Bits Catalog

Product Catalog

Headquarters 1310 Rankin Rd. Houston, TX 77073-4802 www.slb.com Copyright © 2013 Schlumberger. All rights reserved. No part of this book may be reproduced, stored in a retrieval system, or transcribed in any form or by any means—electronic or mechanical, including photocopying and recording—without the prior written permission of the publisher. While the information presented herein is believed to be accurate, it is provided “as is” without express or implied warranty. Specifications are current at the time of printing. 13-BT-0039 An asterisk (*) is used throughout this document to denote a mark of Schlumberger. Other company, products and service names are the properties of their respective owners.

Table of Contents Technological Expertise

1–19

Innovative Smith Bits technology for every stage of drilling

Fixed Cutter Bits

21–33

A wide range of PDC and diamond-impregnated bits

Roller Cone Bits

37–54

A comprehensive selection for various applications

Percussion Hammers and Bits

55–59

Impax hammer products designed for oilfield applications

Specialty Products

61–67

Reference Guide

69–90

Technological Expertise

1

Technological Expertise Innovative Smith Bits technology provides analyses, optimization, and support for every stage of the drilling program, from planning to execution Engineering and Modeling ■■

IDEAS* Integrated Drillbit Design Platform

■■

Computational Fluid Dynamics (CFD) Analysis

■■

i-DRILL* Engineered Drilling System Design

■■

Advanced Services Engineering (ASE)

■■

DBOS* Drillbit Optimization System

■■

YieldPoint RT* Drilling-Hydraulics and Hole-Cleaning Simulation Program

■■

DRS* Drilling Record System

Fixed Cutter Technology ■■

Stinger* Conical diamond element

■■

ONYX 360* Rolling PDC cutter

Roller Cone Technology ■■

Hydraulics

■■

Inserts

Diamond-Impregnation Technology ■■

Grit Hot-Pressed Inserts (GHIs)

2

Engineering and Modeling IDEAS Integrated Drillbit Design Platform

Delivering application-specific drill bits with higher performance and greater reliability The IDEAS* design platform uses advanced simulation and modeling to design and certify every new Smith Bits drill bit. It has five basic elements that enable it to optimize bit performance.

Comprehensive drilling system analysis

The design process takes into account the effects of the lithology at the rock-cutter interface, the drillstring, the drive system, individual BHA components, and the total system on bit behavior in a dynamic drilling environment. It also takes into account the specific operating parameters and the interaction between individual elements of the drilling assembly.

Holistic design process

Smith Bits design engineers account for every critical variable. Virtually every cone or cutter position is selected to create a stable bit that rotates around its center, a key requirement for efficient drilling.

Application-specific enhancements

Continuous improvement results in bits for a specific application that consistently outperform previous designs when measured against the same parameters, for example, ROP, durability, and specific bit behavior with a rotary steerable system. Drill bits that are certified by the IDEAS platform are dynamically stable within the operating envelope for which they are designed, leading to longer bit runs and less stress on the BHA. Each certified bit undergoes rigorous design evaluation and testing to produce a detailed application analysis of how it will perform for a specific drilling program.

Rapid solutions with reliable results

By using sophisticated modeling tools and by accounting for a multitude of dynamic variables in a virtual environment, the IDEAS platform moves bits through the design process much quicker, while ensuring better reliability and performance than ever before. The traditional trialand-error approach is replaced by laboratory tests and simulations to quantify variables such as cutter forces and rock removal rates.

Advanced material integration

Stronger and more durable advanced cutter materials are used more effectively by working in conjunction with IDEAS design and simulation capabilities. The resulting bit has abrasion- and impactresistant cutters, and an optimal design for high performance.

The IDEAS Platform

Define Performance Objectives

IDEAS Platform Simulation ■■ Design ■■

Test

■■

Analyze

Build Bit

Test Bit

Certify Bit Integrate new bit into product line

IDEAS platform eliminates the costly and time-consuming trial-and-error methods of the traditional drillbit design process, enabling Smith Bits to deliver a better solution faster.

www.slb.com/IDEAS 3

Engineering and Modeling

IDEAS Design Platform Certification for Directional Applications Improving performance, reduces risk, and keeps directional wells and drilling budgets on target Extensive analyses of drill bits designed for directional applications using the IDEAS* integrated drillbit design platform shows that a single design can provide exceptional performance with a variety of directional drilling systems, if it is dynamically stable. Often, the range of special features incorporated into conventional directional bits merely allows an intrinsically unstable bit design to drill acceptably for a specific application. If the bit is subsequently used with a slightly different BHA or in a different application, it becomes unstable and a new or significantly modified bit is required. Bits for directional drilling that have IDEAS certification remain stable and provide superior performance with different types of steering systems in a wide range of applications. Changing the system configuration or operating parameters does not diminish the performance of the bit. Drilling with a stable bit reduces costs and equipment failures in addition to providing a smooth, high‑quality wellbore.

www.slb.com/IDEAS 4

Engineering and Modeling Computational Fluid Dynamics (CFD) Analysis

Efficient hydraulics for improved performance and lower drilling costs Smith Bits design engineers use CFD to model the interaction of drilling fluids with the bit and the wellbore. Complex algorithms enable the simulation of a wide variety of downhole conditions, allowing engineers to evaluate various blade and nozzle configurations in order to optimize flow patterns for cuttings removal. Ensuring the cutting structure is always drilling virgin formation improves bit performance. Extensive use is made of this sophisticated technique to maximize the available hydraulic energy, providing bits that will drill at the lowest possible cost per foot.

Using CFD to visualize flow patterns enables designers to analyze design modifications affect bit performance and choose the optimum solution.

5

Engineering and Modeling i-DRILL Engineered Drilling System Design

Maximize performance with a dynamically stable drilling assembly. i-DRILL* engineered drilling system design uses predictive modeling to identify solutions that minimize vibrations and stick/slip during drilling operations, and optimize BHA performance for a given environment. Specially trained engineers simulate the behavior of the bit, as well as each component of the BHA and the drillstring. They evaluate a range of options to reduce harmful vibrations, thus increasing equipment life, minimizing failures, increasing ROP, improving hole condition and directional control, and decreasing overall drilling cost. Various combinations of drillbit options, drilling assembly components, drillstring designs, surface parameters, component placement, and overbalance pressures can be examined for the specific lithology. Advanced graphics capabilities illustrate the results with clarity.

Reliable simulation of downhole behavior eliminates trial-and-error The i-DRILL drilling system design enables quantification of vibrations and ROP produced by a virtual drilling system as a function of time. This is accomplished by combining a bit-drilling-rock model with a finite element analysis of the bit and drillstring.

Analyzing the dynamics of the drilling assembly through multiple formations of variable compressive strength, dip angle, homogeneity, and anisotropy is feasible, a critical factor in obtaining optimal performance through formation transitions. Virtual testing of new technology and unconventional approaches eliminates the risk and expense of trial-and-error on the rig.

Integration of data from diverse sources improves accuracy

Using offset well data, surface and downhole measurements, and a thorough knowledge of products and applications,

the i-DRILL design process creates a virtual drilling environment. Detailed geometric input parameters and rock mechanics data are also taken into account. Simulating the drilling operation enables evaluation of the root causes of inefficient and damaging BHA behavior.

■■

■■

■■

i-DRILL design capabilities ■■

■■

■■

■■

■■

■■

■■

■■

Identify the true technical limit of performance without risking lost rig time associated with exceeding the limit or inefficiencies resulting from operating too far below the limit.

■■

Bit-underreamer balance to determine the combination that will result in the highest ROP under stable conditions BHA comparison to investigate directional behavior while minimizing vibrations Range of weight on bit (WOB) and drillbit revolutions per minute (rpm) for maximum ROP under stable conditions Postwell follow-up to determine usage and effectiveness of prewell i-DRILL design recommendations

Eliminate unnecessary trips to change BHAs when trying to identify the optimum drilling system. Predict the performance of new drillbit designs. Predict the dynamic behavior of directional BHAs in space and time. Identify weak areas in the drillstring and BHA to help prevent the loss of tools downhole. Minimize harmful lateral, torsional, and axial vibrations; and stick/slip, through the selection of dynamically stable drilling assemblies. Balance drillbit and underreamer cutting structure loading to maximize dualdiameter BHA stability. Develop improved drilling program schedules with reduced risk of unplanned delays.

i-DRILL design analyses ■■

■■

■■

Drilling system check to evaluate dynamic behavior; identify issues with vibration, bending moments, and torque; and select the optimal system Bit analysis to identify the design that will yield the highest ROP under stable conditions Bit durability and ROP through different formations

www.slb.com/iDrill 6

Engineering and Modeling Advanced Services Engineering (ASE) In-house bit recommendations and operational advice The ASE team has an established track record of lowering drilling costs through improved performance, by recommending the ideal bit for the application—a vital aspect of a comprehensive well plan. Bit recommendations and operational advice are based upon the technologies and operating parameters best suited for a particular application.

Expert drillbit selection

The ASE group provides an experienced bit application specialist for the client’s drilling team, to deliver engineered bit recommendations and advice to both the operator and the service providers on the day-to-day requirements for maaintaining superior bit performance. ASE engineers consider the entire drilling environment, including the formation, the components of the BHA, drilling fluids, rig capabilities, rig crew, and any special drilling objectives in their search for the optimum bit and subsequent maintenance of its efficiency throughout its life. The engineer uses several proprietary tools, such as the ■■

■■

■■

DRS* drilling record system, which includes detailed bit runs from oil, gas, and geothermal wells around the world DBOS* drillbit optimization system, which helps determine the appropriate combination of cutting structure, gauge protection, hydraulic configuration, and other bit optimizing features YieldPoint RT* drilling-hydraulics and hole-cleaning simulation program for jet nozzle optimization.

Optimized drilling plan

The DBOS program uses knowledge gained from an analysis of offset wells from the DRS system and a spectrum of other relevant information. It provides a thorough reconstruction of expected lithologies

(gleaned from well logs from the closest offset wells), a formation analysis, rock strength analysis, and both roller cone and fixed cutter bit selections. The YieldPoint RT program creates a graphical user interface to aid drilling engineers in specifying mud types and properties that satisfy rheological models of drillstrings and well annuli. The software can answer questions about hole cleaning, with data from the formations to be encountered. Using a cuttings transport model, the program can help assess potential hole-cleaning difficulties during the well planning stage, thus minimizing problems during actual drilling operations. Operational needs and the well plan are also taken into consideration, including casing points and hole sizes, well directional plot, and expected formation tops. The result is an optimized minimum cost per foot program, often with multiple options and alternatives.

Continuous evaluation while drilling

To establish measurable goals, the ASE engineer prepares a comprehensive plan. During drilling, performance is evaluated continuously against this plan. Upon completion of the well, a postwell analysis measures the success of the plan and provides a permanent formal reference for future wells. The appropriate rig and office personnel are briefed on the drilling program and monitor the well prognosis during implementation of the well plan. Unexpected performance or events that arise are identified and investigated, and decisions are made to correct the issues, subject to the objective of maintaining peak drilling efficiency and safety.

www.slb.com/ASE 7

Engineering and Modeling Advanced Services Engineering (ASE)

Postwell Analysis

A thorough performance assessment is conducted upon completion of the well evaluating every part of the drilling operation. The ASE engineer, as part of the drilling team, makes recommendations for improvements related to bit selection and drilling for future well plans. The ASE team provides value by recommending the best bit for the specific application, which will deliver the most efficient and economical drilling performance.

www.slb.com/ASE 8

Engineering and Modeling DBOS Drillbit Optimization System

DBOS system evaluation process

To achieve the minimum cost per foot with a higher degree of certainty and reduced risk, the DBOS* Drillbit Optimization System identifies the best drill bit for the interval to be drilled. This software based system uses offset well data to choose a fixed cutter, roller cone, or turbodrill drill bit that has the appropriate combination of cutting structure, gauge protection, hydraulic configuration, and other critical characteristics. Since its inception, the DBOS system has provided significant cost and time savings for operators around the world, while creating a supporting database of more than 20,000 wells. The system incorporates a thorough analysis of offset well data including well logs, formation tops, mud logs, core analysis, rock mechanics, drilling parameters, drillbit records, and dull bit conditions.

1. Evaluation of expected formation types and their section lengths from offset logs. 2. Determination of unconfined compressive strength, effective porosity, abrasion characteristics, and impact potential. 3. Identification of one or more potentially optimal bit types and various applicable features. 4. Prediction of the cost per foot for each bit and configuration. 5. Drillbit selection for planned hole (simulation).

Operator deliverables

Various levels of analysis are offered, and for each level, data is presented graphically in log plot form, and statistically in the interval analysis plots. The analysis evaluates key bit performance variables over the given intervals, identifying which bit will be the most successful for drilling through specific single intervals or over multiple intervals, based on experience data and the knowledge based heuristics.

DBOS comprises ■■ ■■

a petrophysical log analysis program proprietary algorithms for rock compressive strengths, drillbit performance analysis, and drillbit selection

■■

well log correlation and statistic analysis software

■■

a geologic mapping program.

Parallel analysis for roller cone bit options, PDC bit applications and high-speed turbodrilling options are all considered. The final proposed bit program combines this input for optimized Interval cost per foot.

The flexibility of the system allows engineers to analyze various levels of information and deliver a bit strategy based on input from a single offset well, a multiwell cross section, or a full-field mapping and regional trend analyses.

www.slb.com/DBOS 9

Engineering and Modeling DBOS Drillbit Optimization System

Input parameters include ■■

drillbit record information

■■

directional surveys

■■

real-time ROP and mud log data

■■

wireline or LWD formation evaluation data

■■

rock type and strength data

■■

hydraulic and mechanical energy factors.

Neural networks, planned run simulation and real-time optimization

Neural networks have been used in DBOS system for synthetic log generation since 1997, and serves as the principal modeling for on-time, real- time DBOS system. Artificial neural networks (ANNs) have proven accuracy generating synthetic logs (used primarily for sonic log generation) with R^2 (goodness of fit) values in the high 90 percentiles, compared to traditional offset correlation methods. Neural networks provide system response characteristics, very valuable in non-linear multi-input solution.Drillbit performance can be predicted prior to drilling (ROP, dull grade) in run simulation. In predrilling simulation, drilling systems can be tested in advance to find the most efficient way to drill.

Real-time applications

Optimized drilling parameters can be assessed and delivered to the driller and rig floor in realtime, giving predictions ahead of the bit. The results can be monitored with respect to improved ROP, longer drillbit life, or reduced downhole shock and vibration. DBOS system has contributed to improvements in bit run performance on the order of 20 to 40% or better in ROP, longer bit life, reduced incidents of drillbit related failures.

www.slb.com/DBOS 10

Engineering and Modeling

YieldPoint RT Hydraulics and Hole-Cleaning Simulation Program Optimized hole-cleaning solutions The YieldPoint RT* program identifies potential problems with hole cleaning in the planning stage, rather than during drilling operations when they can have a significant impact on the cost of the well. It aids drilling engineers in specifying mud type and properties to satisfy rheological models of drillstrings and well annuli. This comprehensive program uses sophisticated algorithms to deliver solutions for conventional jet nozzle optimization and selection. It creates simulations of mud properties, flow rate, ROP, and total flow area. The virtual model then demonstrates the effects on observed bit hydraulic factors and on hole cleaning.

Diverse inputs for real-time assessment

YieldPoint RT program allows data to be input and retrieved via an Internet connection and the Web-based wellsite information transfer standard markup language (WITSML), by authorized wellsite providers and off-location users such as ■■

the well operator

■■

drilling contractors

■■

mud loggers

■■

rig instrumentation and wireline companies

■■

drilling fluid service companies

■■

casing running service providers

■■

directional drillers

■■

drilling and exploration engineers and managers

■■

reservoir engineers

■■

management personnel

■■

seismic survey companies

■■

process optimization consultants

■■

materials suppliers.

Wellsite service providers can contribute expertise to the common store via the WITSML interface, and then query the data store for combined information from other wellsite services. This information can support program analysis, visualization, and potential corrective actions, decision making in drilling and production operations in real time. Hydraulics can be optimized to maximize efficiency as the well is being drilled. Operating company personnel can compile information from any mix of vendors, view and monitor current wells via Web-based applications, and extract reports at any time. The result is a realtime solution that substantiall y reduces costs.

www.slb.com/YieldPointRT 11

Engineering and Modeling DRS Drilling Record System

An extensive library of bit run information The Smith Bits DRS* drilling record system is a collection of nearly 3 million bit runs from virtually every oil and gas field in the world. The database was initiated in May 1985 and since that time, records have been continuously added for oil, gas, and geothermal wells. With this detailed data and the capabilities of the IDEAS* integrated drillbit design platform, Smith Bits engineers can simulate bit performance and make changes to their bit designs to optimize performance in a specific application. In addition, the system enables the DBOS* drillbit optimization system to ensure that the right bit is run in a given formation. With this plan in place prior to drilling the well, customers are able to reduce risk, lower drilling costs, and shorten the total time required to drill their wells. The inclusion of bit record data from the client wells in the DRS system contributes to better drillbit selection and application for your drilling program. The system can be accessed through Smith Bits applications engineers or sales representatives.

www.slb.com/records 12

Stinger

Conical diamond element Beyond shear performance The Stinger* conical diamond element provides an innovative cutting structure enhancement that significantly increases a PDC bit’s performance. Located at the bit’s center, the element enables high-point loading to fracture rock more efficiently for increased durability and ROP across a wide range of formations and operating parameters. In field tests comparing conventional PDC bits and PDC bits fitted with a Stinger element across a wide range of rock types and operating parameters, bits with a Stinger element demonstrated greater durability and stability while increasing ROP as much as 46%.

Borehole center challenges conventional PDC bits

By reconfiguring the bit with the Stinger element, a column of rock is allowed to form at the center of the cutting structure, which is continuously crushed and fractured, increasing drilling efficiency.

Because the rotational velocity of cutters decreases with their proximity to the center of a bit’s cutting structure, rock removal by the center-most cutters of conventional PDC bits is much less efficient, especially in hard formations. And since the center cutters bear the highest load, operational and formation changes can cause large variations in depth of cut, inducing bit torque fluctuations.

Stinger element increases PDC bit drilling efficiency To decrease PDC bit damage and increase performance at the center of the cutting structure, bit design engineers selectively removed the PDC bit’s center-most cutters to position the Stinger element. The absence of these cutters allows a stress-relieved column of rock to develop that is continuously crushed and fractured by the Stinger element, improving drilling efficiency.

The Stinger element combines a unique conical geometry with synthetic diamond material that is engineered to provide impact strength and superior resistance to abrasive wear.

Stinger nomenclature

M S i Z 6 19 Cutter size Blade count Z – Stinger—conical diamond element i – IDEAS certified S – SHARC M/S – Matrix or steel

www.slb.com/Stinger 13

ONYX 360 Rolling PDC cutter

The next revolution in PDC cutter durability The ONYX 360* rolling PDC cutter substantially increases PDC bit durability by revolving 360°. Strategically positioned in the highest wear areas of a bit’s cutting structure, the rolling cutter’s entire diamond edge is used to shear the formation.

Fixed cutter limits diamond edge contact Because most of its cutting edge is fixed into the bit blade, very little of a fixed cutter’s edge contacts the formation. Accordingly, more than 60% of the cutter’s circumferential edge is unused during a bit run. The ONYX 360 cutter’s rotating action allows the diamond edge to stay sharper longer, extending cutter life far beyond that of premium fixed cutters. When compared with fixed-cutter-only bits, PDC bits that included ONYX 360 rolling cutters demonstrated run length increases of up to 57%.

