Drilling Bit Optimisation

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DRILLING BIT OPTIMIZATION

PROJECT ADVISOR

Mr. Rehan Hashmat

SUBMITTED BY

Talha Umair Hashmi

(2004-PET-36)

Ashfaq Ali

(2004-PET-42)

Mukhtar Ahmed Barre

(2004-PET-52)

Syed Nisar Hussain Shah

(2004-PET-56)

Department of Petroleum & Gas Engineering,

UNIVERSITY OF ENGINEERING & TECHNOLOGY LAHORE

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PREFACE

The choice of this project was quite natural because it is the need of hour to

highlight the importance of

“Drilling Bit Optimization” in petroleum industry. this

project

“Drilling Bit Optimization” can be regarded as a step ahead from the latest

technology., first defining basic drilling Optimization Concepts and then

illuminate the drill bit analysis based on offset well data. It includes previous well

and field records, bit run etc. modern technology in bits have greatly Optimize the

ROP and has resulted a huge reduction in trip time. The ability to select and

optimize bit and hydraulic criteria is recognizing as a critically important element

of drilling operation. Impregnated Hybrid Bits have greatly increased the ROP and

has decreased the trip time. Although these things, along with a number of

techniques are important but not the prime essential.

Case histories can be used to demonstrate the importance of drilling optimization.

These factual experiences establish a sense e of reality when learning optimization

concepts and methods that cannot be achieved hypothetical simulators exercises or

example calculations. Drilling in a very hard, abrasive and inter bedded formation

has always been extremely tough and challenging due to sudden changes in the

formation characteristics which results in reduction in ROP. Such formations have

proved a Museum Of Geology and drilling here has been most challenging and

difficult. During Drilling the reduced ROP from an unexpected zone was

encountered. Various techniques are applied to increase ROP and reduce trip time.

Using Impregnated and hybrid bits with Turbu-drills, this problem is solved in a

cost effective manner. The wells drill successfully to producing objectives after

applying this optimized technology. This project reviews the optimized selection

of bit, optimized hydraulics and in the end discusses a field example, where such

techniques were applied successfully.

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THIS PROJECT REPORT IS HANDED IN TO MEET NORMS SET

FOR CONFERMENT OF BACHELOR DEGREE

In

Petroleum Engineering

_________________

________________

Project Advisor

External Examinar

(Mr. Rehan Hashmat)

__________________

Chairman Petroleum and Gas Engg. Deptt.

(Dr. Obaid-ur-Rehman Paracha)

Department of Petroleum & Gas Engineering,

UNIVERSITY OF ENGINEERING & TECHNOLOGY LAHORE

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Acknowledgment

We are glad that we have made it to this day when we can cherish the sense

of achievement by the blessing of Allah Almighty.

This project is a result of hard work and team effort which alone would have

had no meaning if the guidance and commitment of our Project Advisor, Mr

Rehan Hashmat was not there, whose helping hand has made this project a

land mark in our career. We are thankful to Mr. Shaukat Ali & Mr. Noor

Ahmed (Dewan Petroleum Pvt. Ltd.)

Mr. Hamad Ahmad (Reedhycalog) for providing the desired Data for the

Project.

We must thank all the Teachers of our Department whose support and

experience always served as batten during the project.

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Dedication

To our

Beloved Parents,

Respected Teachers and

Sincere Friends whose utmost

love and attention for us brought us to

this height of knowledge with the blessings of

Allah Almighty.

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PREFACE

The choice of this project was quite natural because it is the need of hour to

highlight the importance of

“Drilling Bit Optimization” in petroleum industry. this

project

“Drilling Bit Optimization” can be regarded as a step ahead from the latest

technology., first defining basic drilling Optimization Concepts and then

illuminate the drill bit analysis based on offset well data. It includes previous well

and field records, bit run etc. modern technology in bits have greatly Optimize the

ROP and has resulted a huge reduction in trip time. The ability to select and

optimize bit and hydraulic criteria is recognizing as a critically important element

of drilling operation. Impregnated Hybrid Bits have greatly increased the ROP and

has decreased the trip time. Although these things, along with a number of

techniques are important but not the prime essential.

Case histories can be used to demonstrate the importance of drilling optimization.

These factual experiences establish a sense e of reality when learning optimization

concepts and methods that cannot be achieved hypothetical simulators exercises or

example calculations. Drilling in a very hard, abrasive and inter bedded formation

has always been extremely tough and challenging due to sudden changes in the

formation characteristics which results in reduction in ROP. Such formations have

proved a Museum Of Geology and drilling here has been most challenging and

difficult. During Drilling the reduced ROP from an unexpected zone was

encountered. Various techniques are applied to increase ROP and reduce trip time.

Using Impregnated and hybrid bits with Turbu-drills, this problem is solved in a

cost effective manner. The wells drill successfully to producing objectives after

applying this optimized technology. This project reviews the optimized selection

of bit, optimized hydraulics and in the end discusses a field example, where such

techniques were applied successfully.

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Introduction

Chapter # 1

1 1.1 History of Drilling Bit

A brief history of drilling bit;

2550 - 2315 BC The Egyptians Used Diamond Drilling Tools For The Construction Of

The Pyramids.

600 - 260 BC Chinese Drill Up To 14 Inch Diameter and Depths Up To 2000 Feet

1825 AD First Cable Tool Drilling In Europe

1845 AD The Englishman Beart Obtains A Patent On Rotary Drilling Methods.

1863 AD First Diamond Coring In Switzerland

1878 AD First Patent on a Two Cone Bit

1893 AD Drilling Depths Reach 2004 M.

1908 AD First Rock Bit Used

1933 AD Tri-Cone Bit Introduced.

1947 AD Drilling Depths Reach 5418 M.

1948-1968-Signidicance Bit Improvement

1.2 Concept of Optimization

Although bit cost comprises a relatively small fraction in a well's budget (

± 5%), but bit

performance's impact on overall well cost can be significant. This project address bit

types, classification and optimization.

