1.1.

1 INTRODUCTION

Drilling bits, and their close relatives core heads, are the pieces of equipment which actually drill the hole through
rocks. It follows that their efficiency usually has a major influence on the cost of drilling a well, to a degree which
bears little relation to the cost of the bit itself. Because of this a great deal of effort has been put into their design,
ranging from fundamental research into the mechanism of cutting rock to the details of the fabrication of the bits.

The subjects of Topic 2 and Topics 4 to 8 of this Part are drilling bits. Topic 3 is an introduction to diamonds and
synthetic diamond technology.

Topic 9 describes core-heads, which are very closely related to bits. There is in principle little difference between
the two - a core head is a bit with a hole through the middle so that it cuts away a ring, leaving a core of
undisturbed rock to pass up through that hole. Everything which is said about bits applies to core heads (apart
obviously from what is related to the cutting area), but core heads introduce the additional mechanical problem of
recovering the core still in its undisturbed state. This associated equipment is also described.

The last topic, Topic 10, covers equipment which is used for increasing the diameter of an existing hole. The two
variations are the hole opener and the under-reamer.

1.1.2 HISTORY

The first type of drilling rig used a percussion drilling technique, which is just a scaled up version of a man making
a hole in a wall with a hammer and chisel. The bit was chisel shaped and was attached to a heavy weight which
was lifted and dropped repeatedly by means of a cable. (The alternative name for the technique is cable drilling.)
From time to time the loose rock had to be cleaned out by dropping a "bailer" - a hollow pipe with a flapper valve
on the bottom. Progress was slow and evidently there was no means of pressure control.

You are very unlikely to come across this technique and the tools will not be mentioned further.

The greatest single change in drilling techniques was the change from percussion to rotary drilling, in which a
round hole is made by rotating a drilling bit on the end of a length of hollow pipes. The hollow drill string allows a
drilling fluid to be circulated giving many benefits (see Section 3, Part 3), including the cooling of the bit. This
technique is still in use, with the only changes having been to the design of the bit and the method of transmitting
torque to the bit. The latter has been discussed in Section 2, Part 1. This present Part covers the various types of
bit which are available.

The three types of bits that are used in rotary drilling, are drag bits, roller cone bits and diamond bits.

Drag bits were the earliest type of bit used, and although they are now obsolete they could still be used efficiently
in the soft surface formations. They comprise two, three or four steel cutting blades that are an integral part of the
bit body. The alternative name for a drag bit is a fish-tail bit, derived from the appearance of a two bladed bit.

Next in chronological order came roller cone bits. Patents on roller cutting bits date back to 1866, but the first
successful oilfield application was in 1909. That was a bit with two cones (arranged symmetrically). Bits with three
cones (tri-cone bits) were introduced in 1931 and are still the most widely used bits. Multi-cone bits have been
tried but in general were not successful.

In the years since its introduction two major improvements have been made to the design of the tri-cone bit. In
1951 a type of bit was introduced in which the steel teeth that were an integral part of the cone were replaced by
sintered tungsten carbide teeth inserted into the cone. In 1969 a type of bit was introduced in which the roller
bearings in the cone were replaced by journal bearings.

As drilling got deeper and the rocks encountered got harder diamond bits were introduced. Industrial diamonds
were set into the surface of a bit which was used basically as an abrasive tool to wear away the rock. Since 1955 it
has been possible to make diamonds artificially from graphite under a pressure of approximately 7,000 MPa
or1,000,000 psi and a temperature of 1350° C. The longer the pressure and temperature remain applied, the
larger the synthetic diamonds will become. Synthetic diamonds were tried in drilling bits and core-heads instead of
natural diamonds, but were not adopted on a large scale because of a lower impact resistance.
In 1973 experiments with the use of sintered polycrystalline diamond compacts (PDC) as cutting elements were
started. These have developed rapidly, and PDC bits are now almost as widely used as roller cone bits.

In the early 1980s the Thermally Stable Polycrystalline (TSP) diamond was developed. Single artificial diamonds
comprising many small crystals with a random orientation were fabricated under the same conditions but instead of
forming layers they were grown to a large size with a specified shape. TSP diamonds have now virtually replaced
natural diamonds in the type of bit for which the latter have previously been used.

A relatively new development using natural diamonds is that of impregnated bits, in which the diamonds are
arranged not only on the surface of the tungsten carbide matrix bit, but also within it, so that as one layer wears
away a continuous supply of fresh diamond cutting edges is exposed.

1.1.3 CUTTING MECHANISMS

To make hole, a drill bit must deliver enough energy to the formation to break up the rock and remove the
cuttings. The primary objective of a drill bit's design is to cut the rock as efficiently as possible maximising the
volume of rock removed with the available power - to produce high penetration rates. The hydraulic configuration
of the bit, i.e. the flow patterns, must assure that both the hole bottom and the cutting elements are kept clean so
that the bit can keep drilling, and so that it will last long enough to drill an economical section of hole.

Drilling bits use three main methods for cutting rock:

 Crushing, by putting the rock in compression as a roller cone bit

 Ploughing/grinding the formation, as natural diamonds do, and
 Shearing the formation as PDC and TSP diamond bits do.

These methods are illustrated in the relevant Topics.

1.1.4 BIT SELECTION

OBJECTIVE

The bit performance is measured by the total length and time drilled before the bit has to be replaced and is
expressed as the overall cost per unit depth for the bit run.

Minimum cost per metre is the objective.

The required calculation is given in Appendix 1.

CHOICE OF BIT TYPE

Before any bit is chosen an estimate of the probable cost per metre is made for each type of bit in the situation in
which it is to be run. Bit records, and experience, will be used to estimate the penetration rate and service life of
each type in the formation which it is expected to encounter.

Changes in formation during one bit run can have a considerable impact on the penetration rate. Therefore it is
important to know which formations, and how much of each, will be encountered. Some of this information can be
gathered from logs, some from rock samples or cores from previously drilled wells.

In addition to the selection of the correct bit the main factors which play a role in the bit performance are the
drilling parameters, drilling fluid properties and hydraulic factors.

The formations to be drilled and the prognosed depths of formation changes will be given in the drilling
programme. These will form the basis for the decision on the bit types to be made available. In this respect the
difference between exploration drilling and appraisal/development drilling must be borne in mind.
For appraisal/development drilling:

 Provisional bit programmes will have been prepared based on previous experience in the field, specifying
bit type, weight on bit, rpm and hydraulics.
 Available bit records and logs from nearby wells will be used when selecting bits or deciding to pull out.

For exploration drilling:

 There is limited information regarding the drillability of formations. Therefore a wider range is required in
stock than for appraisal wells.
 If available, information from nearby wells or wells in the same geological province will be invaluable when
making the selection and may be included as recommendations in the programme.
 When choosing a bit based on the records from other, older, wells you should remember that the drilling
rate of a formation depends not only on its hardness but is also influenced by other factors. Blindly
copying bit runs from other nearby wells is therefore not sufficient. In particular a very significant factor
that can influence the penetration rate is the drilling fluid density. It should be taken into account that in
the past many formations may have been called hard, although in fact, penetration was adversely affected
by high drilling fluid density, which may no longer be in use. It is therefore not abnormal if a softer bit is
required.
 If no information from nearby wells is available, bit selection becomes a matter of experience and to some
extent trial and error.

There is an enormous variety of bit types potentially available from which to choose. This is simplified by using the
classification scheme described in Appendix 2.

Very often, although diamond bits are many times more expensive than roller bits, the absence of bearings and
other moving parts provides a bit life usually several times that of the conventional roller cone bits. The cost of the
rig time saved by eliminating several round trips to change the bit in a deep well will probably be more than the
additional cost of the bit. Even so, the choice is not automatic, because account has to be taken of how far the bit
will actually have to drill. If there is a casing point or a coring point within a short distance there is little point in
running a bit with a long life - however if an expensive bit has a higher penetration rate than a cheaper bit as well
as a longer life, then it could be run, used to drill a few metres quickly, and then be saved for use in the next well.

The following practical guidelines are usually applied:

 It is good practice to keep more than one type ready to go.

 The condition of the dull bit pulled out is a very important factor in the final selection of the next bit run -
unless there is a high probability that the formation is going to change within a short distance.
 Softer bits generally drill faster, in general are cheaper, and are only replaced by harder bits when strictly
necessary.

1.1.5 BIT RECORDS

Bits may stop drilling for several reasons.

Apart from changes in the formation roller cone bits may make no further progress because:

 the teeth are worn away.

 one or more of the cones is "locked", because a bearing has failed, and is just skidding around on bottom.
 a bearing has failed completely and the cone is lying free on the bottom.
 the teeth are rolling round in a layer of cuttings which are not being cleaned away and are thus unable to
penetrate new formation.
 the teeth may not be able to penetrate because the space between them is clogged up with formation
material which is not being cleaned away.
Assuming that the bit has previously been drilling properly then the possible reasons for the latter two problems
are

 that one or more nozzles has been eroded away ("washed out") thus reducing the jet velocity of the
drilling fluid. A connected reason, which has nothing to do with the bit, is that a leak has appeared in the
drill string through which the drilling fluid will flow preferentially.
 that one or more nozzles has been plugged, thus reducing the flow rate through the bit.

Diamond bits, of all types, may stop making progress because:

 the cutters are worn or broken, either over the whole surface of the bit or at a particular radius, which will
allow a ridge to develop on bottom. In this case the bit is said to be ringed - see Appendix 3.
 the cutters and bit face are not being kept clean. In a bit with nozzles the same reasons given above may
apply. In a bit with water courses, these may have become too shallow because the bit matrix has worn
down.

Whatever the reason why a bit has stopped drilling may be, this is important information. The wear pattern and
general condition should be inspected as soon as the bit has been pulled and should be recorded. Such records give
an indication of the useful working life of that type of bit in that formation and aids the selection of the type of bit
which may prove most efficient in a particular formation in the future. The amount of wear on teeth and bearings
of roller cone bits, or on the cutters and body of diamonds bits, and on the gauge of all types is recorded according
to a so-called dullness grading system. This is explained in Appendix 3.

1.1.6 THE HANDLING OF BITS

Bits are expensive tools and like any other piece of equipment require proper handling. When making up bits to the
drill string so-called "bit breakers" (specially designed steel plates) must be used to avoid damaging the teeth
and/or bearings on roller cone bits, and the inserts and diamonds on PDC and diamond bits. When lowering the bit
into the hole care must be taken to avoid hitting formation ledges. If reaming is necessary this should be done,
where possible, with moderate rotary and very light weight on the bit to avoid damage to the bearings on roller
cone bits and cutting an "O" ring on the bottom outer edge of diamond bits. PDC bits will suffer broken cutters on
the bottom outer edge if used for reaming with too great a weight. When on bottom it is imperative to "drill-in" the
bit with moderate rotary speeds and light weight. The bit, ANY bit, should be given the chance to cut its own profile
in the formation to ensure an even distribution of the load over the whole bit face. It is normal practice to drill up
to a few feet (depending on the hardness of the formation) with very light weight and moderate rotary speed and
then to gradually increase weight and rotary speed to what is required to achieve a proper penetration rate. This
procedure is called "breaking in the bit".

1.1.7 OTHER EQUIPMENT

Two pieces of equipment which are closely related to drilling bits, and to each other, are hole openers and
underreamers.

Both of these pieces of equipment are used to drill a larger hole where a smaller hole already exists. The difference
is that a hole opener has fixed cutting arms so that, like a normal bit, it can only pass through a string of casing
with a larger ID than the size of hole it will drill. An under-reamer, as suggested by the name, is used to drill below
a string of casing which has a smaller ID than the size of hole to be drilled. These are covered in Topic 1.10.

 Roller cone bits

1.2.1 INTRODUCTION

Roller cone drilling bits consist of three major components: the teeth or cutters, the bearings, and the bit body, as
shown in Figure 4.1.02. The cones are mounted with bearings on pins which are an integral part of the bit body.
Radial loads are absorbed primarily by the large outer bearing element near the cone's outer end, either a roller or
a journal bearing, and the plain bearing in the cone nose. The ball bearings serve to retain the cones and in some
instances to absorb both radial and thrust loads. Additional outward thrust bearing capacity is provided by a plain
bearing surface at the end of the bearing pin and at the shoulder between the ball race and nose bearing. The
cutting elements are circumferential rows of teeth extending from each cone and meshing between rows of teeth
on the adjacent cones.
Figure 4.1.02 : The elements of the tri-cone rock bit

Two distinct types of cutting elements and two distinct types of bearings are currently being used in rolling cone
bits. The cutting elements are either steel teeth which are machined from basic cone material (milled tooth bits) or
sintered tungsten carbide teeth which are pressed into holes drilled in the cone surfaces (insert bits). The bearings
are either ball-and-roller or ball-and-journal. Although there are many differences in bits which use various
combinations of the foregoing, basic design considerations are similar for all.

The relative space allotted to the various components of the bit depends on the type of formation to be drilled. For
instance, soft formation bits which generally require light weights have smaller bearings, thinner cone shells, and
thinner bit leg sections than hard formation bits. This allows more space for long toothed cutting elements. Hard
formation bits, which must be run under heavy weights, have stubbier cutting elements, larger bearings, and
sturdier bodies.

Bits can be designed with two to multiple cones. Three cone (Tri-cone) bits are by far the most common and you
are unlikely to see other types of roller cone bits within ADTI operations. The latter are however described here for
the sake of completeness

TWO-CONE BITS

Bits with two cones are available, for soft formations only.

Individual parts of the two-cone bit can be made larger and stronger than those of a bit with three cones but the
loading per cone is higher, so that in practice they are less durable than tri-cone bits in hard formations.
Two-cone bit are less effective in maintaining a gauge hole due to their geometry. Because they have less gauge
area, two-cone bits deflect easily in soft formations and are used for special directional drilling jobs. There exists
also an asymmetric bit with two cones and a large nozzle, called a "badger bit", shown in Figure 4.1.01, which is a
type of bit specially designed for jet deflection during directional drilling in soft formations. In ADTI operations it is
more common to use a normal three cone jet bit fitted with two small jets and one large one to get the badger bit
effect.

Figure 4.1.01 : A badger bit

TRI-CONE BITS

Bits with three cones are manufactured for all formations and are available with milled teeth or tungsten carbide
inserts. The tri-cone design allows a well balanced cutting structure with even distribution of weight and shock
loads. However it requires efficient use of the available space for the parts to be made large enough to withstand
the loads applied. The components are shown in Figure 4.1.02 above.

MULTIPLE CONE BITS

These were used mostly in coring bits where the core hole in the centre of the bit dictates the use of smaller cones
than in normal drilling bits. Core bits are often called core heads and older designs have used eight or more cones.
However in modern coring operations the multiple-cone core head has almost entirely been replaced by the various
types of diamond core head.

1.2.2 BIT DESIGN

The detailed design of a bit for a particular type of service involves the consideration of many factors, of which the
principal ones are:

 The alignment, or offset, and shape of cones in relation to the required cutting action. This influences the
twisting/gouging/scraping or crushing effect.
 The shape of the teeth in relation to their spacing, meshing, hard facing requirements, and materials
(steel teeth or tungsten carbide inserts).
 The bearings; their durability, sealing and lubrication, and whether they are roller or friction bearings.
 The fluid passages or water courses which can be conventional holes or special jet nozzles such as
extended nozzles.

The strength and durability of the bit is controlled by the size of its individual parts and its configuration. One of
the objectives of the drilling bit design is to provide teeth and bearings which will have similar endurance under the
drilling conditions specified for the bit.

The factors listed above will be discussed one by one

CONES AND CUTTING ACTION

The geometry of each cutter cone is not in fact a simple cone but includes a heel cone and inner cone as shown in
Figure 4.1.03.

Figure 4.1.03 : Cone design

To understand why a three-cone drilling bit drills so effectively, it is necessary to study the motion of the teeth at
the bottom of the hole. A cone taken out of the bit and placed upon the table can take two positions. As shown in
Figure 4.1.04 it can turn around point A when it stands on the heel cone or it can turn around point B when it
stands on the inner cone. In both cases the cone on which it is standing makes a pure rolling motion.

Figure 4.1.04 : Cutter rolling on the inner and heel cones

In a pure rolling motion a point on the circumference (a tooth) impacts the bottom at one point and in a drilling bit
this gives a chipping or crushing action (Figure 4.1.05).

