drilling bit optimisation

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.


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


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.

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.

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.

Table of Contents Chapter # 1 Introduction to Drilling Bit Optimization

1.1 History of Drilling Bit 1

1.2 Concept of Optimization 1

Chapter # 2 Drilling Bit Types and Components

2.1 What is a Drilling Bit? 3

2.2 Drilling Bit Types 3

2.2.1 Drag Bits 3

2.2.2 Types of Drag Bits 3

Chevron Bit, Scratcher Bit, Step Bit

2.2.3 Roller Cone Bit 4

2.2.4 Diamond Bit 5

Polycrystalline Diamond Compact (PDC) Bits

Thermally Stable PDC (TSP) Bits

2.3 Drilling Bit Components 5

2.3.1 Journal 5

2.3.2 Bearings 6

2.3.3 Sets of Bearings 6

2.3.4 Seals 7

2.3.5 Nozzle 7

2.3.6 Cone 7

2.3.7 Cutters 7

Chapter # 3 Classification of Drilling Bit

3.0 Bit Classification for Roller Cone Bit 8

3.1 IADC Chart for Mill-Tooth Bits 8

3.2 IADC Chart for Insert Bits 9

3.3 IADC Chart Interpretation 10

3.3.1 Example 10

Chapter # 4 Drilling Bit Selection

4.1 Bit Selection Guidelines 11

4.2 Costs per Foot 12

4.2.1 Example 13

4.2.2 Break-Even Analysis 13


4.3 Specific Energy 14

4.4 Drilling Bit Dullness 15

4.5 Well Bit Records and Geologic information 15

Chapter # 5 Drilling Bit Design

5.0 Drilling Bit Design

16

5.1 Milled Tooth Bits 16

5.1.1 Journal Angle 17

5.1.2 Cone Profile 17

5.1.3 Cone Offset 17

5.1.4 Tooth Number and Spacing 19

5.1.5 Tooth Shape 19

5.1.6 Tooth hard facing 20

5.2 Insert Bits 20

5.2.1 Insert Protrusion 20

5.2.2 Insert Number, Diameter and Spacing 20

5.2.3 Insert Shape 21

5.2.4 Insert Composition 21

5.2.5 Additional Features 21

Gauge Retention, Shirttail Protection

5.2.6 Bearing Systems 22

Bearing Lubrication System

5.2.7 Seals 25

5.3 Polycrystalline Diamond Compact Bits (PDC) 25

5.3.1 Bit Design Elements 25

5.3.2 Bit Body 26

5.3.3 Cutter Geometry 26

Number of Cutters, Cutter Size, Back Rake, Side Rake,

Cutter Shape

5.3.4 Bit Geometry 27

Bit Style, Gauge Protection, Bit Length, Bit Profile,

Blade Geometry, Blade Height, Number of Blades

5.4 Regular Circulation Bit 30

5.4.1 Jet Circulation Bits 30

5.4.2 Air or Gas Circulation Bits 30

5.5 Jet Nozzles 31

Chapter # 6 Dull Grading of Drilling Bit

6.0 The IADC Fixed Cutter Dull Grading System 32

6.1 System Enhancements 32

6.2 Application of Dull Grading System 32

6.2.1Inner/Outer Rows: Spaces 1 and 2. 32

6.2.2 Dull Characteristics: Space 3. 33

6.2.3 Location: Space 4. 34

6.3 Other Evaluation Criteria 35

6.3.1 Bearing: Space 5. 35

6.3.2 Gauge: Space 6. 35

6.4 Additional "Remarks" 35

6.4.1 Other Dull Characteristics: Space 7. 35

6.4.2 Reason Pulled: Space 8. 36

6.5 Conclusion 36

6.6 IADC Roller Bit Dull Bit Grading System 37

6.6.1 Columns (1&2) Steel Tooth Bits 37

6.6.2 Columns (1&2) Insert Bits 38

6.6.4 Column (3) Dull Characteristics: (Use only cutting structure

related codes) 38

6.6.5 Column (4) 38

6.6.6 Column (5) Bearings/Seals: 38

6.6.7 Column (6) Gage: (Measure in fractions of an inch.)

Codes) 38

6.6.8 Column (7) Other Dull Characteristic: (Refer to Column 3 38

6.6.9 Column (8) Reason Pulled or Run Terminated 38

6.6.10 Discussion of Dulling Characteristics 38

Chapter # 7 Drilling Bit Hydraulics

7.1 Introduction 49

7.2 Pressure Losses 49

7.2.1 Surface Connection Losses (P1) 50

7.2.2 Pipe and Annular Pressure Losses 51

7.2.3 Pressure Drop across Bit 51

7.3 Fundamentals of Hydraulics 51

7.4 Flow Regimes 53

7.4.1 Laminar flow 53

7.4.2Turbulent flow 53

7.4.3 Transitional flow 54

7.5 Fluid Types 54

7.6 Rheological Model 54

7.6.1 Bingham Plastic Mode 55

7.6.2 Power L Aw Model 57

7.6.3 Herschel Buckley Yield Power Law Model 58

7.7 Practical Hydraulics Equations 58

7.7.1 Bingham Plastic Model 59

7.7.2 Power Law Model 60

7.8 Pressure Loss across Bit 61

7.8.1 Procedure 62

7.9 Pressure Drop across Nozzles and Watercourses 62

7.9.1 Multiples nozzles 63

7.10 Example: Hydraulics calculations 64

7.10. 1 Bingham Plastic Model 64

7.10. 1 Power Law Model 70

7.10.3 Comparison of the two models 70

7.11 Optimization of Bit Hydraulics 71

7.11 .1 Surface Pressure 71

7.11.2 Hydraulic Criteria 71

7.11 .3 Maximum Bit Hydraulic Horsepower 71

7.11 .4 Maximum Impact Force 72

7.11 .5 Nozzle Selection 72

7.11 .6 Optimum Flow Rate 73

7.12 Field Method of Optimizing Bit Hydraulic 73

7.13 Example: Hydraulics Optimization 74

7.14 Hydraulic and ROP 75

7.15 A practical check on the efficiency of the bit hydraulic program 75

Chapter # 8 Drilling Bit Optimization

8.0 Optimized Bit Technology 76

8.1 Impregnated PDC Bits 76

8.1.1 Advantages 76

Enhanced Hydraulics, Matrix Flexibility

8.1.2 Disadvantage 77

8.1.3 Effect of temperature 77

8.1.4 Possible Remedies 78

8.2 PDC Hybrid Drill Bits 78

8.3 Design Optimization as Applied to Cutting Structure 79

8.3.1 Action of the cones 79

8.3.2 For a hard formation 80

8.3.3 For a soft formation 81

8.4 Bit Selection and Drilling Parameters 81

8.5 Bit Choices 81

8.6 Refining Bit Choice and Parameters Based On Previous Bit Run 82

8.7 WOB (Weight on Bit) 82

8.7.1 Weight-RPM 83

8.7.2 Variable RPM-weight 83

8.7.3 Constant RPM- Variable Weight 83

8.7.4 Constant RPM and Weight 83

Optimum RPM and Weight, Best Weight for given RPM,

Best RPM for given Weight

8.8 Drill off Test 84

8.8.1 To Optimize WOB and RPM. 85

8.8.2 To Optimize Hydraulics 85

8.9 ROP (Rate of Penetration) 85

8.10 Rotary Speed and RPM 85

8.10.1 Longitudinal Drill-string Vibration 86

8.10.2 Transverse Drill-string Vibration 86

8.11 Minimizing Bit Whirl 86

8.12Monitoring Bit Progress While Drilling 87

8.13 When to Pull the Bit 87

8.14 Post-Drilling Bit Analysis 87

Chapter # 9 Case History of Field

9.0 Introduction 89

9.1 Problems Encountered During Drilling the Formations 89

9.2 Cause of such Problems 90

9.3 Solution of such Problems 90

9.4 How Air and Gas Drilling Optimized ROP in Such Formation 90

9.5 Advantages of Bits in Air and Gas Drilling Over

Rotary Conventional Drilling90

9.6 Optimization of new well in this formation 91

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,


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.

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.



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

Figure Mill-tooth & Insert Bits


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.

Figures Diamond and TSP Bits


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

Figure RBF


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

Figure Different Insert Shapes

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



9

3.2 IADC Chart for Insert Bits


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.

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



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 RC 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.


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 RC ft

F

Bit XX;

10000 (8 144) 90054.9 $ /

2670C ft

Bit XY;

10000 (8 180) 90063.5 $ /

2822C 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.

Figure 4.1


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


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.

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



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

Figure 5.2


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

Figure 5.4


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.

Figure 5.5


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

Figure 5.7


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

Figure 5.9


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

Figure 5.10


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

Figure 5.11


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.

Figure 5.12


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.


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.


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


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

Figure 5.14


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

Figure 5.16


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.

Figure 5.17


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.

Figure 5.18

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,



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

Figure6.2


34

in the area

Dull/Other CharacteristicsBC -Broken Cone

BF -Bond Failure

BT -Broken Teeth/Cutters

BU -Balled Up

CC -Cracked Cone

CD -Cone Dragged

CI -Cone Interference

CR -Cored

CT -Chipped Teeth/Cutters

ER -Erosion

FC -Flat Crested Wear

HC -Heat Checking

JD -Junk Damage

LC -Lost Cone

LN -Lost Nozzle

LT -Lost Teeth/Cutters

NO - No Major/Other Dull

NR -Not Rerun-able

OC -Off-Center Wear

PB -Pinched Bit

PN -Plugged Nozzle/

Flow Passage

RG -Rounded Gauge

RO -Ring Out

RR �Rerun-able

SD -Shirttail Damage

SS - Self Sharpening Wear

TR -Tracking

WO -Washed Out Bit

WT -Worn Teeth/Cutters

The most prominent or "primary" physical change from new condition of a cutter is

recorded in the third space. "Other" dull characteristics of the bit are noted in the

seventh space the difference being that space 3 describes cutter wear, while space 7

may concern other wear characteristics of the bit as a whole. Codes for dull

characteristics of both categories are listed in the table in Figure 6.1, including the

addition of "BF" for bond failure.

6.2.3 Location: Space 4.

LocationC - Cone

N - Nose (Row)

T - Taper

S � Shoulder

G - Gauge

A - All Areas Rows

M - Middle Row

H � Heel Row


35

The fourth space is used to indicate the location of the primary dull characteristic

noted in the third space. Locations are designated in the diagram.

6.3 Other Evaluation Criteria

6.3.1 Bearing: Space 5.

This space is used only for roller cone bits. It will always be marked "X" for fixed

cutter bits.

