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Bit Technology - Diamond Bits

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Diamond Bits

Diamond core bits were introduced into the oilfield in the early 1920's and
were used to core extremely hard formations. These early diamond bits
were very expensive, costing about twenty times the price of the roller bits.
Since performance was barely economical for coring, very little
consideration was given to diamond bits as a drilling tool.
By the 1940's, a much improved technique had been developed for the
manufacture of diamond bits. The diamonds were cast in a matrix of
tungsten carbide powder bonded together with a copper and nickel binder.
This change permitted the use of more complex bit designs and diamond
setting patterns. These changes resulted in the improved performance of
diamond bits, and reduced the cost of the diamond bits as compared to
roller cone bits. However, they still were ten to fifteen times the cost of
roller bits, and therefore limited to a “last resort” item.
Regardless of reputation, many drilling engineers were attracted to
diamond bits because of the ability of being able to stay on the bottom and
drill for longer periods of time. During the late 1950's several major oil
companies began research programs on diamond bits, and these studies
provided a much better understanding of the mechanics of diamond bit
drilling and the influence of hydraulics on the penetration rate. This, plus
subsequent developments of more erosion resistant matrix materials, led to
performance levels in the 1970's which provided cost savings on a regular
basis.

Bit Technology - PDC Bit Drilling Parameters

PDC Bit Drilling Parameters

Even though PDC bits have achieved recognition as a viable tool for
improved drilling, certain precautions and drilling parameters should be
met in order that the bit run be as efficient and economical as possible.
1. When the prior bit is removed, it should be inspected for any
damage. If junk was left in the hole, do not run a PDC bit until
the hole is cleaned.
2. When picking-up a PDC bit, take all the precautions normally
taken when handling a diamond bit, and some additional ones:
a. When removing the bit from its box, handle it carefully. Do
not roll it out on the rig floor. If the bit is dumped on the floor
and some of the cutters are chipped, the bits life will be
reduced.
b. The interior of the bit should be inspected to make sure no
debris is left inside.
c. The proper bit breaker should be used to make up the bit.
3. The bit is one solid piece and does not have the limited flexibility
of roller cone bits. Hitting ledges or running through tight spots
can damage the gauge cutters.
4. If it is necessary to ream when going into the hole, pick up the
kelly and run the maximum flow rate. The rotary speed should be
about 60, and go through the tight spot slowly.
5. When near bottom, the last joint should be washed down slowly
at full flow and 40-50 rpm, to avoid plugging the bit with any fill.
a. To locate the bottom of the hole, observe the torque and
weight indicators. Because of the type of cutting structure on
PDC bits, it is common that the first on-bottom indication is a
sudden increase in torque.
b. After the bottom of the hole has been reached, the bit should
be lifted a foot or two off bottom, then circulate and rotate
slowly for about five minutes to make certain the bottom of
the hole is cleaned.
6. When ready to start drilling, bring the rotary speed up to 60 and
approach bottom. Light weight should be used in order to cut a
new hole pattern.
a. At least 1 foot of new hole should be cut in this manner before
looking for optimum weight and rotary speed for drilling.
b. In soft formations, the bit will drill quickly with light weight,
and the rotary speed should be increased until the bit is
drilling at its fastest rate (usually between 100-150 rpm).
c. In hard formations, it will take much longer to drill the one
foot. Adding weight too quickly will damage the cutters.
Once the bottom hole pattern is established and weight is
added, watch the torque indicator for possible problems.
7. There is no limit to rotary speed, use as much as possible without
damaging the rest of the drillstring.
8. The on-bottom torque should approach what is experienced with
roller cone bits. If there is no torque buildup, or the penetration
rate does not increase with added weight, the formation may not
be suitable for PDC bits.
9. After making a connection, the bit should be washed back down
to bottom. Dropping and then stopping the drillstring suddenly
can cause the bit to hit bottom and be damaged due to pipe
stretch.
10. PDC bits respond dramatically to changing formations, if the rate
of penetration suddenly decreases or the bit starts torquing, a
change in the weight-on-bit and rotary speed should help.
11. When the cutters wear to a point where they will not drill, the bit
should be pulled. If the wear is primarily on the outside, there
will be a sudden decrease in the penetration rate and torque, and
an increase in standpipe pressure. If the wear is on the gauge
portion, there will be very high on-bottom torque with little
weight-on-bit and a decrease in the penetration rate.

