bit_selection_guidelines.pdf

8/18/2019 Bit_selection_guidelines.pdf

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Bit Selection Guidelines

A comprehensive set of drill bit guidelines relating to Features, Functions, Selection,Application, and Product nomenclature has been prepared by the NSA DEC. This is anindependent document, aimed specifically to provide DE / DD / PERFORM Engineerswithin Schlumberger an unbiased guide for what bit design and characteristics should berequired to match bit to both drive type and geology for optimal BHA performance. Thiswill aid the engineer in making technically justified bit recommendations and knowledgeof what may need correcting in the event of a poor bit run.

This document is produced in conjunction with the bit selection work flow, though can beused as a stand-alone document reference to either bit design aspects or nomenclature.

Chapter Index Detailed Content Index

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Drill Bit Selection - Index

1. Data Analysis and Evaluation 5. Hydraulics

2. Durability / Aggressivity 6. Stability Aspects

3. Formation Factors 7. Nomenclature / Products

4. Matching Bit to Drive 8. Reference Documents

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Data Analysis and Evaluation

1. Offset Data Requirements 4. Economic Evaluation

2. Subject Well Review 5. Post Run Data Collection

3. Required Dataset 6. Dull Grading

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Data Analysis Process

Offset Data Collection

All relevant offset data must be collected. The higher quality and quantity of the

information available enables the drilling problems to be more clearly understood,leading to better decisions and recommendations being made. The customer must beasked which offset wells they consider to be the most relevant - Maximum informationmust be gathered for these.

The following is a list of the ideal dataset required.

• Bit records. These form a straightforward record of run performance, though varyin consistency, as different Operators will record varied information on their bitrecords. In addition, all bit companies maintain extensive databases containing both individual bit, and entire well records, and thus data may also be obtained

this way.• Bottom hole assembly records. These provide valuable information on the drilling

systems used. In directional wells, the directional driller will frequently add rundescription comments, which can be very insightful and useful.

• Operator daily drilling/operations summary reports. These consist of extremelyuseful information including bit, BHA and mud details. The daily operations arealso recorded with specific drilling comments that highlight drilling problems, practices and performance.

• Drilling service company summary reports and directional drilling post wellreports. These will frequently include comments on performance, problemidentification and recommendations. Ensure all previous End of Well Reports

(EOWRs), Lessons Learnt and Recommendations are collected as there may beaction items that have been agreed with the client that need to be considered.

• Daily Mud Reports from the mud company. These provide good information onthe condition of the mud throughout the drilling process.

• Surface and down hole drilling parameter data in digital format. This data will provide the parameters that were applied and can be correlated to events (e.g.formation, vibration, etc) throughout the section to help draw accurate operationalconclusions. Useful surface and down hole parameter data includes:

o Weight on bit, (DWOB)o Torque, (DTOR)o Rotary Speedo Flow Rate

• Down hole vibration data in digital format. This illustrates the down holevibrations experienced and can be correlated to events (e.g. formation, drilling parameters, etc) throughout the section to help draw accurate bit/BHA/drill stringdynamic conclusions.

• Formation data for evaluation. Use of software such as Terrascope and that fromDCS, requires specific information in digital format to be run effectively. Thetable overleaf illustrates the optimum and minimum dataset required. A rock


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strength analysis calculated using only the minimum dataset is of limited value. Itwill generally provide good comparative data of the rock strength between eachformation encountered in the same well. When porosity is not constant,inaccuracies can occur so formation rock strengths cannot be directly compared.Inaccuracies also occur when comparing different wells even in the same field

due to different porosity values. The optimum dataset will accurately calculaterock strength.

• Log • Optimum

Dataset

• Minimum

Dataset

• Abbreviations • Units

• Mud Log • X • X • •

• Gamma Ray • X • X • GAPI • API

• CompressiveSonic

• X • X • DT, DTCO • µs/ft

• Shear Sonic • X • • DTSM • µs/ft

• NeutronDensity

• X • • RHOB, RHOZ • gm/cm3

• NeutronPorosity• X • • NPHI, DPHZ •

• Seismic cross sections and SLB MEMs (Mechanical Earth Models) can helpvisualize formation characteristics including faults, folds, bedding angles, etc thatmay cause drilling problems.

QA/QC Offset Data

The potential data set for analysis will vary greatly depending on the operator andgeographical location. Regardless of quantity, the key is to select the most relevant data,including that which-

- The customer has identified- Is at a close location- Has a similar formation characteristic- Has an equivalent application characteristic

Once the relevant information has been collected the data needs to be quality checked toensure that it is accurate. This is critical, as benchmarks, key performance indicators, andthe bit selection will be set using this data.


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Subject Well Data

In order to determine relevance of the offset data and define any potential issues or

requirements, it is essential to examine the proposed dataset surrounding the subject well.If correctly following the Schlumberger work process flow chart for well design, therequired factors will already be covered.

As a reminder, the following need to be reviewed:

1) Rig Evaluation, to include

• Power

• Drive

• Crew experience

• Mud pumps

• Solids control equipment• Surface measurement sensors

2) Well design, to include

• Casing program

• Shoe / Plugs / Float equipment

• Well trajectory / Profile

• Survey design

3) Mud system

• Weight

• Additives

• Viscosity

• LCM

• Over / under balance conditions

• Fracture gradient

4) BHA design, to include

• Drive

• Torque & drag

• Hydraulics

• String tools• Drilling parameters


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Defined data for Selection process

Using the data for both the offset wells and that for the subject, the following should be

defined before entering the bit selection process. The list below contains the ideal parameters to be used for an engineered and economic evaluation of your optimal bit viathe selection flowchart.

• Proposed interval

• Average drilling time / ROP from offset bit performance records

• Offset and projected tripping speeds

• Rig cost (hourly rate) for subject well

• Specifications of bits used in offset wells (including cost)

• Formation details, to includeo Rock strengtho Abrasivenesso Elasticityo Pore Pressureo Rock types and frequency of interbeddingo Presence of non PDC drillable lithologies / mineralso Presence of reactive clays

• Offset or potential vibration issues

• Type of drilling fluid and properties / additives

• Available hydraulic energy for the subject well

• Offset drilling parameters and limitations on parameters for subject

• Directional requirements for subject well profile and proposed BHA

• Drive type and drive outputs (Torque, RPM)

• Casing plan – Is an eccentric bit or string reamer required?

• Properties of proposed shoe / plug / float equipment

• Anticipated downhole temperature


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Economic Evaluation

Considering that you have evaluated all the necessary requirements for the bit to be run(i.e. drive, directional, stability, etc), and that your derived bit options can all deliverthese requirements, it is necessary to evaluate the economics so that you can select the

optimal bit to deliver the performance at the lowest cost per foot to the client.

Projected Cost per foot

Although the actual cost of the bit is not a massive sum compared to other drilling tools,it will have a major impact on drilling costs in terms of rig time to drill the section, particularly if additional trips are required or low penetration rates are achieved. Theequation below takes into account these additional factors:

C = R (T + D) + B

F

Where:

C = Overall Drilling cost per footR = Hourly rig costT = Trip time (hrs)D = Drilling time (hrs)B = Cost of bitF = Interval drilled (ft)

This equation can be used to project cost per foot for proposed drill bits in specific

applications. It is an effective method of deriving the optimal bit type for your drillingsystem when faced with an impreg, roller cone, and PDC option. Although used for projection, it must be based on reliable offset data for other bits run in a similarapplication in order to obtain anticipated drilling times and average bit life. If evaluatingconsiderably different bit designs than previously run, estimated life and potential penetration rates must be evaluated using all available resources including the clientsengineering group and the bit representatives who will have access to drill bit simulators.

This will provide a simple insight into anticipated costs if the bit performs as expected,and may allow you to discount certain options based on vast economic differences.However, it will be necessary to further examine the options and consider scenarios and

actions if the bit does not perform as expected.