Bearing/Seals

Non-Sealed Bearing

0 No life Used

8 All Life Used

Sealed Bearing

E Seals Effective

F Sealed Failed

X Fixed Cutter Bit

6.3.2 Gauge: Space 6.

The sixth space is used to record the condition of the bit gauge. 'I' is used if the bit is

still in gauge. Otherwise, the amount the bit is under gauge is recorded to the nearest

1/16th of an inch.

Gauge

1 in gauge

1/16 under gauge up to 1/16

2/16 under gauge 1/16 to 1/8

3/16 under gauge 1/8to 3/16

4/16 under gauge 3/16to1/4

6.4 Additional "Remarks"

6.4.1 Other Dull Characteristics: Space 7.

In the seventh space, secondary evidence of bit wear is noted. Such evidence may

Figure6. 3


36

relate specifically to cutting structure wear, as recorded in the third space, or may note

identifiable wear of the bit as a whole, such as "erosion". Many times, this

"secondary" dull grade identifies the cause of the dull characteristic noted in the third

space.

Codes for grading both "primary" and "secondary" dull characteristics are listed in the

table shown in Figure. The designations "RR" and "NR" have been included as

options for noting whether the bit is rerun-able or not.

6.4.2 Reason Pulled: Space 8.

The eighth space is used to record the reason the bit was pulled. A list of codes is

shown in Figure.

Reasons for Pulling Bit

BHA-Change Bottom hole Assembly

DMF-Down hole Motor Failure

DSF-Drill string Failure

DST-Drill Stem Test

DTF-Down hole Tool Failure

LOG-Run Logs

RIG-Rig Repair

CM-Condition Mud

CP-Core Point

DP-Drill Plug

FM-Formation Change

HP-Hole Problems

HR-Hours

PP-Pump Pressure

PR-Penetration Rate

TD-Total Depth/CSG Depth

TQ-Torque

TW-Twist Off

WC-Weather Conditions

WO-Washout Drill string

6.5 Conclusion

Despite their minor nature, the changes described in this "First Revision to the IADC

Dull Grading System" are expected to facilitate easier, more accurate evaluation of

fixed cutter bit wear. With the addition of new dull characteristic codes, more specific

descriptions of bit wear are possible, while the revised criteria for measuring PDC

cutter wear will ensure a standard approach is taken in each instance. Thus, a dull

grade ultimately will "mean the same thing" to everyone, as originally intended.


37

Worn Cutter (WT) Worn Cutters (WT), Balled Up (BU) Plug Nozzle Flow Pasage (PN)

Bond Failure (BF) Lost Cutters (LT), Erosion (ER) Heat Checking (HC)

Broken Cutters (BT) Broken Cutter (BT) Junk Damage (JD)

Chipped Cutters (CT) Erosion (ER), Lost Cutters (LT) Rounded Gauge (RG)

The above are some examples of grading for the fixed cutter bits.

6.6 IADC Roller Bit Dull Bit Grading System The IADC Dull Grading System (above) can be applied to all types of roller cone bits

as well as all types of fixed cutter bits. Bits with steel teeth, tungsten carbide inserts,

and natural or synthetic diamond cutters can all be described with this system. A

description of the dull grading system follows with each of the components explained

as they apply to roller cone bits. Applications to fixed cutter bits have been discussed

before.

6.6.1 Columns (1&2) Steel Tooth Bits A measure of lost tooth height due to abrasion and/or damage where:

0 No lost worn and/or broken inserts.

8 All of cutting structure lost, worn and/or broken.


38

6.6.2 Columns (1&2) Insert Bits

A measure of total cutting structure reduction due to lost, worn and/or broken inserts

where:

0 No lost worn and/or broken inserts.

8 All inserts lost, worn and/or broken.

6.6.4 Column (3) Dull Characteristics: (Use only cutting structure related codes.) Same as for Fixed Cutters

6.6.5 Column (4)

Location:

N - Nose Row

M - Middle Row (Cone #1)

G - Gage Row (Cone #2)

A - All Rows (Cone #3)

6.6.6 Column (5) Bearings/Seals: Same as for Fixed cutters

6.6.7 Column (6) Gage: (Measure in fractions of an inch.)

Gauge

1/16 - 1/16" out of gauge




6.6.8 Column (7) Other Dull Characteristic: (Refer to Column 3 Codes.)

6.6.9 Column (8) Reason Pulled or Run Terminated Same as for Fixed Cutters

6.6.10 Discussion of Dulling Characteristics

BC (Broken Cone) or BF (Bond

Failure)

BT (Broken Teeth)

BU (Balled Up)

CC (Crocked Cone)

CD (Cone Dragged)

CI (Cone Interference)

CR (Cored)

CT (Chipped Teeth)

ER (Erosion)


39

FC (Flat Crested Wear)

HC (Heat Checking)

JD (Junk Damage)

LC (Lost Cone)

LN (Lost Nozzle)

LT (Lost Teeth)

OC (Off Center Wear)

PB (Pinched Bit)

PN (Plugged Nozzle)

RG (Rounded Gage)

SD (Shirttail Damage)

SS (Self Sharpening Wear)

TR (Tracking)

WO (Washed Out Bit)

WT (Worn Teeth)

Following is a discussion, and photographs of the dulling characteristics common to

roller cone bits. While the possible causes listed and possible solutions for problem

wear modes are not presumed to be exclusive. They represent situations commonly

encountered in the field.

BC (Broken Cone) or BF (Bond Failure)

This describes a bit with one or more cones that have been broken into two or more

pieces, but with most of the cone still attached to the bit. Broken cones can be caused

in several ways.

Some of the causes of BC are: 1. Cone interference - where the cones run on

each other after a bearing failure and break one

or more of the cones. Bit hitting a ledge on trip

or connection.

2. Dropped drill string.

3. Hydrogen sulfide embrittlement.

4. BF (Bond Failure)

5. Refers to Fixed Cutter Dull Condition

Figure BC (Broken Cone) CONE)Cone)


40

BT (Broken Teeth) In some formations BT is a normal wear characteristic of

tungsten carbide inserts bits and is not necessarily an

indicator of any problems in bit selection or operating

practices.

Some causes of BT are

1. Bit run on junk.

2. Bit hitting a ledge or hitting bottom suddenly.

3. Excessive WOB for application. Indicated by broken teeth predominantly on

the inner and middle row teeth. Excessive RPM for application. Indicated by

broken teeth predominantly on the gauge row teeth.

4. Improper break-in of bit when a major change in bottomhole pattern is made.

Formation too hard for bit type.

BU (Balled Up) A balled up bit will show tooth wear due to skidding,

caused by a cone, or cones, not turning due to formation

being packed between the cones. The bit will look as if

a bearing had locked up even though the bearings are

still good.

Some causes of bailing up are:

1. Inadequate hydraulic cleaning of the bottom hole.

2. Forcing the bit into formation cuttings with the pump not running.

3. Drilling a sticky formation.

CC (Cracked Cone) A crocked cone is the start of a broken or lost cone and

has many of the same possible causes.

Some of these causes are: 1. Junk on the bottom of the hole.

Figure BT (Broken Teeth)

Figure Balled Up, BU

Figure Cracked Cone, CC


41

2. Bit hitting a ledge or bottom.



5. Overheating of the bit.

6. Reduced cone shell thickness due to erosion.

Cone interference.

CD (Cone Dragged)

This dull characteristic indicates that one or more

of the cones did not turn during part of the bit run,

indicated by one or more flat wear spots.

Some of the possible causes are: 1. Bearing failure on one or more of the

cones.

2. Junk lodging between the cones.

3. Pinched bit causing cone interference.

4. Bit bailing up.

5. Inadequate break in.

CI (Cone Interference) Cone interference often leads to cone grooving and

broken teeth and is sometimes mistaken for formation

damage. Broken teeth caused by cone interference are

not an indicator of improper bit selection.

Some of the causes of cone interference are:

1. Bit being pinched.

2. Reaming under gauge hole with excessive WOB.

3. Bearing failure on one or more cones.

CR (Cored) A bit is cored when its centermost cutters are worn

and/or broken off. A bit can also be cored when the

Figure Cone Dragged, CD

Figure Cone Interference, CI

Figure Cored Bit, CR


42

nose part of one or more cones is broken.

Some things that can cause bits to become cored are: 1. Abrasiveness of formation exceeds the wear resistance of the center cutters.

Improper breaking in of a new bit when there is a major change in bottom

hole pattern. Cone shell erosion resulting in lost cutters.

2. Junk in the hole causing breakage of the center cutters.

CT (Chipped Teeth)

On tungsten carbide insert bits, chipped insert often

become broken teeth. A tooth is considered chipped,

as opposed to broken, if a substantial part of the

tooth remains above the cone shell.

Some causes of chipped teeth are:

1. Impact loading due to rough drilling.

2. Slight cone interference.

3. Rough running in air drilling application.

ER (Erosion)

Fluid erosion leads to cutter reduction and/or loss

of cone shell material. The loss of cone shell

material on tungsten carbide insert bits can lead to

a loss of inserts due to the reduced support and

grip of the cone shell material.

Erosion can be caused by:

1. Abrasive formation contacting the cone shell between the cutters, caused by

tracking, off-center wear, or excessive WOB.

2. Abrasive formation cuttings eroding the cone shell due to inadequate

hydraulics.

3. Excessive hydraulics resulting in high velocity fluid erosion.

4. Abrasive drilling fluids or poor solids control.

Figure Chipped Teeth, CT

Figure Cone Erosion, ER


43

FC (Flat Crested Wear)

Flat crested wear is an even reduction in height across

the entire face of the cutters. Interpretation of the

significance of flat crested wear are numerous, and

dependent on many factors, including formation,

hardfacing and operating parameters.

One of the causes of flat crested wear is:

1. Low WOB and high RPM, often used in attempting to control deviation.

HC (Heat Checking)

This dulling characteristic happens when a cutter is

overheated due to dragging on the formation and is

then cooled by the drilling fluid over many cycles.

Some situations that can cause heat checking are:

1. Cutters being dragged.

2. Reaming a slightly under gauge hole at high RPM.

JD (Junk Damage)

Junk damage can be detected by marks on any part

of the bit. Junk damage can lead to broken teeth,

damaged shirttail, and shortened bit runs and

therefore can become a problem.

Causes of junk damage are: 1. Junk dropped in the hole from the surface (tong dies, tools, etc.).

2. Junk from the drill string (reamer pins, stabilizer blades, etc.).

3. Junk from a previous bit run (tungsten carbide inserts, ball bearings, etc.).

4. Junk from the bit itself (tungsten carbide inserts, etc.).

Figure Flat Crested Wear, FC

Figure Junk Damage, JD

Figure A4-13 Heat Checking, HC


44

LC (Lost Cone)

It is possible to lose one or more cones in many ways.

With few exceptions, the lost cone must be cleared

from the hole before drilling can resume.

