Remedial Tools Handbook

i

9Remedial ToolsdaTa handbook

Ninth Edition

P.O. Box 60068 • Houston, Texas 77205-0068U.S. and Canada: 800.US SMITH • Tel: 281.443.3370Fax: 281.233.5121 • www.siismithservices.com

Requests for permission to reproduce or translate all or any part of the material published herein should be addressed to the Marketing Services Manager, Smith International, P.O. Box 60068, Houston, Texas 77205-0068.

PrefaceThe 9th edition of this Data Handbook contains useful, practical infor-mation on specialized downhole solutions utilizing remedial tools and services. The content focuses on areas in which we have built a com-bined, renowned reputation for quality service for more than 90 years. These remedial tools and services include downhole milling, sidetrack-ing, underreaming, hole opening, pipe cutting, well abandonment and multilateral systems.

The Smith Services team applies their craft daily in oil and gas fields worldwide. These experienced hands provide downhole solutions to your remedial operations. We hope this 9th edition will aid you in expediting your downhole remedial objectives.

We value customer comments and will consider them for addition to our next handbook.

The Field Operations, Sales, Business Development and Engineering Departments.

The following are marks of Smith International, Inc.: Anchor-Stock, Bearclaw, Drillmill, Dyna-Cut, Economill, Econo-Stock, Ezy-Change, Flo-Tel, Hevi-Wate, Hydra-Stroke, Junk Master, K-Mill, M-I SWACO, Master Drilller, Millmaster, Pack-Stock, Piranha, Reamaster, Retrievable Anchor-Stock, Retrievable Econo-Stock, Retrievable Pack-Stock, Rhino, SPX, Smith Bits, Smith Services, Trackmaster, Underream While Drilling and UWD.

Table of ConTenTs

Downhole MillingGeneral Guidelines 1How to Read Cuttings 2Recommendations on Weights and Speeds 2Some Factors that Affect Milling Rates 2Encountering Rubber in the Hole 3Stabilizing the Mill 3What to do About Rough Operation 3Operating Recommendations for Milling 3

K-Mill® 6Flo-Tel® Option Assures Positive Tool Opening 6General Suggestions for Effective Section Milling 8Recommended Procedure for Milling a Section 8Difficulties Encountered in Cutting Out 9

M-I SWACO Recommendation for Mud Prep Prior to Section Milling 10Mud 10Mud Properties 10Flow Rate 10Hole Sweeps 11

Flow Guidelines for Millmaster® System Tools 11Total Flow Area (TFA) Fixed piston ID = .442 TFA equivalent 11Fluid Velocity 11GPM Rate 11Pressure Drop 11Mud 11Hole Sweeps 11

Standard Millmaster BHA Recommendations 12Section Planning for Sidetracking 16Properties and Flow Rates 16Underreaming for Sidetrack Plug 17Using the K-Mill as a Pipe Cutter 17Cutting the Pipe 17K-Mill Disassembly 17Service Instructions 19Assembly 19

Pilot Mills 23General Guidelines for Using Pilot Mills 23Considerations When Milling Liner Hangers and Adapters 23A Pilot Mill is Ideal for Washpipe 23Milling Drill Pipe and Drill Collars 24

Using the Pilot Mill in Swaged Completion 24Using a Pilot Mill 24

Piranha Mill™ 27Offshore Slot Recovery 28Description of the Piranha Mill 28Slot Recovery Operating Parameters 28Mill Stability 29

Junk Milling 30Junk Milling Procedures 31General Guidelines 31Loose Junk in Open Hole 32Stationary Junk in Open Hole 32Loose and Stationary Junk in Open Hole 32

Junk Subs 35Taper Mills 37

CP Taper Mill Designed for the Toughest Taper Mill Job 37CT Taper Mill Perfect for Milling Restrictions 37General Guidelines for Using a Taper Mill 38How to Clean Up Whipstock Windows Using a Taper Mill 38Procedures for Reaming Out Collapsed Casing 38Enlarging Restriction Through Retainers and Adapters 39Using a Taper Mill to Ream Out Guide Shoes 39

Special Mills 41Economill™ 41Drillmill™ 42Junk Master™ 43

Tungsten Carbide Products 45Tungsten Carbide “S” 45Tungsten Carbide Rod Application 45Tungsten Carbide Removal 47

whipsToCk operaTions

WhipStocks 49Retrievable Pack-Stock™ 49Operational Recommendations 51Retrievable Anchor-Stock™ 51Two Other Unique Advantages 53Anchor-Stock®/Pack-Stock® Running Procedure 53Retrievable Econo-Stock™ 54Standard Econo-Stock Running Procedure 54Tips for a Successful Re-entry 57

Whipstock Sidetracking 57

Trackmaster® Operations 59Trackmaster: The Only One-trip Window Milling System 59Trackmaster System Description 60High-Flow Bypass Valve 60Running Tool 60Milling Tool 60Lead Mill 60Follow Mill 60Dress Mill 60Whip Assembly 60Conclusions 61Objectives 62Benefits 63

ConCenTriC hole enlargeMenT Underreaming 65

Application of Underreamers 65General Guidelines for Underreaming 66

Formation Considerations 66Maximum Weight on Tools with Milled Tooth/TCI Cutters 66Maximum Weight on Tools with PDC-Type Cutters 66Anticipated Life of Cutters 66Tool Selection 67

Reamaster® (XTU) 70Innovative Design Improves Underreaming 71Substantially Reduces Overall Casing and Cementing Costs 71Features 71Customized Cutters 72Improved Hydraulics 72

Reamaster Operating Parameters 74Reamaster Underreaming Guidelines 77Cutting the Shoulder 77Underreaming 77Adding a Connection 78Tripping Out of the Hole 78Reamaster Disassembly 78Reamaster Assembly 81

Drilling-Type Underreamer (DTU) 85Operating Guidelines 85Cutting the Shoulder 85Underreaming 85Adding a Connection 86Tripping Out of the Hole 86

Underreaming Key Seats 86DTU Disassembly 87Drilling-Type Underreamer (DTU) Assembly 89

