Drilling Bits 04 - King Petroleum...A system, known as the Dull Bit Grading System, has been devised by the International Association of Drilling Contractors (IADC) to facilitate this

Drilling Bits! 04An Overview!

Introduction to Well Engineering - 04 - Drilling Bits 1

Contents

1. Introduction 4

2. Types Of Drilling Bit 5

2.1 Drag Bits 5

2.2 Roller Cone Bits 6

2.3 Diamond Bits 7

2.3.1 Natural Diamond Bits 7

2.3.2 PDC Bits 8

2.3.3 TSP Bits 8

3. Bit Design 9

3.1 Roller Cone Bit Design 9

3.1.1 Bearing Assembly 9

3.1.2 Cone Design 12

3.1.3 Cutting Structure 14

3.1.4 Fluid Circulation 15

3.2 PDC Bit Design 17

3.2.1 Cutter Material 17

3.2.2 Bit Body Material 19

3.2.3 Cutter Rake 20

3.2.4 Pro!le 20

3.2.5 Cutter Density 22

3.2.6 Cutter Exposure 22

3.2.7 Fluid Circulation 22

4. Bit Selection 23


4.2. Fixed Cutter Bits 27

5. Rock Bit Evaluation 30

6. Bit Performance 35


6.1.1 Weight on Bit 36

Introduction to Well Engineering - 04 - Drilling Bits ! ! 2

6.1.2 Rotary Speed 38

6.1.3 Mud Properties 39

6.2 PDC Bits 41

6.2.1 WOB/RPM 41

6.2.2 Mud Properties 41

6.2.3 Hydraulic Efficiency 41

Introduction to Well Engineering - 04 - Drilling Bits ! ! 3

1. Introduction

A drilling bit is the cutting or boring tool which is made up on the end of the drill-string (Figure 1). The bit drills through the rock by scraping, chipping, gouging or grinding the rock at the bottom of the hole. Drilling fluid is circulated through passageways in the bit to remove the drilled cuttings. There are however many variations in the design of drill-bits, and the bit selected for a particular application will depend on the type of formation to be drilled. The drilling engineer must be aware of these design variations in order to be able to select the most appropriate bit for the formation to be drilled. The engineer must also be aware of the impact of the operating parameters on the performance of the bit. The performance of a bit is a function of several operating parameters, such as: Weight On Bit (WOB); Rotations Per Minute (RPM); mud properties; and hydraulic efficiency. This chapter will present the different types of drill-bit used in drilling operations and the way in which these bits have been designed to cope with the conditions which they will be exposed to. An understanding of the design features of these bits will be essential when selecting a drill-bit for a particular operation. Since there are a massive range of individual bit designs the drill-bit manufacturers have collaborated in the classification of all of the available bits into a Bit Comparison Chart. This chart will be explained in detail.

When a section of hole has been drilled and the bit is pulled from the well-bore the nature and degree of damage to the bit must be carefully recorded. A system, known as the Dull Bit Grading System, has been devised by the International Association of Drilling Contractors (IADC) to facilitate this grading process. This system will also be described in detail.

In addition to selecting a bit, deciding upon the most suitable operating parameters, and then describing the wear on the bit when it has drilled a section of hole, the drilling engineer must also be able to relate the performance of the bit to the performance of other bits which have drilled in similar conditions. The technique used to compare bits from different wells and operations will also be described.


2. Types Of Drilling Bit

There are basically three types of drilling bit (Figure 1).

Drag Bits.

Roller Cone Bits.

Diamond Bits.

Figure 1 - Types of drilling bit

2.1 Drag Bits

Drag bits were the first bits used in rotary drilling, but are no longer in common use. A drag bit consists of rigid steel blades shaped like a fish-tail which rotate as a single unit. These simple designs were used up to 1900 to successfully drill through soft formations. The introduction of hard-facing to the surface of the blades, and the design of fluid passageways, greatly improved its performance. Due to the dragging/scraping action of this type of bit, high RPM and low WOB are applied.

The decline in the use of drag bits was due to:

e introduction of roller cone bits, which could drill so formations more efficiently.

If too much WOB was applied, excessive torque led to bit failure or drill-pipe failure.

Drag bits tend to drill a ‘crooked’ hole, therefore some means of controlling deviation was required.

Drag bits were limited to drilling through uniformly, so, unconsolidated formations where there were no hard abrasive layers.


2.2 Roller Cone Bits

Roller cone bits (or rock bits) are still the most common type of bit used world wide. The cutting action is provided by cones which have either steel teeth, or Tungsten Carbide (WC) inserts. These cones rotate on the bottom of the hole, and drill hole predominantly with a grinding and chipping action. Rock bits are classified as milled tooth bits, or insert bits, depending on the cutting surface on the cones (Figures 2 and 3).

Figure 2 - Milled tooth bit ! ! ! Figure 3 - Insert bit

The first successful roller cone bit was designed by Hughes in 1909. This was a major innovation, since it allowed rotary drilling to be extended to hard formations. The first design was a 2 cone bit which frequently balled up since the teeth on the cones did not mesh. This led to the introduction of a superior design in the 1930s which had 3 cones with meshing teeth. The same basic design is still in use today, although there have been many improvements over the years.

The cones of the 3 cone bit are mounted on bearing pins, or arm journals, which extend from the bit body. The bearings allow each cone to turn about its own axis as the bit is rotated. The use of 3 cones allows an even distribution of weight, a balanced cutting structure, and drills a better gauge hole than the 2 cone design. The major advances in rock bit design since the introduction of the Hughes rock bit include:

Improved cleaning action by using jet nozzles.

Using Tungsten Carbide for hard-facing and gauge protection.

Introduction of sealed bearings to prevent the mud causing premature failure due to abrasion and corrosion of the bearings.


The elements of a roller cone bit are shown in detail in Figure 4.

Figure 4 - Elements of a rock bit

2.3 Diamond Bits

Diamond has been used as a material for cutting rock for many years. Since it was first used however, the type of diamond and the way in which it is set in the drill-bit have changed.

2.3.1 Natural Diamond Bits

The hardness and wear resistance of diamond made it an obvious material to be used for a drilling bit. The diamond bit is really a type of drag bit since it has no moving cones, and operates as a single unit. Industrial diamonds have been used for many years in drill-bits and in core heads (Figure 1).