In the past, selecting drill bits during well planning hinged to a large extent on the

operator

’s past experience in drilling offset wells. This practice often was a serendipitous,

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Introduction

Chapter # 1

2 hit-or-miss proposition, based on the chance that the company

’s drilling engineer on the

job might have drilled some of the offsets.

The optimization plan also usually involved a survey of historical bit record databases

that indicated how certain bit types reacted in formations likely to be encountered in the

upcoming well. The process was more qualitative than quantitative, and often required

subjective rather than objective decision-making. Such analogous information, when

combined with bit manufacturers

’ technical data on specific products, yielded a list of

bits or bit types that could be used to drill a borehole as clean and as close to gauge as

possible in the least amount of time, given safety requirements and cost limits. In any

case, it took considerable time to rustle up the necessary historical data, yet the estimated

outcome still remained somewhat in doubt. The introduction of the Drill Bit Optimization

System was a driving forcing that helped change all that. DBOS is a multidiscipline

method for determining the optimum cutting structure, gauge protection, hydraulic con-

figuration, and other bit design features for drilling with either roller cone or fixed cutter

bits, whether in the conventional rotary mode or with various down hole motor-driven

drilling tools. To characterize the down hole environment of a single well to be drilled,

DBOS analysis starts with a thorough reconstruction of expected ideologies, revealed by

customer- provided well logs from the closest offset well. The results include a formation

analysis, unconfirmed rock strength analysis, and both roller cone and fixed-cutter bit

selections.

We combine numerous parameters that affect rate of penetration (ROP). These include

bit record information, directional surveys, real-time ROPs and mud log data, along with

rock type and strength data and hydraulic and mechanical energy factors, among others.

In the BPA analysis we evaluates key bit performance variables over the given

drill-ability intervals, identifying which bit type should be the most successful for drilling

through each single interval or over multiple intervals. The analysis also includes both

fixed cutter and roller cone bits in cases where either can be applied. To optimize the bit

performance, we need to quantify and analyze all aspects of the drilling process.

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Drilling Bit Types and Components

Chapter # 2

3 2.1 What is a Drilling Bit?

The tool used to crush or cut rock. Everything on a drilling rig directly or indirectly

assists the bit in crushing or cutting the rock. The bit is on the bottom of the drill-string

and must be changed when it becomes excessively dull or stops making progress. Most

bits work by scraping or crushing the rock, or both, usually as part of a rotational motion.

Some bits, known as hammer bits, pound the rock vertically in much the same fashion as

a construction site air hammer.

2.2 Drilling Bit Types

2.2.1 Drag Bits

Drag bits are oldest type of rotary drilling bit and are rarely use now drag bits do not have

distributed cutters; instead these bits have hard faced blades usually two blades (fishtail)

bit or three. Rotary type Drag Bits are limited to softer formations generally. They are, in

most cases cheaper than Rock Bits. The cutting profile may be flat, chevron or stepped

according to application. They may be used in air or fluid flush. Drag Bits follow the path

of least resistance. They cut very fast but will experience more drilling deviation than

from using a tri-cone drill bit. 4-Blade bits are generally more user friendly to the drilling

rigs as there are more cutting blades on the cutting surface to give a smoother cut.

2.2.2 Types of Drag Bits

Chevron Bit

Chevron bits are designed for medium to hard formation and are used in areas that

contain a lot of rock and also drilling out concrete casings and plugs.

Scratcher Bit

A Scratcher Bit is designed for soft formation such as sand.

Step Bit

Step bits are the most common type of drag bit used in the world today. They are

primarily designed for soft to medium formation.

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Drilling Bit Types and Components

Chapter # 2

4 2.2.3 Roller Cone Bits

As the name implies, roller cone bits are made up of (usually) three equal-sized cones and

three identical legs which are attached together with a pin connection. Each cone is

mounted on bearings which run on a pin that forms an integral part of the bit leg. The

three legs are welded together and form the cylindrical section which is threaded to make

a pin connection.

The pin connection provides a mean of attachment to the drill string, each leg is provided

with an opening for fluid circulation. The size of this opening can be reduced by adding

nozzles of different sizes. Nozzles are used to provide constriction in order to obtain high

jetting velocities necessary for efficient bit and hole-cleaning. Mud pumped through the

drill string passes through the bit pin bore and through the three nozzles, with each nozzle

accommodating one third of the total flow, if all the nozzles were of the same size.

There are two types of roller cone bits:

• Milled Tooth Bits:

Here the cutting structure is milled from the steel making up the cone.

• Insert Bits:

The cutting structure is a series of inserts pressed into the cones.

Figure Chevron Bit Figure Scratcher Bit Figure Step Bit

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Drilling Bit Types and Components

Chapter # 2

5 2.2.4 Diamond Bits

A diamond bit employs no moving parts (i.e. there are no bearings) and is designed to

break the rock in shear and not in compression as is done with roller cone bits. Rock

breakage by shear requires significantly less energy than in compression; hence less

weight on bit can be used resulting in less wear and tear on the rig and drill string.

Polycrystalline Diamond Compact (PDC) Bits

A PDC bit employs a large number of cutting elements, each called a PDC cutter. The

PDC cutter is made by bonding a layer of polycrystalline man-made diamond to a

cemented tungsten carbide substrate in a high pressure, high temperature process. The

diamond layer is composed of many tiny diamonds which are grown together at random

orientation for maximum strength and wear resistance.

Thermally Stable PDC (TSP) Bits

Diamond also posses the highest thermal conductivity of any other mineral allowing it to

dissipate heat very quickly. This is a desirable property from a cutting element to prevent

it from burning or thermal fracture due to overheating. Diamond and TSP (thermally

stable PDC) bits are used for drilling hard and abrasive formations.