Rock-Type Underreamer (RTU) 92Operating Guidelines 93

Cutting the Shoulder 93Flo-Tel Equipped Rock-Type Underreamer (RTU) 93Underreaming the Interval 94Adding a Connection 94Tripping Out of the Hole 94Rock-Type Underreamer (RTU) Disassembly 94Rock-Type Underreamer (RTU) Assembly 95

SPX®/Drag-Type Underreamer 99Operating Instructions 100

Cutting the Shoulder 100Flo-Tel Equipped SPX/Drag-Type Underreamer 101Underreaming the Interval 101Adding a Connection 101Tripping Out of the Hole 101SPX/Drag-Type Underreamer Disassembly 101SPX/Drag-Type Underreamer Assembly 103

Rhino® Reamer System 107Pre-job Planning and Preparation 109Mechanical Analysis 109Pre-run Checklist 109General Procedure for Making up the Rhino Reamer 110Rhino Reamer Make-up and Surface Test Procedure for Lockout Mechanism and Hole Enlargement While Drilling Only 111

Drilling the Casing Shoe Track 112Cutting the Shoulder 113Hole Enlargement 113Tripping Out of the Hole 113

Conventional, Drill and Ream, Rotary Steerable Systems 114Operating Parameters 116

hyDrauliCsBit Hydraulics 117The Flow of Fluid Under Pressure 117Underreamer Hydraulics 118Piston Bore Velocity 121Hydraulic Tool Pressure Loss 121

Hydraulics 124Correct Orifice Selection 124Reamaster and Drilling-Type Underreamers (DTU) 124K-Mill, SPX/Drag- and Rock-Type Underreamers 125SPX/Drag- and Rock-Type Underreamers with Flo-Tel 125Determining System Hydraulics 127Rock-Type Underreamer, Pumping Rate 250 GPM 127Pressure Drops for Mud Weights Other than Ten lb/gal. 129

hole opening

Definition 135Master Driller™ 137

Master Driller Tool Servicing 138Changing Cutters 138Changing Jet Orifice 138Changing Arm Pin Bushings 139Body 139

GTA Fixed Diameter Hole Openers 142Features 143GTA Tool Servicing 143Nozzles 143Cutters and Legs 144Body Repair 146Cutter Installation 147Corrosion Prevention 147

Hole Enlarger 150Body Types 150Features 150

0625-2600 M6980 Hole Enlarger Bodies Field Repair and Service Procedures 152Design and Construction Background 152Repairs 152

3600 M6980 Hole Enlarger Bodies Field Repair and Service Procedure 155Design Background 155Inspection 155

Changing Cutter Assemblies 156Removal of Old Assembly 156Installing New Assembly 156Arm Replacement 156

well abanDonMenT

General Information 159

Shortcut 97/8 in. Cut & Pull Assembly with Seal Assembly Retrieving Tool 159Assembly 159Procedure 159

Pipe Cutters 161Pipe Cutting Operating Parameters 161Jack-ups and Submersibles 162Semi-submersibles and Drill Ships 162Pipe Cutter Assembly for Floaters 163Selecting P-Cutter Lengths and Diameters 163Calculating Spacer Sub Lengths for P-Cutters 164Examples of Spacer Sub Length Sizing 164Selecting P-Cutter Lengths and Diameters 166Example of Arm Size Selection 166Pipe Cutter Disassembly 169Servicing 169Assembly 169

Casing Back-off Tool 172Features and Benefits 172Applications 172

Marine Support Swivel 181Marine Support Swivel Disassembly 174Servicing 174Assembly 174

The Dual Plug and Abandonment System – Only Smith has it 177Mechanical Cutting vs. Explosive Severing 177

One-trip Cut and Recovery 177Dyna-Cut® Deepwater Wellhead Severing System 180

referenCe TablesAPI Casing Data 181Rock Bit Comparison Chart 183Recommended Rock Bit Make-up Torque 184Nozzle Types and Applications for Smith Bits 185Rock Bit Comparison Chart 186Smith Bits Drill Bit Nomenclature 191IADC Dull Bit Grading 192How to Convert “Wags” to Swags” 193A. Bit Selection Equations 194B. Bit Weight-Rotational Speed Equations 194C. Hydraulic Calculation Equations 195D. Drilling Fluid Property Equations 198

Nomenclature 199Recommended Minimum Make-up Torque (ft/lb.) 201Rotary Shouldered Connection Interchange List 209Top Sub Make-up Torque Table (ft/lb.) 211Recommended Maximum-Minimum Tool Joint Dimensions (in.) 212

Drill Pipe Data 213Internal Upset 213External Upset 213Hevi-Wate™ Drill Pipe 214Capacity and Displacement Table — Hevi-Wate Drill Pipe 214Dimensional Data Range II 215

Tubing Data 216Non-upset 216External Upset 216

Drill Collar Weights (lb/ft.) 217Weights of 30 ft. Drill Collars (lb.) 218Buoyancy Factor and Safety Factor 219

Buoyancy Effect on the Drillstring 219Safety Factor 219

Buoyancy Factors 22010 in. Duplex Pump 22112 in. Duplex Pump 22214 in. Duplex Pump 22215 in. Duplex Pump 22316 in. Duplex Pump 22318 in. Duplex Pump 22420 in. Duplex Pump 2247 in. Stroke, Triplex Pump 2258 in. Stroke, Triplex Pump 22581/2 in. Stroke, Triplex Pump 2269 in. Stroke, Triplex Pump 22691/4 in. Stroke, Triplex Pump 22710 in. Stroke, Triplex Pump 22711 in. Stroke, Triplex Pump 22812 in. Stroke, Triplex Pump 228

Hardness Conversion Table - Approximate Values 229Impression Diameter Hardness Table 230Conversion Factors - Fraction to Decimal 232Conversion Factors - English and Metric 233

inDex 237

Downhole MillingThe word “milling” means to cut, grind, pulverize or break down metal into smaller particles. These particles are then circulated up the annulus. The mills cut up objects that fall or get stuck in the hole or can mill away entire sections of casing. All mills are dressed with a special tungsten carbide blend, specially designed to improve milling performance.