Some of the causes of lost cones are: 1. Bit hitting bottom or a ledge on a trip or connection.


3. Bearing failure (causing the cone retention system to fail).


LN (Lost Nozzle)

While LN is not a curing structure dulling

characteristic, it is an important "Other Dulling

Characteristic" that can help describe a bit condition.

A lost nozzle causes a pressure decrease which

requires that the bit be pulled out of the hole. A lost

nozzle is also a source of junk in the hole.

Some causes of lost nozzles are:

1. Improper nozzle installation.

2. Improper nozzle and/or nozzle design.

3. Mechanical or erosion damage to nozzle and/or nozzle retaining system.

LT (Lost Teeth)

This dulling characteristic leaves entire tungsten

carbide inserts in the hole which are far more

detrimental to the rest of the bit than are broken

inserts.

Some causes of lost teeth are:

1. Lost teeth often cause junk damage.

2. Lost teeth are sometimes preceded by rotated inserts.

Figure Lost Cone, LC

Figure Lost Nozzle, LN While LN

Figure Lost Teeth, LT


45

3. Cone shell erosion.

4. A crack in the cone that loosens the grip on the insert.

5. Hydrogen sulfide embrittlement cracks.

OC (Off Center Wear)

This dulling characteristic occurs when the geometric

center of the bit and the geometric center of the hole

do not coincide. This results in an oversized hole. Off

center wear can be recognized on the dull bit by wear

on the cone shells between the rows of cutters, more

gauge wear on one cone, and by a less than expected

penetration rate

Off Center Wear can be caused by: 1. Change of formation from a brittle to a more plastic formation. Inadequate

stabilization in a deviated hole.

2. Inadequate WOB for formation and bit type.

3. Hydrostatic pressure that significantly exceeds the formation pressure.

PB (Pinched Bit)

Bits become pinched when they are mechanically

forced to a less than original gauge. Pinched bits can

lead to broken teeth, chipped teeth, cone interference,

dragged cones and many other cutting structure

dulling characteristics.

Some possible causes of pinched bits are: 1. Bit being forced into under gauge hole.

2. Roller cone bit being forced into a section of hole drilled by

fixed cutter bits, due different OD tolerances. Forcing a bit

through casing that does not drift to the bit size used.

3. Bit being pinched in the bit breaker.

Figure Pinched Bit, PB

Figure Off Center Wear, OC


46

4. Bit being forced into an undersized blow out preventer stack.

PN (Plugged Nozzle)

This dulling characteristic does not describe the

cutting structure but can be useful in providing

information about a bit run. A plugged nozzle can

lead to reduced hydraulics or force a trip out of the

hole due to excessive pump pressure.

Plugged nozzles can be caused by:

1. Jamming the bit into fill with the pump off.

2. Solid material going up the drill string through the bit on a connection and

becoming lodged in a nozzle when circulation is resumed.

3. Solid material pumped down the drill string and becoming lodged in a nozzle.

RG (Rounded Gage) This dulling characteristic describes a bit that has

experienced gauge wear in a rounded manner, but will

still drill a full size hole. The gauge inserts may be less

than nominal bit diameter but the cone backfaces are

still at nominal diameter.

Rounded Gage can be caused by: 1. Drilling an abrasive formation with excessive RPM.

2. Reaming an under gauge hole.

SD (Shirttail Damage) Shirttail damage may be different than junk damage

and is not a cutting structure dulling characteristic.

Shirttail wear can lead to seal failures.

Some causes of shirttail damage are:

1. Junk in the hole.

2. Reaming under gauge hole in faulted or broken formations.

3. A pinched bit causing the shirttails to be the outer most part of the bit.

4. Poor hydraulics. High angle well bore.

Figure Plugged Nozzle, PN

Figure Rounded Gauge, RG

Figure Shirttail Damage, SD


47

SS (Self Sharpening Wear)

This is a dulling characteristic which occurs when

cutters wear in a manner such that they retain a sharp

crest shape.

TR (Tracking) This dulling characteristic occurs when the teeth

mesh like a gear into the bottom hole pattern. The

cutter wear on a bit that has been tracking will be on

the leading and trailing flanks. The cone shell wear

will be between the cutters in a row. Tracking can

sometimes be alleviated by using a softer bit to drill the

formation and/or by reducing the hydrostatic pressure if possible.

Tracking can be caused by:

1. Formation changes from brittle to plastic.

2. Hydrostatic pressure that significantly exceeds the formation pressure

WO (Washed Out Bit) If the bit weld is porous or not closed, then the bit

will start to washout as soon as circulation starts.

Often the welds are closed but crack during the bit

run due to impact with bottom or ledges on

connections. When a crack occurs and circulation

starts through the crack, the washout is established very

quickly.

WT (Worn Teeth)

This is a normal dulling characteristic of the tungsten

carbide insert bits as well as for the soft tooth bits.

When WT is noted for steel tooth bits, it is also often

appropriate to note self sharpening (SS) or flat crested

(FC) wear.

Figure TR (Tracking)

Figure Bit Washout, WO

Figure Worn Teeth, WT

Figure Self Sharpening Wear, SS


48

NO (No Dull Characteristics)

This code is used to indicate that the dull shows no sign of the other dulling

characteristics described. This is often used when a bit is pulled after a short run for a

reason not related to the bit, such as a drill string washout.

Drilling Bits Hydraulics Chapter # 7

49

7.1 Introduction This chapter deals with practical methods of calculating pressure losses in the various

parts of the circulating system and the selection of nozzle sizes. Several models exist

for the calculation of pressure losses in pipes and annulus. Each model is based on a

set of assumptions which cannot be completely fulfilled in any drilling situation. The

Bingham plastic, Power law and Herschel-Buckley models are the most widely used

in the oil industry.

7.2 Pressure Losses Figure 7.1 below gives a schematic of the circulating system. We have divided the

circulating system into four sections:

1. Surface connections.

2. Pipes including drill-pipe, heavy walled drill-pipe and drill collars.

3. Annular areas around drill-pipes, drill-collars, etc.

4. Drill Bit.

Figure 7.1



50

Our objective is to calculate the pressure (energy) losses in every part of the

circulating system and then find the total system losses. This will then determine the

pumping requirements from the rig pumps and in turn the horse power requirements.

7.2.1 Surface Connection Losses (P1) The pressure losses in surface connections (P1) are those taking place in standpipe,

rotary hose, swivel and Kelly. The task of estimating surface pressure losses is

complicated by the fact that such losses are dependent on the dimensions and

geometries of surface connections. These dimensions can vary with time, owing to

continuous wear of surfaces by the drilling fluids. The following equation gives

pressure losses in surface connections:

0.8 1.8 0.21P E Q PV 7.1

Where

ñ= mud weight (lbm/gal)

Q = volume rate (gpm)

E = a constant depending on type of surface equipment used

PV = plastic viscosity (cp)

In practice, there are only four types of surface equipment; each type is characterized

by the dimensions of standpipe, Kelly, rotary hose and swivel. Table below

summaries the four types of surface equipment.

Table: Types of surface equipment

The values of the constant E in Equation (7.1) are given in Table

Table: Values of constant E


51

7.2.2 Pipe and Annular Pressure Losses The pipe losses take place inside the drillpipe and drill collars and are described in

Figure 7.1 as P2 and P3, respectively. Annular losses take place around the drill collar

and drillpipe and are given the names P4 and P5 as shown in the figure 7.1. The

magnitudes of P2 , P3 ,P4 ,and P5 depend on:

Dimensions of drillpipe (or drill collars), e.g. inside and outside diameter and

length;

Mud rheological properties, which include mud weight, plastic viscosity and

yield point; and

Type of flow, which can be laminar, or turbulent.

It should be noted that the actual behavior of drilling fluids downhole is not accurately

known and fluid properties measured at the surface usually assume different values at

the elevated temperature and pressure downhole.

7.2.3 Pressure Drop across Bit Drill bits are provide with nozzles to provide a jetting action, mainly required for

cleaning and cooling, but can also help with rock breakage in soft formations. The

largest nozzle is one inch in size, often termed open, but more often the nozzles used

are a fraction of an inch. Hence, the pressure requirements to pass, say 1000gpm,

through such small nozzles will be large.

For a given length of drill string (drillpipe and drill collars) and given mud properties,

pressure losses P1, P2, P3, P4, and P5 will remain constant. However, the pressure loss

across the bit is greatly influenced by the sizes of nozzles used, and volume flow rate.

For a given flow rate the smaller the nozzles, the greater the pressure drop and, in,

turn the greater the nozzle velocity. For a given maximum pump pressure, the

pressure drop across the bit is obtained by subtracting Pc (= P1+ P2 +P3 +P4+P5) from

the pump pressure.

7.3 Fundamentals of Hydraulics The following are definitions of terms required to understand the various hydraulics

equations. The symbols and units are given with the definitions.


52

7.3.1 Shear rate (sec -1): This is a term most applicable to laminar flow. It refers to the change in fluid velocity

divided by the width of the channel through which the fluid is flowing in laminar

flow.

7.3.2 Shear stress, t (lb/100 ft): The force per unit area required to move a fluid at a given shear rate.

7.3.3 Viscosity, µ (centipoises (cp): This is the ratio of shear stress to shear rate.

7.3.4 Plastic viscosity, PV (cp): Plastic viscosity represents the contribution to total fluid viscosity of a fluid under

dynamic flowing conditions. Plastic viscosity is dependent on the size, shape, and

number of particles in a moving fluid. PV is calculated using shear stresses measured

at 600and 300 rpm on the Fann 35 viscometer.

7.3.5 Effective viscosity, µ (cp): This term takes account of the geometry through which the fluid is flowing and is

therefore a more descriptive term of the flowing viscosity.

7.3.6 Yield stress (lb/100 ft): This is the calculated force required to initiate flow and is obtained when the

rheogram (a plot of shear stress vs shear rate) is extrapolated to the y-axis at Y = 0

sec-1. In practice the yield point is calculated using Equation (7.3).

7.3.7 Gel strength (lb/100 ft): All drilling fluids build a structure when at rest. The gel strength is time-dependent

measurement of the fluid shear stress when under static conditions. Gel strengths are

commonly measured after 10 seconds, 10 minutes, and 30 minutes intervals.

7.3.8 Reynolds number, Re: This is a dimensionless number which determines whether a flowing fluid is in

laminar or turbulent flow. A Reynolds number greater than 2,100 marks the onset of

turbulent flow in most drilling fluids. For laminar flow (Re < 2,100) and for turbulent

flow (Re > 2,100).


53

Figure7. 2

Critical Reynolds number, Rec: T This value corresponds to the Reynolds number at which laminar flow turns to

turbulent flow.

7.3.9 Friction factor (f): This is a dimensionless term used for power law fluids in turbulent low and relates the

fluid Reynolds number to a "roughness" factor for the pipe.