The ONYX 360 cutter’s shaft is fully contained within an integrated housing to ensure continuous rotation and cutter retention during drilling.

Inventive design increases cutter life To integrate a rolling cutter into a PDC bit’s cutting structure would require a novel and robust design. Smith Bits R&D engineers developed a cutter system composed of a housing that is brazed into the bit blade, and within which a sleeve encloses and completely secures the cutter while allowing it to rotate. The rolling cutter’s orientation in the bit blade relative to its contact with the formation, coupled with the bit’s drilling force, drives efficient rotation of the cutter. This reduces wear for more sustained rates of penetration and fewer bit replacement trips.

ONYX 360 nomenclature

M S i R 6 19 Cutter size Blade count R – ONYX 360 rolling cutter i – IDEAS certified S – SHARC M/S – Matrix or steel

www.slb.com/ONYX360 14

ONYX 360 Rolling PDC cutter

Comprehensive evaluation validates rolling concept

Premium fixed cutter

90

The wear that fixed cutters incur is concentrated on only a small percentage of the cutter’s entire diamond edge. As a result, after 90 passes on a test formation, premium fixed cutters developed extreme wear flats. Because 100% of the ONYX 360 rolling cutter’s diamond edge engaged the test formation, wear was evenly distributed, resulting in virtually no wear after 300 passes and very little wear after 540 passes.

ONYX 360 cutter

120

0

50

300

100

150

200

250

480

300

350

400

540

450

500

550

600

Rock cutting passes

Wear Flat Area After 150 hours

0.14

Wear Flat Area, in2

0.12 High wear area

0.10 0.08 0.06 0.04 0.02 0

0

0.5

1

1.5

2

2.5

3

3.5

0

Distance from bit center, in

0.5

1

1.5

2

2.5

3

3.5

Distance from bit center, in

ONYX 360 cutters Premium fixed cutters

In abrasive formations, the bit’s shoulder area (between the center of the cutting structure and gauge) is where cutters typically experience the greatest amount of wear. The ability IDEAS drillbit design platform has to predict the degree and precise location of this wear makes it an invaluable design tool.

Based on analysis using IDEAS design platform, ONYX 360 rolling cutters can selectively replace fixed cutters in the highest wear areas of a PDC bit’s cutting structure.

www.slb.com/ONYX360 15

Roller Cone Technology Adaptive Hydraulics System

Because of the wide range of drilling applications for roller cone bits, no single hydraulics configuration is optimal for every situation. Different applications require each of the three primary functions of bit hydraulics—cutting-structure cleaning, bottomhole cleaning, and cuttings evacuation—to varying degrees. With the Flex-Flo* adaptive hydraulics system, Smith Bits offers the ideal configuration for each application.

V-Flo

V-Flo* vectored-flow nozzle configuration uses three directed nozzles to allocate available hydraulic energy for improved penetration rates through superior cutting-structure cleaning and efficient cuttings evacuation.

The many variations of X-Flo* crossflow nozzle configuration allocate available hydraulic energy to improve penetration rates through cone cleaning and dramatically increased impingement pressure, needed for superior bottomhole cleaning.

S-Flo

In applications with high percentages of solids in the mud and in abrasive formations, S-Flo* standard-flow nozzle configuration uses three identical nozzles to allocate hydraulic energy for increased bit life.

Hydraulic Function vs. Formation Zone 4

Zone 3

Hydraulic Function Need

To help select the most suitable bit hydraulics system, typical applications have been divided into four categories or zones determined by formation types, ranging from very soft to very hard. Within each zone, the relative importance of the three hydraulics system functions can be seen on the graph. Bit hydraulics performance can be enhanced by using this guide to select an appropriate system, which can then be refined for specific applications by consulting a Smith Bits representative.

X-Flo

Zone 2

Zone 1

Very soft and/or sticky formations that generate very large volumes of cuttings with Milled Tooth bits and very soft TCI bits.

Low strength formations that generate large cuttings volumes and drill with soft TCI bits.

Medium strength formations that generate moderate cuttings volumes with medium hard TCI bits.

Soft / Sticky Hard /Abrasive

16

High strength formations that generate low cuttings volumes with hard TCI bits.

Cutting Structure Cleaning Bottom-Hole Cleaning Cuttings Evacuation

Roller Cone Technology Inserts

Insert Options

A large selection of insert geometries and material options, diamond or tungsten carbide, help to optimize bit characteristics for specific applications. A key focus of the Smith Bits R&D program, enhancements to inserts are constantly being incorporated into new and existing bit designs.

Geometry Choices

Smith Bits pioneered the use of specific insert shapes in 1995, and uses proprietary tools to determine the best geometry for a given bit design. These are available in four options: ■■

■■

■■

■■

Incisor

DogBone

ACE

Conical and chisel inserts are designed for hard and soft formations respectively. The unique geometry of the DogBone* durable and aggressive drillbit insert is designed for maximum ROP and impact resistance. The asymmetric conic edge (ACE) insert is a hybrid of the conical and chisel inserts. It has an offset conical top for increased strength, and a flatter leading side to enhance scraping. The design is highly resistant to breakage and impact damage, yet more aggressive and effective in softer formations than a standard conical insert. Incisor* concave drillbit insert combines the benefits of the ACE, chisel, and DogBone designs. With a sharp offset, C-shaped crest and larger corner radii, it is designed for soft to medium-hard formations.

Coarse Carbide Microstructure

Material Choices

Insert material grades are not specific to a particular design. Materials can be optimized for individual applications to maximize performance, reliability, and durability. Smith Bits was the first company to offer diamond-enhanced inserts (DEI) in roller cone bits, and remains the performance leader in this technology, which helps ensure maximum durability in the most challenging applications. Diamond inserts can be used in the heel row, the gauge row, and on the bit leg.

Diamond-Enhanced Insert

17

Relieved Gauge Chisel

Chisel

Conical

Roller Cone Technology Typhoon Hydraulics

Superior Hole Cleaning for Large OD Boreholes Smith Bits engineers use sophisticated computational fluid dynamics (CFD) analysis to ensure optimum flow for cuttings removal, so that the cutting structure is always drilling virgin formation. Typhoon* hydraulics is a feature offered for roller cone bits with a diameter of 16 in and larger, that uses both vectored extended (VE) nozzles and dome jet (J3) nozzles.

VE nozzles direct the fluid flow with precision to the leading edge of the cones, while the J3 nozzles direct flow towards the intermesh area between the cones. The combined effect of these six, precisely oriented nozzles is a flow pattern that significantly improves cone cleaning, optimizes the displacement of cuttings from the bottom of the hole up the drillstring, and maximizes ROP.

CFD analysis allows Smith Bits engineers to optimize available hydraulic energy for maximium ROP.

Shamal* carbonate-optimized TCI drill bits with Typhoon hydraulics incorporate three vectored extended (VE) nozzles and three dome jet (J3) inner nozzles to apply maximum hydraulic energy to the bottom of the wellbore, enhancing cuttings removal and increasing ROP.

www.slb.com/Shamal 18

Diamond-Impregnation Grit Hot-Pressed Inserts (GHI) Technology

GHIs are individual cylinders of impregnated material used in Kinetic* diamond-impregnated bits. Each insert is manufactured using a proprietary granulation process that ensures a much more uniform distribution of the diamond material than the conventional pelletization process. The result is a more consistent GHI, which is significantly more durable, maintains its shape, and drills faster for a longer period of time. Individual GHIs are similar to small grinding wheels, so the depth of cut with each rotation of the bit is very small. While drilling, GHIs continuously sharpen themselves by grinding away the bonding material to expose new diamonds. Smith Bits GHIs are customized with different bonding materials and diamonds to match the formation being drilled and the drive mechanism used. Because the GHIs are raised and allow a greater flow volume across the bit face, they enable Kinetic bits to drill faster in a wider range of formations.

Uniform diamond distribution and optimized material wear rates.

Smith Bits GHIs are more durable than conventional GHIs, and will drill faster for a longer period of time.

19

Fixed Cutter Products

21

Fixed Cutter Bits Product Line Directional PDC Drill Bit

Matrix or steel bits for improved directional response

SHARC* High-Abrasion-Resistance PDC Drill Bit

Matrix or steel bits for improved durability and wear resistance

Spear* Shale-Optimized Steel-Body PDC Drill Bit

Steel-body PDC drill bits for improved performance in shales

Standard PDC Drill Bit

Premium performance with excellent durability

Kinetic Drill Bits

Matrix bits for high rotary speed applications including positive displacement motors (PDMs) and turbodrilling

22

Fixed Cutter Bits Directional PDC Drill Bit

IDEAS certification for directional bits ensures excellent steering response and improved performance IDEAS* integrated drillbit design platform and field experience have shown that a single bit design can provide exceptional performance with a variety of directional drilling systems, if it is dynamically stable. The earlier perception was that each type of rotary steerable system (RSS) or steerable motor BHA required its own bit design with highly specialized directional features. Directional bits with IDEAS certification are stable and produce less torque and stick/slip in transitional drilling. The risk of time-consuming and costly trips due to vibration and shocks is greatly reduced.

Type

Size Availability, in

Type

Size Availability, in

SDi613

171/2

SD519

16, 171/4

SDi616

131/2

MD519

81/2, 121/4

MDi416

6 ⁄8

MD611

57⁄8

MDi513

5 ⁄8, 6 ⁄8, 61/4, 7 ⁄8, 83/4

MD613

6, 61⁄8

MDi516

6 ⁄8, 81/2

MD616

6, 83⁄8, 97⁄8, 121/4, 143/4

MDi519

83/4, 14

MD619

81/2, 91/2, 121/4, 17

1 5

1

7

1

MDi613

63/4, 81/2, 8 ⁄8, 91/2, 9 ⁄8

MD813

81/2

MDi616

81/2, 143/4

MD816

6, 61⁄8, 81/2, 91/2, 121/4, 161/2

MDi619

121/4, 141/2, 16, 171/2

MD819

121/4

5

7

MDi713

5 ⁄8

MD913

81/2, 121/4

MDi716

81/2, 121/4, 143/4

MD916

81/2, 121/4

MDi719

81/2, 105⁄8, 121/4, 141/2

MD919

121/4, 131/2

MDi813

53/4, 83/4, 121/4, 141/2, 143/4, 161/2

MDi816

83⁄8, 81/2, 105⁄8, 121/4, 133/4, 171/2, 181⁄8, 181/4

7

Directional nomenclature

M D i 6 16 Cutter size Blade count i – IDEAS certified D – IDEAS directional certified M/S – Matrix or steel

www.slb.com/directional

121/4-in MDi616

23

Fixed Cutter Bits

SHARC High-Abrasion-Resistance PDC Drill Bit Bit durability and maximum ROP in abrasive formations The cutting-structure layout of a SHARC* PDC drill bit features two rows of cutters set on certain blades. Each row reinforces the other to provide maximum durability over the critical nose and shoulder areas of the bit, ensuring that ROP capability is not compromised. Additionally, the double rows are oriented to ensure that hydraulic cleaning and cooling efficiency are maintained. This feature is important not only in abrasive interbedded sands, but also in surface intervals with high ROP or when hydraulic energy is compromised, for example, on motor runs. When drilling hard, highly abrasive formations, SHARC PDC bits maintain maximum ROP over the target interval. Drilling faster and staying downhole longer, these bits are achieving superior performance in challenging applications all over the world. The key to achieving both bit durability and maximum ROP is maintaining drillbit stability across a broad range of downhole conditions. SHARC bits are designed using the IDEAS* integrated drillbit design platform, specifically to eliminate vibration, resulting in maximum stability for superior wear resistance. Their durability eliminates unnecessary trips, saving time and costs for the operator.

Type

Size Availability, in

MDSi613

57⁄8, 6, 61⁄8, 63/4, 77⁄8, 83/4

MDSi616

77⁄8, 81/2, 83/4, 97⁄8, 12, 121/2, 16, 171/2

MDSi716

77⁄8, 81/2, 83/4, 97⁄8, 12, 121/2, 16, 171/2

MDSi619

143/4, 16

MSi416

61⁄8, 63/4, 77⁄8, 81/2, 83/4

MSi513

61⁄8, 61/4, 77⁄8

MSi516

61⁄8, 63/4, 77⁄8, 81/2, 83/4, 97⁄8, 12

MSi519

77⁄8, 81/2, 83/4, 97⁄8, 121/4

SDSi519

121/4, 171/2

MSi611

61⁄8

MSi613

6, 61⁄8, 61/4, 61/2, 63/4, 77⁄8, 81/2, 83/4, 12

MSi616

6, 61⁄8, 61/2, 63/4, 77⁄8, 81/4, 81/2, 83/4, 91/2, 97⁄8, 105⁄8, 121/4, 143/4, 16

MSi711

55⁄8, 57⁄8, 6

MSi716

77⁄8, 81/2, 83/4, 97⁄8, 12, 121/2, 16, 171/2

MSi816

77⁄8, 83⁄8, 81/2, 83/4, 97⁄8, 121/4, 16, 171/2

MSi1013

12

SHARC nomenclature

M D S i 6 13 Cutter size Blade count i – IDEAS certified S – SHARC D – IDEAS directional certified M/S – Matrix or steel

www.slb.com/SHARC

81/2-in MDSi613LBPX

24

Fixed Cutter Bits

Spear Shale-Optimized Steel-Body PDC Drill Bit Design based on proven drilling performance Introduced in 2011, the Spear* shale-optimized steel-body PDC drill bit significantly reduced bit balling and cuttings that tended to pack around the blades of matrix-body bits.

Type

Size Availability, in

SDi513

6, 61⁄8, 61/4, 61/2, 63/4, 77⁄8, 81/2, 83/4

SDi611

63/4, 83/4

Characterized by its distinctive bullet shape and smaller diameter steel body, the streamlined Spear bit put more distance between the bit body and borehole. This helped increase cuttings evacuation by minimizing blade packing and nozzle plugging, allowing the bit to drill more efficiently. After more than 5,000 runs, the Spear bit’s innovative capabilities have proven to increase drilling performance and lower drilling costs of curve- and long-lateral sections in unconventional shale plays.

SDi613

81/2, 83/4

SDi711

61⁄8, 61/2, 63/4

SDi713

61⁄8, 63/4, 77⁄8, 81/2, 83/4

Next-generation shale-optimized steel-body PDC drill bits

Based on Spear bit performances, and a redesign program conducted by Smith Bits using IDEAS integrated drillbit design platform, the next-generation Spear shale-optimized PDC bit has demonstrated greater directional control and ROP increases of as much as 40%.

The next-generation Spear bits feature a smaller body profile that promotes the movement of cuttings around the body and into the junk slot.

Spear nomenclature

S D i 6 13 Cutter size Blade count i – IDEAS certified D – IDEAS directional certified S – Spear shale-optimized steel-body

www.slb.com/Spear 25

Fixed Cutter Bits

Standard PDC Matrix and Steel Bits The workhorse of the oilfield, delivering premium performance with superior durability. Features such as cutter types, cutter layout, and blade geometry are continuously being evaluated and improved to deliver value and drive down drilling costs. Certification with IDEAS* integrated drillbit design platform ensures these bits offer optimum performance.

Standard PDC nomenclature

M i 6 16

Type

Size Availability, in

Type

Size Availability, in

Mi413

61/2

S619

81/2, 121/4, 171/2

Mi416

61⁄8, 61/4, 63/4, 75⁄8, 77⁄8

S716

143/4

Mi419

6 ⁄8, 81/2, 9 ⁄8

S719

121/4

Mi513

61/4, 61/2, 77⁄8, 83/4

S816

16, 171/2, 26

Mi516

61/2, 83/4, 121/4

S819

26

Mi519

83/4, 97⁄8, 121/4

Si419

81/2

Mi613

7

61/2, 7 ⁄8, 83/4

Si519

81/2, 121/4

Mi616

77⁄8, 97⁄8, 121/4

Si613

16

Mi619

121/4, 17

Si616

121/4

1

7

Mi713

6 ⁄8

Si619

131/2

Cutter size

Mi716

77⁄8, 83/4, 12, 121/4, 143/4

Si819

23, 24

Blade count

Mi811

6

M413

77⁄8

i – IDEAS certified

Mi813

61⁄8, 63/4, 105⁄8, 171/2

M416

6, 77⁄8

M/S – Matrix or steel

Mi816

121/4, 171/2

M419

81/2

Mi913

77⁄8, 121/4

M509

33/4

Mi916

121/4, 14, 16

M511

41/2

Mi919

16

M513

43/4, 47⁄8, 61⁄8, 61/4, 77⁄8

Mi1016

121/4

M516

57⁄8, 97⁄8, 115⁄8, 121/4, 16

S416

63/4

M519

6, 97⁄8, 121/4

S422

6,121/4

M609

35⁄8, 33/4, 41⁄8, 41/2, 43/4

S516

81/2,121/4

M613

6, 81/2, 115⁄8, 121/4

S519

81/2, 10 ⁄8, 121/4, 131/2, 143/4, 16, 17, 171/2

M616

63/4, 97⁄8, 121/4

S522

121/4

M619

77⁄8, 171/2

S613

16

M711

57⁄8

S616

81/2, 121/4, 171/2

M713

81/2, 83/4, 91/2, 121/4

1

5

M716

6, 83⁄8, 121/4

M809

6, 61⁄8, 63/4

M813

6, 77⁄8, 9, 121/4

M816

16

M909

43/4, 57⁄8, 6, 61/2

M916

81/2

M1609

81/2, 83/4

www.slb.com/pdc

83/4-in Mi616MSPX

26

Fixed Cutter Bits

Kinetic Diamond-Impregnated Bit for High-Speed Applications Kinetic bits have established world and numerous field records for the most footage drilled and the highest ROP. Designed for superior performance when drilling at high rotary speeds through the toughest, most abrasive formations, Kinetic* bits are built with precisely engineered grit hot-pressed inserts (GHIs) and thermally stable polycrystalline (TSP) diamond inserts, premium PDC cutters, and proprietary diamond-impregnated matrix materials. Each element is chosen to optimize both durability and ROP.

Type

Size Availability, in

K503

5–121/4

K505

33/4, 57⁄8, 6, 61⁄8, 63/4, 81/2, 12, 143/4, 16

K507

6, 61/2, 83⁄8, 81/2, 83/4, 121/4

K703

41/2–83/4

K705

33/4, 6–121/4

Application-specific design

K707

81/2, 143/4

KH613

57⁄8, 6

KH813

83⁄8, 81/2, 91/2, 121/4

Most Kinetic bits use strategically placed premium PDC cutters in the cone area to improve drillout capability and maximize ROP, while the impregnated matrix material enhances durability. TSP diamond inserts are positioned on the gauge to ensure that the bit maintains a full-gauge hole. In extremely abrasive applications, TSP diamond elements are also placed on the bit shoulder for increased wear resistance in this critical area. Kinetic bits can be customized with different bonding materials and diamonds to match the formation being drilled and the drive system used, making the bits ideal for exploiting the higher rotational velocities possible with turbodrills.

Open face for optimum clearing Brazed-in GHI Application-tuned impregnated body material

The bit uses a combination of center-flow fluid distribution and precisely placed ports to enhance bit cooling and to ensure efficient bit cleaning. These functions are particularly important in softer formations, enabling the bit to drill mixed lithologies effectively. There is no need to trip to change the type of bit. Kinetic bits are able to drill PDC-drillable shoe tracks. They are cost-effective in overbalanced applications, where drilling with a conventional fixed cutter or roller cone bit results in low ROP and reduced footage.