The mills are available in two basic categories: fixed blade tools and hy-draulically activated mills.

General Guidelines• Annular velocity should be maintained at 80 to 120 ft/min.• Oil-base mud should be avoided whenever possible.• Ordinarily, no difficulty is encountered in circulating drilled cuttings under

normal drilling practices. However, milled cuttings are much heavier so weighing the mud has little effect on cutting lift. A ratio of Plastic Viscos-ity to Yield Point (PV/YP) as ratio as close to 0.5 is ideal for steel cutting removal. If the ratio is higher than 1.0, a common remedy is to add lost circulation materials, pills or agents to the mud system. This will help to “sweep” the hole and will aid in carrying the steel cuttings up the annulus and out of the hole.

• Polymer muds are best for milling. Clay-base muds would be a second choice. Oil-base muds would be third. These choices are based on the carrying ability of the mud. Oil-base muds have poor carrying capabilities and often result in more troublesome jobs.

• Never mill faster than it is possible to remove cuttings.• In optimum conditions, it is recommended to start with a high laminar

flow. Small adjustments can be made in the flow rates, rotary speed and weight while monitoring the cuttings for size, shape and thickness.

• If bird nesting occurs, pull up and circulate until proper cutting return is achieved.

• On small workover rigs and deep drilling jobs with limited hydraulics, “sweep” the hole with viscous slugs every two to three hours. During long milling jobs, this procedure should be repeated frequently to maintain an optimum Rate of Penetration (ROP).

• Place ditch magnets in the mud system prior to milling. This will decrease pump damage from cutting contamination.

• The first four to five ft. of a milling job are extremely critical, especially during section milling. Cuttings tend to accumulate at the cutting knife, causing bird nesting. If this occurs, pull the kelly up five ft. and ream down slowly.

• Always inspect the ID of subs and other tools to ensure they are full bore. This will minimize hydraulic problems.

• A junk basket can aid in catching the larger cuttings. This is especially true when milling old, split or corroded casing. Junk baskets are placed in the string just above the mill.

Downhole Milling 1

Downhole Milling2

How to Read CuttingsThe ideal cutting is usually 1⁄32 to 1⁄16 in. thick and one to two in. long. If cut-tings are thin, long stringers, penetration rates are too low. Increase weight on the tool.

If fish-scale-type cuttings are being returned when pilot or section milling, penetration rates will improve by decreasing weight and increasing RPM. This is more common when milling H-40 and K-55 casing. When milling N-80, P-110, Q-135, etc., longer cuttings will be returned.

Recommendations on Weights and SpeedsGenerally the most efficient milling rates are obtained by running the rotary at 80 to 100 RPM. Milling with washover shoes is an exception; they are usually more efficient when run at 60 to 80 RPM. (As with all mill-ing tools, speed and weight will be dictated by actual conditions.)

Always start rotating about one ft. above the fish. Lower onto the fish and vary the weight to improve penetration. Whenever possible, maintain a constant milling weight. Feed the drum slowly, allowing the drawworks to “creep”; do not drill off.

The wear pattern on section and pilot mills is a great indication of its per-formance. If the blades show a hook wear pattern, then the mill is working efficiently. If a tapered pattern exists, ease off on the weight applied.

Some Factors that Affect Milling RatesThe type and stability of the fish (cemented or not), the weight on the mill, the speed at which it is run and proper carbide dressing of the mill are all factors which will affect milling rates. The hardness of the fish or cement will also affect a mill’s performance.

When milling cemented casing, penetration rates can be increased by using higher weight and speeds. Uncemented casing should be milled at lower speeds with less weight. When severely corroded casing is encoun-tered, a high-speed, light-weight run will prevent tearing or splintering of the fish.

Recommended milling rates can be found in the Normal Milling Rate table on Page 4.

Encountering Rubber in the HoleRubber always presents a problem during milling. When encountered, pull up and spud the mill to get a bite on the rubber. When necessary, pull the mill and clean the fish by running a drill bit.

Downhole Milling 3

Stabilizing the MillA mill that moves eccentrically does a poor job. In vertical wells stabilize above the mill at 60 or 90 ft. intervals. The stabilizer OD should not exceed the dressed OD of the mill. Section and pilot mills should also be stabilized to the drift diameter of the casing, 1/2 to 1 in. under drift on taper mill.

What to do About Rough OperationWhen bouncing or rough running occurs, decrease speed and weight, then slowly increase speed and weight until an acceptable ROP is obtained. If rough running reoccurs, once again decrease and then gradually increase to a maximized ROP.

Operating Recommendations for MillingThe RPMs required for good milling rates will vary. If run at high rotary speeds, the mill can hang up and stick momentarily. The string will then violently untwist, often breaking tool joints or twisting off pipe. Thus, RPM is limited by the drillstring and hole conditions.

High speed can burn or damage the tungsten carbide which is critical to milling the steel. Tungsten carbide cuts steel best at 250 to 340 surface ft. per minute or 3,000 to 4,000 surface in. per minute. The following rule of thumb will help you determine the minimum/maximum recommended RPMs:

Note: Slow rotary speed to avoid fracture damage to the carbide if mill is bouncing or torquing up.

Surface speedMin./max. RPM = Tool OD x 3.14

Thus, for a 8 5 ⁄8 in. milling tool:

3,000RPM min. = = 111 RPM 8.625 x 3.14

4,000RPM max. = = 148 RPM 8.625 x 3.14

Downhole Milling4

Type of Mill Weight (lb.) Remarks

Junk mill 4,000 - 10,000 Spud mill from time to time

Pilot mill 6,000 - 10,000 Vary weight to attain best cutting speed

Taper mill / string taper mill 2,000 - 4,000 Start with light weight and low

speed

Economill™ 2,000 - 8,000 Maintain light weight and low speed

Washover shoe 2,000 - 6,000 Pick up from time to time

Section mill 4,000 - 8,000 Do not mill faster than cuttings are removed

Drillmill™ 2,000 - 4,000 Start with light weight and low speed

Junk Master™ 2,000 - 4,000 Do not mill faster than cuttings are removed

Milling Rate (ft/hr.)

