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PEH:Introduction to Roller-Cone and Polycrystalline Diamond Drill Bits
Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume II - Drilling Engineering
Robert F. Mitchell, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 5 - Introduction to Roller-Cone and Polycrystalline Diamond Drill Bits
Rotary drilling uses two types of drill bits: roller-cone bits and fixed-cutter bits. Roller-cone bits are generally used to drill a wide variety of formations, from very soft to very hard. Milled-tooth (or steel-tooth) bits are typically used for drilling relatively soft formations. Tungsten carbide inserts bits (TCI or button bits) are used in a wider range of formations, including the hardest and most abrasive drilling applications (see Fig. 5.1). Fixed-cutter bits, including polycrystalline diamond compact (PDC), impregnated, and diamond bits, can drill an extensive array of formations at various depths. The following material outlines design considerations and general product characteristics for the two types.
Roller-Cone Drill Bits
Wide varieties of roller-cone bit designs are available. They provide optimum performance in specific formations and/or particular drilling environments. Manufacturers meticulously collect information on the operation of their bits to enhance future production efficiency. Modern drill bits incorporate significantly different cutting structures and use vastly improved materials compared with those used in the recent past. As a result, bit efficiency has improved systematically through the years. Variations in operating practices, types of equipment used, and hole conditions commonly require design adjustments, and manufacturers usually work closely with drilling companies to ensure that opportunities for design improvement are expeditiously identified and implemented.
Roller-Cone Bit Design
Roller-cone bit design goals expect the bit to do the following:
- Function at a low cost per foot drilled.
- Have a long downhole life that minimizes requirements for tripping.
- Provide stable and vibration-free operation at the intended rotational speed and weight on bit (WOB).
- Cut gauge accurately throughout the life of the bit.
To achieve these goals, bit designers consider several factors. Among these are the formation and drilling environment, expected rotary speed, expected WOB, hydraulic arrangements, and anticipated wear rates from abrasion and impact. The bit body, cone configurations, and cutting structures are design focal points, as are metallurgical, tribological, and hydraulic considerations in engineering bit design solutions. (Tribology is a science that deals with the design, friction, wear, and lubrication of interacting surfaces in relative motion.)
Basic Design Principles. Drill-bit performance is influenced by the environment in which it operates. Operating choices such as applied WOB, rotary speed, and hydraulic arrangements all have important implications in both the way that bits are designed and their operating performance.
Environmental factors, such as the nature of the formation to be drilled, hole depth and direction, characteristics of drilling fluids, and the way in which a drill rig is operated, are also of critical importance in bit performance and design. Engineers consider these factors for all designs, and every design should begin with close cooperation between the designer and the drilling company to ensure that all applicable inputs contribute to the design.
Design activities are focused principally on four general areas: material selection for the bit body and cones, geometry and type of cutting structure to be used, mechanical operating requirements, and hydraulic requirements. The dimensions of a bit at the gauge (outside diameter) and pin (arrangement for attachment to a drillstem) are fixed, usually by industry standards, and resultant design dimensions always accommodate them (Fig 5.2).
For roller-cone bits, steels must have appropriate yield strength, hardenability, impact resistance, machineability, heat treatment properties, and ability to accept hard facing without damage. Cutting structure designs provide efficient penetration of the formation(s) to be drilled and accurately cut gauge. The importance of bearing reliability in roller-cone bits cannot be understated. In an operational sense, bearings, seals, and lubrication arrangements function as a unit, and their designs are closely interrelated. Bearing systems must function normally under high loads from WOB, in conditions of large impact loads, while immersed in abrasive- and chemical-laden drilling fluids, and in some cases, in relatively high-temperature environments. Hydraulic configurations are designed to efficiently remove cuttings from cutting structure and bottomhole and then evacuate cuttings to the surface.
Design Methods and Tools. How Teeth and Inserts "Drill." To understand design parameters for roller-cone bits, it is important to understand how roller-cone bits drill. Two types of drilling action take place at the bit. A crushing action takes place when weight applied to the bit forces inserts (or teeth) into the formation being drilled (WOB in Fig. 5.3). In addition, a skidding, gouging type of action results partly because the designed axis of cone rotation is slightly angled to the axis of bit rotation (rotation in Fig. 5.3). Skidding and gouging also take place because the rotary motion of a bit does not permit a penetrated insert to rotate out of a crushed zone it has created without causing it to exert a lateral force at the zone perimiter. Both effects contribute to cutting action (Fig. 5.3).
Bit Design Method. The bit geomety and cutting structure engineering method of Bentson has since 1956 been the root from which most roller-cone bit design methods have been designed (see also Reference 1). Although modern engineering techniques and tools have advanced dramatically from those used in 1956, Bentson’s method is the heritage of modern design and continues to be useful for background explanation.
- Bit diameter/available space. Well diameter and the bit diameter required to achieve it influence every design feature incorporated into every efficient bit. The first consideration in the physical design of a roller-cone bit is the permissible bit diameter or, in the words of the designer, available space. Every element of a roller-cone bit must fit within a circle representative of the required well diameter. The API has issued specifications establishing permissible tolerances for standard bit diameters. The sizes of journals, bearings, cones, and hydraulic and lubrication features are collectively governed by the circular cross section of the well. Individually, the sizing of the various elements can, to an extent, be varied. Repositioning or altering the size or shape of a single component nearly always requires subsequent additional changes in one or more of the other components. In smaller bits, finding good compromises can be difficult because of a shortage of space.
- Journal angle. "Journal angle" describes an angle formed by a line perpendicular to the axis of a bit and the axis of the bit’s leg journal. Journal angle is usually the first element in a roller-cone bit design. It optimizes bit insert (or tooth) penetration into the formation being drilled; generally, bits with relatively small journal angles are best suited for drilling in softer formations, and those with larger angles perform best in harder formations.
- Cone offset. To increase the skidding-gouging action, bit designers generate additional working force by offsetting the centerlines of the cones so that they do not intersect at a common point on the bit. This "cone offset" is defined as the horizontal distance between the axis of a bit and the vertical plane through the axis of its journal. Offset forces a cone to turn within the limits of the hole rather than on its own axis. Offset is established by moving the centerline of a cone away from the centerline of the bit in such a way that a vertical plane through the cone centerline is parallel to the vertical centerline of the bit. Basic cone geometry is directly affected by increases or decreases in either journal or offset angles, and a change in one of the two requires a compensating change in the other. Skidding-gouging improves penetration in soft and medium formations at the expense of increased insert or tooth wear. In abrasive formations, offset can reduce cutting structure service life to an impractical level. Bit designers thus limit the use of offset so that results just meet requirements for formation penetration.
Teeth and Inserts. Tooth and insert design is governed primarily by structural requirements for the insert or tooth and formation requirements, such as penetration, impact, and abrasion. With borehole diameter and knowledge of formation requirements, the designer selects structurally satisfactory cutting elements (steel teeth or TCIs) that provide an optimum insert/tooth pattern for efficient drilling of the formation.
Factors that must be considered to design an efficient insert/tooth and establish an advantageous bottomhole pattern include bearing assembly arrangement, cone offset angle, journal angle, cone profile angles, insert/tooth material, insert/tooth count, and insert/tooth spacing. When these requirements have been satisfied, remaining space is allocated between insert/tooth contour and cutting structure geometry to best suit the formation.
In general, the physical appearance of cutting structures designed for soft, medium, and hard formations can readily be recognized by the length and geometric arrangement of their cutting elements.
Design as Applied to Cutting Structure. Application of design factors produces diverse results (Fig. 5.4). The cutting structure on the left is designed for the softest formation types; that on the right, for formations that are harder.
The action of bit cones on a formation is of prime importance in achieving a desirable penetration rate. Soft-formation bits require a gouging-scraping action. Hard-formation bits require a chipping-crushing action. These actions are governed primarily by the degree to which the cones roll and skid. Maximum gouging-scraping (soft-formation) actions require a significant amount of skid. Conversely, a chipping-crushing (hard-formation) action requires that cone roll approach a "true roll" condition with very little skidding. For soft formations, a combination of small journal angle, large offset angle, and significant variation in cone profile is required to develop the cone action that skids more than it rolls. Hard formations require a combination of large journal angle, no offset, and minimum variation in cone profile. These will result in cone action closely approaching true roll with little skidding.
Inserts/Teeth and the Cutting Structure. Because formations are not homogeneous, sizable variations exist in their drillability and have a large impact on cutting structure geometry. For a given WOB, wide spacing between inserts or teeth results in improved penetration and relatively higher lateral loading on the inserts or teeth. Closely spacing inserts or teeth reduces loading at the expense of reduced penetration. The design of inserts and teeth themselves depends largely on the hardness and drillability of the formation. Penetration of inserts and teeth, cuttings production rate, and hydraulic requirements are interrelated, as shown in Table 5.1.
Formation and cuttings removal influence cutting structure design. Soft, low-compressive-strength formations require long, sharp, and widely spaced inserts/teeth. Penetration rate in this type of formation is partially a function of insert/tooth length, and maximum insert/tooth depth must be used. Limits for maximum insert/tooth length are dictated by minimum requirements for cone-shell thickness and bearing-structure size. Insert/tooth spacing must be sufficiently large to ensure efficient fluid flows for cleaning and cuttings evacuation.
