Bit_selection_guidelines[1].pdf

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Bit Selection Guidelines

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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 an independent document, aimed specifically to provide DE / DD / PERFORM Engineers within Schlumberger an unbiased guide for what bit design and characteristics should be required to match bit to both drive type and geology for optimal BHA performance. This will aid the engineer in making technically justified bit recommendations and knowledge of 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 be used 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

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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

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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 be asked which offset wells they consider to be the most relevant - Maximum information must be gathered for these. The following is a list of the ideal dataset required. •

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Bit records. These form a straightforward record of run performance, though vary in consistency, as different Operators will record varied information on their bit records. 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 run description comments, which can be very insightful and useful. Operator daily drilling/operations summary reports. These consist of extremely useful information including bit, BHA and mud details. The daily operations are also recorded with specific drilling comments that highlight drilling problems, practices and performance. Drilling service company summary reports and directional drilling post well reports. These will frequently include comments on performance, problem identification and recommendations. Ensure all previous End of Well Reports (EOWRs), Lessons Learnt and Recommendations are collected as there may be action items that have been agreed with the client that need to be considered. Daily Mud Reports from the mud company. These provide good information on the 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 operational conclusions. Useful surface and down hole parameter data includes: o Weight on bit, (DWOB) o Torque, (DTOR) o Rotary Speed o Flow Rate Down hole vibration data in digital format. This illustrates the down hole vibrations experienced and can be correlated to events (e.g. formation, drilling parameters, etc) throughout the section to help draw accurate bit/BHA/drill string dynamic conclusions. Formation data for evaluation. Use of software such as Terrascope and that from DCS, requires specific information in digital format to be run effectively. The table overleaf illustrates the optimum and minimum dataset required. A rock

strength analysis calculated using only the minimum dataset is of limited value. It will generally provide good comparative data of the rock strength between each formation 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 calculate rock strength. •

Log

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Mud Log Gamma Ray Compressive Sonic Shear Sonic Neutron Density Neutron Porosity

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Optimum Dataset • X • X • X

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Minimum Dataset • X • X • X

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Abbreviations

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Units

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GAPI DT, DTCO

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API µs/ft

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X X

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DTSM RHOB, RHOZ

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µs/ft

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gm/cm3

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X

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NPHI, DPHZ

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Seismic cross sections and SLB MEMs (Mechanical Earth Models) can help visualize formation characteristics including faults, folds, bedding angles, etc that may cause drilling problems.

QA/QC Offset Data The potential data set for analysis will vary greatly depending on the operator and geographical 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 to ensure that it is accurate. This is critical, as benchmarks, key performance indicators, and the bit selection will be set using this data.

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Data Analysis Process 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, the required 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

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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2) Well design, to include • Casing program • Shoe / Plugs / Float equipment • Well trajectory / Profile • Survey design

Data Analysis Process 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 via the selection flowchart. • • • • • •

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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 include o Rock strength o Abrasiveness o Elasticity o Pore Pressure o Rock types and frequency of interbedding o Presence of non PDC drillable lithologies / minerals o 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

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 deliver these 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. The equation below takes into account these additional factors: C = R (T + D) + B F Where:

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 drilling system 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 similar application in order to obtain anticipated drilling times and average bit life. If evaluating considerably different bit designs than previously run, estimated life and potential penetration rates must be evaluated using all available resources including the clients engineering 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 have revealed any historical or potential inconsistencies in drilling performance relating to external factors. For example, chert beds may have appeared on two out of ten offset wells resulting in heavy PDC bit damage and the requirement to pull out and run back in

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C = Overall Drilling cost per foot R = Hourly rig cost T = Trip time (hrs) D = Drilling time (hrs) B = Cost of bit F = Interval drilled (ft)

hole with an alternative design, whereas the other eight wells were all drilled with one run. This risk should be built into the economic evaluation so that best and worst case costs 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 failure Ps = Probability of success S = Cost of success Pf = Probability of failure F = Cost of failure I = 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 risks with each of your derived bit options from the selection process. This can then be evaluated and presented to the client as a proposal. Schlumberger Private

Post Run Data Collection All relevant data should be collected as soon as possible for two reasons. Firstly, the sooner the data is received the sooner decisions or reports can be presented to the customer; 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 the run performance:

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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) includingo Weight on bit o Surface torque o Surface rotary speed o Flow rate Down hole vibration data includingo Axial vibration o Lateral vibration o Torsional vibration o Shock, i.e.: impact, magnitude and count Formation evaluation data includingo Gamma ray o Compressive sonic o Shear sonic o Neutron density o Neutron porosity o Caliper log o Mud log

It is important to QA/QC all data collected to ensure that the true facts are represented e.g. preliminary checks will ensure that the data recorded is of a reasonable magnitude and 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 grading system (SPE 23939). The schematic below has been extracted from that document and displays 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 dull grading 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 0 through to 8, with 0 representing unworn cutters, 4 relating to 50% wear, and 8 equalling complete wear of the cutter. Box one relates to the cutter wear of the inner teeth, thus the inner rows on a roller cone design. 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 as the gauge row (and heel) of roller cone bits, and the shoulder and gauge of fixed cutter designs. Note that it is common on PDC bits to use preflatted cutters at gauge (usually the very last cutter on each blade) and this should not be confused with downhole wear.

Box 3 – Dull characteristic This is an assessment of the major dull characteristic shared by the majority of the cutting 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 at the rear of this section. Box 4 – Location This is the primary location of the major dull characteristic noted above. On fixed cutter designs, 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 of Middle row (M) and Heel row (H). For both bit types you can also use ‘A’ to represent that the dull condition is evident in all areas.

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

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 a visual assessment. With sealed bearings, it is assumed that if the seals are effective that the bearings have not failed. As such, you simply use ‘E’ for seals effective, or ‘F’ for failed seals. With non-sealed bearing designs (usually large diameter top-hole bits) you visually assess (and shake the cones) the life of the bearing and use a sequential numeric scale 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

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 be recorded as the radial distance undergauge. Box 7 – Other characteristics This box is used to include any other dull characteristics evident on the bit secondary to what 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 comprehensive list has been provided on the IADC table. Note that some operators do use a variation of these codes specific to that company (bp in particular).

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

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 at high speed while tripping. It may relate to a materials or manufacturing process issue with the bit, though is unlikely. BF = Bond Failure (PDC only) This is the complete separation of the PDC and upper substrate layer from the substrate post or stud that is embedded in the blade. This is an unusual condition and if it occurs, it would usually only be seen on one or two cutters. A move towards single piece and shorter substrates has also helped to eliminate this dull condition.

This is where a large portion of the cutter, insert, or tooth has broken away. This can be resultant from a number of issues including formation strength, vibration, excessive parameters, inappropriate cutting structure, etc.

BU = Balled up (All) This is when the cutting structure is immobilised due to being coated in formation (usually sticky, water sensitive clays) and thus is unable to drill efficiently. It is resultant from a combination of factors such as inappropriate mud selection for formation, poor HSI at the bit, low junk slot area / volume, etc. It may be ‘unballed’ downhole by a number of means such as picking off and 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 as such, is resultant from the same causes.

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

CD = Cone Dragged (Roller cone only) This occurs when the cones of the bit get locked, either by balling or mechanical locking (formation nodule, junk). Without rotation, the cones 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, with grooves cut into the cone shell. It occurs after a bearing failure, which allows one or more of the cones to move free along its axis thus colliding into the adjacent cones. CR = Cored (All)

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 two codes. Chipped teeth are resultant from the same causes as per that for 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 is on the body around cutter pockets and the substrate of the cutters (PDC) or teeth (Roller cone). If severe, it may result in broken or lost cutters due to reduced support.

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

HC = Heat Checking (All) Cracking and subsequent breakage of tungsten carbide can occur when subjected to high temperatures. The heat may be generated as a result of high RPM, hard and abrasive formations, 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 or formation junk (e.g. pyrite / chert with PDC bits). Damage can range from chipped cutters to severe cutter breakage and broken blades. However, this kind of damage can also 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)

LN = Lost Nozzle (PDC / Roller cone) Loss of the nozzle jet or nozzle retainer. This usually results in cutter breakage if the nozzle component can not be circulated up the annulus quickly. A lost nozzle can be resultant 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 clean empty pocket. General cause of lost teeth is either severe erosion of the pocket, extreme cyclic loading (stick-slip), or poor manufacturing process (braze / hole sizing).

NR = Not Rerunnable (All) Not an acceptable dull condition as it reveals no information on the failure mode of the drill bit. Do not use.

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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 the drilling characteristics of the bit (Torque, ROP).

OC = Off Centre Wear (All) Irregular wear or erosion of the cone shell or bit body. This may occur when the drill bit is run on a directional assembly with a bend so that the bit drills an oversize hole in rotary mode. In hard formations, ridges may develop in the formation that 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 is resultant 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, or rubber from either a failed downhole tool or surface mud pumps. You may have some associated balling or unnatural wear due to inefficient cooling.

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 the cones, 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 will extend down through the cutting structure and through the blades / cones. It is relatively common on PDC bits either on the shoulder or nose. It can relate to either a weakness in the cutting structure 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 code should 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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RG = Rounded gauge (Roller cone)

SD = Shirttail Damage (Roller cone only) Damage or erosion of the shirttail or associated protection components within. This is generally related to either wear from the formation or junk damage, the former usually occurring 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 only light hard metal is applied to the teeth, resulting in continuous erosion of the tooth which thus maintains a sharp cutting edge. TR = Tracking (Roller cone only) This can be identified by symmetrical wear of the cutters. It is resultant from disruption of 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 cog wheels, and thus a secondary condition are indentations in the cone shells caused by the cutters on the adjacent cones.

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 is indicative 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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WO = Wash out (All)

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Durability And Aggressivity

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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 by common design factors i.e. you lower one aspect to improve durability and you usually see a decrease in aggressiveness, and vice versa. This section details the key bit characteristics that need to be balanced during selection to attain both the durability to drill 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

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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 of a PDC bit, however, it is one of the least disclosed from the bit suppliers. As such, the industry tends to refer variation of PDC aggressiveness in terms of blade count and cutter size. This misconception could lead to a directional driller running a design that appears unaggressive when in fact, due to low backrake angles, is aggressive and resultant torque is 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 being drilled as illustrated below. As the cutter face angle moves towards being perpendicular to the formation, back rake angle increases.

Formation

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 reduce the 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 also vary around the profile of the design. Low back rake angle will commonly be located at the nose as this has the greatest influence on penetration rates. These then gradually increase 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 be used 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 in order to fully evaluate the suitability of the bit design to the planned drive type. All bit suppliers should be able to easily supply this information.

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40o

15o

Bit characteristics relating to Durability and Aggressiveness PDC BITS Cutter Size A variety of cutter sizes are in existence. The current commercial cutters generally range from 8mm to 22mm in diameter, with 8, 11, 13, 16, 19, & 22mm being the most common. A PDC drill bit can be composed of a single cutter size or combinations of two or more sizes, depending on both the application and bit supplier. With all other bit specifications constant, the following general rules apply with variation in cutter size: • • •

Increase cutter size = Increase Torque Increase cutter size = Increase ROP Increase cutter size = Decrease durability

The following is a guideline into cutter size application. 8mm: Small cutter sizes initially intended for use in hard rock applications for extended durability. They also benefit with low torque thus are directionally friendly. Recent trend is 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 reasonable durability for medium to medium-hard formations, with backrakes balanced to provide suitable combination of steerability vs. penetration rate. 19mm: Commonly associated with light set designs for use on rotary for drilling fast hole in soft formations. The large cuttings size generated by 19mm cutters in shale effectively reduces the likelihood of balling. This is due to the fact that the surface area of the cuttings for a specific unit of volume is reduced and thus cuttings hydration is also reduced. Due to relatively high torque, careful consideration of lobe configuration is required if running 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 less reduction 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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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 fully understood though it relates to the cutter / rock interaction in this type of lithology.

small diameter bits) and redundancy is reduced (i.e. durability is more likely to be compromised if one cutter fails than a bit that uses smaller cutters). In addition, wear flats generated on large diameter cutters are large and thus capable of producing high frictional heat which aids degradation of the diamond layer. This size of cutter is currently 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 and gauge of a bit that uses a more aggressive cutter diameter on the face of the bit. This helps to provide a smoother borehole surface, with smaller cusps between cutters, thus less uneven torque response.

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Bit characteristics relating to Durability and Aggressiveness PDC BITS Cutter Count The biggest factor affecting cutter count considerations is the anticipated formations to be drilled. 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. High cutter counts means that the applied weight is shared amongst more contact points and thus less depth of cut is attained by each cutter. This results in lower ROP’s, though this may be offset if the bit is durable enough to complete the section.

Note that cutter density on a specific design will vary locally due to the wear differentiation on a PDC design. The cone generally experiences less wear whereas the shoulder and gauge is relatively high due to the higher forces observed at the outer diameter. 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 cutter technology.

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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 of course there is limited room on the bit profile and thus larger cutters will be further spaced apart. Blade count also figures highly within this relationship.

Bit characteristics relating to Durability and Aggressiveness PDC BITS Blade Count The blades of a PDC bit have three key functions: 1. Support the cutting structure 2. Define flow paths for hydraulic flow and cuttings removal 3. Provide exposure for the cutters

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The number of blades is related to the required durability (and hence cutter coverage) for the design. It is generally in the range of 3 to 12. The geometry is dependant on several factors 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 is exposed e.g. 6.5mm for a 13mm cutter, 8.5mm on a 19mm cutter. This should be noted when evaluating a dull bit i.e. that once the cutter is half worn, you are effectively rubbing on the blade tops and thus your cutter is actually 100% worn!

Bit characteristics relating to Durability and Aggressiveness 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 of each of these will define the overall profile.

The cone is generally lighter set as the isolated rock has been relieved of confining forces and 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 point on both the cone angle and radius of the shoulder – Small nose radius is generally used for 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 wear greatest 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. The length is usually defined by the cutter coverage required for durability and experiences the 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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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 already encountered and drilled formation, isolating a section of formation within the cone. This resultant central cone of rock acts as resistant to lateral movement. Thus the angle of the cone, and hence cone volume, will affect the stability of the bit. Deeper cones will mean that there is more volume of rock and thus greater stability. The inverse effect is seen on steerability; Deeper cones reduce steerability as more rock needs to be overcome to attain deviation.

require a long shoulder section in order to maximise cutter count. Bits on rotary assemblies will experience much lower rotational speeds and thus may have a shorter shoulder section. Of course, anticipated lithology is another major factor in shoulder durability. Gauge: This is where the shoulder extends to the full diameter of the bit design. The gauge is generally observed on a bit as where the blade extends out and forms a solid gauge 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 cutter coverage (usually pre-flatted to offer large PDC area). There are a vast variety of gauge geometries dependant on the specific application and manufacturer, though one common factor to all is gauge length. It is generally considered that longer gauge lengths provide more stability in rotation due to increased surface contact between bit and borehole.

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Bit characteristics relating to Durability and Aggressiveness PDC BITS Side Rake Side rake refers to the angle of deviation of the cutter from a theoretical line normal to the direction of travel. A negative angle means that the cutter face is skewed inwards to the centre of the bit, whereas a positive side rake infers that the cutter face is skewed towards the gauge. A) A)Plan View – Negative Side Rake

Centre of Bit

Arrow = Normal to direction of travel Schlumberger Private

B) A)Plan View – Positive Side Rake

Centre of Bit

Arrow = Normal to direction of travel

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

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Durability And Aggressivity – Roller Cone

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1. Skew

5. Tooth Count

2. Profile

6. Tooth Shape

3. Journal Angle

7. Insert Shape

4. Tooth Length

Confidential

Bit characteristics relating to Durability and Aggressiveness 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 so that this journal centerline is offset from the centerline by a specific angle. This results in the cutter teeth sliding and dragging through the formation as the cone rotates, increasing the gouging action of the bit. The downside is that with skew, the cutter does not roll true and is thus less durable. A bit with zero skew is symmetrical as illustrated below. It is suited to drilling hard formations via crushing with high weight. The cones run true and thus provide greater durability.

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Low 0o Skew

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 zero skew but remain relatively durable.

Medium 3o Skew

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

High 5o Skew

Bit characteristics relating to Durability and Aggressiveness ROLLER CONE BITS Bit Profile The profile of the cone has a major effect on the drilling action, with softer formation bits having a rounded cone profile for high penetration rates. Durability is enhanced by having a flatter profile and is thus used for hard formation bits, though at the expense of ROP.

b) Flat

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a) Rounded

Bit characteristics relating to Durability and Aggressiveness ROLLER CONE BITS Journal Angle The journal angle has two effects on the bit design: Cone size, and load capacity whilst drilling. This angle is defined as the deviation of the centerline of the journal from vertical, relative to horizontal. In terms of cone size, the flatter the angle, the more space is available and thus larger cutters (typical angle value is 33 degrees). Larger cutters have a more rounded profile (as discussed prior), which leads to increased gouging and scraping capability. The larger the angle (i.e. more towards vertical), the greater the axial load that can be sustained, thus good for hard formation drilling (typical angle value of 36 degrees).

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Bit characteristics relating to Durability and Aggressiveness ROLLER CONE BITS A) MILLED TOOTH BITS Tooth Length Longer tooth length provides deep tooth penetration and greater gouging ability for higher penetration rates, though are less durable. As such, long teeth are intended for soft formations, with length decreasing, relative to increasing formation hardness. Hard formations are drilled more effectively with a chipping and crushing action, which is obtained by using multiple short, blunt teeth.

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Bit characteristics relating to Durability and Aggressiveness ROLLER CONE BITS A) MILLED TOOTH BITS Tooth Count The quantity of teeth is inversely proportional to the tooth height: When tooth height is maximized 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 compressive strength rocks. Additionally, water sensitive clays are often associated within these soft formations 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 be sustained in order to overcome the rock. The short tooth length in this scenario will aid resistance to break under these loads. Schlumberger Private

Bit characteristics relating to Durability and Aggressiveness ROLLER CONE BITS A) MILLED TOOTH BITS Tooth Shape The most common shape of milled tooth cutter is an ‘A’. If viewed from the side, it appears like a broad sweeping ‘A’ without the crosspiece. You may also find ‘T’ shaped cutters on some designs. This cutter shape basically adds more metal in the cut area and are thus used as a durability feature. These teeth would typically be found in the harder working 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 T Teeth

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Type A Teeth

Bit characteristics relating to Durability and Aggressiveness ROLLER CONE BITS B) INSERT BITS Insert Shape The shape of the insert effects performance and will fall into three main categories. Each represents a tradeoff between durability and potential penetration rates: • • •

As with milled tooth bits, insert length is inversely proportional to durability: Increased length equals reduced durability. Note: Be wary when comparing figures provided for Milled tooth length and Insert length. The insert length includes the material that will be pressed into the cone in order for it to be retained. The measurement that should be used to compare to milled tooth length is ‘insert protrusion’.

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Dome / Round top – Blunt and thus durable. Commonly short length. Hard formations. Shape minimizes insert breakage and thus able to withstand higher applied 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, though are susceptible to chipping and breakage if harder formations are encountered.

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Durability And Aggressivity – Diamond

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1. Differentiation and Application of Diamond Bits 2. Diamond Bit Profile Impregnated Bits

Natural Diamond Bits

a) Overview b) Blade Height c) Diamond Grit d) Matrix

a) Diamond Quality b) Diamond Size c) Abrasion Resistance 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 quite capable of performing in all formation types, though due to slow penetration rates in medium and soft formations (when compared to PDC and roller cone bits), the use of diamond bits is generally within hard and very hard rock. They are generally applied when the expected penetration rate will be similar or exceed that of a roller cone. Due to the high purchase price compared to that of a roller cone, the diamond bit must be significantly durable and save multiple trips in order to be economical. As such, they are generally run at high depths or where rig cost (and thus trip time) 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. This compares 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 the diamond bit in that the components are surface set in a single layer. Instead of using natural 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 cutting structure, 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

Bit Manufacturer Variations Hycalog: The impreg product range from Hycalog is called ‘DuraDiamond’. The nomenclature 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 created to have a variable formation cutting structure, which is capable of higher penetration rates in softer formations. This is accomplished by staggering the heights of the ribs so that only a certain number initially engage. When worn down, more blades engage, making a heavier set design. Hughes Christensen: Diamond bits have a prefix of ‘D’, Impreg bits uses the prefix ‘S’. There is also a specific unique range of Impreg bits known as ‘Hedgehog’. This uses an interrupted structure to form posts along the face. This provides higher flow area and aggressive cutting structure for drilling shales, whilst extended diamond volume improves bit durability in the harder formations. Hydraulics have also been enhanced with the addition of ports in the cone of the bit to relieve balling and maximize hydraulic energy. Hedgehog bits are prefixed with ‘HH’. The bit nomenclature relates to three digits; Matrix type, Cone cutting structure (PDC, ridge set, Radial set), and Blade count (last digit).

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

Security DBS: Impregnated bits fall under the range name of ‘TI’ followed by four numbers to distinguish the actual variant. They commonly use a cone set with a few PDC cutters. The diamond bit range has the ‘LX’ prefix. DBS also has a product range known as the ‘SE3000i Series’. This uses a combination of PDC with impreg backup. Smith: The key impreg product range of Smith is called ‘X-Tend’. It comprises of bits that are classed as either XTG, XTS, XTN, though there is little literature available on the web 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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Bit characteristics relating to Durability and Aggressiveness IMPREG / NATURAL DIAMOND BITS Profile There are two general profiles utilised for diamond bits: The ‘C’ profile, which has a small nose radius and long taper, and the ‘R’ profile which has a short taper and thus larger nose radius.

b) R Profile

The ‘C’ profile is most common as it provides superior rates of penetration with reasonable stabilization. The ‘R’ profile tends to be used in very hard formations as the higher 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 be used 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) C Profile

Bit characteristics relating to Durability and Aggressiveness IMPREG / NATURAL DIAMOND BITS A) IMPREGNATED DESIGNS Similar to matrix bodied PDC bits, the diamond bit is created by making a mould in which the diamonds are selectively placed. The mould is then infilled with tungsten carbide 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 than the diamonds, so as the bit wears, new, sharp diamonds become available to continue drilling efficiently.

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Bit characteristics relating to Durability and Aggressiveness IMPREG / NATURAL DIAMOND BITS

A) IMPREGNATED DESIGNS Blade Height Blades on diamond bits are commonly referred to as ribs. They are of less width and height than that of PDC bits and thus greater in number. The height of the rib controls the amount of impregnated material and thus the durability of the bit, as once impreg material 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 blades not to extend to gauge. This creates an extended ‘junkslot’ of which there may be two or three around the outer diameter of the bit. Schlumberger Private

Bit characteristics relating to Durability and Aggressiveness IMPREG / NATURAL DIAMOND BITS

A) IMPREGNATED DESIGNS Diamond Grit The diamond grit is considerably smaller than the diamond stones used in a natural diamond bit, generally falling into the range of 10 to 25 stones per carat. There are two forms used; •

Natural: Larger sizes, good impact resistance, irregular shapes (angular to sub rounded)

•

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

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

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

Bit characteristics relating to Durability and Aggressiveness IMPREG / NATURAL DIAMOND BITS A) IMPREGNATED DESIGNS Matrix The abrasive properties of the matrix binder are as important as the quality of the diamond grit used and must also be matched to the application. If too soft, the matrix will abrade easily and release diamonds before they have effectively dulled (poor durability). If too hard, the diamonds will excessively dull without release and thus lower penetration rates.

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Bit characteristics relating to Durability and Aggressiveness IMPREG / NATURAL DIAMOND BITS B) NATURAL DIAMOND BITS Diamond Quality Classification The three key crystal structures of diamonds used for industrial purposes are cube (6 square sides), Octahedron (8 triangular sides), and dodecahedron (12 rhomb sides). The crystal shape and quality of the diamond significantly affects the application and drilling performance. There are seven primary grades of stones. Magnifique or West African: High quality, angular monocrystalline diamond. It is an excellent drilling stone with few flaws or inclusions. Unfortunately, due to this, it has gem potential and is also highly sought after for other industrial uses, thus high price. It has the highest abrasion resistance and good shock properties.

Premium: Monocrystalline, round diamond, which has had the soft outer layer mechanically, removed. This gives good abrasion and shock resistant qualities. Cube: Cubic (monocrystalline) diamonds provide both low abrasion and shock resistance. Can perform well in non-abrasive plastic shales and evapourites. Used selectively. Octahedron: Eight sided monocrystalline diamond with reasonable wear resistance and is 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 is fairly scarce and thus high price, but possesses the highest resistance to impact, though low abrasion resistance. Gage: This grade consists of broken or flawed diamonds. They are selectively placed in low 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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Superior: Basically, this is a rounded or worn West African stone, so again, is high quality with few flaws, However, due to its roundness, it lacks the aggressivity of the West African stone.

Bit characteristics relating to Durability and Aggressiveness IMPREG / NATURAL DIAMOND BITS B) NATURAL DIAMOND BITS Diamond Size Diamond size is application specific. The harder the formation, the smaller the stone required. Thus for soft diamond formations (>10 ft/hr) you may require up to 1 ½ carat diamonds, whereas hard formations (<2 ft/hr) this will be down to about 0.15 carats. Shape is also important. Softer formations such as plastic shales, may drill quicker with a pointed stone (such as cube or octahedron) as this aids the scratching effect as opposed to ploughing or grinding.

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Bit characteristics relating to Durability and Aggressiveness IMPREG / NATURAL DIAMOND BITS B) NATURAL DIAMOND BITS Abrasion Resistance Varies with grade of stone. In order of resistance to wear (highest first), they are: 1. 2. 3. 4. 5. 6.

West African Superior Premium Octahedron Cube Carbonado

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Bit characteristics relating to Durability and Aggressiveness IMPREG / NATURAL DIAMOND BITS B) NATURAL DIAMOND BITS Impact Resistance As per abrasion resistance, it varies with grade. In order of resistance to impact (highest first), they are: 1. 2. 3. 4. 5. 6.

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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 design that are purely considerations for durability alone. These are as follows.

PDC Bits

Roller Cone

Natural Diamond Bits

a) Body Material b) Gauge c) Backreamers

a) Metallurgy b) Diamonds c) Shirttail d) Hardfacing

a) Cone Wear b) Gauge

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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 moulding of the bit with matrix powder and alloy and furnacing to form a solid body.

The primary downside of the steel bodied design is that it is potentially subject to erosion and abrasive wear. This usually occurs around the cutter pockets, and if severe, can lead to lost cutters. It is common practice now to apply a layer of erosion resistant hardfacing to the blades, the extent and grade of which, is dependant on the individual bit manufacturer. The matrix bodied design has excellent surface properties with an exceptional ability to resist fluid erosion, however, the mechanical properties are weaker than that of steel and thus the blades are generally lower and wider, with resultant lower junk slot area and volume. As a general rule, you will observe that steel bodied designs are generally light set, open faced bits for drilling soft formations at high penetration rates. The matrix bodied bits are generally heavier set and are used to drill for longer hours and in abrasive / erosive environments. However, the diversity of applications, bit manufacturers ranges, and operator preferences, all combine to make the rule above very general indeed.

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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 and area for effective cleaning of the bit, particularly useful for drilling clays / shales with WBM. It is also cheaper and relatively easy to modify as there is no requirement to update or create a new pattern as with a matrix bodied design.

Durability Factors PDC BITS Gauge Protection The protection used at gauge differs for the two body types. Steel bodied bits typically rely on inserts, which are pressed into drilled holes in the gauge pads. The inserts may be any 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 to infill and are thus embedded in the matrix body after furnacing. It is also possible to have inserts (as for steel body designs) placed in the pads, though these would be brazed instead of pressed due to the reduced size tolerance of matrix to generate the interference fit required. Pre flatted gauge trimmers would also be used. Schlumberger Private

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

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 has cutting 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 depending on the application. Hard formation inserts are durable in terms of both shape and length thus the key material factor is to be resistant to abrasion, thus a low cobalt percentage and small grain size is used. The reverse is seen for soft formation bits where a high percent of cobalt is used with larger grain size to provide mechanical strength as the inserts are relatively 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 be diamond coated. Reduced insert length for durability. • Gauge – Use where prior offset dulls have shown gauge wear / damage to be the limiting factor in bit life. Ideal in soft to medium formations where high abrasivity is encountered. Various gauge trimmers are available from different bit suppliers. They supplement the action of the gauge inserts but additionally cut formation as well. • 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 the face as well as gauge. Application dependant. Schlumberger Private

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 both tungsten 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 for directional / horizontal / abrasive formation applications.

Protection

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 if drilling on bent housing and thus eccentric hole. Lugs pads also help to minimize shirttail wear and prolong seal life.

Lug Pad

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Stabilization

Durability Factors ROLLER CONE BITS Hardfacing Application of abrasion resistant material to the actual steel teeth in order to extend the durability of the teeth. This is packaged by the bit manufacturers in terms of both coverage and grade of applied material. For example, hardfacing may be applied on one side only in order to obtain a ‘self-sharpening’ wear effect. Two sides may be coated in order to maintain maximum tool height, though commonly full coverage is used. The importance of hardfacing has developed due to the increased technology (and thus life) of the bearings, resulting in the bits staying downhole longer and requiring more abrasion resistance.

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Durability Factors IMPREG / NATURAL DIAMOND BITS Cone Wear One of the most common failure modes of diamond bits is to ringout, or core, in the cone area. This is due to the fact that the hydraulics waterways converge in the cone thus creating areas of low diamond coverage. In order to avoid this, look for designs that have waterways that converge into the cone at different radii – Basically an asymmetric waterway design that does not concentrate areas of no diamonds into one zone.

