Patent Grant
11098541
The invention relates to fixed cutter drag bits for drilling oil and gas wells using compressible gases as a circulation medium.
Polycrystalline-diamond compact (PDC) bits are a type of rotary drag bit used for boring through subterranean rock formations when drilling oil and natural gas wells. As a PDC bit is rotated, discrete cutting structures affixed to the face of the bit drag across the bottom of the well, scraping or shearing the formation. PDC bits use cutting structures, referred to as “cutters,” each having a cutting surface or wear surface comprised of a polycrystalline-diamond compact (PDC), hence the designation “PDC bit.”
Each cutter of a rotary drag bit is positioned and oriented on a face of the drag bit so that a portion of it, which may be referred to as its wear surface, engages the earth formation as the bit is being rotated. The cutters are spaced apart on an exterior cutting surface or face of the body of a drill bit in a fixed, predetermined pattern. The cutters are typically arrayed along each of several blades, which are raised ridges extending generally radially from the central axis of the bit, toward the periphery of the face. The cutters along each blade present a predetermined cutting profile to the earth formation, shearing the formation as the bit rotates. A drilling fluid pumped down the drill string, into a central passageway formed in the center of the bit, and then out through ports formed in the face of the bit, both cools the cutters and helps to remove and carry cuttings from between the blades. Conventional methods use liquid drilling fluid that is generally incompressible when employing PDC bits due to erosion issues.
The shearing action of the cutters on the rotary drag bits is substantially different from the crushing action of a roller cone bit, which is another type of bit frequently used for drilling oil and gas wells. Roller cone bits are comprised of two or three cone-shaped cutters that rotate on an axis with an angle that is oblique to the axis of rotation of the drill bit. As the bit is rotated, the cones roll across the bottom of the hole, with the teeth crushing the rock as they pass between the cones and the formation.
Each PDC cutter is fabricated as a discrete piece, separate from the drill bit, by bonding a layer of polycrystalline diamond, sometimes called a crown or diamond table, to a substrate. PDC, though very hard and abrasion resistant, tends to be brittle. The substrate, while still very hard, is tougher, thus improving the impact resistance of the cutter. The substrate is typically made long enough to act as a mounting stud, with a portion of it fitting into a pocket or recess formed in the body of the bit. However, the PDC and the substrate structure can be attached to a metal mounting stud. Because of the processes used for fabricating them, the wear layer and substrate typically have a cylindrical shape, with a relatively thin diamond table bonded to a taller or longer cylinder of substrate material. The resulting composite can be machined or milled to change its shape. However, the PDC layer and substrate are most often used on PDC bits in the cylindrical form in which they are made.
Though the wear surface of a PDC cutter is typically comprised of sintered polycrystalline diamond (either natural or synthetic) exhibiting diamond-to-diamond bonding, polycrystalline cubic boron nitride, wurtzite boron nitride, aggregated diamond nanorods (ADN) or other hard, crystalline materials can be substituted for diamond in at least some application and therefore, for the purposes of the PDC bit described below, should be considered equivalents to polycrystalline diamond compacts. References to “PDC” and polycrystalline diamond (“PCD”) should be understood to refer to sintered polycrystalline diamond, cubic boron nitride, wurtzite boron nitride and similar materials, including those that other materials or structure elements that might be used to improve its properties and cutting characteristics, as well as thermally stable varieties in which a metal catalyst has been partially or entirely removed after sintering. Substrates for supporting a PDC wear surface or layer are made, at least in part, from cemented metal carbide, with tungsten carbide being the most common, and may also, for example, include transitional layers in which the metal carbide and diamond are mixed with other elements for improving bonding and reducing stress between the PDC and substrate.
When the body of a cutter is affixed to the face of the drill bit, the body of the cutter occupies a recess or pocket formed in the cutting face. A separate pocket or recess is formed for each cutter when the body is fabricated, and the body of the PDC cutters is then press fitted or brazed in the recess to hold it in place. PDC bits typically have a steel or matrix body which is made by filling a graphite mold with hard particulate matter, such as powdered tungsten, and infiltrating the particulate matter with a metal alloy that forms a matrix in which the particulate matter is suspended.
The invention pertains generally to adapting fixed cutter rotary drag bits, particularly PDC bits, for advancing boreholes through rock and similar geological formations using a compressible or predominately gas-phase circulating medium instead of conventional drilling fluids.