Requirements for hard, high-compressive-strength formation bits are usually the direct opposite of those for soft-formation types. Inserts are shallow, heavy, and closely spaced. Because of the abrasiveness of most hard formations and the chipping action associated with drilling of hard formations, the teeth must be closely spaced (Fig. 5.5). This close spacing distributes loading widely to minimize insert/tooth wear rates and to limit lateral loading on individual teeth. At the same time, inserts are stubby and milled tooth angles are large to withstand the heavy WOB loadings required to overcome the formation’s compressive strength. Close spacing often limits the size of inserts/teeth.
In softer and, to some extent, medium-hardness formations, formation characteristics are such that provisions for efficient cleaning require careful attention from designers. If cutting structure geometry does not promote cuttings removal, bit penetration will be impeded and force the rate of penetration (ROP) to decrease. Conversely, successful cutting structure engineering encourages both cone shell cleaning and cuttings removal.
Materials Design. Materials properties are a crucial aspect of roller-cone bit performance. Components must be resistant to abrasive wear, erosion, and impact loading. Metallurgical characteristics, such as heat treatment properties, weldability, capacity to accept hard facing without damage, and machineability, all figure into the eventual performance and longevity results for a bit.
Physical properties for bit components are contingent on the raw material from which a component is constructed, the way the material has been processed, and the type of heat treatment that has been applied. Steels used in roller-cone bit components are all melted to exacting chemistries, cleanliness, and interior properties. All are wrought because of grain structure refinements obtained by the rolling process. Most manufacturers begin with forged blanks for both cones and legs because of further refinement and orientation of microstructure that result from the forging process.
Structural requirements and the need for abrasion and erosion resistance are different for roller-cone bit legs and cones. Predictably, the materials from which these components are constructed are normally matched to the special needs of the component. Furthermore, different sections of a component often require different physical properties. Leg journal sections, for example, require high hardenabilities that resist wear from bearing loads, whereas the upper portion of legs are configured to provide high tensile strengths that can support large structural loads.
Roller-cone bit legs and cones are manufactured from low-alloy steels. Legs are made of a material that is easily machinable before heat treatment, is weldable, has high tensile strength, and can be hardened to a relatively high degree. Cones are made from materials that can be easily machined when soft, are weldable when soft, and can be case hardened to provide higher resistance to abrasion and erosion.
Inserts and Wear-Resistant Hard-Facing Materials. Tungsten carbide is one of the hardest materials known. Its hardness makes it extremely useful as a cutting and abrasion-resisting material for roller-cone bits. The compressive strength of tungsten carbide is much greater than its tensile strength. It is thus a material whose usefulness is fully gained only when a design maximizes compressive loading while minimizing shear and tension. Tungsten carbide is the most popular material for drill-bit cutting elements. Hard-facing materials containing tungsten carbide grains are the standard for protection against abrasive wear on bit surfaces.
When most people say "tungsten carbide," they do not refer to the chemical compound (WC) but rather to a sintered composite of tungsten carbide grains embedded in, and metallurgically bonded to, a ductile matrix or binder phase. Such materials are included in a family of materials called ceramic metal, or "cermets." Binders support tungsten carbide grains and provide tensile strength. Because of binders, cutters can be formed into useful shapes that orient tungsten carbide grains so that they will be loaded under compression. Tungsten carbide cermets can also be polished to very smooth finishes that reduce sliding friction. Through the controlled grain size and binder content, hardness and strength properties of tungsten carbide cermets are tailored for specific cutting or abrasion resistances.
The most common binder metals used with tungsten carbide are iron, nickel, and cobalt. These materials are related on the periodic table of elements and have an affinity for tungsten carbide (cobalt has the greatest affinity). Tungsten carbide cermets normally have binder contents in the 6% to 16% (by weight) range. Because tungsten carbide grains are metallurgically bonded with binder, there is no porosity at boundaries between the binder and grains of tungsten carbide, and the cermets are less susceptible to damage by shear and shock.
Properties of Tungsten Carbide Composites. The process of "designing" cermet properties makes it possible to exactly match a material to the requirements for a given drilling application. Tungsten carbide particle size (normally 2 to 6 μm), shape, and distribution, together with binder content (as a weight percent), affect composite material hardness, toughness, and strength. As a generalization, increasing binder content for a given tungsten carbide grain size will cause hardness to decrease and fracture toughness to increase. Conversely, increasing tungsten carbide grain size affects both hardness and toughness. Smaller tungsten carbide particle size and less binder content produce higher hardness, higher compressive strength, and better wear resistance. In general, cermet grades are developed in a range in which hardness and toughness vary oppositely with changes in either particle size or binder content. In any case, subtle variations in tungsten carbide content, size distribution, and porosity can markedly affect material performance (Fig. 5.6).
TCI Design. TCI design takes the properties of tungsten carbide materials and the geometric efficiency for drilling of a particular rock formation into account. As noted, softer materials require geometries that are long and sharp to encourage rapid penetration. Impact loads are low, but abrasive wear can be high. Hard formations are, on the other hand, drilled more by a crushing and grinding action than by penetration. Impact loads and abrasion can be very high. Tough materials, such as carbonates, are drilled by a gouging action and can sustain high impact loads and high operating temperatures. Variations in the way that drilling is accomplished and rock formation properties govern the shape and grade of the correct TCIs to be selected.
The shape and grade of TCIs are influenced by their respective location on a cone. Inner rows of inserts function differently from outer rows. Inner rows have relatively lower rotational velocities about both the cone and bit axes. As a result, they have a natural tendency to gouge and scrape rather than roll. Inner insert rows thus generally use softer, tougher insert grades that best withstand crushing, gouging, and scraping actions. Gauge inserts are commonly constructed of harder, more wear-resistant tungsten carbide grades that best withstand severe abrasive wear. It is thus seen that requirements at different bit locations dictate different insert solutions. A large variety of insert geometries, sizes, and grades through which bit performance can be optimized are available to the designer (Fig. 5.7) (see also Portwood, et al.).
Gauge Cutting Structure. The most critical cutting structure feature is the gauge row. Gauge cutting structures must cut both the hole bottom and its outside diameter. Because of the severity of gauge demands on a bit, both milled tooth and insert type bits can use either tungsten carbide or diamond-enhanced inserts on the gauge. Under abrasive conditions, severe wear or gauge rounding is common, and at high rotary speeds, the gauge row can experience temperatures that lead to heat checking, chipping, and eventually breakage.
Diamond-Enhanced TCIs. Diamond-enhanced inserts are frequently used to prevent wear in the highly loaded, highly abraded gauge area of bits and in all insert positions for difficult drilling conditions. They are made up of PDC, which is chemically bonded, synthetic diamond grit supported in a matrix of tungsten carbide cermet. PDC has higher compressive strength and higher hardness than tungsten carbide. In addition, diamond materials are largely unaffected by chemical interactions and are less sensitive to heat than tungsten carbides. These properties make it possible for diamond-enhanced materials to function normally in drilling environments in which tungsten carbide grades deliver disappointing or unsatisfactory results (Table 5.2) (see also Keshavan, et al., Salesky and Payne, and Salesky et al.).
When diamond-enhanced inserts are designed, higher diamond densities increase impact resistance and ability to economically penetrate abrasive formations. Increased diamond density increases insert cost, however. In the past, diamond-enhanced inserts have been available only in symmetrical shapes. The first of these was the semiround top insert. Today, some manufacturers have developed processes that make it possible to produce complex diamond-enhanced insert shapes.
Tungsten Carbide Hard Facing. Hard-facing materials are designed to provide wear resistance (abrasion, erosion, and impact) for the bit (Fig. 5.8). To be effective, hard facing must be resistant to loss of material by flaking, chipping, and bond failure with the bit. Hard facing provides wear protection on the lower (shirttail) area of all roller-cone bit legs and as a cutting structure material on milled-tooth bits (Fig. 5.9).
Hard facing is commonly installed manually by welding. A hollow steel tube containing appropriately sized grains of tungsten carbide is held in a flame until it melts. The resulting molten steel bonds, through surface melting, with the bit feature being hard faced. In the process, tungsten carbide grains flow as a solid, with molten steel from the rod, onto the bit. The steel then solidifies around the tungsten carbide particles, firmly attaching them to the bit. Hydraulic Features.
Nozzles and Flow Tubes. Drilling fluids circulate through a drillstring to nozzles at the bit and back to the surface via the system annulus. They provide three crucial functions to drilling: cleaning of the cutting structure, cuttings removal from the hole bottom, and efficient cuttings evacuation to the surface. the hydraulic energy that causes fluid circulation is one of only three variable energy inputs (wob, rotary speed, and hydraulic flow) available on a drill rig for optimization of drilling performance.
Many roller-cone bit options, such as nozzle selection, flow tubes, vectored flow tubes, and center nozzle ports, help optimize hydraulic performance. These features provide alternatives for precise placement of hydraulic energy according to well bottom needs.
Generating cuttings is the first step needed to achieve high ROPs; cleaning those cuttings from the cone and hole bottom and lifting them through the annulus to the rig surface is the remaining part of a hydraulic solution. Computer modeling supported by laboratory testing is the most common approach to development and verification of hydraulic designs. Efficient velocity profiles deliver hydraulic energy to the most needed points, even in cases for which drilling flow rates are compromised.
Normally, several different nozzles can be used interchangeably on a particular bit. Nozzles are commonly classified into standard, extended, and diverging categories. Extended nozzles release the flow at a point closer than standard to the hole bottom. Diverging nozzles release the flow in a wider-than-normal, lower-velocity stream. They are designed primarily for use in center jet installations (see also Chia and Smith).
