specifications - ТОРГОВОЕ …torgpredstvo.rs/kontent/kom_106/catalogue1.pdf2 roller bit...

2

Roller bit designation system (product lines, prefixes, suffixes)

The IADC roller bit classification system

Tungsten carbide insert bits (Chart C�1)

Milled tooth bits (Chart C�2)

Standard nozzle list (Chart C�3)

Stabilizers (Chart C�4)

Roller cone bit subs (Chart C�5)

SPECIFICATIONS

SECTION 1. ROCK FAILURE

1.1 Rock failure mechanics

1.2 Drilling practices selection

1.3 Practical use of bit runs results

SECTION 2. AIR CIRCULATION SYSTEM

2.1 Bottom hole cleaning

2.2 Required drilling rig compressor output

2.3 Nozzles selection

2.4 Nozzles replacement

2.5 On�site compressor output measurement

SECTION 3. GUIDELINES TO ROCK BIT OPERATION

SECTION 4. DULL BIT ANALYSIS

SECTION 5. SELECTION OF EFFICIENT ROCK BIT DESIGNS

5.1 Mining and geological drilling conditions analysis

5.2 Technological drilling conditions analysis

5.3 Rock bit performance statistics analysis

5.4 Dull bit analysis and reasons bit failed

5.5 Rock bit cutting structure and bearing design features analysis

5.6 Analysis of techno�economic indicators of rock bits performance basing on bit test results

5.7 Training at Volgaburmash Training Center

SECTION 6. ROCK BITS STORAGE AND TRANSPORTATION

APPENDICES

3

8

9

11

11

12

12

14

15

18

19

20

21

21

22

33

33

34

34

34

35

35

TABLE OF CONTENTSTABLE OF CONTENTS

ROLLER CONE MINING BIT CATALOG

ROCK BIT DESIGNATION AND DESIGN FEATURES

MANUAL

CONTACT INFORMATION

3

9

14

19

24

25

33

36

37

42

3ROLLER CONE MINING BIT CATALOG

АUL N V

sealed bearing: radial journal bearing – elastomer seal –

floating split bushing – ball bearing – thrust journal bearing with a thrust washer –

radial journal bearing

open bearing: roller bearing – ball bearing –

thrust journal bearing – radial journal bearing – thrust journal bearing

open bearing: roller bearing – ball bearing –

thrust journal bearing – roller bearing –

thrust journal bearing

X chisel inserts

Y conical inserts

Z other shape inserts

T enhanced teeth hardfacing

P near gauge of tungsten carbide inserts

G single gauge of tungsten carbide compacts

GG double gauge of tungsten carbide compacts

W enhanced heel row

250.8 V - ALS 74 Y – R824-1

Bit diameter, mm

Product line

Modification by bit and leg (prefixes) First two IADC code figures

Modification by cone (suffixes)

Design number

A jet circulation

АС center circulation

L shirttail and leading edge hardfacing

LLleg leading edge hardfacing and enhanced shirttail hardfacing

S leg protection with tungsten carbide compacts

Tungsten carbide insert bit

9 7/8” AUL-ALS72Y-R976

ROCK BIT DESIGNATION AND DESIGN FEATURESROCK BIT DESIGNATION AND DESIGN FEATURES

PRODUCT LINES (series by bearing types)

АUL PRODUCT LINE

PREFIXES SUFFIXES

Radial journal bearing

Elastomer seal

Floating split bushing

Thrust journal bearing with a thrust washer

Ball bearing


ROLLER BIT DESIGNATION SYSTEM

ROLLER CONE MINING BIT CATALOG4

Tungsten carbide insert bit

6” N-A51Y-R281 Milled tooth bit

6 1/4” N-ALS21-R256

Roller bearing

Ball bearing

Thrust journal bearing



Milled tooth bit

12 5/8” V-A31-R198M

Roller bearing

Ball bearing


Roller bearing

Thrust journal bearingTungsten carbide

insert bit

9 7/8” V-ALS42Y-R430

N PRODUCT LINE

V PRODUCT LINE



5www.vbm.ru

Tungsten carbide thrust button

Air cooling passages

Thrust bearing

Air exit

Ball plug

PREFIXES USED FOR VARIOUS CIRCULATION TYPES

A – jet circulation АС – center circulation

L – leg leading edge and shirttail

hardfacing

LL – leg leading edge and enhanced

shirttail hardfacing



V-CONFIGURATION BEARING

PREFIXES

PREFIXES USED FOR VARIOUS SHIRTTAIL AND LEG PROTECTION CONFIGURATIONS


S – leg protection with tungsten

carbide compacts

X – chisel inserts

Y – conical inserts

Z – other shape inserts

T – enhanced milled tooth hardfacing

G –single gauge of tungsten carbide

compacts

GG – double gauge of tungsten carbide compacts

Р – near gauge of tungsten carbide

inserts



SUFFIXES

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The air passes

through the bit bearing

for proper cooling and

maximized bearing life.

Co

mp

res

se

d

air

Leg air passages

Bearing air passages

Valve assembly

Ball plug

Air tubes

While drilling the air flows into the bit shank, the valve washer

is moved down by the air inside the shank cavity allowing the air

to flow through the washer peripheral slots to the bottom hole

through special replaceable nozzles and through air tubes to the

bearing air passages.

When the air flow stops, the valve washer is returned to

its original position by the return spring, thus preventing rock

cuttings from running into the bit body cavity.

Snap ring

Valve washer

Washer peripheral

slots

Return spring

Retaining ring with

inner clamp

Circular contact ledge

Elastic coating

Seat

Pin bore

Pin thread

Pin ledge

Co

mp

res

se

d

air

OPEN VALVE

CLOSED VALVE



BEARING PROTECTION


The classification system of the International Asso�

ciation of Drilling Contractors is based on a 4�character

code which describes a bit design and formation types

that the bit is designed for.

First three characters are numeric and the 4th

character is alphabetic. The sequence of numeric

characters is defined as «series, type, bearing / gage».

The 4th alphabetic character describes «features

available».

Eight categories of cutting structure series correspond

to general formation characteristics.

Series 1 through 3 refer to milled tooth bits. Series 4

through 8 refer to tungsten carbide insert bits.

Within steel tooth and insert bit groups, formations

become harder and more abrasive as the Series numbers

increase.

Х Х Х Х

Bit cutting structure series (1-8)

Bit cutting structure type (1-4) Bearing design features (1-7)

Features available (A-Z)

Each Series is divided into 4 types depending on degrees

of formation hardness.

Type 1 refers to bits designed for the softest formation

within the Series. Type 4 refers to the hardest formation

within the Series.

1 open (non�sealed ) bearing

2 open bearing for drilling with air circulation

3open bearing + tungsten carbide compacts on cone gage

4 sealed roller bearing

5sealed roller bearing + tungsten carbide compacts on cone gage

6 sealed journal bearing

7sealed journal bearing + tungsten carbide compacts on cone gage

8,9 standby for future use

А air application

Вsealed bearing, special bearing seal allowing for higher RPM

C center jet

D special cutting structure design for deviation control

E extended jets

Genhanced gage/body protection with hardfacing or tungsten carbide compacts

H horizontal/steering application

J jet deflection

L lug pads with tungsten carbide compacts

M motor application

S standard steel tooth bit

T two cone bit

W enhanced cutting structure

X mostly chisel inserts

Y conical inserts

Z other shape inserts

Sixteen (16) alphabetic characters are used to

indicate special cutting structures, bearings, hydraulic

configurations and body gage protection.

Some bit designs may have more than one of optional

features. In such cases the most critical feature is

indicated.

212G a milled tooth rock bit designed to drill medium

formations (21), an open bearing for air application (2),

enhanced leg and shirttail protection with hardfacing

and tungsten carbide compacts (G).

742Х a tungsten carbide insert bit designed to drill

hard formations (74), an open bearing for air application

(2), mostly chisel inserts (X).