Bit Technology - PDC Bit Operating Parameters

PDC Bit Operating Parameters

PDC bits do not have the benefit of the self fluid-cleaning action between
rows of teeth like roller cone bits, so they must rely on the bit’s hydraulics
to flush the cuttings from under the bit to prevent balling. This is
accomplished with strategically positioned converging-diverging nozzles
which maximize cleaning while minimizing erosion of the body near the
nozzle area. Optimum hydraulic range is between 2.0 to 4.0 hydraulic
horsepower per square inch. The interchangeable jet nozzles come in
standard sizes from 8/32’s to 14/32’s.
Bit life is controlled by the cutting structure. As stated earlier, the PDC
cutting elements provide a self-sharpening edge with the wear resistance of
diamonds. This combination is very effective in soft to medium formations
such as shale, chalks, limestones, clays, salts and anhydrite. These
formations have been drilled at excellent penetration rates with weights
between 1000 and 2500 pounds per inch of bit diameter and rotary speeds
of 85 to 140 rpm. Economic performance has also been achieved with
rotary speeds of 750 rpm and weights of 1000 pounds per inch of bit
diameter using downhole motors.
High rotary speeds provide better drill rates and reduce the chances of
deviation. Optimum rotary speed varies with formation hardness. A soft,plastic formation would require higher rpm; a hard formation, lower rpm.
Most applications require rotary speeds less than 120 rpm.
Lighter weight-on-bit means lower stress on the drill string, with increased
string life as a result. There's less drag in directional holes because fewer
drill collars are required, reducing the potential for stuck pipe.
These bits have made economical runs in both oil and water base muds. Oil
base muds and the addition of lubricants to water base muds will enhance
PDC bit performance in formations that tend to be somewhat plastic and
sticky.
Formations which should be avoided with PDC bits are soft sticky shales
and clays, abrasive sands, and those formations which are very hard. In
sticky formations, PDC bits have a tendency to ball up; in abrasive
formations or hard formations, cutter wear and breakage occur rapidly.
PDC bits cannot drill as broad a range of formations as roller cone bits, but
have shown to be competitive with diamond bits. Thus, care must be taken
when selecting bits for various applications. When properly applied, most
PDC bits can be run in more than one well.
PDC bits cost between $10,000 to $25,000, and savings are measured in
terms of trip time saved, longer bit life, improved rates of penetration, and
fewer rig hours required to drill a well.

Bit Technology - Bit Design

Bit Design

PDC bits feature a steel or matrix head, which is advantageous because
there are no bearings to wear out or broken cones to have to fish out of the
hole. The bit has a long, extended gauge with cemented tugsten carbide
wear pads to help maintain gauge. There is also inherent stabilization in the
bits extended gauge.
The face of the bit is concave, permitting several gauge and nose cutters to
attack the rock simultaneously, increasing stabilization while decreasing
the potential for deviation.
Jet nozzles vary in size and number, are interchangeable, and are
strategically located for maximum cleaning action of the cutters and the
bottom of the hole.
The cutters are arranged in one of three patterns:
• an open face, helical pattern on the face of the bit
• a ribbed pattern, with the cutters on ribs less that one-inch above
the bit face
• a bladed patters, with the cutters on blades, more than one-inch
from the bit face
All three types provide complete cutter coverage for a consistent
bottomhole pattern. One bottomhole pattern, known as kerfing, uses a
combination of scribe and round cutters to enhance the scraping and
shearing action of the bit.
Without moving parts, the bit shears the rock rather than gouging or
crushing as do the roller cone bits.

Bit Technology - PDC Drill Blanks

PDC Drill Blanks

These drill blanks consist of a layer of synthetic polycrystalline diamond
bonded to a layer of cemented tugsten carbide using a high-temperature,
high-pressure bonding technique. The resulting blank has the hardness and
wear resistance of diamond which is complemented by the strength and
impact resistance of tungsten carbide.
PDC blanks are self-sharpening in the sense that small, sharp crystals are
repeatedly exposed as each blank wears, and because they are
polycrystalline these blanks have no inherently weak cleavage planes,
which can result in massive fractures as in the large, single crystal
diamonds in the diamond bits.
The blanks are then bonded to tungsten carbide studs, which are then pressfitted
into holes on the steel or matrix head of the bit. The cutters are
positioned in a helical pattern on the bit face so as to have a negative rake,
an equal distribution of weight-on-bit, and a redundant shearing action.
The result being an optimal rate of penetration.
The bit body is forged from the same high strength steel used in the cones
of tri-cone bits, and the face is then coated with a layer of tungsten carbide,
to resist fluid erosion.