7.4 Flow Regimes There are three basic types of flow regimes:

Laminar

Turbulent

Transitional

7.4.1 Laminar flow: In laminar flow, fluid layers flow parallel to each other in an orderly fashion, this flow

occurs at low to moderate shear rates when friction between the fluid and the channel

walls is at its lowest. This is a typical flow in the annulus of most wells.

7.4.2Turbulent flow: This flow occurs at high shear rates where the fluid particles move in a disorderly and

are pushed forward by current eddies. Friction between the fluid and the channel walls


54

is highest for this type of flow. This is a typical flow inside the drillpipe and

drillcollars. Unlike laminar flow, mud parameters (viscosity and yield point) are not

significant in calculating frictional pressure losses for mud in turbulent flow.

7.4.3 Transitional flow: Transitional flow occurs when the fluid flow changes from laminar to turbulent or

vice versa.

7.5 Fluid Types: There are two basic types of fluids: Newtonian and non-Newtonian. Newtonian fluids

are characterized by a constant viscosity at a given temperature and pressure.

Common Newtonian fluids include:

Water

Diesel

Glycerin

Clear brines

Non-Newtonian fluids have viscosities that depend on measured shear rates for a

given temperature and pressure. Examples of non-Newtonian fluids include:

Most drilling fluids

Cement slurries

In drilling operations, practically all drilling fluids are non-Newtonian. Even brines

which are used as completion fluids are not truly Newtonian fluids, as the dissolved

solids in them make them behave in a non-Newtonian manner.

7.6 Rheological Models: Rheological models (Figure 7.2) are mathematical equations used to predict fluid

behavior across a wide range of shear rates and provide practical means of calculating

pumping (pressure) requirements for a given fluid. Most drilling fluids are non-

Newtonian and pseudo plastic and, therefore, hydraulic models use a number of

approximations to arrive at practical equations.


55

Figure 7.3

The three rheological models that are currently in use are:

1. Bingham Plastic model

2. Power Law model

3. Herschel-Buckley (yield-power law [YPL]) model

7.6.1 Bingham Plastic Model: The Bingham Plastic model describes laminar Figure 7.3 Bingham Plastic model flow

using the following equation:

YP PV 7.2

Where;

ô = measured shear stress in lb/100 ft

YP = yield point in lb/100 ft

PV = plastic viscosity in cp

ã= shear rate in sec�1


56

Figure 7.4

The values of YP and PV are calculated using the following equations:

PV = è600 �è300 7.3

YP =è300 � PV 7.4

YP = (2 × è300) � è600 7.5

Figure 7.4a

Figures 7.3, 7.4 and 7.5 describe the Bingham Plastic model. The slope of a line

connecting any point on the straight line to the origin is described as the apparent

viscosity at that particular shear rate, Figure 9.4.

Figure 7.5

The Bingham Plastic model usually over predicts yield stresses (shear stresses at zero

shear rate) by 40 to 90 percent.

The following equation produces more realistic values of yield stress at low shear

rates:


57

YP (Low Shear Rate) = (2 ×è3) - è6

This equation assumes the fluid exhibits true plastic behavior in the low shear-a rate

range only.

7.6.2 Power L Aw Model The Power Law model assumes that all fluids are pseudo plastic in nature and are

defined by the following equation:

( )nK 7.6

Where

ô = Shear stress (dynes /cm)

K = Consistency Index

ã = Shear rate (sec-1)

n = Power Law Index

K and n can be calculated as

600

300

3.321log( )n

7.7

300

551nK

7.8

The constant �n� is called the POWER LAW INDEX and its value indicates the

degree of non-Newtonian behavior over a given shear rate range. If 'n' = 1, the

behavior of the fluids considered to be Newtonian. As 'n' decreases in value, the

behavior of the fluid is more non Newtonian and the viscosity will decrease with an

increase in shear rate. The constant �n� has no units.

The �K� value is the CONSISTENCY INDEX and is a measure of the thickness of

the mud. The constant 'K' is defined as the shear stress at a shear rate of one reciprocal

second. An increase in the value of 'K' indicates an increase in the overall hole

cleaning effectiveness of the fluid. The units of 'K' are lbs/100ft, dynes-sec or N/cm.

The constants n and K can be calculated from Fann VG meter data obtained at speeds

of 300 and 600 rpm through the use of Equation and Equation.

Hence the Power Law model is mathematically more complex than the Bingham

Plastic model and produces greater accuracy in the determination of shear stresses at

low shear rates.

The Power Law model actually describes three types of fluids, based on the value of

'n':


58

n = 1: The fluid is Newtonian

n < 1: The fluid is non-Newtonian

n > 1: The fluid is Dilatants

7.6.3 Herschel Buckley Yield Power Law Model The Herschel-Buckley (yield-power law YPL) model describes the rheological

behavior of drilling muds more accurately than any other model using the following

equation:

0 ( )nK 7.9

Where;

ô = measured shear stress in lb/100 ft2

ôo= fluid's yield stress (shear stress at zero shear rate) in lb/100 ft

K = fluid's consistency index in Pc or lb/100 ft sec2

n = fluid's flow index

ã= shear rate in sec -1

The YPL model reduces to the Bingham Plastic model when n = 1 and it reduces to

the Power Law model when ôo = 0. The YPL model is very complex and requires a

minimum of three shear-stress/shear-rate measurements for a solution

7.7 Practical Hydraulics Equations

The procedure for calculating the various pressure losses in a circulating system is

summarized below:

5. Calculate surface pressure losses using Equation (7.1)

6. Decide on which model to use: Bingham Plastic or Power Law

7. Calculate pressure loses inside the drill-pipe first then inside drill-collars as

follows:

Calculate critical velocity of flow

Calculate actual average velocity of flow

Determine whether flow is laminar or turbulent by comparing average velocity

with critical velocity. If average velocity is less than critical velocity the flow

is laminar. If average velocity is greater than critical velocity the flow is

turbulent.

Use appropriate equation to calculate pressure drop

4. Divide the annulus into open and cased sections


59

5. Calculate annular flow around drill-collars (or BHA) as follows:

Calculate critical velocity of annular flow

Calculate actual average velocity of flow in the annulus

Determine whether flow is laminar or turbulent by comparing average velocity

with critical velocity. If average velocity is less than critical velocity the flow

is laminar. If average velocity is greater than critical velocity the flow is

turbulent.

Use appropriate equation to calculate annular pressure drop

6. Repeat step four for flow around drill-pipe in the open and cased hole sections.

7. Add the values from step 1 to 5, call these system losses

8. Determine the pressure drop available for the bit = pump pressure - system losses

9. Determine nozzle velocity, total flow area and nozzle sizes

The following equations are given for the Bingham Plastic and Power Law models.

The field units used here are:

OD = outside diameter (in), ID = inside diameter (in), L = length (ft), ñ = density

(ppg)

V = velocity (ft/sec) or (ft/min), PV = viscosity (cp), YP = yield point (lab/100ft

7.7.1 Bingham Plastic Model

Pipe Flow Determine average velocity and critical velocity (V´ and Vc):

2

24.5QV´=

D 7.10

2 297 97 8.2C

PV PV D YPV

D

7.11

If V´> Vc flow is turbulent; use

5 0.8 1.8 0.2

4.8

8.91 10 ( )Q PV LP

D

7.12

If V´< V flow is laminar; use

2

V´90,000 D 225

L PV L YPP

D

7.13


60

Annular Flow Determine average velocity and critical velocity (V´and Vc):

2 2

24.5QV´=

hD OD 7.14

2 297 97 6.2C

e

PV PV D YPV

D

7.15

Where

e hD D OD


5 0.8 1.8 0.2

3 1.8

8.91 10 ( )

( ) )( )h h

Q PV LP

D OD D OD

7.16

If V´< Vc flow is laminar; use

2

V´60,000 D 225e e

L PV L YPP

D

7.17

7.7.2 Power Law Model Determine n and K from:

600

300

3.321log( )n

7.18

300

551nK

7.19

Where

600 2PV YP And 300 2PV YP

Determine average velocity and critical velocity (V´and Vc) 1

( ) ( )4 2 15.82 10 1.6 (3 1)

4

nn n

C

K nV

D n

7.20

2

24.5V´ Q

D 7.21


5 0.8 1.8 0.2

3 1.8

8.91 10 ( )

( ) )( )h h

Q PV LP

D OD D OD

7.22

If V´< Vc flow is laminar; use


61

2.41V´ 2n+1300 3

n

e e

KLP

D D n

7.23

7.8 Pressure Loss across Bit The object of any hydraulics program is to optimize pressure drop across the bit such

that maximum cleaning of bottom hole is achieved. For a given length of drill string

(drill-pipe and drill collars) and given mud properties, pressure losses P1, P2 ,P3,P4,P5

will remain constant. However, the pressure loss across the bit is greatly influenced

by the sizes of nozzles used, and the latter determine the amount of hydraulic

horsepower available at the bit. The smaller the nozzle the greater the pressure drop

and the greater the nozzle velocity. The graph shows the pressure drop across the bit.

In some situations where the rock is soft to medium in hardness, the main objective is

to provide maximum cleaning and not maximum jetting action. In this case a high

flow rate is required with bigger nozzles.

To determine the pressure drop across the bit, add the total pressure drops across the

system, i.e. P1+ P2 +P3 +P4+P5 to give a total value of Pc (described as the system

pressure loss). Then determine the pressure rating of the pump used. If this pump is

to be operated at, say, 80-90% of its rated value, then the pressure drop across the bit

is simply pump pressure minus Pc.

Figure 7.6


62

7.8.1 Procedure A. From previous calculations, determine pressure drop across bit, using

Pbit = Pstandpipe -P1+ P2 +P3 +P4+P5 7.24

B. Determine nozzle velocity (ft/s)

33.36 bitn

PV

7.25

C. Determine total area of nozzles (in )

0.32n

QA

V 7.26

D. Determine nozzle sizes in multiples of 32 seconds

7.9 Pressure Drop across Nozzles and Watercourses Following figure 7.6 illustrates the flow of

an incompressible through converging

(nozzles, orifice, etc.) using steady state,

adiabatic and frictionless conditions.

Using Bernoulli�s Equation;

2 21 1 2 2

2 2

P P

g g

7.27

Where

P1&P2 = pressure lb/sq. ft

= density lb/cu. ft

1 2, = velocities at points 1 &2.