The cutting action of a diamond bit is achieved by scraping away the rock. The diamonds are set in a specially designed pattern, and bonded into a matrix material set on a steel body. Despite its high wear resistance diamond is sensitive to shock and vibration and therefore great care must be taken when running a diamond bit. Effective fluid circulation across the face of the bit is also very important to prevent overheating of the diamonds and matrix material and, to prevent the face of the bit becoming smeared with the rock cuttings (bit balling).


The major disadvantage of diamond bits is their cost (sometimes 10 times more expensive than a similar sized rock bit). There is also no guarantee that these bits will achieve a higher Rate Of Penetration (ROP) than a correctly selected roller cone bit in the same formation. They are however cost effective when drilling formations where long rotating hours (200-300 hours per bit) are required. Since diamond bits have no moving parts they tend to last longer than roller cone bits, and can be used for extremely long bit runs. This results in a reduction in the number of round trips, and offsets the capital cost of the bit. This is especially important in areas where operating costs are high (e.g. offshore drilling). In addition, the diamonds of a diamond bit can be extracted, so that a used bit does have some salvage value.

2.3.2 PDC Bits

A new generation of diamond bits known as Polycrystalline Diamond Compact (PDC) bits were introduced in the 1980’s (Figure 5). These bits have the same advantages and disadvantages as natural diamond bits, but use small discs of synthetic diamond to provide the scraping cutting surface. The small discs may be manufactured in any size and shape and are not sensitive to failure along cleavage planes as with natural diamond. PDC bits have been run very successfully in many areas around the world. They have been particularly successful (long bit runs and high ROP) when run in combination with turbodrills, and oil based mud.

Figure 5 - Polycrystalline Diamond Compact (PDC) bits

2.3.3 TSP Bits

A further development of the PDC bit concept was the introduction in the later 1980’s of Thermally Stable Polycrystalline (TSP) diamond bits. These bits are manufactured in a similar fashion to PDC bits, but are tolerant of much higher temperatures than PDC bits.


3. Bit Design

Roller Cone Bits, and PDC Bits, are the most widely used bits internationally, and constitute virtually the entire bit market. Therefore they are the only types of bits that will be discussed in detail in this section.

3.1 Roller Cone Bit Design

The design of roller cone bits can be described in terms of the four principle elements of their design. The following aspects of the design will be dealt with in detail:

Bearing assemblies.

Cones.

Cutting elements.

Fluid circulation.

3.1.1 Bearing Assembly

The cones of a roller cone bit are mounted on journals as shown in Figure 6. There are three types of bearings used in these bits:

Roller bearings, which form the outer assembly and help to support the radial loading (or WOB).

Ball bearings, which resist longitudinal or thrust loads, and also help to secure the cones on the journals.

A friction bearing, in the nose assembly which helps to support the radial loading. e friction bearing consists of a special bushing pressed into the nose of the cone. is combines with the pilot pin on the journal to produce a low coefficient of friction to resist seizure and wear.


Figure 6 - Details of bearing structure

All bearing materials must be made of toughened steel which has a high resistance to chipping and breaking under the severe loading they must support. As with all rock bit components, heat treatment is used to strengthen the steel.

The most important factor in the design of the bearing assembly is the space availability. Ideally the bearings should be large enough to support the applied loading, but this must be balanced against the strength of the journal, and cone shell, which will be a function of the journal diameter and cone shell thickness. The final design is a compromise which ensures that, ideally, the bearings will not wear out before the cutting structure (i.e. all bit components should wear out evenly). However, the cyclic loading imposed on the bearings will, in all cases, eventually initiate a failure. When this occurs the balance and alignment of the assembly is destroyed, and the cones ‘lock’ onto the journals.

There have been a number of developments in bearing technology used in rock bits. The bearing assemblies of the first roller cone bits were open to the drilling fluid. Sealed bearing bits (Figure 7) were introduced in the late 1950’s, to extend the bearing life of insert bits. The sealing mechanism prevents abrasive solids in the mud from entering and causing excess frictional resistance in the bearings. The bearings are lubricated by grease which is fed in from a reservoir as required. Some manufacturers claim a 25% increase in bearing life by using this arrangement.

Journal bearing (Figure 8) bits do not have roller bearings. The cones are mounted directly onto the journal. This offers the advantage of a larger contact area over which the load is transmitted from the cone to the journal. The contact area is specially treated, and inlaid with alloys to increase wear resistance. Only a small amount of lubrication is required as part of the sealing system. Ball bearings are still used to retain the cones on the journal.


Gauge Surface

Gauge Relief

Figure 7 - Sealed bearing bit

Figure 8 - Journal bearing bit


3.1.2 Cone Design

All three cones have the same shape except that the No. 1 cone has a spear point. One of the basic factors to be decided, in the design of the cones, is the journal or pin angle (Figure 9). The journal angle is formed between the axis of the journal, and the horizontal. Since all three cones fit together, the journal angle specifies the outside contour of the bit. The use of an oversize angle increases the diameter of the cone, and is most suitable for soft formation bits. Although this increases cone size, the gauge tip must be brought inwards to ensure the bit drills a gauge hole.

Figure 9 - Journal or pin angle

One important factor which affects journal angle is the degree of meshing, or interfit (i.e. the distance that the crests of the teeth of one cone extend into the grooves of the other). The amount of interfit affects several aspects of bit design:

It allows increased space for tooth depth, more space for bearings and greater cone thickness.

It allows mechanical cleaning of the grooves, thus helping to prevent bit balling.

It provides space for one cone to extend across the centre of the hole to prevent coring effects.

It helps the cutting action of the cones by increasing cone slippage.

In some formations, it is advantageous to design the cones, and their configuration, so that they do not rotate evenly but rather they slip during rotation. This ‘cone slippage’, as it is called, allows a rock bit to drill using a scraping action, as well as the normal grinding or crushing action.


Cone slippage can be designed into the bit in two ways. Since cones have two profiles: the inner (nose) and the outer (heel) cone profile, a cone removed from the bit, and placed on a horizontal surface, can take up two positions (Figure 10). It may either roll about the heel cone, or the nose cone. When the cone is mounted on a journal it is forced to rotate around the centre of the bit. This ‘unnatural’ turning motion forces the inner cone to scrape, and the outer cone to gouge. Gouging and scraping help to break up the rock in a soft formation, but are not so effective in harder formations, where teeth wear is excessive.

Figure 10 - Cone slippage

Cone slippage can also be attained by offsetting the axes of the cones. This is often used in soft formation bits (Figure 11). To achieve an offset the journals must be angled slightly away from the centre. Hard formation bits have little or no offset to minimise slippage and rely on grinding and crushing action alone.