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Durability Factors IMPREG / NATURAL DIAMOND BITS Gauge Protection It is usual to supply these bits mounted on turbine sleeves, which are commonly a steel sleeve 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 important in these applications due to the hard and abrasive nature of the formation, and the high rotational 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 which the roller bearing may be sealed or unsealed (Journal bearings are always sealed). In addition, you may also come across air-cooled roller bearings. •

•

•

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 continuous even load and is capable of handling relatively high rotational speeds without suffering from damaging high temperatures. As such, the general rule is that bits <12 ¼” diameter use Friction / Journal bearings whilst bits >12 ¼” employ roller bearings. 12 ½” is the crossover size between the two.

a) Sealed Roller Bearing

Rollers

b) Sealed Journal Bearing

Journal

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Sealed Roller – The cutter encapsulates a series of roller bearings and it is through these 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. The sealed roller bearing is lubricated by grease providing high bearing life and is thus good for high-speed applications (motor / directional). Unsealed Roller – As per above except that drilling fluid lubricates the rollers thus 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 shallow hole drilling. Journal – Instead of employing roller bearings, the friction bearing is based on the load passing through the cutting structure directly onto the journal over a large, low friction, surface area. There is usually a floating bushing placed between the cutting structure and journal as illustrated below. A journal bearing usually sees minimal 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.

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 NPI geometries by the bit manufacturers. The interface between the polycrystalline diamond and the tungsten carbide substrate is one of high stress due to the fact that in order to form the diamond layer, both are subjected 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 tungsten carbide 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.

An NPI cutter basically has an irregular interface, where numerous ridges or circles exist in 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 allowing higher 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. It also 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 the rim, are the key aspects relating to the marketing of cutters by the manufacturers.

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Planar Cutter

Smith: The premium cutter offering from Smith is grouped as the GeoMax range. This includes 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 edges such as Ring Claw and Deep Ring Claw. The Elite Series designates that these thick diamond table designs have been improved via a new process methodology to offer greater impact resistance.

a) Iris

b) Fan

c) Star

d) Nodule

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

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

• • • • • •

A1 – AXSYM A2 – Manhattan A3 – Alba D2 – BXD D3 – Niagara D4 - Modesto

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 wear against 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. Multimodal diamond selection, where grains of various sizes are used, led to improved abrasion resistance, whereas NPI substrates provided greater impact resistance due to its interlocking nature. However, recently a technological breakthrough has led to the development of a cutter that uses a thin layer of ultra resistant diamond at the cutting edge of a multimodal NPI cutter to radically improve abrasion resistance without any compromise to impact.

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Abrasion & Impact Resistance

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 longer sections but also providing higher penetration rates, as the cutter remains sharp for longer. Ultra abrasion resistant layer

PDC Side View - TReX Cutter

NPI Substrate

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 is drawn from the tungsten carbide substrate. With a thicker diamond layer, more cobalt is drawn and the cobalt concentration at the interface is reduced making it brittle and weak under tensile loads. Two methods can be followed in order to reduce this effect: One is to add cobalt directly to 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, particularly when formulated with the interlocking strength of a non-planar interface. Problems may arise though in manufacturing such geometries due to cracking of the diamond or carbide and 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 shapes that are relatively common in the oilfield; Oval and pointed. Oval cutters are actively promoted by one specific bit manufacturer (BBL). From their geometry it can be observed that there are two key differences between oval and cylinder cutter wear. The first is that a smaller horizontal wear flat will be generated (less PDC contact with formation and less friction / heat), the second being that there is a greater

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Diamond Thickness

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 PDC coverage. 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 point load is applied in order to fracture the formation as opposed to a shear failure mechanism normally associated with cylindrical 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 is that it is formation specific (not good for heterogeneous) and may dull the point rapidly under high weights. Miscellaneous geometry Several other cutter or substrate geometries exist which may be encountered. Some of these include: •

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

Chamfered Substrate

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Pointed Cutters

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Chamfered Cutters: Conventionally the angle between the front face of the PDC and the circumference of the carbide support is 90 degrees. This angle is chamfered in order to improve the carbide support of the diamond cutting edge so as to reduce incidence of PDC breakage that is often resulting from hard formation drilling. One such product is the Tuffedge cutter from Hycalog.

Tuff Edge Cutter

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D E C

D&M—NSA

rilling

Formation Factors

ngineering

enter

Determining the formations to be drilled is the critical step in bit selection. Once an understanding is reached as to what type and density of cutting structure is required to actually remove the rock, then considerations can take place for other aspects such as stability, steerability, matching aspects to drive types, etc. The primary purpose though, is to select the appropriate drill bit that has sufficient durability to remove formation at a reasonable 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 disordered assembly. Soft, sticky, and water absorbent. Certain clay minerals are reactive with water and cause swelling Shale – Claystone that has become compacted. The clay particles become ordered and lie horizontal. As above, particular clay minerals are reactive to water causing swelling shales Siltstone – This is an intermediate between sandstone and claystone / shale, and is classified basically on grain size alone. Similar properties to sandstone though the grains are less than 1/16mm in size. Marl – Semi consolidated clay or siltstone. In some regions it is a calcareous claystone. Relatively soft to drill

•

•

Sandstone – Consolidated sand size particles (2mm – 1/16mm) that are cemented usually with silica or calcareous cement. The particles are generally quartz but may also consist of feldspar, mica, and glauconite as it is derived from igneous rocks. The properties of the sandstone are dependent on particle size, sorting, shape, and strength of the cement. This means that sandstones can be very diverse in nature in terms of drillability. They can also be very abrasive due to the high quantity of quartz. The hardness is usually dependant on the cement. Note that unconsolidated 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 boulder size. This is problematic for PDC drill bits as the boulders may ‘rattle’ between the blades causing heavy cutter breakage. Roller cones are best suited to these formations 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 shell fragments. The hardness of the rock will vary and depend on the quantity of other sedimentary rocks (clay / sand) and the cementation Dolomite – As above but is formed from magnesium carbonate instead of calcium

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b) Arenaceous

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 sediment deposition 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 limestone in 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, though at base level, the best approach is analysis of offset records for dull conditions (see section on dull grading interpretation) and drilling reports. The six primary characteristics for bit selection are:

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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 the majority of shales and claystones. Other formations include soft evapourites (such as salt) and soft siltstones

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1) Stickiness – Formations that are sensitive to water become sticky and pose balling issues. Consideration should be placed on maximising HSI and JIF of the bit and selecting 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 will require either impreg or heavy set inserts bits to drill. 4) Pressure – Differential pressure is the difference between the hydrostatic pressure in the annulus and the formation pressure. The general scenario is that the hydrostatic will be greater than the pressure in the formation. This has a negative effect on potential penetration rates, with the higher the difference resulting in lower ROP. This is because it adds to the confining force and thus compressive strength is greater. It also holds down rock chips generated by the cutting action of roller cone bits, thus slowing rock removal. 5) Abrasiveness – Generally sand formations. Bit considerations should relate to enhanced 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 a formation 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 vary considerably depending on formation type and as such are commonly used for classifying formation strength. This in turn is often used for evaluating bit requirements. The list below provides approximate compressive strength values.

Soft to Medium – Formation strengths in the range of 8-12,000 psi. Formations include soft limestones, marls, soft - medium sandstones, medium shales, chalk and medium anhydrites

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Medium – Compressive strengths in the range of 12-15,000 psi. Typical lithologies include sandy and chalky limestones, medium sandstones, hard shales, anhydrites

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Medium to Hard – Formation strengths in the range of 15-20,000 psi. Hard formations that are not highly abrasive. Lithologies include hard shale, siltstone, low abrasive hard sandstones, limestone, dolomite, and anhydrite

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Hard – Formation strengths up to approximately 35,000 psi, often abrasive. These formations include hard dolomites, crystalline limestone, hard, brittle shales, hard abrasive sandstone and siltstones

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Very Hard – Very hard formations such as quartzite, very fine grained, well-cemented sandstones and siltstones, igneous, and metamorphic rocks with strong crystalline lattices. Formation strengths often in the range of 35-80,000 psi

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Formation Factors Roller Cone Selection The table below is a rough guide based on rock classification / compressive strength. The numbers indicate the IADC code of the bit design. The IADC code is used heavily for rock bit classification, with the primary number increasing from 1 to 8 with increasing hardness of rock. A more detailed table can be viewed at the rear of this section that ties in the correlation between formation strength, IADC number, and actual product types from the major bit manufacturers. For further information regarding the IADC classification, please refer to the IADC section within the guidelines.

Soft

Milled Tooth

Insert

111 - 137

415 - 447

Soft - Medium

515 - 547

Medium

615 - 637 211 - 217

Hard

331 - 337

Very Hard

717 - 737 817 - 835

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Medium - Hard

Reed-Hycalog

Roller Cone Comparison Insert Bits

Tooth Bits

Reference Information

IADC Code

Reed

111

Y11

114 115 116 117 121

Hughes R1 GTX1

EMS11G EMS11GT

GTXG1, MAXGT1

EHT11, HP11

GT1

MHT11G, EHT11G MHT11GT

GTG1, GTG1H STR1, MX1

Y12

Smith DSJ SDS MSDSH MSDSSH

• Nozzle Flow Areas • API Bit Tolerance • API Casing Date • Make-Up Torque

Reference Charts • IADC RollerCone

127 131

136 137 211 214 215

S33SG

MFDSH MFDSSH, FDS2

ERA MPSF MPSF, S33SGF S3J

DTJ

S33 S33G, SS33G EHP12, EHT12 HP12 Y13

R3

FDT

S33F

DGJ

S33GF, S33TGF S4J, S4TJ, S4T

134 135

S33S

S33SF, PSF

125 126

S3SJ

FDS, FDS+ FDSS+

124

Reference Tables

Security

GTXG3, MAXGT3

MSDGH, SDGH

S44G, SS44G

HP13 HP13G MHT13G

ATJG8

FDG FDGH, MFDGH MFDSHOD

S44GF

V2J ETS21G

MSVH, SVH

M44NF M44NGF

• Rock Bit Availability

221

• Trademarks • Contact

EHP41, EHP41A, EHP41H HP41A, HP41H

425 GT09C, H09C, MX09C MX09CG, STR05C

427

DR5 H7, H7J

314

H77

316

H77F R7 H77SG

Security

02MF, F02T

ERA03, ERA03D S80F

05M, M05S M05T, 05MD

SS81

05MF, 05MFD, F05, F05T F07, MF05, MF05T

ERA07, S81F

435

EMS43A, EMS43H MS43A-M

GTX09, MAX11H MAXGT09

10M, 10MD, 12M, 12MD, 12MY M1S, M10T, M12T, M12TY

SS82

437

EHP43, EHP43A, EHP43H HP43, HP43A, HP43A-M HP43--M

GT09, H09 MX09, MX09G STR09

10MF, 10MFD, 12MF, 12MFD, F1 12MFY, F10D, F10T, F12T, F14T MF1, MF10T, MF12

ERA13, ERA13C ERA13D, ERA14C S82F, S82CF, S82F

445

EMS44A, EMS44H

MAXGT18

15M, 15MD, M15S, M15SD, M15T

447

EHP44, EHP44H HP44, HP44-M

GT18, GT18C H18, H18C, MX18

15MF, 15MFD, F15, F15OD, F15T, MA15, MF15 MF15D, MF15T

ERA17, ERA17D S83F, SS83F

515

EMS51A, EMS51H ETS51, MS51A, MS51A-M

GTX20 MAXGT20

20M, 20MD, A1JSL MA1SL, M2S, M2SD M20T, 20MD, M2SD

SS84 2SS82

EHP51, EHP51A, EHP51H EHP51X, HP51, HP51A HP51A-M, HP51H, HP51H-M HP51X, HP51X-M, MHP51H

GT20, GT20S, H20 MX20, MX20G, STR20

20MF, 25MF, A1 F15H, F15HT, F17 F2, F2D, F2H, F20T, F25 F25A, MF2, MF15H MF2D, MF20T, MF25T

DS84F, ERA22 ERA22C, ERA22D HZS84F, S84F S84CF, SS84F

517

GTX20C, MAXGT20CG

525

537

FV FVH

• People

SS80

GT03, H03 MX03, STR03

EMS53A, ETS53A, MS53 EHP53, EHP53A HP53, HP53A HP53A-M, HP53JA, MHP53A

ATJ4

ATJG8

EMS41H

02M, M02S M02T, M01S

535

ATJG4

347

Smith

GTX00, GTX03 MAXGT00, MAXGT03

527

HP21

335

Hughes

M4NJ M44N M44NG, MM44NG

HP21G

311

Reed

EHP52HT, HP52, HP52A HP52X, HP52-M

217

321

417

S44F

216

Unit Conversions

415

S44 EMS13G, ETS13G MS13G

• Nomenclature

• IADC Dull Bit

IADC Code

545

GT20C, GT28, GT28C H28, H28C, MX28 ATJ33A, GT30, H30 MX30, MX30G, STRO30

M27S, M27SD 20MFY, F27, F27D F27A, F27I, MF27, MF27D

ERA25, ERA25C S85F, S85CF

M3S

S86, SS86

30MF, F3, F3D, F3H F37D, MF3, MF3H MF3D, MF30T

ERA33, ERA33C S86F, S86CF

GTX30C, MAXGT30CG GT30C, MX35C, MX35CG STR30C, STR35C

F35, F37, F37A F37H, MF37

ATJ44, ATJ44A, ATJ44G HR40, STR40

F4, F4A, F4H F45H, F47, F47A

M84F

5JS

MM88, M89T

ATJ44C, ATJ44CA, HR40C MX40CG, STR40C

F5, F47H, MF5, MF5D

M84CF, M85F M86CF, M89TF

EHP63, HP63, MHP63

MAX55 ATJ55, ATJ55A, ATJ55R, ATJ55RG HR50, STR50, STR50R

F57

M89F

HP64 EHP73, HP73 HP74 EHP83, HP83,

ATJ66, HR60 ATJ77, HR70, STR70 ATJ88, HR80, STR80 ATJ99

F67 F7

H87F

F9

H100F

547

HP54

617

EHP61, EHP61A HP61, HP61A

625

MS62

627 635

EHP62, EHP62A, HP62 HP62A, HP62JA EMS63

637 647 737 747 837

MAX44C

SS88C S88CF, S88CFH S88F, S88FA

Formation Factors PDC Bit Selection As per for rock bits, rough guidelines for fixed cutter drill bit selection is below. This classifies selection based on blade count and primary cutter size. Note that this is approximated for bits in the size range of 8 ½” to 12 ¼”. Obviously, blade count will need to increase with larger bit sizes.

Blades

Cutter Size (mm)

Soft

3-5

16-19+

Soft - Medium

4-6

13-19

Medium

6-8

13-16

Medium - Hard

7-9

11-13

8-10+

8-13

Hard Very Hard

Impreg / Natural Diamond

Although denoted only for very hard applications, the diversity and technology behind impregnated designs may mean that they are economical for both hard and medium to hard applications as well. With Natural diamond bits, the diamond size is key to matching bit to lithology - The harder the formation, the smaller the stone required. Thus for soft diamond formations (>10 ft/hr) you may require up to 1 ½ carat diamonds, whereas hard formations (<2 ft/hr) this will be down to about 0.15 carats. Shape is also important. Softer formations such as plastic shales, may drill quicker with a pointed stone (such as cube or octahedron) as this aids the scratching effect as opposed to ploughing or grinding. With Impreg designs, the diamond grit is considerably smaller than the diamond stones used in a natural diamond bit, generally falling into the range of 10 to 25 stones per carat. The abrasive properties of the matrix binder are as important as the quality of the diamond grit used and must also be matched to the application. If too soft, the matrix will abrade easily and release diamonds before they have effectively dulled (poor durability). If too hard, the diamonds will excessively dull without release and thus lower penetration rates.

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Impreg / Diamond Bit Selection

Formation Factors Problematic Formations Rock bits are unique in the fact that they can be applied to all formation types, given correct cutting structure is matched to the rock strength. PDC bits however will not successfully drill certain rock or minerals. Pyrite – A gold colored iron mineral that forms as cubes and can occur as local deposits. Pyrite is not sheared by PDC cutters and can cause cutter breakage, dependant on the quantity drilled

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Conglomerate – As mentioned previously, these are large pebbles / boulders in a soft clay matrix. When loose of the matrix, the boulders can become loose within the blades of the PDC causing extensive breakage

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Chert – Fine grained, very hard siliceous material similar to flint. This is not PDC drillable and will cause cutter breakage. Found in localised deposits and commonly found in chalk

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Volcanic / Igneous rocks – Due to their strong interlocking crystalline structures, it is difficult to shear these rock types and thus PDC bits will dull rapidly. The bit selection will depend on the application specifics. In general, due to the very hard, crystalline and homogenous nature of igneous rock, it is ideally drilled with impreg bits, particularly if there is no soft material evident to plug the junk slots / waterways. It can also be drilled with Insert roller cone designs with IADC codes in the range of 817 to 835. Selection will depend on: o Expected duration of run. Insert bits will be subject to bearing life, which will be relatively low because of the high weight on bit used to drill this lithology. You may expect bit hours of 40 or less whereas the impreg life could be in excess of 100 hours, thus it is an economic balance between trip times and initial purchase price of the bits. There is also no risk of leaving junk in the hole with an impreg design. o Drive type. The impreg bit will ideally operate with a high speed, low torque motor. A 2/3 configuration motor should deliver sufficient torque, and rpm's in the range of 350. Extended bearing life will be aided by use of a lower speed motor or rotary, but will have a negative effect on ROP. o High temperature issues. This would also affect bearing life of the Insert bit but not the impreg bit. Circulating temperatures in excess of 300F will degrade the elastomer in the seal, in which case, metal sealed bearings should be used to extend bearing life. The use of offset records will be able to give you an assessment of approximate rock bit bearing life and performance.

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•

Sandstones – This rock type is PDC drillable though note that stability issues are often associated with drilling consolidated sandstones with aggressive PDC designs. This is covered in more detail in the stability section. Avoid use of 19+mm cutters

•

Interbedded formations – The analysis of the data may reveal intermittent beds or ‘stringers’ of hard formation throughout the lithology to be drilled. The bit selection must take into account the quantity and hardness of these formations otherwise a premature termination of the run may occur due to a worn bit. However, one of the key issues with drilling hard interbeds is bit damage from impacting the harder bed whilst drilling at high penetration rates through the softer members. The best preventative measure is not a bit feature, it is optimisation of drilling parameters so that these beds can be entered and exited under control, avoiding sudden impact and weight piling

•

Salt – Issues such as vibration and low penetration rates are associated with drilling salt. PDC bits are ideally suited to drilling salt formations, particularly with oil / Synthetic oil based mud’s. As a rough guide, 13mm cutters are optimal on a medium set bit (5-6 bladed). 16mm cutters have been used to improve penetration rates in large size hole (>16”) on eight bladed designs. Cutter wear is not generally an issue due to the relatively low density of salt, instead, the usual failure mechanism is cutter breakage from lateral / torsional vibration. As such, consider the stability aspects of the design to be used, hence the optimal use of less aggressive 13mm cutters. Backreaming cutters should also be used in mobile salt formations.

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•

D E C

D&M—NSA

rilling ngineering

Matching Bit to Drive

enter

1. Motor Basics

7. Coiled Tubing Applications

2. Bit Requirements for Motor

8. Hole Opening Technology

3. Lobe Configurations

7. Hydraulic Considerations

4. Motor Bit Ranges

8. Steerability Aspects (PDC)

5. PowerDrive Bits

9. Side Track Applications

6. Bits for Exceed

10. Shoe Drill Out

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Bit selection for Schlumberger downhole tools Motor Basics • • • • • • •

Match PDM torque output with the torque requirements of the bit Avoid the use of high speed motors in abrasive formations with PDC bits The more aggressive the bit, the greater the torque requirement PDC bits are considerably more aggressive than roller cone bits Due to the small cutter size, diamond and Impreg designs generate very low torque PDC aggressivity is a function of profile, cutter size, cutter density, and cutter backrake Cutter backrake is the least investigated aspect but is one of the key parameters

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Bit selection for Schlumberger downhole tools Design Requirements for Directional Motors – PDC (see also steerability section) • • •

• •

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•

Bit length – Short so as to reduce distance between contact points and thus enhance DLS capability. Ideally, should comply with LAR concept i.e. bit length (from nose to joint face) should be less than the diameter of the bit. Profile - Short profile (medium cone, short taper) for directional drilling. Long profile (deep cone, long taper) for performance drilling to maximize shoulder cutting structure and enhance life for high speed drilling Gauge length – Short is beneficial for directional. Longer gauge for tangent to enhance borehole quality and lateral stability .A compromise is a spiral gauge, which maintains short gauge length but increased circumferential contact between bit and borehole. Spiral angles in excess of 20 degrees may significantly compromise flow through junkslots, as dead hydraulic areas will be created. Gauge protection – Enhanced protection required, particularly on high speed motors Backreaming – To ensure efficient backreaming, designated upreaming cutters should be used Torque – The biggest issue is to hold toolface when sliding with PDC bits. Due to their aggressive nature, reactive torque generated by the bit may pose problems for the DD. Directional friendly design aspects include the following. Note: Bits used on motors strictly for performance drilling and not for sliding, can be considerably more aggressive. o Back rake angles: High angle equals reduced torque fluctuations and thus more steerable on PDM. Backrake should be relatively high all over the bit though particularly high at the shoulder and gauge. As a rough guide, 20+ degrees on the nose and 25-35 on shoulder and gauge, increasing as you transcend to the gauge. o Cutter size: Small cutter size equals reduced torque fluctuations but also lower penetration rates. Typical directionally friendly cutter sizes include 8, 11, and 13mm. There is a trend to move away from 8mm to 11mm and also the use of 16mm to improve on penetration rates. 19mm cutters on heavyset bits can potentially be used, particularly if the cutter size reduces as you move out along the shoulder. The use of 19mm, and larger, cutters on light set bits are likely to be difficult to steer. o Cutter density: This is primarily reliant on the geology to be drilled, however, the lighter set the design, the greater the torque as a greater depth of cut is attained by each cutter as it removes the rock. Heavyset cutting structures are more beneficial though will limit ROP. o Depth limiters: These are basically extra contact points on the bit which help to control the depth of cut taken by the cutters and thus limit torque fluctuations. They come in various forms, depending on the manufacturer, but are usually in the form of either domed exposed inserts or applied (impregnated) material that is located behind the primary cutting structure.

This is usually limited to the shoulder so as to limit torque fluctuations without imposing on penetration rates. As can be seen above, in order to reduce torque, you usually have to limit the penetration rate capability of the design. The actual torque experienced is also highly dependant on the geological application and drilling parameters applied; Basically, factors that will affect the depth of cut that can be taken by the cutters. This also includes the downhole motor as this affects the downhole rpm of the bit. Design Requirements for Directional Motors – Roller Cone Due to the fact that Roller cone bits generate considerably less drilling torque than PDC designs, they are much more compatible for directional drilling on steerable motors and require less consideration to matching the motor output. As such, more preference can be dedicated to matching the characteristics to the formation to be drilled and the anticipated parameters to be used.

There are also other factors from drilling a directional well that will affect the bearings. Listed below are some general rules: 1. The higher the bend angle, greater the side force, lower the bearing life. This also applies to distance from bit to bend – The greater the distance, the lower the life. 2. Due to off-center movement with a bend angle, the higher the percentage time spent rotating, the lower the bearing life. Sliding mode will generally be less damaging. 3. Increase either hole angle, build rate or dogleg severity and generally bearing life will be reduced. As with PDC bits, the combination of high downhole rotational speeds and side loading results in the need for premium gauge protection for roller cone bits used on motor. Design Requirements for Directional Motors – Impreg / Diamond bits Due to the small size of the cutting structure, there are no torque issues relating to running these types of bit on motor. However, due to their grinding mode of rock removal, they are most efficient at high rotational speeds. With the common combination of these bits on turbines and high-speed motors, gauge length is generally long in order to maintain good stability and reduce hole spiraling. It is

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The big concern that needs to be addressed though is the affect on bearing life. The primary factors that will reduce the bearing life of a roller cone bit is weight on bit and downhole RPM. Obviously, with use of a downhole motor you will be increasing RPM and thus reducing bearing life. The sealed roller bearing is lubricated by grease providing high bearing life and is thus good for high-speed applications (motor / directional). Premium seal technology should be utilized for maximum life.

usual to supply these bits mounted on turbine sleeves, which are commonly a steel sleeve 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 important in these applications due to the generally hard and abrasive nature of the formation. If a bit is pulled undergauge, the following bit has extensive reaming to complete before drilling ahead. If this reaming is carried out on turbine or high-speed motor, this bit will endure significant wear to the shoulder and potentially reduce the life of the run significantly.

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Bit selection for Schlumberger downhole tools Motor Lobe Configurations for Bits Due to the drastic variation in application parameters, it is very difficult to provide guidelines on what lobe configuration will match which bit in a specific lithology. As a very general rule of thumb: • • • •

Impreg / Natural Diamond = 2:3 Heavy set PDC = Minimum 4:5 Light set PDC = Minimum 5:6 Roller cone = 2:3 to 7:8 (Note: Use of high speed motors will reduce bearing life)

GT Motors will increase torque output over that of XP and is suited for running aggressive PDC bits Extra stages have been added to the 2:3 configuration motor, ideal for impreg applications. This is known as HS (high speed)

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The direction taken by PDC designers is to produce bits that produce low torque fluctuations so that they can be run on higher speed motors and thus maintain high penetration rates. For roller cone bits, the concerns lie with improving bearing technology so that the bits can endure long intervals on high-speed motors.

Bit selection for Schlumberger downhole tools Bit ranges for Motor - PDC Genesis HCM: Steerable motor range of PDC bits from Hughes Christensen. Uses patented depth of cut control technology to reduce torque fluctuations. These include, low cutter exposure in the cone of the design, brute cutters in the cone to provide a contact surface if depth of cut is exceeded, and wear knots to limit depth of cut on the shoulder. Dual Torque: PDC bits from Smith for directional drilling applications. They are promoted as supplying predictable and controllable torque responses to WOB changes, and are engineered for both sliding and rotating modes. This is resultant from cutter placement and geometry, particularly in the cone. Steering Wheel: Created by Hycalog for PDC bits. Utilizes a full or partial ring gauge to create high circumferential gauge coverage whilst still maintaining a short vertical height for steerability. Although promoted as a cure for lateral instability, the steering wheel was designed for steerability by reducing the cutter ‘bite’ into the sidewall and thus reducing torque fluctuations.

Hughes: • GTX – High rpm and directional applications. O-ring sealed journal bearings • Ultramax (MX) – Motor line with metal sealed roller bearings • Star (STX) – Slimhole motor applications • Star2 – As above but with additional gauge protection for highly directional wells Smith: • Gemini (G / GF) – Twin seal design for motor applications • Xplorer (XR) – Slimhole insert bits for directional drilling and motor applications • Xplorer Plus (XR+) – As above, but with milled tooth bits Reed-Hycalog: • EMS (Enhanced motor series) – Sealed roller bearing designs • ETS (Enhanced turbine series) – As above but for very high-speed applications • MS (Motor series) – Both milled tooth and insert bits. Sealed roller bearings • SL (Sabre Line) – Slimhole directional applications • TDD (Tuff Duty Directional) – Premium directional bits Security DBS: • SS / MM – Motor bit range

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Bit ranges for Motor – Rock bits

Bit selection for Schlumberger downhole tools PowerDrive Basic tool operation The basic principle of the PowerDrive tool is that a force is exerted from the bias pads, which ‘pushes’ against the well bore. This should theoretically result in the bit moving in the opposing direction, hence attaining the deviation required. One of the key concepts relating to the bit design is that the steering system (including the bit) always lags behind the center of the borehole by a small degree. In effect, this means that the bit is actually tilted in the hole when biasing with this tool. As such, profile and cutting structure will affect steering performance. (Note that due to the requirement of contact between the bias pads and the wellbore, bicentre bits cannot be run in combination with PowerDrive.)

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Guidelines for the bit design requirements for efficient operation on this tool are defined below. These features are based on a bit for maximum steerability. Aspects relating to applications where steering is not the key requirement will be discussed in the section following this. Design Requirements (PDC) Gauge Cutting Structure: In order for effective sidecutting when biasing, the design should have some form of gauge cutting structure. This is generally in the form of aggressive PDC cutters with reduced diameter gauge pad, generally known as ‘Active gauge’. The exact geometry, layout, and name differs from the various manufacturers. Cutter Backrake: Due to the fact that side force tools such as PowerDrive are not restricted by the reactive torque generated by the bit, the designs can be typically more aggressive than what you would use on a motor. Aggressivity (aside from profile) is dominated by cutter size and cutter backrake. The cutter size should relate primary to the hardness of lithology (see geology section) but the backrakes can be adapted to maximize penetration rates with these tools. As previously discussed, lower backrake angles will provide higher torque but greater penetration rates for a given weight on bit. As such,

cutter backrakes on rotary steerable bit designs should be in the range of 12 to 20 degrees. Cutter Backrake Distribution: Low cutter backrakes in the nose are important for axial penetration rates, however, consideration should also be placed on backrakes in the cone, shoulder, and gauge. These also should be relatively low angle (approximately 20 degrees) as they also factor in laterally removing rock when tilted during biasing. The use of lower backrakes will aid efficient transfer of bias force through the cutting structure, and into deviation. Bit Length: As with directional motor assemblies, the potential build and turn rates are defined by three points of contact. With a rotary steerable assembly these are the bit, the bias pads, and the first stabilizer behind the control unit. Thus, the closer the bit face can be from the bias unit, the higher the potential dogleg attainable, and as such, shorter bit lengths are more beneficial. (Note: Due to the difference in manufacturing process, steel bodied bits are inherently shorter than matrix designs).