2.3 Drilling Bit Components

2.3.1 Journal

The bit journal is the shaft on which the bearing is mounted. It is tilted at some angle

depending on the desired structure of the cone.

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Drilling Bit Types and Components

Chapter # 2

6 2.3.2 Bearings

Bearing is a rotating support placed between moving parts to allow them to move easily.

Bit bearings are used to perform the following functions; support radial loads, support

thrust or axial loads and secure the cones on the legs

There are two types of bearings;

1. Sealed Bearing

2. Unsealed Bearing

2.3.3 Sets of Bearings

Roller-Ball-Roller (RBR)

It is the combination of two roller bearings with one ball bearing at the center shown in

the figure.

Roller-Ball-Friction (RBF)

It is the combination of roller bearing, ball bearing and friction (case-hardened material)

shown in the figure.

Figure RBR

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Drilling Bit Types and Components

Chapter # 2

7 Ball-Roller-Ball (BRB)

It is the combination of two balls and one roller bearing at the center.

2.3.4 Seals

These are flexible slip which prevent the oil and grease leakage and

prevent the entrance of dust particles in to bearing as shown in figure

2.3.5 Nozzle

A projecting part with an opening for the regulating and directing the

flow of fluid as shown in figure.

2.3.6 Cone

The conical shell which is surrounding the bearing while the

cutters are milled or inserted on it as shown in figure3.

Two types of cones are usually used:

1. Flat Cone

2. Rounded Cone

2.3.7 Cutters

The small teeth shape pieces inserted or milled on the cone shell use for chipping and

crushing the formation.

There are three types of cutters;

1. Milled Cutters

2. Inserted Cutters

3. PDC Cutters

Figure Seal Figure Nozzle Figure Cone

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Drilling Bits Classification Chapter # 3

8

3.0 Bit Classification for Roller Cone Bits

In 1972, the International Association of Drilling Contractors (IADC) established a three code system for roller cone bits. The first code or digit defines the series classification relating to the cutting structure. The first code carries the numbers 1 to 8.For milled tooth bits, the first code carries the numbers 1 to 3, which describes soft, medium and hard (and semi-abrasive or abrasive) rocks respectively. This number actually signifies the compressive strength of rock. For insert bits, the first code carries the numbers 4 to 8.The second code relates to the formation hardness subdivision within each group and carries the numbers 1 to 4. These numbers signify formation hardness, from softest to hardest within each series. The second code is a sub-division of the first code (1 to 8). The third code defines the mechanical features of the bit such as non-sealed or sealed bearing. Currently there are seven subdivisions within the third code:

1. Non-Sealed Roller Bearing 2. Roller Bearing Air Cooled 3. Sealed Roller Bearing

4. Sealed Roller Bearing with Gauge Protection 5. Sealed Friction Bearing

6. Sealed Friction Bearing with Gauge Protection 7. Special Features - Category now Obsolete.

3.1 IADC Chart for Mill-Tooth Bits

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Drilling Bits Classification Chapter # 3

9

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Drilling Bits Classification Chapter # 3

10

3.3 IADC Chart Interpretation

Character 1: Formation Hardness

1-3: Tooth Bits 4-8: Insert Bits

Character 2: Hardness within Class

Example: 1-1 is softer than 1-2

Character 3: Bearing Type

1. Standard Roller Bearing, No Seal 2. Roller Bearing, Air Cooled, No Seal 3. Roller Bearing, Gauge Protected, No Seal 4. Sealed Roller Bearing

5. Sealed Roller Bearing, Gauge Protected 6. Sealed Friction Bearing

7. Sealed Friction Bearing, Gauge Protected

Character 4: Additional Design Features

A. Air Application C. Center Jet

D. Deviation Control E. Extended Jets

G. Extra Gauge / Body Protection J. Jet Deflection

R. Reinforced Welds

S. Standard Steel Tooth Model X. Chisel Inserts

Y. Conical Inserts Z. Other Insert Shapes

3.3.1 Example

Bit type with code 125A means that

Character 1: Formation Hardness; It’s for Mill-Tooth Bit. Character 2: Hardness within Class; It’s for soft medium.

Character 3: Bearing Type; It’s for Sealed Roller Bearing, Gauge Protected. Character 4: Additional Design Features; It’s for Air Application.

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Drilling Bit Selection

Chapter # 4

11

4.1 Bit Selection Guidelines

Bit selection begins with a thorough examination of bit records from offset wells data. The best and worst performance and dull bit grading in formations comparable to the well being designed should be examined, analyzed and the used to determine the characteristics of the best performing drill bits. In particular attention should be given on the details such as the premature failure of bits, reasons drill bits pulled, dull characteristics of inserts: whether the inserts were worn or broken, etc. A drill bit that had broken inserts clearly indicates that the formation should have been drilled with a much harder drill bit.

Data required for the correct bit selection include the following:

1. Prognoses lithology column with detailed description of each formation 2. Drilling fluid details

3. Well profile

Formation characteristics should be studied in detail to assess the type of cutting structure required to successfully drill the formation. The existence of abrasive and hard minerals such as chert or pyrite nodules should be identified. This will impact on the aggressiveness of the selected milled teeth or insert bits and, in the case of PDC bits, the requirement for hybrid design bits.

Gauge protection (which determines the final hole size) is particularly critical in abrasive formations where the gauge could be lost very quickly resulting in an under gauge hole which requires reaming during the next bit run. For highly abrasive sections the use of insert bits with diamond enhanced gauge protection prevents the occurrence of under gauge hole and reduces reaming on subsequent bit runs.

When drilling directional wells the Contractor should be asked to provide an assessment of the required BHA changes, motor requirements and any limitations on bit operating parameters which may impact on the selection of bits. In addition bit characteristics in terms of walk, build and drop tendencies will need to be assessed for their impact on the well path.