Asymmetric Nozzle Configurations and Crossflow. A bit has a symmetric nozzle configuration when three nozzles of the same size and type, at the same level on the periphery of a bit, are installed 120° from each other. An asymmetric nozzle configuration has two or more different nozzle sizes and/or types.
When the fluid from a nozzle impinges on the well bottom, it moves away from the point of impingement in a 360°, fan-like, spray. A boundary forms at which fluids from two different jets meet. Fluids at these boundaries create stagnant zones known as dead zones. In the case of a symmetric nozzle configuration, dead zones occur under the middle part of the cone’s asymmetric nozzle configurations; dead zones are moved away from the impingement zone of the larger jet and toward that of the smaller jet (i.e., away from the middle of the cone). Asymmetric flows resist entrapment of cuttings under a bit and help prevent the inefficiencies of regrind, lower ROPs, and erosive wear on the bit. Fig. 5.10 shows typical flow patterns.
Crossflow is a subset of asymmetric nozzle sizing in which one jet is blocked by nozzle blank. The blanked side of the bit leaves a natural exit path for the fluid from the opposing two jets. The flow from the two jets sweeps under two of the cones to improve bottomhole cleaning and chip removal.
Practical Hydraulic Guidelines. Table 5.3 is a summary of accepted starting hydraulics configurations for roller-cone bits.
Roller-Cone Bit Components
Bearing, Seal, and Lubrication Systems. Roller cone bearing systems are designed to be in satisfactory operating condition when the cutting structure of the bit is worn out. To achieve this standard of bearing performance, modern goals for seal and bearing system life are 1 million or more revolutions of a bit without failure, as opposed to ≈300,000 or fewer in the recent past. To achieve this goal, research into bearing, seal, and lubricant designs and into materials that improve seal and bearing life is ongoing.Roller-cone bits primarily use two types of bearings: roller bearings and journal bearings, sometimes called friction bearings. Each type is normally composed of a number of separate components, including primary bearings, secondary bearings, seal system, features that resist thrust loading, cone retention balls, and a lubrication system (Fig. 5.9).
Primary bearings are as large as possible within the limits of available space. Secondary bearings are smaller, reduced-diameter bearings located adjacent to the interior apex area in a cone. Secondary bearings provide supplemental load-bearing capability. Primary and secondary bearings can individually be either roller bearings or journal bearings. It is not uncommon for a bearing system to be made up of combinations of the two.
Seals prevent cuttings and drilling fluids from entering the bearing system and prevent lubricant from escaping the bearing system. Thrust washers are located on the end of leg journals and between the primary and secondary bearing surfaces to resist axial loading.
Most roller-cone bits incorporate what appears to be a ball-type bearing. This is the cone retention feature. The balls prevent cones from separating from their journals. Finally, the lubrication system contains the lubricant that, throughout the life of the bearing system, provides lubrication to bearings and seals. These features are described below.
Roller-Bearing Systems. Roller bearings are a common bit-bearing system because they can reliably support large loads and generally perform well in the drilling environment (Fig. 5.11). They are typically used on larger-diameter bits (> 14 in.), which have more physical space to accommodate the rollers. To enhance bearing life, leading manufacturers continually research bearing materials, sizing, and shape.
Journal-Bearing Systems. Journal bearings consist of at least one rotating surface separated from the journal by a film of lubricant. The surfaces are specially designed so that the film of lubricant separates them; were they to touch, mating bearing components would gall or possibly fuse. As long as satisfactory lubrication is provided and loading remains within design limits, journal bearings are extremely efficient. Fig. 5.12 compares roller-bearing and journal-bearing assemblies.
Design of Journal Bearings. Journal bearings must provide a balanced bearing geometry and adequate journal strength and must maximize the thickness of the high-pressure lubricating film developed during hydrodynamic lubrication. Surface areas, journal and cone diameters, and clearances between journal and cone all affect the thickness of lubricating films (Fig. 5.13). Manufacturing tolerances must be precise so that surfaces run true. Roundness of journal and cone surfaces is important, and if any part of a bearing is out of round, the effectiveness of the lubrication regime will be adversely affected.
The metallurgy of a bearing must be balanced to minimize heat generation during boundary lubrication. Cone-bearing surfaces are steel. Soft, silver-plated sleeves are installed on the journal. Silver polishes easily, and minor surface irregularities from machining are quickly smoothed. This smoothness ensures low-friction operation and uniform lubricant flow over the bearing surface (Fig. 5.14).
Open Bearing Systems. Nonsealed roller bearings, referred to as open bearing systems, are typically used in large-diameter (> 20 in.) bits. These bits are often used to drill from surface to relatively shallow depths with a simple drilling fluid system (e.g., seawater). This drilling application does not necessitate the use of seals in the bits. They rely on the drilling fluid for cooling, cleaning, and lubrication of the bearings.
Seal Systems. In general, seal systems are classified as either static or dynamic. Roller-cone bits use both types of seals. Dynamic seals involve sealing across surfaces that are moving in relationship to one another, as would be the case for a bearing seal. Seal parts or surfaces that do not move in relationship to one another during bit operation, such as the seal between a hydraulic nozzle and a bit to prevent leakage around the joint, are static seals.
Bearing Seals. Roller-cone bearing seals operate in an exceptionally harsh environment. Drilling mud and most cuttings are extremely abrasive. Drilling fluids often contain chemicals, and operating temperatures can be sufficiently high to break down the elastomers from which seals are made. Pressure pulses often occur in downhole drilling fluids that apply lateral loading on seals that must be resisted.
On a purely practical level, bearing seals have two functions: to prevent foreign materials, such as mud, cuttings, chemicals, and water, from entering the bearings and to prevent bearing lubricant from escaping the bit.
Visualize the difference in the nature of these two duties. On the interior side, the seal is excluding clean, functional lubricant from escaping the bit, while on the exterior side, the seal is excluding dirt and chemicals from penetrating the bit. The separation of these two extremely different functions takes place at a small point between the two sides of a seal. If either of these functions breaks down, the bearings and the bit could be destined for failure.
Seal Definitions. In a rotating bearing, the two working sides of a seal are called the static energizer and the dynamic wear face. These two parts are directly opposite each other, with the energizing portion bearing on the gland and the dynamic wear face bearing against the rotating unit. For the energizing portion of the seal to function properly, it must have a surface against which to react. This is provided by a channel-shaped groove called a seal gland.
The wearing portion of the seal must have the capability to withstand the heat and abrasion generated as the rotating surface passes over it. The energizer, when functioning correctly, is not a high-wear area. Ideally, it simply bears against the gland and provides the pushing energy that maintains firm contact between the wear surface and rotating cone.
O-Rings. Donut-shaped O-rings are used in many roller-cone bit applications. O-rings are manufactured from elastomers (synthetic rubbers) that withstand the temperatures, pressures, and chemicals encountered in drilling environments. They are a traditional, but still consistently reliable, seal system.
An O-ring is installed in a seal gland to form a seal system. The gland holds the O-ring in place and is sized so that the O-ring is compressed between the gland and the bearing hub at which sealing is required. It presses the interior wall of the O-ring against the hub and the exterior diameter of the O-ring against the gland. These latter forces prevent the seal from turning in the gland and experiencing wear on the outer surfaces by rotational contact with the gland (Fig. 5.15).
Lubrication of Seals. Seals must be lubricated to prevent high wear rates and excessive temperaratures that could lead to seal material failures. Lubricant for the bearings also lubricates the seals.
Lubrication Systems and Lubricants. Lubricants play a vital role in bearing performance. They provide lubrication for both bearings and seals, and they provide a medium for heat transfer away from the bearings. To achieve these functions, lubricants are specially engineered and continually improved. Lubrication systems are engineered to provide reserve storage, positive delivery to the bearing system, capacity for thermal expansion, and pressure equalization with fluids on the bit exterior.
Lubrication systems include a resupply reservoir large enough to ensure availability of lubricant for all lubrication functions throughout the life of the bit. A small positive pressure differential in the system ensures flow from reservoir to bearings. The system is vented to equalize internal and external reservoir pressures. Without equalization, a pressure differential between bit exterior and interior could be sufficient to cause seal damage, leading to bearing failure.
Lubricants. High drilling temperatures and high pressures in the lubrication system, together with the potential of exposure to water and chemicals, require high performance from lubricants. Most bit lubricants are specially formulated. Leading bit manufacturers employ scientists to develop and test lubricants. Better drill-bit lubricants are stable to temperatures > 300°F, and many function normally at temperatures down to ≈0°F. They are hydrophobic (repel water) and retain their stability if water penetrates the bit. Quality lubricants are also resistant to chemicals commonly found in drilling fluids, are environmentally safe, and do not contain the lead additives that have traditionally helped resist high pressures.
- Lubricant supply. Roller-cone bits typically contain one lubricant reservoir in each leg (Fig. 5.16). Thus, for a three-cone bit, there are three reservoirs. Each must have the capacity for sufficient reserves of lubricant for operation of the bearing assembly it serves throughout the bit’s life.
- Pressure equalization and relief. A column of drilling fluids and cuttings contained in a well exerts very high pressures on a bit operating at the well bottom. These high pressures are applied to the seal system and must be resisted by lubricant in the seal and bearing system. At installation, lubricant is at atmospheric pressure and cannot provide significant resistance to well-bottom pressures. Accordingly, internal lubrication system pressures equalize themselves with external bit pressures to prevent seal failure caused by differential pressure. Equalization is accomplished by a small relief valve installed in the lubricant reservoir system.
