DRILL BITSBit Types & IADC ClassificationsClassification

Bits are available in a bewildering array of types, from a number of manufacturers. Before looking in detail at bit performance considerations, it may be helpful to present a quick overview of these types.

We can group bit types into two basic categories:

Rolling cutter bits, also known as roller cone bits, consist of cutting elements arranged on cones (usually three cones, but sometimes two) that rotate on bearings about their own axis as the drill string turns the body of the bit. The principle types of rolling cutter bits are milled steel tooth, or "rock" bits ( Figure 1 , soft formation type,

Figure 1

and Figure 2 ,

Figure 2

medium formation type), and tungsten carbide insert, or "button" bits ( Figure 3 , soft formation type, and Figure 4 , hard formation type).

Figure 3

Figure 4

Fixed cutter bits, also known as drag bits, consist of stationary cutting elements that are integral with the body of the bit and are rotated directly by the turning of the drill string. The principal types of fixed cutter bits are

steel cutter (i.e., "fishtail" bits)

natural diamond

polycrystalline diamond compact (PDC)

thermally stable PDC (TSP)

While steel cutter drag bits have some use in soft, unconsolidated formations, this discussion focuses mostly on diamond fixed-cutter bits, which have a much wider range of applications. Examples of these bits are shown in Figure 5 (natural diamond) and Figure 6 (PDC) .

Figure 5

We may further break down rolling cutter and fixed cutter bit types according to variations in mechanical design and hydraulics.

Figure 6

The International Association of Drilling Contractors (IADC) has approved a standard system of classifying both rolling cutter and fixed cutter bits, based on formation type and design variations. Consisting of simple numbered codes, this system also simplifies comparison of different manufacturers' bit types. For a detailed description of this system, refer to IADC/SPE paper 23937 ( McGehee et. al., 1992 ).

The IADC classification system is a valuable aid in bit selection, and a useful tool for comparing the general features and formation applicability of various bit types. It is important to note, however, that comparable bits are not necessarily equivalent. Companies may differ significantly in specific aspects of metallurgy and design, manufacturing techniques and inspection standards (Craddock, 1973).

The IADC categorizes both rolling cutter and fixed cutter (diamond) bits using a four-character code. The first character in the classification code indicates the cutting structure series. The digits 1-3 are for steel tooth bits in the soft, medium and hard formation categories, while the numbers 4-8 are for insert bits in the soft, medium, medium hard, hard and extremely hard formation categories. The second character further specifies the cutting structure type within each series classification. The third character indicates bearing type and whether or not the bit is gauge-protected, while the fourth character designates additional special features and applications.

Example:

A Smith F2 bit has an IADC classification of 517X:

51 indicates that the Smith F2 has tungsten carbide inserts, designed for use in soft formations with low compressive strength;

7 indicates that the cones on this bit have sealed friction bearings, and that the bit is designed for protection against gauge wear;

X indicates that the inserts have a chisel tooth configuration (as opposed, for example, to a conical shape).

The first character of the IADC classification code for fixed cutter bits indicates the type of body material and cutting elements:

S for steel body PDC bits;

M for matrix body PDC bits;

D for natural diamond bits;

T for TSP bits.

The second character, a digit from 1 to 9, identifies the bit shape, or profile-this indicates its durability and the type of cutting action it provides. The third and fourth characters (also digits from 1 to 9) identify, respectively, the bit's hydraulic design and the size and density of its cutting elements.

Rock Failure Mechanisms

Bits are designed to induce rock failure. Because rock failure can occur in different ways, depending on the formation and on downhole conditions, there are a large number of design variations among rolling cutter and fixed cutter bits. To evaluate these design variations and select a bit, we first need a basic understanding of how rocks fail and how formation conditions affect drilling performance.

The Stress/Strain Relationship

Stress is the force applied to a unit area of material. An analysis of the stresses acting on a particular object can become quite involved. For the purpose of this discussion, however, we can define three basic components of stress:

compressive stress (a pushing or squeezing force);

tensile stress (a pulling or enlongating force);

shear stress (a slicing or cleaving force).

Strain is the deformation experienced by a material in response to an applied stress. This deformation may take one of two forms, depending on the material itself and on the magnitude of the applied stress:

elastic (if the applied stress is below the elastic limit of the material, the material returns to its original shape and size once the stress is removed.);

plastic (if the applied stress exceeds the material's elastic limit, the material experiences permanent deformation; further stress increases result in additional deformation.).

Above a certain stress limit, a material will rupture, or break. If rupture takes place before significant plastic deformation occurs, the material is described as brittle. If, on the other hand, the material ruptures only after experiencing significant plastic deformation, it is considered ductile. It is important to note that under different conditions, a material may exhibit either brittle or ductile behavior.

Stress Response in Sedimentary Rocks

At atmospheric pressure, sedimentary rocks are normally brittle. They become ductile, however, under high confining stress if there is no communication between the internal rock pore pressure and the surrounding pressure medium.

Figure 1 and Figure 2

Figure 2

, comparing the stress/strain plots of Mancos shale and rock salt, illustrates this brittle/plastic transition and shows some marked differences in stress response between the two materials.

Figure 1

For the Mancos shale, percent strain is plotted against applied axial stress (psi) at various confining pressures ( Figure 1 ). The plot indicates the following:

At zero (i.e., atmospheric) confining pressure, the shale experienced brittle failure at 7,000 psi after being compressed approximately 1%;

At 1,000 psi confining pressure, the shale experienced brittle failure at 9,000 psi axial stress after being compressed 2.5%;

At 2,000 psi confining pressure, the shale became completely ductile (plastic) and much stronger. It yielded (permanently deformed) at 12,000 psi axial stress after being compressed 6%. It then required the same axial compressive stress to continuously compress the shale sample about 20%, which was the limit of the test apparatus;

Between 4,000 psi and 6,000 psi confining pressure, the shale became significantly stronger, requiring much higher levels of axial stress to initiate yield. At 6,000 psi, it required 20,500 psi of axial stress for the rock to yield.

As shown in Figure 2 , rock salt exhibits the same transition from brittle to plastic failure, but at much lower levels of confining stress it becomes completely ductile and will flow at confining pressures of 800 psi and greater.

Figure 3 (zero confining stress)

Figure 3

and Figure 4 (3000 psi confining stress) illustrate the stress/strain behavior of a cylindrical sample of porous limestone.

Figure 4

As shown, the sample was placed in a testing chamber and subjected to hydraulic compression.

At zero (i.e., atmospheric) confining pressure, the rock experienced brittle fracture at 12,000 psi compressive stress, with less than 1% strain.

Another limestone sample, identical to the first, was placed in the chamber and subjected to 3,000 psi confining pressure. The compressive stress was raised to 24,000 psi with no rock fractures; the sample experienced about a 12% length deformation, changing to a permanent "barrel" shape.

Experiments like these give some insight into the condition of rock in situ, or downhole, and how it affects drilling.

Wellbore Pressure Effects

The experiments summarized above show that confining pressure has a significant effect on rock behavior. To translate this observation into practical terms, we need to apply these laboratory conditions to the wellbore.

The confining pressure at the bottom of a wellbore is equal to the difference between the pressure exerted by the column of drilling fluid in the hole and the pore pressure, or internal pressure, of the rock. This quantity is commonly expressed as differential pressure, or P.

The value of P defines the hole condition as underbalanced, balanced or overbalanced ( Figure 5 ). Each of these hole conditions, together with temperature and rate of deformation, affects rock failure mechanisms, which in turn affect penetration rate.

Figure 5

Penetration rate is also affected by a pressure-related phenomenon known as chip hold-down. Chip hold-down occurs when a mud filter cake or fine solids block fractures produced by the bit. This prevents the liquid phase of the mud from invading the fractures, and results in a positive pressure differential across the top surface of the chip. The hold-down force is equal to the area of the chip times the differential pressure ( Figure 6 ).

Figure 6

Underbalanced Condition

If the pressure exerted by the fluid column is less than the pore pressure of the formation, the differential pressure is less than zero, and the well is being drilled in an underbalanced condition. This condition most often occurs when drilling with air, fresh water or muds weighing less than 8.6 lb/gal.

In underbalanced drilling, the rock exhibits brittle behavior it has a relatively low failure strength and fractures very easily. Because the rock surface is in tension, it virtually explodes under the compressive loads of the bit. There is no downward pressure to promote chip hold-down, and so there is very little regrinding of already-drilled cuttings. This helps attain very high rates of penetration.

Although its benefits are evident, underbalanced drilling is feasible only in areas where formation fluids can be easily controlled and there is no danger of a blowout.

Balanced Condition

When the pressure of the fluid column is equal to the pore pressure, the hole is in a balanced condition. This condition generally occurs when drilling with brine water or mud weighing 8.6 lb/gal.

Under balanced conditions, the rock is still in the brittle state and fractures relatively easily. The bottom of the hole is in pressure equilibrium, so there is minimal stress concentration present to either enhance or slow penetration rates. Penetration rates are generally slower than those experienced in an underbalanced drilling, because there is some chip hold-down resulting from cohesive forces between the rock cuttings, along with interference due to fluid viscosity.

Balanced drilling, like underbalanced drilling, presents blowout risks, and is an option only when there is no likelihood of unexpected increases in formation pressure.