MaterialJunk Mill

Pilot Mill Piranha™ EconomillSection

Mill

Rotary Shoe Washing

Over

Casing 4 - 6 8 - 12 4 - 8

Drill pipe 2 - 6 6 - 8 6

Drill collars 1 - 2 2 - 3 4

Packers 4 2 - 3 2 - 3

Bits, cones, etc. 2 - 4

General junk 3 - 5 2 - 4

Washpipe 4 - 6

General Operating Recommendations for Milling

Normal Milling Rate

Downhole Milling 5

Section Milling

Millmaster systems are only available on a rental basis in conjunction with Smith job supervision.

U.S. Patent Number: Carbide Insert Milling Tool – 4,710,074

Millmaster® Assembly Showing Chip Breaker Cutting Structure

Downhole Milling6

K-Mill® The K-Mill is a hydraulically actuated tool used to mill a section in casing or tubing. The K-Mill is simple in design, easy to operate and has an outstand-ing reputation for milling performance.

Milling knives are dressed with Millmaster tungsten carbide. This is effec-tive for milling casing which is poorly cemented, split or corroded. Millmas-ter systems utilize patented tungsten carbide inserts to provide extended footage with maximum penetration rates. The cutting structure consists of Millmaster carbide arranged in a brick-work pattern. The carbide, being specially developed for downhole application, prevents premature wear and breakage.

Upon circulation through the tool, a pressure drop is created across the pis-ton. This forces the cam down and expands the cutter knives into contact with the casing. Cut-out knives part the casing, then all the knives partici-pate in milling. When circulation is stopped, the piston spring will retract the piston, causing the cam to withdraw from between knives. The knives are now free to collapse back into the body and the tool can be retrieved. The tool’s cutting action is very effective. Typically up to 60 ft. sections are completed with one set of knives dressed with Millmaster carbide.

Flo-Tel® Option Assures Positive Tool OpeningThe exclusive Flo-Tel option on the K-Mill provides the positive indication that the cut-out has been made. This eliminates the possibility of “skinning” the inside of the pipe instead of milling it up. When the cut-out is complete, flow areas through the tool more than double. This results in a decreased stand pipe pressure between 200 to 250 psi noticeable at the surface. These are positive signs to the operator that cut-out is complete. Weight can now be set on the tool to start milling. The Flo-Tel system provides maximum cutting force against the casing during cut-out.

Downhole Milling 7

Schematic of Staged Knife Opening

Higher pressure against casing for cut-out

Pressure drop for milling

Six cutter knives – three for cut-out, six for milling

Downhole Milling8

K-Mill Series NumberGPM Range Required

During Cut-out During Milling3600* 110 - 160 110 - 160

4100 80 - 125 110 - 160

4500 80 - 125 150 - 200

5500 80 - 125 200 - 250

6100 80 - 125 200 - 250

7200** 80 - 125 200 - 300

8200** 80 - 125 300 - 400

9200** 80 - 125 350 - 450

11700 350 - 450 350 - 600

** Does not have Flo-Tel option.** Jetted top sub is required for flow rates exceeding 300 GPM in order to minimize

excessive velocity through piston which could result in erosion and/or washout.

General Suggestions for Effective Section MillingIt is important that the mill completely cut through the casing so the blades can be firmly seated on the casing. When operating a section mill without a Flo-Tel, prolong the initial cut-out operation to ensure complete cut through. Note: Without Flo-Tel there will not be a 200 to 250 psi indication at surface

once cut-out is achieved.

If you suspect the casing to be corroded, use lower weights with increased RPM.

If you experience a sudden drop off in the milling rate, the decrease may be the result of a loose ring of steel from the casing coupling. This ring will rotate with the section mill, preventing the mill from cutting properly. Try spudding the section mill gently. This should break up the ring and help position it for milling.

Recommended Procedure for Milling a SectionRun in the hole to the desired depth of cut-out.

Pump rates for the K-Mill are predetermined and depend on tool size. Therefore, the correct GPM must be selected to produce the desired pres-sure drop through the K-Mill, assuring good tool operation. To determine the best GPM, see the following table.

Flow Rates

Downhole Milling 9

Start rotation at 60 RPM and build pressure slowly until cut-out GPM is achieved. Keep rotating until the pipe has been severed, as indicated by the Flo-Tel (approximately 200 to 250 psi pressure drop). After the cut has been completed, increase GPM to recommended milling flow rate.

Now start applying weight and increase the rotational speed to 80 to 120 RPM. The most efficient weight range is normally 4,000 to 8,000 lb.

Once the section is milled, or when the knives are worn out, circulate for five to ten min. This will ensure proper closure (hydrostatic equalization). You may pull the tool into the shoe and trip out in the conventional manner.

Difficulties Encountered in Cutting OutThe most common cause of difficulties in cutting out is insufficient pressure at the tool. Approximately 300 psi is the minimum necessary to keep the cutting knives open and part the casing.

Excessive pump surging in the drillstring, with subsequent “yo-yoing” of the pipe, may cause the blades of the mill to try to part the casing over a considerable interval.

Lost circulation material, pieces of drill pipe rubbers or other substances may block the orifice of the tool, causing the mill to function improperly and delay cut-out.

Watch the shaker for cuttings. Good cutting return is essential or problems can develop. Periodic hole sweeps at two- to three-hour intervals are rec-ommended in order to aid cutting lift.

Downhole Milling10

M-i SwACo ReCoMMenDAtion foR MuD PReP PRioR to SeCtion Milling

MudXC (xanthan gum)-treated polymer muds are preferred due to their high viscosity at low shear rates. These XC polymer muds have good plastic vis-cosity to yield point ratios (usually 0.50:1 or better). Partially Hydrolyzed Poly Acrylamide (PHPA) polymer muds are not recommended for milling due to the rapid shear degradation of the viscosity.