Bit Technology - Polycrystalline Diamond Compact Bits

Polycrystalline Diamond Compact Bits

In the early days of oilwell drilling, fishtail/drag bits were used extensively
throughout the oilfields. Around 1909, it was realized that these drag bits
would not penetrate many of the formations which overlay deeper oil and
gas reservoirs, and were eventually replaced by roller cone bits.
General Electric, recognizing that drag bits had advantages (most notably
the absence of moving parts and the efficiency of shear cutting) began in
the early 70's the testing of new cutting structures for these drag bits. Since
their introduction into the oilfields in 1976, the cutting structure of the
polycrystalline diamond compact (PDC) has made the drag bit competitive
with the conventional roller cone and diamond bits.

Bit Technology- Heat Treating

Heat Treating
The desired metallurgical properties and physical strengths are developed
through heat treating. As mentioned above, the strength is improved by
increasing the carbon content at the surface by carbonizing, commonly
known as “case hardening”. This is essential for the teeth on milled tooth
bits, and necessary for strength and wear resistance on the bearing surfaces.
Toughness (resistance to impact and crack propagation) is attained by
leaving the inner part or the “core steel” unchanged.
The overall physical properties that are needed (strength and toughness)
are achieved by heating the parts to a high temperature, then quenching
them in oil. The maximum surface hardness of the carbonized section gets
about 60 - 64 Rc (the hardness of a file). The core hardness will be about 25
- 40 Rc, remaining tough and ductile.
Mill Tooth Bit Teeth
The teeth on a mill tooth bit are sometimes “hard-faced” using tungsten
carbide. This hard-facing can be on the gauge teeth (for hard formations),
the inner teeth (for soft formations), or on both rows. Hard-facing is
applied in such a way so that, as the teeth dull, the hard-facing causes a
self-sharpening of the tooth.
Insert Bits
Over the past ten years, most of the progress in rolling cutter bits has been
made in the design of insert bits. Although the merits of tugsten carbide
bits has long been accepted, it was not until recently that bit manufacturers
obtained enough experience with the carbide material and design to make it
possible to consider this type of bit for application in virtually all
formations - soft, medium and hard.
The chief advantage of this concept is that there is virtually no change in
the configuration of the cutting structure due to wear. In addition, any bit
often finds good application in a variety of formations. Thus, the limiting
factor on performance is usually the life of the bearing assembly (providing
formation changes do not cut short the bit run).
The basic principles governing insert-type bit designs are the same as those
applied to milled tooth design, desired depth of tooth interfit, insert
extension, cone shell thickness, cone diameter, and gauge requirements.
Of primary importance is the proper grade of carbide material used in the
inserts. Much has been learned in this respect since the initial model was
placed on the market. Experience has shown the need for carbide materials
of various grades, dictated largely by the design purpose of the cutting
structure.
At present, the manner in which insert bits now function closely parallels
the mechanics of the three major categories of milled tooth bits, soft
(gouging/spading), medium (chipping plus limited penetration), and hard
(crushing/fracturing). For this reason, the composition as well as the
configuration of the insert material is being subjected to constant
evaluation and improvement. To date, the ultimate in both areas has not
been determined.

Bit Technology- Material Requirements

Material Requirements

The rock bit must be stronger than the rock it is to drill. The measurement
of hard steel is measured on the “Rockwell” hardness tester scale (Rc). The
tester uses a diamond pyramid indenter with a load of 150 kilograms. The
deeper the indentation in the steel, the softer it is.
The degree of hardness that can be produced in steel is determined by its
carbon content, the higher the percentage of carbon (up to 0.7%), the
harder the steel. By heat treating properly, it can be made up to about 65
Rc. Alloying elements improve the hardening potential in thick sections
and cause the steel to have a more uniform response to heat treating. The
steel must also be ductile (resistance to crack propagation). This ductility
or “toughness” of metals is inversely related to hardness (the harder a
metal, the less ductile. The softer the steel, the more ductile). Alloying
elements improve the ductility of steels and toughness, and resistance to
failure from impact loads.

