This document discusses different types of drill bits used in drilling operations. It describes roller cone bits, which have three rotating cones with teeth. The design of roller cone bits is influenced by factors like the journal angle, cone offset, tooth shape and angle, and bearing design. The document also discusses insert bits, which use tungsten carbide inserts pressed into the cone, and PDC bits, which employ a layer of polycrystalline diamond. Standards for grading and classifying bits based on wear are also outlined.

1. 1
7. Drill Bits
Habiburrohman abdullah

2. 2
Drill Bits
• Types and Codes
• Dull Grading
• Economic and Optimization

3. 3
Bit Selection Guidelines
• During the planning stage, the drilling engineer
makes a thorough review of offset well data and
record bit performance and bit grading
characteristics in formation comparable to the well
be designed.
• Data required for the correct bit selection include the
following:
- Prognosed lithology column with detailed
description of each formation.
- Drilling fluid details.
- Well profile

4. 4
Type of Drillbits
Rotary Drilling bits usually are classified according
to their design as :
- Drag Bits, fixed cutter blade (a & b)
- Roller Cutter Bits, has two or more cone (c)
(a)
(b) (c)

5. Type of Bits – Roller Cone Bits
• Roller cone bits are made up of three equal
sized cone and three identical legs which are
attached together with a pin connection.
• Nozzle are used to
provide constriction in
order to obtain high
jetting velocities
necessary for efficient
bit and hole cleaning.
5

6. Type of Bits – Roller Cone Bits
6
• There are two types of roller cone bits:
1. Milled tooth bits:
- the cuttings structure is milled from the
steel making up the cones.
2. Insert bits:
- the cutting structure is a series of inserts
pressed into the cones.

7. Design Factors - Roller Cone Bits
• The drill bit design dictated by the type of the rock to
7
be drilled and size of hole.
• The following factors should be considered when
designing a three cone bits (Roller Cone Bits):
- journal angle
- offset between cone
- teeth
- bearing

8. 8
DESIGN FACTORS
A. Journal Angle
Defined as the angle formed
by a line perpendicular to the
axis of the journal and the
axis of the bit.
The optimum of journal angle
for soft and hard roller cone
bits are 33 degrees and 36
degrees.

9. 9
Design Factors
B. Offset between Cones
The cone profile determines the
durability of the drillbit. Cones with
flatter profile are more durable but
give lower ROP, whilst rounded
profile delivers a faster ROP but is
less durable.
The degree of cone offset is
defined as the horizontal distance
between the axis of the bit and the
vertical plane through the axis of
the journal.

10. 10
Design Factors
C. Tooth Angle and Shape
The drill bit can have slander and long teeth or short and
stubby teeth.
The long teeth are design to drill soft formations with low
compressive strength where the rock more yielding and
easily penetrated.
The short and stubby teeth are design for hard formation,
simply to fracture it by the application of high compressive
loads
Tooth shape

11. 11
Design Factors
Various Bit Style

12. 12
Design Factors
D. Bearing
The bearing
must take the
loads generated
as the bit cutting
structure (and
gauge area)
engage with the
formation as
WOB is applied.
a

13. 13
Insert Bits
• The design factors
relating to cone
offset, bit profile
discussed above for
milled tooth bits apply
equally to insert bits.
• The cutting structure of insert bits relies on
using tungsten carbide inserts which are
pressed into pre-drilled hole in the cone of bit.

14. 14
Insert Bits
• Soft insert bits have fewer and longer inserts
to provide aggressive penetration of the rock.
Durable, hard formation have many, small
diameter inserts with limited protusion.

15. 15
IADC Classification
for Roller Cone Bits
• IADC established a three code system for roller
cone bits.
• The first code define the series classification relating
to the cutting structure (carries the number 1 to 8).
• The second code related to the formation hardness
subdivision within each group and carries the
number 1 to 4.
• The third code defines the mechanical features of
the bit such as non-sealed or sealed bearing.

16. 16
Bit Classification
A. The First Code
- For milled tooth bits carries the number 1 to 3 (soft,
medium and hard rock respectively).
- For insert bits carries the number 4 to 8.
B. The Second Code
- The numbers signify formation hardness, from softest to
hardest within each series.
C. The Third Code
- There are seven subdivisions within third code.