While the plastic viscosity to yield point ratio is often specified to be be-tween 0.75 to 0.50 to 1, more meaningful parameters to monitor are the 3-RPM Fann reading and initial gel strength. M-I recommends the 3-RPM Fann reading and gel strength to be between one to two times the hole size in inches.

Clay-base systems are also acceptable if the 3-RPM value and initial gel are kept in this one to two times hole size (in.) range. Clay-base milling fluids usually require a XC polymer-type additive to achieve these levels of viscosity or must be flocculated with lime, a polymer (like PHPA or GELEX), or with a Mixed Metal Hydroxide (MMH)-type product.

Oil-base muds are usually not recommended for milling because it is more difficult to obtain this level of 3-RPM and initial gel. Oil-base fluids require a rheology modifying additive and higher water contents for this purpose.

Mud PropertiesMaintain in the 3-RPM Fann and initial gel strength readings between one to two times the hole size in inches. This level of low shear viscosity should give a plastic viscosity to yield point ratio between 0.50 and 0.75. This value should not be allowed to go over 0.75.

Flow RateA flow rate capable of producing an annular velocity between 250 and 350 ft/min. is recommended for all milling operations. This is similar to the 35 to 50 GPM times casing ID (in.) recommendation. A bypass jet (jetted top sub) may be required for higher flow rates to reduce the risk of washout or cavitation. Remember that it is the combination of high annular velocity and high viscos-ity which provides hole cleaning when milling; if the viscosity needs to be increased, so does the velocity.

Downhole Milling 11

Hole SweepsPeriodic high viscosity sweeps should be used on a frequent basis depend-ing on milling rate and cutting size to prevent shavings from accumulating in the well. Lost Circulation Materials (LCMs) are also beneficial for these sweeps due to mechanical lifting capability of fiberous materials. While fiberous LCMs like cottonseed hulls or cane fiber work best, granular LCMs like nut plugs are also effective.

flow guiDelineS foR MillMASteR SySteM toolS

Total Flow Area (TFA) Fixed piston ID = .442 TFA equivalent

Fluid VelocityMaintain internal piston velocity at 150 to 200 ft/sec. Piston cavitation in longer section milling intervals will occur at velocities over 200 ft/sec.

GPM RateGPM flow rates from 35 to 50 times casing ID is a good rule of thumb. However, since velocity is a function of flow rate (GPM) and TFA (fixed at .442 in.2), the flow rates must be adjusted so as not to exceed the maxi-mum velocity stated above.

Pressure DropMaintain pressure drop (∆P) at 200 to 500 psi across piston; higher values can be used for short milling intervals only.

MudPolymer muds would be a first choice and clay-base muds would be sec-ond. Most oil-base muds have inferior steel cutting carrying capabilities, which can cause serious hole cleaning problems and bird nest accumula-tion. When lease water is used, gel additives will provide some lift for the steel cuttings. In this situation, extra rathole to fall cuttings is an option when environmentally possible.

Hole SweepsPeriodic gel sweeps or even LCMs such as walnut hulls, etc., and working the pipe every two to three hours will minimize cutting accumulation.

Downhole Milling12

StAnDARD MillMASteR BhA ReCoMMenDAtionS1. Guide mill (dressed approx. 1/2 to 1 in. under drift diameter)

• Verify through Automated Bottom Hole Assembly Profile (ABHAP) analysis, no touching of casing ID allowed.

2. Millmaster (stabilizer sleeve dressed to casing drift diameter)• Straight hole vs. angle hole diameters may vary slightly. Verify through

ABHAP analysis.3. Millmaster top sub and float sub or Millmaster top sub with box-up con-

nection bored for float4. Pony collar at eight to ten ft. long

• Make-up in shop with lifting sub to save rig time.5. Drill collars

• Quantities based on size and weight of casing to be milled.6. Stabilizer

• Use in holes with maximum 15 degree angles; verify through ABHAP analysis.

• Use a milling-type stabilizer staged so it will always remain in upper casing stub.

7. HWDP• Enough joints to accommodate normal transition to/from drill pipe.

8. Drill pipe

Downhole Milling 13

Casing and K-Mill Correlation - API Casing

Note: All dimensions are given in inches unless otherwise stated.

Casing Specifications K-Mill Specifications

Casing Size

Casing Coupling Dia. OD

Wt. per ft. with

Coupling (lb.)

ID of Casing

Casing Drift ID

Tool Series Max.

Collapse Dia.

Knife Dressed

Open Dia.

Stop StabilizerBody

Dia.

41⁄2 5.0009.5011.6013.50

4.0904.0003.920

3.9653.8753.795

3600 33⁄433⁄435⁄8

55⁄855⁄851⁄2

37⁄837⁄833⁄435⁄8

5 5.563

11.5013.0015.0018.00

4.5604.4944.4084.276

4.4354.3694.2834.151

4100 41⁄441⁄841⁄8

4

65⁄1663⁄1663⁄1661⁄16

43⁄841⁄441⁄441⁄841⁄8

51⁄2 6.050

13.0014.0015.5017.0020.0023.00

5.0445.0124.9504.8924.7784.670

4.9194.8874.8254.7674.6534.545

450043⁄443⁄445⁄845⁄841⁄243⁄8

77⁄1677⁄1675⁄1675⁄1673⁄1671⁄16

47⁄847⁄843⁄443⁄845⁄841⁄2

41⁄2

6 6.625

15.0018.0020.0023.00

5.5245.4245.3525.240

5.3995.2995.2275.110

450051⁄451⁄8

547⁄8

715⁄16713⁄16711⁄1679⁄16

53⁄851⁄451⁄8

541⁄2

65⁄8 7.390

17.0020.0024.0028.0032.00

6.1356.0495.9215.7915.675

6.0105.9245.7965.6665.550

550057⁄853⁄455⁄851⁄253⁄8

811⁄1689⁄1687⁄1685⁄1683⁄16

657⁄853⁄455⁄851⁄251⁄2

7 7.656

17.0020.0023.0026.0029.0032.0035.0038.00

6.5386.4566.3666.2766.1846.0946.0045.920

6.4136.3316.2416.1516.0595.9695.8795.795

5500 61⁄461⁄8

66

57⁄853⁄453⁄455⁄8

91⁄16815⁄16813⁄16813⁄16811⁄1689⁄1689⁄1687⁄16

63⁄861⁄461⁄861⁄8

657⁄857⁄853⁄4

51⁄2

Downhole Milling14

Casing and K-Mill Correlation - API Casing (continued)Casing Specifications K-Mill Specifications

Casing Size


Wt. per ft. with

Coupling (lb.)