Bit Technology- Bearing Systems

Bearing Systems

The first type of bearing system used with roller cone bits was a nonsealed,
roller-ball-friction bearing arrangement, utilizing rollers on the heel
of the journal. The primary load, or stress was exerted on these rollers, and
drilling fluid was used to lubricate the bearings. Bearing size was
maximized, since room for a seal was not required. The bearing surfaces
were machined and ground to very close tolerances to ensure dependable
service. This type of bearing system is also available with modifications for
air circulation and for use with a percussion hammer (Figure 3-6a).
The next generation of bearing systems was a sealed roller bearing system,
having a sealed grease reservoir to lubricate the bearings. The bearing
system is composed of: 1) a roller-ball-friction or roller-ball-roller bearings
2) the seal, which retains the lubricant and prevents drilling fluid and
abrasive cuttings from entering the bearing cavities, 3) the shirttail is
designed and hardfaced to protect the seal, 4) a lubricant, an
elasto-hydrodynamic type, is used to ensure minimum friction and wear, 5)
the reservoir, which stores and supplies the lubricant to the bearings, and 6)
the vented breather plug, which transfers downhole fluid pressure against
the lubricant-filled flexible diaphragm to equalize pressures surrounding
the bearing seal (Figure 3-6b).

Figure 3-6a Figure 3-6b
There is, however, one serious drawback to the roller-ball-roller bearing
system. The primary cause of roller bearing failure is journal spalling,
which causes destruction of the rollers and the locking of the cone.
To remedy this, instead of the standard roller bearing assembly, the
“journal bearing” system utilizes solid metal bushings for direct cone to
journal contact. This offers a distinct mechanical advantage over roller
arrangements in that it presents a larger contact area at the load bearing
point. This distribution of the load eliminated the chief cause of roller
bearing assembly failure - spalling in the load portion of the bearing face.
Journal bearing systems in the tungsten carbide insert bits features a metal
bearing surface combined with a hardfaced journal and a lubricant.
Specialized seals and reliable pressure equalization systems keeps the
drilling fluid and formation contaminants out of bearings, and positively
seals the graphite-based lubricant inside the bearing. Precision fit of the
journal and cone distributes contact loading evenly throughout a nearperfect
arc. Bearing surfaces are finished to a carefully controlled surface
texture to ensure optimum lubrication.
The manufacturing of the journal bearing system consists of having the
journals either milled, grooved or pressed (depending on the bit company)
to accommodate the bushing. Then the bushings are inlaid on the journal.
Once the cone is fitted with teeth and gauge protection, the journal is then machine-pressed into the cone. To complete the seal between the cone and
the journal, special rings (seals) have been developed.
Seals
The first and still most popular seal is the radial seal (used mainly on the
sealed roller bearing bits). The radial seal is a circular steel spring encased
in rubber, which seals against the face of the shank and the face of the
cone. The newer “O” ring seal is considered the most effective seal. The
major problem confronting the “O” ring is tolerance, which must be precise
in order to maintain an effective seal.
An understanding of lubricants and lubricating systems is necessary for
successful drilling operations. The lubricating systems are essentially the
same, and are composed of an external equalizer located under the bit or on
back of the shanks, a grease reservoir with some sort of expandable
diaphragm to distribute the grease, and some sort of distribution system to
the bearings. In addition, there is a pressure relief valve to release any
trapped pressure, which might otherwise rupture the seals.
Pressure surges can be detrimental to these sealed systems. As pressure and
temperature increase, the viscosity of the lubricant increases. As a result,
the system cannot instantaneously compensate for abrupt changes in
pressure due to surges (going into the hole, making connections, etc.) and
small quantities of mud invade the system. With the close tolerance
necessary for effective sealing, mud solids can be damaging.
Adequate cleaning is even more important with sealed bearing bits. If
drilled cuttings are allowed to build up around the shirttail, seal damage
and premature bearing failure may result. Gauge protection is also
important to seal and bearing life, because seal damage can occur from
shirttail wear caused by inadequate gauge protection.
Any time a sealed bearing bit is rerun, the seals and shirttail should be
carefully checked for excessive wear or grooving.
To complete the journal-cone assembly, a positive seal is required to keep
drilling fluid out, while allowing the graphite lubricant in, which keeps the
bearings from overheating. The positive seal requires a relief valve to allow
escape of excess pressure, which can overload the seal and cause seal
failure.

Bit Technology- Cutting Structures - Gauge Protection

Gauge Protection

Protection of the gauge surface is vital to the effectiveness of any bit. The
gauge surfaces constantly ream the hole, and thus are subject to continuous
abrasive wear.
Applying tungsten carbide in a steel matrix through a welding process,
called “hardfacing”, provides the best resistance to this type of wear.
Gauge protection is improved as the amount of hardfaced surface area
increases.
The configuration of the gauge teeth determines the available surface area.
The “A” type teeth are standard for soft formation bits, resulting in
minimum gauge protection for drilling medium-hard formations. The “T”
type teeth provides the greatest amount of surface area for the application
of hard metal, and are used for abrasive formation bit types.
For work in very hard formations, a flat-top tungsten carbide insert is
pressed into the gauge surface for additional protection.
Gauge protection is specified in roller cone bits by adding a “G” to the
IADC code.