Risk Analysis

The initial analysis of the offset data at the start of the bit selection process should haverevealed any historical or potential inconsistencies in drilling performance relating toexternal factors. For example, chert beds may have appeared on two out of ten offsetwells resulting in heavy PDC bit damage and the requirement to pull out and run back in


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hole with an alternative design, whereas the other eight wells were all drilled with onerun. This risk should be built into the economic evaluation so that best and worst casecosts can be calculated for each of your bit options. The relevant equation is below:

Cr = (Ps x S) + (Pf x F)

I

Where:Cr = Overall cost per foot, taking into account risk of failurePs = Probability of successS = Cost of successPf = Probability of failureF = Cost of failureI = Interval drilled (ft)

Using both the equations covered in this section, you will result in having a table which

depicts best-case performance / cost, worst-case performance / cost, and potential riskswith each of your derived bit options from the selection process. This can then beevaluated and presented to the client as a proposal.


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Post Run Data Collection

All relevant data should be collected as soon as possible for two reasons. Firstly, thesooner the data is received the sooner decisions or reports can be presented to thecustomer; and secondly, if the data is not collected quickly it has the habit of getting lost

or not downloaded from tools.

The following is a list of the data that is required (if available) for in-depth analysis of therun performance:

• Bit Record

• Bottom Hole Assembly Record

• Dull bit photos

• Bottom hole assembly photos

• Daily Drilling/Operations Summary Reports

• Daily Directional Drilling Summary Reports• Directional Drilling Post Well Summary Reports

• Proposed and actual survey details (digitally and graphically).

• Daily Mud Reports

• Surface and down hole data (preferably digital or log format) including-o Weight on bito Surface torqueo Surface rotary speedo Flow rate

• Down hole vibration data including-o Axial vibration

o Lateral vibrationo Torsional vibrationo Shock, i.e.: impact, magnitude and count

• Formation evaluation data including-o Gamma rayo Compressive sonico Shear sonico Neutron densityo Neutron porosityo Caliper logo Mud log

It is important to QA/QC all data collected to ensure that the true facts are representede.g. preliminary checks will ensure that the data recorded is of a reasonable magnitudeand that the tools have been calibrated correctly.


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Dull Grading

All types of drill bits should be graded using the latest revision of the IADC dull gradingsystem (SPE 23939). The schematic below has been extracted from that document anddisplays the eight boxes that are used to capture the key wear, damage, and reasons

pulled for each bit run. This section will go through each box in sequence. Note that dullgrading does have a degree of unquantative opinion relating to it, and thus will vary from person to person.


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Box 1 – Inner Rows

This is a measure of cutter wear, visually evaluated on a sequential numeric scale of 0through to 8, with 0 representing unworn cutters, 4 relating to 50% wear, and 8 equallingcomplete wear of the cutter.

Box one relates to the cutter wear of the inner teeth, thus the inner rows on a roller conedesign. With fixed cutter bits, this relates to a point outwards from the cone of 2/3 of the bit radius. This generally relates to the cone, nose, and upper shoulder of the bit.

Box 2 – Outer Rows

As per box one above, though relates to cutter wear of the outer teeth. This translates asthe gauge row (and heel) of roller cone bits, and the shoulder and gauge of fixed cutterdesigns. Note that it is common on PDC bits to use preflatted cutters at gauge (usually thevery last cutter on each blade) and this should not be confused with downhole wear.

It is impossible to evaluate wear on impregnated designs using a visual methodology dueto the fact that the cutting structure is continually replenished. Some manufacturers haveadopted systems where they implant wear markers in the matrix body. You would need toapproach the individual manufacturers of these products if a truly accurate measure ofwear is sought.

Box 3 – Dull characteristic

This is an assessment of the major dull characteristic shared by the majority of thecutting structure. The codes and characteristics can be viewed in the IADC table prior.Visual examples and more detailed descriptions of these dull conditions can be viewed atthe rear of this section.

Box 4 – Location

This is the primary location of the major dull characteristic noted above. On fixed cutterdesigns, the bit is broken down into five areas: Cone (C), Nose (N), Taper (T), Shoulder(S), and Gauge (G), as can be viewed below.

With roller cone bits, you still use both cone, nose, and gauge, but also have the option ofMiddle row (M) and Heel row (H). For both bit types you can also use ‘A’ to representthat the dull condition is evident in all areas.


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Box 5 – Bearings / Seals

This section relates to roller cone designs only. For fixed cutter bits, place an ‘X’ in this box and then move onto box six.

This box relates to the effectiveness of either the seals or bearings, and again, it is avisual assessment. With sealed bearings, it is assumed that if the seals are effective thatthe bearings have not failed. As such, you simply use ‘E’ for seals effective, or ‘F’ forfailed seals. With non-sealed bearing designs (usually large diameter top-hole bits) youvisually assess (and shake the cones) the life of the bearing and use a sequential numericscale to grade it (0 = Full life left, 8 = All life used).

Due to the fact that the majority of roller cone bits have three cones (thus three sets of bearings), it is common to differentiate by placing the cone number after the seals / bearing code if one has failed.

Box 6 – Gauge

This is a simple measure of whether the bit has retained gauge, and can be carried out onall bits (except eccentric reamers) using a ring gauge. Note – Be aware whether you areusing a no-go or go gauge ring.

If the design is in gauge, you place an ‘I’ in this box. If the bit has gone undergauge, you place the magnitude (in fractions of an inch) how much under it is. This should berecorded as the radial distance undergauge.

Box 7 – Other characteristics

This box is used to include any other dull characteristics evident on the bit secondary towhat you have already documented in box three. It uses the same two-letter code system.

Box 8 – Reason pulled

The final box relates to the reason as to why the bit run was terminated. A comprehensivelist has been provided on the IADC table. Note that some operators do use a variation ofthese codes specific to that company (bp in particular).


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DULL CHARACTERISTICS

BC = Broken Cone (Roller cone only)

Breakage of the actual cone cutter. This is an unusual and severe condition, resultant

from either high axial impact loading from dropping onto bottom or striking a ledge athigh speed while tripping. It may relate to a materials or manufacturing process issuewith the bit, though is unlikely.

BF = Bond Failure (PDC only)

This is the complete separation of the PDC and upper substrate layerfrom the substrate post or stud that is embedded in the blade. This isan unusual condition and if it occurs, it would usually only be seenon one or two cutters. A move towards single piece and shortersubstrates has also helped to eliminate this dull condition.

BT = Broken Teeth / Cutters (PDC / Roller cone)

This is where a large portion of the cutter, insert, or tooth has brokenaway. This can be resultant from a number of issues includingformation strength, vibration, excessive parameters, inappropriatecutting structure, etc.

BU = Balled up (All)

This is when the cutting structure is immobilised due to beingcoated in formation (usually sticky, water sensitive clays) and thusis unable to drill efficiently. It is resultant from a combination offactors such as inappropriate mud selection for formation, poorHSI at the bit, low junk slot area / volume, etc. It may be‘unballed’ downhole by a number of means such as picking offand rotating at high speed, or pumping detergent to clean.

CC = Cracked Cone (Roller cone only)

Cracks apparent in the actual cone of the bit. This is the step prior to broken cone, and assuch, is resultant from the same causes.


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CD = Cone Dragged (Roller cone only)

This occurs when the cones of the bit get locked, either by balling ormechanical locking (formation nodule, junk). Without rotation, thecones are dragged around the hole via string rotation leading to

heavy wear to the exposed cone surface.

CI = Cone Interference (Roller cone only)

This can be determined by the presence of multiple broken and chipped cutters, withgrooves cut into the cone shell. It occurs after a bearing failure, which allows one or moreof the cones to move free along its axis thus colliding into the adjacent cones.

CR = Cored (All)

This is identified by extreme wear to the cone of the bit as a result ofeither cutter breakage in the cone, drilling hard formation, orextreme erosion from use of a centre jet nozzle with rock bits. It isobserved on both roller cone and impreg / natural diamond bits but israre with PDC bits. Extreme cone wear on PDC bits would normally be classed as a ringout.

CT = Chipped Teeth (All)

Minor chips and breaks of the cutting structure. Not as severe as broken teeth, though can often be recorded as either of these twocodes. Chipped teeth are resultant from the same causes as per thatfor broken teeth.

ER = Erosion (All)

Resultant from either mechanical blasting of the bit body with mud containing high solids/ sand content, or from interaction with very abrasive formations. The usual occurrence ison the body around cutter pockets and the substrate of the cutters (PDC) or teeth (Rollercone). If severe, it may result in broken or lost cutters due to reduced support.