Cast-in GHI

Central flow Dedicated fluid port

A hybrid design, designated with an “H” in the bit nomenclature, is a combination of a traditional PDC bit and a diamondimpregnated bit. Hybrid Kinetic drill bits are suitable in borderline-PDC-drillable formations.

High performance with turbodrills

Because of the inherent power and longevity of a turbodrill compared with a positive displacement motor (PDM), a Kinetic bit delivers a particularly high performance when combined with a Neyrfor* high-performance turbodrill system.

Kinetic nomenclature

K H 8 13 Cutter size Blade count H – Hybrid K – Kinetic impreg

www.slb.com/Kinetic 27

Fixed Cutter Bits Optional Features

L Feature Low Exposure (MDOC—Managed Depth Of Cut) Feature:

L

Cutter backing raised to minimize excessive depth of cut because of formation heterogeneity

Advantage: Reduces cutter loading; minimize torque in transitional drilling Benefit:

Minimizes cutter breakage to extend bit life

M Feature Replaceable Lo-Vibe Inserts Feature:

M

Lo-Vibe* depth of cut control inserts that can be replaced when needed (wear, breakage, etc.)

Advantage: Limits excessive depth of cut and helps reduce torsional vibration Benefit:

Provides superior ROP and bit life

V Feature Lo-Vibe Option Feature:

V

Lo-Vibe depth of cut control insert

Advantage: In applications that produce bit whirl, Lo‑Vibe option improves bit stability and reduces potential for damage to the cutting structure by restricting lateral movement and reducing the effects of axial impacts Benefit:

Optimized ROP and bit life to drill long drilling intervals eliminates tripping

28

Fixed Cutter Bits Optional Features

Z Feature Stinger—conical diamond element

Z

Feature:

Element fails rock more efficiently than conventional PDC bit cutters

Advantage: Improves bit stability and decreases vibration Benefit:

Increases drilling efficiency for greater ROP

K Feature Impregnated Cutter Backing

k

Feature:

Diamonds impregnated in the matrix behind the PDC cutters

Advantage: Limits PDC cutter wear Benefit:

Increased footage drilled in abrasive applications

H Feature Anti-balling

h

Feature:

Higher number of nozzles than standard

Advantage: Increased cleaning, cooling, and cuttings evacuation with available hydraulic flows; higher flow rates with minimal increase in pump pressure, and reduced risk of bit balling Benefit:

29

Superior ROP and bit life; longer drilling intervals eliminates tripping

Fixed Cutter Bits Optional Features

N Feature Fewer Nozzles than Standard Feature:

N

Fewer nozzles

Advantage: Reduced nozzle count to match drilling, formation, and hydraulic system capabilities; reduces the flow rate required to achieve an appropriate hydraulic horsepower per square inch (HSI); eliminates more numerous, smaller nozzles that can become plugged Benefit:

Superior ROP and bit life; longer drilling intervals eliminates tripping

Y Feature 30-Series Nozzles Feature:

Y

Contains 30-series nozzles

Advantage: Allows more freedom in cutting structure design, particularly for smaller bits with limited areas for placement of larger nozzles Benefit:

High efficiency for cleaning, cooling, and cuttings evacuation without compromising the cutting structure resulting in reduced ROP or bit life

W Feature 40-Series Nozzles Feature:

w

Contains 40-series nozzles

Advantage: Increased thread size for resistance to wear and erosion Benefit:

Reduced pop-up force when tightening nozzle

U Feature 50-Series Nozzles Feature:

u

Contains 50-series nozzles

Advantage: Maximum adjustable total flow area (TFA) for smalleror heavier-set designs Benefit:

High efficiency for cleaning, cooling, and cuttings evacuation without compromising the cutting structure, resulting in reduced ROP or bit life

30

Fixed Cutter Bits Optional Features

Q Feature Fixed Ports

q

Feature:

Incorporates fixed ports

Advantage: Optimizes hydraulics in applications where nozzles compromise bit design because of space limitations or other similar reasons; provides additional cleaning of the cutting structure Benefit:

Improves ROP and bit life

R Feature ONYX 360 rolling cutter

r

Feature:

Cutters revolve 360° to stay sharper longer

Advantage: Increases run footage Benefit:

Extends bit durability

E Feature Extended Gauge Length

e

Feature:

Longer than standard gauge

Advantage: Enhances bit stability and allows more area for gauge protection components Benefit:

31

Improves borehole quality

Fixed Cutter Bits Optional Features S Feature Short Gauge Length Feature:

s

Short gauge length

Advantage: Reduced bit height improves bit steerability for directional and horizontal applications; reduces slide time and footage by achieving builds and turns more quickly Benefit:

Lower cost per foot, higher overall ROP

A Feature Active Gauge Feature:

a

Active gauge

Advantage: More aggressive side cutting Benefit:

Aids openhole sidetrack applications

B Feature Backreaming Cutters Feature:

b

Backreaming cutters

Advantage: Strategic placement of cutters on upside of each blade to allow backreaming in tight spots; reduces potential of “bit sticking” while pulling out of the hole Benefit:

Allows a degree of backreaming sufficient to condition borehole without major risk of gauge pad wear

32

Fixed Cutter Bits Optional Features

PX Feature Diamond-Enhanced Gauge Protection

px

Feature:

Diamond-enhanced gauge protection

Advantage: Thermally stable polycrystalline (TSP) diamonds provide extra protection to gauge. Benefit:

In-gauge borehole and longer bit life; longer drilling intervals eliminates tripping

T Feature Turbine Sleeve

t

Feature:

Turbine sleeve

Advantage: Reduces vibration and borehole spiraling in turbine applications; sleeve lengths can be varied to best match a specific application Benefit:

Improved ROP and bit life; long drilling intervals eliminates tripping

PXX Feature Full-Diamond Gauge Pad on Turbine Sleeve

pxx

Feature:

Full-diamond gauge pad on turbine sleeve

Advantage: Diamond-enhanced inserts provide greatest possible extend gauge life in highly abrasive formations and underbalanced drilling Benefit:

33

Produces in-gauge borehole in extreme drilling environments; longer drilling intervals eliminates tripping

Fixed Cutter Bits Optional Features

D Feature DOG Drilling on Gauge Sleeve Feature:

d

DOG* drilling on gauge sleeve

Advantage: Reduces borehole spiraling Benefit:

Enhances BHA stability and helps maintain in‑gauge wellbore

C Feature Connection Not API Standard Feature:

c

Nonstandard bit connection

Advantage: Allows nonstandard box connection for a given bit size, to minimize length between bit box and turbine or motor pin Benefit:

Provides stabilization, reduces bore hole spiraling, and provides additional gauge protection

I Feature IF Connection Feature:

i

IF connection replaces standard connection

Advantage: Allows bit conformity to connection type of directional tools Benefit:

Provides more flexibility in configuring a drilling assembly

34

Fixed Cutter Bits Nomenclature

Product Line

Prefix Description

Face Features

Description

A

ARCS & ARCS advanced

K

Impregnated cutter backing

C

Carbonate

L

Low exposure

D

Natural diamond bit

M

Replaceable Lo-Vibe

Di

IDEAS certified directional design

V

Lo-Vibe

G

Reamers with API connections (box down, pin up)

H

Kinetic hybrid bit

Hydraulic Features

Description

HOX

Heavy oil series

H

Higher number of nozzles than standard

K

Kinetic impregnated bit

N

Lower number of nozzles than standard

L

LIVE

Q

Fixed ports

M

Matrix body

U

50 series nozzles

PR

Pilot reamer

W

40 series nozzles

QD

Quad-D dual diameter

Y

30 series nozzles

R

ONYX 360 rolling cutter

S

Steel body

Gauge Features

Description

S

SHARC

A

Active gauge

ST

Side track

B

Back reaming cutters

SHO

Staged hole opener

D

Dog sleeve

T

Turbine

E

Extended gauge pad length

V

VertiDrill

PX

TSP on gauge

Z

Stinger—conical diamond element

PXX

Full diamond on turbine sleeve

S

Short gauge pad length

T

Turbine sleeve

Nomenclature identifies blade count/cutter size. Example: M616 = 6 Blades /16 mm cutters

Connection Features Description C

Non API standard connection

I

IF connection

Nomenclature example

M S i R 6 16 M H PX PX – TSP on gauge (Gauge feature) H – Higher number of nozzles than standard (Hydraulic feature) M – Replaceable Lo-Vibe (Face feature) Cutter size Blade count R – ONYX 360 rolling cutter (Product line) i – IDEAS certified (Product line) S – SHARC (Product line) M – Matrix (Product line)

35

Roller Cone Products

37

Roller Cone Bits Product Line Tungsten Carbide Insert (TCI) bits ■■

Gemini* dynamic twin-seal drill bit

■■

Shamal* carbonate-optimized TCI drill bit

■■

Xplorer* slimhole TCI drill bit

■■

FH TCI* drill bit

Milled Tooth (MT) bits ■■

Xplorer Expanded* soft formation, milled tooth drill bit

TCT* two-cone drillbit technology

Standard roller cone bits ■■

Milled tooth, TCI, and open-bearing bits for all applications

Kaldera ■■

Roller cone products for geothermal and high-temperature applications

38

Roller Cone Bits

Gemini—Dynamic Twin-Seal Drill Bit The Gemini seal system consists of a primary seal that protects the bearings, and a secondary seal that protects the primary seal, making this system the industry leader in durability and reliability. The proprietary dual-material primary seal combines a highly wear resistant, dynamic face elastomer and a softer energizing material that exerts a consistent contact pressure. The bullet-shaped seal has a large cross-sectional profile to provide maximum protection for the bearing.

Size Type Availability, in

The secondary seal is also made from a mix of patented materials, and is designed to prevent abrasive particles in the wellbore fluids from coming into contact with the bearing seal. A thermoplastic fabric reinforced with Kevlar ® is positioned on the dynamic face, embedded in an elastomer matrix. The fabric provides resistance to wear and tear, and heat damage, in addition to acting as a barrier to abrasive particles. The elastomer matrix provides elasticity and proven sealing ability. Although they work independently, the seals create a synergy that allows them to perform reliably for extended periods of time at higher RPMs, heavier drillstring weights, extreme dogleg severity, and increased mud weights and pressures. Gemini* drill bits are available in a wide range of sizes, as both TCI and milled tooth bits.

Bearings

83⁄8

GF15, GF20, GF40, GFi50

81/2

GF05, GF06, GF08, GF10, GF15, GF20,GF25, GF30, F30, GF40, GF45, GF50, GF65, GF80, GFA21, GFi08, GFi10, GFi12, GFi20, GFi23, GFi28, GFi30, GFi45, GFi50

85⁄8

GF15, GF45

83/4

GF10, GF15, GF27, GF40

91/2

GF20, GF21, GF30, GF45, GFVH

115⁄8

GF15, GF20

12

GF10, GF20, GF28

121/4

G04, GF05, GF10, GF15, GF20, GF26, GF30, GF37, GF40, GF45, GF47, GF57, GFi05, GFi06, GFi12, GFi23, GFi28, GFi30, GFi35, GFi40, GFi45, GFi47, GFK30, GFK57, GFKi28, GGH+, MGGH+

143/4

G10, G15, G25, G40

16

G18, GGH+, MGGH+

171/2

G02, G10, G15, G28, G30, Gi01, Gi03, Gi12, GGH+

22

Gi06

24

G04

26

G04, G28

Gemini bits can be equipped with roller bearings (bit size ≥ 12¼ in) or friction bearings (bit size ≤ 12¼ in).

Cutting Structure

Different cutter layouts are available. TCIs of various grades and geometries have been developed to produce a durable and effective cutting structure. IDEAS* integrated drillbit design platform is used to optimize the cutting structure, so that loads are more evenly distributed over the inserts of all three cones, producing a well-balanced bit with reduced risk of bearing failure.

Gemini nomenclature

GF i 35 Cutting structure i – IDEAS certified G/GF – Gemini designation

www.slb.com/Gemini

171/2-in Gi03

39

Roller Cone Bits

Shamal Hard Carbonate-Optimized TCI Drill Bit Shamal drill bits are designed for hard carbonate drilling, with specifically designed tungsten carbide inserts. The Shamal* product line incorporates a range of TCI bits developed for maximizing performance in hard carbonate formations.

Size Type Availability, in 81/2

These bits use a range of proprietary, coarse carbide grades, which are designed to combat heat checking and subsequent chipping and breakage of inserts, the primary dull characteristics when drilling hard carbonates. Incorporating unique cone layouts and insert geometries, the Shamal product line is providing superior ROP and durability in challenging applications throughout the world.

83/4

GFS15

115⁄8

GFS30

12

GFS28

121/4

GFSi01, GFS04, GS04, GFS05, GS05, GFS06, GFSi06, GFS10, GS10, GFS11, GFS15, GS15, GFS20, GFS26, GFS30, GFSi28

143/4

GS10

151/2

GS10

16

GS03, GS10, GS12, GS18, GS30, GSi01, GSi03, GSi06, GSi12, GSi15, GSi18, GSi20

171/2

GS03, GS05, GS10, GS12, GS15, GS18, GS28, GSi01, GSi12, GSi18

22

GS04, GS12, GSi06, GSi12

231/2

GS04

24

GS18

26 28 36

GS04, GS18 GS04, GS18, GSi18 GSi15

Shamal tungsten carbide

Shamal nomenclature

G S i 05 Cutting structure i – IDEAS certified S – Shamal feature G – Bearing prefix

www.slb.com/Shamal

12¼-in GFS05BVCPS

40

GFS05, GFS06, GFS15, GFS20, GFS30, GFSi10, GFSi23, GFSi28, MFS04, MFS10T, MFS20B

Roller Cone Bits

Xplorer Premium Slim Hole TCI Bit Xplorer drill bits provide consistently superior performance in applications ranging from very soft to ultrahard formations. Maximum steerability and strength

Size Type Availability, in

Xplorer* slimhole TCI drill bits have ultrashort leg forgings, which maximize steerability at extreme build angles, enabling the most demanding directional programs. The forging design also strengthens the chassis and meets the hydraulic demands of modern drilling.

Harder-wearing seals

To handle the high rotation speeds typically seen in the formations in which slimhole bits are used, a dual-material Bullet* drillbit bearing seal is used for soft formation insert bits (IADC 4-1-7X to 5-4-7Y). This system reduces seal wear while limiting temperature buildup in the bearing section through the use of matched, dual elastomers.

33/4

XR20, XR40

7

3 ⁄8

XR30, XR50

41⁄8

XR30, XR50

41/2

XR30

45⁄8

XR30, XR50

43/4

XR15, XR20, XR30, XR40, XR50, XR70

47⁄8

XRi15, XR20, XR30, XR50

51/2

XR20, XR40

5 ⁄8

XR30, XR40, XR50

57⁄8

XR15, XR20, XR30, XR40, XR50, XRi40, XRi50, XRS15

6

XR10, XR12, XR15, XR20, XR30, XR40, XR45, XR50, XR65, XR70, XRS30, XRi15, XRi20, XRi40, XRi45, XRi50

61⁄8

XR10, XR15, XR20, XRSi20, XR25, XR30, XRi30, XRi35, XR38, XR40, XR50, XR60, XRi65, XR68, XR70, XR90, XR35, XRi20, XRi28, XRi40, XRi45, XRi50, XRKi65

61/4 61/2

XR20, XR30, XR40, XR50, XR70, XRi30, XRi35, XRi45 XR10, XR15, XR20, XR30, XR40, XR45, XR50, XR60, XR68, XR70, XR90 XR10, XR20, XR25, XR32, XR40, XR50, XRi30

5

For harder formation Xplorer bits (with IADC codes 6-1-7X and higher), a rotary “O” ring seal with optimized properties is used, which significantly increases the wear resistance of the seal compared to conventional materials. These “O” rings result in market-leading bearing performance in hard formations.

Optimum cutting structures

63/4

Individual cutter layouts, as well as a complete range of inserts, insert grades, and geometric enhancements have been developed specifically for Xplorer bits to reduce breakage, maintain full gauge, and increase ROP. Features such as Ridge Cutters* drillbit chisel inserts, significantly reduce cone shell wear and allow the main cutting structure to function more effectively.

Xplorer nomenclature

XR i 20 Cutting structure i – IDEAS certified XR – Xplorer designation

www.slb.com/Xplorer

61/2-in XR20T

41

Roller Cone Bits

Xplorer Expanded Soft-Formation Milled Tooth Drill Bit Milled tooth bits that are specifically designed to drill soft to firm formations. Enhanced ROP

Xplorer Expanded* milled tooth drill bits are specifically designed to drill soft to firm formations with superior ROP and reliability. The bits are equipped with the Flex-Flo* adaptive hydraulics system, offering the widest range of options for maximizing ROP and ensuring effective hole cleaning in any application.

Type

Size Availability, in

XR+

41/2, 43/4, 47⁄8, 5, 51/2, 55⁄8, 53/4, 57⁄8, 6, 61⁄8, 61/4, 61/2, 63/4, 77⁄8, 83⁄8, 81/2, 83/4, 91/2, 97⁄8, 105⁄8, 115⁄8, 121/4, 131/2, 133/4, 141/2, 143/4, 15, 151/2, 16, 17, 171/2, 181⁄8, 181/2, 191/4, 20, 213/4, 22, 23, 24, 26, 31, 32, 321/4, 323⁄8, 33, 36

Extremely wear resistant MIC2* drillbit hardfacing material provides durability, enabling the bits to drill at a high ROP for prolonged periods. The cutting structure is designed for for maximum shearing and scraping action in the softer formations encountered in milled tooth applications.

Reliable seals and bearings

All Xplorer Expanded bits with 81/2-in or larger diameter benefit from the proven reliability of the dynamic twin bearing-seals system used by Gemini* drill bits. The Spinodal* roller cone drillbit friction bearing used is both reliable and durable. Bit sizes 13½ in and greater incorporate premium sealed roller bearings.

Xplorer nomenclature

XR + Premium milled tooth cutting structure XR – Xplorer designation

www.slb.com/XR-expanded

171/2-in XR+ ODVEC

42

Roller Cone Bits Kaldera Bit

Roller Cone Products for Geothermal and High-Temperature Applications Geothermal and high temperature drill bits

Size Type Availability, in Milled Tooth

High temperature drilling environments, seen most commonly in geothermal wells, provide a unique set of challenges for downhole equipment. In many of these applications the tungsten carbide insert (TCI) roller cone bits used to drill these wells must endure hard and abrasive formations to steam or hot rock in basement formations where temperatures can exceed 500 degF.

Proven durability in high-temperature applications

Tested against baseline bits, in geothermal superheated steam applications where temperatures can reach 530 degF, the new Kaldera roller cone bit was clearly the top performer: Average run length was 33% greater

XRK+

XRK40 1

6 ⁄8

XRK40

77⁄8

FHKi30

81/2

47YGA, FHK15, FHK30, FHK45, FHKi40, FHKi50, FHKi69

9 ⁄8

FHK30, FK47, FK50, FK57

105⁄8

GFK47

121/4

47YG, GFK15, GFK30, GFKi28, GFK10

17

GSK20, GSKi18

22

GSKi12

7

Kaldera high-temperature roller cone drill bit represents a new line of bits with an innovative bearing system that comprises new proprietary composite elastomer seals with specialized fabric compounds and a proprietary high-temperature grease formula. These innovations increase seal life, lubricity, and load capacity at elevated temperatures for HT applications.