Figure 11 - Offset axes in soft formation bits


3.1.3 Cutting Structure

The teeth of a milled tooth bit and the inserts of an insert bit form the cutting structure of the bit. The selection of a milled tooth or insert bit is largely based on the hardness of the formation to be drilled. The design of the cutting structure will therefore be based on the hardness of the formation for which it will be used. The main considerations in the design of the cutting structure is the height and spacing of teeth or inserts.

Soft formation bits require deep penetration into the rock so the teeth are long, thin and widely spaced to prevent bit balling. Bit balling occurs when soft formations are drilled, and the soft material accumulates on the surface of the bit preventing the teeth from penetrating the rock. The long teeth take up space, so the bearing size must be reduced. This is acceptable since the loading should not be excessive in soft formations.

Moderately hard formation bits are required to withstand heavier loads so tooth height is decreased, and tooth width increased. Such bits rely on scraping/gouging action with only limited penetration. The spacing of teeth must still be sufficient to allow good cleaning. Hard formation bits rely on a chipping action, and not on tooth penetration to drill, so the teeth are short and stubbier than those used for softer formations. The teeth must be strong enough to withstand the crushing/chipping action, and sufficient numbers of teeth should be used to reduce the unit load. Spacing of teeth is less critical since ROP is reduced, and the cuttings tend to be smaller.

The cutting structure for insert bits follows the same pattern as for milled tooth bits. Long chisel-shaped inserts are required for soft formations, while short ovide-shaped inserts are used in hard formation bits.

Tungsten Carbide hard-facing is applied to the teeth of soft formation bits to increase resistance to the scraping and gouging action (Figure 12). Hard formation bits have little or no hard-facing on the teeth, but hard-facing is applied to the outer surface (gauge) of the bit. If the outer edge of the cutting structure is not protected by Tungsten Carbide hard-facing two problems may occur:

e outer surface of the bit will be eroded by the abrasive formation so that the hole diameter will decrease. is undergauge section of the hole will have to be reamed out by the next bit, thus wasting valuable drilling time.

If the gauge area is worn away it causes a redistribution of thrust forces throughout the bearing assembly, leading to possible bit failure, and leaving junk in the hole (e.g. lost cones).


Figure 12 - Hard facing for gauge protection

3.1.4 Fluid Circulation

Drilling fluid passes from the drill-string and out through nozzles in the bit. As it passes across the face of the bit it carries the drilled cutting from the cones, and into the annulus. The original design for rock bits only allowed the drilling mud to be ejected from the middle of the bit (Figure 13). This was not very efficient and led to a build up of cuttings on the face of the bit (bit balling), and cone erosion. A more efficient method of cleaning the face of the bit was therefore introduced. The fluid is now generally ejected through three jet nozzles around the outside of the bit body (Figure 14). The turbulence created by the jet streams is enough to clean the cutters and allow efficient drilling to continue.

Figure 13 Figure 14 Fluid circulation through middle of the bit Fluid circulation through jet nozzles


Bit Worn But Not Undergauge

Jet nozzles (Figure 15) are small rings of Tungsten Carbide and are available in many sizes. The outside diameter of the ring is standard so that the nozzle can fit into any bit size. The size of the nozzle refers to the inner diameter of the ring. Nozzles are available in many sizes although diameters of less than 7/32" are not recommended, since they are easily plugged. The nozzles are easily replaced and are fitted with an ‘O’ ring seal (Figure 17). Extended nozzles (Figure 16) may also be used to improve the cleaning action. The nozzles are made of Tungsten Carbide to prevent fluid erosion.

Figure 15 - Jet nozzles

Figure 16 - Extended nozzles


Figure 17 - Nozzle wrench for installing nozzle & ‘O’ ring

3.2 PDC Bit Design

The seven major components of PDC bit design are:

Cutting Material.

Bit Body Material.

Cutter Rake.

Bit Pro!le.

Cutter Density.

Cutter Exposure.

Fluid Circulation.

3.2.1 Cutter Material

The material used to manufacture the cutting surface on PDC bits is called Polycrystalline Diamond (PCD). This synthetic material is 90-95% pure diamond, and is manufactured into compacts which are set into the body of the bit. Hence the name of these bits. The high friction temperatures generated with these types of bits resulted in the polycrystalline diamond


breaking up and this resulted in the development of Thermally Stable Polycrystalline Diamond (TSP Diamond).

PCD is formed in a two stage high temperature, high pressure process. The first stage in the process is to manufacture the artificial diamond crystals by exposing graphite, in the presence of a Cobalt, Nickel and Iron or Manganese catalyst/solution, to a pressure in excess of 600,000 psi. At these conditions diamond crystals rapidly form. However, during the process of converting the graphite to diamond there is volume shrinkage, which causes the catalyst/solvent to flow between the forming crystals, preventing inter crystalline bonding, and therefore only a diamond crystal powder is produced from this part of the process.

In the second stage of the process, the PCD blank, or ‘cutter’, is formed by a liquid-phase sintering operation. The diamond powder formed in the first stage of the process is thoroughly mixed with catalyst/binder and exposed to temperatures in excess of 1400°C, and pressures of 750,000 psi. The principal mechanism for sintering is to dissolve the diamond crystals at their edges, corners and points of high pressure caused by point or edge contacts. This is followed by epitaxial growth of diamond on faces, and at sites of low contact angle between the crystals. This regrowth process forms true diamond-to-diamond bonds excluding the liquid binder from the bond zone. The binder forms a more or less continuous network of pores, co-existing with a continuous network of diamond. Typical diamond concentrations in the PCD is 90-97 vol.%.

If one requires a composite compact in which PCD is bonded chemically to a Tungsten Carbide substrate (Figure 18), some or all of the binder for the PCD may be obtained from the adjacent Tungsten Carbide substrate by melting and extruding the cobalt binder from the Tungsten Carbide. The cutters can be manufactured as disc shaped cutters, or as stud cutters, as shown in Figure 19.

Diamond Layer

WC Substrate

0.525 in. 0.530 in.

0.025 in.

0.315 in.

Figure 18 - PDC cutters

Thermally Stable Polycrystralline (TSP), Diamond bits were introduced when it was found, soon after their introduction, that PCD bit cutters were sometimes chipped during drilling. It was found that this failure was due to internal stresses caused by the differential expansion of the diamond and binder material. Cobalt is the most widely used binder in sintered PCD products. This material has a thermal coefficient of expansion of 1.2 x 10-5 °C compared to 2.7 x 10-6 °C for diamond. Therefore cobalt expands faster than diamond. As the bulk temperature of the cutter rises above 7300°C internal stresses caused by the different rates of expansion leads to severe inter-granular cracking, macro chipping and rapid failure of the cutter.