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HC = Heat Checking (All)

Cracking and subsequent breakage of tungsten carbide can occur when subjected to hightemperatures. The heat may be generated as a result of high RPM, hard and abrasiveformations, and poor cooling via the bit nozzles. It can be observed on tungsten carbide

elements such as cutters, PDC substrates, and matrix bodied fixed cutter bits.

JD = Junk Damage (All)

This may effect any portion of the bit and can result from drilling either man-made orformation junk (e.g. pyrite / chert with PDC bits). Damage can range from chippedcutters to severe cutter breakage and broken blades. However, this kind of damage canalso be resultant from severe downhole vibration, and as such, further evidence needs to be analysed before drawing any conclusions.

LC = Lost Cone (Roller cone only)

A lost cone is resultant from failed bearings and is extremely easy to identify on a dull bit. Identification of failed bearings prior to loss of cone should be identified via thedrilling characteristics of the bit (Torque, ROP).

LN = Lost Nozzle (PDC / Roller cone)

Loss of the nozzle jet or nozzle retainer. This usually results in cutter breakage if thenozzle component can not be circulated up the annulus quickly. A lost nozzle can beresultant from the erosion of the retainer, but in most cases, is due to improper fitting.

LT = Lost Teeth (PDC / Roller cone)

This is when the entire cutter assembly is missing, leaving a cleanempty pocket. General cause of lost teeth is either severe erosion ofthe pocket, extreme cyclic loading (stick-slip), or poormanufacturing process (braze / hole sizing).

NR = Not Rerunnable (All)

Not an acceptable dull condition as it reveals no information on the failure mode of thedrill bit. Do not use.


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OC = Off Centre Wear (All)

Irregular wear or erosion of the cone shell or bit body. Thismay occur when the drill bit is run on a directional assemblywith a bend so that the bit drills an oversize hole in rotary

mode. In hard formations, ridges may develop in the formationthat rub on the bit body or cone.

PB = Pinched Bit (Roller cone only)

Bit will appear ‘squeezed’ with the lugs bent inwards and will be undergauge. This isresultant from forcing the bit into an undergauge hole. Damage will also be evident to the bearings and the overall strength of the body will be reduced.

PN = Plugged nozzle / Flow Passage (All)

Nozzles can be plugged with either formation (packed off), lost circulation material, orrubber from either a failed downhole tool or surface mud pumps. You may have someassociated balling or unnatural wear due to inefficient cooling.

RG = Rounded gauge (Roller cone)

This is basically heavy wear at the gauge, though usually the bit is still in gauge.Generally noted with roller cone bits due to the geometry of the cutting structure on thecones, which can ‘round-off’.

RO = Ringout (All)

This is identified by a band of preferential wear on the bit. This band may be variable in width and in severe instances willextend down through the cutting structure and through the blades/ cones. It is relatively common on PDC bits either on theshoulder or nose. It can relate to either a weakness in the cuttingstructure in that application or may result from disabled cutters(vibration / breakage).

RR = Rerunnable (All)

Basically means that the bit is in an acceptable condition to be run again. This codeshould not be used, as it does not reveal any data concerning the dull condition of the bit.If the bit has no dull characteristic, you should use the ‘NO’ code.


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SD = Shirttail Damage (Roller cone only)

Damage or erosion of the shirttail or associated protection components within. This isgenerally related to either wear from the formation or junk damage, the former usuallyoccurring if the bit has gone undergauge.

SS = Self Sharpening Wear (Roller cone only)

This is rarely seen and is restricted to milled tooth bits only. It occurs when none or onlylight hard metal is applied to the teeth, resulting in continuous erosion of the tooth whichthus maintains a sharp cutting edge.

TR = Tracking (Roller cone only)

This can be identified by symmetrical wear of the cutters. It is resultant from disruptionof the cutting action so that the cutters from one cone fall into the holes in the bottom

hole pattern left by the prior cones. This can be compared to a set of intermeshing cogwheels, and thus a secondary condition are indentations in the cone shells caused by thecutters on the adjacent cones.

WO = Wash out (All)

This can be identified by a hole in the bit body that occurs either at the pin or at a weld point. This is a serious failure.

WT = Worn Teeth (All)

This is a normal dull characteristic and indicative of normal drilling conditions. However,if wear is significantly uneven (as will be revealed by the Inner / Outer teeth wear) it isindicative that either the cutting structure is weak for that application, or that the drilling parameters / conditions were extreme.

NO = No Dull (All)

This code is utilized when there is no dull characteristic i.e. the bit is in new condition.This is a good dull condition, though indicative that the bit is too heavy set and thus performance could be improved.


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Durability And Aggressivity

With all bits there will always be a compromise between durability and potential penetration rates that can be attained. This is due to the fact that both are affected bycommon design factors i.e. you lower one aspect to improve durability and you usuallysee a decrease in aggressiveness, and vice versa. This section details the key bitcharacteristics that need to be balanced during selection to attain both the durability todrill the section, whilst maintaining good ROP.

1. PDC 4. Additional Durability

2. Roller Cone 5. Roller Cone Bearings

3. Diamond 6. Cutter Technology

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Durability And Aggressivity - PDC

1. Back Rake 4. Blade Count

2. Cutter Size 5. Profile

3. Cutter Count 6. Side Rake

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Bit characteristics relating to Durability and Aggressiveness

PDC BITS

Back Rake

The back rake angle of a cutter is one of the key features relating to the aggressiveness ofa PDC bit, however, it is one of the least disclosed from the bit suppliers. As such, theindustry tends to refer variation of PDC aggressiveness in terms of blade count and cuttersize. This misconception could lead to a directional driller running a design that appearsunaggressive when in fact, due to low backrake angles, is aggressive and resultant torqueis too high to maintain toolface on the motor being used.

Back rake angle is defined as the angle that the cutter is presented to the formation beingdrilled as illustrated below. As the cutter face angle moves towards being perpendicularto the formation, back rake angle increases.

The lower the backrake angle (i.e. closer to zero), the more aggressive the cutter is due to

improved efficiency and a greater depth of cut for a given weight on bit. However,greater aggression will result in higher torque. Increasing the back rake angle will reducethe torque, though this will be at the expense of potential penetration rate.

In general, backrakes on PDC bits will be in the range of 12 to 40 degrees and will alsovary around the profile of the design. Low back rake angle will commonly be located atthe nose as this has the greatest influence on penetration rates. These then graduallyincrease as you progress along the profile from the shoulder to gauge, as higher backrakes at gauge will reduce the tendency to whirl. As such a typical PDC bit to beused on PDM may have backrakes in the region of 20 degrees in the cone and nose,incrementally increasing to 30 degrees down to the gauge.

It is important that you obtain the magnitude and distribution of the cutter backrakes inorder to fully evaluate the suitability of the bit design to the planned drive type. All bitsuppliers should be able to easily supply this information.

40o 15o

Formation


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PDC BITS

Cutter Size

A variety of cutter sizes are in existence. The current commercial cutters generally rangefrom 8mm to 22mm in diameter, with 8, 11, 13, 16, 19, & 22mm being the mostcommon. A PDC drill bit can be composed of a single cutter size or combinations of twoor more sizes, depending on both the application and bit supplier.

With all other bit specifications constant, the following general rules apply with variationin cutter size:

• Increase cutter size = Increase Torque

• Increase cutter size = Increase ROP

• Increase cutter size = Decrease durability

A key exception, based on repeated laboratory data, is that 13mm cutters provide higher penetration rates than larger cutter diameters in sandstones. The full reason is not fullyunderstood though it relates to the cutter / rock interaction in this type of lithology.

The following is a guideline into cutter size application.

8mm: Small cutter sizes initially intended for use in hard rock applications for extendeddurability. They also benefit with low torque thus are directionally friendly. Recent trendis to move to use of 11mm cutters, which provide increased ROP whilst still proving to

have good durability and relatively low torque.

13mm: This is the most common size of PDC cutter in existence, providing reasonabledurability for medium to medium-hard formations, with backrakes balanced to providesuitable combination of steerability vs. penetration rate.