When using a mud motor in the assembly all tri-cone bits should have a motor bearing

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Drilling Bit Selection

Chapter # 4

12 system which allows extended use at high motor RPM‘s or a fixed cutter bit should be selected.

Due consideration should always be given to the jet system of the bit. When drilling soft shale sections where the major limitations on ROP is bottom hole and cutter cleaning, the use of centre jet, extended jets or lateral jet bits should be considered.

4.2 Cost per Foot

The criterion for bit selection is normally based on cost/ft (C) and this is determined using the following equation:





( ) $ / B T t R C ft F     4.1 Where

C=cost per foot ($ / ft), B= Bit Cost ($), T= Trip Time (hrs), t= Rotating Time (hrs), R= Rig Cost per Hr, F= Footage (ft)

Equation (4.1) shows that cost/ft is controlled by five variables and for a given bit cost (B) and hole section (F), cost/ft will be highly sensitive to changes in rig cost per hour (R), trip time (T) and rotating time (t). The trip time (T) is the sum of RIH and POOH times. If the bit is pulled out for some reason, say, to casing shoe for a wiper trip, such duration, if added, will influence the total trip time (T) and, in turn, cost/ft. Bit performance, therefore, can be changed by some arbitrary factor and for accurate comparisons of different bit types, the tip time should be based on the time required for straight RIH and POOH. Rotating time is the total time the drill bit is rotating on bottom while drilling.

The rig cost (R) will greatly influence the value of cost/ft. For a given hole section in a field that is drilled by different rigs, having different values of 'R', the same bit will produce different values of cost/ft, assuming the same rotating hours are used in all rigs. It should be pointed out that if the value of R is taken as arbitrary (say 2000 $/hr), then Equation 4.1 will yield equivalent values of cost/ft for all rigs. The value of cost/ft in this case is not a real value and does not relate to actual or planned expenditure; it is merely used for comparison. The criterion for selection of bits on the basis of cost/ft is to choose the bit which consistently produces the lowest value of C in a given formation or hole section.

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Drilling Bit Selection

Chapter # 4

13

4.2.1 Example: Calculation of Cost /ft

Determine the cost/ft for the following bit types which were used to drill the same type of formation in three wells. Which bit would you select for the next well?

Assume bit cost = $10,000 and rig cost= 900 $/hr Solution Using;





( ) $ / B T t R C ft F     Bit XX;





10000 (8 144) 900 54.9 $ / 2670 C     ft Bit XY;





10000 (8 180) 900 63.5 $ / 2822 C     ft

On the basis of cost/ft, bit type XX is more economical than bit XY and should be used in the next well.

4.2.2 Break-Even Analysis

The break-even analysis is usually used to investigate the economics of replacing a current cheap bit by a more expensive bit or vice versa. The comparison is normally based on a graph of footage against rig hours. The graph is established as follows: Calculate the number of rig hour’s equivalent to bit cost using:

A=Cost of new bit ($)/Rig cost ($)

Add trip time to A to obtain the total number of rig hours corresponding to the cost of the new bit before drilling commences. Call this time B.

B = trip time + A

Mark this point on the left-hand side of the X-axis, (i.e. rig hours axis), Figure 4.1.

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Drilling Bit Selection

Chapter # 4

14 Calculate the number of feet of hole at break-even cost using:

F= Cost of new bit +trip cost/Offset cost/ft Mark point F the Y-axis (i.e. footage axis).

Draw a straight line through points B and F, Figure 4.1.This line is the break even line. Any footage and hour combination on this line is a break-even point. Above this line, the new bit will produce lower cost/ft than the offset bit and below this line the new bit is more expensive to run.

4.3 Specific Energy

The Specific Energy Method gives a simple and practical method for Bit Selection. The energy required to remove unit volume of rock. The equation may be derived by considering the mechanical energy expended at the bit in one minute. Thus,

E = W * 2ðR * N in-lb 4.2

Where

W = weight on bit (lb) N = rotary speed (rpm) R = radius of bit (in)

The volume of rock removed in 1 minute is:

V = (ðR2) * PR in3 4.3

Where

PR = penetration rate in (ft/hr)

Dividing equations 4.2 & 4.3 gives specific energy in terms of volume as SE = E/V = W * 2ðR * N / (ðR2) * PR = 10 * * W N R PR 3 * lb in in 4.4

Replacing R by D/2, where D is the hole diameter. = 20 * * W N D PR 3 in lb in  _4.5

Since PR = footage (F)/rotating time (t) In Metric Units = 2.35 * * W N D PR 3 / MJ m 4.6

It was decided that SE is not a fundamental intrinsic property of the rock. It is highly dependent on type and design of bit. This means that for a formation of given

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Drilling Bit Selection

Chapter # 4

15 strength, a soft formation bit will produce an entirely different value of SE from that produced by hard formation bit. This property of SE therefore, affords accurate means for selection of appropriate bit type. The bit that gives the lowest value of SE in a given section is the most economical bit.

Equation of SE also shows that, for a given type in a formation of constant strength, SE can be taken constant under any combination of WN values. This is because changes in WN usually lead to increase value of PR (under optimum hydraulics) and this maintains the balance of equation. The ROP is, however highly influenced by change in WN, and for a particular bit type an infinite number of PR values exist for all possible combinations of WN values. It follows that SE is a direct measure of bit performance in a particular formation and provides an indication of the interaction between bit and rock. The fact that SE. when compared with the ROP, is less sensitive to change in WN makes it practical tool for bit selection.

4.4 Bit Dullness

The degree of dullness can be used as a guide for selecting a particular bit. Bits that wear too quickly are obviously less efficient and have to be pulled out of the hole more frequently. Bit Dullness is described by tooth wear and bearing condition. Tooth wear is reported as the total height remaining and is given a code from T1 to T8. T1 indicates that 1/8 of tooth has gone. T4 indicates that ½ height of the bit has gone. Similarly, bearing life is described by eight codes from B1 to B8. The number B8 indicates that bearing life has gone or the bearing is locked.