 
Figure 4.1.05 : Crushing/chipping motion

When the cone is placed on a pin and turned around, the points on the inner cone are not allowed to roll in a small
diameter ring nor can the points on the heel cone roll in a large diameter ring. The bit cones are forced to turn in
the circle of the hole diameter. This results in the teeth on the inner cone developing a scraping movement caused
by their relatively low rotating speed compared with their forward movement (Figure 4.1.06) and the teeth on the
heel cone developing a gouging movement caused by their relatively higher rotational speed compared with their
forward movement (Figure 4.1.07).

Figure 4.1.06 : Scraping motion

Figure 4.1.07 : Gouging motion

The skidding action of the teeth, to increase the penetration rate in soft formation, can be improved by offsetting
the cone centre lines from the centre of bit rotation (Figure 4.1.08).

Figure 4.1.08 : Cone offset

Both gouging and scraping have a very destructive effect on the formation but are also hard on the teeth of the bit,
thus the geometry of the cones of a particular type of bit is dependent on the hardness and abrasiveness of the
formation for which it is designed.

Harder formations are most efficiently removed by a chipping/crushing action, and for these the geometry is
adjusted to minimise the scraping/ twisting action of the teeth on bottom.

These cutting mechanisms are all relatively inefficient and require a high weight-on-bit to deliver enough energy to
the formation to achieve fast penetration. Such high drilling weights can cause premature bit failure, deviation
problems and drill string wear.

Cone numbering

By convention the three cones of a tri-cone bit are numbered. One reason for this is convenience in reporting the
condition of dull bits - see Appendix 3.

While looking at the cutters, with the bit standing on its pin connection, cone #1 is the one that extends the
furthest towards the centre of the hole. In soft formation bits it has a "spear point". The other two cones are
numbered by going round in a clockwise direction.

CUTTERS

Design considerations

In general formations can be classified from soft to hard and each class is subdivided into more types. Table 4.1.1
shows the cutter design features and the cutting action required for optimum drilling performance in these types of
formation. This is generally applicable to both milled tooth and insert bits. Note that the column headed "type"
gives the IADC classification code for the formation type, as explained in Appendix 2.

The cutters of milled tooth bits are designed suitably:

 spaced: to allow the rock chips to be removed and to avoid balling-up, i.e. formation packing-between
them.
 long: to allow maximum penetration of the formation for the removal of large cuttings.
 slim: to maintain reasonable aggression, i.e. small force required for large chip removal, even after the
teeth have been worn down to perhaps half their original length.
 wear resistant: to withstand abrasion by drilled formation.
 strong (against fatigue and impact): to accept cyclic compressive and shock loads.

Therefore, for soft formations, milled teeth are:

 widely spaced.
 long, and slim.
 generously provided with hard facing.
 not designed for high bit weights.
 tough and able to absorb shock loads.

These characteristics are progressively modified, until the teeth are suitable for hard formations. They will then be:

 sufficient in number to disperse the individual tooth load, but few enough that even after wear the unit
load will still crush the formation.
 short and broad based, to withstand the compressive loads needed to produce the chips, with minimal
twisting/scraping action which would destroy the teeth rather than the rock.
 usually without hard facing material on the teeth, as the latter are made of hard brittle material compared
to normal steel teeth and are designed to crush rather than scrape or gouge (see the next section). There
will usually be gauge protection for the outer face of the teeth.
Figure 4.1.09 is an illustration of the variation in the design of milled tooth bits. There are now few milled teeth bits
available for hard to very hard formation types as this is the application in which insert bits excel.

Figure 4.1.09 : A selection of milled-tooth bits

T-gauge teeth

The outer row of steel teeth on a bit designed for abrasive (but not necessarily hard) formations often have a broad
but relatively thin strip along the gauge surface in order to give more gauge protection. Because of the shape of
the tip of the tooth the latter are said to have a T-gauge. This feature can be seen in Figure 4.1.09c.

Inserts

Inserts are studs made of sintered tungsten carbide and pressed into holes machined in the steel alloy cones. The
principles given in Table 4.1.1 are applicable to insert bits as well as to milled tooth bits, but the absolute
dimensions of inserts are less than those of steel teeth. They have various end shapes depending on the formation
for which they are designed (Figure 4.1.10).

Figure 4.1.10 : Tungsten carbide inserts

The tungsten carbide tooth bit was initially developed to drill extremely hard and abrasive formations such as
cherts and quartzites that had been very costly to drill due to the relatively short life of steel tooth bits. However,
in view of their durability, inserts were soon introduced for use in softer formations by employing various conical
and chisel shapes that are longer, more widely spaced, and can endure twisting/scraping/gouging action. There are
now insert bits to drill virtually every formation economically. A selection is shown in Figure 4.1.11.

 
a) For soft formations b) For medium formations c) For very hard formations

Figure 4.1.11 : A selection of insert bits

Insert bits have a higher initial cost than equivalent milled-tooth sealed bearing bits - see Table 4.1.2 overleaf -
and drill more slowly than a brand new milled tooth bit. However they have a much longer life in the hole and
maintain their penetration rate for a higher proportion of it. Whereas a 121/4" milled-tooth bit for example would
last 25 - 40 hours including the connection time, bit runs of 100 to 150 hours are normal for insert tooth bits of the
same size. This gives them the advantage in deep drilling when long intervals need to be drilled and when round
trips are long, or when rig costs are particularly high.

In recent years tungsten carbide insert bits have been superseded by PDC bits (see Topic 6) for many formation
types, but they are still the preferred choice for the hard abrasive formations for which they were originally
designed, in which a PDC bit would quickly be ruined.

Hard facing

Steel teeth which are gouging or scraping will wear on the side on which the cutting is created as shown in Figure
4.1.12. They can however be protected by hard facing. This hard facing is applied to the front of teeth which have
a scraping action and on the back of teeth which develop a gouging movement. The teeth of hard formation bits
have little hard facing because such teeth mainly chip or crush the formation.
Figure 4.1.12 : Hard facing on teeth

As well as having a cutting action on the bottom of the hole, the cones of a tri-cone bit are in contact with the
cylindrical wall of the borehole with a purely sliding motion. This causes wear which reduces the diameter of the bit
and causes it to drill a hole with a gradually decreasing diameter. Wear is also caused in this area by the cuttings
which are passing on their way up the annulus. Hard facing is also used to provide protection to this face of the
cone. For the same reasons hard facing is also used on the gauge surfaces of the bit body.

The amount of wear is a related to the abrasiveness of the formation and does not depend on its hardness, and
thus gauge protection may be required on bits intended for formations of different hardnesses.

Note that the gauge surfaces of both cones and the bit body can be given resistance to abrasion by either applying
hard facing or by using tungsten carbide inserts. The latter can be seen in some of the bits shown in Figures 4.1.09
and 4.1.11.

BEARINGS

Bearing design is usually a compromise between the dimensions of the various parts to produce satisfactory service
under severe conditions.

Roller bearings

Ball and roller bearings were the first type of bearings used. They have a relatively short life when used with high
bit weights, which means that bits using them tend to be replaced because of bearing wear while the teeth could
still continue drilling. This becomes increasingly disadvantageous as the hole gets deeper and tripping times
increase. For this reason they have been superseded for deeper applications by journal bearing bits (see below)
which are initially more expensive but which have a longer service life. Roller bearing bits are still used for shallow
sections and other applications where they can be expected to last as long as the cutting structure.

A typical ball and roller bearing consists of:

 rollers, to take up radial loads.

 balls, to take inward thrust, and retain the cone on its pin.
 plain thrust bearing at the shoulder to take outward thrust.
 plain bearing at the nose, to take radial loads.
 plain thrust bearing at the inner pin end ("nose button"), to take outward thrust.
Standard bearings are lubricated by grease placed in the bearing during assembly. If there is no seal drilling fluid,
which is a poor lubricant and often very abrasive, can enter the bearings. Sealed bearings were therefore
developed, together with a pressure equalising system. Sealed bearing bits have a lubrication and compensator
system in each bit leg consisting of a grease reservoir, double sealed thick rubber diaphragm, a connecting
passage and seal.This is shown in Figure 4.1.13a. The pressure compensating system equalises the pressure in the
bearing with the pressure of the drilling fluid. This prevents the seal of the bearing from being subjected to a
differential pressure.

Note that a used sealed-bearing bit that is being saved for re-use should never be stored in diesel oil as that
damages the bearing seals and will lead to premature failure.

Journal bearings

A major improvement in bearing performance was due to the development of journal bearings, in which the roller
bearings are replaced by a plain alloy bushing which carries most of the radial loads (see Figure 4.1.13b). These
journal bearings not only reduce unit stress loads for the same WOB (or allow a higher WOB for the same stress
load) but, due to the special metals (e.g. silver alloys) which give added wear resistance, they also have increased
bearing life to match the long downhole life of the insert teeth. There is no point in having long bearing life if the
bit has to be pulled for worn teeth, thus journal bearings are not usually used on milled tooth bits.

a) Roller bearings

b) Journal bearings
Figure 4.1.13 : Details of the two types of sealed bearings

FLUID PASSAGES

There are three types of fluid passages: conventional holes, regular jets and extended nozzles.

Conventional holes

One or more holes in the bit body direct the circulating fluid on to the cutters to clean them. This type of passage is
fixed; it does not contribute to bottom-hole cleaning but aids in preventing bit balling. In modern operations this
type has little application.

Jets

Instead of holes drilled in the bit body one or more nozzle bosses can be machined in their place. These bosses
accept nozzles which allow the jet sizes to be varied. The higher fluid velocity normally obtained in doing this will
clean the cutters better but could also erode the cones.

Much better performance is obtained when the nozzles are located between the roller cones and direct the fluid
stream at the bottom of the hole. The high fluid velocity then greatly improves bit performance by removing the
cuttings from the bottom of the hole to prevent regrinding, and the teeth of the bit are cleaned by the turbulence
of the circulating fluid below the bit.

Replaceable jets or nozzles are available in a range of sizes from 7/32" to 28/32" increasing in steps of 1/32". The
nozzle size used is normally expressed in units of 1/32" i.e. nozzle size 16 means that the ID = 16/32". Where SI
units are in use the nozzle size is quoted in millimetres. The choice of nozzle size is made according to
requirements for hydraulic horsepower at the bit and jet impact force. These subjects are discussed in Section 2
Part 2 Topic 2.5.

The nozzles are held in place by a clip or a threaded lock ring (Figure 4.1.14). A nail is sometimes used in older
designs. The pressure seal between body and nozzle is an O-ring. When installing nozzles in a bit it is very
important to ensure that this O-ring is not damaged because that could lead to a washout and ultimately to losing
the nozzle.

Figure 4.1.14 : Jet nozzles

Extended nozzles

Extended nozzles are used to improve the effectiveness of the jetting action on the bottom of the hole while
drilling. The jets are installed in extension tubes, welded in the conventional nozzle holes. See Figure 4.1.15.

 
Figure 4.1.15 : An extended nozzle bit

The extensions are exposed and vulnerable, and they should therefore not be used for drilling on junk (e.g. cement
floats) or fractured formations, because large chunks could get jammed between rollers and nozzle tubes. For the
same reason it is also necessary to:

 take extra care when reaming is necessary.

 have a near bit stabiliser installed to prevent bit wobble.
 use a special bit breaker.

 
1.2.3 DRILLING PARAMETERS

Weight on bit and rate of penetration

In most formations the ratio between penetration rate (ROP) and weight on bit (WOB) increases approximately
linearly in soft formations, while in brittle formations the relation is initially almost quadratic, provided bottom-hole
cleaning is perfect. See Figure 4.1.16. In soft formations a penetration rate limit is reached by the teeth having
penetrated the formation along their full length; increasing the WOB further will obviously not cause an increase in
penetration rate. The ratio WOB/ROP is always influenced by poor cleaning.

Figure 4.1.16 : Weight on bit vs. Penetration rate

There is however a certain, often small, tooth load required to achieve any penetration at all. This is called the
"threshold pressure" and is required to overcome the compressive strength of the rock. As teeth become worn, the
weight applied will probably need to be increased to maintain an economical penetration rate.

Another factor is the "dwell time". This is the time taken by one tooth to develop the threshold pressure and
penetrate the formation sufficiently to generate cuttings efficiently.

A practical limit on WOB is set by the strength of the bit bearings. The manufacturer's recommended maximum
weight on bit should not be exceeded. The latter is often expressed as so many lbs (Newtons) per inch (mm) of bit
diameter.

Weight on bit and rotary speed

In soft plastic formations the WOB is restricted by the tendency to "ball up" the bit. This effect can partly be offset
with increased rotation rates (rpm). Teeth breaking is not usually serious in such soft formations, although at
excessive rotary speeds the cutters can be adversely affected by abrasion.

In hard formations higher weights can be used to exceed the rock compressive strength without the possibility of
balling-up. However, high rpm generates shock loads which may break teeth, increase abrasive wear and reduce
bearing life.

A guide to the selection of the correct combination of WOB and rpm is given by bit manufacturers. An example is
shown in Table 4.1.3.
Example: Drilling a medium hard formation with an insert bit, using WOB of 350 N per mm bit diameter (2000 lbs
per in bit diameter), 70 rpm can be used. If WOB is increased to 1050 N/mm (6000 lbs/in) it is recommended that
the rpm is reduced to 40.

Rotary speed and rate of penetration

Figure 4.1.17 shows typical relations between penetration rate and rotary rpm for soft and hard formations.

Figure 4.1.17 : Rotary speed vs. Penetration rate

The relation is linear for soft formations and also at low rpm for hard formations. However, each tooth needs a
finite time to penetrate fully into the harder formation, increasing the rpm will therefore reduce the available time
and no longer contribute proportionally to the ROP.

BIT HYDRAULIC POWER

The aim of optimising the hydraulic power at the bit and the jet impact force on bottom is to remove cuttings
before they are redrilled by the next tooth.

Insufficient cleaning action can have two results:

 Bit balling: Particles of formation clog against the teeth of the bit and prevent optimum penetration of
the teeth into the formation. Bit balling is mostly found in formations where scraping and gouging are
dominant i.e. in soft sticky formations.
 Bottom balling: A very fine powder, called rock flour, produced in the drilling process clogs on the
bottom of the hole, again preventing optimum penetration of the teeth into the formation. Bottom balling
is mostly found in formations where crushing is dominant (e.g. light limestones).

On a given rig and in a specific hole size, pump pressure, input power and annular velocity all have their limits. But
there are ways to make more efficient use of the available hydraulic power. For example jet nozzles are normally
placed 125 - 175 mm (5" - 7") above the bottom of the hole and the jet stream loses 50 - 70% of its velocity
before hitting bottom. Using extended nozzles will bring the fluid stream closer to bottom, improving the efficiency
and increasing the impact. This makes extended nozzles very effective when bottom balling occurs.

Bit balling, which often develops in the centre portion of the bigger bits, can be reduced by the use of a fourth
nozzle in the centre. Cleaning becomes more effective, using the same HHP at the bit.
DRILLING FLUID PROPERTIES

The properties of the circulating fluid are of great importance for the penetration rate. The principal factors are:
density, solid contents and fluid loss.

There is a certain fluid pressure within the pores of the formation referred to as the pore pressure P o.

At the bottom of the hole the drilling fluid column also exerts a pressure referred to as bottom hole pressure (or
BHP). This BHP is kept higher than the pressure P o to prevent the fluid in the formation from invading the hole and
causing a kick.

As BHP is greater than Po a flow of liquid from the hole into the formation takes place (Figure 4.1.18). If the fluid in
the hole is a conventional drilling fluid, the solid particles in it will quickly block off further entry of liquid into the
formation and a filter cake plus a filtrate invaded zone at a pressure approximating to P o is formed.

Figure 4.1.18 : Filtrate invasion

This also happens at the bottom of the hole where a noticeable cake is formed in the short time interval between
two successive tooth actions. The chip is now held down by the difference between BHP and P o. This pressure
difference does not depend on a movement of either the drilling fluid or the chip and is called the static chip hold
down pressure (Figure 4.1.19).

Figure 4.1.19 : Static chip hold-down

Due to the chip hold down force, removal of the chips becomes difficult; the teeth penetrate less deeply into new
formation, and regrinding will result. The greater the difference, the greater the static chip hold down pressure.
The density of the drilling fluid is thus a very important factor for the penetration rate and should be kept at the
minimum value consistent with well control.