19mm: Commonly associated with light set designs for use on rotary for drilling fast holein soft formations. The large cuttings size generated by 19mm cutters in shale effectivelyreduces the likelihood of balling. This is due to the fact that the surface area of thecuttings for a specific unit of volume is reduced and thus cuttings hydration is alsoreduced.

Due to relatively high torque, careful consideration of lobe configuration is required ifrunning on a mud motor, if it is intended to slide and thus maintain tool face. There has been a gradual trend to use 16mm cutters as an alternative so as to reduce torque with lessreduction in potential ROP if you were to drop down to 13mm.

22mm: Very large cutters are of course aggressive thus providing good potential for high penetration rates. However, due to their size, cutter separation is greater (particularly on


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small diameter bits) and redundancy is reduced (i.e. durability is more likely to becompromised if one cutter fails than a bit that uses smaller cutters). In addition, wear flatsgenerated on large diameter cutters are large and thus capable of producing highfrictional heat which aids degradation of the diamond layer. This size of cutter iscurrently used by only a few of the bit suppliers.

It may be common to see the use of smaller diameter cutters utilised on the shoulder andgauge of a bit that uses a more aggressive cutter diameter on the face of the bit. Thishelps to provide a smoother borehole surface, with smaller cusps between cutters, thusless uneven torque response.


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PDC BITS

Cutter Count

The biggest factor affecting cutter count considerations is the anticipated formations to bedrilled. The bit ideally should be durable enough in terms of cutter density to drill the planned section, though not too heavyset in order to hinder potential penetration rates.

As a general rule, the harder the formation, the higher the cutter count required. Highcutter counts means that the applied weight is shared amongst more contact points andthus less depth of cut is attained by each cutter. This results in lower ROP’s, though thismay be offset if the bit is durable enough to complete the section.

Inversely, softer formations are drilled with lighter set bits, attaining higher depths of cut

per same applied weight for improved ROP, though with reduced durability. Of course,ROP and durability does not relate solely to cutter count, it is also a primary factor of back rake and cutter size. This latter factor has a major influence on cutter count as ofcourse there is limited room on the bit profile and thus larger cutters will be furtherspaced apart. Blade count also figures highly within this relationship.

Note that cutter density on a specific design will vary locally due to the weardifferentiation on a PDC design. The cone generally experiences less wear whereas theshoulder and gauge is relatively high due to the higher forces observed at the outerdiameter. As such, cutter layout will be light and heavy respectively. The nose is a careful balance of density vs. penetration rate as this is a key area of the bit affecting ROP. From

this it can also be observed that bit profile has a great effect on required cutter density.

It is very important to note that the quality of the cutter used will greatly affect both the bits durability and its potential penetration rate. Please refer to the section on PDC cuttertechnology.


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PDC BITS

Blade Count

The blades of a PDC bit have three key functions:

1. Support the cutting structure2. Define flow paths for hydraulic flow and cuttings removal3. Provide exposure for the cutters

The number of blades is related to the required durability (and hence cutter coverage) forthe design. It is generally in the range of 3 to 12. The geometry is dependant on severalfactors including bit asymmetry, structural strength, junk slot volume, blade material, etc.The exposure of the cutter is determined by the vertical height of the cutter tip above the

height of the blade. The usual design criteria is approximately half of the cutter isexposed e.g. 6.5mm for a 13mm cutter, 8.5mm on a 19mm cutter. This should be notedwhen evaluating a dull bit i.e. that once the cutter is half worn, you are effectivelyrubbing on the blade tops and thus your cutter is actually 100% worn!


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PDC BITS

Profile

Four standard profiles exist, as defined by the IADC, though multiple variations occur.Each profile is created from four aspects: Cone, Nose, Shoulder, and Gauge. Variation ofeach of these will define the overall profile.

Cone: Central location of the bit design. With the exception of designs with flat profiles,the cone is always inverted from the nose. As such, when drilling, the nose has alreadyencountered and drilled formation, isolating a section of formation within the cone. Thisresultant central cone of rock acts as resistant to lateral movement. Thus the angle of thecone, and hence cone volume, will affect the stability of the bit. Deeper cones will meanthat there is more volume of rock and thus greater stability. The inverse effect is seen onsteerability; Deeper cones reduce steerability as more rock needs to be overcome to attain

deviation.

The cone is generally lighter set as the isolated rock has been relieved of confining forcesand is easier to remove.

Nose: This is the initial contact point between formation and bit and is thus the furthest point of the bit vertically from the pin. The radius of the nose will have a defining pointon both the cone angle and radius of the shoulder – Small nose radius is generally usedfor long tapered designs, large nose radius for flat profiles and thus steerable designs.

The nose has significant effect on the penetration rate of the bit, as this is where primary

transfer of applied weight takes place. As such, this is the section of the bit that will weargreatest under normal conditions. Cutter backrake, quantity, and size are a careful balance between ROP and durability in this section.

Shoulder: This is the outer section of the drill bit that links the nose and gauge. Thelength is usually defined by the cutter coverage required for durability and experiencesthe highest cutter rotational speeds due to its outer proximity from the bit centre. As such, bits designed for high-speed applications (turbines, high speed motors) will generally


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require a long shoulder section in order to maximise cutter count. Bits on rotaryassemblies will experience much lower rotational speeds and thus may have a shortershoulder section. Of course, anticipated lithology is another major factor in shoulderdurability.

Gauge: This is where the shoulder extends to the full diameter of the bit design. Thegauge is generally observed on a bit as where the blade extends out and forms a solidgauge pad, which will contact the borehole when drilling ahead. The gauge is usually protected with a variety of applied or inserted components, as well as gauge cuttercoverage (usually pre-flatted to offer large PDC area).

There are a vast variety of gauge geometries dependant on the specific application andmanufacturer, though one common factor to all is gauge length. It is generally consideredthat longer gauge lengths provide more stability in rotation due to increased surfacecontact between bit and borehole.


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PDC BITS

Side Rake

Side rake refers to the angle of deviation of the cutter from a theoretical line normal tothe direction of travel. A negative angle means that the cutter face is skewed inwards tothe centre of the bit, whereas a positive side rake infers that the cutter face is skewedtowards the gauge.

A)

A)

Negative side rake has the effect of ‘pushing’ the generated cuttings inwards as comparedto the opposite being seen with positive rake. In both cases, the actual effective cutterwidth decreases, thus less cutter coverage. Limited benefits have been observed with siderake and thus most manufacturers use side rakes close to zero. As such, little attention isrequired to side rake when optimising the bit design to the drive type.

Centre of Bit Arrow = Normal to direction of travel

) Plan View – Negative Side Rake

Centre of Bit Arrow = Normal to direction of travel

B) Plan View – Positive Side Rake


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Durability And Aggressivity –

Roller Cone

1. Skew 5. Tooth Count

2. Profile 6. Tooth Shape

3. Journal Angle 7. Insert Shape

4. Tooth Length

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ROLLER CONE BITS

Skew

Under normal conditions, the centerline of the journal about which the cutter rotates,intersects the centerline of the bit. However, skew (or offset) can be added to the bit sothat this journal centerline is offset from the centerline by a specific angle. This results inthe cutter teeth sliding and dragging through the formation as the cone rotates, increasingthe gouging action of the bit. The downside is that with skew, the cutter does not roll trueand is thus less durable.

A bit with zero skew is symmetrical as illustrated below. It is suited to drilling hardformations via crushing with high weight. The cones run true and thus provide greaterdurability.

Medium skew is in the range of 2-3 degrees and is intended for medium hard formation,drilled using both crushing and gouging actions. The cones are less true rolling than zeroskew but remain relatively durable.

Low 0o Skew


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High skew angle bits (5 degrees) are intended for soft formations, which are effectivelyremoved via gouging to attain high penetration rates.

Medium 3o Skew

High 5o Skew


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ROLLER CONE BITS

Bit Profile

The profile of the cone has a major effect on the drilling action, with softer formation bitshaving a rounded cone profile for high penetration rates. Durability is enhanced byhaving a flatter profile and is thus used for hard formation bits, though at the expense ofROP.

a) Rounded b) Flat


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ROLLER CONE BITS

Journal Angle

The journal angle has two effects on the bit design: Cone size, and load capacity whilstdrilling. This angle is defined as the deviation of the centerline of the journal fromvertical, relative to horizontal.