Gauge Length: Again, short is best in terms of steerability. A short gauge pad helps to focus the bias force and aid deviation, particularly if the pads contain an appropriate cutting structure. Secondary Cutters: Due to the relatively short profile length, combined with the fact that the shoulder does receive preferential wear with the tilting action, the option of secondary cutting elements should be considered for hard and abrasive applications. The use of premium and high abrasion resistance cutters may be an alternative. Nozzles: Aside from conventional bit hydraulics issues which will be discussed seperately, the PowerDrive tool, irrespective of size, requires a pressure drop ideally in the range of 650 to 750 psi. This is conventionally attained via the use of the bit nozzles, though an internal restrictor within the tool may be an option. In terms of bit selection, ensure that the bit design has an appropriate number of nozzles for the planned mud weight and flow rate of the application. You should avoid designs with high nozzle counts, which require either small jet sizes (LCM issues) or having to blank off jets (poor hydraulic distribution).

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Profile: Short, steerable profile should be used – Shallow cone, short taper section, high nose radius. This profile provides a number of benefits: • Short profile length = Short bit length = Less formation to be removed to attain deviation • High nose radius and short taper provides a high number of cutters on the lower shoulder and gauge for effective sidecutting • Shallow cone reduces the volume of rock to be removed from the center of the bit for lateral movement when biasing • Short, square profiles are less sensitive to lateral forces generated from the cutting structure interacting with the borehole as less surface area is encountered

PDC v Roller Cone The majority of runs on the PowerDrive tool utilize PDC bit designs, thus maximizing penetration rates and run length. Use of rock bits has been successful on the tool, though from analysis of the run database they tend to be run in the following applications: 1. Non-PDC drillable formations e.g. Chert, Pyrite, etc 2. Applications where high torque is observed 3. Where economics cannot justify the use of a PDC bit

PowerDrive Applications Applications in which PowerDrive is used to perform operations such as sidetracks, kicking off from vertical, and highly deviated wells (where a high percentage of biasing is anticipated for a large portion of the well), selection should be focused on maximum steerability of the bit as per the considerations prior so as to perform the operations efficiently. This will reduce percentage biasing required and promote longer tool life. Note that the use of very aggressive PDC bits in relatively soft formations may hinder steerability as weight on bit drills off rapidly thus limiting the effect of a flex collar (if used) and limiting the time that the pads ‘push’ against the formation in any one place on the wellbore. There has been mixed results observed in directional wells with light set 19mm cutter designs. Applications that involve low biasing (i.e. tangents, vertical, horizontal) do not need to focus as heavily on the steerability aspects. As such, aspects such as bit length, profile, and gauge cutters are not high on the requirement list. Instead, you can focus on maximizing penetration rates and bit life in the application as per a standard rotary assembly.

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Unlike that for PDC bits, there is currently no specific range or set of features for a roller cone bit to be run on PowerDrive. The following are considerations: • Due to the layout of a roller cone design it naturally has an aggressive sidecutting ability • Bit length is generally longer than ‘RS specific’ PDC bits • Selection is primarily related to the geological conditions i.e. rock strength • Bit will endure side loads from the natural biasing mode of operation of the tool. Ensure premium bearings are used. As per normal applications, the run length will be limited by bearing life • Conventional nozzles tend to impinge on the side of the wellbore, which could cause hole erosion in soft formations. This would hinder PowerDrive operation, as there is a limited pad travel distance. Consider the use of extended jets so that impingement is at the bit face

Bit selection for Schlumberger downhole tools Exceed Basic Tool Operation Exceed (formerly known as Direct) is the latest solution from Schlumberger for rotary steerable applications. It does not depend on application of a side force, but works on the “point-the-bit” principle, though a side force is applied when changing toolface or initiating a curve. The steering section contains a universal joint that transmits torque and WOB, but permits the axis of the bit to be at an angular offset from the axis of the tool. This offset allows for the directional drilling tendency of the system to be controlled via 3-point contact with the well. The axis of the shaft is kept offset by a mandrel, which is maintained geostationary during collar rotation.

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The bit axis, when drilling with Direct, leads the hole axis, unlike that on PowerDrive where the bit axis is tilted such that it lags the borehole. As with PowerDrive, some measure of bit sidecutting ability is required when changing toolface. Bit Selection Guidelines Exceed is still in field trials and is currently not commercial. However, some initial work was undertaken with the Exceed engineering team relating to bit selection to match the operating mode of the tool. At this current stage, the following points should be considered when matching bits to this tool. a) Steerability • Short taper, steerable profile • Short bit length to minimize distance between bit face and stabilizer sub on Exceed tool • Gauge design that has cutters positioned on the top of the gauge pad. Fully ‘active gauge’ designs as utilised on PowerDrive are not a requirement for this tool

b) Durability • Due to tilt imposed on the bit by the tool, you may see preferential wear on the shoulder. Selection of secondary cutters or abrasion resistance cutter quality in this region should be considered in hard and abrasive formations c) Stability • Force balancing, tracking, secondary components, and spiral gauge for lateral stability • When compared to PowerDrive, Exceed does have lower tolerance to bit generated torque and thus higher cutter backrakes will aid reduction of torque fluctuations and minimise slip stick potential. Overall, bit designs should not be as aggressive as for that used on PowerDrive, though this is highly dependent on the application • As for above point, consider the cutter size in relation to geology to be drilled It is interesting to note that the majority of field trials with this tool have been conducted with PDC bits that possess design characteristics suited for PowerDrive i.e. profile, bit length. Aggressive gauge variants tend not to be used. As per for all Schlumberger tools, it is a matter of matching the bit first to the tool (profile, length, gauge, cutting structure), then to the formation (cutter size / backrake / density).

Side force rotary steerable tools that rely directly on interaction with the well bore are unable to run bicentre drill bits because the tool cannot apply a side force to the borehole once the reamer has opened the pilot hole. It is considered in some applications highly desirable to run a bicentre bit on a rotary steerable tool. Exceed is the rotary steerable solution to this, and bicentre performance has been demonstrated within the trial runs in Gulf of Mexico applications. One issue with bicentre bits, as for all drive systems, is pass through. For the current Exceed tool the outer diameter above the bit is 7.6” (without stabilizer). The calculation below shows the hole size that can be drilled with a BHA pass through of 8.5”: Max drill size = 8.5 + (8.5-7.6) = 9.4” I.e. maximum bicentre size is 8.5” (drift) x 9.4” (drill) This compares to on a motor or conventional rotary assembly, where it is possible to pass through 8.5” and drill 9.875” hole due to the smaller size of the motor body. Loss of contact between borehole and the stabilizer on the tool sub theoretically could be detrimental to the effective steerability of the tool, though field results do not confirm this to date.

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Bicentre Applications

Bit selection for Schlumberger downhole tools Coiled Tubing Applications As already discussed in the aspects of matching bit to motor, the selection of bit to the drive type is an important factor that can affect both penetration rates and ease of steerability. The key issue when considering bit selection for coiled tubing applications is that you have a small diameter motor that can deliver high rpm but low torque. The torque is problematic when looking at fixed cutter designs, as is the high rpm when dealing with roller cone designs. As such, there is a general cut off point based on the required hole size: • •

Hole size less than 4 ¾” should use fixed cutter bits Hole size equal to, and greater than 4 ¾” can use either roller cone or fixed cutter

a) Fixed Cutter bits

Similarly, the use of impregnated designs for hard formations will perform well at high rpm, and due to their very small cutter size, will produce low reactive torque. There are a number of general characteristics that may prove useful, particularly as the majority of coiled tubing applications require high doglegs: • • • • •

Steerable profile – Short bit length, shallow cone, short taper profile Relatively long gauge to provide predictable doglegs on motors with high bend angles Backreaming cutters Extra gauge protection, particularly for high angle applications The use of fixed ports to maximize distribution of hydraulics energy. This is resultant from the considerably smaller size than interchangeable nozzles thus easier to position around the face of the design.

b) Roller Cone bits The combination of relatively high rotational speed and the small size of the bearings of roller cone bits for coiled tubing applications, means that bearing life and reliability is significantly diminished with reduced bit diameter. As such, risk of losing cones is high and thus, roller cone bits are not recommended for diameter sizes less than 4 ¾”.

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Due to the absence of moving parts, PDC bit designs can handle the high RPM. Resultant of the low torque output from the motor, small diameter cutters must be used (typically 8mm). This will also aid toolface control and provide durability, though the cutter density and blade count will need to be matched to the formation strengths to be drilled.

Roller cone bit selection should consider the following features: • •

Enhanced gauge protection Premium bearing technology

Motor Recommendations The following three points are based on coiled tubing experience in Alaska • • •

Select the largest motor diameter possible Choose a high-speed motor for slim hole (<4 ¾”). Ensure that you obtain highest maximum torque rating for motor type with maximum flow to allow efficient hole cleaning (particularly for shale applications) For 4 3/4" motors, ensure that the maximum stall torque multiplied by a factor of two is less than the maximum allowable torque of the coiled tubing. Use a slow speed motor.

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D E C

D&M—NSA

rilling ngineering

Hole Opening Technology

enter 1) Overview and Applications

Bicentre Bits

Reamers

a) Overview b) Casing Drill Out c) BHA Considerations d) Drilling Practices e) Product Lines

a) String Eccentric b) Fixed Concentric c) Mechanical Concentric

Confidential

Hole Opening Technology Overview Hole openers fall into two main categories; Eccentric and Concentric. Eccentric reamers are fixed reamers that are dominated by bicentre drill bits or ‘wing-like’ string reamer tools using PDC cutters. The concentric openers are more diverse and consist of simple fixed designs such as concentric drill bits and string devices (PDC or roller cone), to more complex tools, which open on demand by either mechanical or hydraulic control. Pro’s and Con’s: Obviously the Hydro / Mechanical devices are more expensive, and as with all moving parts, has the potential to fail. However, due to their concentric nature, they are inherently more stable than the eccentric devices with the greater potential to deliver fully opened hole. Fixed concentric devices are not underreamers, as they do not share the ability to pass through smaller diameter casing such as the eccentric and open on demand concentric tools. Concentric compared to eccentric reamer Balanced cutting structure, less spiral hole

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Reduced side forces, improved steerability

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Reduced lateral vibration. Less vibration provides improved cutting structure life

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Higher potential for consistent hole diameter

Application of Hole Openers Requirement Application Benefit Use largest possible casing in the Run large size casing that drifts Production casing string is restricted only by the ID of the reservoir to improve production intermediate casing in production intermediate casing as the reservoir hole has been under-reamed rates or re-entry wells Increase production rates from Gravel pack production zones in Under-reamed holes improve success rate of gravel pack reservoir unconsolidated zones operations. It allows the use of larger production screens Casing design flexibility

Allows well designers a reduction Under-reaming allows the use of larger OD and ID intermediate in size of the casing program for a casing sizes. well and increases the total number of casing sizes that could be run

Minimize risk of stuck casing while Tight annular sections: Swelling Undereaming increases annular clearance, reduces risk of running in shales, salt creep, poor hole differential sticking, and allows for some degree of swelling stability formation before restricting the bore Minimize risk of lost returns when Tight annular sections which could Undereaming increases annular clearance and thus less chance of running casing cause surge issues when running surge and fracture of formations casing: Swelling shales, salt creep. Improve cement job integrity

Tight annular sections which can Undereaming increases annular clearance allowing for optimal hinder cement progress and cement flow and thickness cause poor integrity

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Hole Opening Technology A) BICENTRE BITS Basics Bicentre basically interprets as a bit design with ‘two centers’. It is eccentric in nature and thus has the ability to pass through small diameter casing and then drill a hole larger than that casing size. With the very rare exception of impregnated drill bits, all bicentre bits are PDC. They consist of a concentric pilot section followed by an eccentric reamer section. They are generally steel bodied. Unlike the one size provided for conventional bits (OD), there are three critical sizes associated with bicentre bits; Pilot diameter, Drift diameter, and Drill diameter. All three are explained in the schematics below.

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The pilot and drill diameter both share the same center, as the eccentric reamer will open up, guided by the pilot bit that is concentric. With drift diameter, the center of rotation is off center, located towards the eccentric reamer.

Hole Opening Technology A) BICENTRE BITS Casing Drill Out Traditionally, bicentre designs have not been capable of drilling out the casing shoe and float equipment as they are designed to pass through the casing ID but not to rotate within the casing. As such, it was conventional to drill out with a concentric drill bit and then pick up the bicentre assembly. As of 1999, DPI (Diamond Products International) introduced into the commercial market the first bicentre design capable of drilling out the shoe and float, eliminating the need to trip and thus a big economical incentive to the operators. Following this, the other major bit manufacturers followed suit so as to produce separate ranges of both conventional and drill out bicentre designs, the latter becoming predominant.

The different approaches by the bit manufacturers in tackling these design requirements will be discussed in the commercial products section.

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There are two key considerations in the design of the drill out bicentre bit. Firstly, the reamer section should not bite into the casing, which would result in both casing and bit damage. Secondly, whilst drilling the shoe in casing, the pilot will not rotate around its usual center and thus the profile and cutter layout of the pilot must be such to provide effective coverage and resist breakage. Impact damage is related to effective backwards motion of cutters within the cone of the pilot lying between the drift and drill centers of rotation.

Hole Opening Technology A) BICENTRE BITS BHA Considerations Stabilizers: Due to the eccentric nature of the bit, you cannot use full gauge stabilizers (based on drill diameter) as they obvious will not pass through the previous casing. However, due to the bicentre drift diameter having a center of rotation that is off center from the center of the drillstring, there are further restrictions on the size of the stabilizer used. Basically, the maximum size of ANY TOOL within 10’ of the bit is defined by the formula below:

Ø DRIFT - (Ø DRILL - Ø DRIFT)

Drift Diameter (")

Drill Diameter (")

4.5 4.75 5.5 5.75 6 6.25 6.5 8.5 8.5 10.375 10.625 12.25 12.25 12.25 14.75

5.75 6 6.25 6.75 7 7.25 7.5 9.5 9.875 11.625 12.25 13.5 14.5 14.75 17.5

Maximum OD of any Tool (") Within 10' from Bit After 30' from Bit 3.25 4.5 3.5 4.75 4.75 5.5 4.75 5.75 5 6 5.25 6.25 5.5 6.5 7.5 8.5 7.125 8.5 9.125 10.375 9 10.625 11 12.25 10 12.25 9.75 12.25 12 14.75

Note: As of early 2003, DPI has introduced the ‘Bi-Center Stabilizer’ (BCS). This stabilizer consists of a split eccentric gauge, which aligns with the reamer of the bicentre bit when passing through casing. When opening up hole, the stabilizer is activated via pressure differential and rotation so that half the gauge section rotates 180 degrees into a full-gauge position, leaving the static half directly opposing. The BCS tool can be placed wherever you wish your conventional stabilizers to be. As of writing, there have been a

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Thus for a 12 ¼” drift that drills a 14 ¾” hole, the maximum near bit tool OD equals 12.25 – (14.75 – 12.25) = 9.75”. Due to the flexibility of the BHA, you can increase the stabilizer OD to that of the drift diameter once you have exceeded a distance of 30’ back from the bit. The table below provides maximum tool size OD for the typical bicentre sizes available. This does NOT take into account any effect of any bend on a directional motor.

number of runs with conventional concentric bits, but only a couple of runs on actual bicentre strings. Downhole Motors: Obviously, the chart prior applies to the motor, and as such, motors are often run ‘slick’. However, an issue has arisen on several occasions, which has resulted in not being able to pass through the casing. This problem has arisen with the thread protector sleeves that have exceeded the pass through constraints imposed. Be fully aware of this and make sure that the OD of any component of any tool is not greater than the pas through constraint. In the two incidents recently observed, both assemblies had to be switched to conventional bits, having a significant knock on effect on the casing program and design of the well.

Rotary Steerable: Under NO circumstances can a bicentre bit be used in conjunction with a side force rotary steerable tool that relies on contact between the steering unit and borehole. Bicentre bits have very recently been used on point-the-bit rotary steerable, though these are also affected by pass through constraints that limit the actual hole opening that can be achieved.

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In motor applications, a high torque, low speed motor is recommended. This is also the case for a straight hole application that may be planned as rotary. The use of the motor in these applications will reduce ‘whipping’ of the string, which is poorly stabilized due to the pass through constraints on the stabilizer OD. It is also important to remember that the drop tendency at high inclinations will be generally be greater with a bicentre bit due to the effect of the eccentric reamer section biting into the low side. Consider this factor when planning the trajectory.

Hole Opening Technology A) BICENTRE BITS Drilling Practices If not using a drill out bicentre bit, it is important to ensure that there is sufficient rat hole below the casing shoe prior to commencing underreaming with the bit. Note, that if already running into open hole, you cannot ream with a conventional bicentre design, as it has no pilot for the reamer to rotate around. The same applies for coming out of hole; You cannot back ream. In both cases the bit will be very unstable and may result in both borehole and bit damage. This is an important consideration when running in with a bicentre on motor and wish to wash down the hole.

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Hole Opening Technology A) BICENTRE BITS Commercial Bicentre Products DPI: This is the market leader in bicentre product and has the highest number of runs. They were first into the market with casing shoe drill out designs, and as such, have continuously evolved and developed this technology. It has two primary bicentre product ranges: • •

SpeedReamer – Standard bicentre designs. Steel bodied design, force balanced, and using ‘split blades’ (every blade does not fully extend from nose to gauge) to aid cleaning and penetration rates. SpeedReamerCSD – This is their casing shoe drill out design. Similar concept to the SpeedReamer but with the pilot profile and cutter layout orientated to aid drill out.

Hughes Christensen: Prior to the growth of the bicentre market, Hughes were strong performers with their string reamer (eccentric) tool. In response, they have adapted their reamer tool so that it can connect direct to a drill bit and thus make it a bicentre assembly. The big advantage of this methodology is that they can place any bit on the end of the PDC reamer tool, including rock bits, which may be advantageous in certain applications. The disadvantage is that this bicentre assembly is the longest in the market place thus affecting both steerability and stability (and thus poor hole opening). The top of the reamer section uses passive pads opposing the eccentric reamer which also add to the length of the tool and separates the pilot from the reamer In slim hole applications, Hughes produce a one piece, matrix bodied design, thus no flexibility in pilot. It also employs these passive pads, thus this is still a long tool. There are three product ranges: • SRWD = Reamer and pilot coupled together to form 2-piece bicentre assembly • STRWD = 1-piece reamer and bit assembly for slim hole • DOSRWD = Drill out 2-piece bicentre assembly. Often uses rock bit for drill out

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Both ranges use a large separation between the reamer and pilot (marketed for helping formation to cave-in) and are generally lighter set than competitor product. The separation causes long bit length which is a detriment to potential build / turn rates. It may also be a problem when drilling in WBM for cuttings removal. They are generally fast drillers, achieving speed by sacrificing durability.

The Quad range is promoted with the following features: • Drill-out capability. Uses a second gauge (‘Drift Gauge’) to maintain the shoulder / gauge cutting structure away from the casing • Directional capability. Balanced cutting structure to improve bit stability • Hole integrity. Stability enhanced cutting structure to ensure the pilot drills a true gauge hole. This allows the reamer to rotate truly and open hole appropriately Reed-Hycalog: There are two product lines within Hycalog. The first is the conventional bicentre designs (DS100 – 102). The second is known as ‘Stabil Bicentrix’, which is the latest drill out capable range, which also markets the designs as both stable and steerable. Both are one piece, steel bodied designs with straight blades. The Stabil Bicentrix range is notably shorter and is promoted as such for improved steerability. Other features marketed include: • Steering Wheel concept. Use in both the pilot and reamer section. In the pilot, it aids stabilization to drill a true gauge hole. The use on the reamer is to prevent the gauge cutters contacting the casing and to provide resistance to drop and thus aid steerability • Force balancing. Using short blades opposite to the reamer so that cutters can be placed to balance cutter forces • Cutter devoid area. This is located in the cone of the pilot to ensure that cutters are not damaged when drilling around the drift diameter in casing. Secondary cutters are positioned for effective drill out. • Flat profile. The cone of the pilot has a flat profile to aid steerability

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Smith: The current bicentre range are known as the ‘Quad D Dual Diameter’ bits (Shortened to Quad). They use a one piece steel bodied design, typically with spiraled blades and continuous gauge. They have a diverse range in both size and type and good experience, aided particularly by the Shell contract. They are generally solid performers with little problems.

The use of the steering wheel is specific to Hycalog, though apart from that, the design philosophy is similar to that of Smith. The performance has been good overall though tends to be slower than the competition due to greater durability. The range is diverging into lighter set product for improved ROP performance.

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Hole Opening Technology B) REAMERS String Reamers This is basically the reamer section of a bicentre bit as an independent string tool that can be placed at distance from the actual pilot bit. It is a similar geometry to the bicentre reamer section and has similar constraints. It is generally steel bodied with PDC cutters. It may be supplied with or without nozzles. A typical example of use is when using a rotary steerable tool that needs to be located directly behind the pilot bit. Another is when the stability and directional capabilities of a conventional concentric bit are required, with the hole being opened after critical elements of the BHA have passed through.

Due to their similarity to bicentre bits, most bit manufacturers make both reamers and bicentre designs. Smith have adapted their Quad D bicentre range to provide the ‘Quad D Reamer’. For Hughes, it is even easier as their basic bicentre bit is a pilot bit connected to a string reamer. Their product is known as ‘RWD’.

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Although they can be run in the same assembly as the pilot bit, the key benefit of a string reamer over a bicentre design is that it can be used to open a predrilled pilot hole on a dedicated hole-opening run. It is important in this instance to stabilize and guide the hole opener using either a used drill bit or an appropriately sized bull nose. This is an inert sub that replaces the bit and is used simply to keep the assembly in the predrilled hole. The term ‘appropriate sized’ means consider what the bull nose is supposed to do i.e. an 8” diameter bull nose isn’t going to do much in stabilizing the hole opener in a 12 ¼” pilot hole!

Hole Opening Technology B) REAMERS Fixed Concentric Reamers This reamer group comes in a variety of forms. It simply opens up a concentric pilot hole to a larger diameter. Due to its fixed nature, it is not used to pass through small ID casing and then open a larger hole. Generally it is used for one of two reasons. The first is to directly open hole behind the pilot bit based on the theory that once the inner diameter of formation is removed the rock is not as confined and thus it is easy to open up to the larger diameter. This is a concept used in some regions for hard rock drilling. The second is similar to that of the eccentric sting reamer, in that it is placed upstring of parts of the BHA for either efficient operation (Rotary Steerable) or in order to keep the steerability of a smaller diameter bit then open up. In either case, casing pass through is not an issue and thus fixed reamers can be used. Due to their concentric nature, they are inherently more stable than an eccentric reamer.

1. Single piece reamer and pilot bit. This is particularly promote by DPI (SpeedDrill range) 2. PDC reamer section as a separate tool to be placed in the string. Usually contains both a reamer section and a gauge section equal to that of the pilot hole. Again, as per the eccentric string reamer, this may be used in the same assembly as the pilot bit or on a dedicated hole opening run with bull nose / dull bit 3. As above but with roller cone cutting structure (1)

(2)

(3)

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They are commercially available in three key forms:

Hole Opening Technology B) REAMERS Hydraulic / Mechanical Concentric Reamers There are a number of tools that have pads or arms containing cutters that can be actuated and retracted so that the tool can pass through small ID casing and then open out to ream a larger hole. At the end of the run, the cutters can be retracted so that it can be pulled back through the casing. Security DBS: Known as the NBR (Near Bit Reamer). It consists of three pads with relatively light set PDC cutting elements. The pads are extended hydraulically. There are no dedicated reamer nozzles.

The Anderreamer can be run either directly behind the bit or further back in the drill string, which means that it is capable of both drilling pilot and oversize hole in one run or simply underreaming an existing hole. The Andergauge website lists extensive experience gained with each of the key commercial rotary steerable tools where Anderreamer was run above the RS tool in the BHA.

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Andergauge: This company produces the Anderreamer tool, which consists of three sets of cutter blocks (PDC) that are extended by either mechanical (weight) or hydraulic means. Each cutter block has a dedicated nozzle for cleaning. The cutter blocks are interchangeable and vary depending on the application

Tri Max: The Tri Max tool is known as EWD (Enlarge While Drilling). It is activated mechanically by shearing pins at a pre-set weight. This forces the reaming blocks out which are then locked in place until the section is completed. It uses three cutter blocks that are set with three rows of 13mm PDC cutters (option of TCI inserts), and has one dedicated nozzle per block. It was designed specifically to be run behind the bit, prior to the motor, and as such is equipped with a box down bit sub. Versions have been created to be run behind a rotary steerable tool, which are identical except for the lower connection. The EWD tool is available in sizes ranging from 22” (using 17 ½” pilot), down to 6 ¼” (4 ¼” - 4 ¾” pilot). It is simple in construction and activation. The very latest design from Tri Max is a one-piece mechanical reamer that combines both the bit and reamer. As such, the reamer is very close to the pilot and is thus marketed as being a steerable assembly. The downside is the flexibility in bit design. The technology for the mechanical reamer is identical to that for EWD and is different only in the fact that the bit is part of the assembly. This has only just been released and is known as TBR (Tri-Bit Reamer).

The cutter blocks are interchangeable and each has a dedicated nozzle. One of the key differences with this tool is that the cutters extend both uphole and downhole with a stabilizing gauge pad located in between. This provides an excellent backreaming structure that has enabled some operators to consider reaming when coming out of hole as opposed to conventional reaming while drilling. The RHINO range has nomenclature based on the minimum collapsed diameter of the tool i.e. Series 8000 is 8” whilst Series 16000 is 16”, etc. As with all the mechanical concentric tools, RHINO can be run both as a simultaneous pilot drilling and hole opening operation, or an independent hole opening of an existing pilot hole. With all string reamers that have nozzles, remember to configure your MWD tool to take into account the flow loss at the reamer, typically 20% to 25%. The balance of hydraulic energy between bit and reamer is an important aspect and will be discussed further in the hydraulics section.

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Smith Tool: The very latest offering from Smith is the RHINO range of reamers. This is a hydraulically activated reamer, again with three cutter blocks mounted with PDC cutters. However, the actuated block moves along a tongue and groove section which supplies full support to the block at all times. The blocks open and retract with the pumps being turned on and off, though incorporates a mechanism that doesn’t release the blocks until you are safely out of the casing shoe.

Bit selection for Schlumberger downhole tools Hydraulics considerations Motor bearings - In order to effectively divert mud across the radial and axial bearings of the motor, a minimum pressure drop across the bit of 250 psi is required. For low bit pressure applications, specific bearings exist that only require a minimum of 100 psi pressure drop. Though in most situations, these pressure drops are easily attainable, there may be issues when bits with large TFA’s are run. The maximum pressure drop for the bearings is 1500 psi The PowerDrive tool, irrespective of size, requires a pressure drop ideally in the range of 650 to 750 psi. This is conventionally attained via the use of the bit nozzles, though an internal restrictor within the tool may be an option. In terms of bit selection, ensure that the bit design has an appropriate number of nozzles for the planned mud weight and flow rate of the application. You should avoid designs with high nozzle counts, which require either small jet sizes (LCM issues) or having to blank off jets (poor hydraulic distribution). Schlumberger Private

Bit selection for Schlumberger downhole tools Detailed Steerability aspects – PDC bits A) 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 of each of these will define the overall profile.

The cone is generally lighter set as the isolated rock has been relieved of confining forces and 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 point on both the cone angle and radius of the shoulder – Small nose radius is generally used for 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 wear greatest under normal conditions. Cutter backrake, quantity, and size is 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. The length is usually defined by the cutter coverage required for durability and experiences the 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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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 already encountered and drilled formation, isolating a section of formation within the cone. This resultant central cone of rock acts as resistant to lateral movement. Thus the angle of the cone, and hence cone volume, will affect the stability of the bit. Deeper cones will mean that there is more volume of rock and thus greater stability. The inverse effect is seen on steerability; Deeper cones reduce steerability, as more rock needs to be overcome to attain deviation.

require a long shoulder section in order to maximise cutter count. Bits on rotary assemblies will experience much lower rotational speeds and thus may have a shorter shoulder section. Of course, anticipated lithology is another major factor in shoulder durability. Gauge: This is where the shoulder extends to the full diameter of the bit design. The gauge is generally observed on a bit as where the blade extends out and forms a solid gauge pad that will contact the borehole when drilling ahead. The gauge is usually protected with a variety of applied or inserted components, as well as gauge cutter coverage (usually pre-flatted to offer large PDC area). There are a vast variety of gauge geometries dependant on the specific application and manufacturer, though one common factor to all is gauge length. It is generally considered that longer gauge lengths provide more stability in rotation due to increased surface contact between bit and borehole. However, the attainable build rate of long gauge designs are constrained and a short gauge bit can be more easily tilted in the wellbore and thus more steerable. As such, the general rule is: •

The exact quantitative definition of ‘short’, ‘standard’, and ‘long’ gauge length is variable with bit manufacturer though they are all within the same ballpark. General values for these lengths derived from two of the leading PDC manufacturers are provided below as a guideline. Bit Diameter 2 - 4 3/4" 5 - 6 3/4" 7 - 9 7/8" 9 7/8 - 12 1/4" 12 1/2 - 14 3/4" 14 3/4 - 18" >18"

Short 3/4 - 1" 1 1/4" 1 1/2" 2" 2 1/2" 2 1/2" 3 - 4"

Standard 1 1/4 - 1 1/2" 1 1/2 - 2 1/2" 2 - 3" 2 1/2 - 3 1/2" 3 - 4" 3 - 5" 5 - 7"

Long >2" >2 1/2" >3" >3 1/2" >4" >5" >7"

B) Bit Length

The overall bit length is defined by three elements: The length of the shoulder, the gauge length, and the length of the shank (standard for most individual manufacturers but diverse from each other). Note that the shank length of steel bits is less than that for matrix as it is an integral part of the body. As such, steel bodied designs are shorter when comparing like for like profiles.