These temperatures are much higher than the temperatures to be found at the bottom of the borehole (typically 1000°C at 8000 ft). They, in fact, arise from the friction generated by the shearing action by which these bits cut the rock.


This temperature barrier of 7300°C presented serious barriers to improved performance of PCD cutter bits. Manufacturers experimented with improving the thermal stability of the cutters, and Thermally Stable PolyCrystralline Diamond Bits were developed. These bits are more stable at higher temperatures because the cobalt binder has been removed, and this eliminates internal stresses caused by differential expansion. Since most of the binder is interconnected, extended treatment with acids can leach most of it out. The bonds between adjacent diamond particles are unaffected, retaining 50-80% of the compacts’ strength. Leached PCD is thermally stable in inert or reducing atmospheres to 12000°C but will degrade at 8750°C in the presence of Oxygen. Due to the nature of the manufacturing process the thermally stable polycrystalline (TSP) diamond cannot be integrally bonded to a Tungsten Carbide substrate. Therefore, not only is the PCD itself weaker, but the excellent strength of an integrally bonded Tungsten Carbide (WC) substrate is sacrificed. Without the WC substrate, the TSP diamond is restricted to small sizes (Figure 20), and must be set into a matrix similar to natural diamonds.

3.2.2 Bit Body Material

The cutters of a PDC bit are mounted on a bit body. There are two types of bit body used for PDC bits. One of these is an entirely steel body and the other is a steel shell with a Tungsten Carbide matrix surface on the body of the shell.

Figure 19 - PDC stud cutter

The cutters on a steel body bit are manufactured as studs (Figure 19). These are interference fitted into a receptacle on the bit body. Tungsten Carbide button inserts can also be set into the gauge of the bit to provide gauge protection. The stud can be set with a fixed back-rake and/or side-rake (see below). An advantage of using a stud is that it may be removed and replaced if the cutter is damaged, and the body of the bit is not damaged. The use of a stud also eliminates the need for a braze between the bit body and the cutter. Field experience with the steel body bit indicates that face erosion is a problem, but this has been overcome to some extent by application of a hard-facing compound. Steel body bits also tend to suffer from broken cutters as a result of limited impact resistance (Figure 20). This limited impact resistance is because there is no support to the stud cutter.


1.0410 in.

0.626 in.

Matrix body bits use the cylindrical cutter (Figure 20) that is brazed into a pocket after the bit body has been furnaced by conventional diamond bit techniques. The advantage of this type of bit is that it is both erosion and abrasion resistant and the matrix pocket provides impact resistance for the cutter. Matrix body bits have an economic disadvantage because the raw materials used in their manufacture are more expensive.

Figure 20 - Setting of cutters

3.2.3 Cutter Rake

The cutters can be set at various rake angles. These rake angles include back-rake and side-rake. The bake-rake angle determines the size of cutting that is produced. The smaller the rake angle the larger the cutting and the greater the ROP for a given WOB. The smaller the rake angle, however, the more vulnerable the cutter is to breakage should hard formations be encountered. Conversely the larger the rake angle the smaller the cutting, but the greater resistance to cutter damage. Bake-Rake also assists cleaning as it urges the cuttings to curl away from the bit body thereby assisting efficient cleaning of the bit face. Side-Rake is used to direct the formation cuttings towards the flank of the bit and into the annulus.

3.2.4 Profile

There are three basic types of PDC bit crown profile: flat or shallow cone; tapered or double cone; and parabolic. There are variations on these themes but most bits can be classified into these categories.

The flat or shallow cone profile evenly distributes the WOB among each of the cutters on the bit (Figure 21). Two disadvantages of this profile are limited rotational stability, and uneven wear. ‘Rocking’ can occur at high RPM, because of the flat profile. This can cause high instantaneous loading, high temperatures, and loss of cooling to the PDC cutters.


Figure 21 - PDC bit shallow cone profile

The taper or double cone profile (Figure 22) allows increased distribution of the cutters toward the OD of the bit, and therefore greater rotational and directional stability, and even wear is achieved.

Figure 22 - PDC bit taper or double cone profile

The parabolic profile (Figure 23) provides a smooth loading over the bit profile, and the largest surface contact area. This bit profile therefore provides even greater rotational and directional stability and even wear. This profile is typically used for motor or turbine drilling.


Figure 23 - PDC bit parabolic profile

3.2.5 Cutter Density

The cutter density is the number of cutters per unit area on the face of the bit. The cutter density can be increased or decreased to control the amount of load per cutter. This must however be balanced against the size of the cutters. If a high density is used the cutters must be small enough to allow efficient cleaning of the face of the bit.

3.2.6 Cutter Exposure

Cutter exposure is the amount by which the cutters protrude from the bit body. It is important to ensure that the exposure is high enough to allow good cleaning of the bit face, but not so high as to reduce the mechanical strength of the cutter. High exposure of the cutter provides more space between the bit body and the formation face, whilst low exposure provides good backup, and therefore support to the cutters.

3.2.7 Fluid Circulation

The fluid circulation across the bit face must be designed to remove the cuttings efficiently, and also to cool the bit face. These requirements may be satisfied by increasing the fluid flow-rate, and/or the design of the water courses that run across the face of the bit. This increased fluid flow may however cause excessive erosion of the face, and premature bit failure. More than three jets are generally used on a PDC bit.


4. Bit Selection

It should be appreciated from the above discussion that there are many variations in the design of drill-bits. The International Association of Drilling Contractors (IADC) has therefore developed a system of comparison charts for classifying drill-bits according to their design characteristics and therefore their application. Two systems have been developed: one for roller cone bits; and one for fixed cutter bits.


The IADC bit comparison charts (Table 1) are often used to select the best bit for a particular application. The bits are classified according to the (IADC) code. The position of each bit in the chart is defined by three numbers, and one character. The sequence of numeric characters defines the ‘Series, Type and Features’ of the bit. The additional character defines additional design features.

Column 1 - Series

The series classification is split into two broad categories: milled tooth bits (series 1-3); and insert bits (series 4-8). The characters 1-8 represent a particular formation drill-ability. Series 1-3 bits are therefore milled tooth bits which are suitable for soft, medium or hard formations. Series 4-8 bits are insert bits and are suitable for soft, medium, hard and extra hard formations.