Rearranging the above equation

2 22 1

2

P

g

7.28

Practically 2 2 22 1 2v v v , hence

22 2

Pg

7.29

The ideal rate of flow, 2 2iQ A the actual flow rate is

iQ CQ 7.30

Where C is the flow or nozzle coefficient for a particular design with these

substitutions the equation become

Figure 7.7


63

2

2 222

QP

gC A

7.31

Alternating Practical unit for mud flow is given by,

2

2 47430

qP

C d

7.32

Where

d= nozzle or water-cut diameter, in

Eckal & Bielstein, have shown that C may be as high as 0.98 for properly designed jet

bit nozzles; however 0.95 is commonly used for field purposes. For ordinary water-

cuts which are merely flat drilled holes C= 0.80.

7.9.1 Multiples nozzles Normally a jet rock bit has same

number of nozzle as cones. The

calculation for the purpose of multiples

nozzle bit may be simplified by

substituting the sum of the nozzle

areas for A in the above equation.

For single nozzle

2

2 222

QP

gC A

7.33

For multiple nozzles

212 2

12m

QP

gC A

7.34

However Q1 = Q/n, n= number of nozzles. Therefore

2 2 2 21 12 2 2 2 2

1 1

mP Q A Q A

P Q A n Q A

7.35

It is desired to choose an area A such as

22 2 2

12 21

1A

A n An A

Also A=nA1 7.36

Similarly for the equation

2ed nd 7.37

Where multiples nozzle vary in size

Figure 7.8


64

2 21 2 .ed ad bd etc 7.38

Where

a = number of nozzles having diameter, d1

b = number of nozzles having diameter, d2

de = hydraulically single nozzle diameter, in

Figure 7.7 gives the relation between nozzle area and the pressure drop across bit at

different GPM.

7.10 Example: Hydraulics calculations Using the Bingham plastic and power-line models, determine the various pressure

drops, nozzle velocity and nozzle sizes for a section of 12.25 in (311mm) hole. Two

pumps are used to provide 700 gpm (2650 1/min).

Data: Plastic velocity=12 cp

Yield point=12 lb/100 ft

Mud weight=8.8 lb/gal

Drill pipe ID=4.276 in

OD=5 in

Length=6,480 ft

Drill collars ID=2,875 in

OD=8 in

Length=620 ft (189 m)

Last casing was 13.375 in with an ID of 12.565 in. 13.375 in casing was set at 2,550

ft. The two pumps are to be operated at a maximum standpipe pressure of 2,200 psi.

Assume a surface equipment type of 4.

Solution

The solution to this example will be presented in Imperial units only.

7.10. 1 Bingham Plastic Model

Surface losses Surface losses in surface equipment P1 are given by

0.8 1.8 0.21P E Q PV


65

From Table: Types of surface equipment, the value of the constant E for type 4 is 4.2

x 10; hence, Equation (1) becomes

5 0.8 1.8 0.21 4.2 10P Q PV

5 0.8 1.8 0.21 4.2 10 8.8 700 12 52P psi

This graph the relation between circulation rate and pressure losses through surface

connections.

Pipe losses

Pressure losses inside drill-pipe 7.10 figure shows the relation between circulation

rate and pressure losses through drill pipe.

Figure 7.9


66

2

24.5V´ Q

D

2

24.5 700

4.276

937.97 / minft

Critical velocity 2 297 97 8.2

C

PV PV D YPV

D

2 297 12 97 12 8.2 8.8 4.276 12

8.8 4.276CV

356 / minft Since V´ >Vc flow is turbulent and pressure drop inside drill pipe is calculated from:

5 0.8 1.8 0.2

2 4.8

8.91 10 ( )Q PV LP

D

5 0.8 1.8 0.2

2 4.8

8.91 10 8.8 700 (12) 6480

(4.276)P

670 psi

Pressure losses inside drill collars Following the same procedure as for drillpipe losses, we obtain

2

24.5V´ Q

D

2

24.5 700

(2.875)

2074.9 / minft

Figure 7.9


67

2 297 12 97 12 8.2 8.8 2.875 12373 / min

8.8 2.875CV ft

Since V´ >Vc flow is turbulent and pressure loss inside drill collars P3 is determined

from

5 0.8 1.8 0.2

3 4.8

8.91 10 8.8 700 (12) 620431

(2.875)P psi

7.11 figure shows the relation between circulation rate and pressure losses through

drill collar.

Annular pressure losses From Figure 9.12 it can be seen that part of the drill-pipe

is inside the casing and the rest is inside open hole. Hence,

pressure loss calculations around the drill-pipe must be

split into (a) losses around the drill-pipe inside the casing

and (b) losses around the drill-pipe in open hole.

7.13 figure shows the relation between circulation rate and

pressure losses through annulas.

Figure 7. 11

Figure 7.10


68

Figure 7.12

Pressure Losses around Drillpipe:

Cased hole section

2 2

24.5QV´=

c dpD OD

Where the subscripts 'c' and' dp� refer to casing and drill pipe respectively.

2 2

24.5 700V´= 129.1 / min

12.565 5ft

2 297 97 6.2C

e

PV PV D YPV

D

2 297 12 97 12 6.2 8.8 (12.565) 12299.6 / min

8.8 (12.565)CV ft

Since V´ < Vc flow is laminar and the pressure loss around the drillpipe in the cased

hole is determined from:

2

V´60,000 D 225e e

L PV L YPP

D

(Where L=2500 ft)


69

2

2550 12 129.01 2550 1221

60,000 (12.56 5) 225 (12.56 5)aP psi

Open-hole section- Around Drill-pipe

2 2

24.5 700V´= 137 / min

12.25 5ft

300.4 / minCV ft

Since V´ < Vc flow is laminar and the pressure loss around the drillpipe in the open

hole section is determined from:

2

3930 12 137 3930 1235

60,000 (12.25 5) 225 (12.25 5)bP psi

Where L = 6,480 - 2,550 = 3,930 ft, and L = length of drill-pipe in the open-hole

section). Hence, total pressure drop around drill-pipe is the sum of Pa and Pb. Thus,

5 21 35 56a bP P P psi

Pressure losses around drill collars

2 2

24.5 700V´= 199.3 / min

12.25 8ft

314 / mincV ft Since V´ < Vc flow is laminar and the pressure loss around the drillpipe in the open

hole section is determined from:

4 2

620 12 199.3 620 1210

60,000 (12.25 8) 225 (12.25 8)P psi

Pressure drop across bit Total pressure loss in circulating system, except bit.

1 2 3 4 5

52 670 431 10 56 1219

P P P P P

psi

Therefore, pressure drop available for bit (Pbit)

2200 1219 981psi

Determine nozzle velocity (ft/s)

33.36 bitn

PV

98133.36 351.7 / sec

8.8ft


70

Determine total area of nozzles (in2)

27000.32 0.32 0.6369

351.7n

QA in

V

Nozzle size (in multiples of (1/32)

432 16.64

3

Hence, select two nozzles of size 17 and one of size 16. The total area of these

nozzles is 0.6397 in2 which is slightly larger than the calculated area of 0.6369 in2

7.10.2 Power Law Model

Surface losses 0.8 1.8 0.2

1P E Q PV 5 0.8 1.8 0.2

1 4.2 10 52P Q PV psi

600

300

2 2 12 12 36

12 12 24

PV YP

PV YP

600

300

3.321log( ) 0.585n

300 0.626551n

K

Remaining calculations are left as an exercise.

2 3 4 5670, 431, 5, 19, 1023, 2 16 ' 17bitP P P P P Nozzles s

7.10.3 Comparison of the two models From the above results, it is obvious that the two models produce different nozzle

sizes: the Bingham plastic model produced two 17s and one 16, whereas the power

law model produced two 16s and one 17. In practice, this difference is not considered

serious, and if the mud pumps are capable of producing more than 2,200 psi, then it is

likely that three nozzles of size 16 will be chosen. We should note also that the

turbulent flow equations presented here use a turbulent viscosity term equal to

(PV)/3.2 and not the plastic viscosity. If the plastic viscosity term is used instead, then

pressure losses will be 26% higher than those calculated by our turbulent flow

equation.


71

7.11 Optimization of Bit Hydraulics All hydraulics programs start by calculating pressure drops in the various parts of the

circulating system. Pressure losses in surface connections, inside and around the drill

pipe, inside and around drill collars, are calculated, and the total is taken as the

pressure loss in the circulating system, excluding the bit. This pressure loss is

normally given the symbol Pc

7.11 .1 Surface Pressure Once the system pressure losses, Pc is determined, the questions are how much

pressure drop can be tolerated at the bit (Pbit). The value of Pbit is controlled entirely

by the maximum allowable surface pump pressure.

Most rigs have limits on maximum surface pressure, especially when high volume

rates - in excess of 1000 gpm are used. In this case, two or three pumps are used to

provide this high quantity of flow. On land rigs typical limits on surface pressure are

in the range 2,500 - 3000 psi for well depths of around 12,000 ft. For deep wells,

heavy duty pumps are used which can have pressure ratings up to 5,000 psi. Hence,

for most drilling operations, there is a limit on surface pump pressure, and the criteria

for optimizing bit hydraulics must incorporate this limitation.

7.11.2 Hydraulic Criteria There exist two criteria for optimizing bit hydraulics:

Maximum bit hydraulic horsepower (BHHP)

Maximum impact force (IF).

Each criterion yields difference values of bit pressure drop and, in turn, different

nozzle sizes. Moreover, in most drilling operations the flow rate for each hole section

has already been fixed to provide optimum annular velocity and hole cleaning. This

leaves only one variable to optimize: the pressure drop across the bit, Pbit .

7.11 .3 Maximum Bit Hydraulic Horsepower The pressure loss across the bit is simply the difference between the standpipe

pressure and Pc. However, for optimum hydraulics the bit pressure drop must be a

certain fraction of the maximum available surface pressure.

For a given volume flow rate, optimum hydraulics is obtained when the bit hydraulic

horsepower assumes a certain percentage of the available surface horsepower. In the

case of limited surface pressure, the maximum pressure drop across the bit, as a


72

function of available surface pressure, produces maximum hydraulic horsepower at

the bit for an optimum value of flow rate as shown below:

1bit S

nP P

n

7.39

Where

n = slope of Pc VS Q

Ps= maximum available surface pressure.

In the literature several values of n have been proposed, all of which fall in the range

1.8 - 1.86. Hence, when n = 1.86, Equation above gives Pbit= 0.65 Psi. In other words,

for bit optimum hydraulics, the pressure drop across the bit should be 65% of the total

available surface pressure.

The actual value of n can be determined in the field by running the mud pump at

several speeds and reading the resulting pressures. A graph of Pc (=Ps - Pbit) against Q

is then drawn. The slope of this graph is taken as the index n.

7.11 .4 Maximum Impact Force In the case of limited surface pressure, it can be shown that for maximum impact

force, the pressure drop across the bit (Pbit) is given by:

2bit S

nP P

n

7.40

The bit impact force (IF) can be shown to be a function of Q and Pbit according to the

following equation.