In terms of cone size, the flatter the angle, the more space is available and thus largercutters (typical angle value is 33 degrees). Larger cutters have a more rounded profile (asdiscussed prior), which leads to increased gouging and scraping capability. The larger theangle (i.e. more towards vertical), the greater the axial load that can be sustained, thusgood for hard formation drilling (typical angle value of 36 degrees).


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ROLLER CONE BITS

A) MILLED TOOTH BITS

Tooth Length

Longer tooth length provides deep tooth penetration and greater gouging ability forhigher penetration rates, though are less durable. As such, long teeth are intended for softformations, with length decreasing, relative to increasing formation hardness. Hardformations are drilled more effectively with a chipping and crushing action, which isobtained by using multiple short, blunt teeth.


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ROLLER CONE BITS


Tooth Count

The quantity of teeth is inversely proportional to the tooth height: When tooth height ismaximized for soft formations, tooth count is minimized so that weight applied is shared by only a few cutters. This leads to deeper tooth penetration into low compressivestrength rocks. Additionally, water sensitive clays are often associated within these softformations and can pose a bit balling risk. The wide spacing between teeth will help to prevent this.

Inversely, as formation strength is harder and tooth size is reduced, the quantity of teeth

increase so that improved bit / borehole contact is made and higher weights can besustained in order to overcome the rock. The short tooth length in this scenario will aidresistance to break under these loads.


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ROLLER CONE BITS


Tooth Shape

The most common shape of milled tooth cutter is an ‘A’. If viewed from the side, itappears like a broad sweeping ‘A’ without the crosspiece. You may also find ‘T’ shapedcutters on some designs. This cutter shape basically adds more metal in the cut area andare thus used as a durability feature. These teeth would typically be found in the harderworking areas of the bit such as the gauge.

• ‘A’ – Widely used, Soft - Medium formations, high penetration rates

• ‘T’ – Durability, abrasive formations. May be used selectively at gauge

Type A Teeth Type T Teeth


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ROLLER CONE BITS

B) INSERT BITS

Insert Shape

The shape of the insert effects performance and will fall into three main categories. Eachrepresents a tradeoff between durability and potential penetration rates:

• Dome / Round top – Blunt and thus durable. Commonly short length. Hardformations. Shape minimizes insert breakage and thus able to withstand higherapplied weights.

• Conical – Aggressive for maximum ROP. Suited for wide range of formations, but optimal in soft for penetration rates. More durable than the chisel inserts with

increasing formation hardness.• Chisel – Particularly suited for medium-soft, and plastic formations. Minimizes

off-center bit rotation. Chisels provide effective penetration and gouging, thoughare susceptible to chipping and breakage if harder formations are encountered.

As with milled tooth bits, insert length is inversely proportional to durability: Increasedlength equals reduced durability.

Note: Be wary when comparing figures provided for Milled tooth length and Insertlength. The insert length includes the material that will be pressed into the cone in orderfor it to be retained. The measurement that should be used to compare to milled tooth

length is ‘insert protrusion’.


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Durability And Aggressivity –

Diamond

1. Differentiation and Application of Diamond Bits

2. Diamond Bit Profile

Impregnated Bits Natural Diamond Bits

a) Overview a) Diamond Qualityb) Blade Height b) Diamond Size

c) Diamond Grit c) Abrasion Resistanced) Matrix d) Impact Resistance

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Application and Differentiation of Impregnated, Natural

Diamond, and TSP bits

Introduction

Diamond bits fail rock by either ploughing or grinding the formation. They are quitecapable of performing in all formation types, though due to slow penetration rates inmedium and soft formations (when compared to PDC and roller cone bits), the use ofdiamond bits is generally within hard and very hard rock.

They are generally applied when the expected penetration rate will be similar or exceedthat of a roller cone. Due to the high purchase price compared to that of a roller cone, thediamond bit must be significantly durable and save multiple trips in order to beeconomical. As such, they are generally run at high depths or where rig cost (and thus triptime) is very expensive.

Applications

• High depths thus long trip times

• High trip costs

• Low roller cone penetration rates (>20 ft/hr)

• High cost per foot (>$35-40)

• Hazardous trip conditions

• Mud issues arising from tripping

• High mud weights

• High on-bottom rotation time is required

• Limited weight on bit available• Turbine / high speed motor applications

• Difficulty in maintaining gauge

• Overbalanced drilling conditions

• High rig costs

• Plastic formations

Diamond / TSP v Impreg

All are matrix bodied designs. A natural diamond bit comprises of a number of diamonds

surface set in a single layer on the matrix body with a specific degree of exposure. Thiscompares to an impregnated design, which has a multitude of layers of diamond grit within the matrix. A TSP bit (Thermally Stable Polycrystalline) is the same as thediamond bit in that the components are surface set in a single layer. Instead of usingnatural diamonds, it uses TSP diamonds of varying geometries.


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The key benefit of the impreg bit is that you are continually replenishing the cuttingstructure, whereas the high exposure cutters on the diamond bit will deliver good penetration rates when new. These top views clearly demonstrate this variation.

a) Surface Set b) Impregnated

Impregnated bits are currently the most commonly used diamond design in the industrytoday.

Bit Manufacturer Variations

Hycalog : The impreg product range from Hycalog is called ‘DuraDiamond’. Thenomenclature uses three numbers, which represent the type of cutting structure (impreg,impreg & TSP, Bicentrix, Transformation), Formation hardness, and number of junkslots.

There are three diverse designs: Impregnated Bicentre bit, Drill-out design (as mentioned previous using TSP) and Transformation. A transformation-impregnated bit was createdto have a variable formation cutting structure, which is capable of higher penetration ratesin softer formations. This is accomplished by staggering the heights of the ribs so thatonly a certain number initially engage. When worn down, more blades engage, making aheavier set design.

Hughes Christensen: Diamond bits have a prefix of ‘D’, Impreg bitsuses the prefix ‘S’. There is also a specific unique range of Impreg bitsknown as ‘Hedgehog’. This uses an interrupted structure to form postsalong the face. This provides higher flow area and aggressive cuttingstructure for drilling shales, whilst extended diamond volumeimproves bit durability in the harder formations. Hydraulics have also been enhanced with the addition of ports in the cone of the bit torelieve balling and maximize hydraulic energy.

Hedgehog bits are prefixed with ‘HH’. The bit nomenclature relates tothree digits; Matrix type, Cone cutting structure (PDC, ridge set,Radial set), and Blade count (last digit).


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Security DBS: Impregnated bits fall under the range name of ‘TI’ followed by fournumbers to distinguish the actual variant. They commonly use a cone set with a few PDCcutters. The diamond bit range has the ‘LX’ prefix.

DBS also has a product range known as the ‘SE3000i Series’. This uses a combination ofPDC with impreg backup.

Smith: The key impreg product range of Smith is called ‘X-Tend’. It comprises of bitsthat are classed as either XTG, XTS, XTN, though there is little literature available on theweb to differentiate the difference between them. They also have a Bicentre impreg product.

A standard impreg and natural diamond range also exists. These have the prefixes of ‘K’and ‘D’ respectively.


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IMPREG / NATURAL DIAMOND BITS

Profile

There are two general profiles utilised for diamond bits: The ‘C’ profile, which has asmall nose radius and long taper, and the ‘R’ profile which has a short taper and thuslarger nose radius.

a) C Profile b) R Profile

The ‘C’ profile is most common as it provides superior rates of penetration withreasonable stabilization. The ‘R’ profile tends to be used in very hard formations as thehigher applied weights are applied more evenly over the nose cutting structure.Additionally, due to the shorter length of the profile, a modification of the ‘R’ will beused for hard rock sidetracks. Profile variations from the C & R will compromise between the penetration rate and durability, depending on the application. The blade

profile is generally flat, though may also appear ribbed, which is known as ‘ridge set’.


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A) IMPREGNATED DESIGNS

Similar to matrix bodied PDC bits, the diamond bit is created by making a mould inwhich the diamonds are selectively placed. The mould is then infilled with tungstencarbide powder and alloy, then furnaced.