Column 3 - Type

Each series category is subdivided into 4 types according to the drill-ability in different formation types (i.e. a type 3 is suitable for a harder formation than a type 2 bit within the same series). The classification of the bit according to series and type specification will be dependant primarily on the cutter size and spacing, and bearing and cone structure discussed in the previous sections.

Row 1 - Features

The design features of the bit are defined on the horizontal axis of the system. There are minor variations in the features described on the comparison charts, depending on the comparison chart being used. In Table 1 the numerical characters define the following features:

1. Means a standard roller bearing.

2. Means air cooled roller bearings.

3. Means a roller bearing bit with gauge protection (not shown as an option here).

4. Means sealed roller bearings are included.


5. Means both sealed roller bearings and gauge protection included.

6. Means sealed friction bearings included (for both milled tooth and insert bits).

7. Means both sealed friction bearings and gauge protection included.

Additional Table - Additional Design Features

An additional table is supplied with the bit classification chart. This table defines additional features of the bit. Eleven characters are used to describe features such as: extended nozzles (E); additional nozzles; suitability for air drilling etc.

If a bit is classified as 1-2-4-E this means that it is a soft formation, milled tooth bit with sealed roller bearings and extended nozzles.

The terms ‘soft’ ‘medium’ and ‘hard’ formation are very broad categorisations of the geological strata which is being penetrated. In general the rock types within each category can be described as follows:

So formations are unconsolidated clays and sands. ese can be drilled with a relatively low WOB (between 3000-5000 lbs/in of bit diameter) and high RPM (125-250 RPM). Large &ow rates should be used to clean the hole effectively since the ROP is expected to be high. Excessive &ow rates however may cause washouts. Flow rates of 500-800 gpm are recommended. As with all bit types, local experience plays a large part in deciding the operating parameters.

Medium formations may include shales, gypsum, shaley lime, sand and siltstone. Generally a low WOB is sufficient (3000-6000 lbs/in of bit diameter). High rotary speeds can be used in shales, but chalk requires a slower rate (100-150 RPM). So sandstones can also be drilled within these parameters. Again high &ow-rates are recommended for hole cleaning.

Hard formations may include limestone, anhydrite, hard sandstone with quartic streaks and dolomite. ese are rocks of high compressive strength and contain abrasive material. High WOB may be required (e.g. between 6000-10000 lbs/in of bit diameter. In general slower rotary speeds are used (40-100 RPM) to help the grinding/crushing action. Very hard layers of quartzite or chert are best drilled with insert or diamond bits using higher RPM and less WOB. Flow rates are generally not critical in such formations. A more detailed description of formation types and suitable bits is given in Table 2 and 3.


IADC Bit Classification

Series

Form

atio

ns Type

765421

Standard Roller

Bearing

Roller Bearing

Air Cooled

Sealed Roller

Bearing

Sealed Roller Bearing Gauge Protection

Sealed Friction Bearing

Sealed Friction/Gauge Protection Sealed Geothermal

Elastomer Metal Elastomer Air Elastomer Metal

Stee

l Too

th

1 Soft

1 RC111 GTX-1, RC114

VG-1, GTX-G1, RC115 1-XM ,1-MV711CR ,1-XTS ,1-GV1-XM ,1-MV

2 2-MV721CR2-MV521CR421CR121CR

3 RC131 GTX-3 VG-3, RC135 VM-3, MX-3 RC136 STX-3 VG-3, RC137 VM-3, MX-3, MXB-3

4

2 Medium

1 712CR612CR512CR112CR

2

3 732CR632CR532CR

4

3 Hard

1

2 RC321

3

4 RC347

Tung

sten

Car

bide

Toot

h

4 Soft

1

VG-03, VG-03M, VGA-02, VGA-02M, GTX-00, GTX-00H, GTX-00M, GTX-03, GTX-03H, RC415

VMA-02, VMA-02M, MX-00, MX-03, MX-05H

YMA-03M

RC416 VGA-03, GX-00, GX-03, GX-03H, RC417

VMA-03, MXB-00, MX-03, MXB-03, MX-05

2

3

VGA-10, VGA-10G, VGA-10M,

VGA-11M, GTX-09, GTX-09H, GTX-11H,

RC435

VM-11HM, VMA-10M,

VMA-11MH, MX-09, MX-09G, MX-09H, MX-11H

VGA-09C, VGA-11VGD07CGX-09, STX-09, GX-09C,

STX-09C, GX-09H, STX-09H, GX-09M, GX-11, GX-11C,

GX-11M, RC437

VMA-09, VMD-11, VMD-11G, MX-09, MXB-09, MX-09G,

MX-09H, MXB-09H, MX-09C, MX-09CG,

MX-11

4GTX-11C, GTX-11CH,GTX-12H, GTX-18H,

GTX-18CH

MX-11CH, MX-18,MX-18H, MX-18CH

VG-18,VGA-18, GX-18, STX-18, GX-18H, STX-18H, GX-18C

VM-18, VMA-18, VMD-18H, MX-18, MXB-18,

MX-18H, MX-18C, MXB-18C, MX-18CH

5 Soft Medium

1VG-22, GTX-20,

GTX-20H, GTX-22, RC515

MX-20, MX-20G, MX-20H, VM-20G

VG-20,VG-20M, VG-22S, VGD-20, VGD-21S, VGD-22S, GX-20, STX-20, STX-20G, GX-20H, STX-20H, GX-20M, GX-22, GX-22M, GX-22S, GX-23,