Overbalanced Condition

In overbalanced drilling, the pressure of the mud column exceeds the formation pore pressure. In areas with normal pressure gradients, this condition occurs when the mud weight exceeds 8.6 Ib/gal. For safety reasons, overbalanced drilling is normal practice in most areas.

As the differential pressure increases in an overbalanced hole, the rock below the bit becomes increasingly strong and ductile. The hole bottom is in a state of compression, thus retarding fracture propagation caused by the bit. These factors, along with a high degree of chip hold-down, tend to slow penetration rates. If the differential pressure is too high, the mud can fracture the formation, resulting in lost circulation and possibly a blowout.

Differential pressures ranging from 2,000 to 6,000 psi are not uncommon in south Louisiana, south Texas, the North Sea, the Middle East and other deep basins. The induced rock strength and large chip hold-down forces created by these high differential pressures can make rolling cutter bits drill very slowly in rocks that would normally be soft and easily drilled. A plot of penetration rate versus differential pressure ( Figure 7 ) shows the dramatic effect that increasing overbalance has on drilling rates.

Figure 7

Rock sample:Mancos shale

Mud:Water-base, 10 lb/gal

Circulation rate:320 GPM

Bits used:7" Smith F2

Bit nozzles:Three (3), diameter

Weight on bit:35,000 lb

Rotary rpm:80

The only condition that changed during this experiment was the differential pressure, which was 700 psi for the first set of bit runs, 1,200 psi for the second set of bit runs and 2,500 psi for the third set of bit runs. Table 1., below, and Figure 8 summarize the test results.

Figure 8

Note that with all other conditions held constant, the increase in differential pressure resulted in dramatically reduced penetration rates and increased chip hold-down.

Test No.P, psiROP, ft/hrBottom-hole Pattern ( Figure 8 )

170062Good rock breakage and full bottomhole coverage with good interconnection of tooth craters: nominal hole diameter = 7"

21,2007Poor rock breakage, badly tracking pattern; no tooth-crater interaction; hole somewhat oval-shaped: major diameter = 8"

32,5000 to 0.5Extremely poor rock breakage with gyrating/tracking pattern. Oval-shaped; major diameter = 8"

Table 1. Effect of differential pressure on bit performance.

Normal drilling practice calls for maintaining mud weight 0.2 to 0.4 lb/gal higher than the equivalent mud weight of the formation. While this practice provides a safety factor for well control, it can also result in high differential pressures ( Figure 9 ) which, in turn, can severely limit drilling rates.

Figure 9

For example, using an 11 lb/gal mud at 14,000 feet in a well with a normal pressure gradient results in a differential pressure of 1,700 psi, which places most shales and evaporites, as well as some sandstones, into the plastic region. This results in much lower penetration rates than could be attained in shallower formations with similar lithology.

A basic awareness of rock failure mechanisms and the effects of formation conditions allows us to look more closely at the design features of rolling cutter and fixed cutter bits.

Bit Design (Rolling Cutter Types)Geometry

The shape and profile of a bit depends partly on hole-size constraints and partly on the type of cutting action desired.

The one unalterable constraint on overall bit design is the diameter of the hole to be drilled. Bit components must be of the proper sizes and proportions to fit within this limited space. Hole size determines which design variations are possible, and sometimes makes it necessary to enhance one design element at the expense of another. The larger the hole size, the more flexible designers can be in developing a well-balanced, optimum-performing bit.

Cone Profile Angle

Because it is not possible to fit three true rolling cones into the confined diameter of the borehole, designers must be align them at an angle. Cone profile angle is a design concession to hole-size restrictions. There are normally three types of cone profile angles on tri-cone bits:

inner cone profile angle, in which the front part of the cone is trying to roll around an axis which is normally past the center of the bit;

intermediate cone profile angle, in which the intermediate section of the cone rotates around an axis that is generally in the area just outside the bit diameter;

outer cone angle, or gauge, in which the apex of the outer cone is trying to revolve around a point considerably outside the bit's outside diameter.

The result of these cone angles is that the gauge (outer) rows produce a trailing/skidding action, the inner rows are in approximately a true roll and the intermediate cone angle is a major area of bit wear.

Journal Angle and Offset

The geometric design features that determine cutting action are the journal angle (where the journal is the bearing portion of the bit leg, as shown in Figure 1 ), and the offset.

Figure 1

The journal angle, by definition, is the angle formed by the intersection of a line perpendicular to the axis (or center line) of the journal and the center line of the bit.

Soft formation bits have smaller journal angles than hard formation bits ( Figure 2 and Figure 3 ).

Figure 2

For example, a soft or medium formation bit may have a journal angle of 32, while a medium hard or hard formation bit may have a journal angle of 36. Some specialty bits have a 39 journal angle.

Figure 3

Journal angle determines the following design parameters:

Out-thrust load: By design, all three-cone bits load in an outboard or out-thrust manner;

Journal' diameter: The journal diameter must be large enough to provide adequate strength so that the journal will not fail under high bit loads or rough drilling conditions such as bit bouncing. Note that the journal and leg of the bit are moment arm-type structures, which can deflect under load and load cycles. These cycles can produce fatigue and breakage, resulting in the loss of the journal/cone assembly in the hole;

Inner cone angles: As shown in Figure 2 and Figure 3 , soft formation bit types with low journal angles (32) have greater cone profile angles and a higher crowned bottom hole profile than hard formation, higher journal angle (36) bits. Higher journal angle bits have a flat bottom-hole profile;

Roller bearing diameters and lengths: Journal angle affects the size and length of various roller bearing type bit designs;

Shape of gauge teeth and degree of gauge tooth cutting action: The journal angle, together with the amount of offset in angle bit design, affects the gauge tooth shape and the degree of cutting action it provides.

Offset is the horizontal distance between the center line of the bit and a vertical plane through the center-line of the journal. Figure 4 shows this offset as a positive displacement in the direction of rotation.

Figure 4

In general, the greater the offset distance on a bit, the higher the degree of gouging/scraping cutting action it has. Soft formation bits generally have offsets that are considerably larger than those of hard formation bits ( Figure 5 ).

Figure 5

All bits are designed with some amount of positive offset. If a bit were to have a negative offset, it would produce a skidding and trailing action in the cutting structure, resulting in reduced penetration rates, abnormal wear of the cutting structure and premature failure.

The following bit parameters depend on offset:

In-thrust load-The greater a bit's offset, the more the gauge contact between the cone and the borehole wall is reduced and, therefore, the greater the in-thrust loading (remember that by design geometry, all three-cone bits load in an out-thrust manner);

Shape of the gauge teeth-The greater a bit's offset, the more aggressive (i.e., gouging/scraping) is its cutting action. To facilitate this cutting action in soft formation bits, the cutting structures are made as long and thin as possible. Hard formation bits with less offset use shorter, broader teeth or inserts to increase resistance to breakage and wear;

Degree of reaming action and gauge tooth wear-The greater the offset, the less the amount of contact between the gauge face of the cone and the borehole wall-bits with zero offset would have maximum hole contact.

This is important to understand because as offset increases, the tooth round decreases and tooth space increases. It is therefore necessary, when gauging a soft formation bit, to position a gauge tooth at the gauge point. Otherwise, a gauge ring can be passed over the cutting structure, creating the illusion that a new bit is out of gauge.

The amount of contact that the cutter has with the borehole wall will, of course, influence the degree of wear and the life of the gauge tooth.

Cutting Elements

The two basic categories of rolling cutter bits are defined by their cutting elements. A bit may either have milled steel teeth or tungsten carbide inserts.

Milled steel tooth cutters are an integral part of the bit cone. Their design parameters include shape, spacing and positioning on the cone, and hardfacing patterns.

Soft formation bits have long, relatively thin teeth that are spaced widely apart on the cone ( Figure 1 ).

Figure 1

This configuration promotes a gouging/scraping action that results in high penetration rates with minimal weight on bit. Unfortunately, these long teeth are especially susceptible to breakage in harder rock. Hard formation bits therefore have shorter, smaller, more closely spaced teeth designed to drill at higher bit weights ( Figure 2 ).

Figure 2

Figure 3 illustrates the following design parameters relating to shape and positioning of the teeth:

Teeth are positioned on the cone in rows, with the inner rows on each cone meshing with one another.

Figure 3

This tooth arrangement provides the optimum design space for a given hole size, promotes self-cleaning of the teeth as the bit turns, and provides maximum hole coverage;

Indentations, or interruptions, on the heel (outer) row of teeth, which are smaller than the teeth themselves, help prevent cuttings from wedging between the teeth.

Hard-facing has become an important component in tooth design. Application of hard-facing material can reduce tooth wear, thereby increasing both the average penetration rate and overall footage for the bit run. Manufacturers can selectively apply hardfacing to inner and gauge teeth in a variety of patterns that not only protect the teeth, but promote self-sharpening wear. Figure 4 shows some typical hard-facing patterns.

Figure 4

Tungsten carbide inserts, as their name implies, are not part of the cone material. Rather, they are separate elements, pressed into specially machined holes in the cone. They can be placed either as gauge inserts (along the outside of the cone) or inner row inserts.