With an impregnated design, diamond grit is multiply stacked within the matrix rib

(blade) of the bit. Due to the softer nature of the matrix, this wears at a greater rate thanthe diamonds, so as the bit wears, new, sharp diamonds become available to continuedrilling efficiently.


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Blade Height

Blades on diamond bits are commonly referred to as ribs. They are of less width andheight than that of PDC bits and thus greater in number. The height of the rib controls theamount of impregnated material and thus the durability of the bit, as once impregmaterial is worn away, the replenishment of the cutting structure will stop.

The width determines the dimensions of the waterways. It is usual for some of the bladesnot to extend to gauge. This creates an extended ‘junkslot’ of which there may be two or

three around the outer diameter of the bit.


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Diamond Grit

The diamond grit is considerably smaller than the diamond stones used in a naturaldiamond bit, generally falling into the range of 10 to 25 stones per carat. There are twoforms used;

• Natural: Larger sizes, good impact resistance, irregular shapes (angular to subrounded)

• Synthetic: Limited sizes (can be too small), but good sharp cutting corners andedges. Benefits from consistent shape though are more expensive

In addition to the diamond grit, it is common to see the use of TSP’s also placed withinthe matrix rib. These may be of various shapes including triangles, cylinders, cones androds, and are much larger than the grit; Cylinders up to 1 carat and cones and rodsmeasuring 10mm in length are common. They are used in the face of the bit to fine-tunethe wear areas. The picture below depicts the use and exposure of both grit and TSP’s ona worn impreg bit.

A specific manufacturer (Hycalog) has experimented with TSP discs that areconsiderably exposed by several millimetres out of the body to act similar to a PDCcutter. This is done with the intention of increased exposure to drill out shoe / floatequipment, or to increase penetration rates in soft formations overlying the hard diamondapplication below. Once the hard formation is encountered, the discs wear down and theimpreg ribs contact formation and thus drills as a conventional impreg design. Successfuldrill out tests were completed and commercial product is available.


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Matrix

The abrasive properties of the matrix binder are as important as the quality of thediamond grit used and must also be matched to the application. If too soft, the matrix willabrade easily and release diamonds before they have effectively dulled (poor durability).If too hard, the diamonds will excessively dull without release and thus lower penetrationrates.


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B) NATURAL DIAMOND BITS

Diamond Quality Classification

The three key crystal structures of diamonds used for industrial purposes are cube (6square sides), Octahedron (8 triangular sides), and dodecahedron (12 rhomb sides).The crystal shape and quality of the diamond significantly affects the application anddrilling performance. There are seven primary grades of stones.

Magnifique or West African: High quality, angular monocrystalline diamond. It is anexcellent drilling stone with few flaws or inclusions. Unfortunately, due to this, it hasgem potential and is also highly sought after for other industrial uses, thus high price. It

has the highest abrasion resistance and good shock properties.

Superior: Basically, this is a rounded or worn West African stone, so again, is highquality with few flaws, However, due to its roundness, it lacks the aggressivity of theWest African stone.

Premium: Monocrystalline, round diamond, which has had the soft outer layermechanically, removed. This gives good abrasion and shock resistant qualities.

Cube: Cubic (monocrystalline) diamonds provide both low abrasion and shockresistance. Can perform well in non-abrasive plastic shales and evapourites. Used

selectively.

Octahedron: Eight sided monocrystalline diamond with reasonable wear resistance andis thus suitable for a wide range of applications. Performs well in softer formations.

Carbonado: This is a polycrystalline form, composed of multiple diamond crystals. It isfairly scarce and thus high price, but possesses the highest resistance to impact, thoughlow abrasion resistance.

Gage: This grade consists of broken or flawed diamonds. They are selectively placed inlow exposure areas of the bit (such as the gauge) where they can provide abrasion

resistance without the durability required for actual cutting.


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Diamond Size

Diamond size is application specific. The harder the formation, the smaller the stonerequired. Thus for soft diamond formations (>10 ft/hr) you may require up to 1 ½ caratdiamonds, whereas hard formations (


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Abrasion Resistance

Varies with grade of stone. In order of resistance to wear (highest first), they are:

1. West African2. Superior3. Premium4. Octahedron5. Cube6. Carbonado


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Impact Resistance

As per abrasion resistance, it varies with grade. In order of resistance to impact (highestfirst), they are:

1. Carbonado2. Premium3. West African4. Superior5. Octahedron

6. Cube


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Durability Aspects

Aside from those factors listed in the prior section, which are generally a compromise between aggressivity and durability of the bit, there are several elements of the designthat are purely considerations for durability alone. These are as follows.

PDC Bits Roller Cone Natural Diamond Bits

a) Body Material a) Metallurgy a) Cone Wear

b) Gauge b) Diamonds b) Gauge

c) Backreamers c) Shirttaild) Hardfacing

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Durability Factors

PDC BITS

Body Material & Hardfacing

There are two types of body material used for PDC bit manufacture:

1. Tungsten carbide matrix (referred to as ‘Matrix’)2. Steel

In very basic terms, the steel bodied PDC bit is turned, milled, and drilled out of a forged piece of steel. The matrix bodied design is created by infilling a pressed or cast mouldingof the bit with matrix powder and alloy and furnacing to form a solid body.

The steel bodied design possesses higher mechanical strength and thus can be used to

give higher blade standoff and reduced blade width to optimise both junk slot volume andarea for effective cleaning of the bit, particularly useful for drilling clays / shales withWBM. It is also cheaper and relatively easy to modify as there is no requirement toupdate or create a new pattern as with a matrix bodied design.

The primary downside of the steel bodied design is that it is potentially subject to erosionand abrasive wear. This usually occurs around the cutter pockets, and if severe, can leadto lost cutters. It is common practice now to apply a layer of erosion resistant hardfacingto the blades, the extent and grade of which, is dependant on the individual bitmanufacturer.

The matrix bodied design has excellent surface properties with an exceptional ability toresist fluid erosion, however, the mechanical properties are weaker than that of steel andthus the blades are generally lower and wider, with resultant lower junk slot area andvolume.

As a general rule, you will observe that steel bodied designs are generally light set, openfaced bits for drilling soft formations at high penetration rates. The matrix bodied bits aregenerally heavier set and are used to drill for longer hours and in abrasive / erosiveenvironments. However, the diversity of applications, bit manufacturers ranges, andoperator preferences, all combine to make the rule above very general indeed.


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Durability Factors

PDC BITS

Gauge Protection

The protection used at gauge differs for the two body types. Steel bodied bits typicallyrely on inserts, which are pressed into drilled holes in the gauge pads. The inserts may beany combination of TSP, tungsten carbide, diamond, or PDC. In addition, there will also be coverage of gauge PDC cutters / trimmers.

Matrix bodied bits are dominated by surface set diamonds or TSP (thermally stable polycrystalline) tiles of various sizes and shapes. These are placed in the pattern prior toinfill and are thus embedded in the matrix body after furnacing. It is also possible to haveinserts (as for steel body designs) placed in the pads, though these would be brazedinstead of pressed due to the reduced size tolerance of matrix to generate the interference

fit required. Pre flatted gauge trimmers would also be used.

The key importance of gauge cutters is to maintain gauge diameter, thus avoidingundersize hole, high torque, and the potential need to ream. Selection of gauge protectionshould be based on prior offset dulls and knowledge of the formation abrasiveness.


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Durability Factors

PDC BITS

Backreaming Cutters

This is a common option from most bit suppliers, also known as upreamers. Basically,PDC cutters are positioned along the back angle of the gauge pad with exposure on the pin side of the bit. Thus if encountering material when pulling out of hole, the bit hascutting elements which can aid removal when backreaming.


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Durability Factors

ROLLER CONE BITS

Insert Metallurgy

The metallurgical content of the tungsten carbide insert components will vary dependingon the application. Hard formation inserts are durable in terms of both shape and lengththus the key material factor is to be resistant to abrasion, thus a low cobalt percentage andsmall grain size is used. The reverse is seen for soft formation bits where a high percentof cobalt is used with larger grain size to provide mechanical strength as the inserts arerelatively long and run at high speeds.


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Durability Factors

ROLLER CONE BITS

Diamond Protection

Diamond inserts and tungsten carbide protection can be utilized in varied locations on the bit design in order primarily to protect gauge which is prone to high wear:

• Heel row – Abrasive formations. Use tungsten carbide inserts which may also bediamond coated. Reduced insert length for durability.