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Short = Steerable, Reduced borehole quality, less borehole contact, directional applications Long = Good borehole quality, increased borehole contact, reduced steerability, vertical / tangent sections, turbine / high speed motor applications

As with that for profiles, the shorter the bit length, the more steerable the bit design is. This can be explained via two chains of thought. Firstly, as potential dogleg is defined by three points of contact, the greater the distance from bit to second point (RS Bias unit, Bend, etc), the lower the dogleg will be. Secondly, if you consider that in order to deviate in hole, the bit is tilted, you require a higher degree of lateral movement to achieve the tilt with a longer bit design. With a short design, there is less contact with the wellbore and thus a reduced lateral cut is required by the bit to achieve the tilt imposed.

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Bit selection for Schlumberger downhole tools Side Track Applications This section relates to bit selection for open hole sidetracks i.e. not scenarios using whip stock to mill and exit the casing. It relates primarily to use on motors, as the bit design aspects in terms of profile, length, and gauge cutting structure are generally suited to this application on bits designed for, and used on PowerDrive. The sidetrack bit should have the following aspects. Note that these relate to PDC drill bits only. Roller cone designs with aggressive gauges can be used to sidetrack, though they are at the disadvantage of being considerably longer than that of a specific PDC sidetrack design. • •

•

• • •

The schematics overleaf provide a visual impression of the type of profile and the blade / cutter layouts.

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Flat profile – Flat cone with sharp break over from nose to gauge. No apparent shoulder section. Very short bit length – Both profile and overall bit length should be as short as possible. As such, steel bodied designs are optimal. Due to short run lengths, erosion will not be an issue. Bit lengths should be in the range of 7” for a 12 ¼” diameter bit, and 5.5” for an 8 ½” diameter bit. Very short gauge – Due to the sharp break over of profile, the gauge is basically the only sidewall contact between the bit and borehole. This should be as short as possible so that deviation can be easily performed quickly. Gauge length should be around 1”. Aggressive gauge – In order to deviate efficiently, a high number of full round PDC cutters need to be mounted on the gauge. Due to the short gauge length, sidetrack bits tend to have a relatively high number of blades of which the majority extend from gauge to nose only. A small number extend to the cone of the design to provide cutter coverage. Due to the fact that most sidetrack runs are in the region of 50-200ft in length, durability is not of a great concern. Directionally friendly – In order to control the kick-off in the correct direction, the gauge cutter backrake should be in the region of 30 degrees so as to avoid torque fluctuations. 13mm PDC cutters will also aid directional control. Match geology – Although sidetrack runs are generally short, the design must still match the compressive strength of the rock drilled, though you can go lighter set than normal. In addition to PDC bits, most manufacturers produce a natural diamond / impregnated bit for hard and abrasive applications. They follow the same guidelines above in terms of the profile.

b) Side View

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a) Face View

Shoe / Float Drill out Considerations Roller cone designs are suited to drilling out shoe and float assembles. Caution must be taken when running fixed cutter designs so as to avoid breakage of the cutting structure and thus premature termination of the run. If planning to drill out with a PDC bit, you must ensure that ‘PDC friendly’ equipment is to be used i.e. a greater concentration of plastic and rubber components make for an easier drill out. Remember, PDC is not suited to drilling steel! Liner running tools and float equipment that require an activating ball to set up or close the liner hanger or float valve can pose problems for drilling out, as the balls (typically made of brass) are difficult to drill and tend to rattle within the junk slot areas of the bit causing extensive cutter damage. Aluminium components can also be problematic as they can plug the junk slots resulting in poor cooling and cuttings removal.

If there is any doubt concerning the shoe / float material used, it would be prudent to run a rock bit design, prior to running the optimal assembly for the formation. Although the rock bit will effectively drill the shoe, it too will be potentially subject to damage and thus careful control of the parameters should be utilised (See bit running guidelines). This is the same case if it is anticipated that junk will be drilled. In both scenarios, the optimal product will be a Milled tooth design with short tooth length.

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Note that impreg and natural diamond bits, due to their less aggressive cutting structure, will take, on average, 25-50% longer than a conventional PDC design to drill out. Some bit manufacturers have experimented with TSP discs that are considerably exposed by several millimetres out of the body to act similar to a PDC cutter. This is done with the intention of increased exposure to reduce the time taken to drill out the shoe / float equipment. Likewise, the increased number of impreg designs with more aggressive ridged profiles should also be beneficial.

D E C

Drill Bit Hydraulics

1. Basic Bit Hydraulics

5. PDC Hydraulics

2. Hydraulics Optimization

6. Diamond Hydraulics

3. Tool Considerations

7. Mud Considerations

4. Roller Cone Hydraulics

8. Temperature Limitations

D&M—NSA

rilling ngineering

enter

Confidential

Drill Bit Hydraulics Basics The hydraulics generated at the bit face has three key objectives: 1. Cool the cutting elements of the bit 2. Remove the cuttings from the bit face 3. Clean the cuttings from the hole bottom In addition, in certain applications, they may also be used to • • •

Remove formation by jetting Provide pressure drop for tool operation (RS) Provide pressure drop for cooling and lubricating bearings (PDM)

There are five factors relating to bit hydraulics of importance. These are defined as follows: Schlumberger Private

a) Nozzle Flow Area: Detailed text concerning the nozzles of both PDC and roller cone products can be found under the relevant design features sections. The important aspect is the total flow area (TFA) of the sum of all the nozzles used in the bit design. The flow area of each nozzle is the smallest cross sectional area (expressed in square inches) of the nozzle jet used. TFA is simply the addition of each of these cross sectional areas. A quick summary chart for standard nozzles is supplied below for ease of determining the TFA. Number of Nozzles

Nozzle Size (in.) 1

2

3

4

5

6

7

8

9

7/32

0.030

0.075

0.113

0.150

0.188

0.225

0.263

0.301

0.338

8/32

0.049

0.098

0.147

0.196

0.245

0.295

0.344

0.393

0.442

9/32

0.062

0.124

0.186

0.249

0.311

0.373

0.435

0.497

0.559

10/32

0.077

0.153

0.230

0.307

0.383

0.460

0.537

0.614

0.690

11/32

0.093

0.186

0.278

0.371

0.464

0.557

0.650

0.742

0.835

12/32

0.110

0.221

0.331

0.442

0.552

0.663

0.773

0.884

0.994

13/32

0.130

0.259

0.389

0.518

0.648

0.778

0.907

1.037

1.167

14/32

0.150

0.301

0.451

0.601

0.752

0.902

1.052

1.203

1.353

15/32

0.173

0.345

0.518

0.690

0.863

1.035

1.208

1.381

1.553

16/32

0.196

0.393

0.589

0.785

0.982

1.178

1.374

1.571

1.767

18/32

0.249

0.497

0.746

0.994

1.243

1.491

1.740

1.988

2.237

20/32

0.307

0.614

0.920

1.227

1.534

1.841

2.148

2.454

2.761

22/32

0.371

0.742

1.114

1.485

1.856

2.227

2.599

2.970

3.341

24/32

0.442

0.884

1.325

1.767

2.209

2.651

3.093

3.534

3.976

26/32

0.519

1.037

1.556

2.074

2.593

3.111

3.630

4.148

4.667

28/32

0.601

1.203

1.804

2.405

3.007

3.608

4.209

4.811

5.412

b) Nozzle Pressure Drop. The amount of pressure drop (psi) as the drilling fluid passes through the nozzles. c) Hydraulic Horsepower: The amount of energy (in horsepower) created by the fluid as it exits the nozzles, per square inch of the cross sectional area of the hole being drilled. Units are expressed as Horsepower per square inch (HSI). d) Jet Impact Force (JIF): The force created against the wellbore, in pounds per foot, as the fluid exits the individual nozzle jets. e) Nozzle Velocity: The speed at which the fluid exits the individual nozzles. Recorded in feet per second. Of these aspects, the two key parameters that are required for hydraulics optimization of the bit are the hydraulic horsepower and the jet impact force. The optimization of these values will be carried out by changes in flow rate, mud weight, and the TFA of the actual bit used. Resultant from this, nozzle velocity and pressure drop will be derived once the TFA has been decided and fixed. Schlumberger Private

Bit Hydraulics Hydraulics Optimization 1) HSI Hydraulics horsepower should be maximized when drilling in applications where balling may be a concern. Such applications will include deep holes, the use of high mud weights, and reactive formations with water based muds,

•

Maximum HSI is obtained when the nozzle pressure drop is equal to 65% of the total standpipe pressure. This can be modeled in the Hydraulics program by modifying the TFA of the bit.

•

Optimal HSI for drill bits is in the range of 3 to 7, with the higher values increasingly beneficial to drilling in balling conditions.

•

The optimal HSI may not always be reachable due to other hydraulic limitations. Thus, additional factors that will assist (asides from mud additives) in resisting bit balling will be the actual design of the bit itself. Maximizing face volume, low blade count (PDC), and good cutter spacing, will all help.

2) JIF •

Jet impact force should be maximized in applications where both cuttings returns and bit balling are potential problems.

•

General applications are shallow holes, drilling at high penetration rates through reactive formations.

•

High JIF will also assist in removal of formation by jetting. Be aware that this may cause issues with hole washout in certain situations

•

Maximum JIF is obtained when the bit pressure drop is equal to 50% of the total pump pressure

•

Note: If using a center jet on a roller cone bit, the flow area of that nozzle should not exceed 18% for the total TFA

3) Flow Rate •

The flow rate should exceed the critical transport rate for efficient removal of cuttings, taking into account, hole geometry and trajectory

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•

•

If using high flow rates, ensure that the bit to be used has the capacity for large size nozzles, as these will be required to avoid excessive standpipe pressure. Multiple jets are also beneficial so that a good balance of HSI and JIF can also be obtained

•

Flow rates should ideally be approximately 30 to 50 gpm, per inch of the bit diameter for small diameter bits. Flow rates for larger diameter bits should be in the range of 40 to 70 gpm per inch diameter. See table below for flow rate guidelines, though note that these are NOT limitations. Flow Rate (gpm)

3 1/8

80 - 160

6 1/8

175 - 300

8 1/2

350 - 550

9 7/8

400 - 700

12 1/4

550 - 900

14 3/4

700 - 1050

17 1/2

750 - 1200

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Bit Size (")

Drill Bit Hydraulics Tool Considerations a) PowerDrive. This tool requires a pressure drop in the region of 500 to 800 psi, though ideally 650 to 700 psi. This is constant across the range of tool sizes and is generally attained via the pressure drop across the bit, which is reliant on the correct nozzling. In some applications, nozzling of the bit to attain this required pressure drop is not possible. In these instances, you should implement an internal flow restrictor that sits within the PowerDrive tool (basically, this is an internal centre jet nozzle). Total pressure drop is calculated via the addition of pressure drop across the bit plus that across the centre jet, as these nozzles are in series. b) Motor bearings. In order to effectively divert mud across the radial and axial bearings of the motor, a minimum pressure drop across the bit of 250 psi is required. For low bit pressure applications, specific bearings exist that only require a minimum of 100 psi pressure drop. Though in most situations, these pressure drops are easily attainable, there may be issues when bits with large TFA’s are run. The maximum pressure drop for the bearings is 1500 psi Schlumberger Private

c) Nozzle blanking. In certain applications it may be desirable or necessary to blank one or more of the nozzles (i.e. effectively seal the nozzle closed using nozzle blanks). Blanking nozzles will provide cross flow, but will also leave a segment of the bit with low hydraulic energy. When considering which nozzle to blank, on PDC bits you should select a nozzle that is at the greatest radial distance from the centre of the bit and one that does not clean a primary blade. With roller cone designs, you should blank the nozzle that cleans the cone with the least gauge cutter elements.

Bit Hydraulics Roller Cone Hydraulics Roller cone bit hydraulics are restricted in terms, primarily, of nozzle quantity; There is typically only one nozzle per cone, thus three nozzles per bit. However, there is also the option, particularly on large bit sizes (>17 ½”) of a center jet. This enables good flow to reach the center of the bit, which is often starved in large bits due to the diameter affecting the proximity of the standard nozzles from the center. Another important factor is that these large sized bits commonly drill soft sticky formations in top hole sections, thus the center jet provides useful add ional cleaning. There is also the option to ‘multiple port’ the central nozzle so that you can further optimize jet force and flow direction.

There are a number of common features specific to roller cone nozzle arrangements: •

Extended nozzles: The nozzle exit is extended so that it is closer to formation, improving the jet efficiency for cone cleaning and removing formation. High flow tubes are a similar concept that will accommodate a larger range in jet sizes.

•

Asymmetric nozzles: Large variation in selected nozzles sizes on the bit in order to create cross flow across the face of the bit. An extreme variation would be to actually blank off one of the nozzles to generate this.

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Centre Jet

•

Commercial arrangements: There are a number of nozzle design concepts marketed by the bit manufacturers. These primarily relate to the orientation of the nozzles and their impingement points on the bit. For example: o Mudpick – Developed by Reed. The nozzles are angled to focus the mud flow across the gauge teeth o Clean Sweep – The mud flow is directed backwards across the cutting structure. Hughes

Note: The nozzles used are replaceable and interchangeable in the field to enable hydraulic optimization. They are generally retained in the nozzle housing via a circlip. The nozzle types used by bit manufacturers vary and are often not interchangeable with those used by a separate manufacturer. Ensure sufficient, appropriate, nozzles are available at the rig site.

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Bit Hydraulics PDC Hydraulics A) Nozzles: Nozzle placement is ideally such to provide efficient cutter cooling and cuttings removal from the face of the bit, achieved via adequate radial distribution and quantity of nozzles. The impingement points of the nozzle on the bit profile must also be set so as to avoid body erosion and stagnant flow areas. There are two primary forms of nozzles: •

Interchangeable: One or two-piece designs with varied jet size that screw into a nozzle housing located on the bit. Key interchangeable nozzle types and their associated jet ranges can be viewed in the table below.

•

Fixed: Often referred to as ‘ports’. Generally unchangeable jet size in the field. Some bit suppliers do have the option to seal, or close, the fixed nozzle.

Nozzle Type AAK BBK DDK Series 30 Series 55 Series 60 Series 65 Series 70 Series 75 Series 95 Series 100

Jet Sizes (x 1/32") Min Max 8 8 8 7 7 7 7 7 8 7 8

16 24 32 13 16 22 20 24 28 32 28

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Unlike roller cone designs, both quantity and combination will vary significantly from bit to bit, and thus it is important to clarify nozzle type, quantity, and range of jet sizes when planning bit hydraulics so as you do not derive a TFA which is unobtainable with that specific bit. You should also check that suitable jet sizes and appropriate wrenches are available at the rig site.

Jet optimization will be dependent on factors such as pump pressure limitations, diversion of flow for cooling bearings, pressure drop requirement for PowerDrive, etc. However, if possible, the drill bit should be optimized in terms of Hydraulic horsepower per Square Inch (HSI) in the range of 3-6, particularly when drilling shales / clays. Low HSI values may impede potential penetration rates and could lead to balling issues. There are some ‘alternative’ nozzle arrangements commercially available from the bit manufacturers. There are marketed as follows: Switchblade – Designed by Hycalog and also known as ‘transformation’ or ‘venturi’ hydraulics. The nozzles are arranged in multiple pairs. A venturi effect pulls flow from one nozzle that cleans a minor blade, to support a second nozzle that cleans a major blade. The key objective is to divert maximum cleaning across the blades which remove the most material

•

Lateral Jets – Jets which direct flow across the junk slots for enhanced cooling and cleaning. They are generally situated in the cone of the bit, exiting from the blades that extend into this region. These are promoted by BBL

•

Vortex nozzles – Produced by DBS. These can be identified with an off center exit hole of the nozzle jet. They are designed to create a negative impingement pressure at the formation interface to increase turbulence under the bit. They are promoted as improving cleaning due to this turbulence and the fact that the negative pressure will create an underbalance situation at the interface.

Note: The nozzles used are replaceable and interchangeable in the field to enable hydraulic optimization. They are generally retained in the nozzle housing by screwing them into a threaded connection in the bit body. The nozzle types used by bit manufacturers vary and are often not interchangeable with those used by a separate manufacturer. Ensure sufficient, appropriate, nozzles are available at the rig site. B) Flow Area: JSA, JSV, NFV are three acronyms relate to bit volume available for cuttings removal. 1. JSA – Junk Slot Area: This is the 2D area between the blades, extending from the milled or waterway profile (i.e. where blades join body) to the outer gauge diameter. It is measured perpendicular to the axis of drilling. JSA is usually quoted in square inches. 2. JSV – Junk Slot Volume: This is the volume of the bit between the blades over the entire face profile. Also referred to as OFV (Open Face Volume). It is generally expressed in cubic inches. 3. NFV – Normalized Face Volume: This is the normalization of the OFV for bit size and profile length by taking into account the total face volume of the bit (i.e.

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•

the total volume of material removed by the bit profile). It is expressed as a percentage. With all three, the higher the value, the better the cleaning capability of the design, which may result in higher penetration rates, depending on the application e.g. Good cleaning in soft sticky formations is essential to avoid balling and maintain high ROP. Due to the variation in profiles and bit characteristics such as blade heights, widths, etc, the most beneficial feature for comparing designs is NFV, as JSV can be misleading. Average values taken for a very light and relatively heavyset bit design is displayed below to provide a sense of the range of values per size. Note that the NFV is normalized for size, thus you can observe that the range is approximately 34 to 73%, with the latter being optimal for cleaning. 8 1/2"

Bit Size

12 1/4"

17 1/2"

Light

Heavy

Light

Heavy

Light

Heavy

JSA (sq.in.)

24

10

46

19

95

60

JSV (cu. in.)

78

64

330

147

688

439

NFV (%)

73

45

71

34

70

40

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Density

Bit Hydraulics Diamond Hydraulics Unlike that for roller cone and PDC bits, there are no interchangeable nozzles for diamond bits. Instead the flow passes through the cone of the design and is distributed across the face of the bit using one of two general flow patterns. Crossflow: This is where the flow is directed down several key waterways (feeders), which in turn are split and branched. Waterways on the bit face are created which are not connected in any means to the feeders (known as collectors). These are intended to create a low-pressure area and draw flow across the bit face to them. The key downside is that you get areas with low flow, which may be susceptible to plugging.

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Radial flow: All waterways connect to the central crowfoot. This results in all areas of the bit having equal flow, eliminating areas of low pressure. It provides the fastest layout for cuttings removal and optimal cooling with low pressure drop across the face.

Although formation removal is still a requirement for diamond drill bits, the key requirement is cooling of the diamond as they are usually operated at high rotational speeds with low depths of cut. The total flow area of a diamond bit is comprised of two parts; Firstly the area within the fluid courses (FCA) and secondly, the area created by the diamond exposure between formation and the bit face (DEA).

Note that the degree of exposure is very limited and may well be in the range of 0.03 to 0.045”, depending on the size of the diamonds used.

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Drill Bit Hydraulics Mud Considerations The main concern is with the mud chemistry, primarily for its effect on the elastomers used in the seals on roller cone bits. Use of oil based and synthetic muds may cause deterioration of these elastomers, though this generally occurs over a much longer time period than the bit will be run for, but may be a factor for re-running bits. The percentage content of either sand or solids in the mud will also affect the drill bit, both fixed cutter as well as roller cone. With the latter, high solids / sand content can abrade the seal and sealing surfaces, or the actual bearing itself on unsealed variants. Likewise, for fixed cutter bits, high sand content can abrade body components, particularly in the cone and nose of the bit, which is generally closer to the nozzles. Steel bodied designs will fare worst, though hard facing will slow the process. Matrix bodied designs have higher abrasion resistance and are thus more suitable for long intervals in very abrasive conditions. Schlumberger Private

Drill Bit Hydraulics Temperature Restrictions Heat generation on a drill bit is predominantly resultant from friction. In the case of PDC and impreg bits, this frictional heat is generated from interaction of the formation with the cutting elements. In a roller cone bit, the heat is generated between the seal and the journal. This heat should effectively be dissipated by the drilling fluid. However, in high temperature wells, the fluid is also at a high temperature and thus has less capability to remove heat from the drill bit. It is this factor, as opposed to the actual temperature of the well that is the issue when drilling in high temperature applications. a) Fixed Cutter designs

Frictional heat will drastically increase if the blade tops begin to rub on the formation due to excessive cutter wear. The heat build up will potentially generate surface cracks within both the blade top and the supporting substrate of the PDC cutter (known as ‘Heat checking’). This could lead to chipping or breakage of the PDC, but at this stage, with the cutter worn down to the blade, cutter life and performance cannot really be reduced by any great amount. Note that heat checking on blades will appear more frequently on matrix bodied bits due to its lower conductivity properties as compared to a steel bodied design. Basically, due to similar thermal properties of PDC, any fixed cutter product can be run without any great concern in high temperature wells. b) Roller Cone bits A rotating bearing generates heat, which in a roller cone design should be dissipated by the grease, thus through the bit and the seal. As such, there are two components which may degrade from constant exposure to high temperatures; The grease and the seal. •

Grease used to lubricate roller cone bearings has a ‘dropping point’ (point at which viscosity breaks down) in excess of 500 F (260 C). Circulating temperatures will rarely approach this figure, though you must be wary of high exposure to static conditions. Even so, the temperature specification greatly exceeds that of the seal.

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Due to the high thermal properties of the cutting elements, it is extremely rare to see thermal degradation of the PDC due to excessive heat build up under normal drilling practices in high temperature applications. It is possible to see localised degradation at the cutting edge, as this is where the high frictional heat is generated. If this is observed on dull bits, then you may consider optimising the WOB and RPM to reduce the frictional heat, though as stated prior, this is extremely rare.

•

Typically, the elastomer used in the seals is the weakest link in terms of thermal exposure. An approximate estimate of the temperature capability of the elastomer is 300 F (150 C), though this will vary with manufacturer. As per above, exposure is an important factor – Continuous exposure will gradually affect the tensile and hardness properties of the seal resulting in reduced compression. The rate of degradation will increase rapidly with temperatures exceeding 300 F, thus continual circulation to fully maximise the cooling effect of the drilling fluid is essential. Generally, the use of circulating ‘fresh’ mud from surface will effectively reduce the downhole temperature considerably below the static temperature of the well and ensure that seal degradation is minimised.

Applications that see continual circulating temperatures above this 300 F figure should consider the use of metal face seals to maximise run time. Obviously, the metallic material used has a higher temperature rating and thus will not degrade at the rate of the elastomer.

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In applications where the drilling fluid will be air or mist, the use of unsealed bearings should be considered. This is due to the fact that there is insufficient downhole pressure to force the grease across the bearing surface and thus poor cooling of the bearing. An unsealed bearing will at least allow continual refreshment of the drilling fluid over the bearing components.

D E C

D&M—NSA

rilling

Stability Aspects

ngineering

enter

1. Whirl - General

4. Stick-Slip - General

2. Whirl – Bit Aspects

5. Stick-Slip – Bit Aspects

3. Whirl – Specific Bit Designs

6. Axial Vibration - General

Confidential

Stability Aspects Bit Whirl – General A) Mechanism: Bit whirl is the rotation of the bit off its natural center of rotation in an eccentric manner. Resultant from a combination of excessive side cutting forces and frictional contact with the gauge, the center of rotation moves and creates a momentary center of rotation at a gauge pad of the design. As the bit rotates about this new center, the next blade impacts the wellbore and the center of rotation moves to this point. As this continues, a lobed pattern develops in the wellbore and essentially you obtain a gearing effect between bit and wellbore. The number of lobes generated is a factor of the number of blades of the design plus one e.g. for a six bladed design you would observe either 7, 13, 19 lobes etc. Whirl type vibrations are generally high frequency, in the range of 10-50 Hz.

4

3

1

7 Lobed pattern for 6 bladed design

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B) Identification: This falls into two categories; Identification from parameters and downhole tools whilst drilling, and post evaluation of the drill bit and BHA. • • •

Increased surface torque Large downhole lateral shocks Over gauge hole

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Cutter damage on shoulder and gauge Blade breakage (worst case) Uneven stabilizer wear

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C) Effects: • • • • • •

Reduced bit life = Increased trips Extreme bit damage may require junk recovery / milling trips Undergauge bits resulting in reaming requirement Reduced penetration rates = more rig time Poor borehole quality leading to logging / casing issues Damage to downhole tools & other components of the BHA

D) Cures: This falls into two categories; Drilling parameters and bit selection. In terms of parameters, a combination of high RPM and low weight on bit will increase whirl tendency. This is due to the fact that a low depth of cut is established and thus the bit is more susceptible to moving off its natural center of rotation. Gradually increasing weight at a specific rpm will enable you to optimize parameters to combat whirl. Bit selection will be covered in the following sections.

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Stability Aspects Bit Whirl – Bit aspects With bit design, there are a number of features which may be found in ‘standard’ PDC bit designs that will aid reducing potential to whirl. Additionally, a number of bit manufacturers employ concepts so that the overall design is specific to applications where lateral vibration is anticipated. The general whirl reducing features are as follows: i) Tracking cutting structure – This is when one or more cutters are positioned in the bit directly tracking a primary cutter i.e. tracking cutters theoretically remove the same formation as the primary cutter. This results in the formation of a distinct borehole pattern, which is grooved or scalloped due to these multiple cutters following the same rotational path. In the scenario that the bit is moved laterally, the cutters bite into these ridges and create a restoring force greater than that pushing the bit laterally. Thus the bit retains rotating around its natural geometric center.

iii) Asymmetry – A symmetrical bit design is one that has a blade layout with equal angular spacing between them i.e. a four bladed bit each set at 90 degrees to each other. This symmetrical layout will fit into a lobed borehole in a regular manner, thus creating a low frequency periodicy that will self perpetuate whirl once initiated. A design that is asymmetric does not possess this regularity and will thus cut into the lobed borehole, forcing the bit to return to its natural geometric center. A general estimate of a bits asymmetry can be gained by simply looking at a plan view of the design. Obviously, the most likely candidates for symmetrical bits are those possessing an even number of blades (with exception of a three bladed bit). The designs that are most asymmetric are those termed as ‘porcupine bits’ where cutters are placed irregular on the bit face with random angular positions. These bits are very stable laterally. iv) Force Balancing – When a PDC bit is drilling, each cutter generates a cutting force in a specific vector. The total forces of the drill bit are a summation of all these individual cutter forces. If, for example, the forces from the cutters on all opposing blades were identical, forces would cancel each other out and the imbalance force would be equal to zero. In a realistic world, this is not the case, thus bits will possess an imbalance (or Outof-Balance) force, which is usually expressed as a percentage of the weight of bit. This

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ii) Spiral Gauge – As with spiral blades on stabilizers, the spiraling of gauge pads will increase the contact area between bit and borehole when rotating and thus aid dampening of any initiated bit whirl. The gauge pads should be low friction i.e. gauge protection should be flush with the pad, and ideally, the lead and back angles of the gauge should be chamfered or radiused. Similar approaches have been used with long gauge lengths though of course this leads to detriment in terms of steerability.

out of balance force will also have a direction associated with it and is perpendicular to the bits axis. It is generally accepted that the closer to zero the out of balance force is, the lower the propensity to whirl, though magnitude of whirl related to levels of out of balance force have never really been proven. Additionally, it is the general practice to calculate this force when the bit is theoretically drilling around its geometrical center, which is rarely truly the case when you consider the actual drilling process, particularly the scenario when using a steerable assembly with bends ranging up to 3 degrees. Factors such as formations, parameter changes, and cutter wear must also all be taken into account, along with the bit suppliers modeling software which is NOT uniform through the industry. Thus if you consider the above, the out of balance force value is only valid for a very specific scenario and can only be benchmarked against other values issued by that bit supplier. As such, you should deeply consider how much emphasis should be placed on the quoted out of balance force when selecting a bit for an application.

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Most soft to medium formation bits are designed so that the teeth on one cone intermesh with that of another for effective cleaning and to entirely cover the bottom of the hole when drilling. As such, the cone shape and number of teeth will vary. Due to this intermeshing, any change to one cone in an attempt to balance the bit will require changing the other cones, which may counteract the balance.

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Cone offset and skew applied to improve gouging in soft formations has an increasing effect on bit imbalance forces. Reducing skew and offset of the cones will have a negative effect on penetration rates.

Due to these reasons, force balancing is not a major concern regarding roller cone bits though Security DBS have just released the ‘Energy Balanced Series’, which looks at both force and volume balancing roller cone designs. v) Profile – It has been observed in many technical papers (in particular those of Brett and Warren) that a flat, short profile design is more stable due to the fact that it is less sensitive to lateral displacement than a longer, tapered design. A deep cone will also aid stability, as there is an increased amount of formation which would have to be overcome prior to lateral movement occurring. Note, this also could have a negative affect on steerability. vi) Cutter back rake – An aggressive cutting structure on the shoulder and gauge can lead to a cutting surface that has the tendency to ‘grab’ the formation and initiate whirl. Less

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Although a common concept surrounding the design of PDC bits, this concept is not shared with that of roller cone bits, as they are commonly unbalanced, primarily due to two key reasons:

aggressive back rakes (>20 degrees) and / or the use of chamfered cutters will reduce this tendency. vii) Secondary components – Components located (and usually directly tracking) the PDC cutter known as hybrids, impregs, impact arrestors, etc (depending on bit supplier). These act as additional contact points as they are usually set just below the tip profile of the cutting structure, thus dampening and aiding stability. Additionally, due to their location behind the cutter and that they are separate from the cutter body, they will also take the impact of any backwards whirl motion and protect the cutters themselves.