“Air drilling” uses compressible gases under high pressure, such as air or nitrogen, as a circulating medium instead of a conventional liquid (“drilling fluid” or “mud”) to evacuate or “lift” the rock cuttings to the surface. Conventional liquid drilling fluids or “muds” used as a circulating medium when drilling well bores for oil and gas exploration are not compressible and have a much higher density as compared to mediums used for air drilling. The circulating medium used in air drilling is either in a gas phase or in a mixed phase that is comprised predominately of one or more gasses and a liquid phase. The liquid phase may be introduced at the surface or result from liquid encountered in the formation. Examples of mixed phase circulation mediums used in air drilling include foams and mists.
Compressible gas phase and mixed phase circulating mediums can be more effective than conventional drilling fluids at preventing excessive temperatures that could degrade the diamond table on PDC cutters. However, despite this advantage, PDC bits are rarely used for air drilling because air drilling presents problems and challenges for PDC bits.
Representative examples of a PDC drill bit adapted for air drilling described below embody a number of features that alone and in various combinations of two or more of them address one or more problems caused by air drilling, including, for example excessive erosion, particularly on the bit body and cutter substrates, as compared to conventional PDC drill bits used with liquid circulating mediums while also achieving satisfactory evacuation of cuttings from the face of the bit into the well-bore for circulation up to the surface.
In one non-limiting example of an embodiment of an adapted PDC drill bit, a channel or slot formed on a face of the PDC drill bit for evacuating cuttings have a substantially constant cross-sectional area, or one or more substantially constant dimensions, along at least a portion of its lengths within the cone and nose regions of the face. Such a channel geometry is contrary to a conventional teaching, which is that the cross-sectional area of a “junk slot” should be made as large as possible to improve evacuation and reduce the risk of cuttings blocking the channel or not being evacuated. A conventional junk slot therefore typically increases in cross-sectional area as it extends radially from the center of the drill bit in order for the junk slot to accommodate an increasing total quantity of cuttings from the PDC cutters fixed along its length. It is believed that a channel with a substantially constant cross-sectional area downstream from a nozzle emitting a compressible circulating medium air tends to direct air from the nozzle into a confined stream oriented toward the gauge, keeping the compressible medium at a higher pressure rather than a lower pressure due to expansion, while also lowering its velocity due to its compressibility. With less swirling as compared to conventional junk slots, it is capable of achieving acceptable evacuation of cuttings while lessening the risk of air spilling over a blade adjacent the channel, which leads to erosion of the blades and cutter substrates.
In another representative embodiment, each channel or slot on the face of a representative embodiment of a PDC drill bit adapted for air drilling has a closed end near the central axis that does not join with the other channels or slots on the face. The closed end of a channel forces pressured air emitted from a nozzle positioned near the closed end in each channel down the channel and toward the gauge.
In yet another representative example, PDC cutters mounted along a leading edge of a blade adjacent to a channel are more closely spaced than typical to form a wall with their wear surfaces that interferes with the tendency of air spilling out of the channel, between the formation of the blade. Furthermore, inserts may be added below and behind the PDC cutters to disrupt high velocity flow and interfere with air spilling over from a channel adjacent the trailing edge of the blade.
These and other features are described in detail below in connection with non-limiting examples of representatives embodiments of such a PDC bit shown in the accompanying drawings.
In the following description, like numbers refer to like elements. “Air” in the following description refers to a circulating medium that is comprised of any compressible gas, combination of compressible gases, or combination of one or more gases with one or more liquids (a mixed phase) that is used as a circulation medium when drilling bores in geological formations, particularly, but not limited to, drilling oil and gas wells. “Air drilling” refers to such drilling.
Drill string 104 can be several miles long and, like the well bore, extend in both vertical and horizontal directions from the surface. In this example, the drill string is formed of segments of threaded pipe that is screwed together at the surface as it is lowered into the hole. However, the drill string could also comprise coiled tubing. It may also incorporate components other than pipe or tubing. At the bottom the drill string is a bottom hole assembly (BHA) 105. In addition to the PDC bit 104, a BHA may include, depending on the particular application, one or more of the following: a bit sub, a downhole motor, stabilizers, drill collar, jarring devices, directional drilling and measuring equipment, measurements-while-drilling tools, logging-while-drilling tools and other devices.
The PDC drill bit 102 is rotated to shear the rock 112 and advance the hole. The PDC bit may be rotated in any number of ways. Conventional ways to rotate the PDC drill bit is to rotate drill string with a top drive 116 or table drive (not shown) or with a downhole motor that is part of the BHA 105. The PDC drill bit is surrounded by a sidewall 110 of the well bore.