■■

81/2

6

Drilling for unique energy calls for a unique bit

On-bottom drilling time was 3% to 37% greater

XRK+

TCI

At that temperature, a standard 300 degF-rated bit’s elastomer seals and lubricating material quickly degrades, causing bearing failure, resulting in operational inefficiencies: reduced on-bottom drilling hours leading to multiple bit runs/trips, and increased development costs.

■■

57⁄8

Kaldera milled tooth nomenclature

XRK + Premium milled tooth cutting structure XRK – Xplorer-Kaldera designation

Kaldera TCI nomenclature

GFK 47 Premium TCI cutting structure GFK – Gemini-Kaldera designation

www.slb.com/Kaldera 43

Roller Cone Bits

FH Single-Seal TCI Drill Bit

FH TCI roller cone drill bits offer superior performance in a wide variety of applications at a lower cost per foot. Optimized cutting structure

Size Type Availability, in

FH* TCI drill bits have patented insert and cutter geometries. Engineers use the IDEAS* integrated drillbit design platform to precisely monitor the interaction between the cutting elements and the rock, and optimize bit design to allow the maximum amount of mechanical energy to be applied to the formation.

Reliable seals and bearings

The bullet-shaped, dual dynamic seals of FH TCI bits have undergone extensive finite element analysis (FEA) in a laboratory to ensure reliability. The bearings used are the latest evolution of the silver-plated Spinodal* roller cone drillbit friction bearings. The proven properties of the bearing material, along with the frictionreducing effects of the silver, combine to create a longer lasting, highly reliable bearing package.

77⁄8

FHi20, FHi21, FHi23, FHi24, FHi26, FHi28, FHi30, FHi35, FHi38, FHi40, FHi45, FHi50, FHi43, FHKi30, FH25, FHi08, FHi18, FHi37, FHi39

81/2

FH23, FHi04, FHi20, FHi21, FHi28, FHi40, FHi69, FH30, FH35, FH40, FH45, FH50, FHi90, FHK08, FHK30, FHKi 40, FHKi50, FHKi69

83/4

FH16, FHi18, FH20, FHi20, FHi21, FHi23, FHi25, FH28, FHi28, FHi29, FHi30, FH32, FHi35, FHi37, FHi38, FHi40, FH43, FH45, FHi50, FH23, FH30, FH35, FH40, FH50, FHi32, FHi39, FHi43, FHi45, FHi47, FHi55, FHi90

97⁄8

FH23, FH28, FH30, FH35, FH40, FH45, FH50, FHi12, FHK30

121/4

FH24, FH50

Application-specific hydraulics

The Flex-Flo* adaptive hydraulics system offers a range of hydraulic configurations that are optimized for specific applications. Computational fluid dynamics software, and our bit flow visualization system were used to design this feature.

FH nomenclature

FH i 28 Cutting Structure i – IDEAS Certified FH – FH Designation

www.slb.com/FH

83/4-in FH28GVPS

44

Roller Cone Bits

TCT Two Cone Drillbit Technology More aggressive roller cone designs Smith Bits TCT* two-cone drill bits are designed using the dynamic modeling capabilities of the IDEAS* integrated drillbit design platform. The process includes evaluation and testing in a virtual environment to reduce vibration, enhance stability, and increase ROP.

Size Type Availability, in

Optimal cutting structure

83/4

TCTi+, TCT20, TCT37

97⁄8

TCTi+

121/4

TCTi+, TCT11, TCT12, TCTi11

61/2

TCTi+

7 ⁄8

TCTi20

81/2

TCTi+

7

Extensive analysis ensures that the cutting structure layout optimally exploits the bit’s unique characteristics. Two-cone bits have lower tooth counts than equivalent three-cone bits, and higher point loading per tooth for improved formation penetration. They also benefit from current technology for enhanced insert geometries and the latest carbides and hardfacing materials.

16

TCT+, TCTi+

171/2

TCT10, TCTi+

Five-nozzle hydraulic configuration

TCT two-cone drill bits can incorporate five nozzles, four outboard and one center jet. The field-proven V-Flo* vectored-flow nozzle configuration precisely positions and directs the five nozzles for increased impingement pressure and optimum cutting structure cleaning and cuttings evacuation, thereby improving penetration rates. The five-nozzles significantly increase the available options for directing fluid flow, compared with a three-cone bit that uses three nozzles.

Enhanced stability

Two-cone bits have four points of stabilization. The lug-pad and leg-back placement, along with the forging geometry, reduces vibration, increases bit life, and enables a higher ROP. In addition, the lug pads and leg backs are protected by tungsten carbide inserts to stabilize the bit and ensure a full-gauge wellbore.

Reliable twin-seal system

121/4-in MT TCTi+

The dynamic twin-seal system of Gemini* bits is also employed by TCT two-cone drill bits. It comprises a pair of seals working together to provide the most reliable and robust sealing mechanism available in roller cone bits. The bits maintain seal integrity under the harshest conditions, including high rates of rotation, weight on bit, dogleg severity, mud weights, temperature, and pressure.

TCT nomenclature

TCT i + Premium Milled Tooth Cutting Structure i – IDEAS Certified TCT – TCT Designation

www.slb.com/TCT

121/4-in TCI TCTi

45

Roller Cone Bits

Standard Milled Tooth, TCI and Open Bearing Bits The standard line of Smith Bits journal and roller bearing bits delivers premium performance. These bits are the focus of ongoing product improvement, which enhances existing designs and integrates new materials technology. Standard bits are continuously improved in order to aggressively drive down drilling costs. Among the features and materials incorporated into the standard product offering are Spinodal* roller cone drillbit friction bearings, advanced bearing lubricants, the Flex-Flo* adaptive hydraulics system, MIC2* drillbit hardfacing material, diamond-enhanced inserts, coarse carbide inserts, and relieved-gauge inserts. Size Type Availability, in 33/4 63/4

OFH, OFM

6

FDGH, FHV

71/2

FDT

7 ⁄8

FDS+, FI18, F26Y, F27Y, F27iY, F30Y, F37HY, FI39HY, F45H, F47HY, F47YA, F49YA, F57Y, F59HY, F67Y, F80Y, F85Y, F90Y

83⁄8

MFDGH, SVH, F37Y, F57Y

81/2

F10, F37HY, F37Y, F47HY, F57Y, F67Y, F80Y, F85Y, FDGH, FDS+, MFDGH

83/4

FDS+, F12V, F26Y, F27iY, F30T, F37HUY, F37HY, F39HY, F40YA, 46HY, F47HY, F47YA, F50YA, F59Y, F67Y, F80Y, F85Y, F90Y

87⁄8

F40YA, F50YA

91/2

FDS+

97⁄8

FDS+, F10B, F37Y, F47HY, F59Y, F67Y, F80Y, F85Y, F90Y

105⁄8

F37, F47Y, F67Y, F85Y, F90Y

11

F20, F20Y, F27Y, F37Y, F47Y, FDS

115⁄8

F30, F47Y, FDGH, MSVH

121/4

F25Y, F37Y, F40, F47YA, F57, F67, F80Y, F90Y, FDGH, FDS+, FDT

143/4

F30

17

MSDGH

171/2

DSJ

20

MSDGH

Cutting Structure

22

MSDGH

F – Bearing Prefix

23

DSJ, MSDGH

26

DSJ, MSDGH

28

MSDGH, DSJ

32

MSDSSH

34

MSDGH

36

DSUJ

7

121/4-in FVH

Standard nomenclature/Milled tooth bits

FVH H – Heel Inserts V – Medium to Hard Formation Type F – Bearing Prefix

Standard nomenclature/TCI insert bits

F 12

www.slb.com/rockbits

83/4-in F12

46

Roller Cone Bits Optional Features

TD Feature Diamond-Enhanced Trucut Gauge Protection

td

Feature:

Diamond-enhanced, semiround-top, on-gauge inserts provide finish cut-to-gauge for Trucut* drillbit gauge system with off-gauge inserts are made of tungsten carbide

Advantage: Suitable for more abrasive environments; more durable than standard Trucut gauge configuration Benefit:

Extended bit-gauge life results in long intervals and quality, in-gauge boreholes

SD Feature Shaped Diamond-Enhanced Gauge Inserts

sd

Feature:

Shaped 100% diamond-enhanced gauge inserts

Advantage: Shaped geometry creates a more aggressive cutting structure Benefit:

Maximum ROP and high-quality, in-gauge borehole for the longest possible intervals in highly abrasive environments

D Feature Diamond-Enhanced Gauge Row Inserts Inserts

d

Feature:

Diamond-enhanced gauge inserts

Advantage: Substantially reduced gauge-row wear and breakage rates; greater wear-resistance in highly abrasive applications Benefit:

47

High-quality, full-gauge wellbore over longer intervals compared with tungsten carbide gauge inserts

Roller Cone Bits Optional Features

B Feature Binary Gauge Protection Feature:

b

Small, semiround-top inserts positioned between primary gauge inserts

Advantage: Smaller inserts improve wear resistance Benefit:

Improved bit-gauge durability and longer, in-gauge bit runs

BD Feature Diamond-Enhanced Insert Binary Gauge Protection Feature:

bd

Diamond-enhanced, semiround-top inserts positioned between primary gauge inserts

Advantage: Extreme wear resistance Benefit:

Improved bit-gauge durability and longer, in-gauge bit runs

T Feature Tungsten Carbide Trucut Gauge Protection Feature:

T

TCI protection for Trucut* drillbit gauge system

Advantage: Improved gauge durability and integrity with a twin gauge-insert system composed of aggressive, neargauge inserts to drill the near-gauge and borehole corner with reduced scraping action, and semiroundtop, on-gauge inserts provide finish cut to gauge; significantly reduces stress on gauge inserts Benefit:

Extended bit-gauge life for longer intervals and highquality, in-gauge boreholes

OD Feature Diamond-Enhanced Heel Row Inserts Feature:

od

Up to 50% diamond-enhanced heel row inserts

Advantage: Improved resistance to abrasive wear and impact damage; protection for lower leg and bearing seal areas Benefit:

Extended bit-gauge life for longer intervals and highquality, in-gauge boreholes

48

Roller Cone Bits Optional Features

OD1 Feature All Heel Row Inserts Diamond Enhanced

od1

Feature:

51%–100% diamond-enhanced heel row inserts.

Advantage: The heel cutting structure is designed for the most abrasive environments, resulting in a longer gaugecutting-structure life, and protection for the lower leg and bearing-seal areas. Benefit:

Longer intervals of high-quality, full-gauge borehole in highly abrasive, high compressive strength formations.

DD Feature 100% Diamond-Enhanced Cutting Structure

dd

Feature:

100% diamond-enhanced cutting structure.

Advantage: Premium cutting structure for drilling very abrasive formations efficiently, with longer runs and lower weight on bit (WOB). Benefit:

High ROP and extended bit life.

G Feature Super D-Gun Cone Protection

g

Feature:

Super D-Gun* tungsten carbide cone protection.

Advantage: A hard, tungsten-carbide-based coating applied to cone shells increases resistantance to abrasion and erosion; ideal for highly abrasive formations that generate large volumes of cuttings; provides additional protection in abrasive and inefficient hole cleaning conditions: high angle, directional, and horizontal applications Benefit:

49

Increased bit life, longer bit runs, and improved insert retention

Roller Cone Bits Optional Features Y Feature Conical Shaped Inserts Feature:

y

Conical shaped inserts

Advantage: Geometry optimized to reduce insert breakage Benefit:

Enables high ROP in formations sensitive to weight on bit (WOB)

V Feature V-Flo Nozzle Configuration Feature:

v

V-Flo* vectored-flow nozzle configuration

Advantage: Jets are directed at leading side of following cone for maximum cleaning; enhanced bottomhole cleaning is achieved through efficient cuttings lift and strong, upward, helical flow Benefit:

Clean cutting structure in soft and sticky formations

VE Feature Extended Vectored Nozzle Sleeve (Available for 121⁄4-in and larger bits) Feature:

ve

Extended vectored nozzle sleeve

Advantage: Nozzle angles are precisely oriented to direct fluid flow to leading edge of cones, increasing cleaning efficiency Benefit:

Clean cutting structure, and maximum ROP through higher impingement pressure

50

Roller Cone Bits Optional Features

J3 Feature (Dome Jets) (Available for 16-in and larger bits)

j3

Feature:

Three nozzles located inboard of conventional roller cone nozzle positions

Advantage: Flow is directed toward intermesh area between cones to enhance cone cleaning Benefit:

Increased cone cleaning to prevent bit balling and maximize ROP

C Feature Center Jet

c

Feature:

Center jet installed

Advantage: Enhanced cone cleaning and hydraulic flow patterns across the bit cutting structure Benefit:

Clean, efficient cutting structure in high-cuttingsvolume or sticky formations

L Feature Lug-Type Leg Back Protection

l

Feature:

Shaped steel-pads welded to upper leg back, with flush-set tungsten carbide or shaped diamondenhanced inserts

Advantage: Leg protection and bit stabilization; helps prevent bit whirl and differential wear between bit legs, which can overload individual cone cutting structures and bearings Benefit:

51

High-quality wellbore and extended bit life

Roller Cone Bits Optional Features

R Feature Semiround-Top (SRT) TCI Stabilization and Leg Back Protection Feature:

r

Stabilizing leg back protection

Advantage: Cluster of SRT tungsten carbide inserts, located on upper leg section and extending to near full-gauge, enhance wear protection and improve bit stability Benefit:

Extended bit life and improved borehole quality

PS Feature Semiround-Top (SRT) TCI Leg Back Protection Feature:

ps

Leg back protection

Advantage: Strategically placed, SRT tungsten carbide inserts improve leg protection against wear; tight, overlapping pattern helps prevent grooving of leg backs. Benefit:

Extended bit life in abrasive environments

PD Feature Diamond-Enhanced Leg Back Protection Feature:

pd

Diamond-enhanced leg back protection

Advantage: Strategically placed, SRT, diamond-enhanced and tungsten carbide inserts improve leg protection against wear; tight, overlapping pattern helps prevent grooving of leg backs and is more wear resistant than 100% tungsten carbide protection Benefit:

Extended bit life in extremely abrasive environments

52

Roller Cone Bits Nomenclature Bearing/Seal Identifier & Product Line Prefix D S F MF M K G GF XR

Applies To

Refers To

Description

All All All All All All All All All

Bearing/Seal Bearing/Seal Bearing/Seal Bearing/Seal Bearing/Seal Bearing/Seal Product Line Product Line Product Line

TCT FH S i + DS DG S T G V S H B H T 00–99

All TCI TCI All MT MT MT MT MT MT MT MT MT TCI TCI TCI TCI

Product line Product Line Cutting Structure IDEAS Cutting Structure Cutting Structure Cutting Structure Cutting Structure Cutting Structure Cutting Structure Cutting Structure Cutting Structure Carbide Gauge Carbide Gauge Carbide Gauge Carbide Gauge Cutting Structure

Nonsealed (open) bearing Single seal, sealed roller bearing Single seal, sealed friction bearing Single seal, friction bearing motor bit Single seal, roller bearing motor bit Kaldera* bit, high temperature seals (geothermal applications) Gemini* bit, twin seal, roller bearing Gemini bit, twin seal, friction bearing Xplorer* slimhole TCI bit (up to 6.75 in) Xplorer Expanded* soft-formation milled tooth bit (up to 36 in) TCT* two-cone technology bit FH TCI*bit, single seal, sealed friction bearing Shamal* carbonate-optimized design, with or without Typhoon hydraulics Design certified by IDEAS* integrated drillbit design platform Milled tooth designator/Premium cutting structure Soft type (IADC 1-1-X)—applicable to ‘FDS’ bits only Medium type (IADC 1-3-X)—does not apply to Gemini bits Soft type (formerly DS)—‘D’ and ‘G’ products only Medium soft type (formerly DT) Medium type (formerly DG)—‘D’ and ‘G’ products only Medium hard type (formerly V2) Premium self-sharpening with hardfacing material Nonpremium bit—heel inserts Binary carbide gauge Heavy-set gauge design (count or grade or both) Trucut* gauge (carbide material on both off-gauge and gauge) Insert bit numeric range (00 Softest–99 Hardest)

Product Suffix I W Y A N

Applies To TCI TCI TCI All All

Refers To Cutting Structure Cutting Structure Cutting Structure Cutting Structure Size

Description Inclined chisel on gauge Softer than standard insert grades Conical insert Air application bit Nominal gauge diameter

Feature TD SD SD1 D OD OD1 DD DD2 G Q V E VE J3 C L LD R RD PS PD P

Applies To TCI TCI TCI TCI All All TCI TCI TCI All All All All All All All All All All All All All

Refers To: Diamond Gauge Diamond Gauge Diamond Gauge Diamond Gauge Diamond Heel Diamond Heel Full Diamond Full Diamond Cutting Structure Hydraulics Hydraulics Hydraulics Hydraulics Hydraulics Hydraulics Leg Protection Leg Protection Leg Protection Leg Protection Leg Protection Leg Protection Leg Protection

Description Trucut diamond with diamond-enhanced inserts (DEI on gauge; carbide on off-gauge) Shaped diamond-enhanced gauge inserts and 20% to 50% heel inserts Shaped diamond-enhanced gauge inserts and 51% to 100% heel inserts Semiround top (SRT) diamond-enhanced gauge inserts 20% to 50% diamond-enhanced heel row inserts 51% to 100% diamond-enhanced heel row inserts Diamond-enhanced cutting structure (nose, middle and gauge inserts) Diamond-enhanced cutting structure, (nose, middle and premium gauge inserts) Super-D Gun tungsten carbide insert cone-shell protection Q-Tube hydraulics V-Flo vectored-flow nozzle configuration Extended nozzle tubes Vectored extended nozzle tubes Dome jets (3 jets in the bit dome) Center jet Lug pads with tungsten carbide inserts Lug pads with diamond-enhanced inserts Upper legback semiround top (SRT) TCI cluster and PS feature Upper legback semiround top (SRT) DEI cluster and PD feature Semiround top (SRT) tungsten carbide leg protection Semiround top (SRT) diamond-enhanced leg protection Modified PS feature pattern; Note: West Texas bits only

53

Impax 10 Percussion Air Hammer, with diamond enhanced insert hammer bit

Percussion Hammers and Bits top sub 65⁄8-In API Reg PIn

Connects hammer to drillstring

CheCk valve Prevents backflow

Feed tube Compression rings Secure internal parts

Conveys air to hammer

Feed tube housing Retains feed tube

upper Chamber

snap ring

Pressurizes air to drive piston downwards

Seats feed tube housing

Choke Regulates consumed and surplus air

piston Drives bit into formation

lower Chamber Pressurizes air to drive piston upwards

snap ring Secures piston in hammer during a backoff

guide sleeve Functions as a timing device to control air venting in lower chamber

bit retainer ring Retains bit in off-bottom position

bit shank Receives piston’s striking energy and transmits it to the bit face

driver sub Synchronizes bit and drillstring rotation

retainer sleeve Retains bit head if a shank occurs

Impax is a mark of Schlumberger Copyright © 2012 Schlumberger. All rights reserved. 12-BT-0035

55

Hammers

Percussion Hammers Casing-While-Drilling Drillable Alloy Impax hammer unifies durability and performance for deep-hole drilling The Impax* hammer features a hardened-steel guide sleeve design that significantly optimizes energy transfer between the hammer’s piston and bit. The guide sleeve design also significantly improves deephole drilling reliability by eliminating the plastic blow tube: a component that often causes conventional hammers to fail when they are subjected to shock, vibration, abrasive wear, high temperature, erosion, and misting.