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Stability Aspects Bit Whirl – Specific Bit Designs Bits designed specifically to limit whirl are as follows. Note that these may also incorporate one or more of the prior features, though their overall concept revolves around minimizing whirl potential. i) Antiwhirl Designs – This technology involves a specific layout of the face cutters and the use of a large, low friction gauge pad. The cutter layout is such that the sum vector of all the cutter forces is directed to this low friction pad, causing the bit to slide at the borehole wall and thus not walk around the hole (causing whirl). Due to the pad width, large variations in cutter forces can be observed without the imbalance force moving off the pad.

Anti-Whirl is a well documented design concept that incorporates an

Low Friction Gauge Pad Imbalance Force The primary drawback is that the low friction gauge is created by removal of cutting elements at both the gauge and shoulder thus producing a significant cutter devoid area that is prone to durability issues. Several of the bit suppliers have approaches to solving this downside via both geometry and cutter placement. The primary development of Antiwhirl bits was by Amoco, resulting in cutter placement software, which was licensed, to a number of bit manufacturers. The Antiwhirl theory relies on good depth of cut and is thus best suited for rotary assemblies. ii) Steering Wheel - This was created by, and is specific to Hycalog PDC bits. It involves the creation of a ring of bit body material at gauge to provide 360 degrees circumferential coverage. This centralizes the bit, restricting lateral movement and a reduction in torque fluctuations (thus also good directional bit for PDM). Latter testing revealed that a partial ring provides similar levels of stability with the benefit of increased bit face volume and

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junk slot area. This range of bits most commonly fall in the nomenclature range of DS105, DS106, and DS107.

iv) Trac Loc – These designs originate from Security DBS and are intended to self – stabilize the design by eliminating cutter overlap. This is achieved by a heavy tracking structure, which causes deep kerfs to be cut into the formation when drilling. This means that formation is present between the cutter providing a larger surface area between cutter and formation if lateral forces are experienced. This will result in lower unit stress on the formation so less tendency for the cutter to bite and commence whirl. The disadvantage of Trac Loc is that a higher WOB is required to attain the same ROP as a conventional offset design v) FAST & PLUS – These are bit design ranges from Security DBS and Smith. Both are simply ‘packages’ of stability features used in a standard PDC bit design. Security DBS FAST refers to Force balanced, Asymmetry, Spiral blades/gauge, and Tracking. PLUS from Smith relates to Plurality of cutters (Tracking), Low side force (Force balanced), Unsymmetrical (Asymmetry), and Spiral blades/gauge. These packages are particularly observed in the FM and FS (FAST Matrix, and FAST steel respectively) bit products from Security DBS. They have just released a new ‘FM3000’ range of designs to replace the older ‘FM2000’ bits, which have focused on improving force and torque balancing and distribution.

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iii) ARCS – ‘Alternating Radius of Curvature Stabilization’. This is a cutter layout methodology used by Smith (Geodiamond) that uses different sized cutting elements either over the entire bit face, or in specified regions of the bit, so that: • No two adjacent cutters on a blade are of the same size • If all the cutters were rotated onto a single plane, no two adjacent cutters would be of the same size ARCS is promoted as improving stability without compromising either ROP or durability. The stability aspect is similar to that achieved with tracking, though in these instances, the bottom hole pattern ridges are defined by the varied cutter sizes. It is these varied cutter sizes that lead to overlapping of the large cutting elements which will theoretically improve penetration rates. ARCS II, a development over the original ARCS, has now been developed and is available in the field.

vi) Genesis – This is a bit range from Hughes Christensen which contains a number of particular stability features. Aside from choice of low balance force or an Antiwhirl high imbalance concept, it details two unique approaches to lateral stability; Chordal drop and Lateral Movement Mitigator (LMM). The chordal drop concept attempts to minimize space between the bit body and the wall of the hole so that less lateral movement can be attained. The concept of LMM involves building up the blade material on the shoulder to control depth of cut, thus limiting vibration severity and protecting cutters from impact.

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Stability Aspects Stick-Slip - General A) Mechanism: Non-uniform bit rotation with the string alternating between slowing down and speeding up. In certain scenarios the bit may actually stop, causing the string to torque up to an extent and then spin free thus temporarily creating high-speed rotation of the bit. At this point of breaking free, a torsional wave travels up the drill string, from the bit to surface. This wave is reflected back down the string and may cause the bit to stop again. This continuous cycle will continue until you either pick up off bottom or adjust the drilling parameters to interrupt it. Severe torsional vibrations may result in the bit actually rotating backwards with the potential to cause extreme damage to the bit and downhole components. Stick-slip may be resultant from the bit or relating to BHA / wellbore friction. It is generally a low frequency mechanism (<1 Hz). B) Identification: The primary sensor readings that will aid determination of stick-slip are:

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Large surface torque fluctuations, cyclic. Easier to determine from minimum, maximum, and average surface torque readings Fluctuating drive motor current. Will produce whirring sound on TDS Surface RPM fluctuations (dependant on control system for TDS) Stick-Slip measurement from MWD tool

Identification may also be observed on pulling the assembly out of hole: • • • • •

Drillstring twist off Connections over-torqued or backing off Cutter impact damage, lost cutters (empty pockets), particularly on the nose Accelerated shoulder wear, heat checking Ringouts- Predominantly on shoulder, though appear on nose for large diameter bits (>15”)

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C) Effects: • • • •

Cyclic torque oscillations can lead to premature fatigue failure of drill pipe Premature bit and downhole tool failures Compromised steerability Poor penetration rates

D) Cures: There is greater emphasis on external controls relating to stick-slip, as opposed to bit design features for bit whirl. The key parameter control is to decrease the depth of cut so that the bit is less ‘buried’ in formation. This is achieved by increasing RPM and decreasing weight on bit.

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Improve lubricity of mud to decrease static downhole friction Use of a feedback control system to change drive characteristics e.g. ‘Soft Torque’ Select high gear on TDS Use a motor (if not already) to increase downhole RPM Consider roller reamers or a non-rotating stabilizer

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Other external controls include:

Stability Aspects Stick-Slip – Bit aspects Although bit manufacturers are continuously working on bit design aspects to combat downhole vibrations, to date, there is no actual ‘feature’ or bit, marketed primarily at reducing stick-slip. Instead, the key characteristic of a PDC bit that affects stick-slip is its aggressivity, and thus relates to back rake and cutter size.

Note: All these preventative solutions above will have a negative effect on penetration rates. Consideration of the correct balance between drilling rates and vibration risk must be weighed up. It can also be observed, particularly for points ‘a’ and ‘b’, the effect of weight on bit – Increased weight will increase depth of cut. This equals high torque and stick-slip potential. Drilling parameters are just as important in this aspect as is the nature of the drill bit.

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a) As discussed prior, low backrake angles equal more aggressive cutter action. Basically, it effectively takes a deeper depth of cut than that of a cutter set with higher backrake, at the same applied weight on bit. Due to this, it will generate more reactive torque and thus higher potential for stick-slip. b) Similarly, larger diameter cutters have more exposure and thus the potential to dig deeper into the formation. This generates high reactive torque and thus more potential to stick slip. c) Increasing cutter count will lower potential for stick-slip as you are decreasing the depth of cut per cutter than a lighter set design at the same applied weight on bit. d) Chamfered cutters may help to reduce potential for stick-slip as the chamfer effectively reduces the sharpness of the PDC and lessens the effect to grab and bite into formation. e) Use of hybrids / impregs / impact arrestors. These are generally located behind the PDC cutter (directly tracking) and set below the tip profile height of the cutting structure. They will help to limit or control the depth of cut when weight is applied thus reducing overall torque and torque fluctuations. Due to the large range of components from the varied manufacturers with similar attributes, it is useful to check with the specific supplier as to the location and primary purpose of such components.

Stability Aspects Axial Vibration A) Mechanism: Resonant axial motion of the BHA, where, in general, the bit does not actually leave the bottom of the hole. Instead, you observe increasing and decreasing weight on bit. This mode of vibration is particularly associated with roller cone bit designs due to their crushing mechanism of failing rock as opposed to shearing with PDC. It is most common when drilling hard formations with high weights. Due to the three-cone nature and symmetry, the axial displacement will occur three times per revolution. If this frequency matches a natural axial frequency, the bit and BHA will undergo large axial displacements, leading to bit bounce. The vibration frequency is typically in the range of 1-10 Hz.

C) Effects: • Reduced penetration rates • Low bit / tool life D) Cures: • Consider use of shock sub to dampen axial vibrations • Vary RPM / WOB parameters. Stop and pull off if severe and try to establish new tri-lobe pattern • Impact arrestors on PDC bits. Location is important, as nose will be more beneficial than shoulder. Roller Cone Vibration Issues The bulk of the past sections relate primarily to the effects and cures of vibrating PDC bits with the exception of bit bounce, which is mainly observed, with rock bits. It has been observed that Roller cone bits will also exhibit lateral and torsional vibration, though do so at a lesser extent than that observed with PDC. On review of literature, it appears that the key area of vibration limitation (apart from the addition of durable ‘shock absorbing’ components) lies in the field of balancing roller cone designs. The difficulty and progress with this methodology has already been discussed prior.

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B) Identification: • Axial shocks from downhole tools (MVC, GVR) • Possibly see top drive shaking / vibrating dead line • Weight fluctuations (DH in particular) • Broken cutters / inserts • Failed roller cone bearings

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Nomenclature and Commercial Product

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1. Product Ranges – Roller Cone

4. IADC Classification - PDC

2. Product Ranges – Fixed Cutter

5. IADC Classification - RC

3. IADC Classification - Diamond

6. Bit Profile Schematics

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Bit Nomenclature & Product – Roller Cone

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1. Hughes Christensen

5. New Tech

2. Smith

6. RBI

3. Reed-Hycalog

7. TIX

4. Security DBS

8. Varel

Confidential

Commercial Product and Nomenclature Hughes Christensen The nomenclature system is slightly different depending on whether it is an Insert or a Milled tooth design. With that for an Insert bit, the name is broken down into four parts. The first part is alphabetic characters, which represent the product line. This is followed by characters depicting the key feature. Third character is for type, with the fourth for secondary design features. The name for the Milled tooth design is the same except that no fourth character is used. Product Lines: • • •

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Optional Features: • • • •

C (as prefix) = Center Jet. Use primarily to prevent bit balling C3 (as prefix) = Triple center jet. Center jet has three ports. Use in large diameter bits (>16”) C (as suffix) = Conical shaped inserts D = Gauge enhancement using diamond inserts at gauge. There are three variants, indicated by either the number 1,2, or 3 following the ‘D’. The higher the number, the greater the diamond quantity.

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AirXL. Product range for drilling with air or foam ATM = Suited for any combination of high rotary speed applications, high temperatures, excessive abrasion. Metal seal and journal bearings ATJ = High weight applications at conventional rotary speeds. Elastomer sealed journal bearings GT = Premium range of drill bits. Not specifically designed for motor application. Elastomer sealed journal bearings. Good gauge cutting package. GTX / ATX = As per GT but with an o-ring sealed bearing. Designed specifically for high rpm and directional drilling applications. H / HX = HydraBoss. Hydraulically enhanced designs to cope in balling environments. HR = HardRok. Premium product range for drilling hard and abrasive formations. Designed for high weight and low RPM. MX = UltraMax. High-speed rotary and motor product line. High temperature and abrasive applications. Ball and roller bearings, Metal seal MXGT = As per MX but with GT performance package R = Ball and roller bearings, non-sealed STX = Star. Designed specifically for slim hole applications and thus also suitable for motor applications. The Star 2 range has additional gauge protection for highly directional or abrasive applications. XLX. This range consists of light set milled tooth designs for high penetration in soft applications.

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DX = Thick diamond gauge protection (highly abrasive & directional applications). Again, a secondary number denotes the diamond quantity. DT = Diamond gauge trimmers. DT indicates 100% diamond trimmers, DT1 equals 50% DH = Diamond heel inserts used. DH indicates 100% diamond enhanced, DH1 equals 50% FD = Full diamond compacts across the cutting structure (or majority) G = Gauge enhancement using carbide inserts on both gauge and heel row. H = Impact resistant heel compacts. Extra tough carbide grade. M = Motor hardfacing applied to the shirttail P = Wear / stabilization pad on the OD of the bit R = Spray coated cones with tungsten carbide for abrasive applications S = Shirttail compacts to reduce leg wear T = High flow extended nozzles to provide greater flow capacity. Two variations: T1 with just one tube, and T3 with three tubes

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Commercial Product and Nomenclature Smith The Smith tool rock bit product is divided into product families, which provide the prefix for the bit name. The current product lines prefixes are: • • • •

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Suffixes, which define the additional features, are listed as follows: • • • • • • • • • • • • • •

B = Binary gauge protection. Located between primary gauge to absorb damaging loads. Standard is tungsten carbide. BD = Binary diamond. As above but using diamond inserts C = Non standard API connection D = Diamond inserts on gauge row DD = Full diamond cutting structure G = Tungsten carbide coating on cone shell L = Leg back protection on lug using steel pads, which also aid stabilization OD = Diamond inserts on heel row (50%). Variations are available which include OD1, using 100% diamond inserts, and OD2 which is 100% enhanced diamond for maximum protection PD / PS = Leg back protection on the lug using tungsten carbide inserts Q = Extended nozzle SD = Shaped diamond gauge inserts T = Carbide Trucut gauge protection. This uses 2 gauge elements for durability and hole integrity TD = Diamond insert version of the Trucut gauge V = V-flo hydraulics option for sticky formations

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GF or G = Gemini. These designs use both a primary and secondary set of seals (twin seals) using three distinct material elements. The seal set up has a primary benefit of increasing high rpm reliability for extended life on motors. M = Magnum. These bits use a combination of diamond chisels and Trucut protection at gauge to enhance gauge bit life in tough applications and create gauge hole. S = Shamal. Application specific range of bits primarily developed for carbonate lithologies, based on Middle East experience. A key feature is the use of high flow V-Tubes for effective cone cleaning. TS = Twist & Shout. Milled tooth product that has twisted teeth in order to fully optimize the scraping action of the teeth for high penetration rates. Aggressive cutting structure. XR = Xplorer. These are slim hole insert designs. Designed for directional performance and durability on motor applications. XR+ = Xplorer XR+. Slim hole milled tooth design for motor applications.

Commercial Product and Nomenclature Reed-Hycalog Reed roller cones use a relatively simple nomenclature system. It consists of the two IADC numerical values for formation and type with an alphabetic prefix to define product range and alphabetic suffix to depict optional features. In brief summary of the numerical ranges, 10, 20, and 30 series bits are tooth bits for soft, medium, and hard formations respectively. Insert bits use series 40 (soft), 50 (soft to medium), 60 (medium to medium-hard), 70 (hard), and 80 (very hard formations). The alphabetic nomenclature is defined as follows.

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Prefix: • EHP = Enhanced Performance designs. These are a line of Insert bits with improved durability without loss of penetration rates. Marketed as good for high rotary speed applications. Threaded ring journal bearing. • EHT = Enhanced Hard metal designs. Premium line of Milled tooth bits that provide high penetration rates and durability • EMS = Enhanced Motor series. Milled and insert bits that are designed for high speed, steerable motor drilling. Sealed roller bearing • ETS = Enhanced Turbine series with sealed roller bearings • HP = Premium sealed journal bearing bit. High penetration rate designs. Milled tooth and Insert bits with cutting structures to match formation • MHP = Motor Insert bit with journal bearing • MHT = Motor Tooth. Milled tooth designs specific to high-speed motor applications. Journal bearings. ArmorClad hard metal • MS = Motor Series. Milled tooth and Insert bits designed for durability and high penetration rates on directional, high-speed assemblies. Sealed roller bearings • PMC = Powder Metal Cutter bit. Eliminates manual hardfacing so that hard metal thickness and composition is near identical on every cutter, thus extending bit life • SL = Sabre Line. Slim hole (4 ½” to 6 ¾”) bits, designed particularly for directional drilling applications in deep formations • T = Titan range. Large diameter bits with roller bearings for durability and high penetration rates in top hole sections • TD = TuffDuty range. Premium Insert bits with maximum durability for tough applications. Journal bearings and ‘Match-fit’ insert retention. • TDD = TuffDuty Directional product. As above but designed specifically for directional applications on bent assembly • Y = Non-sealed roller bearing designs for shallow hole drilling. Economic bits that meet applications that do not require extended bearing life. Generally large diameter

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Suffix: • A = Chisel shaped inserts • C = Center jet. Standard on bits larger than 16” diameter and optional on product from 7 7/8” to 15 ½” • DI = Diamond inner row inserts • DG = Diamond gauge row inserts • DH = Diamond heel row inserts • DGH = Diamond gauge and heel row inserts • DIH = Diamond inner gauge and heel row inserts • DA = Full diamond insert coverage • DN = Diamond nose • F = Abrasion resistant cone coating • G = Tungsten carbide heel pacs on milled tooth bits • H = Chisel shaped inserts for medium insert designs with 3 degree skew • JA = Bits for air applications • K = Tungsten carbide inserts on shirttail for wear reduction and seal protection. DK = Diamond shirttail protection • KP = Premium K (higher quantity of inserts). DKP = Premium diamond shirttail protection • KPR = KP with rounded inserts. DKPR = Diamond KPR • L = Lug pads. Welded steel pads with tungsten carbide inserts. DL = Diamond lug pads • M = Mudpick II Hydraulics • T = ToughGauge • X = Cutting structure variation from standard. Differs per actual bit type

Commercial Product and Nomenclature Security DBS The DBS rock bit nomenclature system revolves around a central alphanumeric code consisting of one alphabetic character followed by either a single or double-digit number. The confusing part is that this ‘central code’ is surrounded by an alphanumeric assortment of both prefix and suffixes. Alphabetic character = Application identification. S = Soft, M = Medium, and H = Hard Numeric character = Identification of the cutting structure • 3 to 7 = Steel tooth, non-sealed bearing • 8 to 10 = Insert bit, non-sealed bearing • 33 to 77 = Steel tooth, sealed bearing • 80 to 100 = Insert bit, sealed bearing

Suffixes (follows numerics): • C = Conical shaped inserts • E = Eccentric nozzle tubes • F = Sealed journal bearings • FA = Journal bearing bits for air applications • G = Extra gauge protection • J = Three nozzle jet bit • JA = Jet Air bit • JD = Jet Directional control • J4 = Center circulation bit • L = Shirttail wear pads • N = Notched gauge design • P = Extra heavy seam welds for percussion drilling • S = Most aggressive cutting structure for milled tooth bits • SG = Step gauge feature • T = T-Shaped gauge teeth

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Prefixes: • SS = Double seal for soft formations • MM = Double seal for medium formations • 2 = 2-Cone directional bit • D = Deviation control bit • G = Arm / Shirttail protection • M = Tooth bit with extra arm / shirttail protection for motor applications Note that SS and MM are marketed as their ‘Motor bits’. ERA is the ‘New Era’ range that has features related to optimized flow and cuttings removal (ERA = Enhanced Return Area). They have also recently introduced their ‘Energy Balanced Series’, which combines both force and volume balanced roller cone bits.

In addition, DBS have recently introduced a new range of ‘X’ bits. Their nomenclature is as follows: XS or XL for Friction Bearing XT or XN for Roller Bearing The prefix is followed by either a single or a double digit. Use of a single number denotes a milled tooth bit. Likewise, a double digit indicates an Insert design. E.g. • XS1 to XS5 are Mill Teeth Friction Bearing • XT1 to XT5 are Mill Teeth Roller Bearing • XS00 to XS99 are TCI Friction Bearing • XT00 to XT99 are TCI Roller Bearing

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Commercial Product and Nomenclature New Tech This company specializes in manufacturing Insert rock bits particularly for high-speed applications using sealed journal bearings. They use the prefix ‘NT’ to define the manufacturer, followed by sequential numbers that increase with formation hardness. The chart below depicts how this compares to the IADC coding.

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Commercial Product and Nomenclature RBI Five key rock bit product ranges: • • • • •

Standard Insert = Uses ‘C’ prefix, followed by numeric characters. The lower the first numeric character, the lower the IADC code application. Ranges from 0 (4-1-7) through to 9 (8-3-7) One Cone bits = Uses ‘B’ prefix. One cone designs for slim hole applications (<6 1/8”) M Series = 2 cone designs with extended nozzles for soft formation drilling LRG = High speed milled tooth designs. LRG = Lugged Reaming Gauge, marketed as durable for extended bit life Excalibur = Aggressive designs with motor bearings and reaming gauge

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Commercial Product and Nomenclature TIX TIX uses a separate nomenclature system for both its Insert and Milled tooth ranges. The Insert range uses an alphabetic prefix to denote the bearing type, two digits to reflect IADC code, followed by a multitude of alphabetic characters to reflect the optional features. Insert prefix • X = Floating Bearing • M = Motor Bit • K = Friction bearing, slim hole bits • Z = Sealed roller bearing • XZ = Sealed roller / floating bearing. Bit sizes > 9 5/8” • MZ = Sealed roller bearing for motor bits. Bit sizes > 13 3/8”

Insert Suffix • G = Shirttail inserts • Y = Conical inner row inserts • H = Chisel shaped gauge row • R = Round shaped gauge row • F = Side scraper gauge protection • V = Diamond enhanced inserts at gauge • P = Lug pads • J = Raised tungsten carbide leg protection • C = Center jet

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Insert Numericals • 05 = IADC 41 • 10 = IADC 43 • 15 = IADC 44 • 20 = IADC 51 • 30 = IADC 53 • 40 = IADC 61 • 50 = IADC 62 • 60 = IADC 63 • 70 = IADC 73 • 90 = IADC 83

The milled tooth range differs in that the IADC code of the bit is reflected via an alphabetic prefix and not numerical characters. Following the prefix is an alphabetic character to reflect the bearing type. Alphabetic suffixes denote the optional features. Prefix • • • • • • • •

SS = IADC 11 S = IADC 12 MSS = IADC 13 MS = IADC 21 MH = IADC 23 HS = IADC 31 H = IADC 32 HR = IADC 34

Suffix • • • •

G = Shirttail inserts L = Lug pads J = Raised tungsten carbide inserts on leg protection C = Center jet

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Bearing Character • None = Non sealed roller bearing • X = Floating bearing • M = Floating bearing for motor applications • Z = Sealed roller bearing • XZ = Sealed roller / floating bearing. Bit sizes > 9 5/8” • MZ = Sealed roller bearing for motor applications. Bit size > 13 3/8”

Commercial Product and Nomenclature Varel ETD / ER prefix. No other details available on web.

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Bit Nomenclature & Product – Fixed Cutter

enter

1. BBL

6. Reed-Hycalog

2. Security DBS

7. Tri Max

3. Hughes Christensen

8. Bit Tech

4. DPI

9. Varel

5. Smith

Confidential

Commercial Product and Nomenclature BBL British bits do not publicise a nomenclature system, with the only common feature being that all bits start with ‘BB’. Due to their relatively small range, the product falls under the following nomenclature: • • • • •

BB432 / 452 / 532 – These are their soft formation range. Light set, low blade count, large face volume, spiral blades BB490 / 480 – Designed for coiled tubing applications. Low aggressiveness. BB657 – Durable product for medium hard and interbedded formations BB852 / 652 – Intermediate design for soft to medium formations BB1280 / 880 – Designed for steerability and thus directional applications

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Commercial Product and Nomenclature Security DBS DBS introduced the ‘FAST’ terminology to their product offerings. FAST actually denotes aspects relating to bit stability (Force balanced, Asymmetry, Spiral gauge, Tracking) but now is key to their naming system, replacing the old PDC designs which had prefixes of PD, HZ, QP, and TD. As such, the majority of current product has one of three prefixes, each denoting the body material or cutter type: 1. FM = FAST Matrix 2. FS = FAST Steel 3. FI = FAST Impreg, Now replaced with TI In addition, there is the SE3000i range which are predominantly PDC bits, but with diamond impreg back-up.

1st Number: The first number after the alphabetic prefix is always ‘2’. This is used as the product range and is based on the technologies developed and released as FM2000. DBS have just started to introduce their FM3000 range. This will use the same nomenclature system except that the number following the FM prefix will be ‘3’. 2nd Number: Blade count. Blade counts of 3 to 9 are represented by the corresponding number. A blade count of 10 uses a ‘0’, 11 uses ‘1’, and 12 or more blades uses the number ‘2’. 3rd Number: Cutter size (mm). 2 = 8, 4 = 13, 6 = 19, 8 = 25 4th Number: Profile. The numbers 1 to 8 are used based on the closest match to the profile depicted below.

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Following this prefix is a four-digit code that relates to the design aspects of that particular bit. They are as follows:

In addition to the FAST nomenclature, the six-character name will also have suffixes to denote special features or applications. These include: A = Air drilling application D = Deviation control F = Ports G = Additional gauge or body protection H = Horizontal steering application I = Thermally stable synthetic diamond (TSP) cutting structure J = Jet deflection K = Cross flow hydraulics M = Mud motor applications N = Turbine applications O = Milling applications P = Percussion drilling Q = Lateral nozzles R = Radial flow hydraulics V = Anti-whirl characteristics W = Enhanced cutting structure

Natural diamond bits do not follow this convention. These bits can be identified by the use of either TT, TB, or TBT as the prefix.

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Commercial Product and Nomenclature Hughes Christensen This nomenclature consists of three numbers with an alphabetic prefix. The numbers represent: • •

1st Number: Cutter size (mm). 3 = 9, 4 = 13, 6 = 19 2nd & 3rd Number: Blade count i.e. 6 blades = 06, 12 blades = 12

The prefixes vary and define the product range. The list below contains the current commercial ranges:

• • • •

D = Natural diamond drill bit DORWD = Reaming while drilling tool (DO relates to shoe drill out capability) DOSRWD = Steerable reaming while drilling DOSTRWD = Slim hole reaming while drilling DSM = Diamond speed mill for drilling casing windows. HC = Genesis range. Premium PDC product range with enhanced cutter technology, stability, and hydraulics. This is the current base standard range of PDC product from Hughes. HCM = Genesis range design for steerability on motors. Uses specific cutter positioning and blade geometry to reduce torque fluctuations for improved tool face control. HCR = Genesis range for use on Rotary Steerable tools. Aggressive designs with short, steerable profile, and gauge structures to deliver side cutting ability. HH = Hedgehog design. This is an impregnated design with interrupted cutting structure to make it suitable for interbedded formations. Designed for high rpm applications (turbine & PDM) in hard formations. ST = Sidetrack applications. Either natural diamond or PDC cutting structure.

In addition, the following are older ranges will may still be available or referenced on well records: • • • • • • • • •

AG = Antiwhirl Gold AR = Antiwhirl BD = Black diamond BX = Black Trax. Marketed as steerable bits with extended tandem gauge design G = Gold series. ‘Aggressive profile bits designed for high performance drilling’ HD = Natural diamond bit R = Conventional PDC design S = Standard impreg design. Designed for hard formation using both high RPM and WOB. SRP = Mosaic bit

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STR = Star series. Slim hole designs based on Gold series. High backrake bits with secondary ‘wearknots’ to lessen aggressivity and reduce torque variation for high angle and horizontal applications T = Turbine bits (natural diamond) TX = Product range designed for the AutoTrak tool Z = Combined PDC and mosaic drill bit

With the older ranges listed above, there are still three numerical characters, but they differ considerably. • • •

1st Number = Cutter size: 3 = 9mm, 4 = 13mm, and 5 = 19mm 2nd Number = Profile. Ranges between 1 (long parabolic) and 9 (flat) 3rd Number = Cutter density. Ranges from 1 (very light set) through to 9 (heavy)

The suffixes used by Hughes to denote optional features for both the old and new ranges are:

• • • •

G5 = In gauge, flush mounted, PDC cutters along leading edge of gauge pad G6 = Spiral gauge G7 = TSP gauge protection G8 = Extended gauge length G9 = Turbine sleeve K = Wear Knot. Matrix pads behind PDC cutters to control depth of cut SB = Slick bit coating to aid antiballing U1 = Natural diamond updrill feature. Uses diamond coating as a backreaming option U2 = PDC updrill. 8mm diameter PDC cutters for backreaming U4 = PDC updrill. 13 diameter PDC cutters for backreaming Y = Bit with box connection (for pin down drives) XB = Brute cutters. Secondary cutters positioned behind primaries on face.

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Commercial Product and Nomenclature DPI For concentric drill bits, DPI use a five character code: 1st Character: Body / cutter type • S = Steel body • M = Matrix body • N = Natural diamond bit • T = TSP bit • P = Combined TSP / Natural diamond bit • I = Impregnated bit

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2nd Character: Profile • F = Full face bits with flat profile • H = Full face bits with hemispheric profile • C = Bladed bits with emphasis on cleaning • T = Bladed bits with emphasis on durability • M = Medium taper profile • R = Rounded profile • L = Long profile • S = Spiral bladed 3rd Character: Cutter size Number PDC Diameter (mm) 1 3 2 6 3 8 4 13 5 16 6 19 7 22 8 25

Natural Diamond Type Step cube & cube Step cube & round Step round & round

TSP geometry Small Triangle Medium Triangle Large Triangle

Circle Plot & ridge Ridge

Cylindrical

4th Character: Cutter density Number 1 2 3 4 5 6 7 8 9

PDC Ultra light

Natural Diamond

TSP

Light

Light

Light

Medium

Medium

Medium

Heavy

Heavy

Heavy

Ultra heavy

Ultra heavy

5th Character: Design criteria • C = Core bit • ST = Sidetrack design • H = Horizontal applications • SC = Shaped cutters • F = Face discharge • G = Short gauge • M = Modified • LT = Low Torque

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In addition, DPI has a variation of this system for their eccentric and concentric reamer designs: 1st Characters: Reamer type • SR = SpeedReamer. This is the standard bicentre bit • CSD = Casing shoe driller. This is the bicentre bit designed specifically for drilling out of the shoe • SD = SpeedDrill. Concentric, one piece reamer 2nd Character: Cutter density (as per conventional PDC system) 3rd Character: Cutter size of pilot bit 4th Character: Cutter size of reamer section

Commercial Product and Nomenclature Smith The Smith nomenclature is application based. It relies primarily on two numbers that indicate suitable formation hardness and thus also depict how heavy set the bit is. The numbers are on a scale of 1 to 99 with 1 being hard formations, thus heavyset bits, and 99 being ideal for soft formations (light set bits). They also use prefix and suffix alphabetic characters to denote the product range (Prefix) and any additional features (suffix).