If a bit has high tooth wear and less bearing life is, therefore not suitable for formation selected. If such a bit were a 1-1-1 type, then the use of a bit with a higher numerical code could reduce the wear and bearing deterioration. A bit type 1-2-4 may be chosen; the code 2 for the high rock strength, reducing tooth wear, and the code 4 is for sealed bearing. Code1 indicates that the bit is a milled tooth type.

4.5 Well Bit Records and Geologic information

Drilling data from offset wells and geologic information can provide useful guides selection of drill bits. Sonic Logs from such wells can also be used to provide an estimate of rock strength which in turn provides the guide for selecting the proper bit type.

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Drilling Bit Design

Chapter # 5

16 5.0 Drilling Bit Design

The drill bit design is dictated by the type of rock to be drilled and size of hole. The three

legs and journals are identical, but the shape and distribution of cutters on the three cones

differ. The design should ensure that the three legs must be equally loaded during

drilling.

The following factors are considered when designing and manufacturing a three-cone bit:



Journal Angle



Offset between Cones



Cutters



Bearings

5.1 Milled-Tooth Bits

Milled tooth bit design depends on the geometry of the cones and the bit body and

geometry and composition of the cutting elements (teeth).

The geometry of the cones and of the bit body depends on:



Journal Angle



Cone Profile



Offset Angle

The geometry and composition of the teeth depend on:



Journal Angle



Angle of Teeth



Length of Teeth



Number of Teeth



Spacing of Teeth

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Drilling Bit Design

Chapter # 5

17 

Shape of Teeth



Tooth Hard facing

5.1.1 Journal Angle

The bit journal is the bearing load-carrying surface. The journal angle is defined as the

angle formed by a line perpendicular to the axis of the journal and the axis of the bit, see

Figure The magnitude of the journal angle directly affects the size of the cone; the size of

the cone decreases as the journal angle increases. The journal angle also determines how

much WOB the drill bit can sustain; the larger the angle the greater the WOB. The

smaller the journal angle the greater is the gouging and scraping actions produced by the

three cones. The optimum journal angles for soft and hard roller cone bits are 33 degrees

and 36 degrees, respectively.

5.1.2 Cone Profile

The cone profile determines the durability of the drill bit. Cones with flatter profile are

more durable but give lower ROP, while a rounded profile delivers a faster ROP but is

less durable.

5.1.3 Cone Offset

The degree of cone offset (or skew angle) is defined as the horizontal distance between

the axis of the bit and a vertical plane through the axis of the journal.

Figure 5.1

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Drilling Bit Design

Chapter # 5

18 A drill bit with zero offset has the centre lines of the three cones meeting at the centre of

the drill bit, see Figure 5.2. Skew angle is an angular measure of cone offset.

A cone with zero offset has a true rolling action as the cone moves in a circle centered at

the cone apex and bit centre.

If the cone is offset from the bit centre, then when the drill bit is rotated from surface, the

cone attempts to rotate around its own circle which is not centered at the bit centre. The

cone is forced by the much bigger drill string to rotate about the centerline of the bit and

drill string and this result in the cone slipping as it is rotating. This slipping produces

tearing and gouging actions which are beneficial in drilling soft rocks as it removes a

larger volume of rock.

The amount of offset is directly related to the strength of rock being drilled. Soft rocks

require a higher offset to produce greater scraping and gouging actions. Hard rocks

require less offset as rock breakage is dependent on crushing and chipping actions rather

than gouging, Cone offset increases ROP but also increases tooth wear, especially in the

gauge area, and increases the risk of tooth breakage.

As shown in Figure 5.4, drill bits can have slender and long teeth (Figure 5.4a) or short

and stubby teeth (Figure 5.4b). The long teeth are designed to drill soft formations with

Figure 5.4a. Tooth Shape low compressive strength where the rock is more yielding and

easily penetrated.

Cone Offset Figure 5.3 Cone Onset

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Drilling Bit Design

Chapter # 5

19 Penetration is achieved by applying weight on bit (WOB) which forces the teeth into the

rock by overcoming the rock compressive strength. Rotation of the bit helps to remove

the broken chips.

Harder rocks have high compressive strength and can not be easily penetrated using

typical field WOB values. Hard rock bits therefore have much shorter (and more) teeth

with a larger bearing area, therefore the short teeth will be less likely to break when they

are subjected to drilling loadings. The teeth apply load over a much larger area and break

the rock by a combination of crushing, creation of fractures and chipping. The teeth are

not intended to penetrate the rock, but simply to fracture it by the application of high

compressive loads.

5.1.4 Tooth Number and Spacing

As discussed above, a soft rock requires long and a few teeth allowing the WOB to be

distributed over fewer teeth. The teeth are widely spaced to reduce the risk of the bit

being balled up when drilling water sensitive clays and shales. Wider spacing also allows

the rows of teeth from one cone to engage into the space of equivalent row of the

adjacent cone and thereby help to self clean the cutting structure of any build up of drilled

cuttings.

For hard formations, the teeth are made shorter, heavier and more closely spaced to

withstand the high compressive loads required to break the rock.

5.1.5 Tooth Shape

Viewed from the side most teeth appear like an A without the crosspiece. There are other

design such as the T-,U-, or W-shape which are more durable and are usually found at the

gauge area of the bit. Figure 5.5 shows this.

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Drilling Bit Design

Chapter # 5

20 5.1.6 Tooth Hard-facing

To increase the life of the cutting tooth, hard metal facing (usually tungsten carbide) was

initially applied to one side of the tooth to encourage preferential wear of the tooth. As

the bit drills away, the tooth wears on one side (the uncovered steel side) thereby always

leaving a sharp cutting edge on the metal faced side. This style is known as

self-sharpening hard facing. Nowadays, most toothed bits use Full Coverage Hard facing, in

which the entire tooth is covered with hard metal. This practice provides greater

durability of the tooth and offers sustained ROP

’s.