GX-25, RC517

VM-20, VMA-20, VMA-20M, VMD-20, VMD-22S, MX-20, MXB-20, MX-20G, MX-20H, MX-22

2 GTX-28 MX-20C, MC-28VG-28, VGD-25, VGD-25S, VGD-26,

VGD-28, GX-20C, STX-20C, GX-20CH, GX-28, GX-28C, RC527

VMD-25, VMD26, VMD-28, VMD-29, MX-20CH,

MXB-20CH, MX-28, MXB-28, MX-28G

3VG-30, VG-30HM, GTX-30, GTX-30H,

GTX-33, RC535MX-30H

VG-30, VG-30M, VGD-30M, VGA-30, VGD-30, VGD-30S,

VGD-33, VGD-34, GX-30, STX-30, STX-30H, GX-30M, GX-30S,

RC537

VMD-30,VMD-33, MX-30, MXB-30, MX-30G, MXB-

30G, MX-30HVMG-30

4 GTX-30C, GTX-33CG, RC545 MX-33CG

VG-35, VG-38, VG-38CH, VGD-30C, VGD-35,VGD-36, VGD-38CH, GX-30C, STX-30C, STX-30CG,

GX-33, GX-35, STX-35, GX-38C, GX-38CM, GX-38CH, RC547

VM-35G, VMD-3DC,VMD-38C, MXB-30C, MXB-30CH, MX-35,

MX-35CG, MXB-35CG, MX-38C

VMG-35C

6 Medium

1 VXG-44 VG-40, VG-44G, VGD-40, VGD-44, VGD-44G, STX-40, GX-44, GX-44G MX-40, MX-40G

2 VXG-44C GTX-40C, GTX-44C, RC615 VM-40C, MX-44CG VG-44C, STX-40C, GX-44C,

STX-44C, GX-45, RC617

VM-44C, MX-40C, MX-40CG, MXB-40CG,

MX-44C, MX-44CHVMG-44C

3 MX-55VG-50, VG-55M, VGD-50RG,

STX-50, STX-50R, GX-55, STX-55, GX-55RG

VMD-55, MX-50, MX-50R, MX-50RG, MX-55 VMG-55

4 VG-66, VGD-66, GX-66, STX-66, GX-68

VM-66, MX-66, MX-68, MXB-68, VMD-68 VMG-68

7 Hard

1

2

3 VG-70M, VGD-70, STX-70, STX-77

4

8 Extra Hard

1 STX-88 VM-80, YMD-80

2 GX-89

3 VG-90M, STX-90, GX-95, GX-98M, STX-99

4

©2011 Baker Hughes Incorporated. All Rights Reserved.

Table 1 - Bit Classification Chart


Formation Bit Type Cutting Structure Offset & Pin Angle Bearing Size & Core Shell ickness

So:Low compressive strength, high durability, with some hard streaks e.g. clays, so shale, chalk.

1-1-11-2-11-2-31-3-11-3-1

Long teeth, widely spaced.

Maximum offset, pin angle designated for gouging to high ROP.

Small bearings, thin cone shell to allow for longer teeth.

Medium Hard:Alternate layers of more consolidated rock e.g. sandy shales, sand, limestone.

2-1-12-1-32-3-12-3-3

Shorter teeth, spaced closer together to provide resistance to breakage.

Medium offset and pin angle to combine gouging and chipping action.

Larger bearings and shell thickness to take heavier WOB.

Hard:High compressive strength, abrasive formations, e.g. dolomite, hard limestone, chert.

3-1-33-2-33-3-3

Short stubby teeth, closely packed for crushing action.

Minimum offset to give true rolling action i.e. no scraping/gouging only crushing action.

Larger bearings, thick shells to take high WOB to drill through abrasive formation.

Table 2 - Milled tooth bits

Formation Bit Type Cutting Structure Offset & Pin Angle Bearing Size & Core Shell ickness

So:Unconsolidated formations, low compressive strength e.g. slays, shales.

5-5-75-3-75-4-7

Maximum extension of tooth shaped inserts, widely spaced.

Pin angle designed to give scraping and crushing action.

Small bearings and thin cone shell to accommodate long inserts.

Medium Hard:Soer segments of hard formations e.g. lime, sandy shale.

6-1-76-2-7

Wedge shaped inserts with reduced extension.

Pin angle reduced to give more crushing action, with some gouging effect.

icker shell to give more protection.

Hard:Rocks of higher compressive strength e.g. dolomite, chert.

7-3-77-4-7

Wedge shaped inserts closely spaced.

Offset reduced to give more crushing/grinding effect, very little scraping.

icker shell, larger bearings.

Table 3 - Insert bits


4.2. Fixed Cutter Bits

The fixed cutter bit (diamond, PDC, TSP ) classification system was introduced by the IADC in 1987. The system is comprised of a four character classification code (Table 4) indicating a total of seven bit design features: Cutter type, Body material, Bit profile, Fluid discharge, Flow distribution, Cutter size, and Cutter density. These relate directly to the design features discussed in the previous sections. The four character code corresponds to the following :

Column 1 - Primary Cutter Type and Body Material

Five letters are used to describe the cutter type and body material, as shown in Table 4. The distinction of ‘Primary’ is used because one diamond material type will often be used as the primary cutting structure whilst another is used as backup.

Column 2 - Cross sectional Profile

The numbers 1 - 9 are used to define the bits’ cross sectional profile, according to the 3 x 3 chart shown in Table 4. The term profile is used here to describe the cross section of the cutter/bottom hole pattern. This distinction is made because the cutter/ bottom hole pattern may not be identical to the bit body profile.

Column 3 - Hydraulic Design

The numbers 1 - 9 in the third character of the system refers to the hydraulic design of the bit, according to the 3 x 3 chart in Table 4. This design is described by two components: the type of fluid outlet, and the flow distribution.

Column 4 - Cutter Size and Placement Density

The numbers 1 - 9 in the fourth character of the system refers to the cutter size and placement density, according to the 3 x 3 matrix chart shown in Table 4.


Table 4 - PDC bit selection chart


Gauge Height

Table 4 - PDC bit selection chart (continued)


5. Rock Bit Evaluation

As each bit is pulled from the hole its physical appearance is inspected and graded according to the wear it has sustained. The evaluation of bits is useful for the following reasons:

To improve bit type selection.

To identify the effects of WOB, RPM, etc., which may be altered in order to improve performance.

e performance of the next bit.

To allow drilling personnel to improve their ability to recognise when a bit should be pulled (i.e. to correlate the performance of a bit downhole with its physical appearance on surface).

To evaluate bit performance and help to improve their design.

A bit record (see Table 5 on page 34 for a complete example) will always be kept by the operating company, drilling contractor and/or bit vendor. This bit record is used to store the following information about the bit after it has completed its run:

e bit size type and classi!cation.

e operating parameters.

e condition of the bit when pulled.

e performance of the bit.

The IADC Dull Grading system may be applied to all types of bit - roller cone or fixed cutter (PDC, Diamond). An example of the system is based on the chart shown in Figure 24 and will be described in terms of each column:

Column 1 - Cutting Structure Inner Row (I)Report the condition of the cutting structure on the inner ⅔ of the bit for roller cone bits and inner ⅔ radius of a !xed cutter bit (Figure 24).

Column 2 - Cutting Structure Outer Row (O)Report the condition of the cutting structure on the outer 1/3 of the bit for roller cone bits and outer 1/3 radius of a !xed cutter bit (Figure 24). In column 1 and 2 a linear scale from 0 to 8 is used to describe the condition of the cutting structure as follows:

STEEL TOOTH BITS: a measure of the lost tooth height; 0 - Indicates no loss of tooth height due to wear or breakage. 8 - indicates total loss of tooth height due to wear or breakage.