In addition, there is a product range that is promoted but not covered by the use of prefixes. This is called ‘Velocity’, which is basically the soft formation product offering. The bits are all steel bodied with large face volume, and utilise the 22mm diameter cutter for high penetration rate performance. The current Velocity bits are all denoted by the use of three numerical characters following the ‘S’ prefix for steel. Suffix: • B = Backreaming PDC cutters • C = Non API standard connection • D = Diamond enhanced inserts • E = Extended gauge length

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Prefix: • BC = Steel bicentre design • BD = Natural diamond bicentre design • BM = Matrix bicentre design • D = Natural diamond • DST = Diamond sidetrack design • K = Impregnated • M = Matrix body • MA = ARCS technology design • MDT = Dual Torque. These bits are designed specifically for steerable applications on motor and are promoted as providing smooth torque response • MGR = Geodiamond research. Experimental bits which are renamed if successful • MRS = RotoSteer. Bits designed for rotary steerable tools • MST = Matrix sidetrack bit • RM = Rental bit, matrix body • RS = Rental bit, steel body • S = Steel body • SST = Steel sidetrack bit • XTG = Matrix body with GHI’s and synthetic diamonds • XTN = Matrix body with natural diamonds • XTS = Matrix body with synthetic diamonds

• • • • • • • • • • • •

F = Back up face cutters H = Increased TFA K = Cutter protection using diamond impregnated material N = Lower number of nozzles than standard PX = Gauge protection using combination of diamond and TSP inserts PXX = Extra diamond insert protection. Usually used on steel turbine sleeves Q = Fixed ports S = Short gauge length T = Turbine sleeve V = Low vibration aspects Y = Contains 30 Series nozzles Z = Advanced nozzle geometry

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Commercial Product and Nomenclature Reed-Hycalog A) PDC: The conventional product range from Hycalog does not have any indication of bit design features in the numbering system used. The design numbers are distributed in increasing numerical order as bits are produced, thus the only thing that can be deciphered is the approximate age of the base design. Until recently, the prefix of the bit name also did not give any clues to the product range, with all PDC products having a prefix of DS (goes back historically to when Hycalog was formerly Drilling & Services). However, there are now several prefixes that define product ranges. In addition, the placement of an ‘X’ after the following prefixes depicts that the design is equipped with TReX cutters (Ultra abrasion resistant): • • •

Within the DS range there are clear alliances of designs with sequential numbers that carry the same features. As rough guidelines, these include: • • • • •

DS100 to DS102 = Standard bicentre products DS105 to DS107 = Steering wheel product line DS181 to DS183 = Concentric hole openers DS43 = Sidetrack bit DS86 = Antiwhirl design

The base design will use this four or five character nomenclature. However, each design will also have an alphabetic and numeric character following it, which defines the actual variant of the base design. The general rule is that the first variant will be called ‘A1’, and following variants will increase sequentially i.e. A2, A3, …….A12, etc. A variant change is generally minor and will include variations in backrake, modified hydraulics, and change of cutter type. In some instances, changes which are very significant (cutter size) will switch to the use of ‘B’ or ‘C’ variant, though this is not always the case and should be verified with the supplier. As with all the major bit manufacturers, Reed-Hycalog have a diversity of features which are defined as suffixes after the numerical name. These suffixes follow after the variant character and number, and denote: A = Reserved for use as base variant B = Reserved for use as base variant

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DS = Standard PDC design RS = Design specific for rotary steerable tools R = Rental bit. Any bit type can be classed as a rental. This is purely an administrative term and does not depict any key differences in design SB = This is the bicentre bit line developed for casing shoe drill out (Stabil Bicentrix)

B) Impregnated: The impreg drill bit range from Hycalog is known as the DuraDiamond range. Unlike the PDC, these bits have a nomenclature which is related to the features of the design. This nomenclature uses three digits with no alphabetic prefix. One or two suffixes are commonly used. 1st Number: This refers to the cutting structure and bit geometry. • 3 = Impreg design, enhanced with TSP cutters • 4 = Standard Impreg design • 5 = Impreg bicentre design • 6 = Transformation impreg design. Variable blade heights nd 2 Number: This relates to the formation hardness of the face design and ranges from 3 through to 7. A 3 depicts a design suitable for relatively soft formations, whereas the 7 is reserved for cutting structures suited to very hard formations 3rd Number: Number of junk slots Suffixes: The two suffixes used are ‘P’ which depicts profile, and ‘A’ which relates to the TSP cutter layout used. Both have different configurations which are relayed via the use of a following digit as can be seen below for ‘P’. • P4 =Double cone, aggressive • P5 = Double cone, intermediate • P7 = Rounded, general purpose

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C = Reserved for use as base variant D = Diamondbacks. These are secondary cutters tracking the face (durability) B = Eccentric. No longer used as these bits are now classed as bicentre designs F = Hardfacing on blade faces. The use of F+ denotes that the top of the blades are also hardfaced G = Diamond gauge protection H = Hybrids. These are basically ‘impact arrestors’, placed behind face cutters I = Impregnated design. Not used as these are classed separately as ‘DuraDiamond’ bits J = Fixed ports K = Uses abrasive coating on rear of gauge pads for backreaming (small diameter bits) L = Extended gauge length N = Non Planar Interface Cutter P = PDC Gauge protection R = Natural diamond bit where cutters are placed on ridges S = Short gauge ST = Sidetrack bit T = Turbine sleeve U = Upreamers (PDC) V = Venturi nozzles. Patented cross flow hydraulics W = Spiral gauge X = Non standard API connection Z = Low torque gauge

Commercial Product and Nomenclature Tri Max Due to their relatively small range, the product falls under the following nomenclature: • • • •

DS645 = Medium set steel bodied bit. IADC code of S645. 6 blades, 13mm cutters, low blade height, straight blades. Designed for medium formation strengths. S-1 = Medium set steel bodied design, spiralled blades, 13mm cutters. Designed for soft to medium formations. IADC code of S315. Q-1S = Heavy set steel bodied bit for medium to medium hard formations. IADC code S645. HZ-90 = Heavy set steel bodied bit, designed for horizontal and directional drilling. Shallow profile and short gauge for effective steering, extensive gauge protection for directional wells. IADC code S976.

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Commercial Product and Nomenclature Bit-Tech There are two key designs marketed by Bit-Tech at present: • •

HPB = Slim hole (4 ¾ - 6 1/8”) bits designed for horizontal and directional applications. Matrix bodied designs with 8mm cutting structure, short gauge, forward sweeping blades 45X = 5 bladed, matrix bodied design with 13mm cutting structure, flat profile, short gauge

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Commercial Product and Nomenclature Varel They use a combination of three letters and two numbers as their base naming structure. Extra alphanumerics may appear as a suffix, depicting specific features. 1st Letter: Body Material. S for Steel and M for matrix 2nd Letter: Series. This is generally represented by ‘K’ 3rd Letter: Profile. F = Flat, S = Short, M = Medium, L = Long, O/E = Other/Engineering 1st Number: Cutter size (mm). 2 = 8, 3 = 9, 4 = 11, 5 = 13, 6 = 16, 7 = 19, 8 = 25 2nd Number: Blade count Thus MKS66 = Matrix bodied, short profile design, 6 blades, 16mm cutters. The extra suffixes include: C1 to C9: Specific cutter type variations G1 to G9: Variations in gauge type T1 to T9: Turbo variations Schlumberger Private

IADC Classification of Drill Bits Diamond Bits The system for classification of natural diamond, impregnated, and TSP drill bits is very similar to that for fixed cutters and is used just as rarely. It follows a four-character code relating to body material, cutter density, profile, and diamond type (as opposed to cutter diameter for fixed cutter). First Character: This is an alphabetic character relating to body material, which is always matrix and thus represented by ‘M’. Second Character: This is a numeric range from 6 through to 8 relating to the surface set cutter density. It differentiates itself from that of fixed cutter, which does not exceed the number four. This provides a method for identifying these types of bits from fixed cutter by IADC code alone. The numbers reflect; 6 = <3 stones per carat (SPC) 7 = 3 – 7 SPC 8 = >7 SPC

Third Character: This relates to the diamond type used in the bit construction. It is a numeric range from 1 through to 4 based on; • • • •

1 = Natural Diamonds 2 = Thermally Stable Polycrystalline Diamond 3 = Combination cutter types 4 = Diamond Impregnated

Fourth Character: This is related to profile of the bit design and is exactly the same as that for PDC.

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IADC Classification of Drill Bits PDC A classification system for fixed cutter bits was developed in 1992 by the IADC, following on from the success of such a system in classifying roller cone bit designs. However, unlike for roller cone, the IADC code for fixed cutter bits is not commonly used throughout by either operators or bit manufacturers. As per that for roller cone, the system comprises of four characters, the first being alphabetic, followed by three numerical digits. First Character: This relates to the body material of the bit – ‘S’ for Steel and ‘M’ for Matrix (tungsten carbide matrix). Second Character: This is a number relating to the cutter count of the bit, based on cutter density in terms of 13mm diameter cutters on an 8 ½” diameter bit. The numeric range is from 1 through to 4 where; 1 = <30 x 13mm 2 = 30 – 40 x 13mm 3 = 40 – 50 x 13mm 4 = >50 x 13mm

Third Character: This number relates to the cutter size on the bit. Where multiple cutter sizes are used, select the predominant one. Again, the numeric range is from one to four where cutter diameters are; • • • •

1 = >24mm 2 = 14 – 24mm 3 = 10 – 14mm 4 = <10mm

Fourth Character: This relates to the profile of the bit design. A number is used to depict the best fit to the standard profiles as illustrated below; • • • •

1 = Fishtail 2 = Short 3 = Medium 4 = Long

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IADC Classification of Drill Bits Roller Cone This system was derived in order to classify the design features and intended applications of roller cone bits. This system has been in widespread use since 1972, with notable updates in both 1987 and 1992 to reflect latest design trends. It originated due to the diverse availability of cutting structures and bearing types, affecting the suitability to geographical formations. The adopted system is approved by the IADC (International Association of Drilling Contractors), the API (American Petroleum Institute), as well as the bit manufacturers. The classification is via a three digit code plus a fourth alphabetic character, which, when combined, conveys: Cutting structure type Intended formation type Bearing and seal type Gauge protection Any special applications

First Number: This is divided into eight categories or series from 1 through to 8. Milled tooth bits are contained within series 1 to 3 whereas Insert bits are represented by series 4 through to 8. Within both the milled tooth and insert groups, increasing series number equals increasing rock strength and abrasiveness. Second Number: Each of the series defined prior is defined by four sub categories (Type 1 through to Type 4). Type 1 formation is the softest within that series, the hardest formation strength in that series is defined as type 4. The use of both series and type helps to narrow down the formation strength and required cutting structure for a specific application. Third Number: This relates to the bearing and gauge protection, with each number representing a different bearing and gauge type combination. These variations can be noted in the table overleaf. Fourth Character: Sixteen characters are used to relate to the various additional features which may be beneficial to your application. Again, these can be viewed below. It can be noted that under this classification system, there can be a variation of 224 roller cone bit classifications, without considering the additional features.

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D E C

D&M—NSA

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Bit Profile Schematics

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1. Side View – Steel Bodied PDC Bit 2. Side View – Matrix Bodied PDC Bit 3. Face View – PDC Bit 4. Side View – Diamond Bit 5. Side View – Roller Cone Bit

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Side view Schematic of PDC bit (Steel)

Shoulder

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Face view Schematic of PDC bit

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Side view Schematic of PDC bit (Matrix)

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Side view Schematic of Impreg / Diamond bit

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Side view Image of a Rock bit

Cutter / Cone

Cutting structure

Inner Row Gauge Row Heel Row

Shirttail

Grease reservoir Lug

Bowl Interchangeable Nozzle jet Pin

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Internal bearing system (Roller)

D E C

D&M—NSA

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Reference Material

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1. Supporting Technical Literature 2. Bit Run Guidelines 3. Make-Up Torque Guidelines

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References ARCS – Geodiamond SPE/IADC 39310: Innovative cutting structure improves stability and penetration rate of PDC bits without sacrificing durability. Graham Mensa-Wilmot et al. PDC Features – Hycalog SPE 36435/IADC: High penetration rates and extended bit life through revolutionary hydraulic and mechanical design in PDC drill bit development. Malcolm Taylor et al. PDC Features – Hughes Christensen SPE/IADC 39306: The effect of PDC cutter density, back rake, size, and speed on performance. L.A. Sinor et al. Formation Evaluation – Hycalog Oil & Gas Journal, May 16th 1994: Confined compressive strength analysis can improve PDC bit selection. Robert Fabian.

Formation Evaluation – bp Amoco SPE/IADC 18166: Relationships between formation strength, drilling strength, and electric log properties. E.C. Onyia. Bit Whirl – bp Amoco SPE/IADC 19571: Bit whirl: A new theory of PDC bit failure. Brett et al. Bit Whirl – bp Amoco SPE/IADC 19572: Development of a whirl-resistant bit. Warren et al. Bit Whirl – bp Amoco SPE/IADC 20416: Field testing of low-friction gauge PDC bits. Sinor et al. Bit Whirl – bp Amoco SPE/IADC 21928: Three-dimensional modelling of PDC bits. Behr et al. Roller cone Vibration – TFE SPE/IADC 23888: Surface detection of vibrations and drilling optimisation: Field experience. Henry Henneuse. PDC Vibration – Shell SPE/IADC 23867: PDC bit dynamics. C.J. Langeveld. PDC Vibration – Hycalog

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Roller cone bit selection – bp Amoco SPE Drilling Engineering 1987: Three-cone bit selection with sonic logs. Kenneth Mason.

SPE/IADC 39307: Development of a new concept of steerable PDC bit for directional drilling. Tom Roberts. PDC Vibration – Security DBS SPE Drilling & Completion, 1996: The application of advanced PDC concepts proves effective in South Texas. J.S. Dahlem et al. PDC Vibration - Schlumberger SLC Document: Shocks and general drilling optimisation. Mather & Lockley. Rock Bit Classification – IADC SPE/IADC 16143: Application of the 1987 IADC Roller bit classification system. W.J. Winters et al. Rock Bit Classification – IADC SPE/IADC 23937: The IADC Roller bit classification system. Dave McGehee et al. Rock Bit design & Application – IADC IADC Rotary Drilling Series: The Bit, Unit 1, Lesson 2. Jodie Leecraft.

Roller Cone vibration – Security DBS SPE/IADC 71393: Development and field applications of Roller Cone bits with balanced cutting structure. S.L. Chen et al. Roller Cone vibration – Security DBS SPE/IADC 76811: Field investigation of the effects of stick-slip, lateral, and whirl vibrations on Roller Cone bit performance. S.L. Chen et al. Impreg / Diamond bits – Smith SPE/IADC 59113: New technology in diamond drill bits improves performance in variable formations. Tim Beaton. Impreg / Diamond Bits – Hughes Christensen SPE/IADC 68090: New application of impregnated diamond bit on high-speed motor – A tem approach to performance improvement. Peter Hendriks et al. Impreg / Diamond Bits – Hughes Christensen SPE/IADC 26695: Impregnated bit technology improves drilling efficiency in North Sea conglomerates. Antonio Galletta et al. Impreg / Diamond bits – Reed Hycalog Web based manual: Applied diamond drilling. Doug Caraway et al.

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Drill Bit Design –Reed-Hycalog SLC Document: Drill bit design and selection. R-H.

Drill Bit Running Procedures A Guideline for Field Engineers By Steve Taylor, Drilling and Measurements Table of Contents INTRODUCTION

4

RIG SITE PROTOCOL

5

RIG AND SURFACE EQUIPMENT EVALUATION

6

Solids Control Equipment Mud Pumps Mud Condition Lost Circulation Material Surface Parameter Gauges BOTTOM HOLE ASSEMBLY EVALUATION

8

WELL BORE CONDITION EVALUATION

8

PRECEDING BIT RUN EVALUATION

9

DRILL BIT TFA (TOTAL FLOW AREA) CALCULATION

9

PREPARING THE BIT TO BE RUN IN HOLE

10

MAKING UP THE BIT TO THE DRILLSTRING

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RUNNING IN HOLE

11

DRILLING OUT THE WIPER PLUGS, CEMENT, SHOE AND FLOAT ASSEMBLIES

11

PDC (Including SteeringWheel and BiCentrix), Impregnated and Diamond Drill Bits Roller Cone Drill Bits, (insert and Milled Tooth) Drill Bit Running Procedures

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BEDDING/BREAKING THE BIT IN

13

MAKING CONNECTIONS AND RESTARTING DRILLING

13

GENERAL DRILLING PARAMETERS FOR 'CLEAN' FORMATIONS

13

DRILLED CUTTINGS ANALYSIS

14

FUNDAMENTAL PARAMETER DISCUSION

14

Torque Weight Rotary Speed Flow Rate OPTIMISING DRILLLING PERFORMANCE

16

BP FORMALISED DRILL-OFF TEST PROCEDURES

17

Summary Drill-off Test Method 1 - Locked Brake Test Drill-off Test Method 2 - Drillability Test DRILLSTRING DYNAMICS/VIBRATION

23

General Types of Vibration Drillstring Resonance Axial Vibration Bit Whirl BHA Whirl Torsional Vibration Vibration Coupling VIBRATION MONITORING

29

FACTORS RELATING TO BIT RUN TERMINATION

31

Economics Worn Cutting Structure Worn/Failed Bearings on Roller Cone Bits Bit Balling Drill Bit Running Procedures

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Lost Nozzle Plugged (Blocked) Nozzle Downhole Motor or Turbine Failure DULL GRADING

34

DULL BIT PHOTOS

34

RUN REPORTING

34

REFERENCES

35

DRILLING TERMS

35

APPENDIX 1: OPTIMISATION RUN REPORT EXAMPLE

36

APPENDIX 2: QUICK REFERENCE TABLE FOR COMMON DRILLING PROBLEMS

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Drill Bit Running Procedures

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Introduction While drilling a well, crucial decisions are made on the basis of what is believed to be happening down hole. There are a large number of factors that can effect drilling performance from the drilling rig itself and associated surface equipment to the down hole equipment; from run parameters and formation type to their consequential effect on drillstring dynamics and bit life. It is the purpose of this document to improve the understanding of the entire drilling system and provide guidelines so that the pertinent factors effecting drilling performance can be identified and managed. With better identification and understanding of drilling problems informed decisions can be made to improve drilling performance and significantly reduce the drilling costs for our customers, the operator. These guidelines cover aspects of running a drill bit from arriving at the rig site through to recommending drilling parameters, run recording and reporting. The guidelines can be used as part of the Drilling Optimisation Process, the Plan, Execute & Evaluate Cycle to ensure a quality service is provided to the client.

Whilst in the position of Drilling Optimisation Specialist for BP, Martyn Fear developed two formalised drill-off test procedures for optimising drilling parameters for maximum performance. These procedures are included on Page 16. Other reference material utilised was a Drillstring Vibration Primer written by Fereidoun Abbassian also of BP.

Drill Bit Running Procedures

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Rig Site Protocol On arriving at the rig site ensure that rig site protocol is adhered to. Each operator, contractor or location, be it land or offshore, have their own standards and rules for HSE that must be adhered to. Ensure as a Field Engineer that both SLB standards and rig site standards are met, to which ever has the highest standard. For example, the general rig site protocol for US Land is• • • • • •

Minimum PPE is a hard hat, steel toe capped rig boots and safety glasses. Sign in at entrance. Reverse park your vehicle. Introduce yourself to the oil company representative. State why you are there. Explain your objectives and how you plan to achieve them.

Drill Bit Running Procedures

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Rig and Surface Equipment Evaluation Evaluate the rig and surface equipment to become familiar with the maximum and minimum parameter variables that are available. An understanding of the limitations of the equipment can help in developing a realistic and practical solution to a drilling problem. Solids Control Equipment Poor solids control equipment can cause the following problems• Ineffective or too few shakers can limit the speed at which cuttings can be removed from the mud system. If this is the case penetration rate may need to be limited. • If the solids are not removed from the mud effectively the mud can become very erosive. Erosive mud can reduce bit and downhole tool life resulting in shorter run lengths. • If the solids content becomes too high this can reduce the effectiveness of the mud, eg shale inhibition with water based mud systems. Evaluate the following equipment• Shale shaker specification o Number o Type o Screen/mesh size • Centrifuge equipment Mud Pumps Mud pumps drive the mud around the drilling system. Depending on liner size availability they can be set up to provide high pressure and low flow rate, or low pressure and high flow rate. Analysis of the application and running the Drill Bits hydraulics program will indicate which liners to recommend. Finding the specification of the mud pumps allows flow rate to be calculated from pump stroke rate, SPM. Information requiredo Pump manufacturer o Number of pumps o Liner size and gallons per revolution Mud Condition Drilling mud has two fundamental functions. The primary function is to keep the well bore in good condition by managing the formations, eg: balancing pore pressure, inhibiting shale reaction, etc. The secondary function is to aid the drilling process, eg: transporting cuttings to surface, cleaning and cooling the drilling bit, etc. For maximum drilling performance the mud system must be maintained in good condition. Minimum information requiredo Type (OBM, WBM, POBM, Silicate, etc) o Weight o Solids content o PV/YP

Drill Bit Running Procedures

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Lost Circulation Material Lost circulation material is frequently required to plug fractures in the well bore. If these fractures are not plugged a significant volume of mud can be lost to the formation. Mud is expensive and losses must be minimised. Lost circulation material comes in various sizes and types, eg: nut plug, cottonseed hulls, cellophane, etc. LCM as well as plugging holes in the well bore can plug nozzles in a drill bit. If determined that lost circulation material will be required, ensure that the size and type is known so that drill bit nozzles can be selected that will allow LCM to pass through with a minimal risk of plugging. Surface Parameter Gauges Surface parameter gauges are the primary tools for evaluating and setting drilling parameters. Consequently it is critical that all gauges are operational and calibrated. The following gauges and recording instruments need to be checkedo Standpipe pressure o RPM o WoB o Torque o Geolograph (depth measurement) o Rig Floor Parameter Display/Monitor o SPM

Drill Bit Running Procedures

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Bottom Hole Assembly Evaluation The bottom hole assembly directly effects drilling performance. The addition of a down hole drive mechanism (motor or turbine) can significantly increase penetration rate while the addition of stabilisers can effect the dropping, building or turning tendencies of the drillstring. A rotary steerable system can provide improved directional control compared to that of a motor in some applications, eg: extended reach wells, applications where differential sticking of the BHA is problematic, etc. Useful information is• Turbine specification. o Revolutions per unit volume pumped for RPM calculation, (due to the mechanical operation of a turbine the calculated rpm is theoretical and is not necessarily actual rpm) • Motor specification. o Performance charts o Lobe configuration for motor type, eg: high torque/low speed o Revolutions per unit volume mud pumped for rpm calculation • Stabiliser details can affect both directional tendencies and transmitting weight to the bit, eg: stabilisers hanging up. Details required areo Size o Position in the drillstring (including motor stabilisers) • MWD/LWD details. Find out the specifications for these tools and what data each is collecting. It is easier to ask/get the data if it is known that it is being collected. Down hole data is better than surface data for problem identification, monitoring and curing, eg: down hole vibration data. Useful downhole data iso RPM o Torque, (average, maximum and minimum) o WoB o Pressure o Vibration

Well Bore Condition Evaluation Find out the history of events of the well to date to assess if any incidents have/will affect the run. Gather as much information/ideas fromo Casing depths o Log data o Survey data o Oil company representative o Rig contractor’s tool pusher o Drillers from each shift o Mud company representative o Directional tool representative if applicable (motor, rotary steerable, etc) o Logging company representative/geologist

Drill Bit Running Procedures

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Preceding Bit Run Evaluation Find out the details of the preceding bit run. What factors improved/reduced drilling performance and can the lessons learnt be utilised in the planned run? • • • •

Find out the condition of the preceding bit when it went in hole, ie: new bit, rerun, re-tipped, etc. Be on the rig floor to witness the preceding bit and BHA being pulled through the rotary table. This is the only way of ensuring maximum information is collected on the dull condition of the bit and the BHA, ie: sometimes bit/BHA balling is removed and not recorded. Collect the run details, dull grade the bit and take photos as outlined in the Dull Grading and Dull Bit Photos section. If a detailed run report is required this information may be critical. If it is planned to run a PDC bit and the preceding bit is pulled out of hole with severe damage; lost cutters or cones; or severely under gauge, the hole should be conditioned with a roller cone bit and a junk basket. (PDC bits are generally not recommended for long intervals of reaming or cleaning out junk).

Drill Bit TFA (Total Flow Area) Calculation System hydraulics can greatly affect drilling performance, eg: HSI and cuttings removal for high RoP, cutter cooling for drill bit life, etc. It is important that both the nozzle and pump liner size are selected to optimise the hydraulics for that application. The limiting factor may be available rig power. The drilling rig motor that drives the mud pumps, combined with the pump liners sets the maximum stand pipe pressure and flow rate available. • • • • • • • •

Flow is the critical medium that cleans, cools and lubricates the cutting structure and bit, (critical for unsealed roller cone bits). In some applications, drilling with minimal flow rate will cause rapid degradation of the drill bit cutting structure. HSI is a primary factor for maximising RoP. HSI is the energy at the bit that transports the cuttings from the bit face into the annulus. Flow rate is another important factor. High flow rate helps lift the cuttings to surface. Turbulent flow is generally achieved around the drill bit. Laminar flow is generally preferred around the drill string to prevent hole damage. The Reed-Hycalog Hydraulics program should be run to optimise the hydraulics for either maximum HSI or maximum flow rate depending on the application requirement. If there is the possibility of pumping lost circulation material, small jet sizes should not be run as the risk of plugging them is high. As a general rule, nozzle sizes under 12/32nds should not be run. Calculation of expected pressure change if one of the nozzles becomes plugged or is lost.

Drill Bit Running Procedures

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Preparing the Bit to be Run in Hole These are final checks to ensure that the correct bit with the correct nozzle sizes is run hole and recorded accordingly. • • • •

•

Record bit type, size and serial number. Ensure there is no debris inside the central feed bore and the individual feed bores that could potentially plug a nozzle. Ensure the bit is jetted with the correct size nozzles as indicated by the Drill Bits TFA calculation. If either damaged in transit, a rerun or a repaired bit. o Record bit condition/dull grade o Photograph the bit as outlined in the Dull Bit Photos section. Take extra shots of damaged/worn area as necessary. If a motor is to be tested in the casing recommend using a dull bit rather than the bit required to drill the section. This eliminates the risk of damaging the bit planned for the section in the casing.

Making Up the Bit to the Drillstring Ensure that the bit is not manhandled on the rig floor and if it is damaged record the incident and damage appropriately. If there is severe damage it may be necessary to recommend that a different bit be run in hole. • • • • • • •

Witness the bit and BHA get made up to the string and run through the rotary table. Ensure the bit is handled correctly on the rig floor and not damaged, eg: never place a PDC bit cutting structure directly on the steel decking of a rig floor as this risks damaging cutters, ideally use a wooden or rubber mat. Clean and grease API pin/box connection of both bit and drill string. Using the Reed-Hycalog bit breaker, locate bit in rotary table. Lower drill string onto the bit and engage threads. Either make up by hand or slow rotation. Torque up connection to the specified torque for that API connection, (this can be found on the Product Report that accompanies the bit in the bit box).

Drill Bit Running Procedures

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Running in Hole When tripping there is little that a Field Engineer can influence. The rig crew will try and trip in hole as fast as possible to return to drilling. It is worth noting the following points and communicating them to the oil company representative and the driller. • • •

• • •

Take care running through diverters, BOPs, well heads, casing shoes, etc. Approach tight spots slowly as striking ledges can damage the bit cutting structure. When reaming tight spots pump at maximum flow rate, rotate the string with low rotary speed (50-60rpm approx) and low weight on bit, (no more than 4,000lbs). In a tight spot the weight is only supported by the cutting structure towards gauge resulting in higher weights on individual cutters, insets or teeth than is normally the case. Hence, to prevent cutting structure damage low weight should be recommended. On the final stand/kelly wash the hole at full flow to bottom and rotate the string at low rotary speed to prevent plugging a nozzle or balling the bit with cuttings, cavings, etc that may have collected in the bottom of the hole. Watch for an increase in torque and weight when approaching bottom to identify when the bottom of the hole has been tagged. Lift off bottom 6-12” at maximum flow while rotating the bit for 5 mins approx to clean the bottom of the hole.