5.2 Insert Bits

The design factors relating to cone offset, bit profile and cone profile discussed above for

milled tooth bits apply equally to insert bits.

The cutting structure of insert bit relies on using tungsten carbide inserts which are

pressed into pre-drilled holes in the cones of the bit. The following relates to the various

design features of inserts which are designed to suit various rock types.

5.2.1 Insert Protrusion

Insert protrusion refers to the amount of insert

protruding from the cone and is always less than

the total length of the insert, Figure5.6. Inserts

with large protrusions are suitable for soft rocks

as would be seen on a 4-3 type cutting structure

and to a limited protrusion as on the insert as on a cutting structure.

5.2.2 Insert Number, Diameter and Spacing

The same argument used in milled tooth bits applies here. Soft insert bits have fewer and

longer inserts to provide aggressive penetration of the rock. Durable, hard formation bits

have many, small diameter inserts with limited protrusion, see Figure 5.7.

Figure 5.6

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Drilling Bit Design

Chapter # 5

21 5.2.3 Insert Shape

For soft formation bits, the inserts have chisel shapes to provide aggressive drilling

action. In soft, poorly consolidated formations the chisel shape is more efficient at

penetrating the formation than a more rounded conical shape. Figure 5.8 shows seven

shapes.

5.2.4 Insert Composition

The composition of the inserts can be varied by altering grain size or cobalt

concentration. In general changes that increase the wear resistance of the insert will make

it more likely to break, while tougher inserts, less prone to breakage, may wear more

rapidly.

5.2.5 Additional Features

Additional enhancing features (Figure 5.9) include:

•Gauge trimmers to assist in cutting a gauge hole

•Shirttail compacts to reduce leg wear in abrasive formations

For Soft Rocks Figure 5.8 For Hard Rocks

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Drilling Bit Design

Chapter # 5

22 Gauge Retention

The majority of the drill bit work is spent around the heel and gauge area and therefore

this part suffers the greatest amount of wear.

Gauge trimmers are used to maintain bit gauge (diameter). This achieved by the use of

T-shaped teeth on milled tooth bits and very short inserts in the gauge row. The gauge

inserts may be diamond coated.

Shirttail Protection

All drill bits may have tungsten carbide inserts placed in the heel area of the bit. A worn

shirttail (Figure 5.10) may expose the seal, leading to seal wear and bearing failure.

Various devices may be used to limit or delay shirttail wear. Tungsten Carbide Inserts

may be placed in the shirttail itself. Lug pads may be added to the upper part of the

shirttail. A band of hard metal can be added to the margin of the shirttail.

5.2.6 Bearing Systems

The first type of bearing system used with roller cone bits was a non-sealed,

roller-ball-friction bearing arrangement, utilizing rollers on the heel of the journal. The primary

load, or stress was exerted on these rollers, and drilling fluid was used to lubricate the

bearings. Bearing size was maximized, since room for a seal was not required. The

bearing surfaces were machined and ground to very close tolerances to ensure dependable

service. This type of bearing system is also available with modifications for air

circulation and for use with a percussion hammer Figure 5.11. The next generation of

bearing systems was a sealed roller bearing system, having a sealed grease reservoir to

lubricate the bearings. The bearing system is composed of: 1) a roller-ball-friction or

roller-ball-roller bearings 2) the seal, which retains the lubricant and prevents drilling

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Drilling Bit Design

Chapter # 5

23 fluid and abrasive cuttings from entering the bearing cavities, 3) the shirttail is designed

and hard faced to protect the seal, 4) a lubricant, an elastic-hydrodynamic type, is used to

ensure minimum friction and wear, 5) the reservoir, which stores and supplies the

lubricant to the bearings, and 6) the vented breather plug, which transfers down hole fluid

pressure against the lubricant-filled flexible diaphragm to equalize pressures surrounding

the bearing seal Figure 5.11.

There is, however, one serious drawback to the roller-ball-roller bearing system. The

primary cause of roller bearing failure is journal spalling, which causes destruction of the

rollers and the locking of the cone. To remedy this, instead of the standard roller bearing

assembly, the

“journal bearing” system utilizes solid metal bushings for direct cone to

journal contact. This offers a distinct mechanical advantage over roller arrangements in

that it presents a larger contact area at the load bearing point. This distribution of the load

eliminated the chief cause of roller bearing assembly failure - spalling in the load portion

of the bearing face. Journal bearing systems in the tungsten carbide insert bits features a

metal bearing surface combined with a hard faced journal and a lubricant. Specialized

seals and reliable pressure equalization systems keeps the drilling fluid and formation

contaminants out of bearings, and positively seals the graphite-based lubricant inside the

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Drilling Bit Design

Chapter # 5

24 bearing. Precision fit of the journal and cone distributes contact loading evenly

throughout a near-perfect arc. Bearing surfaces are finished to a carefully controlled

surface texture to ensure optimum lubrication. The manufacturing of the journal bearing

system consists of having the journals milled, grooved or pressed (depending on the bit

company) to accommodate the bushing. Then the bushings are inlaid on the journal. Once

the cone is fitted with teeth and gauge protection, the journal is then machine-pressed into

the cone. To complete the seal between the cone and the journal, special rings (seals)

have been developed.

Bearing Lubrication System

A sealed bearing system is lubricated by a sealed grease reservoir as shown in Figure

5.12 (Journal Bearing). The pressure of grease within the bearing must be the same as

that outside in the mud. The lubrication system works as follows:

An elastomeric pressure diaphragm communicates annular pressure to the grease in a

grease reservoir (inside the leg) and then, via grease passages to the grease within the

bearing itself. Thus zero differential pressure is maintained across the seal at all times.