ID of Casing

Casing Drift ID

Tool Series Max.

Collapse Dia.

Knife Dressed

Open Dia.

Stop Stabilizer

Body Dia.

7 7.656

17.0020.0023.0026.00

6.5386.4566.3666.276

6.4136.3316.2416.15 1

6100 61⁄461⁄867⁄867⁄8

91⁄16

815⁄16

813⁄16

813⁄16

63⁄861⁄461⁄861⁄861⁄8

75⁄8 8.500

20.0024.0026.4029.7033.7039.00

7.1257.0256.9696.8756.7656.625

7.0006.9006.8446.7506.6406.500

550067⁄863⁄465⁄865⁄861⁄263⁄8

911⁄16

99⁄16

97⁄16

97⁄16

95⁄16

93⁄16

73

67⁄863⁄463⁄465⁄861⁄2

51⁄2

75⁄8 8.500

20.0024.0026.4029.7033.7039.00

7.1257.0256.9696.8756.7656.625

7.0006.9006.8446.7506.6406.500

610067⁄863⁄465⁄865⁄861⁄263⁄8

911⁄16

99⁄16

97⁄16

97⁄16

95⁄16

93⁄16

73

67⁄863⁄463⁄465⁄861⁄2

61⁄8

85⁄8 9.625

24.0028.0032.0036.0040.0044.0049.00

8.0978.0177.9217.8257.7257.6257.511

7.9727.8927.7967.7007.6007.5007.386

720073⁄473⁄475⁄871⁄273⁄873⁄871⁄4

115⁄8115⁄8117⁄16

115⁄16

113⁄16

113⁄16

111⁄16

77⁄877⁄873⁄475⁄871⁄271⁄273⁄8

71⁄4

95⁄8 10.625

29.3032.3036.0040.0043.5047.0053.50

9.0639.0018.9218.8358.7558.6818.535

8.9078.8458.7658.6798.5998.5258.379

720083⁄485⁄885⁄881⁄283⁄883⁄881⁄4

1211⁄16

129⁄16

129⁄16

127⁄16

125⁄16

125⁄16

123⁄16

87⁄883⁄483⁄485⁄881⁄281⁄283⁄8

71⁄4


Downhole Milling 15

Casing and K-Mill Correlation - API Casing (continued)


Casing Specifications K-Mill Specifications

Casing Size


Wt. per ft. with

Coupling (lb.)

ID of Casing

Casing Drift ID

Tool Series Max.

Collapse Dia.

Knife Dressed

Open Dia.

Stop Stabilizer

Body Dia.

95⁄8 10.625

29.3032.3036.0040.0043.5047.0053.50

9.0639.0018.9218.8358.7558.6818.535

8.9078.8458.7658.6798.5998.5258.379

820083⁄485⁄885⁄881⁄283⁄883⁄881⁄4

125⁄8127⁄16

127⁄16

125⁄16

123⁄16

123⁄16

121⁄16

87⁄883⁄483⁄485⁄881⁄281⁄283⁄8

71⁄4

103⁄4 11.750

32.7540.5045.5051.0055.50

10.19210.0509.9509.8509.760

10.0369.8949.7949.6949.604

9200 97⁄893⁄495⁄891⁄293⁄8

133⁄4135⁄8137⁄16

135⁄16

133⁄16

103

97⁄893⁄495⁄891⁄291⁄4

113⁄4 12.750

38.0042.0047.0054.0060.00

11.15011.08411.00010.88010.772

10.99410.92810.84410.72410.616

9200 103⁄4103⁄4105⁄8101⁄2103⁄8

1411⁄16

1411⁄16

149⁄16

147⁄16

145⁄16

107⁄8107⁄8103⁄4105⁄8101⁄291⁄4

133⁄8 14.375

48.0054.5061.0068.0072.00

12.71512.61512.51512.41512.347

12.55912.45912.35912.25912.191

11700 123⁄8121⁄4121⁄8121⁄812

1711⁄16

179⁄16

179⁄16

177⁄16

175⁄16

121⁄2123⁄8121⁄4121⁄4121⁄8113⁄4

16 17.000

55.0065.0075.0084.00

15.37515.25015.12515.010

15.18715.06214.93614.822

11700 15147⁄8143⁄4145⁄8

191⁄2193⁄8191⁄4191⁄8

151⁄815

147⁄8143⁄4113⁄4

Downhole Milling16

Section Planning for SidetrackingIn preparation for milling sections, the following should be reviewed:• If a formation log is available and there is a choice of where to cut your

section, a section cut in a sand formation will normally result in fewer problems than one that is cut in a shale formation.

• First, a plug will have to be set to isolate the old well.• A bond log is preferred to determine if cement is behind the casing to be

milled. If you are not sure of a good cement, you should plan to block squeeze the section.

• Never start just below a casing collar.• Plan an extra rathole (100 to 150 ft.) below the section:• - This extra length may be needed during milling if cutting removal be-

comes a problem.• - It can be used to block squeeze if needed.• Polymer muds are best for milling since they have reduced PV/YP ratios

and can be maintained as close to 0.5 as possible.• Clay-base muds have good carrying capabilities but result in more

troublesome jobs and, therefore, should be avoided when possible.• Oil-base muds have poor cutting carrying capabilities and result in more

troublesome jobs and, therefore, should be avoided when possible.The length of section needed will depend upon the following:• Type of well plan and objective.• The necessary rate of build.• Type of deflection tool used.

