DIAMOND BIT CLASSIFICATION

Two types of diamond bits are used for special applications where their cutting action is most efficient. These are natural diamond and the PDC (Poly-crystalline Compact).

11.3.1. Natural Diamond Bits

Natural diamond bits are constructed with diamonds embedded into a matrix and are used in conventional rotary, turbine, and coring operations. Diamond bits can provide improved drilling rates over roller bits in some particular formations and all the diamond bit suppliers provide comparison tables between roller bit and diamond bit performance to aid users in bit selection based on economic evaluation.

Some of the most important benefits of diamond bits over roller bits are:

• Bit failure potential is reduced due to there being no moving parts.

• Less drilling effort is required by the shearing cutting action compared to the cracking and grinding action of the roller bit.

• Bit weight is reduced, therefore deviation control is improved.

• The low weight and lack of moving parts make them well suited for turbine drilling.

11.3.2. PDC Bits

PDC or Stratapax bits were introduced in the 1970s and features the greater abrasion resistance of the diamond complimented by the strength and impact resistance of cemented tungsten carbide.

The advancement in technology in PDC design and performance in recent years has been significant and there is now many manufacturers with wide ranges of bits now available.

Due to the diversity of bits and bit features available, there is no IADC classification system similar to roller bits but simply a code to provide a means of characterising the general physical of fixed cutter drill bits.

11.3.3. IADC Fixed Cutter Classification

To cater for the wide range of fixed cutter bits including natural diamond and PDC, IADC introduced the following classification system.

The classification system consists of a four character code Code 1 - Cutter Type and Body Material (D, M, T, S, O) Code 2 - Bit Profile (1-9)

Code 3 - Hydraulic Design (1-9) Code 4 - Cutter Size and Density (1-9)

Code 1 Code 2 Code 3 Code 4

Cutter Type & Body

Material Bit Profile Hydraulic Design Cutter Size and

Density Table 11.D - IADC Fixed Cutter Classification Code

Code 1

The subgroup classification is simply a five letter designation categorising the type of cutter and body material.

Group Letter Cutter Type and Body Material

D Natural Diamond Matrix Body

M PDC Matrix Body

T TSP Matrix Body

S PDC Steel Body

O Other

Table 11.E – Code 1 Cutter Type and Body Material Code 2

The code numbers (1-9) categorise the bit profile by shape.

Code 2 Bit Profile

1 Long Taper Deep Cone

2 Long Taper Medium Cone

3 Long Taper Shallow Cone (parabolic)

4 Medium Taper Deep Cone

5 Medium Taper Medium Cone

6 Medium Taper Shallow Cone (rounded)

7 Short Taper Deep Cone (inverted)

8 Short Taper Medium Cone

9 Short Taper Shallow Cone (flat face)

Table 11.F– Code 2 Bit Profile Code 3

The code numbers (1-9) describe the hydraulic features.

Changeable Sets Fixed Ports Open Throat

Bladed 1 2 3

Ribbed 4 5 6

Open Faced 7 8 9

Table 11.G - Code 3 Hydraulic Design

Code 4

The code numbers (1-9) categorise the cutter size and cutter material.

Light Medium Heavy

Large 1 2 3

Medium 4 5 6

Small 7 8 9

Table 11.H - Code 4 Cutter Size and Density

An example bit code would then be M442 equates to a PDC bit with matrix body, medium taper-deep cone, changeable jets-ribbed design with large size cutter of medium density.

11.4. BIT SELECTION

Selecting the correct bit for the anticipated drilling conditions requires an evaluation of numerous parameters. Since the variety of bits available, outlined in the previous sections, is much wider with the introduction of innovative bit designs and the improvement in existing designs, the bit selection process is now much more complicated than it was previously.

However there is still a simple guidelines that can be used to increase drill rates and, hence reduce drilling costs.

The parameters involved in the selection of drill bits are:

• Formation hardness

As can be seen from the previous IADC bits are generally categorised by the hardness of the formation they can drill, however these classifications are vague but unfortunately no superior classification method exists.