Special-Purpose Roller-Cone Bit Designs
Monocone Bits. Monocone bits were first used in the 1930s. The design has several theoretical advantages but has not been widely used. Bit researchers, encouraged by advances in cutting structure materials, continue to keep this concept in mind because it has the room for extremely large bearings and has very low cone rotation velocities, which suggest a potential for long bit life. While of a certain general interest, monocone bits are potentially particularly advantageous for use in small-diameter bits in which bearing sizing presents significant engineering problems.Monocone bits drill differently from three-cone bits. Drilling properties can be similar to both the beneficial crushing properties of roller-cone bits and the shearing action of PDC bits. Cutting structure research thus focuses partly on exploitation of both mechanisms encouraged by the promise of efficient shoe drillouts and drilling in formations with hard stingers interrupting otherwise "soft" formations. Modern ultrahard cutter materials properties can almost certainly extend insert life and expand the range of applications in which this design could be profitable. The design also provides ample space for nozzle placements for efficient bottomhole and cutting structure cleaning.
Two-Cone Bits. The origin of two-cone bit designs lies in the distant past of rotary drilling. The first roller-cone patent, issued in August 1909, covered a two-cone bit. As with monocone bits, two-cone bits have available space for larger bearings and rotate at lower speeds than three-cone bits. Bearing life and seal life for a particular bit diameter are greater than for comparable three-cone bits. Two-cone bits, although not common, are available and perform well in special applications (Fig 5.17). Their advantages cause this design to persist, and designers have never completely lost interest in them.
The cutting action of two-cone bits is similar to that of three-cone bits, but fewer inserts simultaneously contact the hole bottom. Penetration per insert is enhanced, providing particularly beneficial results in applications in which capabilities to place WOB are limited.
The additional space available in two-cone designs has several advantages. It is possible to have large cone offset angles that produce increased scraping action at the gauge. Space also enables excellent hydraulic characteristics through room for placement of nozzles very close to bottom. It also allows the use of large inserts that can extend bit life and efficiency.
Two-cone bits have a tendency to bounce and vibrate. This characteristic is a concern for directional drilling. Because of this concern and advances in three-cone bearing life and cutting structures, two-cone bits do not currently have many clear advantages. As with many roller-cone bit designs, however, modern materials and engineering capabilities may resolve problems and again underscore their recognized advantages.
Roller-Cone Bit Nomenclature
Roller-cone bits are generally classified as either TCI bits or milled-tooth bits. To assist in comparison of similar products from various manufacturers, the International Association of Drilling Contractors (IADC) has established a unified bit classification system for the naming of drill bits.
IADC Roller-Cone Bit Classification Method. The IADC Roller-Cone Bit Classification Method is an industry-wide standard for the description of milled-tooth and insert-type roller-cone bits. This coding system is based on key design- and application-related criteria. The currently used version was introduced in 1992 and incorporates criteria cooperatively developed by drill bit manufacturers under the auspices of the Society of Petroleum Engineers (see also Reference 8).
IADC Classification. The IADC classification system is a four-character design- and application-related code. The first three characters are always numeric; the last character is always alphabetic. The first digit refers to bit series, the second to bit type, the third to bearings and gauge arrangement, and the fourth (alphabetic) character to bit features.
- Series. Series, the first character in the IADC system, defines general formation characteristics and divides milled-tooth and insert-type bits. Eight series or categories are used to describe roller-cone rock bits. Series 1 through 3 apply to milled-tooth bits; series 4 through 8 apply to insert-type bits. The higher the series number is, the harder or more abrasive the rock type is. Series 1 represents the softest (easiest drilling applications) for milled-tooth bits; series 3 represents the hardest and most abrasive applications for milled-tooth bits. Series 4 represents the softest (easiest drilling applications) for insert-type bits, and series 8 represents very hard and abrasive applications for insert-type bits.
Unfortunately, rock hardness is not clearly defined by the IADC system. The meanings of "hard" sandstone or "medium-soft" shale, for example, are subjective and open to a degree of interpretation. Thus, information should be used only in a descriptive sense; actual rock hardness will vary considerably, depending on such factors as depth, overbalance pressure, porosity, and others that are difficult to quantify.
- Type. The second character in the IADC categorization system represents bit type, insert or milled tooth, and describes a degree of formation hardness. Type ranges from 1 through 4.
- Bearing design and gauge protection. The third IADC character defines both bearing design and gauge protection. IADC defined seven categories of bearing design and gauge protection: (1) nonsealed roller bearing (also known as open bearing bits); (2) air-cooled roller bearing (designed for air, foam, or mist drilling applications); (3) nonsealed roller bearing, gauge protected; (4) sealed roller bearing; (5) sealed roller bearing, gauge protected; (6) sealed friction bearing; and (7) sealed friction bearing, gauge protected. Note that "gauge protected" indicates only that a bit has some feature that protects or enhances bit gauge. It does not specify the nature of the feature. As examples, it could indicate special inserts positioned in the heel row location (side of the cone) or diamond-enhanced inserts on the gauge row.
- Included features. The fourth character used in the system defines features available. IADC considers this category optional. This alphabetic character is not always recorded on bit records but is commonly used within bit manufacturers’ catalogs and brochures. IADC categorization assigns and defines 16 identifying features.
Only one alphabetic feature character can be used under IADC rules. Bit designs, however, often combine several of these features. In these cases, the most significant feature is usually listed.
PDC Drill Bits
PCD Materials and Bit Design
PDC is one of the most important material advances for oil drilling tools in recent years. Fixed-head bits rotate as one piece and contain no separately moving parts. When fixed-head bits use PDC cutters, they are commonly called PDC bits. Since their first production in 1976, the popularity of bits using PDC cutters has grown steadily, and today they are nearly as common as roller-cone bits in many drilling applications.PDC bits are designed and manufactured in two structurally dissimilar styles: matrix-body bit and steel-body bits (Figs. 5.18 and 5.19). The two provide significantly different capabilities, and because both types have certain advantages, a choice between them would be decided by the needs of the application.
"Matrix" is a very hard, rather brittle composite material comprising tungsten carbide grains metallurgically bonded with a softer, tougher, metallic binder. Matrix is desirable as a bit material because its hardness is resistant to abrasion and erosion. It is capable of withstanding relatively high compressive loads but, compared with steel, has low resistance to impact loading.
Matrix is relatively heterogeneous because it is a composite material. Because the size and placement of the particles of tungsten carbide it contains vary (by both design and circumstances), its physical properties are slightly less predictable than steel.
Steel is metallurgically opposite of matrix. It is capable of withstanding high impact loads but is relatively soft and without protective features would quickly fail by abrasion and erosion. Quality steels are essentially homogeneous with structural limits that rarely surprise their users.
Design characteristics and manufacturing processes for the two bit types are, in respect to body construction, different because of the nature of the materials from which they are made. The lower impact toughness of matrix compared with steel limits some matrix-bit features, such as blade height. Conversely, steel is ductile, tough, and capable of withstanding greater impact loads. This makes it possible for steel-body PDC bits to be relatively larger than matrix bits and to incorporate greater height into features such as blades.
Matrix-body PDC bits are commonly preferred over steel-body bits for environments in which body erosion is likely to cause a bit to fail. For diamond-impregnated bits, only matrix-body construction can be used.
The strength and ductility of steel give steel-bit bodies high resistance to impact loading. Steel bodies are considerably stronger than matrix bodies. Because of steel material capabilities, complex bit profiles and hydraulic designs are possible and relatively easy to construct on a multi-axis, computer-numerically-controlled milling machine. A beneficial feature of steel bits is that they can easily be rebuilt a number of times because worn or damaged cutters can be replaced rather easily. This is a particular advantage for operators in low-cost drilling environments.
Fortunately, both steels and matrix are rapidly evolving, and their limitations are diminishing. As hard-facing materials improve, steel bits are becoming extremely well protected with materials that are highly resistant to abrasion and erosion. At the same time, the structural and wear-resisting properties of matrix materials are also rapidly improving, and the range of economic applications suitable for both types is growing.
Today’s matrix has little resemblance to that of even a few years ago. Tensile strengths and impact resistance have increased by at least 33%, and cutter braze strength has increased by ≈80%. At the same time, geometries and the technology of supporting structures have improved, resulting in strong, productive matrix products. Fig. 5.20 describes PDC bit nomenclature.
PDC Cutters. Diamond is the hardest material known. This hardness gives it superior properties for cutting any other material. PDC is extremely important to drilling because it aggregates tiny, inexpensive, manmade diamonds into relatively large, intergrown masses of randomly oriented crystals that can be formed into useful shapes called diamond tables. Diamond tables are the part of a cutter that contacts a formation. Besides their hardness, PDC diamond tables have an essential characteristic for drill-bit cutters: They efficiently bond with tungsten carbide materials that can, in turn, be brazed (attached) to bit bodies. Diamonds by themselves will not bond together, nor can they be attached by brazing.
Synthetic Diamond. Diamond grit is commonly used to describe tiny grains (≈0.00004 in.) of synthetic diamond used as the key raw material for PDC cutters. In terms of chemicals and properties, manmade diamond is identical to natural diamond. Making diamond grit involves a chemically simple process: ordinary carbon is heated under extremely high pressure and temperature. In practice, however, making diamond is far from easy.
Individual diamond crystals contained in diamond grit are diversely oriented. This makes the material strong, sharp, and, because of the hardness of the contained diamond, extremely wear resistant. In fact, the random structure found in bonded synthetic diamond performs better in shear than natural diamonds because natural diamonds are cubic crystals that fracture easily along their orderly, crystalline boundaries.