The filter cake properties are of significant interest because a drilling fluid with good filter cake properties having a
high clay content reduces the infiltration of filtrate into the formation and contributes to the static chip hold down.

During drilling both density and clay content tend to increase as solids from the formation are taken up in the
drilling fluid and if this process is not kept under close control, penetration rates will slow down noticeably.

In both permeable and impermeable formations there is an additional chip hold down effect. As the tooth
penetrates, cracks are formed which must be filled with drilling fluid from the hole before the pressures all around
the chip are equal. As the drilling fluid rushes in to fill the volume of the cracks, there is a pressure drop along the
path of the flow. This pressure drop results in a pressure differential which contributes to the chip hold down effect
(Figure 4.1.20). It is called the dynamic chip hold down and it increases with drilling fluid viscosity and higher tooth
penetration speeds. Again the result is less chip removal and increased bottom balling.

Figure 4.1.20 : Dynamic chip hold-down

From the point of view of hole stability, low fluid loss and good filter cake forming ability are desirable properties.
However, if only penetration rate is considered, clean water is the best circulating medium. A compromise is always
required.

Chip hold down forces are overcome by good bottom hole turbulence as induced by jet velocities.

To summarise: drilling fluid conditions for good penetration should be:

 minimum overbalance (BHP only slightly larger than P o)

 low viscosity.
 low solid contents.
 high water loss (this however increases the chance of wall sticking further up the hole!).

DRILL-OFF TESTS

The best combination of WOB and rpm can be found by the driller if he is also alert to the changes at the bottom of
the hole. Information from nearby wells will be helpful, but can never provide all the information required. In
practice drill-off tests are used to establish the optimum combination of WOB and rotary speed to maximise
penetration rate in the formation actually being drilled. The procedure is as follows:

 Maintain a constant pump rate.

 Apply a relatively high weight on bit and secure the brake.
 Note the time elapsed for a predetermined WOB drop e.g. a decrease from 225 to 135 kN (50,000 to
30,000 lbs).
 Repeat the test several times (e.g. 5 times) with different rotary speeds.
  The shortest time required to drill off the predetermined drop in WOB indicates the optimal weight on bit
and rotary rpm combination.

Similarly, drill-off tests can be made varying the pump speed while keeping the rotary speed constant.

In order to maintain optimum progress drill-off tests have to be conducted as often as the drilling characteristics of
formations change.

In some areas drill-off tests could cause the drilling assembly to kick-off away from the required bore-hole
inclination.

Table 4.1.4 shows an example of drill-off tests with four steps of weight on bit decrease and three different rotary
speeds. The conclusions are that there are two combinations with an average of only 28 seconds (the best drilling
progress). If the WOB during drilling is maintained at between 225 and 202.5 kN then the rotary speed should be
90 rpm. The WOB could be lower, maintained between 202.5 and 180 kN, but then the rotary speed must be
higher (100 rpm). Other combinations will result in reduced performance.

1.2.4 PROBLEMS AND REMEDIES

When a bit is pulled its condition gives a good indication of what has been happening down hole. This in turn tells
the driller whether any changes

should or could be made to improve the efficiency of the operation. Table 4.1.5 lists a selection of possible bit
conditions, with their causes and possible remedies.
Diamonds

1.3.1 NATURAL DIAMONDS

Diamond is a metamorph of carbon. Natural diamonds are formed when magma solidifies and carbon crystallises at
high temperatures and pressures.

At such elevated pressures and temperatures, diamond is the stable form of carbon but at ambient pressures and
temperatures, graphite is the stable form. In theory, at least, diamond should not continue to exist at ambient
conditions. In practice, if diamond is produced and, immediately after formation, rapidly cooled, the diamond
structure will be retained.

If high amounts of energy are applied to diamond, a much quicker change to graphite takes place. Consequently,
diamond will, if heated to approximately 1300°C at ambient pressure, revert immediately to graphite. In addition,
diamond will burn if heated to about 800°C in the presence of oxygen.

Diamond is the hardest natural material. It has a density of 3,520 kg/m3 (s.g. 3.52) and in industrial applications
is selected for its high hardness, high compressive strength, high thermal conductivity and high heat capacity (see
Table 4.1.6).

The most common commercial unit of diamond weight is the carat (1 carat = 200 milligram). To specify size in
industrial applications the number of stones per carat is normally used. The natural diamonds set in oil-field bits
range from 15 diamonds per carat (ca.2 mm diameter per stone) to 5 diamonds per carat (ca.3 mm diameter per
stone). In exceptional cases larger stones of up to 1 per carat are used.

1.3.2 SYNTHETIC DIAMONDS

MONOCRYSTALLINE DIAMOND

The process of diamond production involves stacking thin, circular layers alternately of carbon and a
catalyst/solvent - usually cobalt and/or nickel and/or iron - in a small container, made from a refractory metal and
referred to as a "can" which is then loaded into a press. The pressure is increased to 1,500,000 psi followed by
resistive heating to approximately 1,500°C . This is maintained for a set time then the system is cooled and finally
depressurised. During maximum pressure and temperature, the molten catalyst/solvent dissolves the graphite and
then deposits diamond crystals in its place. The size and quality of the diamond grit produced is largely determined
by the process time and other operating parameters. It is recovered from the solidified metallic matrix by a
combination of physical and chemical processing.

There are two major companies producing synthetic diamonds. One is GE the other is de Beers.

POLYCRYSTALLINE DIAMOND

Synthetic diamond crystals, like most natural diamonds, are monocrystalline; that is, each diamond itself is only
one crystal, however large. Due to the molecular structure of the diamond crystal, it can be cleaved if an impact is
applied in the correct orientation. These cleavage planes are beneficial in gemstone applications since they allow
the diamond to be cut into multifaceted shapes but can be catastrophic if the diamond is being used in a cutting
tool. Polycrystalline diamond, a conglomeration of tiny monocrystalline diamond particles bonded to each other,
has no such cleavage plane on a macro scale, although each of the individual crystal constituents does. Because of
this, polycrystalline diamond has greater resistance to impact than natural diamond.

Polycrystalline diamond compact manufacture

Polycrystalline Diamond Compact (PDC) components consist of a thin (nominally 1 mm) layer of polycrystalline
diamond integrally bonded to a cemented tungsten carbide support or substrate. The complete structure is referred
to as a compact.

Polycrystalline diamond compacts are manufactured using the same type of press used to make diamond grit, as
described in the previous paragraph. In one method diamond grit, with a predetermined particle size, is placed in a
refractory metal can, usually made from zirconium or molybdenum. The shape of the can determines the final
shape of the compact. A layer of tungsten carbide cemented with cobalt is then placed on top of the diamond grit,
the bottom of the can is put in place and the can is then mechanically sealed.

The can is heated and pressurised to the same conditions used for the production of the grit. Diamond-to-diamond
bonding occurs as cobalt from the tungsten carbide support migrates into the diamond grit and catalyses the
bonding reaction. The cobalt also forms a bond with the tungsten carbide substrate resulting in one integral
component.

Impact and abrasion resistance

The impact and abrasion resistant characteristics of polycrystalline diamond are largely dependent upon the
diamond grain size and the amount of intercrystalline bonding. A larger diamond grain size makes the diamond
compact more abrasion resistant but lowers impact resistance. A smaller diamond grain size increases impact
resistance but reduces abrasion resistance. Modifying the degree of bonding and residual catalyst content provides
optimum performance within this larger constraint.

In addition to the higher natural resistance to impact, support for the thin polycrystalline disc in PDC cutters is
provided by the tougher tungsten carbide backing. However, cutter chipping can still occur due to the severe
impact loads on the PDC during use. The PDC is most vulnerable when new, because all the cutting and weight on
bit forces are carried by a small contact area, that being the initial cutting tip of the unworn diamond first
presented to the formation. As the cutter wears, these forces are spread along the worn edge, resulting in less
pressure and subsequently reduced risk of damage.

To counter any potential premature damage to the diamond, the cutting edge of the PDC is sometimes given a
peripheral bevel which, although only slight, reduces the stress concentrations at the diamond edge. As the cutter
wears, the bevel vanishes, but by then the risk of early failure has passed. This technique has been patented by
Security-DBS, but is widely licenced to other bit manufacturers.

Thermal stability of PDC

The synthetic polycrystalline diamond material used in the compacts has, however, a temperature limitation due to
the catalyst used during both the crystal growth and the bonding onto the substrate. In these processes molecules
of the metallic material become trapped within the diamond microstructure. The metals have a higher coefficient of
thermal expansion than the diamond, thus, as the temperature of the composite rises in service, they expand
differentially. Up to about 700° C the effect is that the diamond compact's wear rate increases with temperature,
but by the time it reaches approximately 750° C, the forces are sufficient to degrade the diamond to diamond
bonding, and the diamond layer will deteriorate. This process occurs extremely rapidly once initiated and it is,
therefore, essential that the PDC be maintained below the critical threshold temperature to avoid the risk of
catastrophic failure.

THERMALLY STABLE POLYCRYSTALLINE (TSP) DIAMOND

Due to the inherent thermal limitations of PDC, much work has been done by diamond manufacturers to produce a
synthetic polycrystalline diamond which exhibits thermal properties closer to those of natural diamond. Two types
of product are currently available.
Leached diamond

Following the the press cycle in which synthetic monocrystalline diamond grit is produced, the grit is loaded as a
thicker layer into cans similar to the ones used for making PDCs. A second cycle of pressure and temperature, in
which additional cobalt catalyst is added to the monocrystals, produces polycrystalline diamond either as a thick
disc or in the shape of the individual cutting elements. This is then treated with acid which leaches out all but
residual traces of the cobalt, resulting in a product which is thermally stable to a temperature of 1150°C (although
it still begins to oxidise at 800°C in the presence of oxygen). This process has been patented by GE.

If the polycrystalline diamond was produced as a thick disc the leached disc is then cut up into the desired shapes
and sizes, depending on the proposed application.

Due to the lack of cobalt in the structure, this form of diamond cannot easily be directly bonded to a support
material . The diamond is not readily "wettable"; that is, a liquid such as brazing alloy tends to "bead-up" and roll
off rather than adhering to the surface. Because of this TSP diamonds are most commonly held in place
mechanically in the drilling bits, in the same way as natural diamonds the difference being that they are much
bigger and can be set in the matrix with a specific orientation. An alternative method is to apply a special coating
to the diamond to provide a measure of wettability and enabling brazing to be used.

Silicon carbide binder

Because the process of leaching the cobalt is subject to a patent by GE the other major manufacturer, de Beers,
has developed an alternative process using silicon as an additive, instead of cobalt, in the manufacture of TSP
diamonds. Although not particularly effective as a catalyst, the silicon reacts with the diamond grit during the press
cycle to form silicon carbide, which acts as a binder phase for the diamond particles. Since silicon carbide has a
considerably lower coefficient of thermal expansion than cobalt, this diamond is thermally stable to a temperature
of more than 1150°C. This form of diamond has the same disadvantage as the leached material in that it is not
readily wettable and is difficult to bind to a substrate.

Diamond bits - general

As mentioned in Topic 1, different types of artificial diamond are now available and are being used in drilling bits
and core heads. This Topic covers the features which are common to all diamond bits. The specific characteristics
of the various types of bit (natural diamond, PDC, TSP and impregnated) are described in the following Topics.

1.4.1 APPLICATION OF DIAMOND BITS

Although diamond bits are up to ten times more expensive than roller bits, the absence of bearings and other
moving parts in a diamond bit can in suitable applications provide a bit life several times that of the conventional
roller cone bits. This prolongation of the bit life increases the percentage of time on bottom and thus reduces the
tripping time and the average cost per unit depth. The application of diamond bits is in formations in which the
latter can be reduced to less than the average cost per unit depth of a roller cone bit.

Diamond bits do, however, have some disadvantages. The stones are sensitive to shock loads, which cause them
to split, the bits need high rotation speeds and the cutting elements require good cooling to prevent overheating
and "burning" of the diamonds. Natural diamonds tend to degrade at temperatures of 800-850°C, which is lower
than might be expected because of the inclusions which they contain. Some types of artificial diamonds have a
higher temperature limit as they can be manufactured without inclusions.

1.4.2 NOMENCLATURE

The nomenclature applicable to diamond bits is given in Figure 4.1.21.

 
1.4.3 BIT DESIGN

The design of diamond bits covers five major areas:

 Bit body
 Bit profile
 Cutter properties
 Gauge protection
 Hydraulics

Figure 4.1.21 : Diamond bit nomenclature

THE BIT BODY

The bit body is required to provide the following functions throughout the life of the bit:

 Retain and provide support to both the cutters and, if present, the nozzles,
 Maintain its strength under downhole operating conditions,
 Direct and control the flow of drilling fluid as it cleans and cools the cutters
 Provide attachment to the drill string.

Body material

Diamond bits fall into two broad categories according to the type of body material. These are steel body bits and
tungsten carbide matrix bits. Each has distinctive characteristics and advantages, as well as limitations which must
be considered before a bit is designed or before a bit is selected for a specific application.

The main factors influencing the choice of material are:

 Erosion resistance - tungsten carbide alloy has a very high resistance to erosion which makes high
pressure drops across the bit face and higher solids content in the drilling fluid possible with matrix bodied
bits. Although steel is less erosion resistant than matrix this shortcoming can be reduced with careful
design of the body geometry and use of hardfacing.
 Strength - A tungsten carbide matrix is not as strong in tension as steel, and is not so well able to
withstand impact loads. Steel bits can be designed to incorporate high, relatively thin blades which can be
useful, especially in water based drilling fluid, soft formation applications. Such designs are generally not
feasible if the bit is manufactured from matrix because of the risk of blade breakage if a harder stringer is
encountered.
 Bit Length - A matrix bit is inherently longer than an equivalent steel bit because of the pin connection
which has to be welded on. In certain situations, such as directional drilling, the bit must be of minimal
length. In these circumstances a matrix bit may be perceived as less desirable than a shorter steel bit.
 Precision - the precision with which the cutter pockets, nozzle threads, "O" ring housings and gauge
diameter can be machined into the steel body of a PDC bit is very high. This allows the cutters to be
shrink fitted into the body, a process not possible with matrix designs.
 Bit Size - In general, the strength advantages for steel bits become more important in larger sizes.
Additionally, the manufacture of matrix bodies becomes increasingly difficult as diameter increases.
 Design flexibility - The method of construction of matrix bodied bits makes a greater range of shapes
possible.

Because of the nature of the diamond cutters, steel bodies can only be used for PDC bits. Tungsten carbide matrix
bodies are always used for natural diamond bits, TSP diamond bits and impregnated diamond bits; they can also
be used for PDC bits. Similarly diamonds can only be used for gauge protection on matrix bodied bits; steel bodied
bits use tungsten carbide inserts.

Matrix bodied bit fabrication

Matrix bodied bits and core heads, of which examples are shown in Figure 4.1.22, are made in one piece,
consisting of three main elements:

 the shank
 a steel core
 a matrix, made of powdered tungsten carbide mixed with a powdered alloy, in which the cutters are
embedded.

 
Figure 4.1.22 : Matrix-bodied bit and core-head

The manufacturing process is as follows:

 A concave carbon mold is machined from a graphite cylinder to give the shape (or profile) of the bit.
 Provision is made for natural diamonds or TSP diamonds by making appropriately shaped indentations on
the inside surface of the mold in a pre-determined pattern. For PDC bits graphite formers are used to
create the pockets into which the support posts are later fitted.
 Fluid courses are modelled in sand, carbon or clay and placed in the mold, their purpose being to provide
suitable channels in the finished bit to distribute the drilling fluid evenly over the face of the bit, cooling
the diamonds and carrying the cuttings away.
 The inside of the mold is then coated with a rubber-based glue and the correct size and quality diamonds
are individually set into their respective machined indentations.
 A steel blank is centred in the finished mold to be bonded to the crown, formed from tungsten carbide and
copper-nickel binder powders which are poured into place between the carbon mold and the steel blank.
 The assembly is placed in an electric furnace where the binder metal melts and infiltrates by capillary flow
into the inter-granular spaces between the tungsten carbide particles, and the whole is fused together
 After a controlled cooling cycle, the matrix materials solidify permitting the crown to be removed from the
carbon mold.
 A pre-machined API tool joint connection (the shank) is welded to the steel blank. (The pin connection
cannot be machined onto the blank before bonding it to the crown because, during the infiltration process,
the blank becomes heated to the point where its properties will no longer provide adequate strength for
the connection).