THE IADC ROLLER BIT CLASSIFICATION SYSTEM


FEATURES AVAILABLE –forth character:

CUTTING STRUCTURE SERIES –first character:

CUTTING STRUCTURE TYPES –second character:

BEARING DESIGN –third character:

EXAMPLES OF IADC CODE:

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SPECIFICATIONSSPECIFICATIONS

TUNGSTEN CARBIDE INSERT BITS

Chart C-1

№

Bit Description

IADC

Pin Size Recommended Drilling Parameters Weight, kg

Diameter

Volgaburmash System

GOST 20692-2003

GOST 50864-

96API 7-2 RPM

WOB, kN

Net Weight

Gross Weight

Inch mm Wooden Box*

Card-board Box**

1. 5 1/8 130.2 N-A61X-R291 ТЗ-ПГН 612X З-76 2 7/8 Reg 115 - 60 40 - 110 10.4 13.4 10.9

2. 5 1/8 130.2 N-AC61X-R236 ТЗ-ПН 612CX З-76 2 7/8 Reg 115 - 60 40 - 110 8.0 11.0 8.5

3. 5 1/4 133.4 N-AC51Y-R260 МЗ-ПН 512CY З-76 2 7/8 Reg 115 - 60 20 - 90 7.0 10.9 7.5

4. 5 3/8 136.5 N-A51Y-R298 МЗ-ПГН 512Y З-76 2 7/8 Reg 115 - 60 20 - 90 11.7 15.6 12.4

5. 5 3/8 136.5 N-AC51Y-R265 МЗ-ПН 512CY З-76 2 7/8 Reg 115 - 60 20 - 90 8.5 12.4 9.2

6. 5 5/8 142.9 N-AC54X-R274 СЗ-ПН 542CX З-88 3 1/2 Reg 115 - 60 20 - 100 10.0 13.9 10.7

7. 5 7/8 149.2 N-A51Y-R266 МЗ-ПГН 512Y З-88 3 1/2 Reg 115 - 60 20 - 100 15.0 18.9 15.9

8. 5 7/8 149.2 N-A61Y-R259 ТЗ-ПГН 612Y З-88 3 1/2 Reg 115 - 60 40 - 120 15.0 18.9 15.9

9. 5 7/8 149.2 N-AC62X-R243 ТЗ-ПН 622CX З-88 3 1/2 Reg 115 - 60 40 - 120 13.0 16.9 13.9

10. 6 152.4 N-A51Y-R281 МЗ-ПГН 512Y З-88 3 1/2 Reg 115 - 60 20 - 100 15.0 19.5 15.7

11. 6 152.4 N-A61Y-R277 ТЗ-ПГН 612Y З-88 3 1/2 Reg 115 - 60 50 - 130 15.0 19.5 15.7

12. 6 1/4 158.7 V-ALS61Y-R406 ТЗ-ПГВ 612Y З-88 3 1/2 Reg 115 - 60 20 - 110 19.0 23.5 19.7

13. 6 3/4 171.4 V-ALS41Y-R830 МЗ-ПГВ 412Y З-88 3 1/2 Reg 115 - 60 30 - 120 19.0 23.5 19.7

14. 6 3/4 171.4 V-ALS51XY-R246M1 МЗ-ПГВ 512XY З-88 3 1/2 Reg 115 - 60 30 - 120 19.0 23.5 19.7

15. 6 3/4 171.4 V-ALS62X-R237М1 ТЗ-ПГВ 622X З-88 3 1/2 Reg 115 - 60 50 - 140 19.0 23.5 19.7

16. 6 3/4 171.4 V-ALS62Y-R278M ТЗ-ПГВ 622Y З-88 3 1/2 Reg 115 - 60 50 - 140 19.0 23.5 19.7

17. 6 3/4 171.4 V-ALS63Y-R408 ТКЗ-ПГВ 632Y З-88 3 1/2 Reg 115 - 60 50 - 140 19.0 23.5 19.7

18. 6 3/4 171.4 V-ALS72Y-R247M1 К-ПГВ 722Y З-88 3 1/2 Reg 115 - 60 80 - 150 18.8 23.3 19.5


20. 7 1/2 190.5 V-ALS52Y-R426М МЗ-ПГВ 522Y З-88 3 1/2 Reg 115 - 60 30 - 130 31.0 36.0 32.1

21. 7 7/8 200 V-ALS41Y-R834 МЗ-ПГВ 412Y З-117 4 1/2 Reg 115 - 60 30 - 140 35.0 40.0 36.1

22. 7 7/8 200 V-ALS51Y-R458 МЗ-ПГВ 512Y З-117 4 1/2 Reg 115 - 60 30 - 140 35.0 40.0 36.1

23. 7 7/8 200 V-ALS62Y-R244 ТЗ-ПГВ 622Y З-117 4 1/2 Reg 115 - 60 60 - 170 35.0 40.0 36.1

24. 7 7/8 200 V-ALS63Y-R808-1 ТКЗ-ПГВ 632Y З-117 4 1/2 Reg 115 - 60 60 - 170 35.0 40.0 36.1

25. 7 7/8 200 V-ALS72Y-R407 К-ПГВ 722Y З-117 4 1/2 Reg 115 - 60 90 - 180 31.0 36.0 32.1

26. 8 1/2 215.9 V-AS42Y-R938 МЗ-ПГВ 422Y З-117 4 1/2 Reg 115 - 60 60 - 180 32.7 37.7 34.3

27. 8 1/2 215.9 V-ACS61X-R235M ТЗ-ПВ 612CX З-117 4 1/2 Reg 115 - 60 60 - 180 38.0 43.0 39.6

28. 8 1/2 215.9 V-AS61X-R895 ТЗ-ПГВ 612X З-117 4 1/2 Reg 115 - 60 60 - 180 35.0 40.0 36.6


30. 9 228.6 V-ALS51Y-R268 МЗ-ПГВ 512Y З-117 4 1/2 Reg 115 - 60 110 - 220 49.0 45.3 41.6


32. 9 228.6 V-ALS41YP-R900 МЗ-ПГВ 412YP З-117 4 1/2 Reg 115 - 60 30 - 150 40.0 54.3 50.6


34. 9 228.6 V-ALS61Y-R431-1 ТЗ-ПГВ 612Y З-117 4 1/2 Reg 115 - 60 70 - 190 40.5 45.8 42.1

35. 9 228.6 V-ALS63Y-R554 ТКЗ-ПГВ 632Y З-117 4 1/2 Reg 115 - 60 70 - 190 40.5 45.8 42.1

36. 9 3/16 233.0 V-ALS63Y-R554М ТКЗ-ПГВ 632Y З-117 4 1/2 Reg 115 - 60 70 - 190 41.7 47.0 43.3

37. 9 5/8 244.5 V-ALS42Y-R509 МЗ-ПГВ 422Y З-121 4 1/2 FH 115 - 60 40 - 150 50.0 56.0 51.4

38. 9 5/8 244.5 V-ALS63Y-R981 ТКЗ-ПГВ 632Y З-121 4 1/2 FH 115 - 60 120 - 220 45.0 47.0 42.4

39. 9 5/8 244.5 V-AS74Y-R901 К-ПГВ 742Y З-121 4 1/2 FH 115 - 60 110 - 220 41.0 47.0 42.4



TUNGSTEN CARBIDE INSERT BITS

Chart C-1

№

Bit Description

IADC


Diameter

Volgaburmash System

GOST 20692-2003

GOST 50864-

96API 7-2 RPM

WOB, kN

Net Weight

Gross Weight

Inch mm Wooden Box*

Card-board Box**

40. 9 5/8 244.5 V-ALS83Y-R261У ОК-ПГВ 832Y З-121 4 1/2 FH 115 - 60 120 - 240 52.4 58.4 53.8

41. 9 7/8 250.8 V-ALS51Y-R257-1 МЗ-ПГВ 512Y З-152 6 5/8 Reg 115 - 60 40 - 170 62.0 69.6 64.7






47. 9 7/8 250.8 V-ALS63Y-R833-1 ТКЗ-ПГВ 632Y З-152 6 5/8 Reg 115 - 60 80 - 210 62.0 69.6 64.7


49. 9 7/8 250.8 V-ALS72Y-R482 К-ПГВ 722Y З-152 6 5/8 Reg 115 - 60 110 - 230 62.0 69.6 64.7

50. 9 7/8 250.8 AUL-ALS72Y-R976 К-ПГАУ 727Y З-152 6 5/8 Reg 115 - 90 150 - 280 62.0 69.6 64.7

51. 9 7/8 250.8 V-ALS74Y-R824-1 К-ПГВ 742Y З-152 6 5/8 Reg 115 - 60 110 - 230 62.0 69.6 64.7

52. 10 3/16 258.0 V-ALS63Y-R833-1M ТКЗ-ПГВ 632Y З-152 6 5/8 Reg 115 - 60 80 - 210 63.0 70.6 65.7

53. 10 3/16 258.0 AUL-ALS72Y-R976М К-ПГАУ 727Y 3-152 6 5/8 Reg 115 - 90 150 - 280 63.0 70.6 65.7

54. 10 3/16 258.0 V-ALS74Y-R824-1М К-ПГВ 742Y З-152 6 5/8 Reg 115 - 60 120 - 240 64.5 72.4 67.5

55. 10 3/16 258.0 V-ALS72Y-R482М К-ПГВ 722Y З-152 6 5/8 Reg 115 - 60 120 - 240 64.8 72.1 67.2

56. 10 5/8 269.9 V-ALS42YGG-R889 МЗ-ПГВ 422Y З-152 6 5/8 Reg 115 - 60 40 - 180 78.0 87.5 81.0

57. 10 5/8 269.9 V-ALS43Y-R271M МЗ-ПГВ 432Y З-152 6 5/8 Reg 115 - 60 40 - 180 78.0 87.5 81.0








65. 11 279.4 V-ALS62Y-R428 ТЗ-ПГВ 622Y З-152 6 5/8 Reg 115 - 60 80 - 230 76.0 85.5 79.0

66. 11 279.4 V-ALS63YGG-R899 ТКЗ-ПГВ 632Y З-152 6 5/8 Reg 115 - 60 80 - 230 76.0 85.5 79.0

67. 11 279.4 V-ALS73Y-R433 К-ПГВ 732Y З-152 6 5/8 Reg 115 - 60 130 - 250 76.0 85.5 79.0







74. 12 1/4 311.1 V-ALS74YGG-R594 К-ПГВ 742Y З-152 6 5/8 Reg 115 - 60 140 - 280 100.0 110.0 104.2