Shape is an important criterion in insert design. The same general rule of thumb applies for inserts as for milled teeth: long-extension, chisel-shaped inserts for soft formations, and short-extension, rounded "button" inserts for hard formations. Beyond this basic guideline, inserts can have a variety of shapes ( Figure 5 ,

Figure 5

gauge chisel Figure 6 ,

Figure 6

inclined gauge chisel , Figure 7 ,

Figure 7

conical chisel, and Figure 8 , semi-round top):

Gauge chisel-This type of insert has a flat surface on gauge, giving it considerable contact area with the borehole compared to other gauge shapes.

Figure 8

It normally has a short extension, and is susceptible to heat generation and cracking;

Standard chisel on gauge-This design can be of various lengths and has a radial surface in contact with the hole wall;

Inclined gauge chisel-This is a special-angle insert designed to actually drill in gauge rather than using a conventional wiping/reaming action;

Conical-This insert type is symmetrical (parabolic) and shaped much like a bullet. It varies in length and extension;

Semi-round top-Hemispherical in shape, this insert type is also used for diamond-enhanced insert designs;

Wedge crest chisel-Similar to the gauge chisel except that the crest, rather than being straight like a tooth, is flared out. The insert has a flat surface contacting the hole wall;

Chisel crest-These inserts are shaped much like the teeth on milled tooth bits. The more aggressive, speed-responsive, soft formation insert bits utilize extended chisel crest designs with long protrusion or extension from the cone shell. These inserts normally have sharp crests and low included angles.

Medium and short chisel shapes have relatively large crest radii and included angles, resulting in greater cross-sectional areas than are found on long shapes. This makes them stronger and more capable of drilling higher-strength formations without chipping and breaking.

Cutting Elements

The two basic categories of rolling cutter bits are defined by their cutting elements. A bit may either have milled steel teeth or tungsten carbide inserts.

Milled steel tooth cutters are an integral part of the bit cone. Their design parameters include shape, spacing and positioning on the cone, and hardfacing patterns.

Soft formation bits have long, relatively thin teeth that are spaced widely apart on the cone ( Figure 1 ).

Figure 1

This configuration promotes a gouging/scraping action that results in high penetration rates with minimal weight on bit. Unfortunately, these long teeth are especially susceptible to breakage in harder rock. Hard formation bits therefore have shorter, smaller, more closely spaced teeth designed to drill at higher bit weights ( Figure 2 ).

Figure 2

Figure 3 illustrates the following design parameters relating to shape and positioning of the teeth:

Teeth are positioned on the cone in rows, with the inner rows on each cone meshing with one another.

Figure 3

This tooth arrangement provides the optimum design space for a given hole size, promotes self-cleaning of the teeth as the bit turns, and provides maximum hole coverage;

Indentations, or interruptions, on the heel (outer) row of teeth, which are smaller than the teeth themselves, help prevent cuttings from wedging between the teeth.

Hard-facing has become an important component in tooth design. Application of hard-facing material can reduce tooth wear, thereby increasing both the average penetration rate and overall footage for the bit run. Manufacturers can selectively apply hardfacing to inner and gauge teeth in a variety of patterns that not only protect the teeth, but promote self-sharpening wear. Figure 4 shows some typical hard-facing patterns.

Figure 4

Tungsten carbide inserts, as their name implies, are not part of the cone material. Rather, they are separate elements, pressed into specially machined holes in the cone. They can be placed either as gauge inserts (along the outside of the cone) or inner row inserts.

Shape is an important criterion in insert design. The same general rule of thumb applies for inserts as for milled teeth: long-extension, chisel-shaped inserts for soft formations, and short-extension, rounded "button" inserts for hard formations. Beyond this basic guideline, inserts can have a variety of shapes ( Figure 5 ,

Figure 5

gauge chisel Figure 6 ,

Figure 6

inclined gauge chisel , Figure 7 ,

Figure 7

conical chisel, and Figure 8 , semi-round top):

Gauge chisel-This type of insert has a flat surface on gauge, giving it considerable contact area with the borehole compared to other gauge shapes.

Figure 8

It normally has a short extension, and is susceptible to heat generation and cracking;

Standard chisel on gauge-This design can be of various lengths and has a radial surface in contact with the hole wall;

Inclined gauge chisel-This is a special-angle insert designed to actually drill in gauge rather than using a conventional wiping/reaming action;

Conical-This insert type is symmetrical (parabolic) and shaped much like a bullet. It varies in length and extension;

Semi-round top-Hemispherical in shape, this insert type is also used for diamond-enhanced insert designs;

Wedge crest chisel-Similar to the gauge chisel except that the crest, rather than being straight like a tooth, is flared out. The insert has a flat surface contacting the hole wall;

Chisel crest-These inserts are shaped much like the teeth on milled tooth bits. The more aggressive, speed-responsive, soft formation insert bits utilize extended chisel crest designs with long protrusion or extension from the cone shell. These inserts normally have sharp crests and low included angles.

Medium and short chisel shapes have relatively large crest radii and included angles, resulting in greater cross-sectional areas than are found on long shapes. This makes them stronger and more capable of drilling higher-strength formations without chipping and breaking.

Bit Design (Fixed Cutter Types)Body Material

Shear bits are traditionally made either of steel, or from a tungsten carbide matrix powder.

Steel body bits can be made from bar stock or cast alloy castings. They are capable of withstanding severe impact and torsional loads without suffering blade breakage. Steel is therefore the preferred material for high stand-off, fishtail-bladed bits, and for use in larger-diameter holes. To enhance the steel's erosion resistance, a variety of tungsten carbide coatings are available.

Tungsten carbide matrix powder is the most erosion-resistant body material now in use unfortunately, it can also be very brittle. Matrix body bits are therefore most often used in smaller diameter holes and in those applications where high-solids mud or very high flow rates are required.

Matrix body bits are fabricated using powder metallurgy techniques. The graphite molding process allows for very fast response time in bringing new matrix bit designs to the field.

Diamond Cutting Elements

Both natural and synthetic diamonds are used in drill bits. Industrial grade natural diamonds come in varying sizes and qualities; the typical diamond size for oilfield usage ranges from one stone per carat to 15 stones per carat. Large diamonds are used to drill softer formations. Their setting is referred to as surface set. Two-thirds of the diamond is buried into the matrix bit body material, while one-third is exposed on the surface of the bit. Small diamonds (8 to 10 stones per carat or smaller) can be completely buried into ridges of tungsten carbide matrix powder to protect the diamond from fracture when drilling extremely hard or abrasive formations. Bits set in this manner are referred to as ridge set.

Synthetic diamonds can be thermally stable, capable of withstanding the same temperature as natural diamonds, or non-thermally stable polycrystalline diamond compact (PDC) material.

PDC cutters are available in a variety of sizes and shapes. As with natural diamonds, larger-diameter cutters are used for drilling softer formations. Soft formation fishtail bits often use 19 mm (") diameter cutters to shear large chips of shale. Large cutter bits tend to generate more torque than bits with smaller diameter cutters, and so are most susceptible to impact damage. When hard stringers are anticipated, it is common practice to use smaller, 13 mm (") PDC cutters. In some hard formations, 9 mm (") cutters have even been used with good results.

Initially, PDC cutters were always round and flat. Subsequent advances in transition layer technology, however, have enabled the development of shaped cutters that are much more impact-resistant than flat cutters, and provide additional benefits as well. Dome shaped cutters, for example, provide side-to-side curvature for better cleaning, and top-to-bottom curvature for more stable cutting action.

Cutter Layout

All diamonds, whether natural or synthetic, are distributed across the bit face so that for each revolution of the bit, there is an equal volume of rock removed per cutter. With the help of computer-aided design programs, manufacturers can refine basic cutter layouts to eliminate potential weak areas along the cutting structure and obtain optimum bottomhole profiles.

PDC cutters are set into the bit with specified attack angles into the rock. These attack angles are referred to as the cutter orientation, or rake angles. Back rake defines the cutter's aggressiveness, or degree of gouging/scraping action.

A cutter that is perpendicular to the rock face has a zero rake angle. If the cutter leans forward into the formation like a plow tilling soil, it has a positive rake angle. If the cutter leans slightly back from the formation, this is called back rake ( Figure1 ).

Figure 1

Extensive laboratory and field tests have proven that the cutter orientation must correspond to the formation hardness. Harder formations require greater back rake angles to give durability to the cutting structure and reduce "chatter" or vibration. Softer formations can be drilled more aggressively with less back rake.

Designers often vary back rake angles across the face of the bit to more evenly distribute the workload of the drilling action through the cutter. For example, rake angles might be close to zero in the bit center and greatest in the gauge section to maximize bit life and produce even wear.

Side rake angle refers to the side-to-side orientation of the cutter ( Figure2 ).

Figure 2

Having some degree of side rake aids in mechanical cleaning of the bit face by orienting the cutter face slightly towards the outside of the bit. This directs cuttings to the annulus instead of to the front of the cutter, so that re-grinding of cuttings does not occur. Side rake also helps to stabilize the bit.

As shown in Figure3 , dome-shaped cutters have variable back rake and side rake angles.

Figure 3

The back rake angle is smallest where the cross-sectional area of the cutter is smallest. Conversely, the back rake is smallest and most aggressive where the cross-sectional area is greatest. In a homogeneous formation, this characteristic allows the dome cutter to drill throughout its life at a consistent penetration rate.