Steel bodied bit fabrication

Steel is received either as forgings or bar stock, which is cut to the required length. The steel is then turned on a
computer controlled lathe to produce the body profile. At this stage the API pin connection is machined directly
onto the body and the main fluid bore drilled. Computer controlled mills machine the body geometry, including
waterways, blades, cutter pockets, gauge insert sockets, nozzles holes and threads.

 
Figure 4.1.23 : A steel bodied bit, with hard-facing

After dressing the machined body, the gauge inserts are pressed into position and the PDC cutters are fitted into
their pockets. Next, the bit OD is ground to gauge. Lastly the bit is fitted with nozzles, which can be replaced at the
rig site should the hydraulics program require it.

BI-CENTRIC AND ECCENTRIC BITS

In certain lithologies there is a risk of the formation swelling and narrowing the hole. For example, some shales
and claystones may "slough" into the well bore and salts may "creep." If the bit is drilling through such rock and
this happens up-hole, it becomes impossible to pull the bit out of the well. Alternatively, if it occurs prior to tripping
in, the bit will not be able to get to bottom without reaming. Bi-centric/eccentric bits are designed to alleviate these
problems by incorporating an asymmetry in the structure, such as an enlargement in the body to one side of the
axis. In use, this enlarged side will rotate with the bit and cut a full gauge hole (or slightly over gauge depending
on the design and degree of eccentricity). However, with no rotation, the asymmetry allows the bit to pass through
a narrower diameter hole than the one just drilled.

BIT PROFILE

The bit profile influences bit stability, cutter loading (wear), and hydraulics. Many different profiles have been
tested and each manufacturer has his preferred shapes, but basically the variables are:

 the radius of curvature of the nose, whose shape can vary from flat, through spherical to parabolic
 the shape of the central cone in matrix-bodied bits
 the shape of the transition from nose section to gauge section
 how far back from the nose the bit reaches full gauge diameter
 the length of the gauge section

The same families of profiles are used in all types of diamond bits. Typical names given to them are conical,
parabolic and step. These are illustrated in Figure 4.1.24. A popular style is a double cone profile. This is an
aggressive profile that has proven to be successful for cleaning, wear resistance, directional control, and
penetration rate.
Figure 4.1.24 : Diamond bit profiles

Cone

The cone of the bit provides a degree of stability when the bit is drilling, due to the resultant forces from the
cutters within the cone generally acting to maintain rotation round the geometrical axis of the bit. The resulting
central cone of rock further enhances this stabilising effect, as it helps prevent the bit from shifting the location of
the central axis. The cone of the bit is usually lighter set than elsewhere on the bit face as the rock cone is
unconfined and consequently less force is required to remove it. Also less rock per revolution of the drill bit needs
to be removed towards the central region of the bit.

Taper/Flank

The taper, or flank, of the bit is the section between the nose and the gauge. It may provide a degree of stability
and its length is usually governed by the cutter density requirement. A bit designed for tough applications, which
needs a large number of cutters, would tend to have a more extended taper than a product for drilling a soft
formation. However, an alternative way to achieve a higher cutter density without increasing the taper is to
increase the number of blades.

Shoulder /Outer Diameter Radius (ODR)

The shoulder, or ODR, refers to that region of the bit profile where the radius at the end of the flank leads into the
gauge of the bit. This region of a bit is extremely important, especially in motor or turbine applications where
rotating speeds are high, as the cutters must withstand the effects of high velocity due to their position on the
outside of the bit

Gauge Length

Bits are produced with a variety of gauge lengths depending on the proposed application. Standard gauge lengths
are of the order of eight to ten centimetres. Greater gauge lengths are used to provide increased stability,
especially in harder formations, and shorter gauge lengths are used to provide increased directional
responsiveness.

CUTTERS

The parameters which describe the how cutters are set in diamond bits are:

 Type
 Density
 Distribution
 Exposure
 Orientation
Type

Diamond bits are categorised by the type of cutters mentioned in the first paragraphs of this Topic; this is reflected
in the layout of this and the following Topics. The distinctions are, however, becoming less rigid and different types
of diamond cutters may be present in the same bit, with the nominal type referring only to the principle cutting
structure. A so-called natural diamond bit will indeed only contain natural diamonds, but PDC and TSP bits may
have natural diamonds and/or impregnated diamonds on the gauge surfaces or even as supplementary cutting
elements on the bit face

One manufacturer - Hycalog - manufactures a

range of PDC bits with secondary elements of
diamond impregnated tungsten carbide set behind
and separate from specific PDC cutters located in
critical, potentially high wear regions of the bit.
Such a bit is shown in Figure 4.1.25. Similarly,
impregnated diamond bits may have natural
diamonds on the gauge surfaces.

Hycalog also manufactures TSP bits with natural

diamond cutters in the centre cone.

 
Figure 4.1.25 : A PDC bit with both PDC cutters and
secondary impregnated tungsten carbide elements
A second manufacturer - Security DBS -
manufacturers a range of PDC bits in which the
tungsten carbide support for the diamond disc is
both impregnated with natural diamonds and
incorporates TSP diamonds.

Another - Hughes Christensen - bonds TSP cutter

elements into discs to form thermally stable cutters
with the size and shape of conventional PDC
cutters. See Figure 4.1.26.

 
Figure 4.1.26 : A PDC/TSP cutter

Distribution

In all types of bit the placement of the cutting elements is varied to match the application. The position of each
cutter on the bit profile and its location relative to waterways, junk slots, and other design features can be
optimised for specific requirements with the help of computer programmes. These programmes enable cutting
forces and torque across the bit face to be optimised, ensuring that the bit runs smoothly.

Density

In general the total weight/volume of cutting material contained in a bit determines its service life. The higher the
diamond weight the longer the bit life. Within one specific family of bits the various types are said to be heavy set,
medium set or light set according to how the diamond weight/number of cutters compares with the average.

For all types of diamond bits, cutter density is designated as light, medium or heavy. Light set bits maximise load-
per-cutter for fast penetration through non-abrasive formations; medium set bits balance ROP and bit life for good
performance in formations with some abrasive rock or stringers; and heavy set bits provide long bit life through
harder and more abrasive sections. In most applications, the correct bit has the fewest number of cutters while
also having sufficient diamond volume to drill an economical hole section without wearing out.

Exposure and clearance

The cutter exposure determines the maximum depth of the cut. The exposure which can be used depends on the
impact resistance of the diamond.

Chip clearance is required in order to allow the cut

material to be displaced away from the cutting edge
and to provide a flow channel for the drilling fluid to
carry the chips away. In a soft and sticky formation
the chip clearance allows the drilling fluid to flow
across the face of the cutters to keep them clean and
prevent bit balling.

Figure 4.1.27 shows a cross section through a PDC

cutter, which normally have high clearances, but the
same principle is applicable to all diamonds.
Figure 4.1.27 : Exposure & chip clearance

Orientation

The natural diamonds used in drilling bits have no well defined shape, thus the parameter orientation is not
relevant for natural diamond and impregnated diamond bits. PDC cutters and TSP diamonds have a well defined
shape and can thus be installed with a specific orientation. The latter is defined by so-called back-rake and side-
rake angles which are described in the Topic covering PDC bits.

GAUGE PROTECTION

Maintaining the full gauge diameter of the hole being drilled is crucial. If the bit loses gauge and begins to drill an
undersized hole, a variety of problems can follow, including the bottom hole assembly becoming stuck in the well.
It is, therefore, imperative the bit has sufficient protection at gauge to avoid excessive wear, while still being of
reasonable length to allow for directional work.

As mentioned above, diamonds can only be used for gauge protection on matrix bodied bits. Steel bodied bits use
tungsten carbide buttons fitted on the gauge surfaces, and additional hard facing next to the inserts can be applied
to improve protection in abrasive formations. .

HYDRAULICS

There are two basically different arrangements for drilling fluid flow through the bit, with several sub-divisions. The
fluid can flow through either a central opening in the bit body, the so-called "crow's foot" or through several
individual openings in the bit face. Steel bodied bits always have several openings in the bit face, matrix bodied
bits can use either arrangement.

There are three types of flow patterns used in connection with a central opening, which are illustrated in Figure
4.1.28. :

 Radial flow, in which the fluid flows through fluid courses which extend from the crow's foot to the
shoulder . This keeps cuttings off the bit face in shale and soft formations.
 Feeder/collector flow, in which there are two sets of fluid courses. One extends outwards from the crow's
foot, the other extends inwards from the gauge surfaces and/or the junk slots but does not intersect the
first set or reach the crow's foot. The pressure in the latter system is lower than in the former, so that the
fluid flows across the cutters from the high pressure feeders into the lower pressure collectors. This gives
better cooling and is appropriate for hard formations like dolomites and limestones.
 Open flow, in which the fluid is directed from the centre to the OD through deep parallel or expanding
courses. This gives a minimal pressure drop and enhances both cooling and cleaning. It is only used on
step-profile bits and is ideal for turbine use.
Figure 4.1.28 : Fluid flow patterns

If openings in the bit face are used, these can either be of a fixed size or fitted with removable nozzles that can be
used to optimise flow rate and pressure drop. Steel bits are invariably fitted with nozzles; matrix bodied bits
formerly had fixed openings cast into the body, but now the majority also have a provision for fitting
interchangeable nozzles.

Diamond bits require more hydraulic power than roller cone bits for bottom hole cleaning and for cooling the
diamonds. The parameter used for diamond bits is power per unit area of hole cross section. The units used are
HP/inch2 (sometimes written as HSI) or kW/mm 2. Its usual value is between 1.5 and 3.0 HP/inch 2 (1.7 x 10-3 to 3.5
x 10-3 kW/mm2).

If high circulation rates are used with radial flow or feeder/collector flow type bits, which have a relatively small
clearance in the hole, the high pressure across the face of the bit will tend to lift it and reduce the effective weight
on bit. This is a consideration in bit selection.

1.4.4 BIT SELECTION

The main reason for running any diamond bit is economics. A calculation is made before a diamond bit is run to
estimate whether the cost per unit length will be more, less, or equal to that expected for roller cone bits or other
types of diamond bit. Refer to Appendix 1.

Sufficient information about the formations to be drilled must be available if the proper diamond bit is to be
selected. Formation properties such as drillability, plasticity, abrasiveness and compressive strength determine
which type of bit is best suited in each case. Changes in formation during one bit run can have a considerable
impact on the penetration rate. Therefore it is important to know which formations, and how much of each, will be
encountered. Some of this information can be gathered from logs, some from rock samples or cores from
previously drilled wells.

Given their long life, diamond bits or core heads may be used more than once. For this reason, and because of
their exceedingly high initial cost, they are normally treated as capital items rather than as consumable stock

1.4.5 RUNNING THE BIT

After the correct bit has been selected, the way in which it is treated has a very definite bearing on its
performance. Care must be exercised while going in the hole. The diamond bit has no moving parts and is very
rigid. Therefore striking a ledge or hitting a tight spot will tend to damage the bit.

If reaming is necessary, extreme care should be taken. Heavy reaming should be avoided since the OD of the bit
could be severely damaged. When reaming, light weights should be used with maximum pump volume and only
moderate rotary speeds (say 50 rpm).

When the bit is ready for drilling, care must be taken when first getting on bottom. Initially the shape of the
bottom of the hole will be different from the shape of the bit and thus not all the diamonds will carry load. Nor will
the distribution of cooling fluid be optimal until the bottom-hole contour fits the bit. Therefore the bit should be
"drilled in" very carefully with low WOB and rpm until the proper contour has been obtained. The pressure drop
over the water courses will slowly increase and the correct cooling will develop gradually.

One point which has to be borne in mind is that metal junk in the hole has an extremely detrimental effect on any
diamond bit, and can ruin it in a few metres. It is thus normal practice to run a junk sub in the string on the last
conventional bit run before a diamond bit is used. The use of a pipe wiper rubber all the time both going in and
coming out of the hole, is a very effective means to prevent junk from falling into the hole.

1.4.6 EVALUATION

Valuable information can be obtained by conscientiously evaluating the performance and condition of the diamond
bit. Table 4.1.7 lists the problems indicated by the various conditions which can be observed, with their remedies.
The information is valuable not only for the well in progress but also for future wells in the same area or which
penetrate formations known to be similar to the one drilled. Bit records and economic evaluations must therefore
be kept for future reference. For example if evaluation shows that progress was very slow with very little bit wear
the bit selected could have been more suitable for a much harder formation and the selection of a different design
in future may result in a higher penetration rate and lower cost per foot in that particular formation.

Natural diamond bits

1.5.1 NATURAL DIAMONDS

GRADES

Natural diamond cutting elements come in various grades and sizes for a range of applications, and are classified
by crystalline structure and diamond shape. Some natural diamonds are mechanically and chemically treated to
provide a smoother cutting surface for improved wear resistance. Small, reclaimed natural diamonds are often
used for gauge protection on drilling and coring bits.

The diamonds used in natural diamond bits are available in five grades:

 Premium
 Special Premium
 Standard
 Cube
 Carbonado

The grade of diamond used depends on the drilling application and on the area of the bit where the diamond is set.

Premium Quality diamonds have a rounded shape and make good, all-purpose stones. These high-impact and
abrasion resistant diamonds are especially effective in brittle shales and hard, fractured formations.

Special Premium (SP) diamonds are sharper than Premium Quality stones, and will increase ROP by about 5%
in medium formations and up to 20% in harder strata. The most wear-resistant natural diamond, SP stones are
recommended for hard, abrasive drilling-- sandstones, etc. However, they are not recommended for fractured or
broken formations because they have less impact resistance than Premium Quality stones.

Standard diamonds are similar to, but of lower quality than Premium Quality diamonds. These stones offer good
performance in applications where little diamond wear is expected.

Cube diamonds are large, sharp, blocky stones that can increase penetration up to 20% in softer formations.
These stones have less resistance to impact and abrasion than round stones and are not recommended for drilling
in hard or fractured formations.

Carbonado stones are sharp, irregularly-shaped diamonds. Carbonado diamonds do not have cleavage planes like
other natural diamonds, but rather have a random crystal structure that provides superior impact resistance.
Typically, these stones are used in combination with other types of stones to improve drilling performance through
fractured formations. Carbonado stones are placed at the apex, or leading edge, of the bit because of their ability
to withstand shock.

SIZES

Diamond sizes for bits are chosen according to the lithology for which the bit is designed. Typically, bits using
smaller stones-- and having less diamond exposure are used for drilling harder formations because smaller
diamonds offer greater impact resistance and are better able to penetrate high strength rocks.

Larger diamonds (1-3 spc) provide greater exposure for a better penetration rate through less hard (but not soft)
formations. Also, the increased exposure of larger stones increases the distance between the bit body and the
formation for easier cuttings removal and better bit cleaning.

In general, because of their limited depth of cut, natural diamond bits typically have low penetration rates of 5 to
15 ft/hr (1.5 to 5 m/h).

1.5.2 CUTTING ACTION

Natural diamonds cut the formation by a combination of ploughing and grinding actions as shown in Figure 4.1.29.
Because of this cutting action, combined with the erosion and abrasion resistance of the matrix construction, these
bits are effective in harder, more abrasive formations.

Figure 4.1.29 : Cutting action of a natural diamond

1.5.3 BIT DESIGN

The main differences between the various types of natural diamond bits is the size of the stone. Large stones are
used for soft to medium hard rock and small stones are used for hard rock.

The size and concentration of diamonds, the profile of the bit and the configuration of the water courses change to
match the size of the diamonds. The weight of diamond (carats) on the bit is still the main design criterion rather
than the total number of diamonds on it.

Stone orientation: while setting natural diamonds in the mould the diamond itself is set at random so that the
sharp cutting edge, if present at all, could be buried in the matrix.

The exposure of the stones is by necessity low in order to prevent them being torn out of the matrix. The
maximum expossure is ca. 30% of the diameter. This in itself limits the depth of the cut and hence the penetration
rate of a natural diamond bit.

With respect to hydraulic design, natural diamond bits always use a central opening in the bit body, usually with a
feeder/collector flow pattern.

