.g., center receptacle 15) are particularly suited for relatively larger bits with diameters greater than about 16.0 inches, and especially for those bits with diameters greater than about 20.00 inches. Relatively smaller bits inches may not provide sufficient space in the underside for both intermediate receptacles and a center receptacle. Consequently, in such smaller bits, the center receptacle or the intermediate receptacles may be eliminated. Moreover, in relatively smaller bits, fewer than six receptacles and nozzles may provide sufficient cleaning capability for the cutting elements and the borehole bottom. For instance, in smaller bits the surface area of the cutting structure to be cleaned is reduced. However, in relatively larger bits, the surface area of the cutting structure and borehole to be cleaned is increased, and may require additional receptacles and nozzles. Consequently, embodiments described herein including six or more receptacles are preferred for relatively larger bits having diameters greater than about 9.00 inches, and even more preferred for bits having diameters greater than about 15 inches.
Although the embodiment of bit 10 shown in
In some cases, it may be geometrically possible and practical to achieve the preferred drilling fluid trajectory by simply drilling or boring a straight receptacle in the dome region in alignment with the desired drilling fluid trajectory. With the sleeve coaxially disposed in the receptacle, the drilling fluid will flow through the sleeve and exit the nozzle disposed in the sleeve in a direction substantially aligned with the desired trajectory. For example, in this embodiment, receptacle 25 is a straight bore through dome 21 within which a straight cylindrical sleeve 25a is disposed. Receptacle 25 and sleeve 25a share a common central axis 25′ that is aligned with the desired drilling fluid trajectory centerline 25c. Consequently, drilling fluid flowing through sleeve 25a and the nozzle disposed in the downstream end of sleeve 25a will exit along centerline 25c. However, in other cases, it may be geometrically impossible and/or impractical to bore the nozzle receptacle in alignment with the desired drilling fluid exiting trajectory. For example, in this embodiment, due to space limitations proximal the periphery of dome 21, outer sleeve receptacle 35 is bored through dome 21 along a centerline 35′ that is out of alignment with the desired drilling fluid trajectory centerline 35c. Thus, the direction of drilling fluid flowing from plenum 24 through outer sleeve receptacle 35 must be adjusted to achieve the desired centerline 35c. Such adjustment in the direction of the drilling fluid may be achieved by the sleeve as described in U.S. patent application Ser. No. 12/104,856 filed Apr. 17, 2008, and entitled “Rock Bit with Vectored Hydraulic Nozzle Sleeves”, which is hereby incorporated herein by reference in its entirety.
The portions of the cone shell (e.g., cone shell 36) proximal the cutting elements impinged by the drilling fluid exiting a nozzle may be coated with an abrasion resistant material to increase erosion resistance. This erosion, referred to as cone shell erosion, typically occurs in areas near the paths of mud or fluid emitted from the nozzles of the bit or in areas proximate the borehole surfaces struck by the mud or fluid flow. In the areas near the flow, the mud or fluid may strike or may be deflected onto the cones and cutters resulting in their erosion. A typical erosion resistant coating would comprise a conventional hardfacing with tungsten carbide particles or a coating of tungsten carbide. These coatings can be applied via a high velocity implantation method such as the Super D-Gun method. To reduce erosion, the cutting elements proximate a fluid flow may also be fabricated of a material with enhanced wear resistance properties.
Erosion of the leg forging itself may also occur as the abrasive drilling fluid flows at relatively high velocities from the plenum through the receptacles. Consequently, an erosion resistant wear sleeve may be disposed in one or more of the outer and/or intermediate receptacles. For example, referring now to
The use of erosion resistant wear sleeve 225a is particularly useful in relatively smaller bits where larger nozzle bores are prohibitive due to the lack of available space in the smaller leg forgings. In general, the inclusion of wear sleeve 225a allows for higher drilling fluid flow rates through receptacle 225 nozzle than would be possible with steel due to the risk of internal erosion of the steel leg forging.
In the manufacture of a leg as shown in
Embodiments described herein offer the potential for dome side installation and/or removal of the intermediate nozzles using a suitable tool such as a tool comprising a T-wrench handle, extension, universal joint, and wrench head. This tool also permits removal of the nozzle from the bit and replacement of a different nozzle size or type as desired. The ability to mill and install nozzles from the underside of the bit permits increased flexibility in the location and orientation of nozzles in the intermediate region of the underside as compared to nozzles placed in receptacles milled through the pin side of the bit. Milling and installation through the pin side of the bit is generally limited because of the limited line of sight provided in the interior of the bit and the limited space available for maneuvering a traditional (straight) nozzle wrench for installing nozzles. Because of these limitations orientation of nozzle bores located in the intermediate region of the underside of conventional bits has been largely limited to orientations that result in direct impingement of fluid flow on top of the cones. While installation from a dome side of the bit has been discussed, it should be appreciated that in other embodiments the intermediate nozzles may be installed from the pin end.
Although the embodiments described herein were described as having three rolling cones cutters 1-3, the principles described may also be applied to a bit having any number of cones (e.g., 1, 2, 4, etc.). Further, although three intermediate sleeve receptacles 25 and three outer sleeve receptacles 35 are shown in the embodiments described herein, in other embodiments any suitable number of receptacles and associated nozzles. For example, in one embodiment, a three cone bit may include two intermediate receptacles and associated nozzles and three outer receptacles and nozzles, with one intermediate receptacle and outer receptacle disposed between two pair of adjacent cones, and only an outer receptacle disposed between the third pair of adjacent cones. It is believed that this configuration may result in sufficient cleaning of the cones in many applications because the intermediate and outer nozzles between two pairs of adjacent cones may be arranged to clean opposite cones and the single outer nozzle between the third pair of adjacent cones may be arranged to clean between the intermesh of the third pair of cones and may include a diffuser nozzle such that cutting structure cleaning is provided one each of the cones near gage and intermesh regions of the cones. In such an embodiment, and center nozzle may also be added for enhanced cone cleaning near the nose portions of the cones.