The pressured “air”—one or more gases—that is used as the circulation medium is delivered to well string 104 from air source 120 of high pressured air represented by arrows 128. High pressure gas can be generated in any number of ways, any of which could be used with a PDC drill bit described herein. For example, the source may comprise one or more high pressure pumps that compresses the air. The air could be possibly atmospheric air but may also include gases from storage tanks (such as liquid nitrogen) that is then vaporized to create high pressure nitrogen gas, which may or may not be further compressed. Air source 120 is intended to be a non-limiting representation any of the possible ways of generating the circulating medium, as the PDC drill bit 102 can be used with any of them.
The compressible circulating medium is circulated downhole by flowing it through the drill string 104, to the PDC bit 102, where it exits through nozzles to carry cuttings away from the face of the PDC drill bit and into the wellbore annulus, where they will carried up to a collection point 122. The air could be recirculated once cleaned of cuttings.
Referring now primarily to
The PDC drill bit 200 has a body 204 made from steel or an abrasion-resistant composite material or “matrix” of, for example, tungsten carbide powder and a metal alloy. Parts of the body may also be hard-faced. The body 204 includes the central axis 202, which the body 204 is intended to rotate about during the drilling process. The body 204 includes an outer surface 220, a face or face portion 210 and a gauge 212. The face 210 of the PDC drill bit 200 is the exterior portion of the body 204 intended to face generally in the direction of boring and generally lies in a plane perpendicular to the central axis 202 of the PDC drill bit 200. The face 210 is best viewed in
The PDC drill bit 200 further includes channels 206 formed in the face 210 of the body 204, blades 208 formed or positioned between the plurality of channels 206, and a hydro-pneumatic nozzle 246 positioned in each of the plurality of channels 206.
Each of the channels 206 in this example extend from within the cone region 214, near the central axis 202, at least to, and preferably through, the gauge 212, where it communicates with the annulus of the well bore during drilling. In this example, there are seven channels spaced around the central axis 202. However, there could be more than our less than seven channels. However, with more channels, the width of the channels can be kept relatively narrow, at least as compared to conventional PDC drill bits, while providing sufficient capacity for evacuating cuttings. In this example, each of the channels 206 has a closed end 232 near the central axis and do not connect with any of the other plurality of channels on the face 210. Thus, each of the channels 206 is separate from the other and do not communicate directly with each other during drilling, when the bottom of the hole is close to the face. As a consequence, air discharged from an orifice of the nozzle 246 within a channel will tend to be directed down that channel. Although in this example all of channels on the face are configured in this way, in alternative embodiments a single channel or two or more of the plurality of channels, but not all, can be configured in this way to achieve at least some of the advantage of this configuration.
The channels 206 are defined between two side walls 222, and a bottom wall 224, and a closed or terminating end 232. The closed or terminating end 232 may be referred to as the beginning of the channel 206. The closed end 232 of each of the plurality of channels 206 is within the cone region 214 near the central axis 202.
Each of the plurality of channels 206 can be defined by a length L, a width W, and a depth D. Not all channels have the same length L, widths W or depths D. The width W and the depth D, at a given position along the length L, defines a cross-sectional area. The width and depth can, and do change, within any given channel, and the widths W and depths D along the lengths of each channels are not necessarily the same for each channel. In at least one or more of a plurality of the channels 206 in one embodiment, or at least two or more or plurality of the channels 206 in another embodiment, or all of the channels on the face in yet another embodiment, one or more of the width W, the depth D, and the cross-sectional area A remains substantially constant or uniform from a first point 226 on its length L to a second point 228 on its length L. The cross-sectional shape of each channel in the illustrated embodiment remains relatively constant or uniform as well. Substantially constant or uniform means, in one embodiment, that a particular dimension varies by not more than 50%, in another embodiment by not more than 25%, in another embodiment by not more than 10%, and in yet another embodiment by not more than 5%. In the illustrated embodiment, the cross-sectional shape or geometry of a channel generally resembles a square or rectangle: the sides and bottom are relatively straight, with rounded transitions or corners. However, alternative embodiments may have different cross-sectional shapes, in which case the dimensions of depth and width would be maximum values. Furthermore, in alternate embodiments, it is possible for the cross-sectional shape or geometry to be different at, or to change between, two or more different points along the length of a channel while the cross-sectional area remains substantially constant at those points and, in a particular embodiment, at each point between them.
In the illustrated example, the first point 226 is located within the cone region 214, and the second point 228 is located within the shoulder region 218. However, in another embodiment, the first point can, instead, be located just downstream from the nozzle 246 or nearer to the transition between the cone and nose regions, or in the nose region. In other embodiments, the second point can, instead, be located within one of the nose (if the first point is in the cone region) or the gauge (if the first point is located within one of the cone, nose and shoulder regions.)