Figure 4.1.30 : Diamond exposure

1.5.4 BIT PERFORMANCE

There is a direct relationship between weight, rpm, torque and hydraulics. Generally, as weight and rpm are
increased, penetration increases. The point at which penetration does not increase is generally the limit of
hydraulics (cleaning rate determines the drilling rate) or the limit of the diamond's ability to penetrate the rock.
Smooth torque allows the diamond to drill at its best with minimum risk of damage.

Weight on bit

The recommended minimum weight on bit is usually half the limiting bit weight, which is the maximum allowable
bit weight as quoted by the manufacturer.

To find the optimal WOB, it should be increased towards the limiting weight by increments of 4500 N (2000 lbs)
until the penetration rate no longer increases. Then the weight on bit should be decreased by about 6500 N (3000
lbs) to give the value to be used while drilling ahead.

RPM and torque

While drilling ahead (after forming the bottom contour) the maximum rpm should be used 150 revolutions per
minute is normal for rotary drilling.

With turbines and Moineau motors this value can be much higher (600-900 rpm).

During rotary drilling rotary speeds which could produce vibrations in the drill string should be avoided. If such
vibrations occur a new combination of WOB and rpm should be established. Variations in torque can be caused by a
change of formation or by bit wear. If torque become excessive a new combination of WOB and rpm should also be
established. This is usually done by lowering the WOB and increasing the rpm.

Hydraulics

The pressure drop across the bit is the pressure loss resulting from fluid flow between the face of the bit and the
formation. It can be determined by noting the difference in circulating pressure with the bit rotating off-bottom,
and on-bottom. Changes in this pressure loss are an indication of changes in formation, change in stand-off
between bit and formation or an indication of uneven bit wear.

If a ring of diamonds is burnt out a ridge of formation will not be drilled. This ridge will gradually close off the water
courses, causing an increase in pressure loss. The bit is then said to have suffered "O-ring" wear - see the
examples in Appendix 3.

PDC bits

1.6.1 INTRODUCTION

The original synthetic diamonds consisted of just one crystal. As the manufacturing technique was developed it
became possible to produce a polycrystalline layer of diamonds composed of many tiny diamonds grown together
with a random orientation. What made polycrystalline material so revolutionary was the diamond to diamond bond
which fuses the individual diamonds together; these bonds have the same strength as the diamond itself. This plus
the random orientation gives maximum strength and wear resistance. The so-called "compacts" (Figure 4.1.31)
consist of such a layer of polycrystalline diamond bonded to a sintered tungsten carbide substrate under the same
conditions that were used to grow the diamonds. The typical thickness of the diamond layer is 0.5 mm on top of a
thicker tungsten carbide substrate.
Figure 4.1.31 : Diamond compacts

As mentioned in Topic 1.3.2 the synthetic polycrystalline diamond material used in these compacts has a
temperature limitation due to the residual catalyst. Because of this the temperature in service has to be kept below
approximately 700°C

tThe same residual catalyst also reduces the impact strength of the polycrystalline diamond material. However the
tungsten carbide substrate to which the diamond is bonded reinforces the diamond layer and provides he required
resistance to impact.

The compacts are bonded to tungsten carbide studs (providing further impact resistance) which in turn are
attached to the bit body either by using a low temperature brazing method (steel or matrix bits) or by pressing
them into a pre-drilled hole with an interference fit (steel body bits). The cutter on the left in Figure 4.1.32 is a
cylinder which is generally brazed into blades of cast tungsten carbide matrix bits. The stud cutter shown on the
right is used on all steel body bits and may either be an interference fit into the body or be brazed. The stud cutter
may also be used in a matrix body, in which case it is brazed

Figure 4.1.32 : Compact attachment methods

The characteristic of paramount importance in the polycrystalline diamond compact (PDC) bit is that the cutter is
self sharpening. This is because the tungsten carbide wears at least an order of magnitude faster than diamond
and hence most of the WOB is carried by the diamond layers. That is one reason why PDC bits can drill so rapidly
at light bit load. The advent of the PDC bit has in fact given rise to what is probably the first self-sharpening drag
bit.

The diamond compact is an engineered diamond cutting edge for which an economical alternative cannot be
obtained from a natural diamond. Unlike the relatively small diamonds used in typical natural or even TSP diamond
bits, the PDC cutter can be attached to the bit body as a large, sharp cutting element.

Add to this the absence of bearings and it should be clear why PDC bits have taken over a large part of the drilling
bit market. As mentioned above they do have one disadvantage, which is the temperature limitation. High
temperatures have to be avoided by using proper bit hydraulics to cool the cutters and by drilling with the right
cutting element at the optimum weight-on-bit and rotary speed for the formation.
1.6.2 CUTTING MECHANISM

PDC cutters are designed to cut the rock in shear and not in compression, as is the case with roller cone bits, or by
a ploughing/grinding action, as is the case with natural diamond bits - see Figure 4.1.33. In relatively plastic
sedimentary rocks like shale, limestone and weak sandstones, shearing is the most efficient cutting mechanism,
requiring significantly less energy than breaking it up in compression, which is the second reason for the low
weight on bit required for PDC bits.

Figure 4.1.33 : Cutting mechanisms

Shearing also tends to lift chips off the bottom to assist cleaning. Because of the latter characteristic PDC bits
suffer less from chip hold-down than do roller-cone bits and much less than natural diamond bits.

Problems with the early fishtail- type drag bits (high torque, premature wear, deviation) have been largely
overcome with diamond compact bits through application of state of the art materials, design technology and
complementary operating techniques.

In the right formations, the shearing action makes it possible for PDC bits to maintain high rates of penetration
with a relatively low weight-on-bit and a long service life. At the same time deviation control is improved and wear
on the bit and the drill string is reduced.

1.6.3 BIT DESIGN

Figure 4.1.34 shows the nomenclature used with PDC bits.

Both steel-bodied and matrix-bodied PDC bits are available, but matrix bodies are in the majority with steel bodies
being confined to the large bladed, soft formation segment of the market.

 
Figure 4.1.34 : PDC bit nomenclature

CUTTERS

Attachment

In most steel bodied bits the cutters are attached by means of an interference fit in machined holes. They can also
be brazed.

In a matrix bit, the cutter pockets are cast around graphite formers, which are then machined out. Although the
holes are precision cast, they are not as accurate as those machined into a steel bit and this, coupled with the
more brittle characteristic of tungsten carbide matrix, makes interference fitting of cutters undesirable. Instead, all
cutters are brazed into a matrix bit.

Size

A variety of PDC cutter sizes are availablebetween 8 mm and 50 mm.

The first PDC manufactured had a diameter of 8 mm diameter. These are still used on bits designed for harder
formations.

The most common size is now 13 mm.. This is suitable for cutting medium to medium-hard formations as well as
abrasive rock.

Large (18 - 25 mm) cutters are most suitable for the fast drilling of soft to medium formations when mounted in
high bladed fishtail style bits. Because larger cutters produce large cuttings in the right application, they are
extremely useful when drilling with oil based drilling fluid or water based drilling fluid in a hydratable formation, as
less surface area of cutting is produced per unit volume of rock removed.

Very large PDCs of up to 50 mm diameter have been used in soft formation bits. However, the incremental
advantage which size gives is outweighed in smaller bits by the inherent lack of redundancy. Space is limited on
the bit face and by using such large cutters there is only sufficient room to mount the minimum number of cutters
to cut a full bore hole. Were one cutter to fail, the bit would be unable to proceed. Additionally, as very large
cutters wear, the very large wear flats produce considerable heat which can cause catastrophic damage to the
diamond layer.

Distribution

Cutter placement depends upon nozzle and junk slot orientation.

Cutters are distributed across the bit face in such a way as to satisfy the following requirements:

 Even wear: no one cutter should wear appreciably more than the rest which would result in a weak spot.
Additionally, even wear results in the efficient utilisation of the PDC.
 Optimum life: based on target formations and operating conditions, the cutters should be arranged across
the bit in such a way as to provide maximum bit life and to take into account expected rates of
penetration and product cost.
 Balance: the lateral imbalance force, resulting from the vector addition of all the cutting forces as the bit
is drilling, is calculated at the design stage. Certain types of anti-whirl drill bits utilise this force in
conjunction with a cutter devoid area and a low friction zone at the gauge to reduce the incidence of
whirling (see Topic 1.6.4 ). On most bits, however, it is desirable to minimise this lateral force and the
cutters are positioned accordingly.

* Redundancy: depending on the target formation, bits may have considerable cutter redundancy built into the
design. This is especially true on the flank and ODR of bits designed for tough, abrasive formations. This
redundancy reduces the risk of premature bit failure

Density & Exposure and chip clearance

Density

Cutter density controls the service life of any

diamond bit. The higher the density of
cutters, the more potential life the bit has.
The lower the density, the greater potential
ROP due to a greater weight on each cutter
giving a greater depth of cut, and to more
efficient cleaning and cooling of the cutters.
Examples of different cutter densities are
shown in Figure 4.1.35.

For PDC bits, the optimum number of

cutters represents a compromise between
penetration rate and bit life.

Figure 4.1.35 : Cutter densities

Exposure and chip clearance

Given that PDC bits tend to be used in softer formations, and given also that the impact resistance of polycristalline
diamond is relatively high, the cutters of PDC bits are usually fully exposed in order to maximise the depth of cut.

As mentioned above a PDC element cuts by shearing the rock, with the sheared material passes up the face of the
cutter. This requires a much greater chip clearance than the ploughing action of a natural diamond. Additionally,
because the greater depth of cut produces higher volumes of cuttings, the chip clearance also has to be greater in
order to allow these to be carried across the face of the bit to the gauge section. Chip clearances are thus greater
in PDC bits than in natural diamond bits. In the softest formations, when cuttings are produced at a high rate,
bladed designs are used to give a very high chip clearance. See for example Figure 4.1.23 and the above Figure
4.1.35.

Orientation
The orientation of the cutter is a significant factor in its performance. The rake angles of a cutting tool define the
angles at which the tool is presented to the formation. PDC elements can have back rake and side rake, each of
which can be positive, negative or zero, see Figure 4.1.36.

Figure 4.1.36 : Cutter orientation

Back rake is the angle from vertical of the PDC cutting element as it attacks the formation. This controls the
aggressiveness and life of the cutter. Cutters are said to be more aggressive when they are positioned such that a
given weight on a bit gives a greater depth of cut. The smaller the back rake angle, the more aggressive the cutter
becomes. The more the back rake the more durable but less aggressive the cutter. The back rake angle used in a
given bit is specified to match the drilling mechanics of the formation for which the bit is designed. In general,
more aggressive back rake angles are more suitable for softer formations. If back rake is too aggressive, drilling
harder formations might result in chattering of the cutter (and hence the bit), followed by chipping of the diamond
and perhaps catastrophic failure of the PDC. Less aggressive back rakes will reduce torque for a given weight-on-
bit, but at the expense of penetration rate. The best balance between rate of penetration and bit life appears to be
in the range 15° to 30°.

Back rake can also be varied to change the sensitivity of the bit to drilling weight. This is particularly important in
directional and horizontal drilling applications. By increasing back rake, the bit becomes less responsive to
variations in weight-on-bit. This widens the operational range and makes the bit a more versatile directional drilling
tool.

The side rake angle affects bit cleaning and the displacement of cuttings. Chips have a tendency to be lifted from
the bottom of the hole and pushed either ahead or to the side as they are cut. Side rake can be used to
mechanically direct these cuttings toward the junk slots and the annulus. However increasing side rake also
reduces the efficiency of the cutter because the effective operating width of the cutter decreases. For this reason it
has limited use on standard bits, with reliance being placed on hydraulics for the cleaning of the bit face.

GAUGE PROTECTION

The general principles given in Subtopic 1.4 .3.6 are applicable.

HYDRAULICS

All PDC bits use nozzles strategically positioned on the bit face to clean the bottom of the hole, clean the bit and
cool the PDC cutters. The majority of bits use interchangeable nozzles to allow the hydraulics to be optimised for
the particular application. The proper sizing of these nozzles provides the high pressure drops and hydraulic
horsepower per square inch required for high penetration rates in PDC drilling, especially in softer formations.

The jetting action of the nozzles and the design of the bit face direct the cuttings toward the junk slots located on
the outside diameter of the bit. Together, the nozzles and junk slots provide the basic flow pattern required to
clean and cool the diamond compact cutters, avoiding bit erosion and areas of stagnation. The actual nozzle
placement and orientation depend on the individual bit style. Typically, nozzles are positioned and oriented to clean
and cool a group of PDC cutters--a blade or spiral pattern, for example. In some designs, with very large cutters,
each nozzle can be dedicated to a single PDC cutter. In some designs the axis of the nozzle is not perpendicular to
the face of the bit, but forms an acute angle to force the fluid in a preferred direction, providing better cleaning of
the cutter faces.

In soft formations, where penetration rates are high and a large volume of cuttings is produced, penetration rate is
limited only by the ability to remove these cuttings and failure to clean the bit will result in bit balling. This is the
case especially in water reactive shales when a water based drilling fluid is being used. In harder formations,
cleaning the bit becomes secondary to cooling the cutters. If the cutters overheat, the diamond layer will degrade
and rapid cutter wear will follow. Therefore, it is apparent that bits for different formations require different
hydraulics. These requirements must be balanced in the bit design and the hydraulics program calculated to suit
the formation being drilled.

 1.6.4 ANTI-WHIRL BITS

Since their introduction, PDC bits have exhibited non-circular hole patterns and have experienced unexplained
impact damage to cutters. This in turn has led to shorter bit life. Figure 4.1.37 is a photograph of the bottom
pattern produced by a standard PDC bit in a test rig in KSEPL. These problems are now known to be the result of
bit-induced vibration, so-called "whirling". Bit whirl is a condition in which the bit revolves around a point other
than its designed centre of rotation. Anti-whirl bits have been designed to minimise this problem and therefore
increase bit life.

Figure 4.1.37 : Bottom pattern - standard PDC bit

Whirling occurs when an imbalance force is introduced, such as when:

 the hole is inclined,

 the formation hardness changes and the hole is not perpendicular to the interface
 the drill string is vibrating due to inadequate stabilisation,
 the sum of the forces on the individual cutters has a lateral component.

There is nothing which can be done about the first two of these, and the third is a question of drill-string design.
Using modern CAD techniques, however, the bit designer has very good control over the direction and relative
magnitude of the forces on the individual cutters.

It is not sufficient to produce a bit in which the cutter forces are balanced, because that still leaves it susceptible to
the unavoidable lateral forces. The approach taken by the majority of manufacturers is to arrange for the sum of
the load forces generated by the cutters to have a certain value directed through a large, low friction, gauge pad
designed to slide on the borehole wall. If the value of this resultant cutter force is always higher than the
unavoidable lateral forces the total force will always pass through the gauge pad and the bit will be self-stabilising
while drilling. Figure 4.1.38 is a photograph of the bottom pattern produced in the same test rig by a similar PDC
bit but designed according to these principles. This technology is licensed by Amoco.
 Figure 4.1.38 : Bottom pattern - anti-whirl bit

An alternative approach, used by Security DBS, is to place the cutters in such a way that they follow the path made
by the one directly in front. Due to this cutting action higher ridges of uncut rock are produced between the cut
grooves than for a conventional PDC bit. These ridges restrain lateral movement and therefore reduce lateral
vibrations.

1.6.5 APPLICATION

The formations for which PDC bits are applicable are the soft to medium hard formations such as:

 Salts
 Chalk
 Anhydrite
 Claystone
 Shale
 Sandy shale
 Soft limestone

The soft sticky shales located near the surface are sometimes too soft for PDC bits. Harder formations than those
listed may be too hard for PDC cutters, causing excessive cutter wear. The use of oil base drilling fluid can extend
the application of PDCs, allowing them to drill the softer sticky shales and some of the harder formations by
controlling shale hydration, enhancing cleaning and lubricating the cutters for extended life.

Because of their high initial cost, PDC bits are often re-used and are treated as a movables item in the same way
as natural diamond bits.