Some formations such as ‘medium to hard’ are sometimes wrongly defined because they had previously experienced low drilling rates although this was actually due to wrong bit selection or operating parameters used.

Where a number of bits can be used, say to drill a soft formations, the bit selected will depend on other conditions such as mud type and hole size. Therefore, bit selection in soft formations becomes a matter of defining the conditions that produce the lowest drilling costs.

Bit action in hard and abrasive formations is by failure in the compressive mode and as a result bits which use shear action are not very successful. In this case, roller bits in IADC code range 6-1-7 or higher are usually more successful as they have been designed for abrasive wear which may be very damaging to shear failure action bits.

Formations with sticky characteristics, often resulting from clay rocks that are hydratable, the cuttings stick to the teeth or bit structure and impede drilling efficiency. Bits designed for sticky formations have a high degree of teeth inter-fit and hydraulics such as centre jetting capabilities. PDC, diamond and short tooth roller cone bits have been particularly unsuccessful unless when PDCs are used with oil based mud.

In general, PDC bits drill faster than mill tooth or diamond bits in soft to medium-soft rocks unless they are sticky. This is substantiated by numerous results test reports.

11.4.2. Mud Types

Oil based muds often reduce the drilling rates with roller cone bits whereas PDC and diamond bits are not effected. Oil based mud is actually believed to enhance the performance of PDC bits since they inhibit clay hydration and stickiness.

Air drilling almost certainly requires the use of roller cone bits as air cannot provide sufficient cooling as liquids do, therefore causing bit failure. Cone bits are available with internal porting to the roller bearings keeping them cool enough and, although PDC and diamond bits do not have ant moving parts, the matrix and blade structures becomes weak and break. Diamonds themselves will fail around 750^oC for polycrystallines and 1,200^oC for natural.

11.4.3. Directional Control

Directional control is affected by a number of factors including these relating to drill bits. The factors affecting directional control are:

• Method of drilling

• BHA design

• Type of bit

• Rotary bit cone offset, number of cones, cutting structure on the cone

• Bit weight

Rotary drilling operations are inclined to right-hand walk. This tendency is increased when using roller bits are used as cone offset from the bit centre increases. The advantage of increased drilling rate when using cones with higher offsets must be balanced with the difficulty in maintaining directional control.

Turbine drilling may have a tendency to left-hand walk. This is controlled by the turbine used, bit gauge length, and BHA stabilisation.

Some bit manufacturers have developed two and four coned roller bits purely for directional cone purposes. These are include in the IADC codes under special feature #8, e.g. 1-2-8 is a soft bit for directional control.

Roller bits are also available with a special cutting structure that are caused by formation dip which normally induces movement towards the dip. The special feature is outside teeth that dig into a dipping formation thus preventing the movement towards the dip.

High bit weights tend to increase directional control problems and, vice versa, low bit weights help maintain straight hole at a penalty in reduced drilling rate. Due to this PDC bits with their relatively lower bit weights and no cones, hence cone offset problems are favoured.

11.4.4. Drilling Method

The means of turning the bit with either the rig’s rotary system or downhole motor does not place any restriction on bit selection. However, in general in deep wells, PDC bits are preferred when using surface rotary systems as reduced weight on bit reduces torque due to bit and wall friction which can be significant.

Due to turbine drilling efficiency, bits with long life expectancies should be used such as PDC, diamond and journal bearing insert bits.

11.4.5. Coring

Bits used for coring must be designed so that it minimises flushing of the formation fluids from core by the mud. PDC or diamond bits are both used for coring operations and are selected by using the previous parameters outlined.

11.4.6. Bit Size

Roller bits are available off-the-shelf for almost all sizes between the range of 3³/8” – 26” in almost every type, cutting structure and jetting system. PDC and diamond bits are not available off-the-shelf as rotary bits in sizes over 15”.

In deep wells with small holes, i.e. 4” or 5”, the PDC bits have much better performance as they have no moving parts as rotary bits which have high failure rates due their small bearing areas.