As previously described, the placement and directionality of the receptacles and associated nozzles, as well as the nozzle sizing and nozzle extension, can significantly affect the rate of penetration for the drill bit and bit life. The optimal placement, directionality and sizing of each nozzle can change depending on the bit size, the formation type being drilled, and the hydraulic energy provided to the bit from the surface. Thus, it should be appreciated that in other embodiments, nozzle sizes, locations, orientations, and extensions may be different than that shown for embodiments herein to best suit drilling requirements for a particular application.
The following examples are given as to particular aspects of the embodiments described herein and to demonstrate the practice and advantages thereof. It is understood that the examples are given by way of illustration and are not intended to limit the specification of the claims to follow in any manner.
A computational study was performed to compare the energy levels on the surface of each cone of a conventional three-cone bit and an embodiment of a three-cone bit in accordance with the principles herein. for two case studies. The conventional bit was a 16.00 inch three-cone bit having an intermediate nozzle positioned and oriented to direct drilling fluid on the top of each cone. The bit in accordance with the principles described herein was also a 16.00 inch bit, however, an intermediate nozzle was positioned and oriented to direct drilling fluid through the intermesh in between each pair of adjacent cones. The intermediate nozzles in both bits were of the same size and type. To determine the energy levels on the cone surfaces, the shear stress was evaluated in the area where the high velocity drilling fluid had the most direct and greatest impact on the cone shell surface. The maximum shear stresses on the cone surface for each cone was measured for both bits and then normalized. Normalizing was performed on a cone-by-cone basis by dividing the maximum shear stress measured for each cone by the maximum shear stress measured for the analogous cone of the intermesh impingement bit (i.e., the bit in accordance with the principles described herein) Thus, the normalized surface shear stress experienced by each cone of the intermesh impingement bit always had a value of one. As shown in
While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the system and apparatus are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.
This application claims benefit of U.S. provisional application Ser. No. 60/979,806 filed Oct. 12, 2007, and entitled “Rock Bit with Hydraulics Configuration,” which is hereby incorporated herein by reference in its entirety. This application also claims benefit of U.S. provisional application Ser. No. 61/038,888 filed Mar. 24, 2008, and entitled “Rock Bit with Vectored Hydraulic Nozzle Retention Sleeves,” which is hereby incorporated herein by reference in its entirety. This application also claims benefit of U.S. non-provisional application Ser. No. 12/104,856 filed Apr. 17, 2008, and entitled “Rock Bit With Vectored Hydraulic Nozzle Retention Sleeves,” which is hereby incorporated herein by reference in its entirety.
| Number | Name | Date | Kind |
|---|---|---|---|
| 2901223 | Scott | Aug 1959 | A |
| 4187921 | Garner | Feb 1980 | A |
| 4369849 | Parrish | Jan 1983 | A |
| 4611673 | Childers et al. | Sep 1986 | A |
| 4665999 | Shoemaker | May 1987 | A |
| 4741406 | Deane et al. | May 1988 | A |
| 4848476 | Deane et al. | Jul 1989 | A |
| 4984643 | Isbell et al. | Jan 1991 | A |
| 5538093 | Siracki et al. | Jul 1996 | A |
| 5601153 | Ensminger et al. | Feb 1997 | A |
| 5853055 | Siracki et al. | Dec 1998 | A |
| 6065683 | Akin et al. | May 2000 | A |
| 6098728 | Wells et al. | Aug 2000 | A |
| 6290006 | Crawford | Sep 2001 | B1 |
| 6311793 | Larsen et al. | Nov 2001 | B1 |
| 6354387 | Harris et al. | Mar 2002 | B1 |
| 6571887 | Nguyen et al. | Jun 2003 | B1 |
| 6585063 | Larsen | Jul 2003 | B2 |
| 6651758 | Xiang et al. | Nov 2003 | B2 |
| 7188682 | Larsen et al. | Mar 2007 | B2 |
| 7213661 | Larsen et al. | May 2007 | B2 |
| 7370711 | Singh | May 2008 | B2 |
| 20050121235 | Larsen et al. | Jun 2005 | A1 |
| 20060054355 | Larsen et al. | Mar 2006 | A1 |
| 20070034411 | Singh | Feb 2007 | A1 |
| 20070163811 | Gutmark et al. | Jul 2007 | A1 |
| 20090159340 | Tedeschi et al. | Jun 2009 | A1 |
| Number | Date | Country |
|---|---|---|
| 1182105 | Feb 1985 | CA |
| 872076 | Apr 1960 | GB |
| 2408763 | Jun 2005 | GB |
| 2443115 | Apr 2008 | GB |
| 2454068 | Jun 2010 | GB |
| 2461429 | Jun 2010 | GB |
| 2461430 | Jun 2010 | GB |
| 2019668 | Sep 1994 | RU |
| 2191244 | Oct 2002 | RU |
| Number | Date | Country | |
|---|---|---|---|
| 20090095536 A1 | Apr 2009 | US |
| Number | Date | Country | |
|---|---|---|---|
| 60979806 | Oct 2007 | US | |
| 61038888 | Mar 2008 | US |