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MILLED TOOTH BITS

Chart C-2

№

Bit Description

IADC


Diameter

Volgaburmash System

GOST 20692-2003

GOST 50864-

96API 7-2 RPM

WOB, kN

Net Weight

Gross Weight

Inch mm Wooden Box*

Card-board Box**

1. 5 1/8 130.2 N-AC12T-R264 М-ПН 122C З-76 2 7/8 Reg 115 - 60 30 - 80 8.0 11.0 8.5

2. 5 7/8 149.2 N-AC21-R422 С-ПН 212C З-88 3 1/2 Reg 115 - 60 40 - 110 13.0 16.9 13.9

3. 6 1/4 158.7 N-ALS21-R256 С-ПГН 212 З-88 3 1/2 Reg 115 - 60 20 - 120 16.0 20.4 16.7

4. 8 1/2 215.9 V-ACS31-R234 Т-ПВ 312C З-117 4 1/2 Reg 115 - 60 100 - 180 36.0 41.0 37.6

5. 9 7/8 250.8 V-ALS21-R452 С-ПГВ 212 З-152 6 5/8 Reg 115 - 60 110 - 210 55.0 62.6 57.7

6. 12 5/8 320.0 V-A31-R198M Т-ПГВ 312 З-152 6 5/8 Reg 115 - 60 140 - 260 105.0 115.0 109.2

Nozzle description

Bit diameter,

mm

Nozzle outlet hole diameter, mm

6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 22 24 25 26 28 30 32

R4803 130.2 - 154.2 * * * * * * * * * *

R4166 155.6 - 171.4 * * * * * * * * * * *

R4117 187.3 - 228.6 * * * * * * * * * * * * * *

R3381

R11010*244.5 - 311.1 * * * * * * * * * * * * *

R8519 349.2 - 393.7 * * * * * * * * * * * * * * *

STANDARD NOZZLE LIST

Chart C-3

The weight of bits packed into wooden boxes may differ from values shown on the list depending on kinds of the wood used and its moisture content.

The weight of bits packed into cardboard boxes may differ from values shown on the list depending on the quantity of sealing elements used.

*

**

R11010 nozzle is made of plastic.*



STABILIZERS

Chart C-4

ROLLER CONE BIT SUBS

Chart C-5

№ Description ConfigurationWeight,

kg

Thread connection

Н М

1. 250.8 СНД 167х12х1/6/152 with 68 tungsten carbide inserts 67 167х12х1/6 3-152




Above�bit stabilizers are designed to

decrease radial runouts and bit shocks

while drilling.

Stabilizer

9 7/8” CНД 167х12х1/4/152

Description:

С � stabilizer

НД � above�bit

Description:

П � sub

СП � special thread

Н � pin

М � box

В � extended

А � protected

Subs are designed to connect the bit to the drilling assembly.

Bit sub

ПСП 165х10/152ПСП Н/М АН

М

ПСП Н/М

ПСП Н/М ВА

№ Description ConfigurationOverall dimensions, mm

Weight, kg

Thread connection

D L d S b Н М

1. ПСП 165 х 10 / 121 w/o tungsten carbide inserts 197-1 250±2 70 170-1 105±1 22 165х10 З-121

2. ПСП 165 х 10 / 152 w/o tungsten carbide inserts 197-1 290±2 93 170-1 145±1 20 165х10 З-152

3. ПСП 167 х 12 / 121 А with 48 tungsten carbide inserts 197-1 300±2 80+5 170-1,9 90±0,5 39 167х12 З-121

4. ПСП 167 х 12 / 152 А with 48 tungsten carbide inserts 197-1 300±2 80+5 170-1,9 90±0,5 31 167х12 З-152

5. ПСП 167 х 12 / 121 ВА with 104 tungsten carbide inserts 197-1 450±2 80+5 170-1,9 170±1 70 167х12 З-121

6. ПСП 167 х 12 / 152 ВА with 104 tungsten carbide inserts 197-1 450±2 80+5 170-1,9 170±1 62,5 167х12 З-152

�0,3

�0,3

�0,3

�0,3

Figure 2

Efficient rock drilling requires an optimum

combination of many factors, one of which is

dynamic load or an impact energy that the bit

cutting structure is subjected to.

The depth of insert penetration depends on

the load applied to it. Figure 1 illustrates this

regularity in a form of a polygonal line with 4

main areas of rock failure (a, b, c, d) under it.

Figure 2 illustrates the rock failure schematics

in the process of penetration of one insert.

When only minor impact energy is applied

there is only minor fragmentation made by the

insert on the rock surface (residual deforma�

tion). This results in the rock cracking around

the insert contour.

With further increase in impact energy the

rock commences to chip away from the insert

contour. This is the first phase of rock failure.

The force resulting in the insert contour chip�

ping is called the load of the first phase of

rock failure.

The further increase in the impact energy

up to the load of the second phase of failure

results only in an insignificant increase in the

volume of failure.

When maximum load is applied the volume

of destruction increases proportionately. This

type of failure is called the second phase of

destruction.

Figure 2 illustrates: 1 – Insert -rock contact surface;

2 – Rock failure crater; 3 – Cutting cross-section.

Figure 1

Area of optimal

loads

ROLLER CONE MINING BIT MANUAL14

SECTION 1. ROCK FAILURESECTION 1. ROCK FAILURE

1.1 ROCK FAILURE MECHANICS

Conditions for a phase in rock failure b, d (Figure 1) depend on the properties of the rock, weight on bit,

rotation speed and bottom hole cleaning conditions.

Optimization of drilling parameters is attained via experimental selection of WOB and RPM. Specifications

shown for WOB and RPM of the bit type should not be exceeded.

In order to determine the most suitable bit cutting structure selection please refer to Chart M-1

“Rocks Classification”. The Chart shows a variety of formations and their classification per IADC code,

GOST 20692�2003, strength coefficient as per the scale of professor M. Protodjakonov, drillability category,

ultimate uniaxial compression strength, etc.

A relation between the bottom hole penetration δ per one rotation and WOB while drilling with a roller cone

bit is illustrated.

Figure 3 illustrates the relation as a curve. Three main areas of rock failure are illustrated under it.

Figure 3

Area I –

Abrasion rock failure.

Micro chipping, crushing and movement of some very small rock chips. The initial chart illustrates insufficient WOB. ROP is not more than 3m/hr.