58bitQ P

IF

7.41

Where

( )mudweight ppg

7.11 .5 Nozzle Selection Smaller nozzle sizes are always obtained when the maximum BHHP method is used,

as it gives larger values of Pbit than those given by the maximum IF method. The

following equations may be used to determine total flow area and nozzle sizes:

(0.0096 )bit

TFA QP

7.42

432

3n

TFAd

7.43


73

Where TFA = total flow area in2

dn = nozzles size in multiple of 1/32 in

7.11 .6 Optimum Flow Rate THE Optimum flow rate is obtained using the optimum value of Pc, n and maximum

surface pressure, Ps. For example, using the maximum BHHP criterion, Pc is

determined from

C S bitP P P 7.44

1 SC S

nP P P

n

7.45

1 SC

nP P

n

7.46

The value of n is equal to the slope of the Pc- Q graph. The optimum value of flow

rate, Qopt is obtained from the intersection of the Pc value and the Pc - Q graph.

7.12 Field Method of Optimizing Bit Hydraulic The index n can only be determined on site and is largely controlled by down hole

conditions. The following method for determining n is summarized here briefly.

1. Prior to POOH current bit for next bit change, run the pump at four or five

different speeds and record the resulting standpipe pressures.

2. From current nozzle and mud weight determine pressure losses across the

bit for each value of flow rate, using Equation of nozzle selection.

3. Subtract Pbit from standpipe pressure to obtain Pc.

4. Plot graph of Pc against Q on log-log graph paper and determine the slop

of this graph which is the index n in equations.

5. For the next bit run, equation 7.7 and 7.8 is used to determine Pbit that will

produce maximum bit hydraulic horsepower. Nozzle sizes are then

selected by use of this value of Pbit.

For a particular rig and field the index n will not vary widely if the same drilling

parameters are used. For standardization purpose it is recommended that the above

test be run at three depths for each bit run. The average value of n for each bit run can

then be used for designing optimum hydraulics.


74

7.13 Example: Hydraulics Optimization Given data: Hydraulic Horse power of pump =1211 hp

Maximum permitted surface pressure Ps = 3500

Hole size = 12.25�, Mud density = 13 ppg,

Drillpipe= 5�/4.276�

Pc = K Qn K =0.01, n =1.86

Use the BHHP to calculate:

Pc, Pbit BHHP and IF

Solution:

1. BHHP Criterion

1bit S

nP P

n

1.863500 2276

1.86 1bitP psi

%Power at bit =2276/3500=65

3500 2276 1224C S bitP P P psi

nCP kQ

1.861225 0.01

554

nQ

Q gpm

Hence the optimized values are: Pc = 1224 psi, Q = 544 gpm and Pbit = 2276 psi

2

(0.0096 )

13(0.0096 544) 0.3947

2276

4 4 0.394732 32 13.1

3 3

bit

n

TFA QP

in

TFAd

(i.e. select three 13�s nozzles for a tricone drillbit)

58

544 13 22761613

58

bitQ PIF

IF lb ft


75

7.14 Hydraulic and ROP It has been established that penetration rate in many formation is proportional to the

hydraulic horsepower expended at the bit. Realization of factor and subsequent

widespread use of jet bits has reversed the trend to small drill pipe sizes which existed

a few years ago. Pressure drops inside the drill string are a large part of total system

losses, and it is obvious that an increase of inside diameter will greatly improve

hydraulic efficiency. Consequently tool joints which have little or no internal

restriction are most commonly used. The use of large drill pipe and drill collars also

entails closer hole-pipe clearance; thus the desired annular velocity can be obtained at

lower circulation rates. In addition, annular velocity requirements have been

reappraised and lower figures are now being applied.

7.15 A practical check on the efficiency of the bit hydraulic program 1. Detemine pressure drop across bit Pbit.

2. Determine bit hydraulic horsepower (BHHP).

bitBHHP P QkW 7.47

3. Divide BHHP obtained above by area of bit to determine k where k.

2 / 4

BHHPk

d 7.48

4. For maximum cleaning k should be between 3 and 6 HHP/sq. in (3.74-6.94 watts/

sq. mm).

Drilling Bit Optimization Chapter # 8

76

8.0 Optimized Bit Technology

In this category of bits, two main bits can be discussed and they are given as follow

PDC Impregnated Bits

PDC Hybrid Bits

8.1 Impregnated PDC Bits

These bits are ideal for drilling abrasive formations because of their self-sharpening

cutting structure that replenishes itself as the bit wears. Impregnated bits utilize sharp,

grit-size diamonds sintered directly into a tough tungsten carbide matrix.

The matrix is formulated to match the application so the carbide matrix wears slightly

faster than the diamond. This ensures fresh, sharp diamonds are exposed at the

optimal rate for maximum ROP and bit life.

8.1.1 Advantages

Impregnated bits are made of segments consisting of carbide matrix and crystalline

synthetic diamonds that are exposed approximately ½ mm. They drill in a similar

fashion as natural diamond bit; the improvement is that as diamond becomes worn the

new diamonds are exposed. This gives them to drill the hardest, the most abrasive

formation at high RPM with a service life several time that of natural diamond. By

definition these are matrix bodies bits, the binding material however differ from that

used for other type of formation for which the bit is designed. It normally contains not

Figure 8.1



77

only cobalt and nickel but also copper and tungsten carbide. As the diamond particle

wear, new diamond particles are exposed.

8.1.1 (a) Enhanced Hydraulics

Impact-force directed where balling occurs with unique ported design. Enhanced ROP

with deep junk slots that optimize cuttings removal and limit hole swabbing during

trips.

8.1.1 (b) Matrix Flexibility

The matrix wears slightly faster than the diamond to ensure the most efficient cutting

structure. Each matrix formulation is matched to the lithology, achieving the optimal

rate of fresh, sharp diamonds for enhanced ROP.

8.1.2 Disadvantage

Due to the small depth of cutters, impregnated bits are well suited for very hard

formation; however, this small diamond exposure can be easily sealed off when

encountering soft rock. In the absence of abrasive sandstone to clean the segments,

the entire bit can be plugged off. The chart below shows the relation between the ROP

and WOB for this bit. The other chart also shows the same relation for the shale.

8.1.3 Effect of temperature

During drilling the impregnated segment surface should have the texture of sandpaper

with sufficient fluid to keep the cutting structure cool in addition to remove cuttings.

Inadequate hydraulics could result in excessive temperature causing the segments to

burn due to high rotational velocities.

Figure 8.2


78

8.1.4 Possible Remedies

A. Due to the hardness and abrasiveness of formation, the primary concern was bit

durability. For this purpose, an IADC class M841 Impregnated bit was selected that

maximizes diamond volume on bottom with sufficient waterways to keep the

segments cool while providing adequate cleaning.

B. Whenever there is chance of baling we use a new IADC class M841 impregnated

diamond bit with multiple interrupted segments to minimize the distance cuttings are

required to travel before reaching a waterway. These bits consist of diamond

impregnated segments bonded into the matrix body. The segments are made from a

mixture of synthetic diamond and tungsten carbide matrix bonded together under high

pressure and temperature.

8.2 PDC Hybrid Drill Bits

The main problem with extended PDC usage into these abrasive formations was to

resolve the problems associated with excessive temperature arise of PDC cutters. This

is a result of this harder formation to shear in a manner most suitable for PDC bit

drilling. Combined with this, the susceptibility of PDC to impact damage and it is no

surprise that hard formation led to rapid wear to try the decrease in these effects, a

secondary cutting structure was developed. This involved setting a diamond

impregnated stud behind and separate from the PDC spud cutters. This behaves in

following way:

When the bit is new the PDC cutting structure acts along to ensure maximum ROP.

Upon entering into harder formation wear of PDC brings the diamond impregnated

stud into contact with the formation. This serves to reduce the cutter loading on the

diamond layer and is associated tungsten carbide wear area reducing heat build up and

chances of the impact damage. The increased support to the PDC cutter also allows

greater weight to be run with a reduced chance of cutter breakage due to cutter

Figure 8.3


79

overloading.

A diamond impregnated stud was chosen because of its durability in harder formation.

The stud was kept separate from the PDC cutter to enable good heat dissipation from

the formation and stud interface. Sometimes hybrid consists of PDC cutters along

with thermally set polycrystalline cutters and diamond impregnated on the back side

for very hard and abrasive formation. PDC and TSP are used for soft to medium and

impregnated for hard and abrasive formations.

8.3 Design Optimization as Applied to Cutting Structure

In the foregoing only those basic fundamentals of rock-bit design which are common

to all types have been considered. Factors which govern basic cone or cutter

configuration and various design criteria apply regardless of whether the type under

consideration is for a soft or a hard formation. The design of a bit for use in a specific

category of formations obviously requires the application of additional design factors.

For example, journal angle and offset values, roiling characteristics of the cones, and

the effect of tooth depth on bearing-structure size, represent several of the factors

which must be considered in the cone-bit design.

8.3.1 Action of the cones

The action of the cones on the formation is of prime importance in regard to the

ability of a bit to drill with a desirable penetration rate. A soft-formation bit requires a

gouging-scraping action, whereas a hard-formation bit requires a chipping-crushing

action. Basically, these actions are governed by the degree to which the cones

approach that of a true roll. A maximum gouging-scraping action requires rolling

characteristics which vary the greatest from that of a true roll. A chipping-crushing

action requires that which more nearly approaches that of a true roll.

Factors in the design which produce these desirable characteristics are:

Degree of journal angle

Amount of offset

Profile of the cone

Bearing structure

Teeth depth


80

A combination of the smallest journal angle, largest offset angle, and greatest

variation in cone-profile angles will develop an action which varies the most from that

of a true roll. Conversely, a combination of the largest journal angle, no offset and

least variation in the cone profile will result in an action which closely approaches

that of a true roll.

8.3.2 For a hard formation

For the hard formation following factors may be considered

No offset; so that a hard-formation bit requires a chipping-crushing action. This

factor provides the necessary support.

Largest journal angle; so that these journals assist the excessive weight on bit. If

we keep journal angle small then this excessive load can break the journals.

Largest Bearing Structure; in the hard formation, generally the weight on bit is

kept very high to withstand these loads the bearing structure kept large.

Least Profile variation; tooth to tooth and tooth to groove spacing kept small

because in the hard formation, we have to increase number of cutters so that the

maximum impact is require and less wear and tear is observed. Due in part to

the abrasiveness of most of the hard formations and, in part, to the chipping

action of the bit, the teeth must be closely spaced to counteract rapid tooth.

Tooth angles must be kept large to withstand the heavy loads required to

overcome the compressive strength of the formation

Shallow Teeth; the teeth on a hard-formation bit are shallow, heavy, and closely

spaced. Due in part to the abrasiveness of most of the hard formations and, in

part, to the chipping action of the bit, the teeth must be closely spaced to

counteract rapid tooth wear and excessive lateral loading

For Soft Formation Figure 8.4 For Hard Formations


81

8.3.3 For a soft formation

For the soft formation above considerations are reversed.

