Drilling Engineering – Chapter 5: Drilling Bits
Chapter 5
Drilling Bits
4.1. Introduction
A drilling bit is the cutting or boring tool which is made up on the end of the drillstring (Figure 1). The bit
drills through the rock by scraping, chipping, gouging or grinding the rock at the bottom of the hole. Drilling
fluid is circulated through passageways in the bit to remove the drilled cuttings. There are however many
variations in the design of drillbits and the bit selected for a particular application will depend on the type of
formation to be drilled. The drilling engineer must be aware of these design variations in order to be able to
select the most appropriate bit for the formation to be drilled. The engineer must also be aware of the impact of
the operating parameters on the performance of the bit. The performance of a bit is a function of several
operating parameters, such as: weight on bit (WOB); rotations per minute (RPM); mud properties; and
hydraulic efficiency.
4.2. Classification of Drilling Bits
There are basically three types of drilling bit (Figure 1)
• Drag Bits
• Roller Cone Bits
• Diamond Bits
4.2.1. Drag Bits
Drag bits were the first bits used in rotary drilling, but are no longer in common use. A drag bit consists of
rigid steel blades shaped like a fish-tail which rotate as a single unit. These simple designs were used up to
1900 to successfully drill through soft formations. The introduction of hardfacing to the surface of the blades
and the design of fluid passageways greatly improved its performance. Due to the dragging/scraping action of
this type of bit, high RPM and low WOB are applied.
The decline in the use of drag bits was due to:
• The introduction of roller cone bits, which could drill soft formations more efficiently
• If too much WOB was applied, excessive torque led to bit failure or drill pipe failure
• Drag bits tend to drill crooked hole, therefore some means of controlling deviation was required
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• Drag bits were limited to drilling through uniformly, soft, unconsolidated formations where there were no
hard abrasive layers.
4.2.2. Roller Cone Bits
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. Advantages of roller cone
bits are:
Improved cleaning action by using jet nozzles
• Using tungsten carbide for hardfacing and gauge protection
• Introduction of sealed bearings to prevent the mud causing premature failure due to abrasion and corrosion of
the bearings.
4.2.3. Diamond Bits
Diamond has been used as a material for cutting rock for many years. The hardness and wear resistance of
diamond made it an obvious material to be used for a drilling bit. The diamond bit is really a type of drag bit
since it has no moving cones and operates as a single unit.
A new generation of diamond bits known as polycrystalline diamond compact (PDC) bits were introduced in
the 1980’s (Figure 5). These bits have the same advantages and disadvantages as natural diamond bits but use
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small discs of synthetic diamond to provide the scraping cutting surface. The small discs may be manufactured
in any size and shape and are not sensitive to failure along cleavage planes as with natural diamond. PDC bits
have been run very successfully in many areas around the world. They have been particularly successful (long
bit runs and high ROP) when run in combination with turbodrills and oil based mud.
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 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;
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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.
4.3. 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.
4.3.1. 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
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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.
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.
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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.
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.
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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.
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Penetration rate is also affected by a pressure-related phenomenon known as chip hold-down. Chip holddown 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
4.3.2. Failure Mechnisms of Drag Bits
Drag bits are designed to drill primarily by a wedging mechanism. If drag bits could be kept drilling by
wedging, they would not dull so quickly. It iw when they are dragging and, thus, scraping and grnding that
they drill slowly and dull quickly. A twisting action also may contribute to rock removal from the center
portion of the hole. A vertical force is applied to the tooth as a result of applying drill collar weight to the bit,
and a horizontal force is applied to the tooth as a result of applying he torque necessary to turn the bit. The
result of these two forces defines the plane of thrust of the tooth or wedge. The cuttings are sheard off in a
shear plane at an initial angle to the plane of thrust that is dependent on the properties of the rock.
The depth of the cut is often expressed in terms of the bottom cutting angle, . the angle  is a function of
the desired cutter penetration per revolution Lp and radius r from the center of the hole.
𝐿𝑝
2𝜋𝑟
Diamond drag bits are designed to drill with a very small penetration into the formation. The diameter
on the individual rock grains in a formation such as sandstone may not be much smaller than the
depth of penetration of the diamonds. The drilling action of diamond drag bits in this situation is
𝑡𝑎𝑛𝛼 =
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primarily a grinding action in which the cementaceous material holding the individual grains is
broken by the diamonds.
Rock mechanics experts have applied several failure criteria in an attempt to relate rock strength
measured in simple compression tests to the rotary drilling process. One such failure criterion often
used is the Mohr theory of failure. The Mohr criterion states that yielding or fracturing should occur
when the shear stress exceeds the sum of the cohesive resistance of the material c and the frictional
resistance of the slip planes or fracture plane. The Mohr criterion is stated mathematically by:
𝜏 = ±(𝑐 + 𝜎𝑛 𝑡𝑎𝑛𝜃)
Where t = shear stress at failure; c = cohesive resistance of the material; n = normal stress at the
failure plane;  = angle of internal friction.