Area II -

Fatigue failure.

Deeper insertion of the inserts and rotation result in rock fatigue and resultant spalling of cuttings or rock chips. Very hard formations are drilled mainly in this area. ROP is not more than 10 m/hr.

Area III –

A bulk failure area where specific power inputs per one unit of rock volume are considerably lower than in the first two areas but ROP is higher.

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1.2 DRILLING PRACTICES SELECTION

Chart M

-1

RO

CK

S C

LA

SS

IFIC

ATIO

N

16 ROLLER CONE MINING BIT MANUAL


17www.vbm.ru


The maximum ROP is determined experimentally for each bit type and size in given mining and geological

conditions. Therefore an optimum ratio of WOB and RPM is theoretically reached, when the insert penetration

into the rock is around 80% of protrusion. 20% remain for efficient cuttings removal.

In practice the recommended drilling parameters for a particular bit type and size shall be determined using

Charts C-1 and C-2. The target is to determine the maximum ROP with the given WOB and RPM.

Excessive WOB at which an insert penetration into the rock is over 80% results in the following:

� cuttings will not be completely removed from the area of failure;

� rock is milled again;

� ROP decreases;

� bit cutting structure and bearing wear intensively;

� load on the drilling rig spinner increases.

When bit RPM is altered, the quantity of inserts impacts against the bottom hole per a time unit changes. As

this takes place the penetration per one rotation – δ can be expressed by ROP:

ROP = n • δ

Figure 4 illustrates how the volume of bit penetration per one rotation δ and ROP depend on rotation speed of

the bit.

With increased RPM in n≤n1

section, the values of ROP and δ increase. With increased RPM in n1≤n≤n

2 section,

δ decreases, but ROP continues to grow. With the further increase in RPM of the bit in n>n3

section, the values of

δ and ROP decrease considerably.

ROP decreases after the point n3

due to:

� reduced insert�rock contact time;

� decreased impact energy applied to an insert;

� increased drilling rod misalignment;

� changed mode of the air flow motion at the bottom hole;

� increased power consumption.

Continuous air circulation in the process of drilling ensures the bottom hole cleanness, the bit bearing cooling and

contributes to the effective formation penetration.

An optimum ratio of the value of a bit penetration per one rotation δ and ROP on Figure 4 corresponds to

bit RPM nоpt.

A further increase in the RPM will result in erosion of the bit cutting structure and bearing with

no further performance benefit.

Figure 4



1.3 PRACTICAL USE OF BIT RUNS RESULTS

An optimum air circulation assurance in up�to�date drilling with mining bits boils down to the following

tasks:

1. To ensure efficient cuttings removal from the bottom hole to the surface.

2. To reduce the cutting structure and bearing erosive wear by means of efficient bottom hole cleaning.

3. To cool the bearing and to keep the bearing clean.

An effective bottom hole cleaning objective comes to obtaining

the required annular return velocity.

The annular return velocity produces a lifting force that ensures

cuttings removal. It can be controlled by:

� selection of a compressor and its adjustment to the optimum air

capacity;

� rock bit size and drill rod OD selection;

� selection of replaceable nozzles with an optimum flow area and

their installation into the bit.

Actual compressor output changes depending on the throttle

flap position, wear of the screw pair and the compressor body, altitude

above the sea level and manifold leakage.

Factors that affect the value of the annular return velocity for

cuttings removal:

� correlation between a bit diameter and a drill pipe OD;

� drill rod gage loss as a result of their wear;

� rock specific weight;

� sizes and shapes of cuttings;

� water in the hole.

They can be expressed by the following formula:

Q = 47 • V • (DB2 – DP2)

where Q – air flow, m3/min;

DB – Bit Diameter, m

DP – Pipe Diameter, m

V – desired air velocity, m/sec;

It should be noted that:

� the air velocity for light weight rock drilling is to be not lower than 25 m/sec;

� the air velocity for heavy weight rock drilling is to be not lower than 35 m/sec;

� the air velocity for drilling of formations with high water content is to be not lower than 50 m/sec.

19www.vbm.ru

SECTION SECTION 2. 2. AIR CIRCULATION SYSTEMAIR CIRCULATION SYSTEM

2.1 BOTTOM HOLE CLEANING

Bitdiameter

Recommended drill rod diameter

Compressor output, m3/min

for desired air velocity:

mm Inch mm Inch25

m/sec35

m/sec50

m/sec

76 3 60 2 23/64 3 4 5

93 3 2/360 2 23/64 6 9 12

65 2 9/16 6 8 11

98.4 3 7/8

60 2 23/64 7 10 14

65 2 9/16 6 9 13

73 2 7/8 5 7 10

114.3 4 1/2

65 2 9/16 10 15 21

73 2 7/8 9 13 18

89 3 1/2 6 8 12

120.6 4 3/4

60 2 23/64 13 18 26

65 2 9/16 12 17 24

73 2 7/8 11 15 22

89 3 1/2 8 11 6

102 4 5 7 10

130.2 5 1/8

73 2 7/8 14 19 27

89 3 1/2 11 15 21

102 4 8 11 15

136.5 5 3/8

73 2 7/8 16 22 31

89 3 1/2 13 18 25

102 4 1/64 10 14 19

139.7 5 1/2

89 3 1/2 14 19 27

102 4 1/64 11 15 21

114 4 31/64 8 12 17

142.9 5 5/8

73 2 7/8 18 25 35

89 3 1/2 15 21 29

102 4 1/64 12 17 24

114 4 31/64 9 13 19

149.2 5 7/8

102 4 1/64 14 19 28

114 4 31/64 11 15 22

127 5 7 10 14

152.4 6

102 4 1/64 15 21 30

114 4 31/64 12 17 24

127 5 8 12 17

158.7 6 1/4

89 3 1/2 20 28 41

102 4 1/64 17 24 35

114 4 31/64 14 20 29

127 5 11 15 21

171.4 6 3/4

102 4 1/64 22 31 45

114 4 31/64 19 27 38

127 5 16 22 31

140 5 33/64 12 16 23

187.3 7 3/8

114 4 31/64 26 36 52

127 5 22 31 45

140 5 33/64 18 26 37

152 5 63/64 14 20 28

159 6 17/64 12 16 23

200 7 7/8

140 5 33/64 24 34 48

152 5 63/64 20 28 39

159 6 17/64 17 24 35

168 6 39/64 14 19 27

Bitdiameter

Recommended drill rod diameter

Compressor output, m3/min

for desired air velocity:

mm Inch mm Inch25

m/sec35

m/sec50

m/sec

215.9 8 1/2

140 5 33/64 32 44 63

152 5 63/64 27 38 55

159 6 17/64 25 35 50

168 6 39/64 21 30 43

228.6 9

168 6 39/64 28 39 56

178 7 24 34 48

180 7 3/32 23 33 47

191 7 33/64 19 26 38

197 7 3/4 16 22 32

233.0 9 3/16

168 6 39/64 31 43 61

178 7 27 37 53

180 7 3/32 26 36 51

191 7 33/64 21 29 42

197 7 3/4 18 25 36

244.5 9 5/8

178 7 33 46 49

180 7 3/32 32 44 48

191 7 33/64 27 38 41

197 7 3/4 25 34 37

203 8 22 30 33

250.8 9 7/8

178 7 37 51 74

180 7 3/32 36 50 72

191 7 33/64 31 44 62

197 7 3/4 28 40 57

203 8 25 36 51

219 8 5/8 18 25 35

269.9 10 5/8

203 8 37 52 74

219 8 5/8 29 41 58

229 9 24 34 48

279.4 11

203 8 43 61 86

219 8 5/8 35 50 71

229 9 1/64 30 42 60

295.3 11 3/5

203 8 54 76 108

219 8 5/8 46 65 92

229 9 1/64 41 57 82

235 9 1/4 38 53 75

311.1 12 1/4

219 8 5/8 57 80 115

229 9 52 73 105

235 9 1/4 49 68 98

254 10 38 53 76

273 10 3/4 26 37 52

320.0 12 5/8

229 9 1/64 59 82 118

235 9 1/4 55 78 111

254 10 45 62 89

349.2 13 3/4

254 10 67 94 135

273 10 3/4 56 78 111

305 12 34 48 68

393.7 15 1/2

305 12 73 102 145

311 12 1/4 68 96 137

330 13 54 76 108

Chart M-2 illustrates the required value of a compressor output versus air velocity, rock bit diameter and drill rod diameter.