Bit Technology- Cutting Structures - Tungsten Carbide Cutting Structures

Tungsten Carbide Cutting Structures

Since most of the basic design features of the mill tooth cuttings structures
have been incorporated into insert bits, the main variations occur in insert
shape (Figure 3-5).

Figure 3-5: Tungsten Carbide Tooth Shapes
Historical shapes of milled teeth have built up a mystique about insert tooth
shape. Many people in the oil field thought that chisel shaped teeth
significantly affected the drill rate in all formations. This was because early
drilling practices used light bit weights, causing the relatively sharp chisel
shaped inserts to have a higher unit loading on the formation, hence faster
drill rates. When heavier bit weights are used, it tends to nullify the
advantage of the chisel shape. Even the steel milled teeth break down under
heavy weights. In fact, most bits drill 75% of the hole in a 1/2 to 3/4 dull
condition. With this in mind, many “blunt” insert tooth designs were made,
and seem to drill efficiently. Nowadays, most insert teeth have this blunt,
conical shape.

Bit Technology- Cutting Structures - Steel Tooth Cutting Structures

Steel Tooth Cutting Structures

There are three basic design features incorporated in steel tooth cutting
structures, teeth spacing, tooth hardfacing, and tooth angle (Figure 3-4).
Using variations of these parameters, bits are separated into formation
types.

Soft Formation Cutting Structures
Teeth on this type of bit are few in number, widely spaced,
and placed in a few broad rows. They tend to be slender, with
small tooth angles (39° to 42°). They are dressed with hard
metal.
Medium Formation Cutting Structures
Teeth on medium formation bits are fairly numerous, with
moderate spacing and depth. The teeth are strong, and are a
compromise between hard and soft bits, with tooth angles of
43° to 46°. The inner rows as well as the gauge rows are
hardfaced.
Hard Formation Cutting Structures
There are many teeth on this type of bit. They are closely
spaced and are short and blunt. There are many narrow rows
with tooth angles of 46o to 50o. The inner rows have no
hardfacing, while the gauge row is hardfaced.

Bit Technology- Cutting Structures

Cutting Structures

In 1909, when roller cone bits were introduced into the oilfield, the drag bit
was replaced by the roller cone’s steel tooth cutting structure. These steel
(milled) teeth have undergone changes in height, number per cone, and
thickness, to accommodate the various types of formations.
When harder formations tended to “eat up” the steel teeth, a different
cutting structure was needed, and in 1949 the first insert bit was used.
Introduced by Hughes Tool Company and nicknamed the “The Chert Bit”,
it brought on-bottom drilling hours up from 5 hours to 30 hours or more.
Many of the design features in the milled tooth bits were incorporated into
insert bits.

Bit Technology- Circulation Systems - Jet Nozzles

Jet Nozzles

There are essentially three types of jet nozzles used in tri-cone bits.
Shrouded nozzle jets provide maximum protection against retainer ring
erosion, excessive turbulence or extended drilling periods. Standard jet
nozzles are easier to install and are recommended for situations where
erosion is not a problem. Air jet nozzles (see above) are used on bits
designated for drilling with air or gas.
Nozzle sizes play an important role in bit hydraulics. The benefits of the
correct selection include effective hole cleaning and cuttings removal,
faster drill rates and thus lower drilling costs.
Orifice sizes are stated in 1/32 inch increments, with the most common
being between 10/32 to 14/32 sizes. Directional bit jets are available in
sizes from 18/32 to 28/32.

Bit Technology- Circulation Systems - Air or Gas Circulation Bits

Air or Gas Circulation Bits

A third type of circulation medium is compressed air or gas, and can be
used with either regular or jet circulation bits. Bits manufactured for air or
gas circulation have special passageways from the bore of the bit to the
bearings, through which a portion of the air or gas is diverted to keep the
bearings cool and purged of dust or cuttings. From the special passageways
to the bearings, the air or gas passes through a number of strategically
located ports or holes in the bearing journal, flows through the bearing
structure and exhausts at the shirttail and gauge of the bit, to flow up the
annulus.