Drilling Out the Wiper Plugs, Cement, Shoe and Float Assemblies Different types of drill bits and bottom hole assemblies have different drill out procedures. When designing a drill out float assembly for PDC applications, ‘PDC friendly’ equipment will ensure a successful run (ie: more plastic and rubber components make for an easier drill out). Liner running tools and float equipment that require an activating ball to set or close the liner hanger or float valve can cause problems during drill out. These balls (typically made of brass) can damage the bit resulting in slower penetration rates and failure to complete the desired interval. Aluminium landing collars can also be problematic. Aluminium in the dart, landing collar, float collar and float shoe can plug the junk slots of the bit impairing bit cleaning/cooling and hence bit performance. Continued over….

Drill Bit Running Procedures

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PDC (including SteeringWheel and BiCentrix), Impregnated and Diamond Drill Bits • Natural diamond impregnated and surface set diamond drill bits will take 25-50% longer than PDC drill bits to drill out casing shoe assemblies. • Ensure there is no metal or junk in the hole. • Do not use Automatic Driller. • Wash and ream to bottom with maximum flow rate at least 30’ above where the cement is expected. • Use 50-60rpm with a rotary assembly and 20-40rpm with a motor assembly. • Tag bottom slowly with 4,000lbs maximum weight on bit and look out for green/wet cement. • If the bit does not drill off, reciprocate the drill pipe. Do not stay on bottom if bit is not drilling. • Use as little weight as possible, do not exceed maximum recommended weight on bit. • If the wiper plugs begin to rotate, it may be necessary to tag bottom without rotation and increase weight on bit slowly. Do not spud the bit into the float equipment. Once sufficient weight on bit (start with 6-8klbs and increase as necessary) is applied, slowly increase rotary to 60-80rpm. Repeat as necessary to drill through the remainder of the plugs. • Monitor penetration rates and adjust weight on bit as necessary. • In difficult drill out applications allow the weight to reduce/drill off naturally and evaluate penetration rate. Repeat this process until a more consistent drilling pattern is established. • Raise the bit 2 feet off bottom and circulate once the plugs are drilled and midway through drilling the float collar assembly, (repeat as often as dictated by hole conditions/bit performance). • Reducing or stopping the flow rate may cause the bit junk slots to pack-off. Use extreme caution when reducing flow rates during drill out. • On semi-submersible and drill ships where the rig may heave, use the compensator to prevent spudding the bit. Rig heave can complicate a successful drill out and can cause bit balling. Roller Cone Drill Bits, (Insert and Milled Tooth) • Wash and ream to bottom with maximum flow rate at least 30’ above where the cement is expected. • Use 50-60rpm with a rotary assembly and 20-40rpm with a motor assembly, (ensure correct motor has been selected as very high speeds do not suit some roller cone bits). • Do not use Automatic Driller. • Tag bottom slowly with 4,000lbs maximum weight on bit and look out for green/wet cement. • If the bit does not drill off, reciprocate the drill pipe. Do not stay on bottom if bit is not drilling. • Use as little weight as possible increasing to 10,000lbs if required, do not exceed maximum recommended weight on bit. • If the wiper plugs begin to rotate, it may be necessary to tag bottom without rotation and increase weight on bit slowly. Do not spud the bit into the float equipment. Once sufficient weight on bit (start with 68,000lbs and increase as necessary) is applied, slowly increase rotary to 90-100rpm. Repeat as necessary to drill through the remainder of the plugs. • Monitor penetration rates and adjust weight on bit as necessary. • In difficult drill out applications allow the weight to reduce/drill off naturally and evaluate penetration rate. Repeat this process until a more consistent drilling pattern is established. • Raise the bit 2 feet off bottom and circulate once the plugs are drilled and midway through drilling the float collar assembly, (repeat as often as dictated by hole conditions/bit performance). • Reducing or stopping the flow rate may cause the bit cutters to pack-off. Use extreme caution when reducing flow rates during drill out. • On semi-submersible and drill ships where the rig may heave, use the compensator to prevent spudding the bit. Rig heave can complicate a successful drill out and can cause bit balling. Drill Bit Running Procedures

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Bedding/Breaking the Bit In • • • • • • •

Approach bottom with maximum flow rate. Slowly set the bit on the hole bottom with no more than 4,000lbs weight and 40-60rpm to establish the bottom hole pattern. Extra care should be taken following a coring run due to the possible ‘stump’ left on the bottom of the hole. If the bit does not drill ahead increase weight until it does. Maintain as low weight as possible until the bit has drilled at least its own length. Until the bit has cut its own bottom hole pattern only some of the cutters will be in contact with formation so if weight is added too quickly, particularly in hard formations, these cutters may be overloaded and fail. Increase weight on bit to target weight on bit, (do not exceed recommended maximum for the bit). As a general rule, the optimum weight for a PDC is less than half that for a roller cone bit. Increase rotary speed up to target RPM.

Making Connections and Restarting Drilling • • • • •

Maintain full flow as bit is raised off bottom. Return to bottom with 50% of the target drilling rotary speed and full flow rate to wash and clean the hole. Return to bottom gently. Dropping the string too rapidly can cause the bit to tag bottom violently and damage the cutting structure. Increase weight on bit to target weight on bit taking care to avoid stick-slip or other detrimental vibrations. Increase RPM to target RPM.

General Drilling Parameters for ‘Clean’ Formations Clean formation refers to a homogenous formation that is not interbedded and is 100% one lithology type. These types of formations are rare as some shales for example include a certain sand and limestone content. However, selecting parameters that suit the primary lithology will generally optimise drilling performance. •

•

•

Soft clean shales o Increasing rotary speed generally improves penetration rate, (usually RPM has a greater effect on RoP than WoB). o There is minimal risk of damaging the cutting structure in this lithology. Hard clean chalk/limestones o Penetration rate is maximised by increasing cutter point loading to fracture the formation. High weight is recommended with low rotary speed to allow the cutters to bite into the formation. o Bits may suffer impact damage. If the formation is clean (ie: no sand content) the cutters should suffer minimal abrasive wear. Hard sandstones o Penetration rate is maximised by increasing cutter point loading so high weight is recommended. o To ensure the cutters can get a bite, low rotary speeds are preferred. o Bits may suffer both impact damage and abrasive wear. Low RPMs will reduce abrasive wear. o Low rotary speeds will also reduce penetration rate so a reasonable compromise must be reached.

Drill Bit Running Procedures

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Drilled Cuttings Analysis Regularly collect and analyse the cuttings coming over the shakers to confirm the formation lithology being drilled. It must be remembered that cuttings coming over the shakers take time to reach surface. This time can be calculated and the cuttings related to their drilled depth and those drilling parameters. Reviewing the cuttings shape and size can indicate drilling efficiency, ie: rock flower is very inefficient.

Fundamental Parameter Discussion Torque • Rotary torque is an indicator of what is happening at the drill bit. For exampleo PDC high torque -the bit is likely to be digging or if there is low RoP the torque could be being generated from the BHA and not the bit. o PDC low torque -the bit could be skidding in a hard formation, the cutting structure could be dull or the bit could be balled up. o Roller cone medium torque -the bit is likely to be digging. o Roller cone high torque -the bit could have locked cones, if this is the case the torque will reduce as the inserts/teeth wear down. o Roller cone low torque -the cutting structure could be dull or balled up. • In soft formations torque may indicate the bit is on bottom before the weight on bit gauge does. In such formations the torque gauge may be the best surface measurement by which to drill. • The torque could be considered to be too high when it starts to slow down surface rotary speed. • The torque is too high when it stalls the motor, rotary table or the top-drive. • Homogenous formations should produce a smooth constant torque signal. • Interbedded formations will produce torque changes as the bit and/or the BHA moves in and out of formation beds that have different rock strength and 'drillability'. • If downhole torque measurements are available they can be used in combination with surface measurements to gain a more accurate representation of what is happening in the well bore. Weight • As a drill bit cutting structure wears more weight will be required to achieve the same RoP in a homogenous formation. • PDC wear flats, worn inserts and worn milled tooth teeth will make the bit drill less efficiently. • Increase weight in increments of 2,000lbs approx. • In general, weight should be applied before excessive rotary speed so that the cutting structure maintains a significant depth of cut to stabilise the bit and prevent whirl. • If downhole weight measurements are available they can be used in combination with surface measurements to gain a more accurate representation of what is happening in the well bore.

Drill Bit Running Procedures

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Rotary Speed • Total bit rotary speed is equal to the surface rotary speed plus the down hole motor/turbine rotary speed. • Rotary speed is not limited when running PDC drill bits. • High rotary speed should be avoided in abrasive formations to prevent rapid abrasive wear. • High rotary speed should be avoided if the drill bit starts to whirl. • Rotary speed may be limited due to drill pipe or drive limitations. • Some rotary speeds can initiate drill string resonance (high levels of vibration) and should be avoided. Either increase or decrease RPM to avoid operating in drill string harmonic frequencies. • High rotary speeds in hard formations may reduce RoP as the cutters are unable to ‘dig in’. • The rotary speed that maximises RoP without causing other drilling problems is likely to be the ‘right’ one. Flow Rate • Flow rate greatly effects hole cleaning. Generally high flow rates provide better hole cleaning than low flow rates as they are better able to return cuttings to surface due to increased annular velocity. • Flow rate greatly effects bit cleaning. Generally high flow rates provide better bit cleaning than low flow rates by increasing hydraulic energy at the bit. • If a motor is in the hole increasing flow rate will increase the rotary speed developed by the motor. of Increasing motor speed must be considered carefully as it can greatly effect drilling performance• In clean shale increasing motor speed increases bit speed that will generally increase penetration rate without damaging the bit cutting structure or other downside. • In hard abrasive sandstone increasing motor speed increases bit speed that will generally increase penetration rate momentarily. However the higher rotary speeds will tend to increase the wear rate of the bit cutting structure that will reduce penetration rate and ultimately bit life. • Increasing motor and consequently bit speed can change the directional tendency of the bottom hole assembly with a bigger effect on building/dropping tendency than azimuth. The compromise between instantaneous penetration rate and sliding corrections must be considered. • High flow rates can cause formation damage especially in highly fractured formations so excessive flow rates must be avoided.

Drill Bit Running Procedures

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Optimising Drilling Performance Optimising drilling performance is frequently interpreted as maximising penetration rate. However, this is not always the case as in some applications drilling performance will be optimised by maximising run length and reducing the number of trips. In these applications, an example of which is interbedded formations, the goal is to protect the cutting structure so it may be necessary to compromise penetration rate for run length. A diligent driller that performs frequent drill off tests for drilling parameter optimisation will always drill further and faster than the driller who “sets and forgets”. Parameter optimisation can significantly reduce cost per foot. Points to note are• • •

• • • •

Be on the rig floor at all crew changes. This is critical to ensure optimum drilling parameters are maintained, to update the new driller of the current drilling/rig issues and of any drilling parameter testing in progress. If running a motor, try setting the automatic driller to run off motor differential pressure rather than weight on bit. This generally corrects the weight faster, consequently the weight will be applied more consistently and better performance achieved. Conduct a series of drill-off tests at various weights (eg: 2-5,000lbs increments), rotary speeds (eg:5-10rpm increments) and flow rate (to change down hole RPM if a motor is in the hole although care is required as flow rate changes will also effect bit HSI and hole cleaning) to find the optimum drilling parameters to achieve satisfactory penetration rate or to minimise bit/BHA damage. Formation changes can result in a penetration rate change, eg: if the RoP reduces and reasonable torque is still generated the formation is likely to be harder so the rotary speed should be reduced and weight increased. If this generates too much torque, weight should be reduced and rpm increased. Monitor mud weight. As mud weight increases, RoP generally decreases. When closer to balanced drilling (where the mud pressure equals the formation pore pressure) RoP generally increases. Maintaining good notes is very important for optimising drilling performance over an entire run. It also aids understanding/problem solving if the drilling becomes problematic. If this is completed in a spreadsheet down hole rpm, etc can easily be calculated and plotted to watch for trends, see Figure 1. Parameter readings are more accurate if read directly from the gauges (Martin Decker for WoB, the stand pipe gauge for pressure, etc) than those displayed on the rig floor monitor or geolograph. The rig floor monitor and the geologragh can be inaccurate unless they are frequently recalibrated as hole is drilled.

Pump 1 Pump 2 Stand Torque Torque Strokes Gallons Strokes Gallons Total Pipe Date Time Rotary Depth RoP WoB RPM RPM RPM OnOffper Liner per Flow per Liner per Flow Flow Pressure /Slide (ft) (fph) (klbs) Surface Motor Total Bottom Bottom Minute Size Stroke (gpm) Minute Size Stroke (gpm) (gpm) (psi) Comments

Figure 1: Spreadsheet for recording and calculating drilling parameters.

Drill Bit Running Procedures

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BP Formalised Drill-Off Test Procedures Summary Drill-off tests are essential to identify which factors are limiting ROP on a particular bit run, and the levels of WOB and RPM that will give best ROP for the constraints acting during that bit run. This section describes how to perform a drill-off test, and how to treat the resultant mud logging data to yield clear drilling parameter relationships to ROP, so that the best WOB and RPM can easily be chosen. There are two types of drilling test available to relate WOB and RPM to ROP : 1. A "drill-off" test, where the WOB is built to a selected level, the brake locked, and the bit allowed to drilloff as the string extends under its own weight. RPM and flow rate are held constant as the bit drills off, and the drill off is then repeated at different rotary speeds. ROP is calculated from the rate of WOB decay as the bit drills off, and plotted versus WOB for each RPM 2. A "drillability" test, where pairs of WOB and RPM are chosen, and a certain depth increment drilled at each pair. Average values of WOB, RPM and ROP are then taken for each interval, and crossplots of ROP versus WOB created, again for each RPM. The first type of test is generally preferred, because a range of WOB and ROP data is gathered while the bit drills off over only a very small interval. Thus the results are less likely to be affected by formation changes. The second type of test is however useful when prevailing ROP is very high, because insufficient (time-based) data can be gathered if the bit drills-off rapidly at high WOB during the drill-off type of test. The second type of test guarantees acquisition of a minimum amount of (foot-based) data irrespective of ROP. Both types of test may be limited as to the maximum applicable weight on bit, either by motor stalling when a motor is in use, by weight below the jars, or by torque cycling if the soft torque system is not perfectly in tune. In addition, varying surface RPM when a motor is in use may be of little value, since small changes in surface speed make little difference to bit speed with a motor in use. Motor speed will probably need to be constant since a flow rate stipulation will be in effect for hole cleaning. Both types of test have been run in BPXC wells since 1993, and have proven useful and relatively easy to perform. The most laborious step involves treating the mud logging data to reduce the contribution of errors in the ROP measurement. To aid this, BP's methods have been built into drill-off test software which is currently being installed onto Exlog and Geoservices mud logging systems. Since this software is as yet incomplete and not validated, a more generalised method for drilling tests is described next, where data is treated using conventional spreadsheet packages.

Drill Bit Running Procedures

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Drill-off Test Method 1 – Locked Brake Test Planning and supervising the test 1. Choose the WOB to drill off from/to. Choose upper limit noting torque cycling, motor stalling, weight below jars, and bit limit (from catalogue). Drill-off over as wide a range as possible within these constraints. 2. Choose the three rotary speeds to be applied (if a rotary BHA). Choose as wide a range as possible, e.g. 80, 140 & 200 RPM (a lower maximum may be applicable with a tricone bit). 3. Notify the mud logging unit that a test is to be performed. 4. Ensure that the WOB is simultaneously zeroed by the driller and the mud logging unit immediately before the test. Note the reference hookload (string weight) values (from the mud logging display and the Martin Decker gauge), while rotating off bottom at the same RPM and SPM as will be used during the drill-off test. 5. With the middle RPM value, build the WOB up to the desired maximum, lock the brake, and allow the bit to drill-off at constant RPM/SPM. Lower the desired maximum WOB and restart the test if torque cycling is severe. 6. Repeat step 5 with the highest and lowest RPM, and lastly with the middle RPM (this last repeat drill-off will give some idea if the formation remained constant, and if the data quality is good). 7. Return to normal drilling. Instruct the mud loggers to process the drill-off test data. Processing of the data by the mud loggers During the test, the logging system should run a time database and chart recorder, gathering the following data at an interval not longer than every 30 seconds: time, block height, hookload, instantaneous WOB, RPM, average torque, sigma torque, flow rate in, pump pressure. These data will be used for the computations described here. • Calculate a value for the axial stiffness (compliance) of the drillpipe (ignore the HWDP and drill collars). The formula is : C = L/E (Fdp1/Adp1 + Fdp2/Adp2), C L E Fdp1,2 Adp1,2

= = = = =

in which

compliance (m/kn) total length of drillpipe (m). Exclude HWDP and drill collars young's modulus for steel (gpa) fraction of drillpipe length for pipe of size 1 and 2 (e.g. 5" and 6.5/8" pipe) cross-sectional area of pipe of size 1 and 2, (e.g. 5" and 6.5/8" pipe) (sq.mm).

Example values are : E Adp Adp Fdp1 Fdp1

= = = = =

206 gpa for drillpipe 5354 sq.mm for 6.5/8" drillpipe (average of body and tooljoint) 4153 sq.mm for 5" drillpipe (average of body and tooljoint) 1 if the drillpipe is all of 1 size 0.4 if 40% of the drillpipe length is of 1 size, with 0.6 (60%) of the other size.

Note that to convert C to ft/klb, multiply C (m/kn) by 14.5939. • From the acquired chart or time database data, identify the start and end of each drill-off interval Drill Bit Running Procedures

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• From each drill-off interval, read the following data into a spreadsheet : time, hookload, instantaneous WOB, pump pressure (the latter if a motor BHA only). • Within the spreadsheet, perform the following calculations for each line of data : Delta time Depth change ROP Avg. WOB

= = = =

time spacing between data points (secs) C * (Inst. WOB - previous inst. WOB) (feet) Depth change * 3600/delta time (ft/hr) (Inst. WOB + previous inst. WOB / 2) (klbs)

• Crossplot average WOB (x axis) versus ROP (y axis), for each RPM. Label or code each curve for the RPM value. • If the plot is noisy (e.g. attachment 11), repeat the calculations by selecting only intermittent data points, i.e. by expanding delta time (all four of the above calculations must be repeated). • Repeat the last step with longer time increments until clear ROP/WOB relationships appear. Avoid using excessively long time increments, since the character of the ROP/WOB relationship will be suppressed. A delta time of 1-4 mins will normally suffice; use the lowest that gives a clear plot. • Deliver the crossplot to the Drilling Representative or Assistant. An example of the spreadsheet calculations is shown on the attachment (note that on the attachment example, WOB was calculated from the difference between reference hookload and instantaneous hookload, because the raw WOB data was unreliable. Note also how two separate sets of ROP and AVG. WOB were computed using different delta times). Interpreting the test results Review the ROP/WOB crossplot. Use the examples on attachments to aid identification of excessive drag or bit dulling. Choose the optimum WOB and RPM noting any excess torque cycling at high WOB/low RPM, and any WOB/RPM constraints for required BHA directional behaviour. If possible, choose the lowest WOB and RPM that gives maximum ROP (if additional loads are applied without any extra ROP, this will only shorten bit life). Note that when informing the driller of the chosen optimum WOB, the value from the crossplot will be the mud loggers' value of WOB. Any discrepancy with the Martin Decker WOB will need to be rectified before the driller is given an optimum WOB.

Drill Bit Running Procedures

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Drill-off Test Method 2 – Drillability Test Planning and supervising the test 1. Choose the three or four WOB values to use during the drillability test. Choose the highest WOB noting torque cycling, motor stalling, weight below jars, and bit limit (from catalogue). 2. Choose the three rotary speeds to be applied at each WOB (if a rotary BHA). Choose as wide a range as possible, e.g. 80, 140 & 200 RPM (a lower maximum may be applicable with a tricone bit). 3. Notify the mud logging unit that a test is to be performed. 4. Start the test early enough in the drilling of a stand so that making a connection will not be necessary before the test is completed. 5. Ensure that the WOB is simultaneously zeroed by the driller and the mud logging unit immediately before the test. Note the two reference hookload (string weight) values (from the mud logging display and the Martin Decker gauge), while rotating off bottom at the same RPM and SPM as will be used during the drilling test. 6. With the first WOB value, drill 5 ft with each of the three RPM's. Abort the test at highest WOB if torque cycling is severe, and restart with lower WOB. Ensure the driller works to maintain as constant WOB as possible. 7. Repeat step 6 with the other WOB values. 8. Return to normal drilling. Instruct the mud loggers to process the drill-off test data. Processing of the data by the mud loggers During the test, the logging system should run a time database and chart recorder, gathering the following data at an interval not longer than every 30 seconds: time, block height, hookload, instantaneous WOB, RPM, average torque, sigma torque, flow rate in, pump pressure. These data will be used for the computations described here. If any problems exist with these data, conventional depth database data can be used. • From the time database or chart recorder data (former is preferred), identify the start and end of each period of constant WOB and RPM • Calculate an accurate average of WOB and RPM for each period when these parameters were held constant • For each period of constant WOB and RPM, calculate an average ROP from the change in block height, and the duration of the period. • Repeat the calculations for each period of constant WOB and RPM. • Crossplot average ROP (y axis) versus average WOB (x axis), for each RPM. • Deliver the crossplot to the drilling Representative or Assistant. An example of part of a time database data set from this type of drilling test is shown. The final ROP/WOB crossplot is shown. Two RPM's were used at each WOB in this case.

Drill Bit Running Procedures

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Interpreting the test results Review the ROP/WOB crossplot. Use the examples to aid identification of excessive drag or bit dulling. Choose the optimum WOB and RPM noting any excess torque cycling at high WOB/low RPM, and any WOB/RPM constraints for required BHA directional behaviour. If possible, choose the lowest WOB and RPM that gives maximum ROP (if additional loads are applied without any extra ROP, this will only shorten bit life). Note that when informing the driller of the chosen optimum WOB, the value from the crossplot will be the mud loggers' value of WOB. Any discrepancy with the Martin Decker WOB will need to be rectified before the driller is given an optimum WOB.

Drill Bit Running Procedures

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PROCESSING DRILL-OFF TEST DATA DRILL-OFF TEST Drillpipe length = DP modulus = Area of DP = Compliance = Compliance =

DRILLABILITY TEST

2000 m 206 GPA 4153 mm*mm 0.0023 m/kn 0.0104 m/klb

Drill off test at (depth): m Date: 10/11/97 dd/mm/yy Bit type: G536GU 12.1/4"

Drillability test at (depth): Date: Bit type:

699 m 1/9/97 dd/mm/yy 17.1/2" O2M

10 mins at each pair: Raw drill-off test data: WOB from M.De c ke r

mins

Calculated c o m p lia nc e

Delta WOB

Interval d rille d

Average WOB

Calculated ROP

RPM

Test

klbs

m/klb

klbs

m

klbs

m/hr

revs/min

1

50

0.010398898

2

45.5

0.010398898

4.5

0.046795

47.75

2.81

3

42

0.010398898

3.5

0.036396

43.75

2.18

4

38.7

0.010398898

3.3

0.034316

40.35

2.06

5

35

0.010398898

3.7

0.038476

36.85

2.31

6

110 110 110 110 110 110 110 110 110 110 110 110 110 110 110 110 110 110 110

31.8

0.010398898

3.2

0.033276

33.4

2.00

7

29

0.010398898

2.8

0.029117

30.4

1.75

8

27.2

0.010398898

1.8

0.018718

28.1

1.12

9

24

0.010398898

3.2

0.033276

25.6

2.00

10

21.8

0.010398898

2.2

0.022878

22.9

1.37

11

19.9

0.010398898

1.9

0.019758

20.85

1.19

12

18

0.010398898

1.9

0.019758

18.95

1.19

13

16.1

0.010398898

1.9

0.019758

17.05

1.19

14

14.7

0.010398898

1.4

0.014558

15.4

0.87

15

12.9

0.010398898

1.8

0.018718

13.8

1.12

16

11.8

0.010398898

1.1

0.011439

12.35

0.69

17

10.6

0.010398898

1.2

0.012479

11.2

0.75

18

9.9

0.010398898

0.7

0.007279

10.25

0.44

19

8.9

0.010398898

1

0.010399

9.4

0.62

20

8.1

0.010398898

0.8

0.008319

8.5

0.50

80 80 80 80 140 140 140 140

WOB klbs 20 40 50 60 20 40 50 60

ROP m/hr 1.4 8.5

4.3 9.1 11.6 14.4

16 14 12

80 rpm

10

140 rpm

8 6 4 2 0 0

10

20

30

40

50

60

WOB (klbs)

EXAMPLE DRILL-OFF TEST

ROP (m/hr)

Distance drilled (m) 0.23 1.42 Slip-stick Bouncing 0.72 1.51 1.93 2.4

Drill-off test: 17.1/2" 02M at 699m, BJ-2

ROP (m/hr)

Time ste p

RPM

y = 0.0529x + 0.1328

3.00 2.50 2.00 1.50 1.00 0.50 0.00

2

R = 0.897

0

10

20

30

40

50

WOB (klbs) 110 RPM

INTERPRETING DRILL-OFF TEST RESULTS 1 2 .1 /4 " DS 4 7 H, C5 FO RM. @ 1 3 0 0 5 ft, 1 4 0 RP M 6 .0 0

17.1/2" MAX-11HD IN C5, @ 9256ft, 160 RPM

y = 0 .1 4 4 9 x + 0 .6 0 1 4 R 2 = 0 .9 2 4 4

5 .0 0

Ser ies1

8.00

L in e ar (Ser ies1 )

7.00

T e s t s h o ws ROP d e c re a s in g to wa rd ze ro a s W OB fa lls to wa rd ze ro , ie n o rma l. No te th e b e s t-fit lin e fitte d , u s in g th e " In s e rt" " T re n d lin e " o p tio n in e xc e l.

2 .0 0 1 .0 0 0 .0 0 0 .0 0

1 0 .0 0

2 0 .0 0

3 0 .0 0

ROP (ft/hr)

ROP (ft/hr)

4 .0 0 3 .0 0

Two drill-off tests from within one bit run. Second shows flatter response of ROP to WOB, perhaps due to bit wear

9.00

Sharp bit

6.00

ROP (ft/hr)

5.00 4.00 3.00

Test shows decreasing benefit of WOB, as WOB rises

2.00

Dull bit

1.00 0.00 0

4 0 .0 0

20

40

60

80

WOB (klbs)

100

W O B (klbs)

W O B ( k l bs )

Typical test result; ROP will only be close to zero as WOB approaches zero, and response is linear

Decreasing benefit of higher WOB; perhaps due to imperfect bit cleaning (e.g. in water base mud/shale)

Decreasing response of ROP to WOB; often seen as a PDC bit suffers abrasive wear of the cutters

The two types of drilling test Drill-off test showing drag, ie bit stops drilling off before zero WOB is reached. Pump pressure confirms drag by disappearance of differential when the bit stops drilling off, probably showing WOB no longer reaching the bit

Drill-off test: 17.1/2" 02M at 699m, BJ-2 16 14

ROP (ft/hr)

Pump pressure

ROP (m/hr)

12 WOB

80 rpm

10

140 rpm

8 6 4 2 0 0

20

40

60

WOB (klbs)

Drill-off test with a steerable motor in a deviated well; considerable drag detected

Drill Bit Running Procedures

Drillability test, in which the combination of low RPM and high WOB was impossible due to cyclic torque.

1. Drill-off test, in which: • pick-off bottom, & set RPM and flow rate • return to bottom, build to maximum WOB • let the bit drill-off with brake locked. Note WOB every minute • repeat at other RPM’s • mud loggers calculate ROP from hookload changes • mud loggers plot ROP vs WOB and RPM. 2. Drillability test, in which: • set RPM and flow rate • drill for 10 minutes with constant WOB; write down distance drilled in 10 min period • repeat at other WOB values • repeat sequence with other RPM’s • mud loggers plot ROP vs WOB and RPM.

Page 22 of 38

Drillstring Dynamics/Vibration General • Drillstring vibration is inevitable. • Low levels of vibration can be harmless. • Severe downhole vibrations can be problematic and can cause the followingo Drillstring failure, washout/twist off o Premature bit failure o Poor directional control o Damage to well bore, hole enlargement o Rotary drive stalls, top drive/rotary table o Motor stalls o Motor failure, bearings/stator o MWD failure o Stabiliser/tool joint wear o Reduced penetration rate • Primary drillstring excitation forces areo Bit/formation interaction o BHA/borehole interaction o Downhole motor/turbine o Rotary drive type • The response of the drillstring to excitation forces is complex. • The complexity of vibration is due to the physical coupling between the bit and the drillstring and the coupling of vibration mechanisms. • Identify if the rig is equipped with a rotary feedback system (“soft torque”) and whether it is activated. Types of Vibration • There are three types of vibrationo Axial, motion along the drillstring axis. o Whirl, eccentric rotation of a component about a point other than its geometric centre that can generally be recognised/seen as lateral vibration (side to side motion). This can relate to both the bit and the bottom hole assembly. o Torsional, motion causing twist/torque/stick-slip. • These types of vibration can co-exist and produce symptoms that belong to more than one vibration mechanism. This can make the detection process iterative for identification and cure. Drillstring Resonance • Drillstrings have their own natural frequencies for vibration relating to rotary speed. • Excitation frequencies close to the natural frequency of the drillstring will cause the drillstring to resonate, (vibrate laterally and/or torsionally). • A resonating drillstring can be highly damaging to bit/BHA components. • Rotary speeds that induce and sustain drillstring resonance should be avoided.