Chart M-2

The above calculation gives a preliminary estimate of required compressor output. The final data can be obtained only after a test drilling.



2.2 REQUIRED DRILLING

RIG COMPRESSOR OUTPUT

Optimum combination of drilling equipment on

a drilling rig, i.e. bit diameter, drill rod OD, actual

compressor output for given mining and geological

conditions makes it possible to gain the required

annular return velocity and satisfactory bottom hole

cleaning and cuttings removal.

The better the bottom hole cleaning and cuttings

removal, the less the erosive wear of the cutting

structure and the bearing at maximum ROP. However

it is very important to realize that an air circulation

system of a bit is to ensure not only the required

annular return velocity but to provide conditions for

the best cooling and keeping the bearing clean.

This problem is solved solely by the choice of bit

nozzles diameter because only nozzles selection

makes it possible to gain an air pressure drop in a bit

which is required for successful drilling.

Recommended air pressure in a bit is determined

in each case experimentally by making measurements

with a special measuring tool as illustrated in the

photo. The long�term experience in drilling of blast

holes at mines reveals that the air pressure

in a bit is to be within the range of not less

than 0.20 – 0.22 MPa (29.7-32.6 psi) and

has to correspond to physical�mechanical properties

of formations and drilling conditions.

Non�observance of the recommended values of

air pressure in a bit will inevitably result in premature

bearing failure.

Nozzles are fixed with a nail�shaped retaining pin. The nail is installed through a hole in the leg

and fills in the ring groove made in the nozzle recess in the leg and in the nozzle. Such method

of retention is the most reliable and facilitates nozzles replacement.

Nozzles replacement procedure:

1. Remove the retaining pin to remove the nozzle

3. Install a new nozzle

2. Remove the nozzle

4. To fix the nozzle install the retaining pin with a hammer

21www.vbm.ru


2.3 NOZZLES SELECTION

2.4 NOZZLES REPLACEMENT

The subject method makes it possible to measure an actual drilling rig compressor output on�site taking into account its wear, air circulation system leakage and other factors stated above.

Values obtained with the method are true only for Volgaburmash bits when their air passages are free from cuttings.

It is recommended to measure compressor output in the following order:

1. Determine the bit type and size and its condition. Only new or effective bits can be used.

2. Determine what the nozzles flow area is. Be sure that all three nozzles are the same.

3. When the compressor is switched on check the air flow under the cones in order to make sure that all air passages are empty. The compressor shall operate with a nominal working temperature and with water supply switched on.

4. Determine air temperature with the instruments in the operator’s cabin.

5. Install a pressure gage into one of the nozzles and measure the pressure.

6. Basing on the corresponding bit and nozzle diameter find compressor output on the chart.

7. For your calculation use correction factors in Charts M�4, M�5, M�6: working level altitude above the sea level, temperature of air pumped into the bit, ambient temperature.

COMPRESSOR OUTPUT (m3/min)for 244.5 – 269.9 mm (9 5/8” – 10 5/8”) bits

ALTITUDE ABOVE SEA LEVEL CORRECTION FACTOR

Chart M-3

Chart M-4

МРаNOZZLES DIAMETER, mm

11 12 14 16 17 19 22 24

0.1 10 12 14 16 19 21 28 31

0.11 11 12 14 17 20 22 29 32

0.12 11 13 15 18 20 23 30 34

0.13 12 14 16 19 21 24 32 35

0.14 12 14 16 20 22 25 33 37

0.15 13 15 17 20 23 26 34 38

0.16 13 15 18 21 24 27 36 40

0.17 14 16 18 22 25 28 37 41

0.18 14 17 19 23 26 29 39 43

0.19 15 17 20 24 27 31 40 45

0.20 15 18 20 24 28 32 41 46

0.21 16 18 21 25 29 33 43 48

МРаALTITUDE ABOVE SEA LEVEL, m

0 500 1000 1500 2000 2500 3000 3500 4000 4500

0.1 1 1.03 1.06 1.09 1.13 1.17 1.21 1.27 1.33 1.41

0.11 1 1.03 1.06 1.09 1.13 1.17 1.22 1.28 1.35 1.43

0.12 1 1.03 1.06 1.10 1.14 1.18 1.23 1.29 1.36 1.45

0.13 1 1.03 1.06 1.10 1.14 1.19 1.24 1.30 1.38 1.46

0.14 1 1.03 1.06 1.10 1.15 1.19 1.25 1.31 1.39 1.48

0.15 1 1.03 1.07 1.11 1.15 1.20 1.26 1.32 1.40 1.49

0.16 1 1.03 1.07 1.11 1.15 1.21 1.26 1.33 1.41 1.50

0.17 1 1.03 1.07 1.11 1.16 1.21 1.27 1.34 1.42 1.52

0.18 1 1.03 1.07 1.11 1.16 1.21 1.28 1.35 1.43 1.53

0.19 1 1.03 1.07 1.12 1.16 1.22 1.28 1.35 1.44 1.54

0.20 1 1.04 1.07 1.12 1.17 1.22 1.29 1.36 1.44 1.55

0.21 1 1.04 1.08 1.12 1.17 1.23 1.29 1.36 1.45 1.55



2.5 ON-SITE COMPRESSOR

OUTPUT MEASUREMENT

Example 1: Selection of air circulation parameters for efficient rock bit operation on

СБШ�250МНА�32 drilling rig .

Basic Data:

250.8 V�ALS74Y�R824 rock bit;

Bit nozzles: ∅19 mm x 3 nozzles;

Altitude above sea level: 500 m;

Air temperature in bit: +300C;

Ambient temperature: �100C;

Drill rod diameter: 203 mm;

Formations: ferruginous quartzite;

Holes contain no water.

1. Measure the pressure with the pressure gage included into the set. 0.18 MPa

2.Chart M�3: “244.5 � 269.9”. Find the corresponding compressor output basing on the changed pressure (0.18 MPa) and nozzles sizes (∅19 мм x 3 nozzles)

29 m3 /min

3.Chart M�4. Find correction factor for the altitude above sea level (500 m). According to the chart it is 1.03:

29 x 1/03 = 29.87 m3 /min

4.Chart M�5. Find correction factor for the air temperature in the bit (+ 300C). According to the chart it is 0.98:

29.87 x 0.98 = 29.27 m3 /min

5.Chart M�6. Find correction factor for the ambient temperature (�100C). According to the chart it is 0.90:

29.27 x 0.90 = 26.34 m3 /min

6. Actual compressor output on СБШ�250МНА�32 drilling rig is 26.34 m3 /min.

7.

Basing on Chart M�2 we determine that the required air velocity (35 m/s) is not ensured (with ∅203 mm drilling rod, with the actual compressor output of 26.34 m3 /min, when drilling in heavy, no water formations). However, when the drilling rod is replaced by a ∅219 mm one, the compressor with 26.34 m3 /min output ensures the required air velocity (35 m/sec).

8.In order to extend the bit bearing life time it is required to have pressure in the bit not lower than 0.2 MPa. Replace the three nozzles by ∅17.5 mm ones.

9. The second measurement of the pressure in the bit. 0.21 MPa

Therefore, we have selected nozzles and air velocity required for an effective bit operation.

BIT TEMPERATURE (t 0С)CORRECTION FACTOR

Chart M-5

AMBIENT TEMPERATURE (t 0С)CORRECTION FACTOR

Chart M-6

t 0С in bit Factor

� 20 1.08

�10 1.06

0 1.04

10 1.02

20 1.00

30 0.98

40 0.97

50 0.95

60 0.94

70 0.92

80 0.91

90 0.90

100 0.89

110 0.87

120 0.86

130 0.85

140 0.84

Ambient t 0С

Factor

� 40 0.80

� 30 0.83

� 20 0.86

� 10 0.90

0 0.93

10 0.97

20 1.00

30 1.03

40 1.07

50 1.10

60 1.14

70 1.17

80 1.20

23www.vbm.ru


Our recommendations will allow you to obtain good bit performance.

3.27. Dull bits intended for repair and drilling of not completed holes or for cleaning of backfilled holes shall be flushed and cleaned from mud, their bearing and thread shall be lubricated. It is not recommended to use new bits in repair operations.