Floating Feed Tube

Impax Hammers also have an improved air delivery system that features a patented Floating Feed Tube (US Patent 7,950,475). The feed tube is designed to reduce wear and downtime issues related to wear on the piston and air delivery components. Because high-back pressure, circulation volume, and the water produced from misting and influx are major causes of hammer failure, the Impax hammer’s lower chamber has been designed to handle 10% to 20% more water than conventional hammers. When water incursion forces conventional hammers to be tripped out of the well, the Impax hammer’s combined capabilities enable it to endure deephole drilling conditions while delivering reliable performance. Impax hammers are available in 8-, 10-, and 12-in sizes.

Impax Dual Retention System

1

2

3

Impax bits offer a highly reliable, proven retention system that helps prevent the loss of the bit head in the hole and saves the cost of fishing or sidetracking. The system’s primary retention mechanism is a set of split retainer rings at the top of the bit (1). For conventional hammer bits, the split rings are the only means of attachment to the drillstring, and the possibility of losing the bit head is so great that the bits have built-in fishing threads to facilitate retrieval. The secondary catch system catches the bit head in the event that a shank (fracture in the spline area) prevents the primary retention rings from functioning. This is accomplished with a retainer sleeve (2) that is trapped between the shoulders of the driver sub and the hammer case. A rope thread is machined on the retainer ID and the bit OD (3) allowing ease of assembly/disassembly and the retention of the shanked head. During the trip out of the hole, right-hand rotation of the drillstring virtually eliminates any chance that the bit head will come out of the retainer.

www.slb.com/Impax 56

Hammer Bits

Impax Diamond-Enhanced Insert Hammer Bit Superior reliability, durability, and performance in hard formations. Gauge Plus ATG Feature (Patent 8,387,725)

Increased footage at lower cost

The Gauge Plus engineered hammer bit advantage is achieved by strategically positioning a staggered adjacent to gauge (ATG) row cutting structure to augment the work capabilities of the primary gauge inserts. This differs from a standard percussion bit that uses a non-staggered gauge row configuration to cut a specific but independent portion of the sidewall and hole bottom with no work overlap. The ATG row on a Gauge Plus bit assists in cutting a portion of the outer hole helping to reduce the load on the primary gauge row inserts. This innovative new design enhances drilling efficiency by enabling the two rows to work in unison on the hole bottom rather than acting independently.

Impax hammer bits have tough and durable DEIs that increase the footage drilled and lower the cost per foot. These bits eliminate the need for reaming, extending the life of the subsequent bit and providing a quality borehole for running casing. In addition, three exhaust ports improve bit-face cleaning for longer life and better ROP.

Secondary Air Course

When possible, a secondary air course is used to provide additional flow channels that enhance cuttings removal by providing greater flow area across the bottom of the hole. The efficient use of circulating air improves hole cleaning capabilities and reduces the regrinding of cuttings to maximize ROP.

Design Engineering

Gauge Plus is designed with a precise amount of bottom hole coverage overlap between the ATG and primary gauge rows. This overlapping of insert coverage greatly enhances fracture propagation and communication because the impact points are in close proximity. Combined, the innovative combination of ATG inserts precisely located in the cutting structure increases chip generation improving the rock failure mechanism.

The bit can be supplied with a concave bottom, which optimizes directional control.

The unique bottom hole fracture pattern uses energy more efficiently and subjects the cutting structure to less stress. This increases gauge integrity compared to a conventional hammer bit. The reduced exposure to competent formation significantly improves overall bit durability while enhancing ROP potential.

Impax nomenclature

H 15 12 D + Gauge Plus feature D – Diamond Enhanced Insert Number adjacent to Gauge Inserts Number of Gauge Inserts H – Hammer Bit Indicator

www.slb.com/Impax

9 7⁄8 H1209D+ V7RPD

57

Hammer Bits DIGR Hammer Bit

DIGR diamond in gauge row hammer bits

DIGR* hammer bits are the cost-effective choice for drilling applications that do not require cutting structures with 100% DEIs. They offer a full range of options for cutting structure layout, but use DEIs only in the gauge row and outer rows when required, providing excellent ROP and durability in less demanding formations. DIGR bits use the same retention system as Impax bits.

8 7⁄8 H1512G1 V6RPD

www.slb.com/Impax 58

Hammer Bits

Nomenclature and Optional Features

Impax Features Prefix C D F G M N PD R V X + 6 7 8

Impax Nomenclature and Features Size, in Type H0804 6, 61⁄8, 61/4, 63⁄8, 61/2, 63/4 H0806 H1006 H1008 H1209 77⁄8 H1206 83⁄8 H1209 H1209+ H1206 81/2, 85⁄8, 83/4, 87⁄8 H1209 H1509 H1512 H1209+ 91/2, 95⁄8, 93/4, 97⁄8, 105⁄8, 11 H1209 H1509 H1209+ H1209 121/4, 123⁄8, 127⁄16 H1509 H1512 H1411+ 141/2, 143/4, 15 H1812 H1812+ 171/2 H1809

Description Carbide insert Diamond enhanced insert (DEI) Flat profile Diamond on gauge Modified profile Nonretainable DEI gauge protection Retainable Concave profile Convex profile Gauge Plus 6 ⁄8-in [3/4-in, 18-mm] diameter gauge insert 7 ⁄8-in [22-mm] diameter gauge insert 8 ⁄8-in [1-in] diameter gauge insert

Available Features D, G, C, X, 6, R, PD D, G, C, X, 6, R, PD D, G, C, V, X, 6, R, PD D, G, C, X, 6, R, PD D, G, C, V, 7, R, PD D, G, C, V, 7, R, PD D, G, C, V, 7, R, PD D, G, V, 6, R, PD D, G, C, V, 7, R, PD D, G, C, V, 7, R, PD D, G, C, V, 6, R, PD D, G, C, V, 6, R, PD D, G, V, 6, R, PD D, G, C, V, 7, R, PD D, G, C, V, 7, R, PD D, G, V, 7, R, PD D, G, C, V, 7, R, PD D, G, C, V, 7, R, PD D, G, C, V, 7, 8, R, PD D, G, V, 7, R, PD D, G, C, V, 7, R, PD D, G, V, 7, R, PD D, G, C, V, 7, R, PD

Custom sizes and types available.

8 7⁄8 -in H1512D V6RPD R08

59

www.slb.com/Impax

Hammer Bits

Nomenclature and Optional Features Gauge and Face Inserts

Bit Head Retention

D Feature—Diamond-Enhanced Insert (DEI) Feature: All DEI cutting structure Advantage: Exceptional durability and abrasion resistance Benefit: Excellent drilling performance in longer intervals through hard formations

N Feature—Nonretainable Feature: No retaining feature on the bit head (standard fishing threads) Advantage: Compatibility with third party hammers that have no bit retention features Benefit: Flexibility to use the bit in various BHA assemblies such as those used for water wells, construction, etc.

G Feature—Diamond (DEI) in Gauge Row Feature: A cutting structure with carbide face inserts and DEI gauge inserts Advantage: Exceptional gauge durability and abrasion resistance Benefit: Excellent bit gauge life when drilling shorter, mediumsoft formation intervals C Feature—Carbide Insert Feature: All carbide cutting structure Advantage: Excellent durability and abrasion resistance Benefit: Superior and cost-effective drilling performance in soft to medium-soft formations

R Feature—Retainable Feature: Patented bit head retention system Advantage: Prevents loss of the bit head in the hole Benefit: Saves the cost of sidetracking or fishing

Gauge Reinforcement PD Feature—Optional Gauge Protection Feature: All diamond gauge reinforcement Advantage: Significantly extends the life of the bit gauge Benefit: Prevents the drilling of an undergauge hole and eliminates the need for reaming (the practice of reducing the hole size after pulling out a nonPD hammer bit), increasing the life of the subsequent bit and providing a quality hole for running casing

Gauge Insert Size 6 Feature—6⁄8-in [18 mm] Diameter 6 Feature: ⁄8 -in diameter DEI gauge cutting structure Advantage: Enables use of heavy-set diamond gauge cutting structures Benefit: Eliminates the need for reaming, increasing the life of the subsequent bit and providing a quality hole for running casing

+ Feature—Gauge Plus ATG Feature Feature: Optimum placement of gauge and adjacent to gauge insert Advantage: Provides the maximum durability of the gauge row inserts and optimizes overall bit longevity Benefit: Increased footage and reduced risk of hole problems where long sections and hard formations are encountered

7 Feature—7⁄8-in [22 mm] Diameter 7 Feature: ⁄8 -in diameter DEI gauge cutting structure Advantage: Enables use of diamond gauge cutting structures with improved impact-damage resistance Benefit: Eliminates the need for reaming, increasing the life of the subsequent bit and providing a quality hole for running casing 8 Feature—1-in [25 mm] Diameter Feature: 1-in diameter DEI gauge cutting structure Advantage: Allows use of diamond gauge cutting structures with improved impact-damage resistance Benefit: Provides an insert with the maximum amout of insert strength, resulting in the best posible insert where durability is a requirement

www.slb.com/Impax 60

Hammer Bits

Nomenclature and Optional Features Bit Profile Shapes F Feature—Flat Feature: Flat bottom with a single gauge-angle bit head profile Advantage: Enables use of heavier-set cutting structures on the bit face Benefit: Excellent drilling performance in hard formation intervals M Feature—Modified Feature: Nonstandard bit head profile Advantage: Unique geometry incorporated for specific operating parameters Benefit: Enhanced performance for special drilling applications V Feature—Concave Feature: Concave bottom with a dual gauge-angle bit head profile Advantage: Additional drilling stability and directional control Benefit: Excellent drilling performance in medium-soft to medium formation intervals where hole deviation is a primary concern X Feature—Convex Feature: Flat bottom with a dual gauge-angle bit head profile Advantage: Enables use of heavy-set face and gauge cutting structures Benefit: Excellent drilling performance in medium to medium-hard formation intervals

www.slb.com/Impax 61

62

Specialty Applications

63

Specialty Applications PDC Hole Openers ■■

Staged Hole Openers

Quad-D* Dual-Diameter Drift and Drill Bi-center ■■

Quad-D Reamer*

■■

Quad-D Bits*

Direct XCD casing-while-drilling bit

64

Specialty Applications Concentric Staged Hole Openers (SHO)

Concentric Staged Hole Openers (SHO) from Smith Bits have been developed from a tradition of application know­ledge and technical excellence gained from the success of Quad-D* dualdiameter drift and drill, reaming products. Superior borehole quality and high ROP

The staged hole opener (SHO) incorporates precision-engineered cutting structures to ensure fast, smoothly drilled, high-quality, concentric hole opening under a wide range of application conditions. SHO tools are run successfully on rotary and rotary steerable assemblies in both straight and deviated holes.While the overall cutting structure is balanced, it is divided into four sections, each serving a specific purpose.

Stage three—SHO pilot conditioning section (PCS) ■■

Stage One—Pilot Bit ■■

The pilot bit, either fixed cutter or roller cone, drills the initial hole diameter. A bull nose can also be used to follow a predrilled pilot hole. SHO assemblies can be used with multiple pilot configurations for specific applications, and can be positioned for various drillstring configurations.

Stage four—SHO reaming section ■■

Stage two—SHO pilot section ■■

The cutting structure is designed to minimize work rates on each cutter position for maximum durability. By stress-relieving the formation with this intermediate stage, larger-hole drilling can be done at a more aggressive ROP. The third stage recentralizes the SHO on the given well trajectory in both vertical and directional applications. Gauge pads and gauge trimmers provide the main stabilization for the SHO. Gauge pad lengths in the section may vary depending on whether the application calls for a near-bit or drillstring placement.

The pilot section consists of one or two rows of cutting structures to recondition the pilot hole and remove any swelling clays or moving halites. Gauge pads provide initial stabilization as the SHO begins the staged reaming process to reduce stick/slip, whirling, or off-center tendencies.

This cutting structure completes the final hole diameter. With the formation already stress-relieved, the reaming section remains aggressive even in more competent formations. Gauge trimmers and spiraled gauge pads ensure good hole quality. Gauge pads in this section are kept short in length for directional responsiveness.

Staged Hole Openers nomenclature

SHO S i 6 16 Cutter Size Blade Count IDEAS Designed SHARC Feature SHO – Staged Hole Opener

www.slb.com/SHO 65

Type SHO719 SHOS516 SHO516 SHOSI616 SHO519 SHOSI616 SHOSI519 SHO716 SHO519 SHO519 SHOI616 SHO519 SHO516 SHO519 SHOSI616 SHO516 SHOI616 SHOS516 SHOS516

Size, in 26 24 24 22 171/2 171/2 17 16 16 143/4 141/2 14 131/2 121/4 121/4 105⁄8 97⁄8 81/2 71/2

Pilot, in 22 20 20 191/2 121/4 121/4 121/4 121/4 121/4 121/4 105⁄8 11 81/2 81/2 81/2 81/2 81/2 61⁄8 61⁄8

Specialty Applications Quad-D Reamer

The versatility of Quad-D* dual-diamter drift and drill products is best demon­ strated by the range of applications that they drill. The GeoReam* dual-diameter near-bit reamer, is well suited to be run directly above the pilot bit for directional applications and it is the recommended alternative to the Quad-D bit in appli­cations in which a PDC cutting structure is not the best option for the pilot bit. Although compact in length, the stability-enhancing technology used in the GeoReam ensures optimal hole quality while drilling. With longer pilot conditioning sections and drill string connections, Quad-D Reamers are designed to maximize performance in rotary applications. The longer pilot conditioning section acts like a string stabilizer to ensure centralization and stabili­zation. This tool is designed to be run with various BHA configurations, including rotary steerable systems.

Type QDGS7419 QDG5216 QDG5216 QDG5216 QDG5216 QDG7313 QDG7313 QDG5313 QDG5313 QDG5316 QDG5216 QDG5313 QDG5216 QDG5313 QDG5316 QDG5209

Size, in 32 22 20 20 17½ 17 16 14¾ 13½ 13¼ 12¼ 12¼ 97⁄8 8½ 7 6½

Pilot, in 28 181⁄8 16 17 14½ 137⁄8 13½ 12¼ 12¼ 12¼ 105⁄8 105⁄8 8½ 7½ 6 57⁄8

Type DRS5216 QDR5319 QDRS5313 QDR5313 QDR5316 QDR5313 QDR5213 QDR5316 QDR5313 QDR5313 QDR5313 QDRS6313

Size, in 20 19 17½ 17 16 14¾ 14½ 13¼ 12¼ 10¾ 97⁄8 71⁄8

Pilot, in 16½ 16½ 14½ 14½ 14¾ 12¼ 12¼ 12¼ 105⁄8 9½ 8½ 65⁄8

Fishing Neck

Advantages ■■

Directional & BHA flexibility for precise control of wellbore

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Drill-out capability for eliminating trips

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Diameter control for full gauge wellbore

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Formation-specific design for optimized drilling efficiency

The QDR has drill collar connections for string placement

Quad-D nomenclature

QD G 5 3 16 Cutter Size Reamer Blades to Full Diameter Pilot Blade Count

8½ in × 9 7⁄8 in QDG5216

G/R – GeoReam or Reamer Product QD – Quad-D Technology

Tong Neck

8½ in × 97⁄8 in QDR5313

www.slb.com/Quad-D 66

Specialty Applications Quad-D Bi-Center Bits

Quad-D dual-diameter drift and drill bi-center bits provide hole opening through installed casing or liner sections. This family of aggressive matrix and steel body bits is designed to provide durability, reduce torque response, maintain tangents, and reduce sliding time without compromising efficiency when drilling either float equipment or formation. It features a strong, one-piece construction and a very low overall height that enhances directional capabilities when drilling with downhole motors.

Advantages ■■ ■■

■■ ■■

Drill-out capability for eliminating trips Directional responsiveness for precise control of wellbore Diameter control for full gauge wellbore Formation-specific design for optimized drilling efficiency

Vibration is controlled by force and mass balancing, employment of spiral blades and gauge, asymmetrical blade layout, and use of Lo-Vibe* inserts. Because of the resulting bit vibration control, bit rotation is maintained about the true bit axis ensuring accurate finished hole diameter and quality. Hydraulic ports are positioned to provide efficient cuttings removal and cleaning of both the pilot and reaming sections. A unique gauge profile prevents cutters from contacting and damaging the casing and also provides a high degree of stabilization and gauge protection. Quad-D* dual-diamter drift and drill bi-center bits have achieved success in a broad range of applications.

14¾-in Hole Maintained

Pilot gauge section

Quad-D nomenclature 12¼ in × 14¾ in QDS7213

QD S 7 3 13 Cutter Size Reamer Blades to Full Diameter Pilot Blade Count M/S – Matrix or Steel QD – Quad-D Technology

www.slb.com/Quad-D

Type QDM3209 QDM3309 QDM4209 QDM4213 QDM7309 QDM7313 QDMS4209 QDS3209 QDS4209 QDS5209 QDS5213 QDS5216 QDS5219 QDS6309 QDS7213 QDS7309 QDS7313

16½ in × 20 in QDS7313PX

67

Size Availability, in 3¾ × 41⁄8 57⁄8 × 6½ 3¾ × 41⁄8 6×7 6×7 8½ × 97⁄8, 105⁄8 × 12¼ 3¾ × 41⁄8 4¾ × 55⁄8, 4½ × 5¾ 4¾ × 55⁄8, 6 × 7 7 × 83⁄8 8½ × 97⁄8, 12¼ × 14¾, 14½ × 17½ 8½ × 97⁄8, 14½ × 17½ 17 × 20 6½ × 7½, 8½ × 97⁄8 12¼ × 14¼ 6×7 7½ × 8½, 8½ × 97⁄8, 9½ × 11, 105⁄8 × 12¼, 16½ × 20

Specialty Applications

Direct XCD Casing-While-Drilling Drillable Alloy Bit Drillable PDC bit for casing-while-drilling applications drills to TD, enabling cementing casing in place and bit drillout The nonretrievable Direct XCD* drillable alloy bit is specially suited for vertical or tangential well applications. The bit drills with standard casing, which is turned at the surface by the rig’s top drive. The Direct XCD bit’s cutting structure can be fitted with 13 to 19 mm PDC cutters and are availble in optional premium grades. The bit’s sub is composed of durable oilfield grade steel, and its body is made of an alloy that allows efficient drill out by any PDC bit after the Direct XCD bit drills to TD and casing is cemented in place. After drillout, the drillout bit can continue drilling the next interval, enabling production casing to be run below the shoe. Available bit sizes Application Soft Formations < 8,000 psi unconfined compressive strength (UCS)

XCD319 XCD413 XCD416

95⁄8 × 121/4

XCD419

95⁄8 × 121/4

Medium Formations 8,000–14,000 psi UCS

XCD316 XCD416

95⁄8 × 121/4

XCD419

95⁄8 × 121/4

Bit

XCD516 XCD519 XCD616 Hard Formations > 14,000 psi UCS

Casing Size, in × Bit Size, in 133⁄8  × 171/2 103/4 × 131/2 133⁄8  × 171/2

185⁄8  × 23

123/4 × 151/2

7 × 81/2

XCD516

133⁄8  × 171/2 103/4  × 131/2 16 × 181/4 133⁄8  × 16

95⁄8  × 115⁄8

XCD613

95⁄8 × 121/4 95⁄8 × 121/4

Direct XCD bit nomenclature

9 5⁄8 × 121/4 XCD 5 16 Cutter size Blade count XCD – Direct XCD drillable alloy bit Bit size Casing size

www.slb.com/DirectXCD

9 5⁄8 -in × 121/4-in XCD613

68

133⁄8 × 171/2

20 × 23

20 × 24

Specialty Applications

Direct XCD Casing-While-Drilling Drillable Alloy Bit

Exclusive PDC cutting structure

Proprietary nozzles

Cutting structure design comprises premium grade PDC cutters on each blade, which can be sized from 13 to 19 mm.