17. 17
Bit Classification
Third code subdivision:
- non-sealed roller bearing
- roller bearing air cooled
- sealed roller bearing
- sealed roller bearing with gauge protection
- sealed friction bearing
- sealed friction bearing with gauge protection
- special features – category now obselete

18. 18
Bit Classification
Example :
A Code of 1-2-1 indicates :
Code 1: long, slim and widely spaced milled
tooth bit
Code 2: medium soft formation
Code 3: non-sealed bearing

19. 19
PDC Bits
• A Polycrystalline Diamond Compact (PDC) bit
employs no moving part and is design to
break the rock in shear and not in
compression as is done with roller cone bits.
• A PDC bit employs a large number of cutting
elements, each called PDC cutter. The PDC
cutter is made by bonding a layer of
polycrystalline man-made diamond to a
cemented

20. 20
Roller Cone & PDC Bits
Roller Cone
Bit
PDC Bit

21. 21
Bit Grading
• It is the procedure for describing the condition
of a bit after it has drilled a section of rock
and has been pulled out of the hole.
• It is directed at 2 areas:
– Determining the amount of physical wear
– Analysis of the cause of the wear

22. Reasons for Having Accurate
22
Bit Grading
• Will provide reliable info for future well
planning (better bit selection)
• Will improve drilling practices. It gives clues
as to what is happening down hole
• Provides the basis for determining optimum
bit life
• Will improve bit design

23. 23
IADC / SPE 23939 (1987)
• Allows for 8 factors to be recorded:
– Cutting Structure: Inner rows, Outer rows, Dull Character,
Location
– Bearing / Seals
– Gauge 1/16”
– Remarks: Other Character, Reason Pulled

24. 24
Inner Rows
• Used to report the conditions of the cutters
not touching the borehole walls.
Outer Rows
• Used to report the conditions of the cutting
elements that touch the borehole walls.

25. 25
Inner / Outer Rows
• Wear is recorded on a linear scale as a single
digit from 0 (no wear) to 8 (no usable cutting
structure remaining)
• Use an IADC PDC Wear Gage for PDC

26. 26
Inner / Outer Rows
• For fixed cutter bits the
average amount of wear
of each area is recorded,
with 2/3 of the radius
representing the “Inner
rows” and the remaining
1/3 representing the
“Outer rows”

27. 27
Dull Character
• The code for the most prominent or primary
characteristic of the dull bit should be entered
here. Any secondary dull characteristics of
the bit can be entered in “Other
Characteristic”.

28. 28
Fixed Cutter Bit Dull
Characteristic Codes
• BF - Bond Failure
• BT - Broken Cutters
• BU - Balled Up
• CR - Cored

29. 29
Fixed Cutter Bit Dull
Characteristic Codes
• CT – Chipped Cutters
• DL – Cutter Delamination
• ER – Erosion
• HC – Heat Checking
• JD – Junk Damage

30. 30
Fixed Cutter Bit Dull
Characteristic Codes
• LM – Lost Matrix
• LN – Lost Nozzle
• LT – Lost Cutter
• NR – Not Rerunable
• NO – No Dull Characteristics

31. 31
Fixed Cutter Bit Dull
Characteristic Codes
• PN – Plugged Nozzle
• RO – Ring Out
• RR – Rerunable
• TR – Tracking
• WO – Washed Out Bit
• WT – Worn Cutters

32. 32
Roller Cone Bit Dull
Characteristic Codes
• BC – Broken Cone
• BT – Broken Teeth
• BU – Balled Up
• CC – Cracked Cone
• CD – Cone Dragged
• CI – Cone Interference
• CR – Cored
• CT – Chipped Teeth
• ER – Erosion
• FC – Flat Crested Wear
• HC – Heat Checking
• JD – Junk Damage
• LC – Lost Cone
• LN – Lost Nozzle
• LT – Lost Teeth
• NO – No Dull Characteristics
• NR – Not Rerunable
• OC – Off Center Wear
• PB – Pinched Bit
• PN – Plugged Nozzle
• RG – Rounded Gauge
• SD – Shirttail Damage
• RR - Rerunable
• SS - Self Sharpening Wear
• TR - Tracking
• WO - Washed Out Bit
• WT - Worn Teeth

33. 33
Location for Fixed Cutter
• This is the location of the primary dull
characteristic.
• Use the codes:
– C - cone
– N - nose
– T - taper
– S - shoulder
– G – gauge
– A – All

34. 34
Location for Fixed Cutter

35. 35
Location for Roller Cone Bits
• N – Nose Row (the centermost cutting elements of
the bit)
• M – Middle Row (the cutting elements between the
nose and the bit)
• G – Gauge Row (those cutting elements that touch
the wall of the hole)
• A – All Rows
• 1, 2 or 3 – Cone number

36. 36
Location for Roller Cone Bits

37. 37
Bearing / Seals
• Indicates the condition of the bearing and
seal assembly.
• Fixed cutter bits will always be designated
"X".
• Equivalent to the B of the old TBG grading.

38. 38
Bearing / Seals
• Non-sealed bearings: 0 – 8 estimate of
bearing wear.
• Sealed bearings:
– E – effective seal
– F – seals failed
– N – not able to grade

39. 39
Gauge
• This is used to record the condition of the bit gauge.
• The letter "IN" is used if the bit is In gauge.
• If the bit is under gauge,the amount should be
recorded to the nearest 1/16th of an inch.
• It is good practice to gauge a bit both before and
after a run.
• Use a nominal ring gauge for milled tooth bits and a
fixed cutter ring gauge is used to gauge fixed cutter
bits. Due to different manufacturing tolerances ,a
roller cone bit gauge will show a fixed cutter bit to be
under gauge.