3.28. Dull bits intended for utilization shall be:

3.28.1 Examined by the drilling rig operator, and registeredin bit registry and in the Dull Bit Condition Report (Appendix No.2).

3.28.2 Disassembled in order to have a stock of effective parts, i.e. relieve valves and nozzles on site.

3.29. “Bit Records” and “Dull Bit Condition Report” shall be delivered to the engineer in charge of rock bit record keeping for “Bit Run Statistics” review (Appendix No.3).

3.30. A normative indicator of the bit work is deter�mined basing on “Bit Run Statistics” for a specific mine by an average performance of no less than 50 bits of the similar size and type and designation, with a Report issued.

3.31. A report on dull bit run statistics including meters drilled, hours and ROP shall be delivered to the manufac�turer.

3.1. Inspect the drill pipe spinner spindle thread condition. If the thread condition is unsatisfactory the spindle is to be replaced.

3.2. Inspect the drill rods condition. Do not use curved rods or a worn thread.

3.3. Inspect the bushings condition. Do not use worn bushings.

3.4. Inspect compressor functionality basing on the pres�sure gage reading on the outlet as compared to its specification data. Adjust the flap position if necessary.

3.5. Inspect the air ducts and hoses for leakage. Fix the leakage found in the system.

3.6. Inspect the operability of control instrumentation.

3.7. Inspect operability of hoisting jacks. Do not allow loosing the drilling rig horizontalizing while drilling.

3.8. Inspect the bit condition and completeness, reliability of the fixture and operation of the relieve valve, availability and size of nozzles, connection thread condition.

3.9. Do not make unauthorized changes to the bit design.

3.10. Flush the drilling assembly with air before the bit screwing on.

3.11. Screw the bit on with no impacts and shifts.

3.12. Select nozzles so that the pressure in the bit would not be less than 0.2 MPa.

3.13. Fill in the Bit Record Card for each bit. (Appendix No.1).

3.14. Break in a new bit for 15 minutes with the drill rod rotation at 30 RPM and WOB of 10% of the upper limit recommended in the bit specification. Break in a new bit in a new hole (except for the first row holes) with the compressor on.

3.15. Smoothly apply the operation parameters recom�mended in the bit specification. Do not exceed the WOB and RPM indicated in the specification.

3.15.1 If with sequential increase in WOB the ROP does not increase or decreases then the WOB shall be reduced to the earlier registered level at which the maximum ROP was obtained.

3.15.2 If the drill rod starts vibrating then the bit RPM or WOB shall be reduced to the level at which the vibration stops.

3.16. Optimum drilling parameters shall be determined only by experiment. The most critical factor is the maximum ROP.

3.17. Perform drilling only with the compressor on.

3.18. Do not apply weight on the bit when it does not rotate.

3.19. Do not drill when the bit cones are balled up and do not rotate.

3.20. Do not drill when the bit air ducts are blocked.

3.21. Do not complete an old hole with a new bit. It can result in shirttail and hill row inserts cracking and cones locking.

3.22. Perform tripping and hole conditioning only with the drilling assembly rotating and the compressor on.

3.23. Do not use new or test bits to clean out collapsed holes. Always apply a used bit for this purpose.

3.24. Emergency drilling stop and leaving a bit at the bottom hole with the compressor off may result in plugged bearing and locked cones.

3.24.1 Lift the bit above the bottom hole by 1.5 – 2 meters with no rotation. Turn on the compressor and flush the bit. While doing so, control the pressure increase in the drilling rig air line with a pressure gage.

3.24.2 Trip the bit out of the hole, clean the bit, control cones rotations by hand, turn the compressor on, visually check flushing air through the cones.

3.24.3 You can continue drilling with the bit if the bit examination results are satisfactory for the drilling rig operator.

3.24.4 If the bit examination results are not satisfactory for the drilling rig operator then the bit shall be removed for its repair at the bits preparation shop.

3.25. Before the bit starts to drill a new hole clean, flush and examine it.

3.26. Use bits till they have obvious failure symptoms:

� locking of bearing at least in one cone;

� big play resulting in cones jamming and interference;

� rollers and balls come out of at least of one cone bearing;

� teeth (inserts) from one cone interfere with other cones.

� excessive wear of the cones cutting structure;

� bit failure (bearing failure, welding seams cracking, cones cracking and other);


SECTION SECTION 3. GUIDELINES TO ROCK BIT OPERATIONGUIDELINES TO ROCK BIT OPERATION

BEFORE DRILLING

WHILE DRILLING

AFTER DRILLING

Symptom:

Teeth break flush to cone steel.

Cause:

� Too high RPM of the spinner;

� Broken, desintegrated formation either while drilling or spudding a hole;

� Improper rock bit;

� Alteration of formations including very hard ones.

Remedy:

� Reduce the spinner RPM;

� Drill sections interbedded with very hard formations with reduced WOB and RPM;

� Select a bit with the cutting structure features fitting the drilling conditions.

Symptom:

Chipped tungsten carbide inserts.

Cause:

� Excessive WOB;

� Broken, desintegrated formation either while drilling or spudding a hole;

� Wrong tungsten carbide inserts grade;

� Cone interference.

Remedy:

� Revise the drilling conditions and WOB;

� Reduce WOB and gradually reduce RPM;

� Select a bit with more wear resistant tungsten carbide inserts.

Symptom:

Tungsten carbide inserts came out of the cone. Very often a reason for that is junk at the bottom hole.

Cause:

� Metal on the bottom hole;

� Cone shell erosion;

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

� Excessive WOB.

Remedy:

� Reduce WOB and RPM – (as an option you can use both actions in complex).

� Select a bit with features that are more suitable for the application.

25www.vbm.ru

SECTIONSECTION 4. 4. DULL BIT ANALYSISDULL BIT ANALYSIS

BROKEN TEETH (ВТ)

CHIPPED TEETH (СТ)

LOST TEETH (LТ)

Symptom:

Inserts wear blunt. Slow penetration rates.

Cause:

� Excessive WOB;

� Carbide grade does not match the rock properties;

� Formations changed and are interbedded with hard abrasive stringers;

� Excessive RPM;

� This dulling characteristic can be considered as a standard one if the values of meters drilled and hours are high.

Remedy:

� Reduce WOB and RPM – (as an option one can use both actions in complex);

� Select a bit with another shape of inserts and with a more wear resistant carbide grade.

� Select a bit with features that are more suitable for the application.

Symptom:

Inserts surface is worn specifically and looks like a “snake skin”. It very often results in inserts breakage.

Cause:

� Carbide grade does not correspond to formations drilled;

� Inserts are heated in the process of drilling and at the same time they are cooled with water injected into the hole with air and by underground waters.

Remedy:

� Select a bit with carbide grade which is less prone to heat checking (higher cobalt content or bigger grain size);

� Reduce RPM and water supply.

Symptom:

The gage inserts are rounded towards the center of the bit.Slow penetration rates.

Cause:

� Excessive RPM;

� Carbide grade does not match the formation hardness.

Remedy:

� Reduce RPM;

� Use a bit with a more wear resistant carbide grade;

� Use a bit with a lesser offset and a bigger journal angle.



WORN TEETH (WT)

HEAT CHECKING (HC)

ROUNDED GAUGE (RG)

Symptom:

Inserts are worn mainly on one side. This is a dulling characteristic which occurs when the inserts mesh like a gear into the bottom hole formation.

Cause:

� Usually caused by improper WOB and RPM;

� Improper bit selection;

� Changes in the formation.

Remedy:

� Adjust WOB and rotation so that the proper rock shattering within a particular time period is achieved;

� Select a bit better suited for the application or a bit with an irregular skip pitch.

Symptom:

This is a dulling characteristic which occurs when inserts wear in a manner such that they retain a sharp crest shape. This dulling characteristic indicates proper bit selection and operating parameters.

Symptom:

Cone steel erodes away from inserts and results in inserts loss. Also, excessive leg erosion can result in inserts loss on the bit leg and in shirttail wear.

Cause:

� High abrasiveness of the formation drilled;

� Inadequate air volume passing through the nozzles to the bottom hole;

� Wet (from either ground water or excessive water injection), sticky, and abrasive formations;

� Excessive air circulation speed.