• Gauge – Use where prior offset dulls have shown gauge wear / damage to be thelimiting factor in bit life. Ideal in soft to medium formations where high abrasivityis encountered. Various gauge trimmers are available from different bit suppliers.They supplement the action of the gauge inserts but additionally cut formation aswell.

• Inner row / Nose – Some or all of the standard tungsten carbide inserts on the bit

design may be replaced with diamond coated inserts for greater durability in theface as well as gauge. Application dependant.


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Durability Factors

ROLLER CONE BITS

Shirttail Protection

A number of features can be applied to the shirttail to reduce wear to this component.Shirttail wear may lead to exposed seals and premature bearing failure.

1) Application of hard metal on the top leading edge for abrasion resistance.

2) Pressed inserts into the actual shirttail itself. These may be a combination of bothtungsten carbide and diamond coated inserts. Inserts not only add extra wear resistance but will also improve bit stabilization. Use of shirttail inserts is particularly good fordirectional / horizontal / abrasive formation applications.

3) Lug Pads. Used to reduce gauge breakage and bearing damage by absorbing impact between bit and bore. Particularly useful in applications where you expect wash out or ifdrilling on bent housing and thus eccentric hole. Lugs pads also help to minimize shirttailwear and prolong seal life.

Stabilization

Protection

Lug Pad


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Durability Factors

ROLLER CONE BITS

Hardfacing

Application of abrasion resistant material to the actual steel teeth in order to extend thedurability of the teeth. This is packaged by the bit manufacturers in terms of bothcoverage and grade of applied material. For example, hardfacing may be applied on oneside only in order to obtain a ‘self-sharpening’ wear effect. Two sides may be coated inorder to maintain maximum tool height, though commonly full coverage is used.

The importance of hardfacing has developed due to the increased technology (and thuslife) of the bearings, resulting in the bits staying downhole longer and requiring moreabrasion resistance.


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Durability Factors


Cone Wear

One of the most common failure modes of diamond bits is to ringout, or core, in the conearea. This is due to the fact that the hydraulics waterways converge in the cone thuscreating areas of low diamond coverage. In order to avoid this, look for designs that havewaterways that converge into the cone at different radii – Basically an asymmetricwaterway design that does not concentrate areas of no diamonds into one zone.


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Durability Factors


Gauge Protection

It is usual to supply these bits mounted on turbine sleeves, which are commonly a steelsleeve mounted onto the bit with various diamond / tungsten carbide inserts for gauge protection (similar to that for steel bodied PDC bits). Gauge protection is very importantin these applications due to the hard and abrasive nature of the formation, and the highrotational speeds required to drill efficiently.


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Roller Cone Bearings

There are two key type of bearing: Roller and Journal (also known as Friction), of whichthe roller bearing may be sealed or unsealed (Journal bearings are always sealed). Inaddition, you may also come across air-cooled roller bearings.

• Sealed Roller – The cutter encapsulates a series of roller bearings and it is throughthese that the load placed on the cutting structure is transmitted through to the journal. There can be up to three roller races, depending on the bit size. Thesealed roller bearing is lubricated by grease providing high bearing life and is thusgood for high-speed applications (motor / directional).

• Unsealed Roller – As per above except that drilling fluid lubricates the rollersthus is open to contamination and subjected to abrasive wear from mud solids.This leads to lower bearing life. Generally used in large diameter bits for shallowhole drilling.

• Journal – Instead of employing roller bearings, the friction bearing is based on theload passing through the cutting structure directly onto the journal over a large,low friction, surface area. There is usually a floating bushing placed between thecutting structure and journal as illustrated below. A journal bearing usually seesminimal wear unless seal failure occurs and lubrication is lost. As such, journal bearing wear is mainly related to seal life, which can be affected by temperature,mud chemicals, and mechanical damage.

Cyclic loading will occur on a roller bearing every time a roller passes over a specific point, leading to fatigue. In contrast, the friction bearing journal sees a more continuouseven load and is capable of handling relatively high rotational speeds without sufferingfrom damaging high temperatures. As such, the general rule is that bits 12 ¼” employ roller bearings. 12 ½” is thecrossover size between the two.

a) Sealed Roller Bearing b) Sealed Journal Bearing

Rollers Journal


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PDC Cutter Technology

NPI

One of the primary revolutions within PDC cutter technology in the recent years is the

development of non-planar interface (NPI) cutters and the rapid variation of NPIgeometries by the bit manufacturers.

The interface between the polycrystalline diamond and the tungsten carbide substrate isone of high stress due to the fact that in order to form the diamond layer, both aresubjected to 1400 oC. The tungsten carbide will shrink more than the diamond on cooling,as it has a lower expansion coefficient and will thus set up a regime in which the tungstencarbide support is in tension whereas the diamond is in compression at the interface.Thus, in a planar interface, this stress is dissipated over a very narrow band.

Planar Cutter

An NPI cutter basically has an irregular interface, where numerous ridges or circles existin the tungsten carbide substrate, so that when adhered, the diamond has a non-planar

interface with the substrate and a large surface area contact. This results in the stress being dissipated across a wider area at the interface, reducing peak stress, and allowinghigher loads to be applied prior to failure. This provides improved impact resistance.

NPI Substrate: a) Side View b) Face View

An integral part of the NPI cutter is a recessed rim around the cutter diameter that provides further load support, particularly with the residual stresses around the edge. Italso further increases surface area and aids dissipation of heat away from the cutting tip.

The design and geometry of both the ridges and circles that define the interface, and therim, are the key aspects relating to the marketing of cutters by the manufacturers.


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Smith: The premium cutter offering from Smith is grouped as the GeoMax range. Thisincludes SonicMax (NPI consisting of multiple circular rings of varying amplitude),GridMax (rippled grid interface with sloped rim), and TecMax (consists of both a primary and secondary diamond table).

Security DBS: The latest cutter technology from DBS falls under the ‘Elite Series’. DBS prior offerings have included grooved interface geometries with thick diamond edgessuch as Ring Claw and Deep Ring Claw. The Elite Series designates that these thickdiamond table designs have been improved via a new process methodology to offergreater impact resistance.

Reed-Hycalog: The ‘standard’ NPI design utilized by Hycalog is the Iris geometry. Theirrange of products, though, also include Star, Nodule, and fan geometries.

a) Iris b) Fan

c) Star d) Nodule


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Hughes Christensen: The latest cutter technology from Hughes is grouped into a familycalled the ‘Genesis Cutters’. These have been marketed as either applicable for abrasiveapplications (‘A’ prefix) or fracture orientated applications (‘D’ prefix). The currentoffering includes:

• A1 – AXSYM

• A2 – Manhattan

• A3 – Alba

• D2 – BXD

• D3 – Niagara

• D4 - Modesto

Abrasion & Impact Resistance

These two properties of the PDC are a primary function of grain size of the diamond;Large grain sizes give good mechanical locking and are thus more resistant to impact.Smaller grain sizes improve abrasion resistance, as there is higher surface area to wearagainst the formation. The selection of grain size is an intermediate between the two.

The goal has been to continually develop cutter technology so that both impact resistance

and abrasive resistance can be maximized without detriment to the other. Multimodaldiamond selection, where grains of various sizes are used, led to improved abrasionresistance, whereas NPI substrates provided greater impact resistance due to itsinterlocking nature. However, recently a technological breakthrough has led to thedevelopment of a cutter that uses a thin layer of ultra resistant diamond at the cuttingedge of a multimodal NPI cutter to radically improve abrasion resistance without anycompromise to impact.


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This was developed by Reed-Hycalog and commercially released as the TReX cuter. Numerous offsets have proven that this cutter is extremely successful in enduring longersections but also providing higher penetration rates, as the cutter remains sharp forlonger.

Side View - TReX Cutter

Diamond Thickness

The general rule is that the thicker the diamond table, the lower the impact resistance,resultant from the sintering process. Normally the cobalt used to sinter the diamond isdrawn from the tungsten carbide substrate. With a thicker diamond layer, more cobalt isdrawn and the cobalt concentration at the interface is reduced making it brittle and weakunder tensile loads.