Flow rate and hydraulic force are directed by nozzles for maximum ROP.

Patent pending bit body design

Large-face waterways

Bit body composition allows drill out by any PDC bit.

Cuttings removal is maximized with large face waterways and junk slot areas.

Bi-metal composition A drillable alloy body includes a bit sub made of oilfield grade steel.

Spiral gauge pads

Erosion resistant coating

Spiral gauge pads maximize bit stability and reduce vibration.

Direct XCD Features Face Features P S O Hydraulic Features H L E Connection Features B WP BTC C

An optional tungsten carbide coasting applied to bit body and blades increases durability.

Description Premium cutters Standard cutters Optimized drillout path Higher number of nozzles than standard Lower number of nozzles than standard Errosion resistant nozzles Blank thread form Weld Prep API buttress connection Premium threaded per request

www.slb.com/DirectXCD 69

Reference Tools

71

Reference Total flow area chart

Total Flow Area (TFA) of Standard Nozzles, in2 Nozzle Number of Nozzles Size, in 1 2 3 7 ⁄32 0.038 0.075 0.113 8 ⁄32 0.049 0.098 0.147 9 ⁄32 0.062 0.124 0.186 10 ⁄32 0.077 0.153 0.230 11 ⁄32 0.093 0.186 0.278 12 ⁄32 0.110 0.221 0.331 13 ⁄32 0.130 0.259 0.389 14 ⁄32 0.150 0.301 0.451 15 ⁄32 0.173 0.345 0.518 16 ⁄32 0.196 0.393 0.589 17 ⁄32 0.222 0.443 0.665 18 ⁄32 0.249 0.497 0.746 19 ⁄32 0.277 0.554 0.831 20 ⁄32 0.307 0.614 0.920 21 ⁄32 0.338 0.676 1.015 22 ⁄32 0.371 0.742 1.114 23 ⁄32 0.406 0.811 1.217 24 ⁄32 0.442 0.884 1.325 25 ⁄32 0.479 0.959 1.438 26 ⁄32 0.518 1.037 1.555 27 ⁄32 0.559 1.118 1.677 28 ⁄32 0.601 1.203 1.804 29 ⁄32 0.645 1.290 1.935 30 ⁄32 0.690 1.381 2.071 31 ⁄32 0.737 1.474 2.211 32 ⁄32 0.785 1.571 2.356

4 0.150 0.196 0.249 0.307 0.371 0.442 0.518 0.601 0.690 0.785 0.887 0.994 1.108 1.227 1.353 1.485 1.623 1.767 1.917 2.074 2.237 2.405 2.580 2.761 2.948 3.142

5 0.188 0.245 0.311 0.383 0.464 0.552 0.648 0.752 0.863 0.982 1.108 1.243 1.384 1.534 1.691 1.856 2.029 2.209 2.397 2.592 2.796 3.007 3.225 3.451 3.685 3.927

72

6 0.225 0.295 0.373 0.460 0.557 0.663 0.778 0.902 1.035 1.178 1.330 1.491 1.661 1.841 2.029 2.227 2.434 2.651 2.876 3.111 3.355 3.608 3.870

7 0.263 0.344 0.435 0.537 0.650 0.773 0.907 1.052 1.208 1.374 1.552 1.740 1.938 2.148 2.368 2.599 2.840 3.093 3.356 3.629 3.914

8 0.301 0.393 0.497 0.614 0.742 0.884 1.037 1.203 1.381 1.571 1.773 1.988 2.215 2.454 2.706 2.970 3.246 3.534 3.835

9 0.338 0.442 0.559 0.690 0.835 0.994 1.167 1.353 1.553 1.767 1.995 2.237 2.492 2.761 3.044 3.341 3.652 3.976

Reference

Recommended fixed cutter bit makeup torque Recommended Makeup Torque—Diamond and Fixed Cutter Drill Bits With Pin Connections API Reg Connection Size, in Bit Sub OD, in Minimum, ft.lbf 3 1,970 23⁄8 2,660 31⁄8 31/4 3,400 31/2 3,380 27⁄8 33/4 and larger 5,080 5,700 41⁄8 41/4 6,940 31/2 41/2 and larger 8,400 51/2 13,700 41/2 53/4 18,100 41/2 and larger 18,550 71/2 40,670 65⁄8 73/4 and larger 41,050 81/2 53,100 83/4 63,500 75⁄8 9 and larger 68,600 10 96,170 85⁄8 101/4 and larger 107,580

Normal, ft.lbf 2,280 3,100 3,950 3,950 5,900 6,600 8,050 9,850 16,600 21,100 21,600 47,300 47,800 61,850 73,750 79,800 102,600 114,700

Notes: 1. Recommended make-up torque dictated by all BHA components 2. Higher makeup torque values within the above ranges are recommended when high WOB is used. 3. Box connection bits should use makeup torque values between Minimum and Normal. 4. All connections must be lubricated with a joint compound meeting API requirements.

Recommended roller cone bit makeup torque Size Range in, [mm] 31/2–41/2 [89–114] [118–127] 45⁄8–5 [137–187] 51⁄8–73⁄8 71/2–9 [194–229] [241–711]† 91/2–28† 143/4–28† [375–711]† 181/2–28† [470–711]†

API Pin Size in, [mm] 23⁄8 Reg 27⁄8 Reg 31/2 Reg 41/2 Reg 65⁄8 Reg 65⁄8 Reg or 75⁄8 Reg 75⁄8 Reg or 85⁄8 Reg

Recommended Torque ft.lbf, [N.m] 3,000–3,500 [4,000–4,800] 4,500–5,500 [6,000–7,500] 7,000–9,000 [9,500–12,000] 12,000–16,000 [16,000–22,000] 28,000–32,000 [38,000–43,000] 34,000–40,000 [46,000–54,000] 40,000–60,000 [54,000–81,000]

[60] [73] [89] [114] [168] [168 or 194] [194 or 219]

 Makeup torque must correspond to API pin connection for each bit size.

†

Note: Some of the above bit sizes are available on special order with alternate pin connections.

API gauge tolerances for fixed cutter and roller cone bits Bit size, in 63/4 and smaller 625⁄32–9 91⁄32–133/4 1325⁄32–171/2 1717⁄32 and larger

Fixed Cutter, in -0.015–+0.00 -0.020–+0.00 -0.030–+0.00 -0.045–+0.00 -0.063–+0.00

Roller Cone, in -0.0–+1/32 -0.0–+1/32 -0.0–+1/32 -0.0–+1/16 -0.0–+3/32

73

Maximum, ft.lbf 2,450 3,300 4,200 4,200 6,300 7,000 8,550 10,500 17,000 22,400 22,900 50,200 50,750 65,670 78,300 84,750 108,950 121,800

Reference

Field operating procedures for fixed cutter and roller cone drill bits BIT PREPARATION

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Bit Handling at rig site

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■■

Bit cutting elements with diamond both fixed cutter and roller cone bits, are brittle and susceptible to impact damage. Care should be taken when handling or removing any bit containing diamond-cutting elements.

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Engage the hanging box connection to the doped threads of the bit pin. Proper makeup for small diameter bits is to makeup by hand for several turns, then place in the bit breaker and makeup to the recommended torque. Uncover the rotary and locate the bit and breaker onto the breaker holder.

■■

Do not drop the bit even if it is in the container.

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Use a piece of wood or rubber under the bit face.

Makeup applying the recommended torque.

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■■

Makeup torque specifications are from API spec RP7G.

Bit Inspection ■■

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Roller Cone Bits

Inspect bit for integrity (cutting elements, pin connection and makeup shoulder).

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Ensure there are no foreign objects or obstructions in the internal fluid passageways.

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Verify TFA on bits with fixed TFA.

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Record bit size, type and serial number.

TRIPPING IN THE HOLE ■■

Nozzle Installation ■■ ■■

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■■ ■■

■■

Ensure that nozzle series are correct for bit type. Gauge the orifice size of every nozzle to ensure proper total flow area (TFA).

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Remove the plastic plug and ensure that O-rings are properly installed and seated. If different size nozzles are to be used ensure that the correct sized nozzles are in the correct place. Put bigger size nozzles in the in the center of the bit.

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Ensure that the threads are clean and greased (any petroleumbased grease). Fixed cutter bits with matrix threads should not be greased.

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Grease the nozzle body below the threads to prevent O-ring damage. Screw the nozzle in by hand until snug. Use nozzle wrench for final tightening. Excessive force is not necessary and can damage the carbide nozzle.

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Makeup

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Identify potential problem areas before tripping. Trip slowly through BOP, doglegs, tight spots, ledges, casing shoes, cementing equipment, etc. Wash and or ream as necessary. Severe problems may require a special ‘cleanup’ run. Roller cone bit legs will yield slightly and the bit can be rotated slightly in order to pass through some tight spots. Fixed cutter bits do not yield. Bits with PDC cutting elements are susceptible to impact damage. PDC bits are more susceptible to damage during tripping in the hole than roller cone bits. Certain types of fixed cutter bits with low junk slot area can create higher surge and swab pressures than roller cone bits due to more restrictive annular space. Local knowledge/practice will typically dictate wash down and reaming procedures. Minimum recommendation is to wash down at least the last joint to bottom at reaming speed with full circulation. Preference is to ream the last stand/90 feet at reaming speed with full circulation.

TAGGING BOTTOM

If nozzle sizes below 9⁄32 are to be used, recommend the use of drill pipe screens and/or a float to prevent reverse circulation plugging. Use grasshoppers if necessary.

■■

Keep BHA as vertical as possible when making up bit to ensure no damaging contact between the nozzles (full-extended or mini’s) and the bit breaker occurs.

Ensure that the appropriate bit breaker is with the bit. Inspect to insure good condition and that it fits properly. Remove the bit from the box and place face down on a piece of wood or rubber.

■■

Engage the bit breaker with the bit and move them onto the rotary table. A float above the bit should be installed, especially on extended nozzle roller cone bits, in areas that tend to plug.

■■

74

Approach the hole bottom cautiously, monitoring WOB and torque. An increase in WOB or torque will indicate either contact with the hole bottom or fill. Fixed cutter bits will typically show an increase in torque first. Bit is on bottom when torque increases with the WOB. Difference between measured depth and contact point should be depth of fill. If fill is present, pick up above the fill and rotate to bottom with full circulation until bottomhole contact is assured. Regardless if fill is present, the pipe should always be reciprocated off-bottom. On rotary assemblies, use a maximum of 500 lbf per inch of bit diameter, 40 to 60 rpm.

Reference

Field operating procedures for fixed cutter and roller cone drill bits ■■

■■ ■■

On motor assemblies, use a maximum of 500 lbf per inch of bit diameter and the minimum allowable rpm.

will dictate flow rate as a compromise is needed between providing adequate cleaning and minimum rpm.

Do not use high WOB when in fill. This could cause the bit to ball.

■■

Circulate and rotate off-bottom (as close as possible preferably less than 6 in, no more than 1 ft) enough (5 to 15 minutes, application dependent, recommend 15 min as minimum) to ensure the hole bottom is clear of fill or junk.

Drilling cement plugs, float equipment and casing shoes ■■

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■■

■■

Bouncing or erratic torque may indicate locked cones. Temporarily increase the weight to ensure cone rotation, then reciprocate the bit slightly off-bottom while continuing circulation and rotation to help clean the bit. Resume with original parameters when the bouncing or erratic torque has been eliminated. Maintain minimum WOB/torque to prevent wiper plugs from rotating. Erratic torque may indicate a rotating plug.

Rotating Plugs

When using fixed cutter bits to drill out, ensure that all cementing equipment (plugs, float collars and shoes) is PDC drillable (non-metallic, rubber, nylon, plastic or cement).

■■ ■■

Recommend the use of non-rotating plugs. Alternatively, it is preferable when cementing to pump some cement on top of the plug to help prevent it from rotating during drill out. Using the maximum allowable flow rate to assist cleaning is preferred, but may not be possible with motor assemblies.

Should a plug begin to rotate, set down on plug with no rpm Increase WOB until 2,000 to 3,000 lbf per inch of bit diameter is reached or alternatively an increase of 300 psi over the normal standpipe occurs.

■■

Then begin rotation, ending with 40 to 60 rpm.

■■

Repeat until penetration is achieved and wiper plug is drilled.

Alternative procedure (last resort)

Procedure

■■

Rotate bit at 20 to 40 rpm.

■■

■■

Use 500 lbf per inch of bit diameter.

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■■

■■

Frequently raising and lowering the bit while continuing circulation and rotation will help keep the bit clear of debris. Flushing after every 1 to 2 in drilled while reciprocating 3 to 4 ft will ensure debris is removed and new material is being drilled. Should the penetration rate decrease suddenly, repeat this step until it resumes.

■■

ESTABLISHMENT OF Bottomhole PATTERN

Do not spud. Spudding (impacting on the hole-bottom) can damage cutting structure elements on both fixed cutter and roller cone bits. It can also damage the roller cone bearing/ seal system.

Bottomhole pattern break-in is considered to be when a new bit achieves uniform cutting structure loading. Proper break-in is critical to durability and ROP.

Monitor pump pressure to ensure nozzles do not become plugged.

■■

Change rpm if bouncing or erratic torque is encountered.

Fixed Cutter Bits ■■

■■

■■

On rotary, use the maximum flow rate with less than 6,000 lbf WOB and 60-100 rpm.

■■

On motor assemblies, drill with less than 6000 lbf WOB and the minimum allowable rotary rpm. Local practice will dictate flow rate as a compromise is needed between providing adequate cleaning and minimum rpm.

■■

Maintain low and consistent torque. ■■

Roller Cone Bits ■■

■■

Alternate using no flow rate for 1 minute to full flow for 30 seconds.

On rotary, drill with 2,000 to 3,000 lbf per inch of bit diameter and 40 to 60 rpm.

After drilling out the casing shoe, establish the bottomhole pattern. There may be some BHA dictated WOB and rpm guidelines until the BHA is below the casing shoe. Optimization of WOB and rpm may have to wait until the BHA or some portion of the BHA has cleared the casing shoe. Use extra care establishing a new bottomhole pattern when following a bit with a substantially different bottomhole profile, e.g., a PDC bit following a roller cone bit or vice-versa. Roller cone bits typically drill a larger size hole than a fixed cutter bit. Be sure to properly establish the bottomhole pattern when following a roller cone bit in order to insure stability. Establishment of bottomhole pattern can be dependent upon factors such as bit design, BHA, etc.

Roller Cone Bits ■■

On motor assemblies, drill with 2,000 to 3,000 lbf per inch of bit diameter and the minimum allowable rotary rpm. Local practice

75

Break-in is done with light WOB and slow rpm and a new bottomhole pattern is normally achieved within 3 to 6 in (assuming no tracking or off-center rotation).

Reference

Field operating procedures for fixed cutter and roller cone drill bits ■■

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■■

Formation Changes

On rotary, use a maximum of 500 lbf per inch of bit diameter with 40 to 60 rpm.

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On motor assemblies, use a maximum of 500 lbf per inch of bit diameter and the minimum allowable rpm—keep rotary rpm to a minimum 20 to 30 rpm. Minimum allowable motor rpm can be formation dependent.

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Soft, balling formations should be entered with full flow rate. At that point, WOB and rpm can be gradually increased to typically operating levels or to initial drill-off test levels. Increase WOB first then rpm.

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Fixed Cutter Bits ■■

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Although a new bottomhole pattern is created in less than a bit diameter, it is preferred to drill 3 to 5 feet before increasing WOB and rpm. ■■

Maintain low and consistent torque changing operating parameters as needed. Take extreme care following a coring operation or bits of different types or profiles. A different existing profile can overload specific cutting elements potentially causing a premature failure

■■

If in or encountering a known hard or abrasive formation of short length with a dull bit, controlled drilling (sacrificing ROP) through the interval may enhance the following bit’s performance. The dull condition and bit type will determine the feasibility. Monitor the ROP and torque, follow the recommendations for evaluating ROP and torque as listed below. Proceed only if ROP and increased risk is acceptable to the customer.

■■

Optimum WOB and rpm determined are for a particular application and can only be continuously used in a homogeneous formation. Therefore in intervals of various formations, ROP optimization tests will not produce the optimum weight and rotary combination. Drill off tests will be necessary anytime the formation changes. Typically a range of WOB and rpm combinations is derived for the interval, e.g., interbedded formations.

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When economics dictates.

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When ROP dictates.

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Loss of directional characteristics

■■

Loss of pump pressure due to a washout.

Roller Cone Bit ■■

Deviation & Directional Control

■■

If an unknown formation (anomaly/transition) is expected, reduce the rpm and the WOB to a minimum accepted level. Establish ROP and torque baselines at these levels. Monitor ROP and torque to determine when formation has been encountered and when through the anomaly.

PULLING THE BIT

Controlled Drilling

■■

When anticipating a harder/more difficult formation, to prevent impact damage, reduce the rpm maintaining WOB while still in the softer formation to help prevent initiation of lateral or torsional vibrations when the hard formation is encountered. After the formation is encountered, adjust the parameters or perform a drill-off test.

Operational Parameter Guidelines

For starting parameters, use maximum flow rate, less than 6,000 lbf WOB and 60 to 100 rpm.

RUNNING THE BIT ■■

Formation changes can instigate both torsional and lateral vibrations. Monitor and adjust accordingly.

■■

Deviation concerns may override optimum WOB used. Typically minimum WOB is used to control deviation on rotary assemblies.

■■

Monitor deviation on straight holes. Reduce WOB to maximum allowable to maintain deviation specified by customer. Monitor for vibration. Generally, increase rpm to improve ROP. Higher torque and higher speed changes bit walk direction by making the bit attack the formation at different angle due to higher torque. The bit tries to climb the hole wall at a different position at different torque levels. High speed on turbines can make the bit change direction completely.

76

When a substantial increase or dramatic fluctuation in torque is seen with low or high WOB and low ROP or when tagging bottom. Magnitude is typically area and application dependent. There is no 100% effective/reliable indicator. The best indicator is dramatic fluctuations of torque when tagging bottom.