1.6.6 DRILLING PARAMETERS

TORQUE

Due to the sharp edges of the PDC cutters on a new bit, rotary torque is an effective measure of what is happening
at the bit face. In soft or plastic formations, the rotary torque may show the bit is on bottom before the weight
indicator does. In such formations, the torque indicator may well prove to be the most suitable instrument by
which to drill. The weight on bit may be varied to maintain a steady torque reading. A suitable torque level will be
sufficient to ensure the cutters are indeed digging into the formation, but not to the point that this results in
appreciable slowing of the rotary table
A steady torque is expected when drilling shales and other homogeneous formations, whereas those which are
layered will result in a varying surface torque. In sands, torque may increase considerably and even become
excessive, at which point the weight on bit should be reduced accordingly. A characteristic of PDC bits, when
drilling through soft or plastic formations, is an oscillation in the on-bottom torque and rotary speed. This results
from the drill pipe behaving like a long, torsional spring, responding to drag generated by the PDC bit. As the bit
digs into the formation, it will slow down for a short period. As the drill pipe continues to rotate, surplus torque is
built up until it is sufficient to spin the bit rapidly, resulting in a spontaneous increase in rotary speed and reduced
level of torque. This cycle will then be repeated at a frequency dependent largely upon the drill pipe diameter, the
mass of the drill collars, the length of the drill string and the formation. Commonly, this frequency falls between
two and eight seconds and may be tolerated provided it is not too severe and the penetration rate is acceptable.
This torque cycling can be lessened by reducing the weight on bit or increasing the rotary speed or by using a "soft
torque" rotary drive.

WEIGHT ON BIT

As the bit drills, the PDC cutters will wear down and proportionally more of the weight applied will be taken by the
wear flats generated on the tungsten carbide supports to the rear of the polycrystalline diamond layer. This
reduces the rate of penetration and, as a consequence, it is usually necessary to increase the weight on bit as the
run progresses. This can be done in increments until an acceptable penetration rate is achieved or the maximum
recommended weight suggested in the bit operating guidelines has been reached. In general, weight on bit should
be applied before the rotary speed is increased too much, so that the PDC cutters will attain a minimum depth of
cut.

The WOB used with PDC bits is usually lower then that for roller bits because the weight is carried on the very
narrow compacts. Very low WOB should be used for drilling-in to establish the correct bottom pattern because a
load, similar to that on diamond bits, will be taken by only a few cutters at the start. No pressure increase will be
noticed during drilling-in (unlike natural diamond bits).

ROTARY SPEED

Higher rotating speed will usually result in higher penetration rates and whatever rotary speed yields the highest
rate of penetration, without causing problems, is generally the right one. If increased rpm does not produce better
ROP in soft to medium formations bottom-hole cleaning may be insufficient. With regard to the bit itself there are
no limitations to maximum rpm, except in some hard formations where the PDC cutters are unable to "dig in"
beyond a certain threshold rotary speed.

The factors that do place a maximum practical RPM level for PDC bits in specific applications include the drill pipe
and drive mechanism. Critical rotary speeds which cause drill string vibration must be avoided.

The best combination of WOB and rpm should be established by drill-off tests. If it is found that low WOB and high
rpm give the same penetration rate as high WOB and low rpm, the former combination is preferred.

HYDRAULICS

In general the maximum available hydraulic power at the bit should be used to maximise bottom-hole cleaning and
cooling and cleaning of the cutters. The usual value of HSI for a PDC bit is between 2 and 3.0 HP/inch 2 (2.3x10-3 to
3.5x10-3 kW/mm2).

TSP bits

1.7.1 INTRODUCTION

Given that the metallic material responsible for the limited temperature stability of the diamond in PDC cutters is
not present, but that they share their impact resistance, TSP diamonds are suitable for drilling hard and abrasive
rock with a limiting temperature of 1000°- 1200°C.

While in many ways what has been learned about natural diamond bits is applicable to TSP diamond design and
performance, there are other ways in which the two technologies diverge. The advantage of TSP diamond cutting
elements over natural diamonds, which are single crystals, is that the cutter is self-sharpening that is, as the
cutting edge is worn away, fresh, small crystals are constantly being exposed to continue the cutting action. Thus,
the TSP diamond diamond cutter, like the diamond compact of PDC bits, remains sharp throughout its entire life.

1.7.2 CUTTING MECHANISM

Like natural diamond bits TSP bits have the capability to effectively "plough through" hard rock formations; and
like a PDC cutter they can shear soft to medium formations. Both cutting actions are more efficient than the
crushing and gouging action of a roller cone bit. TSP bits thus offer multi-purpose cutting mechanics combined on
one bit for efficient drilling in a range of formation types. At the same time they offer high ROP and long life in
medium-hard and abrasive formations.

1.7.3 BIT DESIGN

The design variables are the same as for the other types of diamond bit.

THE BIT BODY

Currently available TSP diamond material is not supported by a tungsten carbide substrate, so, like natural
diamonds, its use is limited to matrix body bits. Figure 4.1.39 shows a TSP bit; this one uses triangular cutters.

1.7.4 APPLICATION

TSP diamond bits perform well in medium hard formations such as limestones, dolomites, anhydrite, mildly
abrasive sands, and interbedded hard sandstone and brittle, silty shales.

1.7.5 DRILLING PARAMETERS

Given the similarity between the two types of bit, the comments concerning natural diamond bits in Topic 1.5 are
also relevant for TSP bits.

CUTTERS

Attachment

Due to the lack of cobalt in the structure the diamond is not readily "wettable" and cannot be directly bonded to a
support material. TSP diamonds are thus usually held in place mechanically by being baked into a tungsten carbide
matrix.

Given that the TSP diamond material is thermally stable up to 1200° C, it can be baked into the matrix body in the
same manner as natural diamonds.

An alternative method is to apply a special coating to the surface of the diamond material to provide wettability
and allow it to be brazed to tungsten carbide posts or studs.

 
Size

TSP diamond material is available in many different sizes and shapes. The
principal cutting elements are much larger than the stones used in natural
diamond bits; two of the most successful are the small triangular shaped stone of
ca. 1/3 carat and the disc shaped stone of ca. 1 carat see Figure 4.1.40.

TSP diamonds can also be impregnated into the tungsten carbide matrix for
specific applications, in which case they are smaller than 25 stones/carat.
Figure 4.1.40 : Typical TSP
  cutters

Density

The TSP diamond bit is similar to the PDC bit with regard to density. The greater the density of the cutting
elements, the longer the bit life will be, but lighter set bits are easier to keep clean on bottom, and may produce a
better penetration rate at the softer end of the range.

Exposure

Since TSP diamonds cut with a shearing action, chip clearance is necessary. For this reason, for a more aggressive
cutting action and to maximise the potential life of the stone, maximum exposure is utilised.

Given their size, shape and impact resistance, TSP cutters can be mounted with greater exposure than natural
diamonds.

Orientation

Unlike the diamonds used in natural diamond bits TSP diamond cutters have a well defined shape and can be set in
the matrix body in a specified orientation. The designer can thus specify the back rake and side rake angles to be
used in the same way as is done for PDC bits. Different orientations have the same effect as described in the
previous Topic.

As previously mentioned one manufacturer Eastman Christensen bonds TSP cutter elements into discs to form
thermally stable cutters of the size and shape of conventional PDC cutters as shown in Figure 4.1.26. Bits using
these cutters give an increased penetration rate plus a longer life than standard PDC bits when drilling interbedded
formations of soft, abrasive shales interbedded with harder sand or carbonate stringers.

GAUGE PROTECTION

All TSP diamond bits have both natural diamonds and TSP diamond cutting elements in the gauge and transition
areas. The natural stones and TSP diamond cutters are mixed and arranged in such a way that gauge protection is
maximised. This combination of gauge material not only protects the gauge of the bit and maintains the
appropriate hole size, but if necessary will also cut or ream the hole to gauge.

HYDRAULICS

TSP diamond bits utilise radial or feeder/collector hydraulics systems, according to the hardness of the formation
for which they are designed. The flow rates and hydraulic power requirements for TSP diamond bits are very
similar to those of natural diamond bits due to the physical restraints of the water courses and matrix. Since TSP
diamond bits are mostly used for medium-hard formations they do not require extremely high HSI values for
proper cooling and cleaning. Most TSP diamond bits are run with an HSI value of between 1.5 and 2.5 with good
results.
Figure 4.1.39 : A TSP bit

Impregnated bits

1.8.1 INTRODUCTION

Impregnated, or sintered, diamond bits contain sharp, natural diamond cutters mixed in various concentrations
through a tungsten carbide matrix. They drill in a similar fashion to natural diamond bits, the improvement is that
as the diamonds become worn and are torn out of the matrix new ones are continually being exposed. This gives
them the ability to drill the hardest, most abrasive formations at high RPM with a service life several times that of a
standard natural diamond bit.

1.8.2 CUTTING MECHANISM

The natural diamonds in impregnated bits cut in a ploughing mode like those mounted on the surface of the
traditional natural diamond bits.

1.8.3 BIT DESIGN

THE BIT BODY

By definition these are matrix-bodied bits. The binding material however differs from that used for the other types
of diamond bit because it has to be tailored to the abrasiveness of the type of formation for which the bit is
designed. It normally contains not only cobalt and nickel but also copper and wolfram. A typical impregnated
diamond bit is shown in Figure 4.1.41
CUTTERS

Size

The diamonds used in these bits are in general much smaller than those used in conventional natural diamond bits.
The "grain size" of the impregnated diamonds ranges from very fine sand to coarse sand (0.1-1.0 mm).

Distribution/Density

The same criterion applies as for the other types of diamond bits, extended to three dimensions.

In general the life of the bit is determined by the total volume of cutting material it contains. The higher the
diamond weight the longer the bit life. However, in order to maximise penetration rate the weight on each cutter
has to be optimised which means that a relatively small number of diamonds must be cutting simultaneously.

There has to be a good balance between the rates at which the diamonds and the matrix wear, otherwise the bit
will either lose diamonds before they are worn and have a short life or have a very low penetration rate because
the WOB is being supported by the matrix. See figure 4.1.42.

When starting drilling the segment is blunt.

Penetration rate is low. Abrasive formation particles
wear the matrix and expose the diamonds. Penetration
rate increases.

After the matrix is eroded a matrix backing for the

diamonds is formed. Penetration rate gets to the
maximum.  

Diamonds are wearing down. Wear flats increase the

cutting forces.

The higher cutting forces will pull out the worn

diamonds. Their erosion exposes the next layer of new
sharp cutting material.

A proper working segment always has a large amount

of sufficiently exposed diamonds and only a small
Figure 4.1.42 : Wear process amount of already popped out diamonds.
in impregnated bit

Exposure
As the diamonds are very small, their exposure is limited, thus penetration rates of impregnated diamond bits are
relatively low in comparison with other diamond bit types.

Orientation

The natural diamonds cannot be given a specific orientation, but in any case the manufacturing process would
exclude the possibility.

GAUGE PROTECTION

Larger sizes of natural diamonds are placed on the gauge surfaces of the bit in order to reduce the rate of wear
and maintain the hole size throughout the bit run.

HYDRAULICS

Fluid courses are cast into the bit face, as for surface mounted diamond bits, with the hydraulic design matched to
formation characteristics. Since the bit material is designed to wear away in service this inevitably means that the
fluid courses become shallower during the process. It is usually the deterioration of the bits capacity to keep the
face clean which determines how long the bit continues to make progress.

Coring

1.9.1 INTRODUCTION

A core is a cylindrical sample of the formation penetrated in a state that is as little disturbed as possible. A
completely undisturbed sample is virtually impossible to obtain as it will always be affected by the drilling fluid and
may be cracked by the mechanical action of the core-head, but the important point is that it has not been broken
up by the bit into cuttings. Typical diameters of a core in a conventional well are 3" or 4", which are normally cut
using a core barrel in an 81/2" hole.

A core is required for specialised studies that cannot be accomplished by using cutting samples. These include:

 determination of the lithological characteristics and geological age of the formations penetrated.
 confirmation of wireline log interpretations and the calibration of scales for interpretation.
 the direct measurement of the porosity, permeability and flow characteristics of the reservoirs, in order to
evaluate the possibility/necessity of treatment.

For coring the drilling bit is replaced by a core-head, which is little more than a drilling bit with a hole through the
middle so that it cuts away a ring leaving the core to pass up inside it. Immediately above the bit is a core barrel
including a core catcher. The barrel is a special container for the core and the catcher is a simple mechanical device
which allows the core to pass upwards but not to fall back down.

The length of the core barrel is restricted by handling considerations. They come in the same lengths as drill pipe
and can be connected together, thus it is possible to cut 30 ft, 60 ft or 90 ft cores in one run into the hole. If a
longer core is required two or more runs with the coring equipment have to be made. Coring a long section is thus
a very expensive operation.

A 100 % recovery of cores is obviously important both because the geological record should be complete and
because if a part is missing it is often difficult to determine whether the recovered part was at the top or bottom of
the cored section, and the depth correlations then become unreliable. Given that cores only provide a picture of the
down-hole situation if they are recovered from the barrel in the correct sequence, and that the operation cannot be
repeated, great care is essential while handling the core on surface. It may take a few minutes longer to get the
core neatly into boxes in the correct order, but it is of utmost importance. A core deposited as a pile of rock rubble
on the rig floor is completely useless.

1.9.2 CORE HEADS

Soft formation core heads can be the roller cone type. Nowadays however this type is hardly used and all core
heads used in ADTI's coring operations use diamond cutters. They are available with all types of cutter,
corresponding to the type used in the drilling bit which would be used for the same formations.

Figure 4.1.43 shows a selection of coreheads.

Figure 4.1.43 : Core heads

If long hard sections are to be cored it is advisable to use more than one core head in turn. This may avoid having
to ream long intervals if one core head becomes undersized.
1.9.3 CONVENTIONAL CORE BARRELS

 As mentioned above, a core barrel consists of an inner

and outer barrel, plus a core catcher. These are the
essential elements relevant to coring, but for practical
reasons a barrel also has a safety joint and one or more
stabilisers. A drawing of a conventional core barrel is
shown in Figure 4.1.44.

There are two slightly different types of core barrel,

called "conventional double barrel" or "maritime double
barrel". The two types of core barrels differ only in the
wall thickness of the outer barrel. The maritime core
barrel has a heavier cross-section to withstand shock
loads due to the wave motion that exists when
operating from a floating rig. The additional strength of
the maritime barrel is also considered to be
advantageous for extremely deep wells, wells where
high bit weights are required to achieve an acceptable
penetration rate, and for wells containing hydrogen
sulphide or corrosive fluids which attack the metallic
structure.

The only other distinct characteristic of maritime barrels

is the stronger thread geometry, which is possible due
to the increased wall thickness.

Referring to Figure 4.1.44, core barrels have an outer

barrel for transmitting torque and weight to the bit, and
an inner barrel which will contain the core and isolate it
from the drilling fluid. The latter passes through the
annulus between the inner and outer barrel. To further
support and prevent deterioration of the core, the inner
barrel is suspended on an low-friction thrust bearing.
This isolates the outer barrel rotary motion, that drives
the bit, from the stationary inner barrel, containing the
core.

INNER BARRELS

To replace the conventional steel inner barrel,

disposable aluminium or fibreglass inner barrels were
developed and are now almost universally used. These
bring undisturbed core samples to the surface and to
allow the cores to be transported from the field to the
laboratory without disruption or contamination. The
core plus barrel can either be transported as recovered
or together cut into more easily transportable lengths.
The cut ends are sealed with plastic caps and resin. Figure 4.1.44 : A conventional core barrel
These types of inner barrels are often used in soft,
friable, broken and unconsolidated formations. The
aluminium barrels are used where fibreglass ones are
not suitable such as in hot holes or other detrimental
environments.

 
In addition to minimising the disturbance of the core material on surface, the use of an aluminium or fibreglass
inner barrel also has other advantages:

 There is less friction between barrel and core than in the case of a standard steel inner barrel, and it can
be reduced even more by lining the disposable barrel with plastic or, for hard abrasive formations, by
chrome plating the inner surface. This reduces the tendency to fracture during the cutting operation.
 There is less exposure to the atmosphere, minimising changes to the volatile components.
 The core can be gamma ray and/or density logged at surface while still in the inner barrel. This enables
rapid calibration of the logging tools when the cored hole is subsequently logged.

CORE CATCHER

The core catcher keeps the core in the inner barrel when making a connection and when tripping out. For a hard
formation it is a cage-type basket design with hard facing on the inside ribs; for soft or broken formations it is a
finger-type basket.