Remedy:

� Select WOB and RPM to achieve maximum ROP ;

� Inspect air delivery system of the drilling rig for leaks;

� If using water dust control reduce water supply. Make sure that the nozzles are not plugged.

� Inspect cuttings removal efficiency;

� Increase nozzle size to reduce air pressure;

� Proceed with drilling and do not change drilling parameters if high ROP.

27www.vbm.ru


TRACKING (ТR)

SELF-SHARPENING WEAR (SS)

EROSION (ER)

CRACKED CONE (СС)

LOST CONE (LC)

Symptom:

The cone cracks either axially or circumferentially.

Cause:

� Cone steel fatigue;

� Cone interference causing the cone to heat and generate cracks;

� Excessive WOB;

� Dropped drill rod.

Remedy:

� This dulling characteristic can be allowed if the drilling is long;

� Reduce WOB;

� Review the drilling conditions and make sure that the bit drills the bottom hole smoothly with no impacts;

� Monitor and control wear of drill rod threaded joints.

Symptom:

Cones are left at the bottom hole.

Cause:

� The bit overdrilled the bottom hole.

� Bit hitting bottom;

� Bearing failure (all rollers and balls came out).

Remedy:

� Observe instructions in the bit manual;

� Monitor and control wear of drilling rod threaded joints.

Symptom:

Bearing wear results in the teeth (inserts) from one cone interfering with another cone. It often results in intermittent cone locking and inserts deterioration and radial cone breakage.

Cause:

� Excessive WOB resulting in exaggerated bending moment of journals;

� Plugged air to bearing passage resulting bearings being starved of coolant;

� Roller bearing wear, excessive thrust or eccentric drilling caused by bent steel, the thread wear or drilling rig table bushing resulting in thrust flange breakage;

� Insufficient air volume transferred to the bearing;

� Running a bit down an undersized hole;

� Rollers and balls come out of one cone.

Remedy:

� Reduce WOB;

� Inspect drilling rods condition, their diameter wear and deviation;

� Inspect drilling assembly bushings for wear;

� Check the relieve valve availability as well as availability and proper selection of bit nozzles.



CONE INTEFERENCE (CI)

CONE DRAGGED (CD)

Symptom:

All three cones are locked. The cones have typical tracks (flats) caused by inserts sliding at the bottom hole.

Cause:

� Drilling with an air compressor switched off or failed;

� Air supply stopped or is insufficient due to air hose tear or big air leakage in the circulation system;

� A foreign object jammed between the cones;

� Bit balling up.

Remedy:

� Repair and adjust the compressor;

� Eliminate air leakage in the system;

� Follow the instructions in the bit manual.

Symptom:

Formation is packed between the cones. (It can be erroneously considered as the bearing locking).

Cause:

� Inadequate hydraulic cleaning of the bottom hole.

� Forcing the bit into formation cuttings with the compressor off;

� Drilling a sticky formation.

Remedy:

� Increase the speed of air flow by nozzles selecting;

� When you plan a blackout inform the drilling rig operator in advance;

� Examine the bit after each drilled hole.

Symptom:

Nose parts of the cones are missing or worn.

Cause:

� Excessive WOB resulting in the cone body being in contact or heating the bottom hole;

� Inadequate hole cleaning causing cone erosion;

� Nose parts of the cones of center jet bits badly wear while drilling of abrasive formations due to sand blasting effect resulting in lost inserts and worn nose parts;

� Junk at the bottom hole.

Remedy:

� Reduce WOB;

� Select inserts projection, shape, diameter and quantity on the rows so that the cone body would not be in contact and would not hit the bottom hole;

� Measure the actual compressor output, drill rod diameter and control the nozzles selection;

� Replace the center jet bit by a jet bit.

29www.vbm.ru


CORED BIT (CR)

BALLED-UP BIT (BU)

BROKEN LEG (BL)

PLUGGED NOZZLE (PN)

PINCHED BIT (PB)(mechanically damaged bit)

Symptom:

One or all three legs are missing. It often happens as a result of the operator’s error or failed equipment.

Cause:

� The drill rod lost in the hole while tripping or repair.

Remedy:

� Periodically examine the thread on the spinner spindle sub. In case of a wear or damage of turn of thread replace the sub.

Symptom:

On inner rows the inserts are chipped. Between the rows of one cone there are traces of the adjacent cone.

Cause:

� Hole redrilling with a new bit;

� Cleaning out of an existing holes with a new bit.

Remedy:

� Use a worn bit to clean out or redrill a hole;

� If there are no worn bits drill a new hole adjacent to old hole;

� Order undersized bits for hole cleaning;

� Have a stock of dull bits good for hole redrilling or cleaning.

Symptom:

A nozzle plugged with cuttings or rubber hose scraps. The compressor discharges air through the valve. Significant erosion of the bit shirttails and legs.

Cause:

� The bit was left at the bottom hole with air off for workover and for power transmission line switching;

� The valve protecting from cuttings failed or is missing in the bit;

� The compressor failed, the air hose fell off.

Remedy:

� Use a dull bit for workover;


� Periodically examine the relieve valve in the bit, its operability and the fixture reliability. Replace the valve by an effective one if it is necessary;

� Forbid using bits that have no valve protecting from cuttings;

� Adjust the compressor, eliminate air leakage in the system, clean the bit from cuttings (nozzles and air tubes in the legs);

� Flush the drill rod with air before screwing the bit on.



LOST NOZZLE (LN)

OFF-CENTER WEAR (ОС)

SHIRTTAIL DAMAGE (SD)

Symptom:

A plugged nozzle usually results in a sharp pressure drop while drilling and requires an immediate trip out of the hole.

Cause:

� Breaking the rules of nozzle installation;

� Mechanical damage of nozzles or their retention system;

� Nozzles or their fixture erosion;

� Bit balling up.

Remedy:


Symptom:

Leg shirttail that protects bearing rollers is broken.

Cause:

� Axial part of the load on the bearing results in the shirttail bearing a part of the load;

� Axial runout when the bit rotates;

� Erosion weakens the shirttail structure.

Remedy:

� Reduce WOB and select a bit with a smaller journal angle and bit axis;

� Inspect the bit for off center wear and the drilling rods for a bent;

� Inspect the bit thread and the sub thread for damage;

� Inspect the drill rod, compressor and the air line for leakage.

Symptom:

Excessive wear of one or two legs (legs, shirttails); of one or two cones (gage and hill rows), along with bearings failure; cones locking and lost rollers and balls.

Cause:

� The drill rod is bent resulting in off center bit rotation (radial runout);

� The bit is screwed on the sub with a warp, the bit thread is damaged.

Remedy:

� Inspect the drill rod rotation for eccentricity;

� Inspect the bit for damaged thread;

� Inspect and replace the bit sub if its thread is damaged.

31www.vbm.ru


BEARING SLUDGING (BS)

PLAY (PL)

Symptom:

Sludge in the bit bearing. (It can be erroneously considered as the bearing locking).

Cause:

� Insufficient compressor output;

� Improper nozzles selection;

� Drilling with a relieve valve removed;

� The bit was left at the bottom hole for a long time with a compressor off.

Remedy:

� Select nozzles following the recommendations;


� Run the bit with a relieve valve available.

Symptom:

Play.

Cause:

� Insufficient compressor output;

� Improper nozzles selection;

� Roll and ball bearings wear, bearing overheating resulted in journal bearing failure.

Remedy:

� Repair the compressor or replace it to a more efficient one;

� Select nozzles according to the recommendations;




More than 84 rock bit types and sizes have been developed and can be manufactured for mining

companies.

It is important to select effective rock bit designs for particular mining and geological drilling conditions

and to provide rock bit services to ensure the best performance including:

� reduced expenses for drilling equipment and drilling operations;

� increased drilling rigs productivity;

� reduced time for blast blocks preparation.

Our specialists give all recommendations on the optimum bit types and sizes selection and analyze the

efficiency of bit runs. Efficient bit selection at each mining company is made basing on a complex

assessment of

mining, geological and technological drilling conditions;

rock bit performance statistics;

dull bit analysis;

cutting structure and design features;

technical and economic indexes of bits performance basing on test results.

We can design and manufacture rock bits basing on our customer’s specific requirements.

A critical factor that affects a bit performance is the mining and geological drilling conditions analysis.