Properties and Flow RatesThe fastest way to remove steel cuttings from the hole is with a turbulent flow. Turbulent flow, however, can also be the fastest way to get into trouble due to:• Bird nesting of the cuttings.• Loading of the hole creates turbulent flow due to the restriction caused

by cuttings in the annulus.• - This is especially critical at the beginning of the section where the drill

collars are still inside the casing. Laminar flow increases slip velocity, causing particles to fall through the mud and fill up the lower stub.

• - Small adjustments in the flow rate, rotary speed and weight-on-tool can be made while carefully monitoring the returns from the size, shape and thickness.

Underreaming for Sidetrack PlugUnderreaming may be required (especially in small casing sizes) to allow for a large plug to be set.

The cement for the plug has to be calculated to allow for correct displace-

Downhole Milling 17

ment of the lower stub, the open hole in the section area and at least 100 ft. of cement inside the casing above the section. This is needed to allow the operator to test the plug and dress off the top contaminated part of the plug before starting the sidetrack.• The cement plug must be hard enough to perform the sidetrack.• The cement in the section area must have a uniform consistency.• It has to be large enough to prevent going off the side of the plug and

creating a sharp dogleg.

Trip in hole with a bit to dress off and test the plug after approximately 16 hours. A minimum of three ft. into the section should be drilled before picking up the mud motor and directional assembly.

Using the K-Mill as a Pipe CutterThe K-Mill is very effective in cutting single strings of casing. The efficiency of the knives in conjunction with the Flo-Tel feature ensures optimum results.

Cutting the Pipe• Pick up the tool and run in hole to cutting depth.• Start rotary speed at 80 to 100 RPM; note torque.• Start pump slowly and increase volume and pressure until you notice a

reaction at the rotary or torque (amps) increases significally.• Maintain a rotary speed of 80 to 100 RPM.• When cut is complete, there is a definite indication — a momentary loss of

returns or an increase of mud in the annulus. Quite often excessive noise will indicate when the casing is parted.

• The loss of torque, a decrease in pump pressure, or both, are indications the cut has been completed.

• Shut off pumps.• Stop rotary.• Pull out the hole.

K-Mill Disassembly• Remove top sub.• Remove Flo-Tel assembly. (Note: Flo-Tel not available for 3600 Series.)• Remove arm-stop stabilizers.• Remove hinge pins.• Remove the knives. Do not remove lugs.• Using wrenches furnished in tool kit, remove cam locknut and cam.• Piston and spring may not be withdrawn from the body.• Remove piston head retaining screws.• Remove orifice and anti-wash tube from piston ID. Note: The 3600, 4100 and 4500 Series tools, due to the restricted piston diam-

eter, do not have an anti-wash tube. Remove orifice O-ring.

Downhole Milling18

Body

Arm stop body stabilizerCam lock nut

Cam

Piston

Anti-wash tube

Orifice

Spring

O-ring

Flo-Tel tensions screw

Cone cap

Hinge pin retaining screw

Retaining screw

Milling knife

Arm hinge pin

Lug

Piston head retaining screw

Piston packing

Piston head

Flo-Tel assembly

Top sub

K-Mill Components

Downhole Milling 19

Service Instructions• The tool should be thoroughly cleaned after completion of each job.

Steam cleaning is best. When not available, cleaning solvents may be used. All packing should be inspected after cleaning and replaced if any wear is visible.

• When the tool is reassembled, all parts should be thoroughly lubricated. Any light grease is suitable.

Assembly• Replace the Flo-Tel orifice (complete with packing) into the piston after

sliding the anti-wash tube into place. Note: The 3600, 4100 and 4500 Series tools do not have anti-

wash tubes.• Replace the piston packing and piston head. Secure the piston head to piston with the piston head retaining screws. Make up firmly. Make sure the V-type lips of the packing are face up.• Place spring over piston and slide assembly into the body.• Using wrenches furnished on tool kit, make cam up firmly on the piston.• Make up cam locknut firmly to prevent backing off.• Assemble Flo-Tel loosely:

• - Place stinger in seat.• - Place bail on cone cap.• - Align holes in seat and cone cap and start threads of the tension screws.

Do not make screws up tightly at this point, as this will expand the bail and the assembly will not enter the body.

• - Slide the Flo-Tel assembly into the body. The bail will snap into place when properly positioned.

• - Tighten tension screws firmly. This expands the bail into its mating groove in the body and locks the assembly into its proper place.

• Install new knives, hinge pins and hinge pin retaining screws.Note: The spare knives are packaged complete with hinge pins and retaining

screws. Do not attempt repeated use of these items.• Install and tighten arm-stop body stabilizers.

Downhole Milling20

Nominal overall length

Fishing neck length

Top pin connection

Body diameter

Fishing neck

diameter

K-Mill

Downhole Milling 21

Section Mill Specifications

Tool Series

Casing SizesBodyDia.

Fishing Neck

Length

Fishing NeckDia.

Overall Length

Top Pin Conn.

Wt.(lb.)

3600 41⁄2 35⁄8 18 31⁄8 56 23⁄8 135

4100 5 41⁄8 18 31⁄4 66 23⁄8 175

4500 51⁄2, 6 41⁄2 18 41⁄8 70 27⁄8 220

5500 65⁄8, 7 51⁄2 18 43⁄4 74 31⁄2 350

6100 75⁄8 61⁄8 18 43⁄4 74 31⁄2 368

7200 85⁄8, 95⁄8 71⁄4 18 53⁄4 89 41⁄2 554

8200 95⁄8 81⁄4 18 53⁄4, 8 87 41⁄2, 65⁄8 900

9200 103⁄4, 113⁄4 91⁄4 18 53⁄4, 8 87 41⁄2, 65⁄8 980

11700 133⁄8, 16 111⁄2 18 8, 9 90 65⁄8, 75⁄8 1,725

Notes:1. All dimensions are given in inches

unless otherwise stated.2. All weights are approximate.3. Standard API regular pin connections.

Others available upon request.4. Flo-Tel is standard equipment for

4100 through 11700 Series.