In the illustrated embodiment, one or more of the width W, the depth D, or the cross-sectional area of the channels of each of the one or more channels 206 remains substantially constant from the first point 226 to a third point 230 along its length L, with the third point 230 being located in the gauge region 212. In another aspect, both the width W and the depth D of each of the one or more channels 206 remain substantially constant to the third point 230, with the third point 230 been located in the gauge region 212. In some embodiments, the length L, the width W and the depth D of each of the plurality of channels 206 is substantially consistent along a portion of the length L that extends from a point within the cone region 214 to a point within the gauge region 212.
Maintaining a uniform or constant cross-sectional area of a channel 206 inhibits volume expansion of the air discharged from the nozzle 246 in the channel. Inhibiting or reducing volume expansion of the air, which is a gas or compressible fluid, will tend to reduce pressure loss and thus also flow rate. It may also reduce air velocity, swirling and a tendency of the air to flow between the blade and the bottom of the hole during use.
Each of the blades 208, which is defined by or otherwise separated by the two of the channels 206, has a leading edge 238 formed by the intersection of a side wall of a channel forward of or leading the blade channel and a top surface of the blade, and a trailing edge 240, also formed at the intersection of the top surface of the blade and a side wall of the following or trailing channel. Arrow 234 indicates the direction of rotation of the PDC drill bit 200 about the central axis 202
This particular, non-limiting example of a PDC drill bit has both a first row 242 of PDC cutters and a second row 243 of PDC cutters mounted on each blades 208. The first row of cutters 242 are mounted on the leading edge 238 of each blade 208. The second row of cutters 243 are located behind the primary cutters. In this example, the second row cutters are located primarily on the shoulder of the bit. However, in other embodiments, the second row cutters could be omitted or they could instead, or in addition, be placed in the nose and cone regions. In this example, first row of PDC cutters 242 are mounted in a closely spaced arrangement along the leading edge 238 to reduce gaps between them. By reducing gaps between the cutters, less of the leading edge 238 is exposed to air that may leak from the channel and flow between the blade and the bottom of the hole. The close spacing also tends to block such flow, as the primary cutters will be engaging formation. The first row of cutters can be primary cutters and the second row of cutters are secondary or backup cutters. However, this arrangement is not required. Furthermore, primary cutters can be single set or plural set. In the illustrated example, the PDC drill bit also includes PDC cutters 245 mounted on the gauge in a manner that act primarily as wear surfaces.
Each of the PDC cutters is set, in this example, within a recess or pocket (not shown) formed in the face 210 of the PDC drill bit 200. Each of the PDC cutters may each have the same shape or be individually shaped, depending on preferred drilling dynamics. Furthermore, in alternative embodiments, PDC cutters 242 in the first row may be shaped and placed so that they fit together form a composite cutting structure.
The plurality of PDC cutters 242, whether intended as a wear or cutting surface, may be made of a super hard, polycrystalline diamond, or the like, supported by a substrate that forms a mounting stud for placement in each recess formed in its respective blade 208.
In the illustrated example, inserts 244 are mounted on the blades 208 behind the rows of PDC cutters 242 and 243. The inserts may be arranged in one or more rows. Multiple rows are shown. At least some of the inserts 244 may also be placed proximate the trailing edge 240 of each of the blade 208, as they have been in this example. The inserts tend to disrupt or block flow of the pressurized air across the trailing edge of the blades, and from directly impinging on the substrates of the PDC cutters 242 and 243. Disrupting the flow will tend to lower its velocity and thus erosive effect. Each of the channels may also have formed on a side wall bumps 247 for improving air flow down the channel.
The hydro-pneumatic nozzles 246 each have an orifice 258 that is located proximate the closed or terminating end 232 in at least one, two or more, or, in the illustrated example, in each of the one or more channels 206. The nozzle 246 is mounted in the bottom wall 224 of each of the plurality of channels 206 within the cone region 214. Each of the nozzles 246 are positioned near the central axis 202 and oriented to discharge a stream of high pressure air in the channel in which it is located, but in a direction that does not directly impinge on the PDC cutters 242 that are mounted along a top edge of channel. The nozzle 246 is positioned to direct air downstream from the closed end 232 of the channels 206 to evacuate the rock cuttings through and subsequently out of the plurality of channels 206.