INSERT BITS: a measure of total cutting structure reduction due to lost, worn and/or broken inserts; 0 - Indicates no lost, worn and/or broken inserts. 8 - Indicates total loss of cutting structure due to lost, worn and/or broken inserts.

FIXED CUTTER: a measure of the cutting structure wear (Figure 25); 0 - Indicates no loss of cutter or diamond height due to wear or breakage. 8 - Indicates total loss of cutter or diamond height due to wear or breakage.

Column 3 - Cutting Structure Dull Characteristics (D)Report the major dull characteristics of the bit cutting structure based on the table shown in Figure 24.

Column 4 - Cutting Structure Location (L)Report the location on the face of the bit where the major cutting structure dulling characteristic occurs. is may be reported in the form of a letter or number code as shown in Figure 24. e location of dull characteristics for four !xed bit pro!les is shown in Figure 25.

Column 5 - Bearing Condition (B)Report the bearing condition of roller cone bits. e grading will depend on the type of bit. is space will always be occupied by an ‘X’ for !xed cutter bits.

NON - SEALED BEARING BITS: a linear scale from 0-8 to indicate the amount of bearing life that has been used; 0 - Indicates that no bearing life has been used (new bearing). 8 - Indicates that all of the bearing life has been used (locked or lost).

SEALED BEARING BITS: a letter scale to indicate the condition of the seal; E - Indicates an effective seal. F - Indicates a failed seal.

Column 6 - Gauge (G) Report on the gauge of the bit. e letter ‘I’ is used if the bit has no gauge reduction. If the bit has gauge reduction it is reported in 1/16 of an inch.

Column 7 - Remarks (O) Report any dulling characteristic of the bit in addition to that reported for the cutting structure in column 3. Note that this is not restricted to only the cutting structure dull characteristic. e two letter codes to be used in this column are shown in Figure 24.

Column 8 - Reason for Pulling Report the reason for pulling the bit out of the hole. is may be a two or three letter code as shown in Figure 24.


Figure 24 - IADC dull grading system


Figure 25 - Location of dull characteristics


Well Bit# Hole Size

Bit Type

Depth In

Depth Out

Bit Hrs.

FTGE Bit

Bit Wt %Win Dev Dull Ft/Hr

Bit$/Ft Bit

Acc. Hrs

Acc $/Ft

Mosley #25-4 1 12.25 SDS-C 80 2750 23.00 2670 5 5 EFR 0.25 4, SB, I 116.10 $2.83 23.00 $2.83

Baker #31-2 1 12.25 SDS-C 80 2810 24.50 2730 5 0 EFR 1.00 4, SB, I 111.40 $2.88 24.50 $2.88

Hutcheson #22 1 12.25 SDSC 100 3030 27.75 2930 5 0 EFR 0.50 4, 4, I 105.60 $2.92 27.75 $19.39

Kenney #15-4 1 12.25 CX3A 80 3240 33.00 3160 6 5 EFR 0.75 5/4/WT/A/SB/I/FC/PR 95.80 $3.05 33.00 $3.05

Mosley #23-2 1 12.25 SDSC 65 3074 34.00 3009 4 5 EFR 1.00 6, SB, I 88.50 $3.26 34.00 $3.27

Wilson #16-3 1 12.25 FDSC 80 2805 32.75 2725 4 0 EFR 1.00 3/3/WT/A/SB/I/SS/PR 83.20 $3.49 32.75 $3.49

Mosley #25-4 2 12.25 SDS-C 2750 3441 15.75 691 6 0 EFR 0.50 4, SB, I 43.90 $9.00 38.75 $4.10

Hutcheson #22 2 12.25 SDSC 3030 3714 16.25 684 7 0 EFR 0.50 6, SB, I 42.10 $9.31 44.00 $17.50

Baker #31-2 2 12.25 SDS-C 2810 3812 37.25 1002 6 5 EFR 0.50 DNS 26.90 $10.57 61.75 $4.94

Wilson #16-3 2 12.25 FDSC 2805 3556 25.00 751 5 0 EFR 0.25 4/3/WT/A/SB/I/SS/PR 30.00 $10.77 57.75 $5.06

Mosley #23-2 2 12.25 SDSC 3074 3575 21.25 501 6 5 EFR 0.75 6, SB, I 23.60 $14.66 55.25 $4.91

Kenney #15-4 2 12.25 J-33 3240 4100 27.25 860 8 0 139 0.75 3/2/BT/A/SB/I/NO/TD 31.60 $17.12 60.25 $6.06

Mosley #25-4 3 12.25 J-33 3441 4038 25.50 597 6 5 102 0.75 DNS 23.40 $24.06 64.25 $7.11

Wilson #16-3 3 12.25 J-33 3556 4096 28.00 540 5 0 78 0.50 2/3/BT/A/SB/I/NO/TD 19.30 $27.54 85.75 $8.08

Hutcheson #22 3 12.25 SDGH 3714 4000 23.75 286 8 0 EFR 0.25 8, 6, I 12.00 $27.69 67.75 $18.24

Mosley #23-2 3 12.25 F-3 3575 4050 26.75 475 6 5 73 1.00 2, SE, I 17.80 $30.77 82.00 $8.00

Baker #31-2 3 12.25 F-3 3813 4140 17.50 328 5 5 86 0.00 DNS 18.70 $38.96 79.25 $7.69

Table 5 - Example of a completed bit record


6. Bit Performance

The performance of a bit may be judged on the following criteria:

How much footage it drilled ().

How fast it drilled (ROP).

How much it cost to run (the capital cost of the bit plus the operating costs of running it in hole) per foot of hole drilled.

Since the aim of bit selection is to achieve the lowest cost per foot of hole drilled, the best method of assessing the bits’ performance is the last of the above. This method is applied by calculating the cost per foot ratio, using the following equation:

where;C = Overall cost per foot ($ / foot)Cb = Cost of bit ($)Rt = Rotating time with bit on bottom (hrs)Tt = Round trip time (hrs)Cr = Cost of operating rig ($ / hrs)

This equation relates the cost per foot of the bit run to the cost of the bit, the rate of penetration and the length of the bit run. It can be used for:

Post drilling analysis to compare one bit run with another in a similar well.

Real-time analysis to decide when to pull the bit. e bit should be pulled theoretically when the cost per foot is at its minimum.

Since penetration rate is one of the most significant factors in the assessment of bit performance this will now be studied in greater depth.