Variable rake angle is also an advantage in drilling interbedded formations. In softer drilling, where the depth of cut is greater, the dome cutter is at the more aggressive portion of its curvature, giving a greater attack angle and thus a higher penetration rate. In harder formations, where the depth of cut is less, the dome cutter attacks the formation with a higher degree of back rake, resulting in lower penetration rates but greater durability.

Profile

The shape of the head on a fixed cutter bit is called its profile. Bits designed for very soft formations have long, parabolic, sharp-nosed profiles, while harder-formation bits have compressed, wide-nosed profiles. Figure 1 illustrates bit profile and labels the parts of a diamond bit head-synonyms for the most commonly used terms are shown in parentheses.

Figure 1

The location of the bit nose (i.e., distance from center line) and the sharpness of the nose radius curvature indicate the prevalent type of cutting action and the durability of the bit design. The closer the nose is to the center line of the bit, the more aggressive the bit's cutting action will be. The more generous the bit's nose radius, the greater its durability.

Bit profile is designated by the second character of the 4-digit IADC classification code, as shown in Figure2 ,

Figure 2

Figure3 , and Figure4 .

Figure 3

Figure 4

Hydraulic Systems

The fluid flow in natural diamond bits exits the bit through a crow foot ( Figure5 )

Figure 5

that opens to waterways arranged in either feeder-collector or radial feeder-collector flow patterns ( Figure6 and Figure7 ).

Figure 6

The crowfoot was originally named for the three-toe shape of the exit ports on a natural diamond bit. A more recent six-fingered design, or split crow foot, is also available, which provides improved fluid distribution and cooling of the bit.

Figure 7

In a radial flow pattern, the waterways begin at the crowfoot exit and proceed directly toward the outside diameter of the bit. These waterways can be straight or curved. A reverse spiral, curving forward in the direction of the bit's rotation, forces fluid over the diamond pads to cool the diamonds. Radial flow natural diamond bits provide faster cleaning at high penetration rates.

Feeder-collector patterns, also known as cross-flow patterns, are composed of alternating feeder waterways, which are radial flow lines, and collectors, which are zero pressure zones. The V-shaped collectors do not connect to the crowfoot, and therefore receive no incoming fluid through the bit inside diameter. Rather, they take fluid from the feeder waterways. This cross-flow process drags the drilling fluid across the diamond pads to cool the diamonds.

Feeder-collector patterns are especially applicable in situations where heat dissipation is expected to be a problem. Turbine drilling and drilling in hard, abrasive formations requires the use of such patterns.

Jet nozzles, which are used in nearly all PDC bits, can be placed and oriented to efficiently direct drilling fluid for the removal of large volumes of cuttings. In soft-to-medium formations drilled with PDC bits, most of this hydraulic energy is used to clean cuttings from the bottom of the hole.

The hydraulics calculations used for determining nozzle sizes in PDC bits are identical to the calculations used for rolling cutter bits.

As a general rule, PDC bits are designed to use the largest possible nozzle diameter that is consistent with other bit size constraints to keep fluid velocities in high flow rate environments below the nozzle erosion threshold.

Nozzle orientation, or impingement angle, is designed to prevent excessive splashback, which could erode the bit blades. To prevent turbulent eddies, the inside bore of the bit is made as smooth as possible.

PDC bits exhibit no significant pump-off force; fluid courses along the bit continually expand to allow for fast cuttings removal.

Summary of Design Features

We may associatively group the various design features of fixed cutter drill bits to apply to different types of formations, as shown in Table 1., below. Note that natural diamond bits that use large stones tend to use radial flow hydraulics, while smaller-stone natural diamond bits used in drilling harder formations require the feeder-collector fluid course arrangement.

Formation HardnessDiamond TypeProfileHydraulic System

soft3/8" PDCLong ParabolaNozzles

1/2" PDCShort ParabolaNozzles

B-Crown

medium3/8" PDCShort ParabolaNozzles

concave

1 stone per caratLong ParabolaRadial

3-4 stones per caratShort ParabolaRadial

Feeder-collector

hard8-15 stones per caratB-CrownFeeder-collector

Table 1. Summary of design features, fixed cutter bits.

Bit HydraulicsBit Hydraulics

Hydraulic conditions at the bit are as important as its mechanical design features in determining overall drilling performance. The objective of a drilling hydraulics program is to maximize bit life and penetration rate by efficiently removing cuttings as they are drilled, and by cleaning, cooling and lubricating the bit and drill string. To accomplish this, the hydraulics system must deliver the optimum amount of energy to the bit.

Parameters that influence drilling hydraulics include formation characteristics, mud properties, circulating rate and pressure, hole size and system pressure losses. In general, the easiest, most practical method of optimizing hydraulics energy is to utilize the system pressure losses by varying the size of the bit nozzles.

General Concepts

The amount of energy that is transferred from the surface to the bit is usually expressed in terms of hydraulic horsepower, impact force or fluid velocity. Bit hydraulics programs are designed to maximize one of these quantities under a given set of operating conditions.

Bit hydraulic horsepower (HHP), impact force (IF) and fluid velocity are related to the pressure drop across the bit and the flow rate of the drilling fluid. We may express these quantities as follows:

HHP = (Pbit q)/1,714 (horsepower) ( 1 )

(HHP per square inch = HSI = HHP/Aflow) ( 2 )

IF = 0.0173 q (PbitW)1/2 ( 3 )

Fluid velocity = (.32086 q)/Aflow (ft/sec) ( 4 )where:

Pbit = pressure drop across bit, psi

q = flow rate, gallons/minute

MW = mud weight, pounds per gallon

1,714 and 0.32086 = conversion constants

Aflow = total flow area across the bit, square inches

The pressure drop across the bit face, Pbit, is given by the formula:

Pbit = (MW q2 )/[10,858 (Aflow )2] ( 5 )Where the flow rate and mud properties are constant, Aflow is the one factor that will cause the HHP, fluid velocity and pressure drop across the bit to vary. It follows, therefore, that we can control these quantities by changing the flow area (i.e., nozzle sizes) at the face of the bit.

We may also express the pressure drop across the bit in terms of the surface pressure at the mud pumps and the pressure losses in the circulating system:

Pbit = Psurf - Psys ( 6 )When:

Psurf = surface pressure at mud pump discharge

Psys = pressure losses through circulating system, including surface equipment, drill string and drill string/hole annulus

It can be shown mathematically that:

bit hydraulic horsepower reaches a maximum when the pressure drop across the bit is equal to approximately 65% of the mud pump discharge pressure, or

Pbit = .65 Psurf ( 7 )

bit impact force reaches a maximum when the pressure drop across the bit is equal to approximately 48% of the mud pump discharge pressure, or

Pbit = .48 Psurf ( 8 )For derivations of these relationships, refer to the section titled, "Determination of Optimal Bit Energy", which is found under the heading, "References & Additional Information".

For a given flow rate through a particular drill string, and with constant mud properties, Psys will be a constant. The limiting factor on Pbit in such a situation is the pressure that can be supplied by the mud pumps. That is, if pressure losses in the circulating system should increase with increasing well depth, and the mud pump is already working at its maximum operating pressure, there will be less pressure available at the bit.

To determine the optimum nozzle flow area where circulating rates are limited by mud pump capacity, annular velocity restrictions or other considerations, we can use the following procedure:

1. Determine the maximum available or allowable pump pressure.2. Calculate the pressure system losses for established circulation rates there are a number of service company hydraulics programs and graphic methods available for doing this.

3. Determine the maximum available bit pressure drop using the formula

Pbit = Psurf - Pcirc

4. Size the bit nozzles using equation 5:

Pbit = (W q2)/[10,858 (Aflow )2]

Note: When a bit uses two or three jet nozzles, we must divide Aflow by the number of nozzles to obtain Anozzle, which is the area for each nozzle. The nozzle diameter D is then calculated by the relationship

dnozzle = [(4/) Anozzle]1/2 ( 9 )

In English units, dnozzle is commonly expressed in 32nds of an inch. The nozzle diameters are selected to match as closely as possible the calculated value of Anozzle. For example, where three nozzles are used and Aflow is determined to be 0.35 in2, then:

Anozzle = 0.35 3 = .117 in2

dnozzle = [(4/)(.117)]1/2 = .386 in

386 32 = 12.35

use two" nozzles and one" nozzle

It is important to keep in mind that hole conditions change throughout the drilling of a well, and that an engineer must continually re-evaluate the hydraulics program to ensure that it applies to the current situation.

Diamond and PDC Bits

An important hydraulics consideration when drilling with PDC cutters is the need to provide sufficient fluid volume and velocity to maintain the mean wearflat temperature below 700 C (1,300 F). (The wearflat is defined as the cutting edge of the diamond layer.)

There is an optimum balance between hydraulic parameters in PDC bit applications. For example, in very soft formations, cleaning the bit and the hole are the critical factors, and so higher fluid volumes are required. In harder formations with lower penetration rates, on the other hand, keeping the cutters cool is the more important consideration.