Rock properties, namely ultimate uniaxial compression strength, alteration, inclusions, attitude of beds,

water cut, abrasiveness, broken ground formations, etc. determine rock bit specification and design

features.

Since geology may alter with a mine contour deepening and widening it is important to consider the

drilling volume as per “Long Term Drilling Operations Plan”.

Intensive mining complex development is directly related to technical re�equipment and replacement

of existing drilling rigs to the state�of�the�art equipment. Such technical characteristics of drilling

rigs as productivity, drilling rod assembly, jointing thread, compressor output shall correspond to design

features of bits.

It is obvious that it is impossible to achieve a considerable economic effect in drilling using the

state�of�the�art bits on an old and worn drilling rig.

At the same time it is well possible to reduce drilling expenses by selection of bits which efficiency

would correspond to actual drilling rig technical parameters.

33www.vbm.ru

SECTIONSECTION 5. 5. SELECTION OF EFFICIENT ROCK BIT DESIGNSSELECTION OF EFFICIENT ROCK BIT DESIGNS

5.1 MINING AND GEOLOGICAL DRILLING CONDITIONS ANALYSIS

5.2 TECHNOLOGICAL DRILLING CONDITIONS ANALYSIS

The evaluation database for an efficient rock bit design selection is Rock Bit Performance Statistics

Analysis (Appendix 3). Modern drilling companies usually use a few bit types of different manufacturers

and it is important to make a comparative assessment of their efficiency not taking into account the bits

cost.

Example 2:

A and B rock bits comparison assessment with

the following statistics:

A rock bit, Bit Life (BLA) = 60 meters drilled,

Bit Hours (BHA) = 10 hrs;

B rock bit, Bit Life (BLB) = 40 meters drilled,

Bit Hours (BHB) = 8 hrs.

Let’s determine the average ROP of A and B bits

performance:

;

Conclusion: Rock bit A is more effective than

rock bit B, because BLA > BH

A, ROP

A > ROP

B.

Example 3:

C and D rock bits comparison assessment with

the following statistics:

C rock bit, Bit Life (BLC) = 60 meters drilled,

Bit Hours (BHC) = 10 hrs;

D rock bit, Bit Life (BLD) = 60 meters drilled,

Bit Hours (BHD) = 12 hrs.

Let’s determine the average ROP of C and D bits

performance:

;

Conclusion: Rock bit C is more effective than

rock bit D, because ROPC > ROP

D.

If the meters drilled and ROP of two bits are equal then the bits are equal in their efficiency.

After assessment of bits efficiency basing on statistics it is necessary to make a comparative analysis of

each bit type dulling and reasons. The analysis results are important because it is critical to very precisely

determine what bit design features are required for the application. The evaluation database for dull bit

analysis is Dull Bit Grading Report (Appendix 2).

As a rule for the optimization of a rock bit design features selection specialists in drilling at mines use

a method for bits identification basing on the information provided by manufacturers. It is a list of products

at web�sites and in catalogues with bits specification. The information contains alphabetic characters as

per GOST 20692�2003 and the designation as per IADC code.



5.4 DULL BIT ANALYSIS AND REASONS BIT FAILED

5.5 ROCK BIT CUTTING STRUCTURE AND

BEARING DESIGN FEATURES ANALYSIS

5.3 ROCK BIT PERFORMANCE STATISTICS ANALYSIS

A bit design efficiency is determined basing on comparative test results in equal mining and geological

conditions. An efficient bit design shall be considered the one that ensures the minimum value of

operational expenses for drilling of one running meter of a hole which is determined by the formula:

;

Example 4: Calculation of А and В bits efficiency:

Therefore the drilling with rock bit B is more economic as the total savings are $24,850.

Indexes A Rock bit B Rock bit % Diff

Bit Cost $4,500 $4,500

Bit Life (meters) 5,000 4,500 �10%

Bit Hours 200 150 �25%

ROP 25 30 +20%

Rig Cost/hour $500 $500

Bit Cost /metre $0.90 $1.00 +10%

TDC/metre $20.90 $17.70

TDC Savings/metre $3.20

TDC/Bit $104,500 $79,650

Total Savings $24,850 +24%

Specialists of mining companies are challenged to

optimize drilling as rock bits nomenclature broadens

and old drilling rigs are replaced by the�state�of�

the�art ones.

In order to assist in solving the problems

Volgaburmash, JSC set up a Training Center where

the specialists of the Mining Products Engineering

Group provide a 3 days training course on

“Up�to�Date Miming Bits: Production and

Operation” program.

35www.vbm.ru


5.6 ANALYSIS OF TECHNO-ECONOMIC

INDICATORS OF ROCK BITS PERFORMANCE BASING

ON BIT TEST RESULTS

5.7 TRAINING AT VOLGABURMASH TRAINING CENTER

6.1. Rock bits shall be stored in a dry and

enclosed facility.

6.2. Rock bits shall be stored at a warehouse

in cardboard or wooden boxes placed on pallets.

6.3. The transportation shall be made either

on pallets or in boxes (without pallets).

6.4. The transportation shall be made by all

modes of transport in conformity with cargo

transportation rules for each mode of transport

subject to protection from atmospheric pre�

cipitations and mechanical damage.

6.5. Storage and transportation of bits in bulk is borbidden.

6.6. Bits shall not hit each other or other solid objects while handling.

6.7. Gloves shall be used when handling rock bits. 8 1/2” bits and bigger diameter bits shall be handled

using a mechanized equipment.

6.8. Rock bits shall be stored at drilling rigs in the manufacturer’s package or with their shanks

upwards and the thread and the relief valve protected by a cap.


SECTIONSECTION 6. 6. ROCK BITS STORAGE AND TRANSPORTATION ROCK BITS STORAGE AND TRANSPORTATION

LENGTH mm m inch foot

mm 1 mm 1 0.001 0.03937 0.003281

m 1 m 1000 1 39.3701 3.2808

inch (in) 1 inch 25.4 0.0254 1 0.08333

foot (ft) 1 foot 304.8 0.3048 12 1

WEIGHT kg tn lb

kg 1 kg 1 1000 2.2046

t 1 tn 1000 1 2204.6

lb 1 lb 0.45359 4.5359*10�4 1

PRESSURE bar atm MPa kg/cm2 psi (lb/in2)

bar 1 bar 1 0.98692 0.1 1.01972 14.504

atm 1 atm 1.01325 1 0.10132 1.03323 14.696

MPa 1 MPa (N/m2) 10 9.8692 1 10.197 145.0377

kg/cm2 1 kg/cm2 0.98067 0.96784 0.09806 1 14.2233

psi (lb/in2) 1 psi (lb/in2) 0.06895 0.06805 6.89*10�3 0.07031 1

VOLUME l m3 cf

l 1 l (dm3) 1 0.001 0.03531

m3 1 m3 1000 1 35.3146

cf (ft3) 1 cf (ft3) 28.3168 0.02831 1

CIRCULATION RATE l/min m3/min cfm

l/min 1 l/min 1 0.001 0.03531

m3/min 1 m3/min 1000 1 35.3146

cfm (ft3/min) 1 cfm (ft3/min) 28.3168 0.02831 1

VELOCITY m/s km/h m/h ft/min

m/s 1 m/s 1 3.6 3600 196.85

km/h 1 km/h 0.2778 1 1000 54.68

m/h 1 m/h 2.778*10�4 0.001 1 0.05468

ft/min 1 ft/min 0.00508 0.01828 18.2879 1

37www.vbm.ru

CONVERSION TABLE

Appendix 1

Appendix 2

Appendix 3 Appendix 4

Appendix 5

Phone: +7 (846) 330�30�70, 300�31�63

Fax: +7 (846) 330�27�52

E�mail: [email protected]

42

CONTACT INFORMATIONCONTACT INFORMATION

GENERAL DIRECTOR

COMMERCIAL DEPARTMENT

SERVICE AND BIT RESEARCH DEPARTMENT

Phone: +7 (846) 300�80�34, 330�29�90


Phone: +7 (846) 330�30�79, 330�31�56, 300�80�34

Fax: +7 (846) 330�31�06


www.vbm.ru

VOLGABURMASH, JSC1, Groznenskaya Str., Samara,

443004, Russia

FOR NOTESFOR NOTES

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