40. 40
Gauge
Note:
L is ingauge, R is 4/16th

41. 41
Other Characteristic
• This is used to record secondary bit wear. This
could relate specifically to cutting structure wear or
may identify wear to the bit as a whole, such as
erosion.
• This is in addition to the wear identified and
recorded in Dull Characteristic and may highlight
the "cause" of this wear.
• "Other characteristics" can be used to record
whether a bit is re-runable "RR" or not "NR".
• The codes for both "primary" and "secondary" wear
are the same.

42. Bit Optimization: Nozzle Selection
42
• Jet Nozzle Area
• An = nΣi=1 (Jeti
2) x 0.000767
– Where:
• An = Jet nozzle area, in2
• Jeti
2 = nozzle diameter in 32nd of an inch
Note:
• Most roller cone bits use three or four jet nozzles, while PDC bits usually contain
six to nine. The flow area of all jets must be determined separately, then added
together.

43. 43
Jet Nozzle Velocity
• Velocity of the mud exiting the jet nozzles
• Important in hydraulic optimization
• Vj = (PO x 0.32086) / An
– Where:
• Vj = nozzle velocity, ft/sec
• An = nozzle area, in2
• PO = pump output, gpm

44. 44
Bit Pressure Drop
• Essential in determining the hydraulic
horsepower
• PDb = (Vj2 x MW) / 1120
– Where:
• PDb = Bit pressure drop, psi
• Vj = nozzle velocity, ft/sec
• MW = mud weight, ppg

45. 45
Bottom Hole Cleaning
• Proper bottom hole cleaning will:
– Eliminate excessive regrinding of drilled solids
– Result in improved ROPs
• Bottom hole cleaning efficiency is achieved
through proper bit jet size selection

46. 46
Bit Optimization
• Through proper nozzle selection, optimization
may be based on maximizing one of the
following:
– Jet Impact Force
– Bit Hydraulic Horsepower
• There is no agreement on which of these two
parameters should be maximized

47. 47
Max Bit Hydraulic
Horsepower: Basis
• Based on the theory that cuttings are best
removed from beneath the bit by delivering
the most power to the bottom of the hole
• To optimize Bottom Hole Cleaning and Bit
Hydraulic Horsepower, it is necessary to
select a circulation rate and nozzle sizes
which will cause appx 65% of the pump
pressure to be expended forcing the fluid
through the jet nozzles of the bit

48. 48
Bit Hydraulic Horsepower
• HPb = (PDb x PO) / 1714
– Where:
• HPb = Bit HP, hp
• PDb = Bit pressure drop, psi
• PO = pump output, gpm
Bit HHP Per Unit Bit Area
• HPb/area = HPb / Ab
– Where:
• HPb = Bit hydraulic horsepower in hp
• Ab = Area of the bit

49. 49
Percent Pressure Drop At Bit
• PDb% = (PDb / PP) x 100
– Where:
• PDb = Bit pressure drop, psi
• PP = Pump Pressure, psi

50. 50
Max Bit Hydraulic
Horsepower: Conclusion
• In general, the hydraulic horsepower is not
optimized at all times
• It is usually more convenient to select a pump
liner size that will be suitable for the entire
well
• Note that at no time should the flow rate be
allowed to drop below the minimum required
for proper cuttings removal

51. 51
Max Jet Impact Force: Basis
• Based on the theory that cuttings are best
removed from beneath the bit when the force
of the fluid leaving the jet nozzles and striking
the bottom of the hole is the greatest

52. 52
Max Jet Impact Force:
Optimization
• High flow rates impacting with moderate force
rather than a small volume impacting at a
high pressure
• Optimized when circulating rates and bit
nozzle sizes are chosen which will cause
48% of the pump pressure to be used to force
fluid through the jet nozzles

53. 53
Jet Impact Force
• Impact Force = (MW x Q x Vj) / 1930
• Impact Force = MW x Q x Vj x 0.000516
Where:
• MW = Mud Density, ppg
• Q = Flow Rate, gpm
• Vj = Nozzle Velocity, ft/sec
Note:
As can be seen, Impact Force depends on maximizing flow rate and nozzle
velocity rather than pressure. Therefore, higher flow rates are required. The
emphasis is on a large volume of fluid impacting with moderate force, rather
than a small volume impacting at a high pressure.
This condition is optimized when circulating rates and bit nozzle sizes are
chosen which will cause 48% of the pump pressure to be used to force fluid
through the jet nozzles.

54. 54
END