Pump-Off Force

The pressure drop across a bit acts over the area between the cutting face of the bit and the formation, and tends to lift the bit up from the bottom of the hole. This force may sometimes be large enough to require bit weight compensation. For example, the pump-off force for a 6" natural diamond bit having a pressure drop of 600 psi would be about 3,250 lbs.

We can approximate hydraulic pump-off force as follows:

Hydraulic Pump-Off Force (lbs) = 0.942 Pbit [(bit diameter) - 1] ( 1 )

Mud Type

In water-base mud, when drilling non-hydrateable shale and permeable sandstone, drilling rate increases with increasing bit HHP.

When drilling highly hydrateable shale with a water-base mud, the highest practical bit HHP should be used. However, increased bit HHP alone does not appear capable of keeping a PDC bit clean when drilling gumbo-type shale.

When drilling with oil-base mud in non-hydrateable shale, drilling rate shows very little response to increasing bit HHP. However, when drilling hydrateable shales and permeable sandstones with oil-base mud, drilling rate increases with increasing HHP.

Tables 1 through 4, below, show general hydraulics guidelines for PDC and natural diamond bits. When drilling with water-base or oil-base muds in the formations described above, the HSI values in the upper half of the range should be used.

Bit Diameter InchesFlow Rate gallons/minute per square inchHydraulic Horsepower

7300-1502.0-5.0

8-8400-6502.0-6.0

9-9550-8502.0-6.5

10600-9002.0-7.0

12650-1,0002.0-7.0

14700-1,1002.0-7.0

16-17800-1,3002.0-7.0

Table 1. Hydraulics guidelines, fishtail PDC bits. (Courtesy Smith International)

Bit Diameter InchesFlow Rate gallons/minute per square inchHydraulic Horsepower

4-480-1501.0-3.0

5-5150-2501.0-3.0

6-6175-2751.0-3.0

7250-1001.0-1.5

12600-1,0001.0-6.0

8-8300-5501.0-5.0

9-9400-7001.0-5.0

10500-8001.0-5.5

12600-1,0001.0-6.0

Table 2. Hydraulics guidelines, full face PDC bits. (Courtesy Smith International)

Bit Diameter InchesFlow Rate gallons/minute per square inchHydraulic Horsepower

4-480-1501.0-5.0

5-5150-2501.0-5.0

6-6175-2751.0-5.0

7250-1001.0-6.0

8-8300-5591.0-7.0

Table 3. Hydraulics guidelines, full face matrix PDC bits. (Courtesy Smith International)

Bit Diameter InchesFlow Rate gallons/minute per square inchHydraulic Horsepower

4-480-1501.0-1.5

5-5100-1751.0-2.0

6-6130-2501.0-2.5

7180-3001.5-2.5

8-8250-5001.5-3.0

9-9350-5002.0-4.0

10450-6502.04.0

12500-7002.0-5.0

Table 4. Hydraulics guidelines, natural diamond bits. (Courtesy Smith International)

ExerciseDetermine the proper jet nozzle sizes for the following bit run:

Hole size = 8.75"

Depth = 3,200 feet

Mud weight = 10.0 pounds per gallon

Operating pump pressure = 2,200 psi

Maximum allowable pump pressure = 2,200 psi, due to annular velocity limitation

Circulating rate = 500 gallons per minute

Pressure losses through circulating system = 765 psi

Number of nozzles: 3

Express the diameter of each nozzle in 32nds of an inch. Note that all three nozzles may not have the same diameter.

SolutionStep 1: Determine the available pressure loss across the bit nozzles.

Pbit = Psurf - Psys = 2200 - 765=1435 psiStep 2: Determine the flow area across the bit and for each nozzle.

Aflow = [(M.W. Q2)/(Pbit 10858)]1/2

= [(10.0 5002)(1435 10858)]1/2 = 0.4005 in2

Anozzle = Aflow/3 = 0.1335 in2

Step 3: Determine the nozzle diameters:

Dnozzle = [(4/) Anozzle]1/2 = 0.4124 in. ="

use two" nozzles and one" nozzle

Bit Selection CriteriaFormation Properties

With respect to bit programs, formation properties are constant-that is, they are not subject to control. Knowing formation properties, however, is the first step in determining which bit to use in a given interval.

Formation properties that figure prominently in bit selection include:

compressive strength;

elasticity;

abrasiveness;

overburden pressure;

stickiness;

pore pressure;

porosity and permeability.

Compressive strength refers to the intrinsic strength of the rock, which is based on its composition, method of deposition and compaction. For a bit to "make hole," the driller must apply enough drill string weight to overcome this compressive strength, and the bit must be able to perform under this applied weight.

Elasticity affects the way in which a rock fails A rock that fails in a plastic mode will deform rather than fracture, this occurs most often under high confining pressures. Under such conditions, a bit utilizing a gouging/scraping action would be preferable to a bit designed to chip and crush the rock.

Abrasive formations require bits with extra gauge protection. Undergauge holes result in extra reaming and wasted rig time, and increase the chances of the drill string sticking.

Overburden pressure is the pressure exerted on a formation by overlying formations. Under normal conditions, overburden increases with depth, compacting formations and making them harder.

Porosity is a measure of the void space contained within a unit volume of rock. One cc of sandstone with a porosity of 20%, for example, contains 0.20 cc of void space. Permeability is a measure of a rock's fluid flow properties. In general, penetration rates would be expected to be higher in a highly porous, permeable formation than in a low-porosity, "tight" formation.

Pore pressure is a measure of the pressure exerted by the formation fluid on the rock matrix. Pore pressure affects mud weight requirements, which in turn can affect penetration rates.

Sticky formations (i.e., "gumbo") can result in bit-balling and reduced penetration rate.

There are a number of resources available for determining the locations, depths and properties of formations. Most of these resources consist of information from offset wells, which may include some or all of the following:

formation name and age;

open-hole logs (i.e., SP/resistivity, gamma ray, neutron, sonic);

mud logs;

core analyses;

drilling and production records;

stratigraphic cross sections.

In less-drilled areas, of course, these resources may be scarce the drilling engineer then has to make a "best guess" based on whatever geologic information and well records are available.

Well depth, hole size and casing program, directional considerations, drilling fluid characteristics and drill string configuration are interrelated "downhole" factors that are a part of the overall well program. Well depth is a key aspect, helping define both these other factors and the formation properties already described; it also relates to the capacities and capabilities of the drilling rig.

Bit Information

Both rolling cutter and fixed cutter bits are designed for a wide variety of formation types. Certain bit types, however, are best suited to a particular range of formations. For example, Table 1 below summarizes PDC applications and non-applications.

PDC bits are generally applicable toPDC bits are generally not applicable to

very weak, unconsolidated, hydrateable sediments ( sand, shale, clay )hard cemented sandstones ( angular, porosity less than 15 % )

low strength, poorly compacted, nonabrasive precipitates, (salt, anhydrite, marls, chalk )hard carbonates ( low porosity limestone evaporites or dolomite )

moderately strong, somewhat abrasive ductile sediments ( claystone, shales, porous carbonates )pyrite, chert, granite, and basalt

Table 1. PDC bit applications.

The IADC classification system provides a good starting point for comparing bit types and determining which bits might be appropriate for a given situation.

Bit records from offset wells, when available, are among the most useful tools for designing a bit program. For specific bit sizes and types, they can provide information regarding depth intervals, footage, rotating time, penetration rates, bit weight, rotational speed, jet nozzle sizes and condition of the bit at the end of the run. Assuming that depth and lithology can be correlated between the offset well and the proposed well, this information can be valuable in estimating bit performance and making an informed selection.

Offset bit records do have limitations, one of the most obvious being that they may not contain information for all of the bits that the engineer may be considering. In spite of what bit records might not reveal, however, they can provide a basis for developing and modifying the bit program as drilling progresses, and may contain data that is unavailable elsewhere.

Rig Capabilities

The drilling engineer must answer the following rig-related questions when deciding whether to run a particular bit type:

Can the rig provide the bit weight and rotating speed (determined from vendor specifications) required to obtain the optimum penetration rate from this bit?

Can the mud pumps provide the rates and pressures necessary to provide adequate hydraulics with this bit?

Since the rig's characteristics are not easily changed, a "no" answer to either of these questions requires selecting a different bit and/or changing the hydraulics program.

Bit Grading & EvaluationADC Dull Grading System

The IADC and the SPE have developed a system that allows both fixed cutter and rolling cutter bits to be evaluated using compatible grading parameters (McGehee et al., 1992; IADC/SPE 23938). Because of its versatility and flexibility, this is the preferred method for dull bit grading.

The IADC system employs eight descriptive categories for grading dull bits. The first four categories describe the condition of the cutting structure, the fifth describes the condition of bearings/seals, the sixth indicates gauge wear, and the seventh and eighth are reserved for remarks. These categories are laid out as follows, in the form of "fill-in boxes" on a bit grading sheet:

Box 1. Cutting Structure, Inner Rows Scale of 0 to 8, where 0 indicates no wear and 8 indicates no usable cutting structure.

Box 2. Cutting Structure, Outer Rows Scale of 0 to 8, where 0 indicates no wear and 8 indicates no usable cutting structure.