Largest offset; in the soft formation the offset is kept largest, as here we need

gouging and scraping action and cuttings structure should be large.

Smallest Journal Angle; as the soft formations are not very abrasive, so the weight

on bit is kept small and hence the smallest journal angle.

Smallest Bearing Structure; as the weight on bit is kept small in case of soft

formation so that bearing structure is also kept small so that we may use more

space for other structure.

Greatest Profile variation; in the soft formation the tooth to tooth and tooth to

groove spacing are kept large for maximum cleaning and to avoid bit balling in

such soft and sticky formation.

8.4 Bit Selection and Drilling Parameters:

Having arrived at a carefully considered position on which bit is likely to be best for

each formation the following information should be included in the drilling program.

1). Recommended bits for each hole size, showing in each case the best offset

bit and why the recommended bit differs (if it does).

2). Anticipated BHAs for each part of the well.

3). Recommended ranges of drilling parameter for each bit.

4). Expected performance of each recommended bit for example footage to drill and

average ROP.

8.5 Bit Choices:

Sometimes the next bit in may have to drill to a particular depth (coring

point, for instance), which is considerably less distance than would be expected from

a full bit run. It may be possible to run a cheaper (or used, re-useable) bit instead. The

rig need a list of bit prices and the drilling supervisor should consider bit cost

when making the selection. For example, it may be that the bit being pulled

early has already drilled through an abrasive zone where premium gauge

protection was used. The next bit in May not require this expensive feature

and so a cheaper alternative may be possible.


82

8.6 Refining Bit Choice and Parameters Based On Previous Bit Run

A good bit choice, run correctly and pulled at the end of its economic life,

should show worn cutting structure and/or bearings. Severe dull bit features

(excessive gauge loss, broken cutters, cones locked, etc.) are warnings that

something went wrong, especially if the performance fell below expectations.

Try to ascertain what conditions may have caused the specific dull conditions

and evaluate what changes could be made to bit choice running procedures,

drilling parameters, BHA, mud, etc., to reduce the impact of these conditions.

For example, a common mistake is to assume that broken teeth equates to a

bit that is too soft; there are other more likely causes in most cases.

Downhole shock or vibration, hard nodules, or junk could all play a part.

Running too hard a bit for the formation is likely to compromise your overall

bit performance.

8.7 WOB (Weight on Bit):

When drilling, weight is applied to the cutters so that rock is penetrated. Up

to certain limits the more weight applied the faster the bit will drill. If too

much weight is applied, the cutters may become completely buried (known as

bit flounder) and weight will be taken by the cones or bit body. This will

reduce ROP and rapidly wear the cones. Increasing weight will also

accelerate wear on bearings and cutters.

Deviation is also affected by WOB. A rotary locked or build assembly will

have an increasing build tendency with greater weights; where a rotary

pendulum is in an established drop then increasing weight will tend to

increase drop, up to a point where further increasing the weight may produce

unpredictable results. In a vertical borehole with a flexible pendulum or build

BHA, increasing weight will deflect the well path from vertical. In a motor-

bent sub combination increased weight will increase side force at the bit, and

therefore accelerate the rate of direction change in the direction of tool face

azimuth, up to the point where motor stalls. When planning to change hole

direction, the BHA selected may dictate the approximate WOB to be used,

which may affect the bit Choice.


83

8.7.1 Weight-RPM:

Pan American's optimized drilling program is based on equations developed

by Galle & Woods and Billington & Blenkarn, which define how the

complex relationship between weight-on-bit and rpm affects the wear of a bit

it in a particular formation. To get some concept of optimization, it is

important to understand what these equations can provide in terms of data

output. Using these equations, the weight: rotary-speed relationship can be

categorized as follows:

8.7.2 Variable RPM-weight:

Because so few rigs are electric or completely versatile as far as range of rpm

and weight is concerned, little use can be made of a variable optimum rpm

and weight program. However, it is the most efficient method for drilling

with mill tooth bits.

8.7.3 Constant RPM- Variable Weight:

This method for drilling with mill tooth bits appears to be practical.

Generally, good drillers gradually apply more weight as bits become dull.

This method has not been widely accepted since it requires an automatic

driller and more supervision than other weight-rpm programs. However

where applicable, the constant rpm and variable weight method is

considerably more efficient than constant rpm and constant weight programs.

8.7.4 Constant RPM and Weight:

Because of the limitations indicated above, most computer programs have

been restricted to constant rpm and weight. Because so many limitations do

exist, it has been necessary to make programs as flexible as possible and to

cover as wide a range as the drilling engineer considers necessary. There are

three available approaches:

8.7.4 (a)Optimum RPM and Weight:

This is the rpm and weight that one might run if no limitations except the bit

could be considered. This is the rpm and weight for absolute minimum cost,

not considering any other factors such as condition of drill string, deviated

hole or development of torque.


84

8.7.4 (b) Best Weight for given RPM:

Should formation or rig capability limit rpm, the program will determine the

proper weight for minimum cost with imposed restrictions. This will cost

more per foot than when optimum rpm and weight are used.

8.7.4 (c) Best RPM for given Weight:

Should the available drill collars or deviation control dictate a certain weight-

on-bit this program predicts proper rpm for optimum cost considering this

restriction. This cost will also be more than for optimum rpm and weight.

8.8 Drill off Test

8.8.1 To Optimize WOB and RPM.

1. Prior to running bit, check the Drilling Programme for the recommended

parameters to be used with the bit. This will typically be a range suitable for

the bit type to be used.

2. Check the rotary speed using rope marker on Kelly bushing and stopwatch.

3. Mark and measure drill-off interval on Kelly, L, such that LROP = 0.1.

(This is to prevent excessive time spent drilling with less than optimum

parameters; the test should take approximately 6 minutes).

4. Set and maintain a predetermined WOB at the light end of the range whilst

measuring time taken to drill interval L.

5. Calculate ROP in ft/hr and plot graphically against RPM.

6. Increase rotary speed in 10 rpm increments and plot the resultant ROP.

Select the point at which an increase in rpm does not give corresponding

proportional increase in ROP. From the graph of data points generated, select

the rpm which corresponds to the maximum ROP. Monitor and record the

level of torque throughout test.

7. Repeat steps I through 6 above, maintaining the selected rpm whilst

varying WOB in 2K increments. Plot the WOB against ROP for each

increment. If increased WOB does not result in a proportional increase in

ROP, reduce WOB to the previous optimum level. Plot graph of data points

to select the optimum WOB. Monitor torque through test.


85

8.8.2 To Optimize Hydraulics:

Where ECD (Equivalent Circulating

Density) conditions permit pump

parameters can be optimized by drill-

off tests to achieve optimum bit

performance. This is particularly

important when running PDC bits

which require efficient hydraulics to

maintain a clean cutting structure

and achieve effective bottom hole

solids removal.

The following procedure may be used

1. Use the optimum WOB and RPM as selected in the above drill-off test.

2. Increase the pump rate in 20 strokes increments and record the resultant

ROP. Plot the data points and determine the optimum flow rate which results in the

optimum.

8.9 ROP (Rate of Penetration):

To prevent damage to bit drill string or lost circulation variations in

parameters must never exceed those specified in the Drilling Program. Two

drill-off tests must be conducted per tour when drilling the same formation

with one additional test when any formation change is encountered.

8.10 Rotary Speed and RPM:

Increasing RPM will increase ROP up to a point where the cutters are moving

too fast to penetrate the formation before they move on. Excess RPM will

cause premature bearing failure or may cause PDC or diamond cutters to

overheat. Deviation is also affected by RPM. Higher rotary speeds tend to

stabilize the directional tendencies of rotary BHAs. A rotary BHA has a

natural tendency to turn to the right; this tendency is weaker at higher rotary

speed.

Figure 8.5


86

Rotary speeds that cause string vibrations (critical rotary speeds) must be avoided.

The driller should recognize this condition and modify RPM accordingly.

Two types of vibration can be related to drillstring rotary speed and the

calculated approximate speed of occurrence.

8.10.1 Longitudinal Drill-string Vibration:

Longitudinal 78640

critp

VL

Where Lp length of DP string, meters (Critical vibrations also at 4x and 9x

this value.)

8.10.2 Transverse Drill-string Vibration:

Transverse 2 2 247000 /critV D d L

D = pipe OD

d = pipe ID

L = joint length

(All measurements are in inches)

8.11 Minimizing Bit Whirl:

Bit whirl occurs where the friction at the gauge of the bit makes the center of

rotation locate itself at the edge of the bit (where the formation is in contact),

instead of the geometric center. Since the forces on the cutters are now in

different directions than the designed direction, cutter breakage can result.

Bit design seems to be the dominant factor. Good stabilization probably

decreases bit whirl and many bits are already advertised to be an "anti-whirl"

design. Whirl is often initiated when the bit just starts drilling, such as after

making a connection. Research has indicated that using the following

procedure after making a connection will minimize the chances of bit whirl

starting: While still off bottom, bring the mud pumps and the rotary table up

to speed. Slowly slack off until the bit starts to take weight. Increase the

WOB in small increments (say about 20% of planned total WOB) and allow

the rotary table to stabilize in between increments for 10-30 seconds (longer

for deeper ho 1 e).


87

8.12Monitoring Bit Progress While Drilling:

Cost per foot calculations should be done while drilling. Once the cost per

foot starts to increase, the bit will be nearing the end of its economic life. However,

several other factors should be considered making a decision to pull the bit.

Pull the bit earlier if there are indications of bearing failure (high and/or

fluctuating torque on bottom compared to steady, reasonable torque just off

bottom).

Leave the bit in longer if offset information indicates that the slowdown is mainly due

to decreasing formation drill-ability. Sometimes a bit is pulled under

these

circumstances and the next bit in does not drill any faster. Clearly in this case it is

better to extend the bit run if there are no concerns as to bit condition. The hole

section summary showing offset bit runs at the same place may indicate this.

There are different theories that aim to make a bit pull decision easy, such as by hours

on bit or number of revolutions. However, these will lead to below optimum drilling

performance and should only be used when bit bearing condition

cannot be monitored. It is possible to consistently pull bits at the end of their

economic lives, maximizing the overall performance without seriously risking

leaving cones n the hole. This requires close and skilled supervision of the run.

8.13 When to Pull the Bit:

"Cost per foot" calculations can help to decide when to pull the bit. If this

is done consistently, the chance of having to fish for cones is small and the

overall cost per foot will be minimized. The point where the cost per foot is

consistently increasing is the point that the bit should be pulled. If the

indications are to pull the bit, do not waste time drilling the Kelly down. This may

be modified by other factors. Pull the bit early if there are any signs of bearing

failure;

8.14 Post-Drilling Bit Analysis:

Proper analysis of the bit run is important to improve future performance. A

large problem is that different people will grade a particular bit differently.