To understand the use of the Mohr criterion, consider a rock sample to fail along a plane. When
loaded under a compressive force F and a confining pressure p. the compressive stress 1 is given by
𝐹
𝜎1 = 2
𝜋𝑟
The confining pressure is given by
3 = p
If we examine a small element on any vertical plane bisecting the sample, the element is in the stress
state. Further, we can examine the forces present along the failure plane at failure using the free-body
elements. The orientation of the failure plane is defined by the angle  between the normal-to-thefailure plane and a horizontal plane. Summing forces normal to the fracture plane gives
The unit area along the fracture plane dAn is related to the unit areas dA1 and dA2 by
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Making these substitutions in the force balance equation gives
Summing forces parallel to the fracture plane gives
Expressing all unit areas in terms of dAn and simplifying yields
These two equations represent graphically by the Mohr’s circle.
Example: A rock sample under a 2,000 psi confining pressure fails when subjected to a
compressional loading of 10,000 psi along a plane wich makes an angle of 270 with the direction of
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the compressional load. Using the Mohr failure criterion, determine the angle of internal friction, the
shear strength and the cohesive resistance of the material.
Solution: the angle  and 2 must sume to 900. Thus the angle of internal friction is given by
 = 90 – 2(27) = 36 0
The shear strength is computed as follows
 = ½(1 – 3)sin(2) = ½(10,000 – 2,000)sin(540) = 3,236
The stress normal to the fracture plane is
n = ½(1 + 3) – ½(1 – 3)cos(2) = 3,649 psi
The cohesive resistance can be computed
c =  - ntan= 585 psi
4.3.3. Failure Mechanism of Rolling Cutter Bits
Percussion or crushing action is the predominant mechanism present for the rolling cutter bits. Since
these types of bits are designed for use in hard, brittle formations in which ROP tend to be low and
drilling costs tend to be high, the percussion mechanism is of considerable economic interest.
The apparatus allowed the borehole pressure, rock pore pressure, and rock confining pressure to be
varied independently. The apparatus was equipped with a static loading device which used an airactuated piston to simulate constant force impacts similar to those produced in rotary drilling. Strain
gauges and a linear potentiometer were used to obtain force displacement curves.
Maurer found that the crater mechanism depended to some extent on the pressure differential between
the borehole and the rock pore pressure. At low values of differential pressure, the crushed rock
beneath the bet tooth was ejected from the crater, while at high values of differential pressure the
crushed rock deformed ina plastic manner and was not ejected completely form the crater.
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As load is applied to a bit tooth (A), the constant pressure beneath the tooth increases until it exceeds
the crushing strength of the rock and a wedge of finely powdered rock then is formed beneath the
tooth (B). as the force on the tooth increases, the material in the wedge compresses and exerts high
lateral forces on the solid rock surrounding the wedge until the shear stress exceeds the shear strength
of the solid rock and the rock factures (C). these fractures propagate along a maximum shear surface,
which intersect the direction of the principal stresses at a nearly constant angle as predicted by the
Mohr failure criteria. The force at which fracturing begins beneath the tooth is called the threshold
force. As the force on the tooth increases above the threshold value, subsequent facturing occurs in
the region above the initial fracture, forming a zone of broken rock (D). at low differential pressure,
the cuttings formed in the zone of broken rock are ejected easily from the crater (E). the bit tooth then
moves forward until it reaches the bottom of the crater, and the process may be repeated (F, G). At
high differential pressures, the downward pressure and frictional forces between the rock fragments
prevent ejection of the fragments (E’). As he force on the tooth is increased, displacement takes place
along fracture planes parallel to the initial fracture (F’, G’). This gives the appearance of plastic
deformation, and craters formed in the manner are called pseudoplastic craters.
4.4. Factors affecting penetration rate
The most important variables affecting penetration rate that have been indentified and studied
included: bit type, formation characteristics, drilling fluid properties, bit operating conditions (WOB,
and ROP), bit tooth wear, and bit hydraulics.
4.4.1. Effecting of Bit Type
The bit type selected has a large effect on ROP. For rolling cutter bits, the initial ROP is often highest
in a given formation when using bits with long teeth and a large cone offset angle. However, these
bits are practical only in soft formations because of a rapid tooth destruction and decline in
penetration rate in hard formations. The lowest cost per foot drilled usually is obtained when using
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the longest tooth bit that will give a tooth life consistent with the bearing life at optimum bit operating
conditions.