Drill Bit Running Procedures

Page 23 of 38

Axial Vibration General • Severe axial vibration leads to Bit Bounce. • Vibration range is 1-10Hz, (1Hz is equal to 1 vibration cycle per second). • Most frequently occurs when drilling with roller cone bits in hard formations. • Occasionally occurs with PDC drill bits in hard formations. • Caused by weight on bit fluctuations. Extreme WoB variance can cause the bit to lose contact with the bottom of the hole and then impact back to bottom. • The three cones of a roller cone bit will generate a tri-lobe pattern causing the bit to be axially displaced three times per bit revolution. • Can be caused by formation change. Detection • Large surface vibration. • Axial movement of pipe at surface. • Large weight on bit fluctuations. • High levels of axial vibration from MWD tools. Consequences • Bit damage including cutting structure/bearings/seals. • Reduction in penetration rate. • Short run lengths. • BHA washout. • MWD failures. Cures and Control • Destroy tri-lobe bottom hole pattern by eithero Changing drilling parameters. o Lifting off and returning to bottom with lower weight and lower rotary speed. • Run a shock sub in the BHA. • Running shock subs with PDC bits is not recommended as they can lead to bit ‘chatter’ (high frequency vibrations) that can chip and prematurely fail PDC cutters.

Drill Bit Running Procedures

Page 24 of 38

Bit Whirl General • The eccentric rotation of the bit about a point other than its geometric centre. • Whirl is a self perpetuating motion. • Types of whirlo Forward whirl, the centre of rotation rotates in the same direction as the drillstring. Causes flat spots on stabilisers and tool joints. o Backward whirl, the centre of rotation rotates in the opposite direction to the drillstring. Is more violent than backwards whirl and can cause severe cutting structure damage. o Chaotic whirl, the whirl rotation moves between forward and backward whirl. • Can generally be recognised/seen as lateral vibration (side to side motion). • Whirl induces high frequency lateral/torsional vibrations in the range 10-50Hz, (10Hz is equal to 10 vibration cycles per second). • Causes a dramatic increase in impact loading on the bit cutting structure causing rapid failure. • Motors with bent housings can cause whirl. • Can be initiated by formation change. • Frequently seen while reaming. • BHA whirl can induce bit whirl and vice-versa. Detection • Can be difficult to detect at surface. • Generally seen at high RPMs and low WoBs. • Increased surface and downhole torque. • High frequency downhole lateral/torsional vibration. • Increase in MWD shock counts. • Reduction in penetration rate. • Over gauge hole. • Cutter impact damage, generally over the shoulder and gauge areas of the bit. Consequences • Bit damage, cutting structure damage generally over the shoulder and gauge areas of the bit. • Reduction in penetration rate. • Short run lengths. • BHA washout. • MWD failures. • Motor failures. Cures and Control • Reduce rotary speed and increase weight on bit. • Ream at lower rotary speeds. • Destroy bottom hole whirl pattern by eithero Changing drilling parameters. o Lift off bottom and attempt to restart drilling without initiating whirl, try high WoBs and low RPMs • Run anti-whirl or SteeringWheel bit. • Run higher torque and lower speed motors so that higher weights can be applied. • Run roller reamers instead of stabilisers. Drill Bit Running Procedures

Page 25 of 38

BHA Whirl General • The eccentric rotation of the BHA about a point other than its geometric centre. • Whirl is a self perpetuating motion. • Types of whirlo Forward whirl, the centre of rotation rotates in the same direction as the drillstring. Causes flat spots on stabilisers and tool joints. o Backward whirl, the centre of rotation rotates in the opposite direction to the drillstring. o Chaotic whirl, where the bit moves between forward and backward whirl. • Can generally be recognised/seen as lateral vibration (side to side motion). • Initiated by friction between stabilisers/tool joints and the well bore leading to gearing of the BHA around the hole. • Whirl induces high frequency lateral/torsional vibrations in the range 5-20Hz, (5Hz is equal to 5 vibration cycles per second). • A stabiliser passing a ledge or through a formation change can initiate BHA whirl. • Mud properties greatly affect BHA whirl as the mud is the lubricant that reduces friction between the stabiliser/tool joint and bore hole wall. • Bit whirl can induce BHA whirl and vice-versa. Detection • Can be difficult to detect at surface. • Increased surface torque. • High frequency downhole lateral/torsional vibration. • Increase in MWD shock counts. • Localised wear on stabilisers and tool joints. • Damage to stabiliser blades. Cures and Control • Change drilling parameters, reduce rpm and raise WoB. • Increase mud lubricity, eg: pump a pill. • Run roller reamers or non rotating stabilisers. • Run non rotating drill pipe protectors. • Lift off bottom and attempt to restart drilling without initiating whirl, high weights and low RPMs should facilitate this.

Drill Bit Running Procedures

Page 26 of 38

Torsional Vibration General • Severe torsional vibration leads to stick-slip. • Stick-slip vibration range is below 1Hz, (1Hz is equal to 1 vibration cycle per second). • Stick-slip is the rotary acceleration and deceleration of the drillstring. The bit can stop rotating momentarily at regular intervals causing the drillstring to windup and the torque to increase. The drillstring will then brake free and accelerate the bit to high rotary speeds with minimal torque. • Stick-slip motion is often accompanied during its slip phase by lateral vibration of the BHA. • Most common with PDC drill bits and can cause severe and rapid damage to their cutting structures. • Can be formation dependent. • Can be caused by the interaction ofo the bit and formation. o the BHA and the bore hole, eg: stabilisers ‘digging in’ to a soft formation. o the drillstring and the bore hole, (eg: high well bore tortuosity). • Can be caused by the drive system characteristics. • Generally occurs at low rotary speed and high weight on bit. Detection • Can be detected at surface by both torque (Max – Min Torque > 20% Mean Torque) and rpm variance. • Increased surface mean torque. • Rotary drive stalls, (rotary table or top drive). • Increase in MWD shock counts. • Downhole rpm can range from zero to up to 2-3 times surface rpm. • Bit impact damage, cutting structure damage generally seen over the nose of the bit. • MWD tool failure. • Reduced penetration rate. • Over torqued connections, washouts and twist-offs. • Connection back-off due to backward rotation. • Downhole memory data acquisition and analysis. Cures and Control • Change drilling parameters, increase rpm and reduce WoB. • Increase flow rate for increased motor RPM and increased lubricity/reduced friction due to improved hole cleaning. • Run rotary drive system (rotary table or top drive) in higher gear. • Run a soft torque system. This consists of a top drive or rotary table feedback mechanism that regulates surface torque fluctuation by altering rotary speed thus enabling more uniform bit rotation. The system must be regularly tuned to take account of changing parameters including depth and formation. • Increase mud lubricity, eg: pump a pill. • Run a motor to decouple the drill bit from the drillstring and to increase bit RPM. • Run roller reamers or non rotating stabilisers. • Lift off bottom and attempt to restart drilling without initiating stick-slip, high RPMs and low weights should facilitate this.

Drill Bit Running Procedures

Page 27 of 38

Vibration Coupling • Vibration mechanisms can be coupled since some can trigger others, for exampleo Bit whirl can be triggered by high bit speeds generated during stick-slip motion. o Stick-slip can generate lateral vibration of the BHA as the bit accelerates during the slip phase. o Large lateral vibration of the BHA into the well bore can cause bit bounce. o Bit whirl can induce BHA whirl and vice-versa. o Bit torsional vibration can induce BHA torsional vibration and vice-versa.

Drill Bit Running Procedures

Page 28 of 38

Vibration Monitoring General • It is essential to establish what vibration mechanism is occurring downhole in order to prescribe the correct remedial actions. • Corrective actions for one may exacerbate another, eg: the corrective actions for bit whirl are directly opposite than those for stick-slip. Tool Inspection • The nature of damage to downhole drilling components can often be a direct indication of the vibration source and mechanism. For exampleo The location of bit impact damage could suggest bit whirl or stick-slip, (shoulder and gauge for whirl, nose and face for stick-slip). o Flat spots on tool joints are evidence of forward whirl. o Damage to stabiliser blades is an indication of BHA whirl and lateral vibration. Mud Logging Data • Mud logging data can provide the following surface measurementso Mean torque. o Max/min torque. o RPM o WoB o Flow rate • This data gives a good indication of whether stick-slip is present, ie: separation between max and min torque is indicative of stick-slip type vibration. • To improve accuracy, set the chart recorder speed between 0.1-0.3 ft/min. MWD Data • MWD data can serve as an invaluable real time monitoring system. • An increase in the number of lateral shocks above a threshold value (usually set at 25g’s) provides a direct indication of severe BHA lateral vibration. • Schlumberger D&M, Baker Hughes Inteq and Sperry-Sun provide MWD tools with shock measurements. • Other down hole measurements that give a true indication of whirl or stick-slip at the bit areo RMS torsional vibrations. o RMS axial vibrations. o RMS lateral vibrations. • Gamma ray can indicate if any of the vibration mechanisms are related to lithology, ie: correlate formation changes to vibration changes. • If a rock strength analysis is completed (both gamma and sonic required as minimum) it may indicate if rock strength is inducing the vibration mechanisms. LWD/Wireline Log • Calliper data indicates hole oversize and provides evidence for either bit or BHA whirl.

Drill Bit Running Procedures

Page 29 of 38

High Frequency Surface Measurements • High frequency surface measurements of axial and torsional vibration can help indicate bit whirl, especially in shallow and non-deviated wells. • Baker Hughes Inteq can provide these measurements. Downhole Recording • In deviated wells, it is not usually possible to detect high frequency events such as bit whirl from surface measurements due to dampening and attenuation of lateral vibrations. • Downhole recording of the vibration data can be analysed for subsequent wells. • Schlumberger (DRT) and Sperry-Sun can provide downhole vibration measurement recording tools.

Drill Bit Running Procedures

Page 30 of 38

Factors Related to Bit Run Termination For a quick reference of common problems see Appendix 1. Economics • Frequently assess the run economics for the benefit of the operator, for exampleo At a formation change, it may be more economical to replace an insert bit with a faster PDC bit even though the insert bit still has many operating hours left. o It may be more economical to pull a bit early to achieve a shorter trip and then complete the section with a longer final run. Worn Cutting Structure • Cutting structures wear out, (PDC/insert/milled/impreg/diamond). • A worn cutting structure requires more weight to achieve the same penetration rate as a new/green cutting structure, ie: RoP generally decreases. • If the gauge area of the cutting structure wears first the bit can become a ‘wedge shaped plug’ that fits tightly in the hole. This can cause high on-bottom torque even with low weight on bit, very low penetration rate and often accompanied by an increase in SPP. Under gauge bits can also cause the stabilisers to hang up and cause general BHA damage. • As an impregnated or surface set diamond bit wears the standpipe pressure will increase due to a reduction of the flow area. This is due to a reduction in blade height due to wear. • As a PDC bit wears, for a given weight on bit, torque generally reduces as the cutting structure is no longer as aggressive. • Severe PDC wear can result in the blades being worn down to the bit body/nozzles. Consequently, a significant increase in SPP will be seen as the flow is restricted due to contact of the bit face and the formation. Worn/Failed Bearings on Roller Cone Bits • If it is thought that the bearings have failed the bit should be immediately pulled. Failed bearings can deteriorate rapidly and result in losing a cone downhole. This is a very serious and expensive failure for the oil company due to lost time fishing. • There are various symptoms that suggest a bearing failure, for exampleo Torque changes: spikes, character or overall level not related to parameter or formation changes. o RoP changes: not related to parameter or formation changes. The RoP can increase temporarily as the skew angle of a cone increases with a failed bearing. o Directional responsiveness change: loss in control of toolface. o MWD signal quality deteriorates as the vibration from the bit masks the signal. Bit Balling • Usually occurs when drilling soft sticky formations with WBM. • Some formations, predominantly shales react with water swelling considerably and becoming sticky. • Montmorillonite content is the most significant factor with respect to formation hydration and bit balling. • Montmorillonite changes to illite with time and temperature. • Kaolinite does not hydrate and react with water.

Drill Bit Running Procedures

Page 31 of 38

•

• • • •

• •

• •

The order of claystones with greatest to least balling tendency iso Montmorillonite o Mixed layer, montmorillonite and illite o Illite o Kaolinite Swollen and sticky cuttings can adhere to the bit clogging up waterways, junk slots, individual cones and possibly the entire bit. Severe balling results in total clogging up of the cutting structure so that the string weight is transmitted to the formation via the balling material rather than the cutting structure. Consequently, penetration rate is dramatically reduced. Balled formation can also plug the annulus so that no cuttings can be returned to surface. This results in an increase in SPP and possible risk of losing mud into the formation. Balled bits are generally characterised byo Reduced rotary torque o Reduced penetration rate o Increased SPP If it is thought a bit is balling up lift off bottom immediately. Drilling with a balled bit can only exacerbate the problem by forcing more material to plug the bit or annulus further. This tightens/compresses the material and makes it heavier and more difficult to transport back to surface. Methods for un-balling a bit areo Increase flow rate to the maximum for at least 5mins. o Spin the bit as fast as possible to ‘fling’ the material off. o Lift and drop the string rapidly to ‘shake’ the formation off, (take care not to surge the hole and damage the formation or drop the bit on bottom and damage the cutting structure). o Pump a pill, (eg: Nut Plug) to try and wash the material off. o A combination of the above. When returning to bottom after un-balling a bit use maximum flow rate and high rotary speed. Tag bottom gently as there may be huge chunks of balled material that need to be cut up. If weight is added too quickly the bit may just push into the balled material and become immediately balled again. Where balling is expected the risk of occurrence can be reduced by limiting penetration rate. This means that a reduced and more manageable amount of cuttings can be transported away from the bit face and annulus to surface.

Lost Nozzle • A lost nozzle will cause a sudden decrease in pump pressure. Calculation will indicate the expected pressure drop. • Pressure may continue to decrease gradually in an erosive environment due to the nozzle feed bore washing out and increasing in size/cross sectional area. • If penetration rate is not significantly reduced drilling can continue but may result in cutting structure damage due to drilling on tungsten carbide nozzle components. • In softer formations, a lost nozzle may be pushed into the hole wall and cause minimal cutting structure damage. • If a nozzle is lost HSI is reduced so there in an increased risk of bit balling and reduced RoP.

Drill Bit Running Procedures

Page 32 of 38

Plugged (Blocked) Nozzle • Nozzles can be plugged by a variety of materials. Some examples areo Formation o Lost circulation material o Motor stator rubber • A plugged nozzle will result in increased SPP. • If penetration rate is not significantly reduced drilling can continue. • If multiple nozzles are plugged and there is a severe deterioration in RoP it should be attempted to un-plug the nozzles or pull the bit out of hole. • Methods for un-plugging a bit areo Increase flow rate to the maximum for at least 5mins. o Lift and drop the string to ‘shake and surge’ the plugging material free, (take care not to surge the hole and damage the formation or drop the bit on bottom and damage the cutting structure). • A bit with plugged nozzles has an increased probability of balling in softer formations and accelerating cutter wear in abrasive formations. Downhole Motor or Turbine Failure • A down hole motor or turbine failure will dramatically reduce penetration rate. • SPP pressure fluctuations are likely to occur as the failure develops. • A reduced pressure differential (the difference between on and off-bottom pressure) over the motor or turbine is likely to be seen. • Depending on the failure, even if the rotary drive is rotating the string, there is a high probability that the bit will not be turning. This is because the motor or turbine may not be able to transmit any torque to the bit. • Catastrophic motor failures can be caused by repeated motor stalling. • Motor and turbine failures can be caused by bit whirl, stick-slip, BHA lateral vibration, etc. • At surface, motor bearing wear can be estimated/measured by examining the play in drive shaft.

Drill Bit Running Procedures

Page 33 of 38

Dull Grading •

• •

Witness the bit and BHA being pulled out of hole as evidence for run analysis can be collected. Take photos if necessary. For exampleo All the tool joints worn on the same side suggests forward whirl. o BHA balling, (Roughnecks will frequently clean the BHA off and this information will be lost and not recorded). o Bit balling, (Roughnecks will frequently clean the bit off and this information will be lost and not recorded). Dull grade the bit using the IADC system, (dull grading manuals for each drill bit type can be found on the SLB website). Roller cone bits and fixed cutter bits have different sized gauge rings. Ensure that the correct gauge ring is used. ie: if an in-gauge PDC bit is measured with a roller cone gauge it will appear to be under gauge.

Dull Bit Photos • • •

Use a digital camera so that the photos can easily and quickly be e-mailed to the Product Centres, DEC or Optimisation Engineer if necessary and for easy manipulation in a Run Report. Ensure good quality close up photos are taken. Number each blade with a marker pen to aid photo analysis at a later date. Take the following photos to ensure the full dull bit condition is recordedo Face view o Side view o Blade by blade o Close ups of any extraordinary cutting structure damage, body junk damage, etc

Run Reporting • • • • •

If good notes are maintained throughout the run a good report can easily be written. It is good practice to write the report as the run is progressing so relevant points are highlighted and not forgotten. On the report it is important to record the run objectives and observations, dull bit observations and finally recommendations for how performance can be improved or good performance maintained consistently. Record the ‘drillability’ of each of the different lithologies drilled. Record mud and BHA details. See Appendix 2 for an example of an Optimisation Run Report.

Drill Bit Running Procedures

Page 34 of 38

References Drillstring Vibration Primer, January 1994, Fereidoun Abbassian, BP Exploration

Drilling Terms

Annulus BHA Bit Breaker BOP Cavings Drill Collar Fishing GPM HSE HSI Kelly LCM LWD MWD OBM RMS RoP Rotary Table RPM RSA PDC POBM PPE PSI Sliding SPM SPP Spudding TFA Toolface Top Drive WBM WoB

The space between the drill pipe and hole wall or casing inside surface. Bottom Hole Assembly. The steel plate that locates the bit in the rotary table while it is screwed onto/made up to the drillstring. Blow Out Preventer, a series of valves that close to seal in the well and prevent it blowing out. Formation that has fallen out of the well bore wall down hole. Heavy drill pipe used in the BHA to add weight. Attempting to recover an item out of the well bore to surface. Gallons Per Minute. Health, Safety and Environment. Hydraulic horsepower per Square Inch. The heavy steel drive shaft with a square or hexagonal cross section that locks in the rotary table and is connected to the drillstring to transmit torque. Lost Circulation Material. Logging While Drilling. Measurement While Drilling. Oil Based Mud. Root Mean Square (a method of averaging a signal). Rate of Penetration, fph/mph. Device on the rig floor used to drive/rotate the kelly and support the drillstring. Revolutions Per Minute. Rock Strength Analysis. Polycrystalline Diamond Compact. Pseudo Oil Based Mud. Personal Protective Equipment. Pounds per Square Inch, fluid pressure. While directionally drilling with a motor, the rotary drive is switched off so the drillstring does not rotate and is ‘slid’ downhole. Strokes Per Minute. Stand Pipe Pressure. Burying the bit face into material, eg: the hole bottom or casing shoe assemblies. Total Flow Area, the sum of the cross-sectional areas of the exits of all nozzles in the bit. The direction the motor is orientated to in hole while sliding. A torsional motor used to drive the drill string. Usually installed on the bigger rigs and can provide more power than a kelly drive. Water Based Mud. Weight on Bit, klbs/tonnes.

Drill Bit Running Procedures

Page 35 of 38

Appendix 1

Drill Bit Running Procedures

Page 36 of 38

Appendix 2 Common Problems Affecting PDC, Natural and Thermally Stable Diamond Bit Performance COMMON PROBLEM Difficulty going to bottom.

Low pressure differential across nozzles or bit face.

PROBLEM CAUSE - Previous bit under gauge. - New bottom hole assembly.

-

Collapsed casing. Out of drift. Bit oversized.

-

Stabilizer oversized. Flow area too large. Flow area too low.

-

Different drilling parameters than designed for. Washout in drill string.

High pressure differential across nozzles or bit face.

Fluctuating standpipe pressure.

-

Flow area too small. Excessive flow rate. Diamond too small for formation.

-

Bit partially plugged (formation impaction)

-

Formation change.

-

Ring out. Downhole motor stalled. Drilling through fractured formation. Formation breaking up beneath bit.

-

Bit won’t drill

-

-

Stabilizers hanging up.

-

-

Equipment failure. Bottom not reached. Stabilizers hanging up or too large. Formation too plastic.

-

-

-

Establishing bottom hole pattern. Core stump left.

-

Bit balled

-

-

Not enough weight on bit;

-

-

Slow RoP

PREFERRED ACTION - Ream with roller cone bit. - When reaming to bottom, pick up and ream section again. If difficulty remains, check stabilizers. - Roll casing with smaller bit. - Use bi-centre bit or reduce bit size. - Gauge bit with API gauge; if not in tolerance, replace bit. - Replace with correct size stabilizer. - Increase flow rate and correct on next bit. - Increase flow rate/strokes. - Change liners. - Attempt to optimise, on next bit change flow area. - Check bit pressure drop, drop soft line, trip to check pipe and collars. - Reduce flow rate, on next bit change flow area. - Reduce flow area.. - If ROP acceptable, change on next bit. - If ROP unacceptable, pull bit and use bit with correct diamond size. - Check off bottom standpipe pressure. Let bit drill off, circulate full volume for 10 minutes while rotating. Check off bottom pressure again. - Pick up, circulate, resume drilling at higher RPM, reset, drill-off test. - On - and off- bottom pressure test, pull bit. - Refer to manufacturer’s handbook. - If ROP acceptable, continue.

Drill Bit Running Procedures

-

-

If ROP acceptable, continue. Check equipment. Try combination of lighter weight and higher RPM. Check over pull. Check stabilizers on next trip. Repair equipment. Check tally. Check torque, over pull. Check pressure – increase flow rate, decrease / increase bit weight, RPM. Can take up to an hour. Attempt to carefully drill ahead with low bit weight. Back off and increase flow rate, then slug with detergent or oil. Increase weight on bit Page 37 of 38

Excessive torque

Bit Bouncing

-

hydraulic lift. RPM too low/high. Plastic formation.

-

Change in formation. Overbalanced.

-

Diamonds flattened off.

-

Cutters flattened.

-

Pressure drop too low. Wrong bit selection. Excessive weight on bit. Slow RPM.

-

Stabilizers too large.

-

Collars packing off. Bit under gauge. Slip-stick action. Broken formation. Pump off force.

Drill Bit Running Procedures

-

Increase/decrease rotary. Reset drill off Reset weight Reset drill off. Accept ROP. Pull bit. Compare beginning and present drops – new bit may be required. Increase weight. Pull bit. Increase flow rate – new bit may be required. Pull bit. Reduce weight and RPM. Increase rotary. Decrease weight Check bottom hole assembly; stabilizers should be 1/32” to 1/16” under hole size. Increase flow rate and work. Pull bit. Change rotary weight combination. Reduce rotary speed and weight. Increase weight. Decrease volume.

Page 38 of 38

Reed-Hycalog Main Menu

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Roller Cone Products CD Reference Information Recommended Rock Bit Make-Up Torque Reference Information

Bit Size in.

API Pin Size

Recommended Torque

mm

in.

mm

3 3/4 - 4 1/2

95.2 - 114.3

2 1/8

60.3

3000-3500

4000-4800

• API Bit Tolerance

4 5/8 - 5

117.5 - 127.0

2 7/8

73.0

6000-7000

8000-9500

• API Casing Date

5 1/8 - 7 3/8

136.5 – 187.3

3 1/2

88.9

7000-9000

9500-12000

7 5/8 - 9

193.7 - 228.6

4 1/2

114.3

12000-16000

16000-22000

• IADC RollerCone

9 1/2 - 26*

241.3 - 660.4

6 5/8

168.3

28000-32000

38000-43000

• Nomenclature

14 3/4 - 26*

374.6 - 660.4

7 5/8

193.7

34000-40000

46000-54000

18 1/2 - 26*

469.9 - 660.4

8 5/8

219.1

40000-60000

54000-81000

Reference Tables • Nozzle Flow Areas

• Make-Up Torque

Reference Charts

• Rock Bit Availability • IADC Dull Bit

ft-lbs

N-m

Unit Conversions

*Make-up torque must correspond to API pin connection for each bit size.

• People • Trademarks • Contact

Detailed Contents Index A Abrasiveness (Formation) Anderreamer Antiwhirl ARCS Arenaceous Rocks Argillaceous Rocks Asymmetric Nozzles Asymmetry Axial Vibration - General

B Back Rake Backreamers BBL - Nomenclature (Fixed Cutter) Bearings (Roller Cone) Bicentre - Commercial Products Bicentre - Drilling Practices Bicentre Bits - Basics Bicentre Bits - BHA Considerations Bicentre Bits - Casing Drill out Bicentre Stabilizer Bit Length (PDC) Bit Run Guidelines Bit Selection for Schlumberger Tools Bit Selection Properties - Formation Bit-Tech - Nomenclature (Fixed Cutter) Black Diamond Black Trax Blade Count (PDC) Blade Height (Impregnated bit) Body Material (PDC) Brute Cutters

C Carbonates Center Jets Chert Clean Sweep Coiled Tubing Applications Compressive strength (Formation)

Concentric Reamers - Fixed Concentric Reamers - Mechanical Conglomerate Cross Flow Cutter Count (PDC) Cutter Size (PDC)

D Data Analysis - Bit Selection Reqt. Data Analysis - Offset Data Collection Data Analysis - Post Run Data Collection Data Analysis - QA/QC Data Data Analysis - Subject Well Diamond - Abrasion Resistance Diamond - Cone Wear Diamond - Impact Resistance Diamond - Quality Classification Diamond - Size Diamond Bit Selection - Formation Diamond Bits - Application Diamond Bits - Differentiation Diamond Bits - Failure Mechanism Diamond Bits - Products Diamond Protection (Roller Cone) DPI - Nomenclature (Fixed Cutter) Dual Torque Dull Characteristics Dull Grading DuraDiamond

E Eccentric String Reamers Economic Evaluation Elasticity (Formation) Enlarge While Drilling (EWD) Evapourites Excalibur Exceed - Basic Tool Operation Exceed - Bit Selection Guidelines Extended Nozzles

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F

Junk Slot Area (JSA) Junk Slot Volume (JSV)

FAST Flow Rate Force Balancing

L Lateral Jets Lug Pads

G

M

Gauge Length - PDC Gauge Protection (Diamond Bits) Gauge Protection (PDC) Gemini Genesis Gold Series Grit (Diamond)

H Hardfacing (PDC) Hardfacing (Roller Cone) HardRok Hedgehog Hole Opening Technology - Applications Hole Opening Technology - Overview Hughes Christensen - Nomenclature (Fixed Cutter) Hughes Christensen - Nomenclature (Roller Cone) HydraBoss Hydraulic Horsepower Hydraulics - Basics Hydraulics - Diamond Bits Hydraulics - Optimization Hydraulics - PDC Hydraulics - Roller Cone

Magnum Make-Up Torque Matrix (Impregnated Bit) Motor - Diamond Bit Requirements Motor - Hydraulics Motor - Lobe Configurations Motor - PDC Requirements Motor - Roller Cone Requirements Motor Basics Mud Considerations Mudpick

N Near Bit Reamer New Tech - Nomenclature (Roller Cone) Nomenclature - Fixed Cutter Products Nomenclature - Roller Cone Products Normalized Face Volume (NFV) Nozzle Blanking Nozzle Flow Area Nozzle Pressure Drop Nozzle Types (PDC) Nozzle Velocity

I

P

IADC Classification - Diamond Bits IADC Classification - PDC Bits IADC Classification - Roller Cone IADC Code - Roller Cone Selection Impregnated Bits - Overview Insert Metallurgy Insert Shape (Roller Cone) Interbedded Formations

PDC Bit selection - Formation PDC Cutter technology PDC Cutter technology - Abrasion PDC Cutter technology - Cutter Shape PDC Cutter technology - Thickness PDC Cutter technology - Elite PDC Cutter technology - Genesis PDC Cutter technology - GeoMax PDC Cutter technology - Geometry PDC Cutter technology - NPI PDC Cutter technology - TReX

J Jet Impact Force Journal Angle

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PLUS Porosity (Formation) PowerDrive - Applications (Bits) PowerDrive - Basic Tool Operation PowerDrive - Hydraulics PowerDrive - PDC Bits PowerDrive - Roller Cone Pressure (Formation) Problematic Formations Profile (Diamond) Profile (PDC) Profile (Roller Cone) Pyrite

Shoe Drill Out Side Rake Side Track Applications Skew Smith - Nomenclature (Fixed Cutter) Smith - Nomenclature (Roller Cone) SpeedDrill SpeedReamer Stabil Bicentrix Star Steerability (PDC) - Profile Steering Wheel Stickiness (Formation) Stick-Slip - Bit Aspects Stick-Slip - General Switchblade

Q Quad

R Radial Flow RBI - Nomenclature (Roller Cone) Reamers Reed-Hycalog - Nomenclature (Fixed Cutter) Reed-Hycalog - Nomenclature (Roller Cone) Reference Material Rhino Reamer Risk Analysis Rock Classification Roller Cone Selection - Formation RotoSteer

S Sabre Line Salt Drilling Sandstones Schematics - Face view, PDC Schematics - Side view, Diamond bit Schematics - Side view, Matrix bodied PDC Schematics - Side view, Roller Cone Schematics - Side view, Steel bodied PDC Secondary Cutters Security DBS - Nomenclature (Fixed Cutter) Security DBS - Nomenclature (Roller Cone) Shamal Shirttail Protection

R Technical Literature (Supporting) Temperature Restrictions Titan TIX - Nomenclature (Roller Cone) Tooth Count Tooth Length Tooth Shape Trac Loc Tracking Tri Max - Nomenclature (Fixed Cutter) TuffDuty Twist & Shout

U Ultramax

V Varel - Nomenclature (Fixed Cutter) Varel - Nomenclature (Roller Cone) Velocity Volcanic / Igneous rocks Vortex nozzles

W Whirl - Bit Aspects Whirl - General Whirl - Specific bit designs

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