The IADC 8 point grading scheme is vastly better than the old TBG


88

grading, however, if grading are not done with care, it will mislead future

drillers. Record grading details and comments on the bit report. Make more

extensive comments and recommendati9ns in the end of section report for

inclusion in the final well report. The IADC 8 point grading should always

be used to grade bits. The first four digits refer to the cutting structure. The

last four digits refer to other characteristics.

Case Study of A Field Chapter # 9

89

9.0 Introduction A field namely �A� consists of wells X, Y and Z. The name of different formations in

this field are F1(shale), F2(limestone), F3(shale), F4(limestone), F5(sandstone),

F6(limestone), F7(shale), F8(sandstone), F9(shale),F10(sandstone), F11(shale) and

F12(limestone). During drilling these formations, there were losses of circulation in

the F1 (shale) and F2 (limestone) formations. Also the there are two abandoned well.

One well was abandoned due to fishing, and the other well went dry due to which it

was abandoned. There was also a developing well in this reservoir which is under

drilling process. The formations in this field were a combination of different rocks

due to which different bits and drilling parameters were used to drill.

9.1 Problems Encountered During Drilling the Formations: 1. Reduce rate of penetration

2. Lost circulation

3. Balling of bit

4. Erosion of bit

5. Worn of teeth

9.2 Cause of such Problems: 1. Basically we were drilling soft formation, we put all the parameters of bit

according to the soft formation but during drilling encountered hard formation

due to which the rate of penetration ROP has been decreased and caused the

bit to pull. It was a great loss of trip time because bits were coming out of the

hole before its economic life.

2. Due to the lost circulation cutting were not coming back to the surface and the

circulation rate was high, due to which the bit was eroded.

3. When you are drilling a sticky formation, a very common problem balling of bit

can occur.

4. Excessive hydraulics resulting in high velocity fluid erosion. Abrasive drilling

fluids or poor solids control.

5. This is the normal drilling problem and is caused by small metal junk.

Excessive string vibrations or shock holding. Excessive WOB.



90

9.3 Solution of such Problems

1. For the soft formation we should use bit of such type which has smallest journal

angle, largest offset, small bearings structure set and large size of cutters.

2. Drilling such formation having lost circulation problems, the remedy to such

types of problems is to use air or foam drilling.

3. Use with bits maximum number of nozzles fitted in optimized geometry. Also

check the hydraulics in this situation.

4. For the problem of bit erosion we check the hydraulics for the bit to be used..

9.4 How Air and Gas Drilling Optimized ROP in Such Formation The most severe restriction on air and gas drilling fluids is their inability to control

encountered subsurface pressures. When a permeable zone drilled, its fluid content

readily enters the borehole and interferes with normal circulation. Water entry is the

most common problem and its removal may require prohibitive air circulation rates.

Small quantities of water from low permeability formations, while posing no removal

problem, do cause cutting balling and general hole stickiness which may result in

stuck drill pipe. This is the most severe problem than large water volume. Much work

is being done to develop materials and techniques for effectively sealing encountered

water formations. Such methods will have to be fast, safe, and must be performed

with a minimum of special equipment in order to be economically feasible. This

technique holds considerable promise; the cost of the foaming agents, however, must

be balanced by the increased penetration rate.

9.5 Advantages of Bits in Air and Gas Drilling Over Rotary Conventional Drilling The principal advantages of air and gas drilling over conventional rotary drilling are

given as under

Low pressure and low permeability water zones may be drilled without danger of

pipe sticking.

Quick weight buildup is immediately obtained by shutting off the injected air.

Explosion and fire possibilities are minimized by the water in the mixture.

Here we include another example of Drilling Bit Optimization. In this example we

have a gas producing zone having a thickness of 800 ft of alternating Shale and


91

Sandstone. Water sensitive Clay contents, low matrix permeability, and a natural

fracture system all contribute to drilling and completion Problems. A comparison of

Conventional Drilling and Air Drilling is given the following table:

Drilling Method Time Required Bit

Used Remarks

Rotary, Conventional Mud 10-20 days 8-10 Sever Formation Damage

Rotary Gas Drilling 4 ½ days 3-4 Higher Well Productivity

A major benefit is the greater well productivity brought about by decreased

permeability damage. A further, economic incentive is that drilling gas is normally

furnished by adjacent gas producing wells this eliminate the need for compressors.

9.6 Optimization of new well in this formation In order to drill a new well in the same formations, we shall make the following

considerations.

Air and gas drilling in the zone of lost circulation from 0-500 m F1 (shale), F2

(limestone), F3 (shale)) by using extended nozzle bits to overcome the lost

circulation.

For further drilling from depth 500-2200m (F4 (limestone), F5 (sandstone), F6

(limestone)), we shall use conventional and normal roller-cone bits as there are not

problematic zones.

As we have different types of formations in this deep zone, we go further with turbo-

drilling from 2200-3300m (F7 (shale), F8 (sandstone), F9 (shale), F10 (sandstone),

F11 (shale) and F12 (limestone)) with the help of impregnated bits for hard and

abrasive formation such F12 (lime stone) and hybrid bits for soft formation such as

(F7 (shale), F8 (sandstone), F9 (shale), F10 (sandstone), F11 (shale).


92

The bits record of the well under discussion

Bit Bit Bit Bit Jet Depth FT ROP Weight RPM Pump

No. Size Mfgr. Type Size Out formation LB Press

1 26.00 STC MSDSHC 3X20 104.0 shale 104.00 1.30 0-10 90 700

2 26.00 STC MSDSHC 3X20 169.0 shale 65.00 1.50 0-10 110 700

3 17.50 HW GTX-C03 3X20 283.0 lime stone 114.00 5.70 25.00 90 400

4 17.50 VAREL CR3GJMRS OPEN 300.0 lime stone 17.00 2.10 28.00 85 100

5RR 17.50 HW GTX-COR OPEN 392.0 lime stone 92.00 3.68 28.00 95 100

6 17.50 VAREL CR1GJMRS OPEN 502.0 Shale 110.00 5.78 24.00 90 150

7 12.25 HUGHES GX-09 3x16 792.0 Shale 290.00 5.70 14-16 110 560

8 12.25 HUGHES HC606Z

6x14

2x16 800.0 Shale 7.00 8.00 4 to 6 120 900

9 12.25 HUGHES GX-C20 OPEN 836.0 Shale 36.00 2.70 12 to 14 120 500

10RR 12.25 SMITH FDS OPEN 872.0 Shale 36.00 3.20 10 to 12 120 422

9RR 12.25 HUGHES GX-C20 OPEN 974.0 Shale 102.00 3.10 10 to 12 120 500

8RR 12 1/4 HUGHES HC606Z

6x14

2x16 976.0 Shale 2.00 0.50 4 to 8

120-

160 834

7RR 12 1/4 HUGHES GX-09 3x16 1013.0 Shale 55.00 2.07 6 to 8

120-

130 1363

11 12 1/4 VAREL CH1GJM 4x 16 1151.0 Shale 120.00 2.94 12 to 14

110-

120 1135

12 8.5 SMITH MFDGH 3x14 1199.0 sandstone 48.00 3.20 6 to 8

90-

120 1000

13 8.5 SECURITY EBXS55 3x16 1275.0 sandstone 76.00 2.80 12to14

120-

130 1040

14 8.5 SMITH XR+ 3x14 1306.0 sandstone 31.00 3.20 6 to 8

115-

120 1200

15 8.5 SMITH M813VPX

3x12,

3x14 1354.0 sandstone 48.00 4.80 4 to 6

115-

120 1035

14RR 8.5 SMITH XR+ 3x14 1393.0 sandstone 39.00 1.25 10 75 216

13RR 8.5 SECURITY EBXS55 3x16 1394.0 lime stone 1.00 0.50 10 65 216

16 8.5 REED TD41A 3X18 1491.0 lime stone 89.00 3.37 10 65-85 325

17 8.5 SECURITY EBXS55 OPEN 1579.0 lime stone 88.00 2.31 10 65-85 500

18 8.5 SECURITY EBXS085 OPEN 1680.0 lime stone 101.00 2.50 10 65-85 485

19 8.5 SMITH F3 OPEN 1736.0 lime stone 56.00 1.10 12

125-

65 500

20 8.5 REED TD41A 3X18 2015.0 lime stone 279.00 2.75 12 65 800

21 8.5 SECURITY FIX6632 6X18 2468.0 Shale 453.00 6.68 6 90 870

22 6 SMITH XR+ OPEN 2491.0 lime stone 23.00 1.70 7 70 1558

23 6 REED SL53 3 x 16 2593.0 lime stone 102.00 1.54 6 to 8

75 to

85 2010

24 6 SMITH M813PX 4 x 12 2627.0 lime stone 34.00 3.00 4 to 6

75

to80 2130

25 6 HUGHES HC406 4 x 12 2673.0 lime stone 46.00 1.44 4 to 12

75 to

100 2150

26 6 SMITH XR10TPS 3 x 14 2751.0 lime stone 78.00 1.85 7 to 9

75 to

85 2433

27 6 REED SL51HKP 3 x 16 2860.0 Shale 109.00 2.47 7 to 8

75 to

85 2130

28 6 SECURITY XS20S 3 x 16 2956.0 sandstone 96.00 1.96 7 to 8 75 to 2246


93

85

24RR 6 SMITH M813PX 4 x 12 3009.0 sandstone 53.00 1.73 4 to 9

75 to

100 2167

29 6 HUGHES STX-20 3 x 14 3070.0 sandstone 61.00 1.39 8 to 10

70 to

75 2440

30 6 REED SL51HP 3 x 14 3229.0 lime stone 159.00 2.65 8 70-75 2500

REFERENCES 1) Petroleum Engineering, Drilling and Well Completion; by Carl Gatlin.

PRENTICE-HALL, INC. 1960.

2) Well Engineering & Construction by Hussain Rabia.

3) Drilling Practices Manual by Preston L.Moore.

Second edition;PennWellBooks.

4) IADC Drilling Manual,eBook Version (V.11)

5) Advanced Oil Well Drilling Engineering Hand book & Computer programs; by

Mitchell

10th edition, 1st revision July 1995.

6) Smith Tools �Bit Selection, Design, and Evaluation Manual� by H.G.Bentson.

7) Drilling Optimization Service; End of Well Report; Presented To Norsk Hydro

8) www.bitbrokers.com

9) www.xeg.ca

10) www.HCCbits.com

11) www.lonestarbits.com


http://www.bitbrokers.com

http://www.xeg.ca

http://www.HCCbits.com

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