In addition to such conventional core catchers, there are also full closure core catchers on the market, e.g.
Eastman's hydro-lift system. The advantage of these is that the inner barrel is actually closed off after coring has
been completed preventing core loss during tripping. The system is designed for use in soft and unconsolidated
formations, but can be used in any coring application.

Coring with the full closure system proceeds much like conventional coring operations. When coring is complete, a
second ball is dropped to activate the full closure catcher.

DROP BALL

A feature incorporated in the core barrel is an orifice through the top of the inner barrel which allows fluid to be
directed in two different directions. It can be closed from the surface by dropping a ball. When the port is open,
drilling fluid can flow through the upper end of the inner barrel, flushing out all of the cuttings that might have
entered while running into the well. It also allows unrestricted circulation in order to clean the bottom of the hole
before commencing to cut the core. When adequate flushing has been accomplished, the ball is dropped closing the
orifice and redirecting the drilling fluids to the annulus via the ports between the outer barrel and the inner barrel.

SAFETY JOINT

The core barrel is provided with a connection at the top of the outer barrel referred to as a safety joint. This
consists of coarse, high-pitched threads which give it a low locking stress. Shims are provided between the inner
barrel and the safety joint to obtain a pre-set clearance between the bottom part of the inner barrel and the inside
of the core head. The clearance is such that, in case of excessive pull to break the core, stretch of the inner barrel
results in contact between inner barrel and outer barrel which can withstand the additional force required.

The safety joint can be selectively disconnected, which results in separation of the inner barrel components from
the outer barrel in the event the core barrel becomes stuck, allowing recovery of the core even under these
extreme conditions.

STABILISATION

Stabilisation is essential to the satisfactory operation of the core barrel. This to prevent the outer barrel bending
and causing an uneven load on the face of the bit. It is also necessary that the diamond core bit and barrel rotate
about their designed axis in a regular motion to assure that the diameter of the core being generated is of a size
compatible to the core catcher and the inner barrel. Stabilisers assist in achieving these results and are normally
placed at 30 ft intervals on the core barrel starting at the bit. The near bit stabiliser provides the most important
support.

If a core is required at a depth where a large hole is programmed the core will still be taken using an assembly for
an 81/2" hole. (Evidently this will have to be opened up to full size later in a special run with a hole-opener - see
Topic 1.10. ) If this is the case an 81/2" pilot hole which is at least as long as the core barrel will have to be drilled
before reaching the coring point otherwise it will be impossible to stabilise the barrel in the hole as the core is cut.
Stabilisation is very important when coring in depleted reservoirs where the risk of differential sticking is much
greater than in normally pressurised formations.

 1.9.4 SPECIAL CORING TECHNIQUES

RUBBER SLEEVE CORE BARREL

This type of core barrel was designed to provide virtually undisturbed

cores in difficult coring operations such as soft, unconsolidated
formations, conglomerates or badly fractured rocks. A rubber sleeve
wraps tightly around the core as it passes into the inner barrel, keeping it
intact and protecting it from fluid washing, blocking, friction, grinding and
crumbling. See Figure 4.1.45.

This has in the past been a popular technique, but it is no longer

recommended as it is now believed that even though good recovery is
achieved the core disturbance is more pronounced than can be achieved
using a rigid container.

Figure 4.1.45 : A rubber sleeve core

barrel

PRESSURE CORING

This method allows the retrieval and examination of core material at near in-situ conditions. It relies on preventing
the core from expelling fluids during pressure depletion by maintaining a pre-determined pressure in the barrel as
the core is brought to surface. The recovered core material may then be used to provide accurate measurements of
important rock properties such as fluid saturations, relative permeabiIity, porosity, wettability, shear strength,
compressibility and gas content and deliverability.

Because of the high confinement pressure great care has to be taken when recovering and handling the core.
SPONGE CORING

This is an alternative approach to pressure coring when measurements on the liquid phases are required.

The core fluids contained in the retrieved core are expelled as a result of depressurisation as the core is brought to
the surface, but are collected and trapped in an absorbent polyurethane material (sponge) lining the inner barrel.
The inner barrels (commonly aluminium) are ribbed lengthwise with 1/2" thick, cylindrical shaped absorbent
material molded into the space between absorbent material molded into the space between the ribs (See Figure
4.1.46).

Figure 4.1.46 : A sponge-coring barrel

The sponge can absorb and collect fluid up to a volume larger than the fluid capacity of most rock materials.

ORIENTING CORING

The knowledge of core orientation in the reservoir can be important in the structural and sedimentological study of
the reservoir. Oriented coring refers to cutting a core which is marked by narrow grooves along its length and
providing directional survey data referenced to these grooves. The marking of the core is accomplished by the
knives of a scribe shoe which is located at the mouth of the core barrel. The reference knife in the scribe shoe is
aligned with the survey instrument at the start of the survey. This alignment should not change during the coring
but in practice may easily become misaligned due to vibration or torque. The groove markings are often also used
in non-oriented core taking for core fitting and alignment after the retrieval of the core.

The traditional method used to obtain survey data was a magnetic multishot system which takes photographs of a
compass on a continuous strip of film. This tool was located directly above the core barrel inside a non-magnetic
housing (drill-collar) and was subject to mechanical and hydraulic vibrations. Coring and circulation need to be
stopped to obtain proper photographs of the compass which often caused loss of core and occasionally caused the
assembly to become stuck in the hole.

A more modern method makes use of an electronic multi-shot device (EMS) which is capable of taking a very large
number of measurements without the requirement to stop coring/circulating. The system typically makes a
measurement every five centimetres and allows very accurate verification of the scribe line. There are generally no
temperature limitations for the system (up to 260°C). The most recent orienting methods rely on lasers instead of
the standard optical techniques for achieving a perfect alignment of the knives relative to the survey tools.

A drawback with oriented coring is that the cutting of a groove on the core surface significantly increases the
friction at the point entry of the core into the core barrel. This may lead to jamming and breakage of the core.
Also, if the formation is unconsolidated or fractured the scribe lines may be improperly marked and it may be
impossible to reconstruct a continuous trace on the recovered material. In that case it may be very difficult or
impossible to assign an orientation to each piece .

 
WIRELINE CORE BARREL

This special core barrel permits drilling or coring as required while

the core barrel remains in the hole. The core head accepts a
retrievable plug, which can be placed by dropping it through the
drill string under its own weight. This transforms he core head
into a drill bit (see Figure 4.1.47). As required, the drill plug can
be removed for either coring or inspection by retrieving it through
the drill string with a wireline overshot. For coring, an inner barrel
and bearing assembly are then dropped through the drill string
and, when the core is cut, retrieved with the overshot. This allows
drilling and coring to be alternated at will.

It is possible to run slim-hole logging tools through the coring bit

and in lost circulation or kick situations lost circulation material or
cement can be pumped through the core barrel. The diamond Drilling mode Coring mode
coring heads available for wireline coring restrict its application to Figure 4.1.47 : A wire-line core head/barrel
medium hard to hard and abrasive formations.

1.9.5 CORING PROCEDURE

Like all diamond bits, core-heads are easily damaged by junk in the hole, therefore, every precaution should be
taken to clean the hole before coring is started and to keep it free of junk during the coring operation. Either a junk
sub should be used on the last drilling bit, or a junk basket should be run before going in to core.

Trips in and out of the hole have to be performed in the same manner as with any diamond drilling bit. Going in
the hole the driller should be very careful not to run into ledges or tight places too fast. Especially the first time,
running in with a full size diamond bit should be done slowly to preventing jamming the bit in a tight spot.

When near the bottom, the bit should be stopped about a foot off bottom and the well should be circulated for
fifteen minutes to clean the inner barrel. Finally the bit should be lowered slowly to bottom until all fill has been
circulated from the well bore. The drill string should be raised to where kelly can be broken from the drill string and
spaced out with pup joints so that the full length of the kelly is above the rotary when on bottom. This is done in
order to obtain the maximum length of core before breaking it to add a single.

The ball is dropped into the drill string, the kelly or top drive made up and circulation re-established. Sufficient time
must be allowed for the ball to reach its seat in the bearing assembly prior to coring.

For each size of diamond bit-core barrel combination the pump volume should be carefully controlled to clean the
diamonds but avoid eroding the core.

With the desired fluid volume and rotating at about 30 rpm the core head is slowly lowered to bottom until about 9
kN (2000 lbs) of weight has been applied. The core head is allowed to cut its profile into the bottom under these
conditions for about ten minutes and then the weight is gradually increased to 13.5 kN (3000 lbs). The rotary
speed and weight on bit should not then be changed for the first few inches as it is very important to get the core
started up in the inner barrel correctly. After that the rotary speed may be increased to the required rate and the
weight on the core head gradually ncreased until it is drilling off at a steady rate. Even feed-off of the drilling line
from the drum to keep a constant weight will help the core head to drill off at a steady rate and will aid in obtaining
the maximum core recovery with longest bit life.

If a fractured core should jam in the barrel, it is essential that the barrel be pulled out of the hole and the core
removed from the inner barrel. When a core is wedging in the inner barrel the drilling weight will be transferred
from the bit to the inner barrel, the bearings, and the core. If an attempt is made to continue coring under these
conditions, the inner barrel, bearings, core catcher and core head may be damaged, and core recovery will be poor.

After several inches of core have been cut, and if the pump rate is kept constant, the pump pressure should remain
constant. Any variation in pump pressure is an alarm signal and, if the pressure does not return to normal but
continues to change, the bit should be picked off bottom. The following tabulation gives possible causes for these
pressure fluctuations:
In most cases the core barrel should be pulled out and checked.

If circulation is stopped for any reason, it is imperative that the rotary be stopped immediately and the bit picked
off bottom, otherwise the bit will be damaged and the core barrel may become stuck.

Weight on bit

1. Weight is the single most important factor in achieving a satisfactory core recovery at a reasonable
penetration rate. The best weight is a function of the formation type and can vary between 27 kN and 67
kN (6,000 lbs and 15,000 lbs) for a given bit size. It should be correctly adjusted at the initiation of
coring. Weights in excess of 90 kN (20,000 lbs) are rarely required.
2. Sufficient drill collars and full-size stabilisers both on the core barrel and in the drill string assembly are
recommended to give the necessary weight on the bit and reduce bit wobble.
3. An accurate weight indicator is very important. Most indicators are affected by temperature change and
this should be taken into account while coring.

Rotary speed

The manufacturer's specification should be followed.

BREAKING THE CORE

After cutting the desired length of core, the brake is tied down and the bit is allowed to undercut the core for ten
minutes or longer depending on what the penetration rate had been. Then the rotary is stopped and the core barrel
is slowly pulled off bottom with the pump on. Most cores break off readily giving a slight flicker of the weight
indicator needle.

The harder cores may require the above procedure to be repeated twice or more before they fail.

When drilling with a conventional kelly the core has to be broken to make a connection every thirty feet. When a
top drive is in use it is not necessary to break the core to make a connection, giving the advantage that a core can
be cut, without breaking, that is the length of the made up core barrel - 120 ft is common. This is an advantage as
it is sometimes difficult to restart the coring operation after a connection is made because the core is firmly held by
the core catcher and it may be difficult to free it

Final precautions

In order to avoid serious trouble several operating conditions should be watched carefully.

 Any change in pump pressure, either increasing or decreasing, which does not quickly return to normal,
should be checked to determine the cause.
 Any backlash in the rotary table which might be caused by binding of the bit or core barrel in the hole
should be checked immediately.
  If the diamond bit does not drill off at all, even after adding several thousand pounds over the normal
coring weight, the cause should be determined.

If, after a careful check, the cause for situations cannot be determined, it will be necessary to pull the core barrel
out of the hole in order to check the drill pipe, the core barrel and the bit.

CORE RECOVERY

To recover the core a core-clamp assembly is attached to the inner barrel to hold the core and stop it from
dropping. The inner barrel and core are raised while holding the core with the core tongs. The core catcher sub and
core support pin are removed (see Figure 4.1.48a) and the inner barrel lowered until it rests on the floor. With the
core standing on the rotary table, the inner barrel is raised, while the core-clamp assembly slides along the core.

When three or four feet of core is exposed the core is held with the clamp assembly and the exposed section
broken off below the clamp (see Figure 4.1.48b). This is removed and the procedure repeated until the entire core
is removed. If a highly fractured core tends to stick in the barrel, it is advisable, with the inner barrel resting on the
table, to tap the lower end of the inner barrel until the core starts moving. If this is not successful, the inner barrel
should be laid down on the catwalk and a piece of 2" pipe used to push the core out of the barrel. If that fails, the
core should be pumped out.

Keep your hands and feet away from below the bottom of the inner barrel while recovering the core, a falling core
could cause serious injury.

Special core recovery techniques are required if a gas bearing formation has been core. If the gas is not allowed to
bleed off slowly during the trip out of the hole there will still be a very high pressure inside the core barrel when it
reached surface !

Even more specialised techniques are required if there is a possibility of the core containing H 2S.

The whole point of taking cores is for geological and petrophysical information. It is thus essential that when they
are recovered they are packed and boxed in such a way that reservoir fluids are not lost and that the sequence and
orientation of all the recovered pieces is known. If it is known that a piece is missing it should be indicated by
placing a wooden spacer in the box.

 
Figure 4.1.48a : Removing the core-
Figure 4.1.48b : Retrieving the core
catcher

 
Hole openers & under-reamers

As mentioned in the general introduction of Topic 1, both of these pieces of equipment are used to drill a larger
hole where a smaller hole already exists. The difference is that a hole opener has fixed cutting arms so that, like a
normal bit, it can only pass through a string of casing with a larger ID than the size of hole it will drill. An under-
reamer, as suggested by the name, is used to drill below a string of casing which has a smaller ID than the size of
hole to be drilled. It achieves this by using retractable cutting arms. Due to the necessity for hinges an under-
reamer is never as robust as a hole opener.

1.10.1 HOLE OPENERS

A hole opener is used in circumstances where the successive hole sections could have been drilled using normal
drilling bits, but where for one or another reason a reduced diamer hole section known as a pilot hole was
required at a particular depth.

Possible reasons are:

 because a core was required

 because the best possible quality of wireline logs was required. The response of some logging tools is
inversely proportional to the hole size.
 while drilling through what may be a pressure transition zone when pressures and reservoir depths are not
known with confidence. Circulating bottoms up takes less time in a small hole, and if there should be a
kick it is easier to control. Once the required casing setting depth has been reached with no problem using
a pilot hole the full size hole can be drilled quickly with confidence.
 because it is easier to control the trajectory of a smaller hole

A hole opener is normally used after the entire pilot hole has been drilled to the depth required. It is run with a
bull-nose that is a closed rounded plug at the lower end, or one joint below it to give flexibility. The bull-nose
enters the pilot hole and guides the hole-opener along it; there is thus no need to steer the hole opener and no risk
of it drilling away from the pilot hole.

A hole opener may also be required if the diameter of the hole has been reduced by the formation expanding into it
so that a full size bit can no longer pass. This may happen in sections containing plastic shales or salt.

The majority of hole openers still use roller cones as cutters, with either steel teeth or tungsten carbide inserts as
appropriate for the formation. These are available from 83/8" (6" pilot hole) to 48" (171/2" pilot hole). The number
of cones depends on the size of the hole - it varies from three to eight. Figure 4.1.49 shows a hole opener with a
range the cutter cones which can be used with it.

Hole openers are also available with fixed, PDC, cutters but only in sizes up to 181/2". Figure 4.1.50 shows such a
tool. This one also has cutters mounted in such a way that if the formation squeezes in above the tool it can cut in
an upwards direction.
Figure 4.1.49 : A hole opener with a selection of cutter cones

For optimum performance using any hole opener in any formation, the following consideration are important:

 Soft formations will normally respond better to higher rpm andlower WOB, while hard formations require
higher WOB and less rpm.
 If fractured formations are encountered and rough drilling conditions are noticed, adjust drilling
parameters - rpm and WOB - to avoid bouncing and breakage of cutters.
 Use sufficient flow rate to-obtain good bottom-hole cleaning and efficient cuttings removal.
 Cutter selection must be based on the same considerations as for bits.
 Hold rpm's at the lowest practical level when using large hole openers. This is because the cutters on the
outer periphery (larger cutters) are running at a higher velocity than cutters of smaller diameter tools.
 Always stabilise the lower end of the hole opener to prevent it from rotating off-centre. A bullnose pilot or
a rock bit approximately 1/2" smaller than the pilot hole will suffice.