Diamond grit is less stable at high temperatures than natural diamond, however. Because metallic catalyst trapped in the grit structure has a higher rate of thermal expansion than diamond, differential expansion places diamond-to-diamond bonds under shear and, if loads are high enough, causes failure. If bonds fail, diamonds are quickly lost, so PDC loses its hardness and sharpness and becomes ineffective. To prevent such failure, PDC cutters must be adequately cooled during drilling.
Diamond Tables. To manufacture a diamond table, diamond grit is sintered with tungsten carbide and metallic binder to form a diamond-rich layer. They are wafer-like in shape, and they should be made as thick as structurally possible because diamond volume increases wear life. Highest-quality diamond tables are ≈2 to 4 mm, and technology advances will increase diamond table thickness. Tungsten carbide substrates are normally ≈0.5 in. high and have the same cross-sectional shape and dimensions as the diamond table. The two parts, diamond table and substrate, make up a cutter (Fig. 5.21).
Forming PDC into useful shapes for cutters involves placing diamond grit, together with its substrate, in a pressure vessel and then sintering at high heat and pressure.
PDC cutters cannot be allowed to exceed temperatures of 1,382°F [750°C]. Excessive heat produces rapid wear because differential thermal expansion between binder and diamond tends to break the intergrown diamond grit crystals in the diamond table. Bond strengths between the diamond table and tungsten carbide substrate are also jeopardized by differential thermal expansion.
Basic PDC Bit Design Principles
Four considerations primarily influence bit design and performance: mechanical design parameters, materials, hydraulic conditions, and properties of the rock being drilled.Geometric Parameters of PDC Bit Design. Geometric considerations include bit shape or profile, which is predicated on cutter geometry, cutter placements, cutter density, and hydraulic requirements, along with the abrasiveness and strength of the formations to be drilled and well geometry. Each of these factors must be considered on an application-to-application basis to ensure achievement of ROP goals during cooling, cleaning the bit, and removing cuttings efficiently. During design, all factors are considered simultaneously.
Cutting Structure Characteristics. Cutting structures must provide adequate bottomhole coverage to address formation hardness, abrasiveness, and potential vibrations and to satisfy productive needs.
Early (1970s) PDC bits incorporated elementary designs without waterways or carefully engineered provisions for cleaning and cooling. By the late 1980s, PDC technology advanced rapidly as the result of new understanding of bit vibrations and their influence on productivity. Today, cutting structures are recognized as the principal determinant of force balancing for bits and for ROP during drilling.
Cutting Mechanics. The method in which rock fails is important in bit design and selection. Formation failure occurs in two modes: brittle failure and plastic failure. The mode in which a formation fails depends on rock strength, which is a function of composition and such downhole conditions as depth, pressure, and temperature.
Formation failure can be depicted with stress-strain curves (Fig. 5.22). Stress, applied force per unit area, can be tensile, compressive, torsional, or shear. Strain is the deformation caused by the applied force. Under brittle failure, the formation fails with very little or no deformation. For plastic failure, the formation deforms elastically until it yields, followed by plastic deformation until rupture.
PDC bits drill primarily by shearing. Vertical penetrating force from applied drill collar weight and horizontal force from the rotary table are transmitted into the cutters (Fig. 5.23). The resultant force defines a plane of thrust for the cutter. Cuttings are then sheared off at an initial angle relative to the plane of thrust, which is dependent on rock strength.
Formations that are drillable with PDC bits fail in shear rather than compressive stress typified by the crushing and gouging action of roller-cone bits. Thus, PDC bits are designed primarily to drill by shearing. In shear, the energy required to reach plastic limit for rupture is significantly less than by compressive stress. PDC bits thus require less WOB than roller-cone bits.
Thermally stable PDC cutters are designed to plow or grind harder formations because of their thermal stability and wear resistance. This grinding action breaks cementing materials bonding individual grains of rock.
Cutters. Cutters are expected to endure throughout the life of a bit. To perform well, they must receive both structural support and efficient orientation from bit body features. Their orientation must be such that they are loaded only by compressive forces during operation. Then, to prevent loss, cutters must be retained by braze material that has adequate structural capabilities and has been properly deposited during manufacturing.
Cutter Density Cutters are strategically placed on a bit face to ensure complete bottomhole coverage. "Cutter density" refers to the number of cutters used in a particular bit design. PDC bit cutter density is a function of profile shape and length and of cutter size, type, and quantity. If there is a redundancy of cutters, it generally increases from the center of the bit to the outer radii because of increasing requirements for work as radial distance from the bit centerline increases. Cutters nearer to the gauge must travel farther and faster and remove more rock than cutters near the centerline. Regional cutter density can be examined by rotating each cutter’s placement onto a single radial plane (Fig. 5.24).
If the number of cutters on a bit face is reduced, the depth of cut increases, ROP increases, and higher torque results, but life is shortened. Conversely, if cutter density is increased, ROP and cutting structure cleaning efficiency decrease, but bit life increases.
Cutter density has been increased in the "outward" radial direction from the bit centerline for the bit depicted in Fig. 5.24. Note that planar cutter strike pattern inscribes an image of bit profile.
Cutter Orientation. PDC cutters are set into bits to achieve specific rake (attack) angles relative to the formation. Back rake angle has a major effect on the way in which a bit interacts with a formation. Back rake is the angle between a cutter’s face and a line perpendicular to the formation being drilled (Fig 5.25). This angle contributes to bit performance by influencing cleaning efficiency, increasing bit aggressiveness, and prolonging cutter life. Back rake causes the cuttings to curl away from the cutting element, and as the back rake angle is increased, the tendency for cuttings to stick to the bit face is reduced.
Back rake is the amount, if any, that a cutter in a bid is tilted in the direction of bit rotation. It is a key factor in defining the aggressiveness or depth of cut by a cutter. Aggressiveness is increased by decreasing back-rake angle. This increases depth of cut and results in increased ROP. Smaller back-rake angles are thus used to maximize ROP when softer formations are drilled. Increased back-rake angles reduce depth of cut and thus ROP and bit vibration. It increases cutter life. An increase in angle also reduces cutter breakage from impact loading when harder formations are encountered. Harder formations require greater back rake angles to give durability to the cutting structure and reduce "chatter" or vibration. Individual cutters normally have different back-rake angles that vary with their position between the bit center and gauge.
PDC Bit Profile
The shape of a PDC bit body is called its profile. Bit profile has a direct influence on the following bit qualities:
- Stability (tendency to vibrate or drill laterally away from bit centerline).
- Cutter density.
- Cleaning efficiency.
- Prevention of thermal damage to cutters by cooling.
Elements of PDC Bit Profile A profile governs hydraulic efficiency, cutter and/or diamond loading, and wear characteristics across the bit face. It is also the principal influence on bit productivity and stability. The geometry established by the profile contributes to hydraulic flow efficiency across the bit face. Hydraulic flows directly influence ROP through the cuttings removal they provide. If cuttings are removed as rapidly as they are produced, ROP will be relatively higher. If a bit is capable of generating cuttings faster than they can be removed, however, penetration is restricted by the cuttings, and achievement of optimal ROP is impeded. Hydraulic flows also cool bit cutting elements and prevent thermal damage to them. Cutter life influences bit life and the economic efficiency of a bit investment. Fig. 5.26 describes the nomenclature of various PDC bit profiles. Starting at the centerline of the bit and moving outward to the gauge, profile is broken into five zones: cone, nose, shoulder, taper, and gauge.
Profile Categories. Profile shape is one of the most important characteristics of fixed-cutter bits, having direct influence on possibilities for cutter placement and densities and on hydraulic layouts. Operationally, bit stability, the rotational speeds at which the bit can be run, directional characteristics, permissible WOB, and bit durability are also affected by profile.
There are four general categories of PDC bit profiles. These range from long, parabolic curves to flat shapes with narrow-radius, compressed curves. The types are described as flat profiles, short parabolic profiles, medium parabolic profiles, or long parabolic profiles (Fig. 5.27).
Parabolic profiles are considerably more aggressive than flatter profiles and produce higher ROPs at the expense of accelerated rates of abrasive wear. As bit profile becomes more parabolic, cutter wear on the inner radii around the nose increases. Parabolic profiles are susceptible to cutter breakage by impact, particularly if insufficient cutter density exists in the nose area.
When harder formations are drilled, flat profiles and high cutter loading are required. Flatter profiles uniformly place high loading on individual cutters and increase penetration. If abrasive wear is predominant, however, parabolic profiles enable the higher cutter densities that limit penetration but increase resistance to abrasion.
PDC bits most frequently incorporate large shoulder radii and primarily use either short or medium parabolic profiles. Cone angles are sufficient to stabilize the bit from unwanted deviation without hindering steerability. Such designs give bits the versatility to drill efficiently either by conventional rotary drilling or with downhole motors.
Flat and long parabolic profiles are less commonly used designs. Flat profiles have a single radius on the shoulder and are less aggressive than parabolic profiles. Long parabolic profiles are made up of a series of curves beginning at the cone-to-nose intersection and continuing to the outside-diameter radius and gauge intersection.
PDC Cutters. PDC cutters are made up of a working component, the diamond table, and a supporting component called the substrate (Fig. 5.28).Substrate. Substrates are a composite material made up of tungsten carbide grains bonded by metallic binder. This material bonds efficiently with diamond tables but is very hard and thus capable of impeding erosive damage to a working cutter.