Two methods can be followed in order to reduce this effect: One is to add cobalt directlyto the diamond grit; the second is to use coarser diamond grit that requires less cobalt.Unfortunately, both methods result in significantly reduced abrasion resistance.

The issues with thick diamond tables may be overcome using a suitably designed rim,which will provide thick diamond at the cutting edge and increased strength, particularlywhen formulated with the interlocking strength of a non-planar interface. Problems mayarise though in manufacturing such geometries due to cracking of the diamond or carbideand thus great importance is placed on the manufacturing process in place.

Cutter Shape

The vast majority of cutters are cylindrical in shape. However, there are two other shapesthat are relatively common in the oilfield; Oval and pointed.

Oval cutters are actively promoted by one specific bit manufacturer (BBL). From theirgeometry it can be observed that there are two key differences between oval and cylindercutter wear. The first is that a smaller horizontal wear flat will be generated (less PDCcontact with formation and less friction / heat), the second being that there is a greater

PDC

NPI Substrate

Ultra abrasionresistant layer


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vertical quantity of diamond volume. However, due to this greater vertical component,you may have some cutter placement constraints on tight profiles resulting in less PDCcoverage. It is also claimed by BBL that the use of oval cutters will provide optimum point loading for high depths of cut and thus ROP.

Oval Cutters

Pointed cutters are basically cylindrical in shape with the cutting edge shaped to form a point. Their primary application is for hard chalk / limestone formations where a pointload is applied in order to fracture the formation as opposed to a shear failure mechanism

normally associated with cylindrical cutters.

Pointed Cutters

Several bit manufacturers have used these cutters, notable Smith (Arrow cutter), DBS,and Hycalog (Scribe cutter). The bit designs may use a mixture of both cylindrical and points in order to obtain both fracture and shear. The downside of the pointed cutter isthat it is formation specific (not good for heterogeneous) and may dull the point rapidlyunder high weights.

Miscellaneous geometry

Several other cutter or substrate geometries exist which may be encountered. Some ofthese include:

• Modified Substrates: This is where the actual substrate has had a relief groove cutinto it on the cutting edge side. The idea is to enhance depth of cut and reducesubstrate / formation interaction when the PDC starts to generate a wear flat. BothSmith (Quick cutter) and Hycalog (Hibernia substrate) promote this substrategeometry in varied cutter diameter sizes.

Chamfered Substrate


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• Chamfered Cutters: Conventionally the angle between the front face of the PDCand the circumference of the carbide support is 90 degrees. This angle ischamfered in order to improve the carbide support of the diamond cutting edge soas to reduce incidence of PDC breakage that is often resulting from hardformation drilling. One such product is the Tuffedge cutter from Hycalog.

Tuff Edge Cutter


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Formation Factors

Determining the formations to be drilled is the critical step in bit selection. Once anunderstanding is reached as to what type and density of cutting structure is required toactually remove the rock, then considerations can take place for other aspects such asstability, steerability, matching aspects to drive types, etc. The primary purpose though, isto select the appropriate drill bit that has sufficient durability to remove formation at areasonable penetration rate.

1. Rock Classification 4. Roller Cone IADC

2. Bit Selection Properties 5. Fixed Cutter Selection

3. Roller Cone Selection 6. Problematic Formations

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Formation Factors

Rock Classification

a) Argillaceous rocks

• Claystone – flat, microscopic clay particles that form a loose and disorderedassembly. Soft, sticky, and water absorbent. Certain clay minerals are reactivewith water and cause swelling

• Shale – Claystone that has become compacted. The clay particles become orderedand lie horizontal. As above, particular clay minerals are reactive to water causingswelling shales

• Siltstone – This is an intermediate between sandstone and claystone / shale, and isclassified basically on grain size alone. Similar properties to sandstone though thegrains are less than 1/16mm in size.

• Marl – Semi consolidated clay or siltstone. In some regions it is a calcareousclaystone. Relatively soft to drill

b) Arenaceous

• Sandstone – Consolidated sand size particles (2mm – 1/16mm) that are cementedusually with silica or calcareous cement. The particles are generally quartz butmay also consist of feldspar, mica, and glauconite as it is derived from igneousrocks. The properties of the sandstone are dependent on particle size, sorting,shape, and strength of the cement. This means that sandstones can be very diversein nature in terms of drillability. They can also be very abrasive due to the highquantity of quartz. The hardness is usually dependant on the cement. Note thatunconsolidated sandstone is basically loose quartz grains and known as sand(generally easy to drill)

• Conglomerate – These consist of coarse material in a soft clay / silt matrix.Usually present in top-hole sections, where the coarse material can be bouldersize. This is problematic for PDC drill bits as the boulders may ‘rattle’ betweenthe blades causing heavy cutter breakage. Roller cones are best suited to theseformations due to their crushing action, though there is still the risk that loose boulders may lodge between the cones and lock them.

c) Carbonates

• Limestone – Formed by calcium carbonate deposits and may also contain shellfragments. The hardness of the rock will vary and depend on the quantity of othersedimentary rocks (clay / sand) and the cementation

• Dolomite – As above but is formed from magnesium carbonate instead of calcium


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d) Evaporites

• Salt – Formed by the evaporation of seawater to leave behind the salt minerals.Due to the relatively soft and light nature of the salt, overlying sedimentdeposition usually deforms the salt beds to bulge towards the surface, forming

what is know as a salt dome or diapir• Anhydrite – This is resultant from the deposition of calcium sulphate. It is

usually present in massive form, though may be crystalline. Similar to limestonein drillability

• Gypsum – A hydrated variant of Anhydrite, thus softer to drill

(Note: Ensure that the local formation name reflects the actual lithology. For example some shales such as the ‘Laffan Shale’ and the ‘Wolfcamp Shale’ are in fact carbonate

rocks. This also occurs with some ‘Sandstone’ groups. Confirm on the mud logs or with

the geologist the actual lithology instead of the actual local name for the formation.)


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Formation Factors

Bit Selection Properties

Following determination of the lithologies to be drilled, an assessment of the formation

characteristics must be performed. This can be carried out by a number of models, thoughat base level, the best approach is analysis of offset records for dull conditions (seesection on dull grading interpretation) and drilling reports.

The six primary characteristics for bit selection are:

1) Stickiness – Formations that are sensitive to water become sticky and pose ballingissues. Consideration should be placed on maximising HSI and JIF of the bit andselecting designs with large face volume and open cutting structures.

2) Elasticity – Elastic formation have a tendency to deform rather than fail. As such,elastic formations should be drilled with large cutting elements with high depth of

cut e.g. long milled teeth or 19mm PDC bits.3) Porosity – Rocks with high porosity will fail easily. You can determine porosity

by using sonic data. Values lower than 60 ms/ft indicate a tight rock that willrequire either impreg or heavy set inserts bits to drill.

4) Pressure – Differential pressure is the difference between the hydrostatic pressurein the annulus and the formation pressure. The general scenario is that thehydrostatic will be greater than the pressure in the formation. This has a negativeeffect on potential penetration rates, with the higher the difference resulting inlower ROP. This is because it adds to the confining force and thus compressivestrength is greater. It also holds down rock chips generated by the cutting actionof roller cone bits, thus slowing rock removal.

5) Abrasiveness – Generally sand formations. Bit considerations should relate toenhanced cutting structure (abrasion resistance cutters or hardfacing), body protection, and extra gauge protection, particularly in directional wells.

6) Compressive strength – This is a measure of the force per unit area that aformation can withstand before it fails in compression, thus the lower the value,the easier it is to drill. Compressive strength is measured in psi. Values varyconsiderably depending on formation type and as such are commonly used forclassifying formation strength. This in turn is often used for evaluating bitrequirements. The list below provides approximate compressive strength values.

• Very Soft – Formation strengths less than 4,000 psi. High drillability.

Typical lithologies include clay, soft shales, marl, gumbo (sticky) clays,and unconsolidated sand, or poorly cemented, sands

• Soft – Formation strengths in the range of 4-8,000 psi. Dominated by themajority of shales and claystones. Other formations include softevapourites (such as salt) and soft siltstones


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• Soft to Medium – Formation strengths in the range of 8-12,000 psi.Formations include sof