Drill Bits

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7. Drill Bits

Habiburrohman abdullah

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Drill Bits

• Types and Codes

• Dull Grading

• Economic and Optimization

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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

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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)

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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.

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• 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.

Type of Bits – Roller Cone Bits

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Design Factors - Roller Cone Bits

• The drill bit design dictated by the type of the rock to 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

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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.

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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.

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Design FactorsC. 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

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Design Factors

Various Bit Style

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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

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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.

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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.

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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.

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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.

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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

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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

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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

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Roller Cone & PDC Bits

Roller Cone Bit

PDC Bit

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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

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Reasons for Having Accurate 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

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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

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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.

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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

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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”

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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”.

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Fixed Cutter Bit Dull Characteristic Codes

• BF - Bond Failure • BT - Broken Cutters • BU - Balled Up• CR - Cored

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• CT – Chipped Cutters • DL – Cutter Delamination• ER – Erosion • HC – Heat Checking • JD – Junk Damage

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• LM – Lost Matrix• LN – Lost Nozzle • LT – Lost Cutter • NR – Not Rerunable • NO – No Dull Characteristics

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• PN – Plugged Nozzle • RO – Ring Out • RR – Rerunable • TR – Tracking• WO – Washed Out Bit • WT – Worn Cutters

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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

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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

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Location for Fixed Cutter

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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

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Location for Roller Cone Bits

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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.

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Bearing / Seals

• Non-sealed bearings: 0 – 8 estimate of bearing wear.

• Sealed bearings: – E – effective seal– F – seals failed– N – not able to grade

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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.

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Gauge

Note:L is ingauge, R is 4/16th

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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.

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Bit Optimization: Nozzle Selection

• Jet Nozzle Area• An = nΣi=1 (Jeti

2) x 0.000767– Where:

• An = Jet nozzle area, in2

• Jeti2 = 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.

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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

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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

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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

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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

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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

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Bit Hydraulic Horsepower• HPb = (PDb x PO) / 1714

– Where:• HPb = Bit HP, hp


• 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

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Percent Pressure Drop At Bit

• PDb% = (PDb / PP) x 100– Where:


• PP = Pump Pressure, psi

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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

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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

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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

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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.

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END

Engineering

Drill Bits