Cutter geometry, at the interface between diamond table and substrate, seeks to enhance bonding between the two. Generally, geometries that increase interface surface area improve bonding (Fig. 5.29). Geometries also attempt to control stresses at the bond to the lowest possible level.
Diamond Table. The shape of a diamond table is governed by two design objectives. It must include the highest possible diamond volume and total diamond availability to its working features. It must also ensure the lowest possible stress level within the diamond table and at the substrate bond.
Geometric features of an interface between a diamond table and substrate can significantly improve the ability of the diamond table to withstand impact (Fig. 5.30).
Diamond Table Bonds. High stress concentrations in a diamond table can result in delamination failures between diamond tables and substrates or in diamond table edge and corner chipping. Poor bonds between grains of diamond grit can lead to cracking in a diamond layer and eventually to diamond table and substrate failure.
Thermally Stable PDC. As described earlier, the maximum safe operating temperature for PDC materials is 750°C [1382°F]. Higher temperature resistance can be achieved in a diamond table, however, by removing residual cobalt catalyst from the manufacturing process. The resulting material is called thermally stable polycrystalline diamond (TSP). When cobalt is removed, problems related to differential thermal expansion between the binder and diamond are removed, making TSP stable to ≈1200°C [2192°F].
TSP is formed like PDC and, except for thermal properties, behaves like PDC with one important exception. Because cobalt contained in PDC plays a key role in bonding PDC diamond tables to tungsten carbide substrates, attachment of TSP cutters to a bit is relatively difficult. Therefore, TSP is generally used only in applications in which bit operating temperature cannot be reliably controlled.
Cutter Optimization. To achieve cutter durability and reliable bonds between diamond tables and substrates, design engineers use a variety of application-specific cutter options. These include cutter diameter options between ≈6 and 22 mm, optimized total diamond volumes in diamond table designs, special diamond table blends, a variety of nonplanar interface shapes that increase bond area and reduce internal stresses between the diamond table and substrate, and a variety of external cutter geometries designed to improve performance in particular drilling environments.
Cutter Shape. The most common PDC shape is the cylinder, partly because cylindrical cutters can be easily arranged within the constraint of a given bit profile to achieve large cutter densities. Electron wire discharge machines can precisely cut and shape PDC diamond tables (Fig. 5.31). Nonplanar interface between the diamond table and substrate reduces residual stresses. These features improve resistance to chipping, spalling, and diamond table delamination. Other interface designs maximize impact resistance by minimizing residual stress levels.
Certain cutter designs incorporate more than one diamond table. The interface for the primary diamond table is engineered to reduce stress. A secondary diamond table is located in the high-abrasion area on the ground-engaging side of the cutter. This two-tier arrangement protects the substrate from abrasion without compromising structural capability to support the diamond table.
Highly specialized cutters are designed to increase penetration in tough materials such as carbonate formations. Others include engineered relief in the tungsten carbide substrate that increases penetration and reduces requirement for WOB and torque, or beveled diamond tables that reduce effective cutter back rake and lower bit aggressiveness for specific applications.
Special Bit Configurations
Diamond Bits. The term "diamond bit" normally refers to bits incorporating surface-set natural diamonds as cutters. This bit type, which has been used for many years, was the predecessor to PDC bits and continues to be used in certain drilling environments. Diamond bits are used in abrasive formations. They drill by a high-speed plowing action that breaks the cementation between rock grains. Fine cuttings are developed in low volumes per rotation. To achieve satisfactory ROPs with diamond bits, they must, accordingly, be rotated at high speeds.Diamond bits are described in terms of the profile of their crown, the size of diamond stones (stones per carat), total fluid area incorporated into the design, and fluid course design (radial or cross flow).
Diamonds do not bond with other materials. They are held in place by partial encapsulation in a matrix bit body. Diamonds are set in place on the drilling surfaces of bits (Fig. 5.32).
Impregnated Bits. Impregnated bits are a PDC bit type in which diamond cutting elements are fully imbedded within a PDC bit body matrix (Fig. 5.33). Impregnated bit bodies are PDC matrix materials that are similar to those used in cutters. The working portions of impregnated bits are unique, however: matrix impregnated with diamonds.
Both natural and synthetic diamonds are prone to breakage from impact. When embedded in a bit body, they are supported to the greatest extent possible and are less susceptible to breakage. However, because the largest diamonds are relatively small, cut depth must be small and ROP must be achieved through increased rotational speed. Thus, impregnated bits do not perform well in rotary drilling because of relatively low rotary speeds. They are most frequently run in conjunction with turbodrills and high-speed positive displacement motors that operate at several times normal rotational velocity for rotary drilling (500 to 1500 rpm).
Impregnated bits use combinations of natural diamond, synthetic diamond, PDC, and TSP for cutting and gauge protection purposes. They are designed to provide complete diamond coverage of the well bottom with only diamonds touching the formation. Variations in diamond size and the ratio of diamond to matrix volumes allow optimization of performance in terms of aggressiveness and durability. Varying diamond distribution also affects the ratio of diamond to matrix with similar effects on aggressiveness and durability.
During drilling, individual diamonds in a bit are exposed at different rates. Sharp, fresh diamonds are always being exposed and placed into service.
Dual-Diameter Bits. Dual-diameter bits have a unique geometry that allows them to drill and underream. To achieve this, the bits must be capable of passing through the ID of a well casing and then drilling an oversized (larger than casing diameter) hole. State-of-the-art dual-diameter bits are similar to conventional PDC drill bits in the way that they are manufactured. They typically incorporate a steel body construction and a variety of PDC and/or diamond-enhanced cutters. They are unitary and have no moving parts (Fig. 5.34).
Dual-diameter bits can provide drilling flexibility through well diameter control, directional aptitude, and reduction of drop tendencies. They are functional in vertical and directional wells and in a wide range of formations. Maximum benefit is realized in swelling or flowing formations in which the risk of sticking pipe can be reduced by drilling an oversized hole. They are commonly used in conjunction with applications requiring increased casing, cement, and gravel-pack clearance; they also can eliminate the need for extra trips and avoid the risk of moving part failure in mechanical underreamers in high-cost intervals. When a well is deepened below existing casing, they reduce the need for additional underreamer runs and increase clearance for smooth casing run in curve sections. With this flexibility, they are also useful in exploratory wells, in which they provide for maximum casing diameters.
Dual-Diameter Bit Drilling Method. Fig. 5.35 shows the maximum dual-diameter bit diameter that can be tripped through casing without problems (left). On the opposite side of the reaming section, the pilot section is significantly removed from the casing pass-through diameter, and the centerline of the bit is similarly to the left (in the image) of casing/hole centerline. The only contact area between the bit and the casing pass-through diameter is at the small side of the reaming section. There is no cutter contact with casing during drillout, and neither the casing nor the bit cutting structure is damaged by tripping.
During drilling, the bit is centered on the hole, and the large sides of the reaming and pilot sections are in contact with the hole (right).
Dual-diameter bits are possible largely because of sophisticated modern engineering. Because of the unique geometry of dual-diameter bits, many obstacles and challenges must be overcome. To drill properly, this type of bit must be stable. If a conventional PDC bit becomes unstable during drilling, it will drill an oversized hole. If, on the other hand, a dual-diameter bit becomes unstable during drilling, the pilot section will drill an oversized hole that will, in turn, cause the reaming section to drill undersize, and hole diameter goals will not be achieved. To drill with optimal hole-opening ability, a dual-diameter bit must rotate purely around the bit axis. Stability is achieved with bit features and through careful engineering. The bits are force and mass balanced. Without care, dual-diameter bits could have a large turning moment between the pilot and reamer sections because of the axial separation of loading. Excessive torque contributes to poor bit stability, which adversely affects hole condition.
Designs must ensure that gauge cutters are prevented from contacting the casing, even in extreme applications. Dual-diameter designs must perform similarly to conventional PDC drill bits and produce a high-quality, larger hole.
Dual-diameter bits are often configured for drillout. Drillout cutting structures are more aggressive than those that will eventually serve rotating and sliding modes but are generally more durable during drillout than most bits, even though the bits eventually perform other functions besides drillout.
Dual-diameter bit hydraulics requires special attention. Fluids provided to the pilot must fully clean the pilot section. Much of the total flow must, however, be reserved for and directed to the full-gauge section from which a much higher volume of cuttings removal is required. Excessive flow to the pilot risks washout to the hole bottom, whereas insufficient flows to the gauge cutting area will provide inadequate cuttings removal and poor ROP or even binding of the drillstring. Dual-diameter bits require a special geometric relationship between reamer nozzles and the bit profile that minimizes flow scatter and maximizes available hydraulic energy across the reamer cutters. This layout works with pilot section hydraulics and deep junk slots to ensure high overall cleaning efficiency.
IADC PDC Bit Classification
IADC Fixed-Cutter Bit Classification System. The IADC Fixed-Cutter Bit Classification System seeks to classify fixed-cutter PDC and diamond drill bits effectively so that they can be efficiently selected and used by the drilling industry. IADC classification codes for each bit are generated by placing the bit style into the category that best describes it so that similar bit types are grouped within a single category. The version currently used was introduced in 1992 using criteria that were cooperatively developed by drill-bit manufacturers under the auspices of SPE.,  The system leaves a rather broad latitude for interpretation and is not as precise or useful as the IADC Classification System for Roller-Cone Bits.
The system is composed of four characters that designate body material, cutter density, cutter size or type, and bit profile. It does not consider hydraulic features incorporated into a bit and does not attempt to give a detailed description of body style beyond basic classification of the overall length of the bit cutting face. Special designs incorporating unconventional use and densities of gauge cutters are not considered for classification.