Some leakage of the grease may occur due to rapid pressure changes resulting from axial

movement of the cone on the journal. The grease reservoir has enough fluid to allow for

minor leakages.

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Drilling Bit Design

Chapter # 5

25 5.2.7 Seals

The first and still most popular seal is the radial seal (used mainly on the sealed roller

bearing bits). The radial seal is a circular steel spring encased in rubber, which seals

against the face of the shank and the face of the cone. The newer

“O” ring seal is

considered the most effective seal. The major problem confronting the

“O” ring is

tolerance, which must be precise in order to maintain an effective seal. An understanding

of lubricants and lubricating systems is necessary for successful drilling operations. The

lubricating systems are essentially the same, and are composed of an external equalizer

located under the bit or on back of the shanks, a grease reservoir with some sort of

expandable diaphragm to distribute the grease, and some sort of distribution system to the

bearings. In addition, there is a pressure relief valve to release any trapped pressure,

which might otherwise rupture the seals. Pressure surges can be detrimental to these

sealed systems. As pressure and temperature increase, the viscosity of the lubricant

increases. As a result, the system cannot instantaneously compensate for abrupt changes

in pressure due to surges (going into the hole, making connections, etc.) and small

quantities of mud invade the system. With the close tolerance necessary for effective

sealing, mud solids can be damaging. Adequate cleaning is even more important with

sealed bearing bits. If drilled cuttings are allowed to build up around the shirttail, seal

damage and premature bearing failure may result. Gauge protection is also important to

seal and bearing life, because seal damage can occur from shirttail wear caused by

inadequate gauge protection. Any time a sealed bearing bit is rerun, the seals and shirttail

should be carefully checked for excessive wear or grooving. To complete the

journal-cone assembly, a positive seal is required to keep drilling fluid out, while allowing the

graphite lubricant in, which keeps the bearings from overheating. The positive seal

requires a relief valve to allow escape of excess pressure, which can overload the seal and

cause seal failure.

5.3 Polycrystalline Diamond Compact Bits (PDC)

5.3.1 Bit Design Elements

There are many details relating to bit design which can be covered in detail here.

Reference to manufacturers catalogues is recommended for the interested reader.

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Drilling Bit Design

Chapter # 5

26 The PDC design is affected by:

1. Body design: can either be steel-bodied or tungsten carbide (matrix)

2. Cutters Geometry



Cutters



Number of Cutters and spacing of cutters



Size of Cutters



Back Rake



Side Rake

3. Geometry of Bit



Number of Blades



Blade Depth

4. Diamond table



Substrate interface



Composition



Shape

5.3.2 Bit Body

The bit body may be forged or milled from steel (steel-bodied bits) or constructed in a

cast from tungsten carbide (matrix bit). From a practical standpoint, steel bodies bit are

preferable as they can be easily repaired but suffer from erosion. Matrix bits are more

resistant to erosion but are prone to bit balling in soft clay formations due to their low

blade height compared with steel bodied bits.

5.3.3 Cutter Geometry

Cutter geometry depends on:

Number of Cutters

Soft rocks can be penetrated easily and hence fewer cutters are used on soft PDC bits as

each cutter removes a greater depth of cut. More cutters must be added to hard PDC bits

for harder formation to compensate for the smaller depth of cut.

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Drilling Bit Design

Chapter # 5

27 Cutter Size

Large cutters are used on softer formation bits and smaller cutters on the harder formation

bits. Usually a range of sizes is used, from 8mm to 19mm is used on any one bit.

Back Rake

Cutter orientation is described by back rake and side rake angles. Back rake is the angle

presented by the face of the cutter to the formation and is measured from the vertical, see

Figure the magnitude of rake angle affects penetration rate and cutter resistance to wear.

As the rake angle increase, ROP decreases but the resistance to wear increases as the

applied load is now spread over a much larger area.PDC cutters with small back rakes

take large depths of cut and are therefore more aggressive, generate high torque, and are

subjected to accelerated wear and greater risk of impact damage. Cutters with high back

rake have the reverse of the above. Back rake angles vary between, typically, 15

° to 45°.

They are not constant across the bit, nor from bit to bit.

Side Rake

Side rake is an equivalent measure of the orientation of the cutter from left to right. Side

rake angles are usually small. The side rake angle assists hole cleaning by mechanically

directing cuttings toward the annulus.

Cutter Shape

The edge of the cutters may be beveled or chamfered to reduce the damage caused by

impacts.

5.3.4 Bit Geometry

The factors affecting bit geometry include:

Bit Style

When all of the above features are put together, a variety of bit styles emerge as shown in

Figure. The bit on the extreme left of Figure is a light set bit with a few, high blades and a

few but large cutters with small back rake angles. Thus light set bits typically have a few,

high blades, with few large cutters, probably with low back

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Drilling Bit Design

Chapter # 5

28 For hard rocks, PDC bits will have more blades, with smaller and more numerous cutters

and this trend continues to the heavy set bits on the extreme right.

Gauge Protection

As discussed before, the greatest amount of work is done on the heel and gauge of the

drill bit. A PDC bit that wears more on the gauge area will leave an under gauge hole

which will require reaming from the next bit. Reaming is time consuming and costly and

in some cases can actually destroy an entire bit without a single foot being drilled. Hence

maintaining gauge is very important. One or more PDC cutters may be positioned at the

gauge area. Pre-flatted cutters are used to place more diamond table against gauge.

Tungsten carbide inserts, some with natural or synthetic diamonds embedded in them

may be placed on the flank of the bit. A major advantage with fixed cutter bits over

roller cone bits are those the gauge on fixed cutter bits may be extended to a larger length

of the drill bit.