Bit Technology- Circulation Systems - Regular Circulation Bits

Regular Circulation Bits

Regular circulation bits (Figure 3-3a), have one to three holes drilled in the
dome of the bit. Drilling fluid passes through the bore of the bit, through
the drilled holes, over the cutters, and then to the bottom of the hole, to
flush away the drill cuttings.

Bit Technology- Circulation Systems

Circulation Systems

The first hydraulic features incorporated into drilling tools dated back to
the original use of hollow drillpipe with direct circulation of drilling fluids.
As the first fishtail bits became popular, around the turn of the century,
circulation though water courses was used for the first time. The first
rolling cutter rock bits of 1909 introduced a central water course system
which directed fluid discharge towards the cutters.
In 1942, rock bits with jet nozzles were introduced to the oil industry. The
“jet bit” concept is considered to be the major hydraulic design
improvement in drill bits and remains state-of-the-art.
Further improvements in the circulation systems include extended nozzle
bits, seven to twelve nozzles in PDC bits, and the various water courses in
diamond bits.

Bit Technology- Interfitting Teeth and Cone Offset

Interfitting Teeth and Cone Offset

The idea of interfitting teeth (Figure 3-2a), makes it possible to have large bit parts, and allows the inner row of teeth to cut new formation on each rotation. Interfitting also offers some degree of self-cleaning. One result of this interfitting is that each of the three cones are different.

Cone offset (Figure 3-2b), is caused by the journal centerline not intersecting the bit centerline (or bit center of rotation). The distance that the journal centerline misses the bit centerline (measured perpendicular to the journal centerline at the center of rotation) is the offset.

The skew point is an arbitrary point along the journal centerline and is the angle formed by the offset, the centerline of the journal, and a line from the bit center to the skew point. The skew direction is always “positive”, or in the direction of rotation. This permits the tips of the teeth to “ream” the hole to full gauge. “Negative” skew would have the gauge face rubbing the hole wall, increasing gauge wear.

As with the journal angle, the offset will be different in each type of formation. In soft formation bits, the maximum offset (3o skew angle) is used to increase the gouging, scraping action. Medium formation bits add a limited offset (2o skew angle) to develop cutter action. While hard formation bits have no offset, to minimize gouging and scraping.

Bit Technology- Journal Angle

Journal Angle

One of the basic design fundamentals of rolling cutter rock bits is the journal angle. Though this angle may vary from one rock bit type to the next, in each bit the three journal angles are all identical.
The journal angle (Figure 3-1) is the angle at which the journal is mounted, relative to a horizontal plane. This mounting moves the cutting elements (cones) outside the support members. The journal angle also controls the cutter profile or pattern it drills, and it affects the amount of cutter action on
the bottom of the hole.

Journal angles are different for each “type” of formation:

Soft Formations

Journal angle (33o) - this allows a cutter profile which accentuates cutter action and permits greater tooth depth.

Medium Formations

Journal angle (34o to 36o), to decrease cutter action.

Hard Formations

Uses a large journal angle (39o), to minimize cutter action.

Bit Technology - Rolling Cutter Rock Bits

Rolling Cutter Rock Bits

The first successful rolling cutter rock bit was introduced into the oil field by Howard Hughes Sr. in 1909. Over the next fifteen years, the rolling cutter bit was used primarily in hard formation areas. This rolling cutter bit was a two-cone bit with cones that did not mesh, consequently, the bit had a tendency to “balled-up” in soft shales. The bit was redesigned with meshing teeth (self-cleaning) in the 1920s and in the early 1930’s, the tricone bit was introduced with cutters designed for hard and soft formations.

The primary drilling mechanism of the rolling cutter bits is intrusion, which means that the teeth are forced into the rock by the weight-on-bit, and pulled through the rock by the rotary action. For this reason, the cones and teeth of rolling cuttings rock bits are made from specially, case hardened steel.

One advantage of a rolling cutter bits is the three bearing design located around the journal of the bit. Heel bearings are roller bearings, which carry most of the load and receive most of the wear. Middle bearings are ball bearings, which hold the cone on the journal and resist thrust in either direction. The nose bearing consists of a special case hardened bushing pressed into the nose of the cone and a male piece, hard faced with a special material, to resist seizure and wear.

Although rock bits have been continually improved upon over the years, three developments remains outstanding: (1) the change in water course design and the development of the “jet” bit, (2) the introduction of the tungsten carbide insert cutting structure, and (3) the development of sealed journal bearings.

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