Reference

Measurement units and drilling formulas Standard Measurement Units Quantity/Property Depth Weight on bit (WOB) Nozzle size Drill rate Volume

Units ft lbf

Annular velocity and slip velocity Linear length and diameter Pressure

32 nds in ft/hr barrels galUS/stroke galUS/min bbl/stroke bbl/min ft/min in psi

Mud density Mud gradient Funnel viscosity Apparent and plastic viscosity yield point Gel strength and stress Cake thickness Filter loss Torque

lbm/galUS psi/ft s/qt (US) centipoise lbf/100ft 2 32 nds in mm or cc ft.lbf

Pump output and flow rate

Multiply By 0.3048 0.445 4.535 × 10 -4 0.794 0.3048 0.1590 3.785 × 10 -3 3.875 × 10 -3 an oil barrel is 0.159873 × m3 exactly 0.1590 0.3048 25.4 6.895 0.006895 0.06895 119.83 22.621 1.057 1 0.4788 (0.5 for field use) 0.794 1 1.3358

To Obtain meters decanewton tonne millimeters meters/hour cubic meters cubic meters/stroke cubic meters/minute cubic meters/stroke cubic meters/minute meters/minute millimeters kilopascals megapascals bar kilograms/cubic meter kilopascals/meter seconds/liters millipascal seconds pascals millimeters cubic centimeters newton meters

Symbol m daN tonne mm m/hr m3 m3/stroke m3/min m3/stroke m3/min m/min mm kPa MPa bar kg/m3 kPa/m s/l mPa.s Pa mm cm3 N.m

Drilling Formulas Flow Rate (Q) Bit Pres. Drop (∆Pbit) Hydraulic Horsepower (HHPbit) HSI Jet Velocity (JV) Impact Force (IF)

Cost per Foot (CPF) Bit Cost + Rig Cost (Trip Time + Drilling Time) CPF = Footage Drilled Pressure Drop (∆D) Flow Rate2 × Mud Weight ∆P = 10,856 × TFA2

= (Pump Stks × Output / stk) = (MWt. × Q 2) / (10858 × TFA2) = (∆Pbit × Q) / (1714) = (HHPbit) / (.7854 × D2) = (.32086 × Q) / (TFA) = (JV) × (MWt) × (Q) × (.000516)

MWt = Mud Weight TFA = Nozzle Flow Area D = Bit Diameter

Hydraulic Horsepower (HHP) (Bit Pressure Drop) (Flow Rate) HHP = 1,714 Hole Area (Ah) π × Hole Diameter2 Ah = 4 Hydraulic HP per Square Inch (HSI) Hydraulic Horsepower HSI = Hole Area, in2

77

Reference

Drill collar specifications Drill Collar Weight (Steel), lbm/ft Drill Collar Drill Collar ID, in OD, in 1 11⁄4 7 19 18 2 ⁄8 3 21 20 22 22 31⁄8 26 24 31⁄4 30 29 31⁄2 35 33 33⁄4 4 40 39 43 41 41⁄8 46 44 41⁄4 51 50 41⁄2 43⁄4 5 51⁄4 51⁄2 53⁄4 6 61⁄4 61⁄2 63⁄4 7 71⁄4 71⁄2 73⁄4 8 81⁄4 81⁄2 9 91⁄2 93⁄4 10 11 12

11⁄2 16 18 20 22 27 32 37 39 42 48 54 61 68 75 82 90 98 107 116 125 134 144 154 165 176 187 210 234 248 261 317 379

13⁄4

2

21⁄4

21⁄2

23⁄4

3

31⁄4

31⁄2

33⁄4

4

35 37 40 46 52 59 65 73 80 88 96 105 114 123 132 142 152 163 174 185 208 232 245 259 315 377

32 35 38 43 50 56 63 70 78 85 94 102 111 120 130 139 150 160 171 182 206 230 243 257 313 374

29 32 35 41 47 53 60 67 75 83 91 99 108 117 127 137 147 157 168 179 203 227 240 254 310 371

44 50 57 64 72 79 88 96 105 114 124 133 144 154 165 176 200 224 237 251 307 368

60 67 75 83 91 100 110 119 129 139 150 160 172 195 220 232 246 302 364

64 72 80 89 98 107 116 126 136 147 158 169 192 216 229 243 299 361

60 68 76 85 93 103 112 122 132 143 154 165 188 212 225 239 295 357

72 80 89 98 108 117 128 138 149 160 184 209 221 235 291 352

93 103 113 113 133 144 155 179 206 216 230 286 347

84 93 102 112 122 133 150 174 198 211 225 281 342

78

Reference

English and Metric Multiply By Grains 64.79891 Grains 0.03527 Inches 0.08333 Inches 25.4 Inches of water 0.03613 Kilometers 3,281 Kilometers 0.6214 Kilometers per hour 0.6214 Knots 6,080 Knots 1.152 Knots per hour 1.152 Liters 0.03531 Liters 0.2642 Meters 3.281 Meters 39.37 Meters 1.094 Miles 5,280 Miles 1.609 Miles 1,760 Miles per hour 88 Miles per hour 1.609 Miles per hour 0.8684 Minutes 0.01667 Minutes (angle) 0.0002909 Minutes (angle) 60 Ounces (fluid) 1.805 Ounces per cubic inch 1.72999 Paschal (unit or force, 1.0 pressure) Pints 28.87 Pints 0.125 Pounds 453.6 Pounds 0.4536 Pounds of water 0.01602 Pounds of water 27.68 Pounds of water 0.1198 Pounds per cubic foot 0.01602 Pounds per cubic foot 16.0185 Pounds per square foot 4.88241 Pounds per square foot 47.8803 Pounds per square inch 2.307 Pounds per square inch 2.036 Pounds per square inch 0.689476 Quarts (U.S.) 57.75 Quarts (U.S.) 57.75 Quarts (U.S.) 0.946331 Radians 57.30 Radians per second 9.549 Square centimeters 0.1550 Square feet 144 Square feet 0.00002296 Square feet 929 Square inches 6.4516 Square inches 0.006944 Square miles 640 Square miles 2.59 Square kilometer 247.1 Square meters 10.76 Square meters 0.0002471 Square yards 9 Square yards 0.8361 Temperature 1.8 (degrees Celsius) (degC) (+ 32 degrees) 5 ⁄9 or 0.5556 Temperature (degrees Fahrenheit) (degF) (− 32 degrees) Tons (long) 2,240 Tons (metric) 2,205 Tons (short) 2,000 Yards 0.9144 Yards 91.44

Conversion factors Fraction to Decimal 1 17 ⁄64 0.0156 ⁄64 1 9 ⁄32 0.0312 ⁄32 3 19 ⁄64 0.0468 ⁄64 1 5 ⁄16 0.0625 ⁄16 1 21 ⁄64 0.0781 ⁄64 3 11 ⁄32 0.0937 ⁄32 7 23 ⁄64 0.1093 ⁄64 1 3 ⁄8 0.1250 ⁄8 9 25 ⁄64 0.1406 ⁄64 5 13 ⁄32 0.1562 ⁄32 11 27 ⁄64 0.1718 ⁄64 3 7 ⁄16 0.1875 ⁄16 13 29 ⁄64 0.2031 ⁄64 7 15 ⁄32 0.2187 ⁄32 15 31 ⁄64 0.2343 ⁄64 1/4 0.2500 1/2 English and Metric Multiply Acres Acres Acres Barrels, water Barrels, water Barrels, oil (API) Barrels per day Centimeter Cubic centimeters Cubic feet Cubic feet Cubic feet Cubic feet Cubic feet Cubic feet Cubic feet per minute Cubic inches Cubic yards Cubic yards Degrees (angle) Degree Fahrenheit (degF) Feet Feet Feet Feet Feet of water (depth) Feet Foot pounds Foot pounds Furlongs Gallons (imperial) Gallons (imperial) Gallons (U.S.) Gallons (U.S.) Gallons (U.S.) Gallons (U.S.) Gallons per minute Gallons per minute

0.2656 0.2812 0.2968 0.3125 0.3281 0.3437 0.3593 0.3750 0.3906 0.4062 0.4218 0.4375 0.4531 0.4687 0.4843 0.5000

⁄64 ⁄32 35 ⁄64 9 ⁄16 37 ⁄64 19 ⁄32 39 ⁄64 5 ⁄8 41 ⁄64 21 ⁄32 43 ⁄64 11 ⁄16 45 ⁄64 23 ⁄32 47 ⁄64 3/4 33 17

By 43,560 0.001562 4,840 31.5 263 42 0.02917 0.3937 0.006102 1,728 0.03704 7.481 0.1781 28.3160 0.03704 0.4719 16.3871 27 0.764555 0.01745 [degF − 32] ÷ 1.8 or [degF − 32] × 5⁄9 30.48 12 0.3048 0.0001894 0.4335 0.3048 1.35582 0.138255 660 1.209 4.54609 3,785.434 0.02381 0.1337 3.785 0.002228 34,286

0.5156 0.5312 0.5468 0.5625 0.5781 0.5937 0.6093 0.6250 0.6406 0.6562 0.6718 0.6875 0.7031 0.7187 0.7343 0.7500

⁄64 ⁄32 51 ⁄64 13 ⁄16 53 ⁄64 27 ⁄32 55 ⁄64 7 ⁄8 57 ⁄64 29 ⁄32 59 ⁄64 15 ⁄16 61 ⁄64 31 ⁄32 63 ⁄64 1 49 25

0.7656 0.7812 0.7968 0.8125 0.8281 0.8437 0.8593 0.8750 0.8906 0.9062 0.9218 0.9375 0.9531 0.9687 0.9843 0.10000

To Obtain Square feet Square miles Square yards Gallons Pounds Gallons Gallons per minute Inches Cubic inches Cubic inches Cubic yards Gallons Barrels (oilfield) Liters Cubic yards Liter per second Cubic centimeters Cubic feet Cubic meters Radians Degree Celsius (degC) Centimeters Inches Meters Miles Pounds per square inch Meters Joules Meter-kilograms Feet Gallons (U.S.) Liters Cubic centimeters Barrels, oil Cubic feet Liters Cubic feet per second Barrels per day

79

To Obtain Milligrams Ounces Feet Millimeters Pounds per square inch Feet Miles Miles per hour Feet Miles Miles per hour Cubic feet Gallons Feet Inches Yards Feet Kilometers Yards Feet per minute Kilometers per hour Knots per hour Hours Radians Seconds (angle) Cubic inches Grams per cubic centimeter Newton per square meter Cubic inches Gallons Grams Kilograms Cubic feet of water Cubic inches of water Gallons Grams per cubic centimeter Kilograms per cubic meter Kilograms per square meter Newtons per square meter Feet of water Inches of mercury Newtons per square centimeter Cubic inches Cubic centimeters Liters Degrees Revolutions per minute Square inches Square inches Acres Square centimeters Square centimeters Square feet Acres Square kilometers Acres Square feet Acres Square feet Square meters Temperature (degrees Fahrenheit) (degF) Temperature (degree Celsius) (degC) Pounds Pounds Pounds Meters Centimeters

Reference Buoyancy factor Buoyancy Factor k Mud Density kg/l lbm/galUS 1.00 8.35 1.02 8.51 1.04 8.68 1.06 8.85 1.08 9.01 1.10 9.18 1.12 9.31 1.14 9.51 1.16 9.68 1.18 9.85 1.20 10.01 1.22 10.18 1.24 10.35 1.26 10.52 1.28 10.68 1.30 10.85 1.32 11.02 1.34 11.18 1.36 11.35 1.38 11.52 1.40 11.68 1.42 11.85 1.44 12.02 1.46 12.18 1.48 12.35 1.50 12.52 1.52 12.68 1.54 12.85 1.56 13.02 1.58 13.18 1.60 13.35

k lbm/ft3 62.4 63.7 64.9 66.2 67.4 68.7 69.9 71.2 72.4 73.7 74.9 76.2 77.47 78.7 79.9 81.2 82.4 83.7 84.9 86.2 87.4 88.7 89.9 91.2 92.4 93.7 94.9 96.2 97.4 98.7 99.9

0.873 0.869 0.867 0.864 0.862 0.859 0.857 0.854 0.852 0.849 0.847 0.844 0.842 0.839 0.837 0.834 0.832 0.829 0.827 0.824 0.822 0.819 0.817 0.814 0.812 0.809 0.837 0.804 0.801 0.798 0.796

Mud Density kg/l 1.62 1.64 1.66 1.68 1.70 1.72 1.74 1.76 1.78 1.80 1.82 1.84 1.86 1.88 1.90 1.92 1.94 1.96 1.98 2.00 2.02 2.04 2.06 2.08 2.10 2.12 2.14 2.16 2.18 2.20 2.22

Apparent weight = Real Weight × Buoyancy Factor Mud Density hence: Buoyancy Factor (k) = 1 − Steel Density

80

k lbm/galUS 13.52 13.68 13.85 14.02 14.18 14.35 14.52 14.68 14.85 15.02 15.18 15.35 15.53 15.69 15.86 16.02 16.18 16.36 16.53 16.69 16.86 17.02 17.18 17.36 17.53 17.69 17.86 18.02 18.19 18.36 18.54

lbm/ft3 101.2 102.4 103.7 104.9 106.2 107.4 108.7 109.9 111.2 112.4 113.7 114.9 116.2 117.4 118.7 119.9 121.2 122.4 123.7 124.9 126.2 127.4 128.7 129.9 131.2 132.4 133.7 134.9 136.2 137.4 1338.7

0.793 0.791 0.789 0.786 0.783 0.781 0.779 0.776 0.773 0.771 0.768 0.765 0.763 0.760 0.758 0.755 0.752 0.749 0.747 0.745 0.742 0.739 0.737 0.734 0.732 0.729 0.727 0.725 0.722 0.719 0.717

Reference

Fixed cutter bit nozzle installation Correct Nozzle Installation Helps Prevent Washouts ■■

Remove the plastic plug and the O-ring from each nozzle port.

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Grease the O-ring and replace it in the O-ring groove.

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Do not grease nozzles in Matrix bits before installation.

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Lightly grease nozzles in steel bits and screw into jet ports.

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Hand tighten the nozzle with a tee wrench until snug.

Damage may occur if a cheater bar is used on the tee wrench handle. Nozzle and Port Size Availability for PDC Bits Nozzle or Nozzle Series Port Size, in 30 40 ■ 07/32 ■ ■ 08/32 ■ ■ 09/32 ■ ■ 10/32 ■ ■ 11/32 ■ ■ 12/32 ■ ■ 13/32 14/32 15/32 16/32 17/32 18/32 19/32 20/32 21/32 22/32 Empty Area 0.1503 in² 0.1385 in²

Port Steel

Matrix

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0.1963 in²

0.3718 in²

Wrenches

Series 30: 60007986 Series 40: 60018251 Series 50: 60024519 Series 60: 60003448 Vortexx 60: 60005675

O-Ring Series N30 Series

N40 Series

N50 Series

81

N60 Series

Series 30: 60007985 Series 40: 60007985 Series 50: 60019245 Series 60/Vortexx 60: 60003276

Reference

Nozzle comparison chart Jet Boss Series 55

Standard 55 Series

Diverging

Mini Extended Nozzles

70

70 Series

71 Series

72 Series

74 Series

95

95 Series

91 Series

97 Series

98 Series

100

100 Series

101 Series

105 Series

Physical Nozzle Size Availability Chart (Roller Cones) Series Nozzle Size, X⁄32 in 7 8 9 10 11 12 13 14 ■ ■ ■ ■ ■ ■ ■ ■ 55

15

16

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18

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0.65 0.65 0.69 0.899

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97

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101

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105

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32

0.196

65

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30

Empty jet TFA, in2

■ ■

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82

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0.899 0.899 0.899 0.899

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1.629 1.629

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1.629

Reference

Roller Cone Diverging Nozzle Hydraulics Chart Physical Nozzle Size, in 8 ⁄32 9 ⁄32 10 ⁄32 11 ⁄32 12 ⁄32 13 ⁄32 14 ⁄32 15 ⁄32 16 ⁄32 17 ⁄32 18 ⁄32 19 ⁄32 20 ⁄32 22 ⁄32 24 ⁄32

Pressure Nozzle Size, in ⁄32 11 ⁄32 12 ⁄32 13 ⁄32 14 ⁄32 16 ⁄32 17 ⁄32 18 ⁄32 19 ⁄32 20 ⁄32 21 ⁄32 22 ⁄32 24 ⁄32 26 ⁄32 28 ⁄32 10

Equivalent Pressure Area, in2 0.007 0.093 0.110 0.130 0.150 0.196 0.222 0.249 0.277 0.307 0.338 0.371 0.442 0.518 0.601

Approximately 20% of the total flow should be programmed through center jet. Note: For hydraulic calculations, determine the corresponding equivalent nozzle size for the spesific diverging nozzle size. For example 12⁄32 is the equivalent nozzle size in hydraulic calculations for a 10⁄32 diffuser nozzle size.

83

Reference

Nozzle types and applications for roller cone bits Bit Size, in

31⁄8–51/2 57⁄8–63/4 73⁄8–75⁄8 77⁄8–83⁄8 81/2–83/4 91/2–97⁄8 105⁄8–121/4 131/2–143/4 16–28

Milled Tooth Series Open Sealed Bearing Bearing

70 95 95 95 95 95 100 100

55 70 95 95 95 95 95 100 100

Jet/Air Series ALL

70 95 95 95 95 95

TCI Series Sealed/ Journal Bearing 55 70 95 95 95 95 95 100 100

Center jet component list Center jet retention systems Bit Size Range, in Three-Cone Open Bearing 61⁄8–63/4 65 70 long 71/2–75⁄8 70 long 77⁄8 81/2–9 70 short 91/2–143/4 95 16–20 100 short 22–28 100 long

Three-Cone Closed Bearing

TCT Bits

70 long 70 long 70 short 95 100 short 100 long

70 long 70 long 70 short 95 100 short 100 long

84

TCT, Two-Cone Outer Jets

70 70 95 95 100 100

All Three-Cone Bits Full-Extended Q-Tubes Tubes

70 70 95

95 100 100

Mini-Jets MT

TCI

72/74

72/74

97 97 97 97/98 105 105

98 98 98/99 98/99 105 105

Reference

65⁄8 in API pin restrictor nozzle The pin restrictor nozzle is used in special applications for mud motors that require high bit pressure drops (650–850 psi) during operation. Pin restrictors are designed to split the total bit pressure drop between a nozzle in the pin and the bit jet nozzles. Installing a pin restrictor allows larger nozzles to be installed in the bit face reducing the jet nozzle velocity and bit body erosion. Pin restrictors are installed in the pin of the bit and require a modified pin for installation. The modification can be made on the bit when first built, or it can be retrofitted after the bit is manufactured. Two sleeves are designed to fit into the modified pin. A nozzle sleeve can be installed when a pin restrictor is required. A blank sleeve can be installed when no pin restrictor is required.

6 5⁄8 in API Pin restrictor assembly with nozzles

Pin restrictors do not run as efficiently as standard jet nozzles. An Excel spreadsheet has been developed to aid in the selection of the pin restrictor and outer nozzle sizes. Contact your Smith Bits representative for the spreadsheet prior to running a pin restrictor nozzle in a bit.