Bit Body Material. The first digit in the IADC Fixed-Cutter Bit Classification describes the material from which the bit body is constructed: M or S for matrix- or steel-body construction, respectively.
Cutter Density. The second IADC classification character is a digit that represents the density of cutting elements. Densities for PDC cutter and surface set diamond bits are described separately through use of numerals 1 through 4 for PDC bits and 6 through 8 for surface-set diamond bits. Numerals 0, 5, and 9 are not defined. Specifically, for PDC bits, density classification relates to cutter count; for surface-set bits, it relates to diamond size. Because heavier cutter densities generally correspond to tougher drilling applications, the density classification digit implies an applications aspect as it increases.
- PCD Bit Cutter Density. PDC bit cutter density represents total cutter count, usually including gauge cutter count. A designation of 1 represents a light cutter density; 4 represents a heavy density. Within the classification rules, a density of 1 refers to ≤ 30 cutters; a density of 2 refers to 30 to 40; density 3 indicates 40 to 50; and density 4 refers to ≥ 50 cutters.
Manufacturers classify their PDC bits within these four numeric categories, depending on a manufacturer’s internal criteria for cutter density. Bits that are "borderline" are placed into a higher or lower density category, depending on manufacturer preference.
- Surface-Set Diamond Bit Density. Surface-set diamond density, numerals 6 through 8, categorize variations in the size of the cutter material. The numeral 6 represents diamond sizes > 3 stones per carat; 7 represents diamond sizes from 3 to 7 stones per carat; and 8 represents diamond sizes < 7 stones per carat. Thus, diamond size becomes smaller as the density classification increases. This generally corresponds to what would be expected in surface-set bit designs intended for harder or more abrasive formations.
Cutter Size or Type. The third character in the IADC classification designates the "size" or "type" of cutter. This again differs for PDC and surface-set diamond bits. For PDC cutter bits, the third character is a digit that represents cutter size: 1 indicates PDC cutters > 24 mm in diameter; 2 represents cutters from 14 to 24 mm in diameter; 3 indicates PDC cutters < 14 but > 8 mm; and 4 is used for cutters < 8 mm.
For surface-set bits, the third character represents diamond type, with 1 indicating natural diamonds, 2 referring to TSP material, 3 representing combinations such as mixed diamond and TSP materials, and 4 indicating impregnated diamond bits.
Bit Profile. The final (fourth) character describes the basic appearance of the bit based on overall length of the cutting face. "Fishtail"-type PDC bits are an exception as bits; for this type of bit, the ability to clean in fast-drilling, soft formations is thought to be a more important body feature than profile. The numeral 1 represents fishtail PDC bits and "flat" TSP and natural diamond bits; 2, 3, and 4 indicate increasingly longer bit profiles of both types (a virtually flat PDC bit would be identified by 2, whereas a long-flanked "turbine style" bit would be categorized as 4). In lieu of developing a formula relating overall bit face length (depth) to bit diameter, each manufacturer classifies its own product profiles using these rules.
IADC Bit Dull Grading
The IADC, in conjunction with SPE, has established a systematic method for communication of bit failures The intent of the system is to facilitate and accelerate product and operational development based on accurate recording of bit experiences. This system is called dull grading. The IADC Dull Grading Protocol evaluates eight roller-cone or seven PDC bit areas, provides a mechanism for systematically evaluating the reasons for removal of a bit from service, and establishes a uniform method for reporting., Partly because of dull analyses, bit design processes and product operating efficiencies evolve rapidly. Engineers identify successful design features that can be reapplied and unsuccessful features that must be corrected or abandoned; manufacturing units receive feedback on product quality; sales personnel migrate performance gains and avoid duplication of mistakes between similar applications, and so forth. All bit manufacturers require collection of dull information for every bit run.
IADC dull grading is closely associated with its bit classification systems, and the general formats for fixed-cutter bit and roller-cone bit dull grading are similar. There are important differences that must be taken into account, however, and the two approaches are not interchangeable. The following explains IADC Dull Grading and points out the differences between diamond/PDC and roller-cone bit rules.
IADC Dull Grading System. IADC dull grading reviews four general bit wear categories: cutting structure (T), bearings and seals (B), gauge (G), and remarks. These and their subcategories are outlined in Fig. 5.36.
Cutting Structure Wear Grading (T). For dull grading purposes, cutting structures are subdivided into four subcategories: inner rows, outer rows, major dull characteristic of the cutting structure, and location on bit face where the major dull characteristic occurs. Fig. 5.37 illustrates the dull grading system.
- Roller Cone Cutting Structure Evaluation. Dull grading begins with evaluation of wear on the inner rows of inserts/teeth (i.e., with the cutting elements not touching the wall of the hole bore). Grading involves measurement of combined inner row structure reduction caused by loss, wear, and/or breakage with the measurement method described above. Outer rows of inserts/teeth are those that touch the wall of the hole bore. Grading involves measurement of combined outer row teeth/insert structure reduction caused by loss, wear, and/or breakage with the measurement method described above.
- Roller-Cone Cutter or Insert/Tooth Wear Measurement. Measurement of roller-cone cutting structure condition requires evaluation of bit tooth/insert wear status. Wear is reported by use of an eight-increment wear scale in which no wear is represented by "0" and completely worn (100%) is represented by "8" (Fig. 5.38).
- PDC Bit Cutter Wear Evaluation. Cutter wear is graded with a 0 to 8 scale in which 0 represents no wear and 8 indicates that no usable cutting surface remains (Fig. 5.39). PDC cutter wear is measured across the diamond table, regardless of the cutter shape, size, type, or exposure. The location of cutter wear is categorized as either the inner two-thirds or outer third of the bit radius (Fig. 5.40).
- PDC Bit Inner and Outer Row Cutter Wear Measurement. For both PDC and surface-set diamond bits, a value is given to cutter wear with the method described above. To obtain average wear for the inner rows of cutters depicted in Fig. 5.40, the six included cutters must be individually graded, summed as a group, and averaged to obtain the inner row wear grade, (a + b + c + d + e + f) / 6;. This analysis is repeated for each blade, and blade results are summed and averaged for the final result. A similar analysis is made for the seven cutters used in the outer bit rows, and the two results are recorded in the first two spaces of the dull grading form.
- Dull Characteristic (D). The cutting structure dull characteristic is the observed characteristic most likely to limit further use of the bit in the intended application. A two-letter code is used to indicate the major dull characteristics of the cutting structure.
The primary cutter dull characteristic, the third cutting structure subcategory, is recorded in the third space on the dull grading record. (Note that noncutting structure or "other" dull characteristics that a bit might exhibit are noted in the seventh grading category.) Category 3 defines only primary cutter wear, whereas Category 7 can be used to describe either secondary cutting structure wear or wear characteristics that relate to the bit as a whole and are unrelated to cutting structure. Grading codes for the other dull characteristics category are the same as those listed above.
- Roller-Cone Bit Dull Location (L). A two-letter code is used to indicate the location of the wear or failure that necessitated removal of the bit from service. These codes are listed in Fig. 5.37.
- PDC Bit Cutting Structure Drill Location. The last of the cutting structure-related wear grades, dull location, indicates the location of the primary dull characteristic. Possible locations include the cone (C), nose (N), taper (T), shoulder (S), gauge (G), all areas (A), middle row (M), and heel row (H). Location grades are reported in the fourth space on the dull grading form.
Bearing and Seal Criteria (Not Used for PDC Bits). IADC provides separate protocols for estimation of bearing and seal wear in nonsealed and sealed bearing assemblies. Seal and bearing grading applies only to roller-cone bits. It is always marked "X" for PDC bits.
- Estimating Wear on Nonsealed Bearings. For nonsealed bearings, wear is estimated on a linear scale of 0 to 8: 0 is new, 8 is 100% expended.
- Estimating Wear on Sealed Bearings. A checklist for the seal and bearing system condition is provided in Table 5.4. The grading protocol is as follows:
- If no seal problems are encountered, use the grading code E.
- If any component in the assembly has failed, use the grading code F.
- If any portion of the bearing is exposed or missing, it is considered an ineffective assembly; again, use the grading code F.
- Use the grading code N if it is not possible to determine the condition of both the seal and the bearing.
- Grade each seal and bearing assembly separately by cone number. If grading all assemblies as one, report the worst case.
Gauge Grading (G). The gauge category of the Dull Bit Grading System is used to report an undergauge condition for cutting elements intended to touch the wall of the hole bore. For diamond and PDC bits only, gauge is measured with an API-specified ring gauge. (API specifications for ring gauges for roller-cone bits have not been issued.)
- Roller-Cone Bit Gauge Grading. For three-cone bits, the "two-thirds rule" is applied to measuring the gauge condition. The amount out of gauge, as measured by the ring gauge, is multiplied by two-thirds to give the true gauge condition.
For two-cone bits, gauge is the measured distance from either the gauge or heel elements, whichever is closer to gauge.
Measurements are taken at either the gauge or heel cutting elements, whichever is closer to gauge (Fig. 5.41). Undergauge increments of 1/16 in. are reported. If a bit is 1/16 in. undergauge, the gauge report is 1. If a bit is 1/8 in. (2/16 in.) undergauge, the gauge report is 2. If, a bit is 3/16 in. undergauge, the gauge report is 3, and so forth. Round to the nearest 1∕16 in. Gauge rules apply to cutting structure elements only.