In addition to correct bit selection penetration rate is a function of many parameters:

Weight On Bit (WOB).

Rotary speed (RPM).

Mud properties.

Hydraulic efficiency.

C = Cb + (Rt +Tt )Cr

F


F = Footage

6.1.1 Weight on Bit

A certain minimum WOB is required to overcome the compressibility of the formation. It has been found experimentally that once this threshold is exceeded, penetration rate increases linearly with WOB (Figure 26).

Figure 26 - Penetration rates vs. weight on bit

There are however certain limitations to the WOB which can be applied:

(a) Hydraulic horsepower (HHP) at the bit

If the HHP at the bit is not sufficient to ensure good bit cleaning the ROP is reduced either by:

1. Bit balling where the grooves between the teeth of the bit are clogged by formation cuttings (occurs mostly with so formation bits), or;

2. Bottom hole balling where the hole gets clogged up with !ne particles (occurs mostly with the grinding action of hard formation bits).

If this situation occurs no increase in ROP results from an increase in WOB unless the hydraulic horsepower (HHP) generated by the fluid flowing through the bit is improved (Figure 27). The HHP at the bit is given by:

HHPb =PbQ1714


B

where;Pb = Pressure drop across the nozzles of the bit (psi)Q = Flow rate through the bit (gpm)

Figure 27 - Penetration rate variation due to hole cleaning

To increase HHP therefore requires an increase in Pb (by using smaller nozzles) or Q (by increasing pump speed or using larger liners). This may mean a radical change to other drilling factors (e.g. annular velocity), which may not be beneficial. Hole cleaning may be improved by using extended nozzles to bring the fluid stream nearer to the bottom of the hole. Bit balling can be alleviated by using a fourth nozzle at the centre of the bit.

(b) Type of formation

WOB is often limited in soft formations, where excessive weight will only bury the teeth into the rock and cause increased torque, with no increase in ROP.

(c) Hole deviation

In some areas, WOB will produce bending in the drill-string, leading to a ‘crooked hole’. The drill-string should be properly stabilised to prevent this happening.


B

(d) Bearing life

The greater the load on the bearings, the shorter their operational life. Optimising ROP will depend on a compromise between WOB and bearing wear.

(e) Tooth life

In hard formations, with high compressive strength, excessive WOB will cause the teeth to break. This will become evident when the bit is retrieved. Broken teeth is, for example, a clear sign that a bit with shorter, more closely packed teeth or inserts is required.

6.1.2 Rotary Speed

The ROP will also be affected by the rotary speed of the bit and an optimum speed must be determined. The RPM influences the ROP because the teeth must have time to penetrate and sweep the cuttings into the hole. Figure 28 shows how ROP varies with RPM for different formations. The non-linearity in hard formations is due to the time required to break down rocks of higher compressive strength. Experience plays a large part in selecting the correct rotary speed in any given situation.

Figure 28 - Penetration rate vs. rotary speed


The RPM applied to a bit will be a function of:

(a) Type of bit

In general lower RPM’s are used for insert bits than for milled tooth bits. This is to allow the inserts more time to penetrate the formation. The insert crushes a wedge of rock, and then forms a crack which loosens the fragment of rock.

(b) Type of formation

Harder formations are less easily penetrated and so require low RPM. A high RPM may cause damage to the bit or the drill string.

6.1.3 Mud Properties

In order to prevent an influx of formation fluids into the well-bore the hydrostatic mud pressure must be slightly greater than the formation (pore) pressure. This overbalance, or positive pressure differential, forces the liquid portion of the mud (filtrate) into the formation, leaving the solids to form a filter cake on the wall of the borehole. In porous formations this filter cake prevents any further entry of mud into the formation. This overbalance and filter cake also exists at the bottom of the hole where it affects the removal of cuttings. When a tooth penetrates the surface of the rock the compressive strength of the rock is exceeded and cracks develop, which loosen small fragments or chips from the formation (Figure 29). Between successive teeth the filter cake covers up the cracks, and prevents mud pressure being exerted below the chip. The differential pressure on the chip tends to keep the chip against the formation. This is known as the static chip hold down effect, and leads to lower penetration rates. The amount of plastering which occurs depends on mud properties. To reduce the hold down effect:

Reduce the positive differential pressure by lowering the mud weight (i.e. reduce the overbalance to the minimum acceptable level to prevent a kick).

Reduce the solids content of the mud (both clay and drilled solids). Solids removal is essential to increase drilling efficiency.


Figure 29 - Static chip hold down effect

In less porous formations the effect is not so significant since the filter cake is much thinner. However dynamic chip hold down may occur (Figure 30). This occurs because, when cracks form around the chip mud enters the cracks to equalise the pressure. In doing so, however, a pressure drop is created which tends to fix the chip against the bottom of the hole. The longer the tooth penetration, the greater the hold down pressure. Both static and dynamic hold down effects cause bit balling and bottom hole balling. This can be prevented by ensuring correct mud properties (e.g. mud weight and solids content).

Figure 30 - Dynamic hold down effect


6.2 PDC Bits

6.2.1 WOB/RPM

PDC bits tend to drill faster with low WOB and high RPM. They are also found to require higher torque than roller cone bits. The general recommendation is that the highest RPM that can be achieved should be used. Although the torque is fairly constant in shale sections the bit will tend to dig in and torque up in sandy sections. When drilling in these sandy sections, or when the bit drills into hard sections and penetration rate drops, the WOB should be reduced but should be maintained to produce a rotary torque at least equal to that of a roller cone bit. Too low a WOB will cause premature cutter wear, possible diamond chipping and a slow rate of penetration.

6.2.2 Mud Properties

The best ROP results have been achieved with oil based muds but a good deal of success has been achieved with water based muds. Reasons for the improved performance in oil based muds has been attributed to increased lubricity, decreased cutter wear temperature, and preferential oil wetting of the bit body. The performance of PDC bits in respect to other mud properties is consistent with that found with roller cone bits i.e. increase in mud solids content or mud-weight decreases ROP.

6.2.3 Hydraulic Efficiency

The effects of increased hydraulic horsepower at the bit are similar to their effect on roller cone bits. However manufacturers will often recommend a minimum flow-rate in an attempt to ensure that the bit face is kept clean, and cutter temperature is kept to a minimum. This requirement for flow-rate may adversely affect optimisation of HHP.


Documents

Drilling Bits 04 - King Petroleum...A system, known as the Dull Bit Grading System, has been devised by the International Association of Drilling Contractors (IADC) to facilitate this