In operation, the face 210 of the PDC drill bit 200 engages the bottom 108 of the hole 106 being drilled to advance the hole 106. The gauge 212 of the PDC drill bit 200 engages the side 110 of the hole 106 being drilled. The air is pumped down the drill string, enters plenum 249, which communicates the pressurized air to hydro-pneumatic nozzles 246 that are positioned at the closed end 232 of the channels 206. Each hydro-pneumatic nozzle 246 includes a constriction that forms a high speed jet of air that exits the orifice 258. Each nozzle is oriented to direct the pneumatic fluid, or air, away from the plurality of PDC cutters 242 positioned on the leading edge 238 of the blades 208 and towards a downstream path along the length L of the channels 206.
If two or more channels have substantially the same geometries—the width, depth and cross-section area being the substantially same in each channel at each point along their length—the flow down each should be the substantially the same, assuming that the volume and velocity of air from the nozzle in each channel is the same. Because each nozzle 246 gets air from a common source, channels with substantially similar geometries tend to receive the same amount of air. In the illustrated example, all of the channels on the face of the drill bit have substantially similar geometries and work together in the system to manage and control the flow and wear of the air and cuttings. However, alternative embodiments may have few then all of the channels made with substantially the same geometries and shapes.
Additionally, the PDC drill bit 200 is connected to a shank 250 that has a coupling 252 for connecting the PDC drill bit 200 to a drill string. The PDC drill bit 200 may also be connected to a “bit breaker” surface 254 for cooperating with a wrench to tighten and loosen the coupling to the drill string.
The width W and the depth D, at a given position along the length L, forms a cross-sectional area. One or more of the width W, depth D, or cross-sectional area of the channels 306 remains substantially constant or uniform from a first point 326 on its length L to a second point 328 on its length L. In the illustrated example, the first point 326 is located within the cone region 314, and the second point 328 is located within the shoulder region 318. One or more of the depth, width and cross-section of the channel between the second point and third point 330 may also remain substantially uniform or constant, the third point 330 located on the gauge of the bit. In alternative embodiments, the first point may be located in the cone or nose, and the second point may be located in one of the nose (unless the first point is located there), shoulder or gauge.
The foregoing description is of exemplary and preferred embodiments. The invention, as defined by the appended claims, is not limited to the described embodiments. Alterations and modifications to the disclosed embodiments may be made without departing from the invention. The meaning of the terms used in this specification are, unless expressly stated otherwise, intended to have ordinary and customary meaning and are not intended to be limited to the details of the illustrated or described structures or embodiments.
This application claims the benefit of provisional application No. 62/644,379 filed Mar. 16, 2018, the entirety of which is incorporated herein for all purposes.
| Number | Name | Date | Kind |
|---|---|---|---|
| 4246977 | Allen | Jan 1981 | A |
| 4887677 | Warren et al. | Dec 1989 | A |
| 5875858 | Brady | Mar 1999 | A |
| 6474425 | Truax | Nov 2002 | B1 |
| 7278499 | Richert | Oct 2007 | B2 |
| 7703557 | Durairajan | Apr 2010 | B2 |
| 8191657 | Richert | Jun 2012 | B2 |
| 9243458 | Bilen | Jan 2016 | B2 |
| 10233696 | Casad | Mar 2019 | B2 |
| 10494875 | Richert | Dec 2019 | B2 |
| 20080156539 | Ziegenfuss | Jul 2008 | A1 |
| 20100155150 | Wells et al. | Jun 2010 | A1 |
| 20120080230 | Flores | Apr 2012 | A1 |
| 20130008724 | Endres | Jan 2013 | A1 |
| 20180002986 | Zhang et al. | Jan 2018 | A1 |
| 20180283105 | Thomas | Oct 2018 | A1 |
| 20190284887 | Casad | Sep 2019 | A1 |
| Number | Date | Country |
|---|---|---|
| 2013074788 | May 2013 | WO |
| 2016105882 | Jun 2016 | WO |
| Entry |
|---|
| International Application No. PCT/US2019/022435, “International Search Report and Written Opinion”, dated Jul. 5, 2019, 25 pages. |
| International Application No. PCT/US2019/022435, “Invitation to Pay Additional Fees and, Where Applicable, Protest Fee”, dated May 31, 2019, 16 pages. |
| International Application No. PCT/US2019/022435, International Preliminary Report on Patentability, dated Oct. 1, 2020, 18 pages. |
| Number | Date | Country | |
|---|---|---|---|
| 20190284887 A1 | Sep 2019 | US |
| Number | Date | Country | |
|---|---|---|---|
| 62644379 | Mar 2018 | US |