Box 3. Cutting Structure, Dull Characteristics BC - Broken Cone

BT - Broken Teeth/Cutters

BU - Balled Up

CC - Cracked Cone

CD - Cone Draged

CI - Cone Interface

CR - Cored

CT - Chipped Teeth/Cutters

ER - Erosion

FC - Flat Crested Wear

HC - Heat Checking

JD - Junk Damage

LC - Lost Cone

LN - Lost Nozzle

LT - Lost Teeth/Cutters

OC - Off-Center Wear

PB - Pinched Bit

PN - Plugged Nozzle/Flow Passage

RG - Rounded Gauge

RO - Ring Out

SD - Shirttail Damage

SS - Self Sharpening Wear

TR - Tracking

WO - Washed Out- Bit

WT - Worn Teeth/Cutters

NO - No Major/Other Dull Characteristics

Box 4. Cutting Structure, Location C - Cone

N - Nose (Row)

T - Taper

S - Shoulder

G - Gauge Area

A - All Areas/Rows

M - Middle Row

Box 5. Bearing/Seals Nonsealed BearingsScale of 0 to 8, where 0 indicates no life used and 8 indicates all life used

Sealed Bearings E indicates seals effective; F indicates seals failed; N indicates not able to grade; X indicates fixed cutter bit.

Box 6. Gauge 1/16" I indicates in gauge; 1/16 indicates 1/16-inch undergauge; 2/16 indicates 1/8-inch undergauge

Box 7. Remarks, Other Dull Characteristics This box is for recording secondary wear characteristics, using the same designations as given for Box 3. If a bit does not show any secondary wear, the engineer can simply write NO.

Box 8. Remarks, Reason Pulled BHA - Change Bottomhole Assembly

DMF - Downhole Motor Failure

DSF - Drill String Failure

DST - Drill Stem Test

DTF - Downhole Tool Failure

LIH - Left in Hole

LOG - Run Logs

RIG - Rig Repair

CM - Condition Mud

CP - Core Point

DP - Drill Plug

FM - Formation Change

HP - Hole Problems

HR - Hours

PP - Pump Pressure

PR - Penetration Rate

TD - Total Depth/Casing Depth

TQ - Torque

TW - Twist -Off

WC - Weather Conditions

WO - Washout, Drill String

Traditional Grading Rolling Cutter Bits

While the IADC/SPE system is the preferred method for evaluating dull bits, engineers may often come across older bit records that use different grading criteria. It is therefore useful to have some familiarity with these criteria.

Rolling cutter bits have traditionally been evaluated according to their degree of tooth (or insert), bearing and gauge wear. Tooth and bearing wear are graded on a scale of 1 to 8, while gauge wear is measured as loss of diameter.

Tooth or insert wear The designation for tooth wear is a T followed by a number from 1 to 8. For milled tooth bits, tooth wear is designated in terms of the tooth fraction that has been worn away, expressed as eighths of the original tooth height.

For example, if approximately of the bit's original tooth height has been worn away, the bit is graded a T-5; if the teeth are completely worn down, the bit is a T-8. Of course, such evaluations are overall estimates, since some teeth may be more worn than others. A bit with no tooth wear at all would be designated as "New," while a bit containing broken teeth would carry the added designation BT.

The tooth wear designation is identical for insert bits, although the meaning is different. Tungsten carbide inserts are usually lost from the bit rather than shortened. The tooth wear fraction is thus reported as the fraction of the total number of inserts that have been lost. For example, an insert bit with a designation of T-5 is one that has of its inserts missing.

Bearing wear The designation for bearing wear is B, also followed by a number from one to eight. Unfortunately, bearing wear is much more difficult to evaluate in the field than tooth wear, since the internal bearing structure is not visible. The only certainty is that completely failed bearings may be reported as B-8, while slightly loose cones may be designated by B-7. For intermediate classifications, some guesswork is required.

Intermediate bearing wear may be expressed in terms of how many additional hours the bearings might have lasted if the bit had not been pulled. For example, if a bit was pulled after 20 hours on bottom, and the drilling engineer estimates that it could have run another 20 hours, he or she would grade it a B-4 (i.e., bearings, or half-worn).

Gauge wear Using a ring gauge and a ruler, the engineer can determine how much gauge wear a bit has experienced. The loss of diameter is reported to the nearest". For example, a bit that is" under gauge would be designated by the classification G-O-3, with the G designating "gauge," the O designating "out" and the 3 designating". (G-I indicates that the bit is in gauge.)

Tooth, bearing and gauge wear are usually expressed together (e.g., T-8 B-4 G-O-1); most older bit record forms also contain space for additional remarks pertinent to the bit run.Factors Affecting Bit Wear

The appearance of a bit at the end of its run can reveal much about hole conditions, operating practices and the effectiveness of the bit program, and can provide valuable clues to help improve drilling performance when similar formations are encountered.

Roiling Cutter Bits

Even, uniform wear of bearings and teeth or inserts and minimal loss of gauge indicate that the right bit was selected and good drilling practices (i.e., proper weight on bit, rotary speed, bottom-hole assembly configuration) were followed. On the other hand, both milled tooth bits and insert bits can provide indications of drilling problems. Table 1. and Table 2. (Garner), below, list some of these indicators.

Table 1: Problems affecting milled tooth bit performance (Courtesy of Smith International)

Bit Problem Possible Cause(s) Possible Corrective Action

Excessive tooth breakage

Improper break-in

Drill a few feet before applying initial drilling weight

Junk in hole

Use more time washing on bottom before drilling, and run a junk basket

Improper bit type

Use bit with shorter teeth

Drilling practices

Use less W.O.B. and/or RPM in unconsolidated formations

Unbalanced tooth wear

Improper bit type

Select a bit with deleted gauge row teeth if inner teeth are duller and bit shows no gauge wear

Excessive shirttail wear

Cuttings "milling" around bit

Review hydraulics program

Brinnel marks, indentations under rollers/balls

Impact load from hitting ledge or bridge, or tagging hole bottom

Exercise caution when running in hole and making connections

Cones skidded, even though bearings in good condition

Bit balling up, or cones locking while drilling out casing shoe

Review hydraulics program and circulating rate

Select bit with longer, wider-spaced teeth

Use less bit weight

If from drilling float shoe, use slower rotary rpm so that torque can be more easily detected from rig floor

Off-center wear

Sloughing shale, high mud weight

Use softer-formation bit

Use faster rotary rpm

Use bottomhole reamer and stabilizers in drill string

Heavy gauge wear, inner bearing loose

Improper bit type

Use bit with less offset and/or more gauge protection

Excessive rotary speed

Reduce rotary rpm

Unstabilized drill collars

Stabilize drill string

Table 2: Problems affecting insert bit performance(Courtesy of Smith International)

Bit Problem Possible Cause(s) Possible Corrective Action

Excessive insert breakage

Improper break-in

Drill a few feet before applying initial drilling weight

Improper bit selection

If using chisel inserts, select a type with less insert extension

Drilling practices

Adjust W.O.B. and/or RPM.

Damage from foreign materials

Drilling on broken inserts from previous bits

More washing and pumping to bottom

Other junk in hole

Use junk basket on all insert bit runs if feasible

Gauge and outer rows broken

Too much offset

Use bit with less offset, which may also have less gauge insert extension

High rotary RPM

Use lower RPM

Formation wear on cone shell around inserts

Inserts too short

Use bit with longer insert extension and more offset

Insufficient cleaning under bit

Review hydraulics program

Excessive gauge wear

Too much offset

Use bit with less offset

High RPM in abrasive formation

Use slow RPM in abrasive formations

Off-center wear

Sloughing shale, high mud weight

Use softer-formation bit

Use faster rotary rpm

Use bottomhole reamer and stabilizers in drill string

Fixed Cutter (Diamond) Bits

There are four types of failure that occur in diamond wafer cutter elements: LS bond, delamination, spalling, and chipping ( Figure 1 ,

Figure 1

Figure 2 ,

Figure 2

Figure 3 , and Figure 4 ).

Figure 3

LS bond is a failure in bonding between the tungsten carbide stud and the tungsten carbide substrate.

Figure 4

Delamination is a failure in bond strength between the tungsten carbide substrate and the PCD layer.

Spalling involves flaking or partial removal of one or two of the layers that make up the diamond wafer. The amount removed and depth of the flaking determine whether the cutter should be replaced.

If the diamond wafer has spalling down to the first or second layer and involves more than 25% of the wafer, the cutter should be replaced.

Chipping is a small depression, or missing fragment, in the PCD diamond layer. It does not generally affect the cutter's performance.Wear patterns that are commonly seen on fixed cutter bits include worn, lost, broken, eroded and heat-checked cutters ( Figure 5 ).

Figure 5

A worn cutter is one in which both the diamond wafer and stud have been worn down by the formation.

Lost cutters can be interpreted several different ways, according to the IADC/SPE standardized grading system. Usually, a lost cutter results when the entire stud and wafer are missing from the socket. This is generally caused by a weak braze which holds the cutter in place. Another way to interpret a lost cutter is LS bond failure, which is also promoted by a weak braze between the stud and the substrate.

Broken cutters occur when the diamond wafer and a portion of the stud are missing. This is generally a result of impact or stud failure.

Erosion is caused by solids in the formation and drilling fluid. Unless erosion is severe, it generally does not affect bit performance.