85

Reference

Maximum cone dimensions for three-cone rock bits and Approximate bit weights Maximum cone dimensions for three-cone rock bits Size Range, Maximum Diameter, in [mm] in [mm] [89–98] 23⁄8 [60] 31/2–37⁄8 [73] 43/4 [121] 27⁄8 [149–150] 41/4 [108] 57⁄8–61/4 61/2–63/4 [165–172] 41/2 [114] [187–203] 51/4 [133] 73⁄8–8 [206–216] 57⁄8 [149] 81⁄8–81/2 [219–229] 61⁄8 [156] 85⁄8–9 [232–241] 61/2 [165] 91⁄8–91/2 5 7 [245–251] 63/4 [171] 9 ⁄8–9 ⁄8 [254–270] 71/4 [184] 10–105⁄8 [279–302] 77⁄8 [200] 11–117⁄8 12–121/4 [305–311] 8 [203] [244] 131/4–15 [337–381] 95⁄8 16 [406] 101/4 [260] 171/2 [445] 111/2 [292] 181/2 [470] 12 [305] 20 [508] 121/2 [318] 22 [559] 133/4 [349] 24 [610] 151/4 [387] 26 [660] 16 [406] 28 [711] 17 [432]

Maximum Length, in [mm] 15⁄8 [41] 21⁄8 [54] 31⁄8 [79] 31/2 [89] 4 [102] 41⁄8 [105] 45⁄8 [117] 43⁄8 [111] 43/4 [121] 51/2 [140] 57⁄8 [149] [156] 61⁄8 75⁄8 [194] [206] 81⁄8 [219] 85⁄8 9 [229] [244] 95⁄8 101/2 [267] 111/4 [286] 123/4 [324] 13 [330]

86

Approximate bit weights Milled Tooth Approx. Weight, lbm [kg] 10 [5] 15 [7] 35 [16] 45 [20] 75 [34] 90 [41] 95 [43] 125 [57] 135 [61] 165 [75] 195 [89] 205 [93] 345 [157] 410 [186] 515 [234] 525 [239] 625 [284] 1,000 [455] 1,385 [629] 1,450 [659] 1,550 [704]

TCI Approx. Weight, lbm [kg] 12 [5] 20 [9] 45 [20] 55 [25] 85 [39] 95 [43] 100 [45] 130 [59] 145 [66] 175 [180] 210 [95] 225 [102] 380 [173] 450 [205] 545 [248] 570 [259] 700 [318] 1,170 [532] 1,400 [636] 1,550 [704] 1,650 [750]

Reference

Roller Cone Bit Nozzling Procedures Series 55 65 70 72 74 75 91 95 97 98 99 100 101 105

Nozzles Size, X⁄32 in 7 8 9 10

11

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Empty Jet TFA, in2 0,196 0,307 0,650 0,650 0,650 0,690 0,899 0,899 0,899 0,899 0,899 1,629 1,629 1,629

Reference

Rock Bit Comparison Chart Milled tooth

1. Standard roller bearing

4. Sealed roller bearing

5. Sealed roller bearing gauge protected

Series Formations Types Smith Bits

Hughes ReedSecurity Smith Christensen Hycalog DBS Bits

Hughes ReedSecurity Smith Christensen Hycalog DBS Bits

Hughes ReedSecurity Christensen Hycalog DBS

1

DSJ

R1

Y11

XN1

SDS

GTX-1

XR+ GSSH+ TCTi+

GTX-G1 MAX-GT1 MX-1 MXL-1 MXL-1V

DTJ DGJ

R3

Y13

XN3

MGG

GTX-3

GGH+ GTX-G3 MSDGH MAX-GT3 MX-3 SVH

2

3

Soft 1 Formations/ LowCompressive Strength 2 3 Med. to Med.-Hard Formations/ HighCompressive Strength Hard, SemiAbrasive Formations

1 2 3

XN4 M4N OFM

1 2 3 4

Milled tooth

XN5 R7

6. Sealed friction bearing

Series Formations Types Smith Bits

1

DR5

Soft 1 Formations/ LowCompressive Strength

FDS

HP11

XS1 XSC1

2

FDT

HP12

XSC2

3 2

3

7. Sealed friction bearing gauge protected

Hughes ReedSecurity Smith Christensen Hycalog DBS Bits

Med. to Med.-Hard Formations/ HighCompressive Strength Hard, SemiAbrasive Formations

1

HP13 ATJ-4

M44NF

XR+ FDS+ TCTi+

Hughes ReedSecurity Christensen Hycalog DBS

GT-1 MX-1 MXL-1 MXL-1V STR-1 STX-1

MFDGH MX-3 FDGH GFVH ATJ-G4 FVH

2 3 1 2 3 4

H77F ATJ-G8

88

TC10 TC11 SL11 TD11 D11 SL12 HP12 HP13G D13 HP21G

XSC1 XLC1 EBXS1 EBXSC1 EBXLC1

XS3 XL3 XS4 XL3

T11 XT1 EMS11G XT1S ETS11G XL1N

T13 XT3 EMS13G EBXT3 ETS13G XT4 XT4S

Reference

Rock Bit Comparison Chart TCI

5. Sealed roller bearing Gauge protected

7. Sealed friction bearing Gauge protected

Series Formations Types Smith Bits

Hughes Christensen

4

GSi01B, GS01, GS01B, GS02B, GS02T, GS03B Gi03B, G04B, GS04B, TCTi01

GTX‑00, GX‑00 T41, MAX‑GT00, EMS41H MXL‑00, GTX‑03, GX‑03, MAX‑GT03, MXL‑03

XT00‑05, EBXT00‑05

GFSi01, GFS04, GFS04B, MFS04, GT‑00, MX‑00, GT‑03, MFi04 MX‑03, GX‑00, GX‑03, STR‑03, H‑03, MXL‑00, MXL‑03

HR‑90, HR‑99, XS00‑05, STX‑90,STX‑99, STR‑90, XL00‑05, HR‑95, GX‑95, MX‑99 EBXS00‑05, EBXL00‑05

GS05, GS05B GSi06B, G08B, GS08B

GXT‑03C

T42, EMS42H

XT06‑09, EBXT06‑09

GF05, GF05B, GFi05B, GFSi06, MF05B

STR‑05C, HX‑05C

TD42H, R07A

XS06‑09, XL06‑09, EBXS06‑09, EBXL06‑09

3

G10B, G10T GS10B, GSi12B GSi12UB, TCT10

GTX‑09, MX‑09, T43, MAXGT‑09 GTX‑11, EMS43A, MX11, MX11S, EMS43H MXL‑09

XT10‑13, EBXT10‑13

F10, F10B, F12, F12Y, GF08B, GF10B, GF10HB, GFS10B, GF12T, XR12, MF10T, MFS10T, XR10T, TCT11, TCT12

GT‑09, STR‑09, STX‑09, STX‑09H, HX‑09, GX‑11, MX‑09, MX‑11, MX11H, MXL‑09, MXL‑11

SL43H, TD43, TD43A, TD43H, D43, HP43A, HP43H, R09A, R12A, RD12, R14

XS10‑13, XL10‑13, EBXS10‑13, EBXL10‑13

4

GSi15B, G15, GSi18B, GSi20B, G11Y, M15S, 15JS

MAXGT‑18 MX‑18 T44, EMS44H, EMS44A

XT14‑17, EBXT14‑17

FH16, FH16B, FHi18, MF15M, F15T, MF15B, MF19, GF15, GF15B, GF15Y, GFS15B, XR15, XR15T, XRi15G

GT‑18, STR‑18, STX‑18, H‑18, HX‑18, GX‑18, MX‑18, MXL‑18

TD44, TD44H, TD44X, XS14‑17, D44, HP44H, HP44X, XL14‑17, R14A, RD15, R15A, R15 EBXS14‑17, EBXL14‑17

G20, GS20B, G25, GTX‑20, MAXGT‑20 T51, G20B, 20GMS, MX‑20, MXL‑20, EMS51A, 2JS, GSi20B GTX‑22 MX‑22 EMS51H

XT18‑23, EBXT18‑23

F15H, F2, MF2, MF15H, FHi20, FHi21, FHi23, GFi20, GF21, GF25, GFS20, MFS20, XR20, XR20B, XR25, F25Y, GF20Y, XR20Y,TCTi20

GT‑20, STR‑20, STX‑20, H‑20, HX‑20, GX‑20, MX‑20, GX‑22, MX‑22, GX‑23, GX‑25, MXL‑20

SL51H,TD51, TD51A, TD51H, TD51X, D51, HP51H, P51A, HP51H, HP51X, R19A, R20A, R21A, R22A, RD21

G28B

GTX‑20C MAX‑GT20CG MX‑20C, MX‑28G

T52, EMS52H

XT24‑27, EBXT24‑27

GF26, F27, GFS28, FHi28, GFi28B, FHi29, Fhi25, F26Y, MF26Y, FHi24Y, F27A, F27IY, GF27Y, XR20TY

GT‑20C, GT‑28, H‑28, TD52,TD52A,TD52H, HX‑28, GX‑20C, GX‑28, TD52i, TD52X, HP52, MX‑20C, MX‑28, MXL‑28 HP52X, R24A, R25A, R26A, RD25, R27, R28A

XS24‑27, XL24‑27, EBXS24‑27, EBXL24‑27

G30, GS30B 3JS

MX‑30H, MAX‑GT30

T53, EMS53, EMS53A, ETS53A

XT28‑33, EBXT28‑33

F3, F30, FH30, F30T, FHi30, FHi31, FH32, GF30, GF30B, GF30T, MF30T, XR30, XR32, F30Y, FH30Y

STR‑30, STX‑30, GT‑30, STX‑35, GX‑30, H‑30, HX‑30, MX‑30, MXL‑30

SL53,SL53A,TD53, TD53A, TD53B, TD53H, D53,HP53, HP53A, HP53H, JA53, R30,R30A, RD33

XS28‑33, XL28‑33, EBXS28‑33, EBXL28‑33

GTX‑30C, GTX‑33, MAX‑GT30CG, MX‑33CG

T54

XT34‑39, EBXT34‑39

FHi35, GFi35, F30Y, F37Y, FHi37Y, GT‑30C, STR‑30C, STR‑, FHi38Y,, F39Y, GFi35YG, F37Y, 35C, STX‑30C, HR‑38C, XR30Y, XRi35, XR35Y HR‑30C, HR‑35, GX‑30C, GX‑35, GX‑38, MX‑35C

TD54A, TD54X, TD54, R34A, R35A, R36A

XS34‑39, XL34‑39, EBXS34‑39, EBXL34‑39

ETS61A

XT40‑45, EBXT40‑45

FH40, FHi45, F40, F45H, MF4H, GF40H, GF40Y, Xr38, XR40, XR45Y, F40Y, F40YA, F47Y, F47YA, FH43Y, GF47Y

STR‑40, HR‑40, HR‑44, STX‑40, GX‑44, MX‑40, MX‑44

SL61, SL61A, TD61, XS40‑45, TD61A, HP61A, HP61H, XL40‑45, R40A, R40 EBXS40‑45, EBXL40‑45

EMS62

XT46‑51, EBXT46‑51

F50, FHi50, FHi50Y, F46HY, F47HY, GF45Y, GF50Y, XR40Y, XR40YA, XR45Y, XR50

STR‑40C, STR‑44C, STX‑44C, HR‑40C, HR‑44C, GX‑44C, GX‑45C, MX‑40C, MX‑44C, MXL‑44C

SL62,SL62A,SL62X, TD62, TD62A, HP62, HP62A, HP62H, JA62, R44A, R45, R48

XT52‑58

F57Y, F57HY, GF50YB, F50YA, XR50Y

STR‑50, STR‑50A, STX‑50, SL63, TD63, HP63, R50 XS52‑58, HR‑50, HR‑55, GX‑55, XL52‑58, MX‑50, MX‑55 EBXS52‑58, EBXL52‑58

4

XT61‑69

F59Y, F59HY, F67Y, GF67Y, XRi65Y

HR‑60, HR‑66, HR‑68, STX‑60, MX‑66, MX‑68

Hard, Semi- 1 Abrasive and Abrasive 3 Formations 4

XT71‑75

Extremely 1 Hard and Abrasive 2 Formations 3

5

Soft 1 Formations/ LowCompressive Strength 2

Soft to 1 MediumHard Formations/ LowCompressive 2 Strength 3

4

6

Medium1 Hard Formations/ HighCompressive 2 Strength

3

7

8

G40, G40Y, G40YB, 4JS

GT‑40C, MX‑44C

MX‑55

ReedSecurity Smith Bits Hycalog DBS

Hughes Christensen

ReedHycalog

TD64, TD64H, HP64, HP64H, R60, R65

Security DBS

XS18‑23, XL18‑23, EBXS18‑23, EBXL18‑23

XS46‑51, XL46‑51, EBXS46‑51, EBXL46‑51

XS61‑69, EBXS61‑69 XS71‑75, EBXS71‑75

XT77‑81

F7, XR68Y, XR68HY, XR70Y

XT83‑89

XR75Y

XT91‑93

F80Y, GF80Y, XR80Y

HR‑80, HR‑88, STX‑80, STX‑88, STR‑80, MX‑88

XT95‑97

F85Y

HR‑89

XT99

F90Y, FHi90Y, XR90Y

HR‑90, HR‑99, STX‑90, STX‑99, STR‑90, HR‑95, GX‑95 ,MX‑99

89

STR‑70, STX‑70, HR‑70

SL73, HP73

XS77‑81, EBXS77‑81

TD74,HP74,R75

XS83‑89, EBXS83‑89

TD81, HP81, R80, R85

XS91‑93, EBXS91‑93 XS95‑97, EBXS95‑97

SL83, TD83, HP83, R90, R95

XS99, EBXS99

Reference

Smith Bits roller cone bit nomenclature Seal and Bearing Prefix D – Non-sealed (open) bearing S – Single seal, roller bearing F – Single seal, friction bearing M – Single seal, roller bearing motor bit MF – Single seal, friction bearing motor bit

Product Type Milled Tooth Milled Tooth All All All

Example DSJ SDGH F15 MSDGH MFDGH

Premium Product Type Prefix FH – FH, single seal, friction bearing GF – Gemini twin seal, friction bearing G – Gemini twin seal, roller bearing XR – Xplorer, single seal, friction bearing XR+ – Xplorer Expanded

Product Type Insert All All Insert Milled Tooth

Example FH23 GF30 G18 XR25 XR+

Milled Tooth Cutting Structures S – Soft formation type T – Soft to medium formation type G – Medium formation type V – Medium to hard formation type S – Self sharpening hard facing H – Heel inserts + – Premium Milled tooth cutting structure

Product Type Milled Tooth Milled Tooth Milled Tooth Milled Tooth Milled Tooth Milled Tooth Milled Tooth

Example FDS DTJ FDGH SVH MSDSSH SDSH FDS+

Insert Cutting Structures S – Shamal design 00–99 – Insert bit digits (00 Softest–99 Hardest)

Product Type Insert Insert

Example GFS10 FH50

Cutting Structure and Feature Suffix A – Air application bit B – Binary carbide gauge BD – Binary diamond gauge C – Center jet D – SRT diamond gauge DD – Fully diamond enhanced cutting structure G – Super-D Gun cone coating H – Heavy set gauge design I – Inclined chisel on gauge L – Lug Pads pressed with tungsten carbide inserts LD – Lug pads pressed with diamond inserts N – Nominal gauge diameter OD – Diamond heel (50%) OD1 – Diamond heel (100%) PS – SRT tungsten carbide legback protection PD – SRT diamond legback protection R – Upper and Lower tungsten carbide legback protection RD – Upper and Lower diamond legback protection SD – Shaped diamond gauge and 50% Diamond heel SD1 – Shaped diamond gauge and 100% Diamond heel T – Trucut carbide gauge TD – Trucut diamond gauge inserts U – Unconventional cutting structure/feature V – V-Flo hydraulics W – Softer than standard insert grades Y – Conical cutting structure 3 – 27⁄8 in connection (not Smith Bits default size 23⁄8 in) 6 – 65⁄8 in connection (not Smith Bits default size 75⁄8 in) 7 – 75⁄8 in connection (not Smith Bits default size 85⁄8 in)

90

Product Type Insert Insert Insert All Insert Insert Insert Insert Insert All All All All All All All All

Example F47A GFS10B GS03BD F10C XR30D MF37DD F12YG F37H F27I FH45L MF15LD GF05N F57OD XR25OD1 FH28PS F37PD GS18R

All Insert

F50RD G25SD

Insert

MF20SD1

Insert Insert All All Insert Insert F All

XR20T XR32TD GS18U FH35V XR15W 59Y XR30-3

All

XR-6

All

XR-7

Reference IADC dull bit grading Cutting Structure Inner Outer 1 2

Dull Char. 3

Location 4

1. Inner Cutting Structure (All Inner Rows) (For fixed cutter bits, use the inner 2⁄3 of the bit radius) 2. Outer Cutting Structure (Gauge Row Only) (For fixed cutter bits, use the outer 1⁄3 of the bit radius) In columns 1 and 2, a linear scale from 0 to 8 is used to describe the condition of the cutting structure according to the following: Steel Tooth Bits A measure of lost tooth height due to abrasion and/ or damage 0 – No Loss of Tooth Height 8 – Total Loss of Tooth Height Insert Bits A measure of total cutting structure reduction due to lost, worn and/or broken inserts 0 – No Lost, Worn and/or Broken Inserts 8 – All Inserts Lost, Worn and/or Broken

Bearings/ Seals

Gauge

Other Dull Characteristics

Reason Pulled

5

6

7

8

4. Location Roller Cone N – Nose Row M – Middle Row G – Gauge Row A – All Rows Cone # 123 Fixed Cutter C – Cone N – Nose T – Taper S – Shoulder G – Gauge A – All Areas

5. Bearings/Seals Non-Sealed Bearings A linear scale estimating bearing life used 0 – No Life Used 8 – All Life Used, i.e., no bearing life remaining

Fixed Cutter Bits A measure of lost, worn and/or broken cutting structure 0 – No Lost, Worn and/or Broken Cutting Structure 8 – All of Cutting Structure Lost, Worn and/or Broken

Sealed Bearings E – Seals Effective F – Seals Failed N – Not Able to Grade X – Fixed Cutter Bit (bearingless)

3. Dull Characteristics (Use only cutting structure related codes) BC† – Broken Cone LN – Lost Nozzle BF – Bond Failure LT – Lost Teeth/Cutters BT – Broken Teeth/Cutters OC – Off Center Wear BU – Balled Up Bit PB – Pinched Bit CC† – Cracked Cone PN – Plugged Nozzle/Flow CD† – Coned Dragged Passage CI – Cone Interference RG – Rounded Gauge CR – Cored RO – Ring Out CT – Chipped Teeth/Cutters SD – Shirttail Damage ER – Erosion SS – Self Sharpening Wear FC – Flat Crested Wear TR – Tracking HC – Heat Checking WO – Washed Out Bit JD – Junk Damage WT – Worn Teeth/Cutters LC† – Lost Cone NO – No Dull Characteristics †

6. Gauge Measure to nearest 1 ⁄16 of an inch 1 in In Gauge 1– 1⁄16 in Out of Gauge 2– 2⁄16 in Out of Gauge 4– 4⁄16 in Out of Gauge

Show cone number(s) under Location (4)

91

7. Other Dull Characteristics Refer to column 3 codes

8. Reason Pulled or Run Terminated BHA – Change Bottom-Hole Assembly DMF – Downhole Motor Failure DTF – Downhole Tool Failure DSF – Drillstring Failure DST – Drill Stem Test DP – Drill Plug CM – Condition Mud CP – Core Point FM – Formation Change HP – Hole Problems LIH – Left in Hole HR – Hours on Bit LOG – Run Logs PP – Pump Pressure PR – Penetration Rates RIG – Rig Repair TD – Total Depth/Casing Depth TW – Twist Off TQ – Torque WC – Weather Conditions

Reference

Stinger element dull bit grading

The unique conical geometry of the Stinger element requires a modified dull grading to measure damage observed (lost, worn, or broken). The wear rating scale (0 to 8) is the same, as used for standard PDC cutters.

0 (0% wear) 4 (50% wear)

WT – No wear (Level 0 severity)

WT – Minimal wear (Level 1 severity)

WT – Minor wear (Level 2 severity)

CT – Chipped element

SP – Spalling

BT – Broken element

DL – Stinger element delamination

BF – Bond failure

LT – Lost element

8 (100% wear)

Stinger element wear can be recorded from a linear scale of WT0 to WT8, with 0 representing no wear and 8 representing no diamond table remaining.

92

Notes

93

Scan QR code with an iPhone® to download the Smith Bits Quick Calc Hydraulics app from the iTunes® store.

www.slb.com/SmithBits

*­ Mark of Schlumberger Other company, product, and service names are the properties of their respective owners. Copyright © 2013 Schlumberger. All rights reserved. 13-BT-0039