As an alternative to a hole-opener, especially in hole

sizes of 171/2" and less, it is common practice to
use a normal bit as a hole opener. In this case there
is no bull nose to guide the bit along the pilot hole
and one hopes (!) that the bit will follow the path of
least resistance, which is where the rock has already
been cut away and where it has probably been
weakened around the actual hole. In a medium to
hard formation this technique will usually work.
There is of course no guarantee, and it is therefore
necessary to measure the deviation of the well at
frequent intervals to check that it is following the
same trajectory as the original hole. In a soft
formation it is very likely that the bit would start
drilling a new hole, which is an undesirable
situation, and a hole opener is the only real option.

Figure 4.1.50 : A hole opener with PDC cutters

1.10.2 UNDER-REAMERS

An under reamer is used where it is geometrically impossible

to drill the required size hole with a full size bit. There are
several possible reasons:

 A sequence of closely fitting casing strings are

planned. One casing may just be able to fit inside
another but may not fit into a hole drilled by a bit
which will also just go through that first string. Even if
it will just pass, assuming no irregularities, there will
not be enough clearance to cement the string
properly. The solution is to under-ream the hole for
the second casing string.
 If it is known that a plastic formation will start
"squeezing in" in the time between drilling it and
running the casing, salt for example. The answer may
be to drill an extra large hole through it.
 A hole may have to be enlarged through the reservoir
so that an external gravel pack can be placed without
restricting the well bore.
Figure 4.1.51 : An under-reamer
 

Under-reamers used to have rolling cones on extending arms, but they are now almost universally fitted with PDC
cutters. They also tend to be multi-purpose tools with different arms fitted for different uses. Figure 4.1.51 shows a
hole opener fitted with extended reach arms. Figure 4.1.52 shows in diagrammatic form how the same body can be
fitted with standard under-reamer arms, extended reach arms or stabiliser arms. Pictures of the arms are shown
alongside the relevant diagram.

The arms are extended by increasing the circulation pressure, and hence the
pressure drop across the tool, beyond a critical value

An under-reamer can be run in a pilot hole with a bull-nose as described for

the hole opener, but it can also be run in combination with a smaller drilling
bit so that the pilot hole and the full size hole are cut in one run. In that case
a balance has to be made between the work done by the bit and that done
by the under-reamer. Similarly the nozzle sizes have to be matched bearing
in mind the pressure drop required to open the arms. This technique has
disadvantages because neither tool is working at full efficiency, but it also
has two advantages. One is in floating drilling. If the string is heaving up and
down with the vessel and there is only a bullnose in a pre-drilled hole below
the under-reamer, any impact loads due to the string hitting the bottom will
act through the expanded cutters, which are relatively weak components. If
the two hole sections are being drilled simultaneously any impact loads will
be shared by the much stronger bit. The other advantage is that it can often
(but not always) save time.

Figure 4.1.52 : Under-reamer

possibilities

It may be useful to be able to stabilise the string in the under-reamed section of hole, especially in the case of a
deviated hole. For this reason underreamers are available fitted with stabiliser arms instead of cutters.
Appendix 1

The economics of a bit run

How well a bit drills depends on several factors, such as the condition of the bit, the weight applied to it, and the
speed with which it is rotated. Also important for bit performance is the effectiveness of the drilling fluid in clearing
cuttings produced by the bit when drilling on bottom.

The aim of drilling is to:

 make hole as fast as possible and along a planned well bore trajectory by selecting bits which produce
good penetration rates.
 run bits with a long working life to reduce tripping frequency .
 use bits which drill a full-size or full gauge hole during the entire time they are drilling on bottom.

The choice of bit depends on several factors.

 the hardness of the formation to be drilled.

 the abrasiveness of the formation.
 the price of the bit.

In the shallower part of the hole only one or two bits are needed before the drill string is pulled for logging or
running casing. Often one bit is sufficient to make the hole in which the conductor is to be set. As formations near
the surface are often very soft one bit may even be re-useable for several wells. In this case an expensive bit with
a long service life is not cost effective because no tripping time is saved. In the deeper part of the hole, however, it
is more likely that several bits have to be used between casing setting depths and an expensive bit which can
reduce the number of trips will be more cost effective than a cheaper bit which needs to be replaced more often.

Getting the highest possible footage from the bit cuts down total bit costs and minimises the number of trips
needed for bit changes. However, continuing to use a bit that is still drilling, but slowly, is false economy as at a
certain moment the drilling time gained by changing to a new bit will be greater than the time spent on an
additional trip. The overall objective is to minimise the sum over the entire well of the costs of the bits and the rig
time for making hole/tripping.

PERFORMANCE EVALUATION

A "real time" evaluation of bit performance is necessary to determine the ongoing cost per unit depth drilled. This
allows the operator to:

 establish when to pull the bit.

 compare bit performances.
 work as economically as possible.

There are two trends affecting the unit operating cost of a bit.

 If the penetration rate is reduced by bit wear, the operating cost per unit depth will increase.
 Bit and trip cost per unit depth decreases as more progress is made between trips.

The combination of these two trends has an optimum value, where the total cost per unit depth is lowest, see
Figure 4.1.53.
Figure 4.1.53 : Composite cost/unit depth

To establish in practice when a bit is no longer drilling economically the cost per unit depth need to be calculated
every hour using the following formula:

Example of bit evaluation

Bit cost : $ 1500

Rig cost : $ 1600/hour

Trip time : 5 hours

 Referring to the figures shown in Table 4.1.9, the cost per unit depth decreases until the 9th hour. In such
a case the bit should be pulled after the 10th hour when cost/unit depth begins to increase.
 It is important to use actual time on bottom only, deducting for all delays, connection time, etc.
 When making the decision to pull a bit, any available information regarding imminent formation changes
should be borne in mind.
 Other considerations should be how much further there is to drill to casing-, coring-, or logging point. It
would be beneficial to drill just a few metres or feet more, even at a relatively slow rate, but save another
bit run. The economic evaluation depends on several factors as well as the actual penetration rate.
Appendix 2

Bit classification

GENERAL

Formations vary greatly in hardness, abrasiveness and strength, all of which have a considerable effect on bit
performance. If there were no differences in rock formations one type of bit only would be required, using a
standard bit weight, rotary speed and pump pressure to drill at the maximum rate. Unfortunately such a situation
does not exist and many types of bit are required for the various types of formation with different combinations of
properties.

Changing the bit every time the formation changes is, however, also impractical. A compromise thus has to be
made, and a bit that performs reasonably well in as wide a range as possible of conditions is selected.

Given the many different types of formation for which bits have been designed, compounded by the different
approaches of the different bit manufacturers, each of whom has his own specific nomenclature, the choice of bit in
given circumstances is not easy. It is also evident that every drilling engineer and every driller cannot be
personally familiar with all the bit types produced by every manufacturer. In order to simplify the bit selection
process as much as possible an industry wide classification scheme was introduced so that the manufacturers could
indicate the type of service for which each bit was intended. In principle all bits with the same classification code
can be used in the same formation, no matter who manufactured them. Thus, it is not necessary to remember that
if a Hughes JG4 bit performs well in a particular formation, then a Reed HP21G bit, a Security M44NGF bit and a
Smith FVH bit are probably the best bits from those manufacturers' respective ranges for that formation. It is only
necessary to remember that bits classified 217 are suited to that particular formation.

It must be emphasised that the classification system does not imply that identically classified bits from each
manufacturer will perform identically. On the contrary, there will always be differences as each strives to produce a
better product than the others. And for reasons which no-one will be able to identify there will always be one bit
better suited to the formation than the others which appear very similar. It is still a question of trial and error to
find the single best bit for the particular circumstances.
There are also design parameters which are not reflected in the classification scheme. For example, of two bits
designed to drill the same soft formation one may be optimised to maximise the penetration rate at the cost of a
limited service life and some fragility (ideal for short intervals in a homogeneous formation), while another may be
optimised to be able to cope with thin intercalations of a hard formation without breaking the teeth, but at a cost of
a slight reduction in penetration rate. For this reason you will find that the manufacturers very often have different
bit types with the same IADC classification.

THE CLASSIFICATION SCHEME

There are in fact two classification schemes, one for roller cone bits and one for fixed cutter (diamond) bits. The
current versions of each were introduced in 1987 jointly by the SPE (Society of Petroleum Engineers) and the IADC
(International Association of Drilling Contractors).

The classifications schemes both make use of four characters. For roller cone bits this consists of three numbers
and a letter, whereas diamond bits use a letter and three numbers (diamond bits may also use a letter as the third
character). The basis for the classification is however slightly different as explained below, even though the end
result is the same.

Roller cone bits

The system is based primarily on the formation characteristics with the first two characters indicating the hardness
of the formation for which the bit is designed/suited, and also indicating whether it has milled teeth or tungsten
carbide inserts. The second character is used to sub-divide the hardness classes defined by the first character.

The third and fourth characters indicate the general features of the bit itself, such as the type of bearing, whether
there is gauge protection or not (which also reflect the type of formation for which it is intended) and whether the
bit has any special features or whether it is intended for any special applications, such as air drilling.

The significance of these four characters is summarised in the boxes overleaf.

As an example a bit classified 6.3.5.Y would be a tungsten carbide insert bit with sealed roller bearings and gauge
protection. It would have conical inserts intended for hard formations.

ROLLER BIT CLASSIFICATION SCHEME

Diamond bits

The classification system of diamond bits is based much more on the construction and geometry of the bit than on
the explicit formation type. For this reason the manufacturers sometimes quote not only the classification code for
the diamond bit itself, but also the code for the tri-cone bit which would be appropriate for the same formations.

The first character indicates the cutter type and the body material. The second character indicates the profile of the
cutting face of the bit. The third character indicates the design of the bit with regard to the flow of drilling fluid
across its face. The fourth and last character indicates the size and density of the cutters.

The meanings of the four characters are shown in the boxes opposite.

CHARTS

Each bit manufacturer produces a classification chart for tri-cone bits showing how their own and their competitors'
bits fit into the system. It should however be realised that they tend to provide the greatest information on their
own brand of bit. A selection of classification charts from different manufacturers will give an adequate choice. The
roller cone bits of four major manufacturers and one smaller one have been listed in the tabulations on the
following pages of this Appendix, giving the manufacturers own type codes with the bits arranged according to the
IADC classification

Equivalent classification charts for diamond bits do not exist, probably because the designs, and thus the type
names, are changing much more rapidly than tri-cone bits, and any comparative chart would become out of date
as soon as it was printed. The choice of diamond bits is made from the individual manufacturers catalogue and
often in discussion with his representative.
 Appendix 3

Dull bit grading

THE DULLNESS GRADING SYSTEM FOR USED BITS

A critical aspect of working with drilling bits is the saving of information. Every time a bit is run it adds to the
information about how that type of bit performs in the formation it is drilling (which may be, but is not necessarily,
the formation that the driller thought he was going to penetrate). This is extremely valuable information and must
be saved. The driller needs it in order to choose which bit to use the next time that formation is to be drilled; the
bit manufacturer needs it in order to carry out a continuous process of improvement of his designs.
The following information is saved:

 Distance drilled
 Time taken
 Averaged drilling parameters (WOB, RPM, Pump speed)
 Average drilling fluid properties (type, density, viscosity, fluid loss)
 The condition of the bit when pulled.

The first four of these are objective measurements which can be obtained by reference to the standard daily
reports. The condition however is a very subjective assessment made by the driller. In order to provide a measure
of consistency between bit condition reports made by all drillers, world wide, a grading system has been
introduced. This is the IADC (International Association of Drilling Contractors) system which applies to roller cone
bits, diamond bits and core heads. It uses code characters for describing six categories of wear, grouped into the
three sections cutters, bearings and gauge, and adds two codes for remarks.

If a standard bit report form is being completed there are eight boxes in which the individual codes are entered. If
the bit condition is being discussed, or described in "free-format" text the three sections containing the description
of the wear are each identified by a letter, or in one case a phrase. This will be clarified in the following paragraphs
and in the example at the end of this Appendix.

The cutting structure:

Four codes are used to describe the cutting structure - the teeth/inserts on a roller cone bit, or the cutting
elements of a diamond bit. These are entered into the first four boxes of a standard report, otherwise they are
identified by the letter "T" for roller cone bits or "cutting structure" for diamond bits.

The first two codes define the wear on the cutters using a scale of 0 to 8, where 0 represents no wear and 8
indicates that no usable cutting structure is left. The first code represents the average wear of the cutters in the
inner two thirds of the bit radius, the second refers to the average wear of those in the outer third. Note that in the
case of core bits the "radius" is to be interpreted as the distance from the ID to the OD of the core head, i.e. in
Figure 4.1.60 the centre line shown would be the ID of the core head/OD of the core.

Figure 4.1.59 : Wear of milled teeth Figure 4.1.60 : PDC cutter wear

For a roller cone bit the worst cone is taken for the grading

The wear of milled teeth on roller cone bits and PDC cutters on diamond bits is graded in eighths of the original
tooth height - see Figures 4.1.59 and 4.1.60 and Table 4.1.13.
In figure 4.1.60 the first two codes would be (0+1+2+3+4)/5=2 and (5+6+7)/3=6.

For roller cone insert bits and for cutting element wear on natural diamond and TSP bits the number of inserts or
diamonds broken or missing is more relevant than the actual wear on the individual inserts or cutting elements. It
is a combination of wear and missing inserts/diamonds which determines the amount of wear to be reported. Some
experience is required to do this correctly.

The third box is for the code describing the primary wear characteristic of the cutting structure, chosen from the
list in Table 4.1.14.
 

Figure 4.1.61shows how "tooth" wear terms are applied to PDC cutters, and a selection of photographs illustrating
several of these wear characteristics for these and other types of cutter is presented at the end of this Appendix.

The fourth part of the cutting structure code defines the basic location of the wear on the bit. This can range from a
specific part of the bit face to the entire bit. The codes are chosen from the list given in Figure 4.1.62 and in the
case of a tri-cone bit the number(s) of the affected cone(s) is/are added.

Figure 4.1.61

Figure 4.1.62

The bearing/seals

The letter B is used to identify the code used for bearing/seal reporting. If a standard report form is being used the
code is entered into the fifth box.

If no seals are used then the bearing wear is reported on a scale of 1 to 8, as for the teeth, with 0 representing "as
new" condition, and 8 indicating that all bearing life has been used up (i.e. the bearings have failed). The condition
of the worst bearing is reported. See Table 4.1.15.
For sealed bearings, only the condition of the seals is reported with either E indicating that the seals are still
effective or F indicating that the seals have failed.

For fixed cutter bits without bearings or seals the code "X" is entered into standard report forms.

The gauge.

The letter G is used to identify the code used for reporting the condition of the bit gauge. If a standard report form
is being used the code is entered into the sixth box.

The reduction in diameter is measured in millimetres or in sixteenths of an inch. If bit is full gauge an "I" indicates
that it is in gauge. Working in SI units a "1" indicates that it is 0 to 1 mm under gage. A "2" indicates that it is 1-2
mm under gage. A "3" indicates that it is 2-3 mm under gage, and so on.

In oilfield units the wear would be reported as "1/16" indicating that the bit is zero to 1/16" under gage. "2/16"
would indicate that it is 1/16" to 1/8" under gage, etc.

Gauge wear can be determined by using a ring gauge and ruler. This should be done with the bit standing on its
cones so that they take up the position they had when cutting the hole.

There are two methods used to measure the wear. In the first, most common, method the ring gauge is pulled
against the gauge points of two cones, and the space between the ring and third cone is measured (Figure
4.1.63a). Usually, this measurement is used for the amount of wear; however, to be exact, the measurement
should be multiplied by 2/3.

In the second method, the bit is centred in the gauge ring and the ruler is used to measure the distance from the
ring to the outermost cutting surface (gauge surface) (Figure 4.1.63b). This measurement must be multiplied by 2
to give the loss in diameter and thus the total amount of wear. Offset bits should be measured at one of the
maximum gauge points as shown in Figure 4.1.63).

 
Figure 4.1.63 : Gauge wear measurement

Remarks

In the first of the two places available for remarks at the end of the wear code more information is given on the
state of the cutting structure and flow passage(s), chosen from the same list as for the primary characteristic of
tooth/cutter wear.

In the last place the reason for pulling the bit is given. This is taken from the list in Table 4.1.16.