- PDC Bit Gauge Grading. For diamond and PDC bits, gauge is measured with a nominal ring gauge. Use of an "IN" code indicates that the bit remains in gauge. Undergauge increments of 1/16 in. are reported. If a bit is 1/16 in. undergauge, the gauge report is 1. If a bit is 1/8 in. (2∕16 in.) undergauge, the gauge report is 2, and so forth. Round to nearest 1/16 in. Gauge rules apply to cutting structure elements only. Measurements are taken at the gauge cutting elements.
Roller Cone and PDC Bit Remarks. The "remarks" category allows explanation of dull characteristics that do not correctly fit into other categories and is the category in which the reason a bit was removed from service is recorded.
- Roller-Cone Bit Other Dull Characteristics (O). Dull characteristics can be used to report dull characteristics other than those reported under cutting structure dull characteristics (D). Evidence of secondary bit wear is reported in the seventh grading category. Such evidence could relate to cutting structure wear, as recorded in the third space, or may report identifiable wear, such as erosion, for the bit as a whole. The secondary dull characteristic often identifies the cause of the dull characteristic noted in the third space.
- Roller-Cone and PDC Bit Reason Pulled (R). The eighth dull grading category reports the reason why a bit was pulled.
Hydraulic Energy. Energy is the rate of doing work. A practical aspect of energy is that it can be transmitted or transformed from one form to another (e.g., from an electrical form to a mechanical form by a motor). A loss of energy always occurs during transformation or transmission. In drilling fluids, energy is called hydraulic energy or commonly hydraulic horsepower.
The basic equation for hydraulic energy is
where H = hydraulic horsepower, p = pressure (psi or kPa), q = flow rate (gal/min or L/min), and 1,714 is the conversion of (psi-gal/min) to hydraulic horsepower [or (kPa•L/min) = 44 750].
Rig pumps are the source of hydraulic energy carried by drilling fluids. This energy is commonly called the total hydraulic horsepower or pump hydraulic horsepower:
where H1 = total hydraulic energy (hydraulic horsepower) and p1 =actual or theoretical rig pump pressure (psi). (See prior equation for metric conversion.) Note that the rig pump pressure (p1) is the same as the total pressure loss or the system pressure loss. H1 is the total hydraulic energy (rig pump) required to counteract all friction energy (loss) starting at the Kelly hose (surface line) and Kelly, down the drillstring, through the bit nozzles, and up the annulus at a given flow rate (q).
Bit hydraulic energy, Hb, is the energy needed to counteract frictional energy (loss) at the bit or can be expressed as the energy expended at the bit:
See prior equation for metric conversion.
Fluid Velocity. The general formula for fluid velocity is
where v = velocity (ft/min or m/min), q = flow rate (gal/min or L/min), and A = area of flow (ft2 or m2).
The average velocity of a drilling fluid passing through a bit’s jet nozzles is derived from the fluid velocity equation:
where vj = average jet velocity of bit nozzles (ft/sec or m/s) and An = total bit nozzle area (in.2 or cm2 ).
Nozzle sizes are expressed in 1/32-in. (inside diameter) increments. Examples are 9/32 and 12/32 in. The denominator is not usually mentioned; the size is understood to be in 32nds of an inch. For example, 9/32- and 12/32-in. nozzles are expressed as sizes 9 and 12.
The impact force of the drilling fluid at velocity vj1 can be derived from Newton’s Second Law of Motion: force equals mass times acceleration. Assuming that all the fluid momentum is transferred to the bottomhole,
where Ij = impact force of nozzle jets (lbf or kPa), W = mud weight (lbm/gal or kg/L), q = flow rate (gal/min or L/min), and vj = average jet velocity from bit nozzles (ft/sec or m/s).
System Pressure Loss. Pressure losses inside the drillstring result from turbulent conditions. Viscosity has very little effect on pressure losses in turbulent flow. At higher Reynold’s numbers, a larger variation results in only a small variation in friction factor. The calculated pressure loss equations are based on turbulent flow and are corrected for mud weight instead of viscosity:
where An = total combined area of the bit nozzles (in.2 or cm2), W = mud weight (lb/gal or kg/L), pb = bit nozzle jets pressure loss (psi or kPa), and q = flow rate (gal/min or L/min).
Regardless of how good a new product or method may be to a drilling operation, the result is always measured in terms of cost per foot or meter. Lowest cost per foot indicates to drilling engineers and supervisors which products to use most advantageously in each situation. Reduced costs lead directly to higher profits or, in some cases, to the difference between profit and loss.For those in administration, engineering, manufacturing, and sales, cost calculations are used to evaluate the effectiveness of any product or method, new or old. Because drilling costs are so important, everyone involved should know how to make a few simple cost calculations.
For example, the cost of a PDC bit can be up to 20 times the cost of a milled-tooth bit and up to 4 times the cost of a TCI bit. The choice of a PDC bit, a milled-tooth bit, or an insert roller-cone bit must be economically justified by its performance. Occasionally, this performance justification is accomplished by simply staying in the hole longer. In such cases, the benefits of using it are intangible.
The main reason for using a bit, however, is that it saves money on a cost-per-foot basis. To be economical, a PDC bit must make up for its additional cost by either drilling faster or staying in the hole longer. Because the bottom line on drilling costs is dollars and cents, bit performance is based on the cost of drilling each foot of hole.
Breakeven analysis of a bit is the most important aspect of an economic evaluation. A breakeven analysis is necessary to determine whether the added bit cost can be justified for a particular application.
The breakeven point for a bit is simply the footage and hours needed to equal the cost-per-foot that would be obtained on a particular well if the bit were not used. To break even, a good offset well must be used for comparative purposes.
If the bit record in Table 5.5 were used, we could determine whether a bit would be economical.
Total rotating time = 212.5 hr
Total trip time = 54.3 hr
Rig operating cost = $300/hr
Total bit cost = $16,148
Total footage = 3,380 ft
Note: Tripping rate is computed at 1,000-ft/hr average. This rate will vary, depending on rig type and operation. Therefore, the offset cost per foot for this interval (8,862 to 12,242 ft) is calculated with the standard cost-per-foot equation:
where C = drilling cost per foot ($/ft), R = rig operating cost (plus add-on equipment, such as downhole motor) ($/hr), t = trip time (hr), td = drilling time (hr), Cb = bit cost ($), and F = footage drilled (ft).
From the data provided in the example above, the cost per foot is
In determinations of whether an application is suitable for a bit, the offset performances are given, but bit performance must be estimated. Thus, we must assume either the footage the bit will drill or the ROP it will obtain. If the footage is assumed, then we use the following equation to calculate the break-even ROP:
where Cr = rig operating cost ($/hr), Co= offset cost per foot ($), t = trip time of bit (hr), Cb = bit cost ($), and F = assumed bit footage (ft). Therefore, in the above example,
The bit must drill the 3,380 ft at an ROP of 13.7 ft/hr to equal the offset cost per foot of $28.46 for the same 3,380 ft.
If an ROP is assumed, use the following equation to calculate the breakeven footage:
Thus, in the above example, if we assume an ROP of 20 ft/hr, we have
In this case, the bit must drill 1,627 ft to attain the breakeven point.
Bit Selection and Operating Practices
Rules of Thumb for Bit Selection
- Shale has a better drilling response to drill speed.
- Limestone has a better drilling response to bit weight.
- Bits with roller bearings can be run at a higher speed than bits with journal bearings.
- Bits with sealed bearings have a longer life than bits with open bearings.
- Bits with journal bearings can be run at higher weights than bits with roller bearings.
- Diamond product bits can run at higher speeds than three-cone bits.
- Bits with high offset may wear more on gauge.
- Cost-per-foot analysis can help you decide which bit to use.
- Examination of dulls can also help you decide which bit to use.
Tripping Can Ruin a New Bit
- Make the bit up to proper torque.
- Hoist and lower the bit slowly through ledges and doglegs.
- Hoist and lower the bit slowly at liner tops.
- Avoid sudden stops. Drillpipe stretch can cause a bit to hit the hole bottom.
- If reaming is required, use a light weight and low speed.
Establish a Bottomhole Pattern
- Rotate the bit and circulate mud when approaching bottom. This will prevent plugged nozzles and clear out fill.
- Lightly tag bottom with low speed.
- Gradually increase speed and then gradually increase weight.
Use a Drill-Off Test To Select Best WOB and Speed
- Select speed.
- Select bit weight. Depending on bit selected, refer to appropriate manufacturer’s recommended maximum speed and WOB.
- Lock brake.
- Record drill-off time for 5,000-lbm increments of weight indicator decrease.
- Repeat this procedure for different speeds.
- Drill at the weight and speed that give the fastest drill-off time.
The Bit Is Not Always To Blame for Low ROP
- Mud weight may be too high with respect to formation pressure.
- Mud solids may need to be controlled.
- Pump pressure or pump volume may be too low.
- Formation hardness may have increased.
- Speed and weight may not be the best for bit type and formation. Use drill-off test.
- Bit may not have adequate stabilization.
- Bit may be too hard for the formation.
Figures and tables in this chapter are courtesy of Smith Intl. Inc.
SI Metric Conversion Factors
ft | × | 3.048* | E–01 | = m | |
gal | × | 3.785 412 | E–03 | = m3 | |
in. | × | 2.54* | E–02 | = cm | |
lbf | × | 4.448 222 | E+00 | = N | |
lbm | × | 4.535 924 | E–01 | = kg | |
psi | × | 6.894 757 | E+00 | = kPa | |
sq in. | × | 6.451 6* | E–04 | = m2 |
*Conversion factor is exact.