Heat checking results from excessive heat on the cutters of a PDC bit.This heat can cause cracks to develop in the diamond wafer and carbide stud, leading to cutter failure.

Table 3 lists some of the problems that can affect diamond bit performance.

Table 3: Problems affecting diamond bit performance(Courtesy of Smith International)

Bit Problem Possible Cause(s) Possible Corrective Action

Difficulty going to bottom

Previous bit undergauge

Ream with roller cone bit

New bottomhole assembly

When reaming to bottom, pick up and ream section again; if difficulty remains, check stabilizers

Collapsed casing

Roll casing with smaller bit

Out of drift

Gauge bit with API gauge; replace bit if not in tolerance

Bit oversized

Use bi-carrier bit or reduce bit size

Stabilizer oversized

Replace with correctly sized stabilizer

Low pressure differential across nozzles or bit face

Flow area too large

Increase circulation rate, and change flow area on next bit run

Flow rate too low

Increase flow rate/strokes; change pump liners

Change in drilling parameters

Recalculate hydraulics program

Washout in drill string

Check bit pressure drop, drop softline, trip to check drill pipe and drill collars

High pressure differential across nozzles or bit face

Flow area too small

Use bit with less offset, which may also have less gauge insert extension

Excessive flow rate

Use lower RPM

Diamonds too small for formation

If ROP is acceptable, change on next bit; if ROP is not acceptable, pull bit and use bit with correct diamond size

Bit partially plugged (formation impaction)

Check off-bottom standpipe pressure; let bit drill off; circulate at full volume for 10 minutes while rotating; check off-bottom pressure again

Formation change

Pick up, circulate, resume drilling at higher RPM; reset; run drill-off-test

Ring out

On and off-bottom pressure test; pull bit

Downhole motor stalled

Refer to manufacturer's specifications

Fluctuating standpipe pressure

Drilling through fractured formation

If ROP is acceptable, continue

Formation breaking up beneath bit

If ROP is acceptable, continue

Check equipment

Try combination of lighter WOB and higher RPM

Stabilizers hanging up

Check overpull; check stabilizers on next trip

Bit won't drill

Not on bottom

Re-check pipe tally

Stabilizers hanging up or too large

Check torque, overpull

Formation too plastic

Check pressure, increase flow rate; decrease/increase WOB, RPM

Establishing bottomhole pattern

Can take up to an hour

Core stump left

Decrease WOB

Bit balled

Back off and increase flow rate, then slug with detergent, oil or synthetic fluid

Slow rate of penetration

WOB too low

Increase WOB

RPM too low/high

Increase/decrease RPM

Plastic formation

Reset drill-off; reset WOB

Formation change

Reset drill-off

Overbalance

If ROP acceptable, continue bit run; if ROP unacceptable, pull bit

Diamonds flattened off

Compare beginning and current pressure drops; may need new bit

Pressure drop too low

Increase flow rate; may need new bit

Wrong bit selection

Pull bit

Excessive torque

Too much weight on bit

Reduce WOB and RPM

Slow RPM

Increase rotary speed

Stabilizers too large

Use smaller stabilizers

Collars packing off

Increase flow rate

Bit undergauge

Pull bit

Bit bouncing

Slip-stick action

Change WOB/RPM combination

Broken formation

Reduce RPM and WOB

Pump-off force

Increase mud weight; decrease circulating volume

Bit Run Economics

As with other aspects of well design, drilling and production, bit programs are ultimately based on economics, with their most basic objective being to minimize the overall cost per foot of drilling the well.

The cost per foot of a bit run is expressed in Equation 1.

Along with mechanical indicators like torque, this cost per foot relationship is a useful tool for monitoring bit performance. During a bit run, C typically reaches a minimum, and then begins to increase as the bit wears and the penetration rate decreases. By periodically calculating C throughout the bit run, an engineer can determine when it would be more economic to run a new bit.

While knowing how to calculate cost-per-foot during a bit run is important, it is only the first step in analyzing bit economics. We need to take Equation 1 a step further so that we can select bits based on comparative performance.

For example, the cost of a diamond bit can be up to four times the cost of a tungsten carbide insert bit, and up to twenty times the cost of a mill tooth bit. For the diamond bit to be economical, its performance (footage, drilling time) must justify this extra cost. To determine whether this is the case, we can conduct a break-even analysis.

C = [R(T + t) + B]/F ( 1 )where:

C = drilling cost per foot

R = rig operating cost per hour *

T = drilling time, hours

t = trip time, hours

B = bitcost

F = footage drilled

*Note that R includes all costs associated with the actual drilling of the well, including rig rate, mud logging and conditioning, equipment rentals, transportation, and all other supporting materials and services

The break-even point is simply the combination of footage and drilling time needed for the cost per foot of one bit to equal the cost per foot that we could obtain if we used a different bit (or bits) for the same interval. To find the break-even point, we need a bit record from an offset well, (see example below).

Example:

The following partial bit record is available from a nearby well:

Bit SizeTypeBit CostDepth OutFtg.Hrs.ROP, ft/hr

8"OSC-1G$1,0008,650 ft6501640.6

8"OSC-1G$1,0009,175 ft5251535.0

8"X3A$1,0009,600 ft4251528.3

8"J22$4,35010,150 ft5502027.5

8"J22$4,35011,000 ft8503028.3

Offset well performance(interval 8,000' to 11,000'):

Total rotating time = 96 hours;

Total trip time = 48.5 hours;

Rig operating cost = $300/hour;

Total bit cost = $11,700;

Total footage = 3,000 feet.

Therefore, the offset cost for the interval 8,000'-11,000' is

C = [300 (96+48.5) + 11,700]/(3,000) = $18.35/ftWhen performing a break-even analysis, the bit performances in the offset well are known, but bit performance in the new well must be estimated. Thus, we must assume either the footage that the new bit will drill or the penetration rate it will attain.

If we assume that the bit will drill a certain footage, then we can calculate the break-even penetration rate using the following formula, which can be derived from Equation 1.

ROP = ( 2 )Where:

ROP = break even penetration rate, ft/hr

R = rig operating cost, $/hr

C1 = offset cost per foot, $

t = trip time for new bit

B2 = new bit cost, $

F2 = assumed new bit footage, ft

To determine the break-even performance of a PDC bit costing $14,800

R = $300

C1 = $18.35/ft

t =11 hours

B2 = $14,800

F2 = 3,000'

Thus, the break-even penetration rate is

ROP = 300/[18.35 - (300 11 + 14,800)13,000] = 24.4 ft/hrIf we instead assume a penetration rate, we can calculate the break-even footage as follows:

F = ( 3 )Continuing with the preceding example,

If we assume a penetration rate of 30 ft/hr, the break-even footage is

F = [(300 x 11) + 14,800]/[18.35 - (300/30)] = 2,168 ftThe PDC bit needs to drill only 2,168 feet to attain the break-even point if it can maintain an average penetration rate of 30 ft/hr.

Although this illustration involves a comparison between a PDC bit and rolling cutter bits, break-even analysis can be applied to any bit types.

We can see from this discussion that economic analysis of bit performance involves a certain amount of guesswork. Our bit selection based on break-even analysis is only as valid as our estimates of footage or penetration rate. These estimates, therefore, must be as accurate as possible, which is why the drilling engineer must become as familiar as he or she can with bit types, formation characteristics, mud properties, hydraulics, rig operating conditions and other factors that influence bit performance.

Exercise1. Determine the cost per foot of the following PDC bit run:

Rig cost = $350/hour

Rotating time = 105 hours

Trip time = 12 hours

Bit Cost = $12,500

Footage = 2,750 feet

Soln

C = [R(T + t) + B]/F = [350(105 + 12) + 12500]/2750 = $19.44/ft

2.

You are considering using a PDC bit on your next bit run which costs $12,500. Bit records from several offset wells indicate an average cost of $25.00 per foot for drilling this same interval with insert-type rock bits. Based on experience in other areas, it is reasonable to expect a penetration rate of 30 ft/hr for this PDC bit. Your rig's operating cost is $400/hour, and the current trip time is 10 hours.

Should you run the PDC bit, or continue to use insert bits?

SolnBreak-even penetration rate:

ROP = R/[C/F - (RT + B)/F] = 400/[18.00 - (4000 + 12500)/2500] = 35.1 ft/hr

To break even with the insert bit performance, the PDC bit would need to average 35.1 ft/hr over the assumed 2500 foot interval. Previous experience indicates that this ROP may be beyond the bit's capability in this formation. You should therefore continue to run insert bits in this interval.

Bit Operating GuidelinesGeneral Considerations

As with other drilling equipment, proper care and handling increases bit life and lessens the chance of failure. Some basic guidelines that apply to all bit types are as follows:

Preliminary Inspection

Check the bit type to confirm proper size, type and option.

Look inside the bit for any foreign objects that could plug a nozzle.

Check the age of the bit the amount of time for which it has been stored could affect its performance. For example, some bits stored longer than four years could have problems with bearing lubrication and could fail prematurely.

Inspect the cutting structure and API pin connection for any signs of damage due to mishandling during shipping or delivery.

Using a ring gauge, measure the bit OD to verify API gauge standards.

Re-check well conditions to ensure that the nozzles (or total flow area) are appropriately sized.