Bit Length

This is important for steer ability. Shorter bits are more steerable. The two bits on the left

of Figure 5.14 are sidetrack bits, with a short, flat profile. The

‘Steering Wheel’ bit on the

right of is designed for general directional work

Figure 5.13

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Drilling Bit Design

Chapter # 5

29 Bit Profile

Bit profile affects both cleaning and stability of the bit. The two most widely used

profiles are: double cone and shallow cone, Figure 5.15.

The double cone profile allows more cutters to be placed near the gauge giving better

gauge protection and allowing better directional control. The shallow cone profile gives

faster penetration but has less area for cleaning. In general a bit with a deep cone will

tend to be more stable than a shallow cone.

Blade Geometry

PDC bits can be manufactured with a variety of blade shapes ranging from straight to

complex curve shapes. Experience has shown that curved blades provide a greater

stability to the bit especially when the bit first contacts the rock.

Blade Height

A soft formation PDC bit will have a lager blade height than a hard PDC bit with a

consequent increase in junk slot area. Higher blades can be made in steel bodied- bits

than matrix bits, because of the greater strength of steel over that of matrix.

Number of Blades

Using the same analogy for roller cone bits, a PDC

bit designed for soft rocks has a fewer blades (and

cutters) than one designed for hard rocks. The soft

formation PDC bit will therefore have a large junk

slot area to remove the large volume of cut rock and

to reduce bit balling in clay formations, Figure 5.16a.

Figure 5.15

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Drilling Bit Design

Chapter # 5

30 A hard PDC bit with many blades requires many small cutters, each cutter removing a

small amount of rock, Figure 5.16b.

5.4 Regular Circulation Bits

Regular circulation bits (Figure 3-3a), have one to three holes drilled in the dome of the

bit. Drilling fluid passes through the bore of the bit, through the drilled holes, over the

cutters, and then to the bottom of the hole, to flush away the drill cuttings.

5.4.1 Jet Circulation Bits

Jet circulation bits Figure 5.17 are manufactured with smooth, streamlined, fluid

passageways in the dome of the bit. Drilling fluid passes through the bore of the bit at

high velocities with minimum pressure losses, through the jet nozzles, and then to the

hole bottom to flush cuttings away from the bit and up the hole. Excess fluid that

impinges on the hole bottom flows up and around the cutters for cutter cleaning.

5.4.2 Air or Gas Circulation Bits

A third type of circulation medium is compressed air or gas, and can be used with either

regular or jet circulation bits. Bits manufactured for air or gas circulation have special

passageways from the bore of the bit to the bearings, through which a portion of the air or

gas is diverted to keep the bearings cool and purged of dust or cuttings. From the special

passageways to the bearings, the air or gas passes through a number of strategically

located ports or holes in the bearing journal, flows through the bearing structure and

exhausts at the shirttail and gauge of the bit, to flow up the annulus.

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Drilling Bit Design

Chapter # 5

31 5.5 Jet Nozzles

There are essentially three types of jet nozzles used in tri-cone

bits. Shrouded nozzle jets provide maximum protection against

retainer ring erosion, excessive turbulence or extended drilling

periods. Standard jet nozzles are easier to install and are

recommended for situations where erosion is not a problem. Air

jet nozzles (see above) are used on bits designated for drilling

with air or gas. Nozzle sizes play an important role in bit

hydraulics. The benefits of the correct selection include

effective hole cleaning and cuttings removal, faster drill rates and thus

lower drilling costs.

Orifice sizes are stated in 1/32 inch increments, with the most common being between

10/32 to 14/32 sizes. Directional bit jets are available in sizes from 18/32 to 28/32.

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Dull Grading of Drilling Bit

Chapter # 6

32

6.0 The IADC Fixed Cutter Dull Grading System

Dull grading systems for fixed cutter bits, described herein, were implemented to improve utilization and effectiveness of the dull grading system.

6.1 System Enhancements

The format of the dull grading chart is shown in Figure 6.1. Eight factors are recorded: the first four spaces describe the extent and location of wear of the "Cutting Structure". The next two spaces address other criteria for bit evaluation, with the fifth space reserved for grading "Bearing" wear of roller cone bits. This space is always marked with an "X" when fixed cutter bits are graded.

The sixth space indicates "Gauge Measurement". The last two positions allow for "Remarks" which provide additional information concerning the dull bit, including "Other (or secondary) Dull Characteristics" and "Reason Pulled", respectively. Additional enhancements include addition of a dull characteristic code, "BF", to distinguish "bond failure" between the cutter and its support backing from "LT", loss or a cutter. In addition, the optional designations "RR" or "NR" were added to allow for indication of whether a bit is "rerun able" or not. Application of these minor revisions will further "standardize" the meaning of a dull grade. Examples of dull characteristics are shown in Figure 6.1.

6.2 Application of Dull Grading System

6.2.1Inner/Outer Rows: Spaces 1 and 2.

Evaluating "Cutting Structure"

Cutting Structure

0 No Wear 4 50% Wear

8 No Useable Cutting

Using a linear scale from 0 to 8, as before, a value is given to cutter wear in both the,

(46)

Dull Grading of Drilling Bit

Chapter # 6

33 inner and outer rows of cutters. Grading

numbers increase with amount of wear, with 0 representing no wear, and 8 meaning no usable cutters left. A grade of 4 indicates 50% wear.

For surface-set bits, the scale of cutter wear is determined by comparing the initial cutter height with the amount of usable cutter height remaining. Rather than evaluating "usable cutter height", PDC

cutter wear is now measured across the diamond table, regardless of the cutter shape, size, type or exposure. This eliminates the difficulty in determining the initial cutter height on a bit in which

PDC cutters are designed with less-than-full exposure.

For both surface-set and PDC bits, the average amount of wear for each area is recorded, with 2/3 of the radius representing the "inner rows" and the remainder representing the "outer rows".

6.2.2 Dull Characteristics: Space 3.

Average wear is calculated by simply averaging the individual grades for each cutter

Figure 6.1