Drag bits are designed to obtain a given penetration rate. As discussed previously, drag bits give a
wedging type rock failure in which the bit penetration per revolution depends on the number of
blades and the bottom cutting angle. The diamond and PCD bits are designed for a given penetration
per revolution by the selection of the size and number of diamonds or PCD blanks. The width and
number of cutters can be used to compute the affective number of blades.
4.4.2. Effecting of Formation Characteristics
The elastic limit and ultimate strength of the formation are the most important formation properties
affecting ROP. The shear strength predicted by Mohr failure criteria sometimes is used to
characterize the strength of the formation. To determine the shear strength from a single compression
test, an average angle of internal friction of 350 was assumed. The angle of internal friction varies
from about 30 – 400 form most rocks
The permeability of the formation also has a significant effect on the ROP. In permeable rocks, the
drilling fluid filtrate can move into the rock ahead of the bit and equalize the pressure differential
acting on the chips formed beneath each tooth. This would tend to promote the more explosive elastic
mode of crater formation. it also can be argued that the nature of the fluids contained in the pore
spaces of the rock also affects this mechanism since more filtrate volume would be required to
equalize the pressure in rock containing gas than in a rock containing liquid.
The mineral composition of the rock also has some effect on ROP. Rocks containing hard, abrasive
minerals can cause rapid dulling of the bith teeth. Rocks containing gummy clay minerals can cause
the bit to ball up and drill in a very inefficient manner.
4.4.3. Effecting of Drilling Fluid Properties
The properties of drilling fluid reported to affect the ROP include: density, rheological flow
properties, filtration characteristics, solids content and size distribution, and chemical composition.
Penetration rate tends to decrease with increasing fluid density, viscosity and solids content, and
tends to increase with increasing filtration rate. The density, solid, and filtration characteristics of the
mud control the pressure differential across the zone of crushed rock beneath the bit. The fluid
viscosity controls the system frictional losses in the drillstring and thus the hydraulic energy available
at the bit jets for cleaning. The most important factor out of the drilling fluid properties is the density.
Changing density will change the overbalance. The ROP decreases as the overbalance increases.
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4.3.4. Effecting of operating conditions
When plotting ROP vs. WOB obtained experimentally with all other drilling variables held constant
has the characteristic shape as shown:
No significant ROP is obtained until the threshold bit weight is applied (point a). ROP then increases
rapidly with increasing values of WOB. For moderate value of bit weight, a linear curve is often
observed (segment bc). However, at higher values of bit weight, subsequent increase in bit weight
causes only slight improvements in ROP (cd). In some cases, a decrease in RO is observed at
extremely high value of WOB (de). This type of behavior often is called bit floundering. This poor
response of ROP at high values of bit weight usually is attributed to less efficient bottomhole
cleaning at higher rates of cuttings.
A typical plot of ROP vs. rotary speed obtained with all other drilling variables held constant is
shown
ROP usually increases linearly with low RPM. At higher values of RPM the response of ROP to
increase RPM diminishes. The reason is due to the poor hole cleaning.
Maurer developed a theoretical equation for rolling cutter bits relating ROP to WOB, RPM, bit size,
and rock strength. The equation was derived from the following observation made in single tooth
impact experiments: (1) the crater volume is proportional to the square of the depth of cutter
penetration (2) the depth of cutter penetration is inversely proportional to the rock strength.
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2
𝐾 𝑊
𝑊
𝑅 = 2[ −( ) ] 𝑁
𝑆 𝑑𝑏
𝑑𝑏 𝑡
Where
K = constant of proportionality
S = compressive strength of the rock
W = bit weight
W0 = threshold bit weight
db = bit diameter
N = rotary speed.
The theoretical equation of Maurer can be verified using experimental data obtained at relatively low
bit weight and rotary speeds corresponding to segment ab in Figures above.
Bingham suggested the following drilling equation on the basis of considerable laboratory and field
data.
𝑊 𝑎5
𝑅 = 𝐾( ) 𝑁
𝑑𝑏
Where K is the constant of proportionality that includes the effect of rock strength and a5 is the bit
weight exponent.
In this equation the threshold bit weight was assumed to be negligible and the bit weight exponent
must be determined experimentally for the prevailing conditions.
4.4. Bit Selection
4.4.1. Formation 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.
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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
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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 to
PDC bits are generally not applicable to
very weak, unconsolidated, hydrateable sediments ( sand, shale, hard cemented sandstones
clay )
porosity less than 15 % )
(
angular,
low strength, poorly compacted, nonabrasive precipitates, (salt, hard carbonates ( low porosity limestone
anhydrite, marls, chalk )
evaporites or dolomite )
moderately strong, somewhat abrasive ductile sediments (
pyrite, chert, granite, and basalt
claystone, shales, porous carbonates )
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?
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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.
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