Inspect the previous bit for tooth wear, broken teeth, gauge wear and Junk damage. Broken teeth and Junk damage are indications of possible Junk in the hole. Take all precautions to ensure that the hole is clean before running any bit.

Bit Make-Up

Make sure the bit is handled with care. Do not set it directly on the rig floor; instead, use a piece of wood or a rubber mat.

Grease the API pin and fit the bit into a properly sized bit breaker. Lower the drill string onto the bit and engage the threads. Locate the bit and breaker in the rotary table and make up to the recommended torque values.

Tripping

Trip slowly through the blowout preventers, casing shoe and liner hanger, and be especially careful of dog legs, tight spots or ledges spudding and sudden impacts are common reasons for early bit failure.

Consider using a vibration dampener to minimize shock when drilling hard, abrasive formations.

Stabilize the bit using the appropriate bottomhole assembly.

Approach the bottom of the hole cautiously. Kick in the pumps and wash the last three joints to bottom at reduced rotary speed. Observe weight and rotary torque indicators. When bottom is reached, "break in" the bit gradually using reduced bit weight and rpm. Once the bit establishes its bottomhole pattern, weight and rpm can be gradually increased.

Drilling

Do not exceed the manufacturer recommendations for weight and rotary speed; use the appropriate W.O.B and rpm for the formation.

Monitor penetration rates and periodically calculate the economics of the bit run to determine when it should be pulled. At the same time, be aware of torque, reduced drilling rate and other indications of bit wear.

Roller Cutter Bits

There are several things to keep in mind when running rolling cutter bits, particularly those with inserts or journal bearings (Jackson and Wood, 1973):

Be especially wary of running excessive weight on insert bits; this can result in lost inserts and damage to the bearings;

In shales, increasing rotary speed generally has more effect on penetration rate than increasing weight on bit;

In limestones, increasing weight while decreasing rotary speed prevents insert breakage;

In broken formations, it may be necessary to reduce rotary speed to prevent bit bouncing;

Pull the bit when it begins to "torque up." Torque can indicate locked bearings or an undergauge hole. Special care needs to be taken with journal-bearing bits, which may exhibit very little torque before failing.

Fixed Cutter Bits

PDC and natural diamond bits are run under different conditions than rolling cutter bits, including conditions related to weight on bit, rotary speed, hydraulics and bit break-in. While some of the procedures below are generally applicable, the specifics (e.g., recommended rotary speed) are just for diamond bits.

When drilling out float equipment, make sure that it and the cement plugs are PDC-drillable. If they are not, then make a run with a mill-tooth bit before running the PDC bit.

Before reaching to bottom, kick on the pumps and wash the last three joints to bottom with full flow and 40-60 rpm rotary speed. After tagging bottom, circulate at full flow with 40-60 rpm for 5 to 10 minutes.

Reaming long sections while tripping in the hole with a PDC or diamond bit is not recommended. Excessive reaming can result in severe gauge damage. However, if reaming does become necessary

use low rotary speed and weight on bit (40-60 rpm; 2,000,000 lb)

always use maximum pump strokes while reaming slowly

avoid high torque

When breaking in the bit, establish the bottomhole cutting pattern with 2,000,000 lbs bit weight and 60-80 rpm. Record pump strokes and standpipe pressure and compare these values to expected hydraulics. Slowly break in the bit, drilling at least one foot at this weight and speed. Increase rotary speed to 100-120 rpm and add weight in 2,000 lb increments to determine optimum weight on bit. While maintaining constant weight on bit, vary the rotary speed to determine optimum drilling conditions.

When drilling ahead, follow these procedures for making connections or during formation changes:

After making a connection, reset the pump strokes and check the standpipe pressure. Set the bit approximately six inches off bottom and pump for 30 seconds before drilling.

With 60-80 rpm, slowly lower the bit back to bottom. Gradually add weight to attain the previous weight on bit and increase the rotary speed to the previous rpm. Do not spud the bit on bottom this may result in cutter damage or bit balling.

As the bit encounters formation changes or stringers, it will be necessary to adjust the weight on bit and rotary speed to maintain optimum performance. When drilling harder formations or abrasive sand stringers, the rotary speed should be reduced to increase bit life.

Observing these guidelines will result in improved bit performance and lower cost per foot.

Determination of Optimal Bit Energy

Many drilling people talk about the maximum bit hydraulic horsepower occur-ring when the pressure drop across the bit is equal to 65% of the total pump pressure, and the maximum jet impact force occurring when the pressure drop across the bit equals 48% of the pump pressure. This section shows how these numbers are derived.

Maximum Bit Hydraulic Horsepower

Let

Psurf = pump pressure (assume constant)

Q = circulating rate

Pbit = bit pressure drop

HHP = bit hydraulic horsepower

Kds = drill string pressure loss constant

K = bit pressure drop constant

Psys = pressure losses through drill string and surface equipment

HHP = (K)(Pbit)(Q) ( 1 )

and Pbit = Psurf - Psys ( 2 )Substituting,

HHP = (K)(Psurf - Psys )(Q) ( 3 )

Define Psys = (Kds)(Q)x ( 4 )where x = a constant for a given rig and drilling assembly.

For this case, let x = 1.82

Substituting ( 4 ) into ( 3 ),

HHP = (K)[Psurf - KdsQ1.82](Q) ( 5 )

HHP = (K)[(Psurf)(Q) - Kds(Q2.82)] ( 6 )Maximizing HHP with respect to Q by differentiation,

(dHHP)/(dQ) = K(Psurf - 2.82(KdsQ1.82) = 0 ( 7 )

(K = 0 is the trivial case)

Solving for the other case,

Psurf - 2.82(KdsQ1.82) = 0 ( 8 )

Psurf = 2.82(KdsQ1.82) ( 9 )

and KdsQ1.82 = Psys ( 4 )Substituting ( 4 ) into ( 9 ),

Psurf = 2.82 Psys ( 11 )

Psys = .355 Psurf ( 12 )

Pbit = Psurf - Psys = 0.65 Psurf ( 13 )Maximum bit hydraulic horsepower occurs when the pressure loss across the bit nozzles is equal to 65% of the pump pressure. In practice, most people simply use a value of 66% or 2/3.

NOTE: Depending on the value of x in (B.4), the value of 65% will vary slightly. This method is not accurate if laminar flow occurs in the annulus. Typical values for x, along with the corresponding percentage for Pbit, are as follows:

Exponent xPercent of Pressure Drop

1.7864%

1.8064%

1.8265%

1.8465%

1.8665%

1.9066%

Maximum Jet Impact Force

Let:

Fb = Impact force

W = weight of drilling fluid

g = gravitation constant

V1 = nozzle jet velocity

V2 = fluid velocity parallel to V1 direction after impingement on hole bottom

t = time

= Fluid density

Q = flow rate

Pbit = pressure drop across bit

K = bit pressure drop constant

C = nozzle coefficient

K' = adjusted bit pressure drop constant

Ki = impact force constant

Psys = pressure drop through drill string and surface equipment

Kds = drill string pressure drop constant

Psurf = pump pressure

Newton's law:

Fb = (W/g)a = (W/g)[(V1-V2)/t] ( 14 )

Assume V2 0

W/t = Q (mass flow rate) ( 15 )

Pbit = ( Q2)/KA2C2) ( 16 )

V1 = Q/A, so V12 = Q2/A2

=> Pbit = ( V12)/(KC2) ( 17 )

V1 = [Pbit (KC2)]/ ( 18 )where = constant (assume incompressible fluid)

V = K'(Pbit)1/2 ( 19 )Substituting ( 15 ) and ( 19 ) into ( 14 ),

Fb = [K' Q(Pbit)1/2]/g ( 20 )Define Ki = (K' )/g

=> Fb = Ki Q(Pbit)1/2 ( 21 )Holding the pump pressure constant,

Pbit = Psurf - Psys ( 22 )Substituting,

Fb = Ki Q(Psurf - Psys)1/2 ( 23 )

Psys = Kds(Q1.82) ( 24 )Substituting (24) into (23),

Fb = Ki Q[Psurf - Kds(Q1.82)]1/2so

Fb = Ki (Psurf Q2 - Kds Q3.82)1/2 ( 25 )Using differentiation to maximize Fb with respect to Q,

dFb/dQ = Ki [2Psurf Q - 3.82 Kds Q2.82][.5(Psurf/Q2 - KdsQ3.82)-1/2] (26)

Ki = 0 is the trivial case; for the other case,

(2Psurf)Q = 3.82 Kds Q2.82 ( 27 )and

Psurf = 1.91 KdsQ1.82 ( 28 )now

Kds Q1.82 = Psys ( 24 )so

Psurf = 1.91 Psys ( 29 )

Pbit = Psurf - Psys ( 22 )

Pbit = Psurf (Psurf/1.91)

=> Pbit = 0.48 Psurf ( 30 )Maximum Jet Impact Force occurs when the bit pressure drop is 48% of the surface pump pressure. For simplicity's sake, this is often approximated as 50% or 1/2.

NOTE: The pressure loss exponent will cause differences in this 48% figure. If flow in the annulus is laminar, this method is not accurate.

Exponent xPercent of Pressure Drop

1.7847%

1.8047%

1.8248%

1.8448%

1.8648%

1.9049%