Ordering Instructions:When ordering or requesting quotations on section mills, please specify:1. Tool series2. Size and weight of casing to be milled 3. Top pin connection

Downhole Milling22

Pilot Mill

Downhole Milling 23

Pilot MillSPilot mills are recommended for milling washpipe, safety joints, crossover swages and washover shoes. Liner hangers can be milled efficiently, elimi-nating inside cuts and running spears. The nose, or pilot, can be dressed to mill out junk which may be encountered.

Pilot mills can be used to mill:• Adapters • Casing • Liners• Washpipe • Drill pipe • Swaged casing

General Guidelines for Using Pilot MillsIn selecting a pilot mill, the blade OD should be about 1 ⁄4 in. larger than the OD of the tool joint or coupling to be milled. The pilot OD should be the same as the drift diameter of the tubular.

The best speed and weight to run a pilot mill must be determined for each job. Also, conditions may change from one pilot milling job to the next in the same well.

This may require different speeds and weights at different times. In the absence of experience, start with a rotary speed between 80 and 100 RPM and a tool weight of 2,000 to 6,000 lb. or less.

If when milling swaged casing a sudden drop-off in milling rate occurs, the trouble may be caused by a loose ring of steel formed at a joint or weld which is turning with the pilot mill. Try spudding the pilot mill gently. This should break up the ring and help position it for milling.

If cutting stops altogether when milling washpipe, casing or liner, and there is no noticeable increase in torque, there is a good chance a section of the casing or tubular is turning. If this is the case, pull the mill and attempt retrieval using a spear.

Considerations When Milling Liner Hangers and AdaptersOn most liner milling jobs, a pilot mill is used to first mill the liner hanger or adapter, and then the liner. In some cases the liner hanger or adapter is milled using a junk mill. Then the liner is milled with a pilot mill. This latter method is preferred if there is hard cement behind the liner or if the liner has numerous bow-springs, slips, etc.

A Pilot Mill is Ideal for WashpipeThe pilot mill is the most efficient tool for milling stuck washpipe. If drill pipe or collars are inside washpipe, however, they must first be milled with a junk or smaller pilot mill.

Downhole Milling24

Milling Drill Pipe and Drill CollarsIf the ID is open, drill pipe and collars are sometimes milled with pilot mills. If the drill pipe or collar is cemented inside the casing, particularly in deviated holes, the pipe is probably lying on the low side with its center eccentric to the casing. Most often this makes the job extremely difficult for a pilot mill. Under these conditions, we recommend a full gauge junk mill. A pilot mill will do a reasonable job on drill collars, provided the cuttings can be removed as the milling progresses. If cuttings tend to fall into the ID and plug it, then a junk mill must be used.

Using the Pilot Mill in Swaged CompletionThe pilot mill is ideally suited to mill out the necked-down portion of casing in swaged completion. Necked-down lengths of casing, corre-sponding in length to the thickness of the producing zones, are made up with swages to the regular casing collars in the string. The casing is cemented and water shutoff is obtained at all zone intervals. The necked portions are then milled out with a pilot mill and the resulting sections are opened with an underreamer. This underreaming opera-tion removes cement and wall cake, providing a clean producing area.

Using a Pilot Mill1. Lower the mill about five in. above the tubular. Set the brake and

start rotating. Slowly increase rotation to 125 RPM. Raise and lower the mill three to six ft. but do not touch the tubular while rotat-ing. This action will show the neutral torque to be determined. By noting the torque in the string when the pilot of the mill enters the tu-bular, you can determine if the pilot has been entered properly.

2. Reduce rotation to about 30 RPM and enter the pilot into the tubular. Apply 2,000 lb. of weight. Stop rotation quickly while you note the torque action of the string. A gradual slow down or spin indicates that the mill has entered the tubular with proper alignment.

Downhole Milling 25

3. To mill H-40 or K-55 casing, use a weight between 4,000 and 6,000 lb. and a speed of 80 to 100 RPM, whereas N-80, P-110 and Q-135, etc. casing requires a weight of 8,000 to 10,000 lb. and a RPM of 100 to 120. If the casing is surrounded by hard cement, or if the open hole diameter is the same or less than the blade OD of the mill, more weight may be needed to drill cement and formation. When working below the shoe of the casing, ream the hole up and down after every 15 to 20 ft. of tubular milled to clean out any accumulation of cuttings which may have collected at the shoe. Periodic reaming to ensure cutting removal is also a good practice in holes with deviation of 30 degrees or more.

4. Normally, milling should be continued at an even rate without interruption once it has been started. Milling weight should be applied at a constant rate. Do not allow weight to drilloff.

Fishing neck diameter

Top pin connection

Blade diameter

Pilot diameter

Fishing neck length

Pilot Mill

Downhole Milling26

Blade Dia.

Pin Conn. API Reg.

Pilot Dia.Overall Length

Fishing Neck

Length

Fishing Neck Dia.

Wt. (lb.)

31⁄4 - 137⁄8 23⁄8 13⁄4 - 123⁄4 27 12 31⁄ 40

41⁄8 - 143⁄8 23⁄8 13⁄4 - 123⁄4 27 12 31⁄8 45

41⁄8 - 153⁄8 27⁄8 21⁄8 - 131⁄4 27 12 33⁄4 120

51⁄2 - 155⁄8 31⁄2 21⁄2 - 143⁄4 38 16 41⁄4 240

53⁄4 - 173⁄8 31⁄2 21⁄2 - 143⁄4 38 16 43⁄4 255

61⁄8 - 197⁄8 41⁄2 43⁄4 - 163⁄4 42 18 53⁄4 305

97⁄8 - 171⁄2 65⁄8 73⁄4 - 15 45 18 73⁄4 550


unless otherwise stated.2. All weights are approximate.3. Standard API regular pin.

Other sizes available upon customer request.

Ordering Instructions:When ordering or requesting quotations on pilot mills, please specify:1. Size and weight of casing to

be milled2. Size and weight of casing to

be run through, if available3. Top pin connection

Pilot Mill Specifications

Downhole Milling 27

Piranha Mill™

Millmaster

Millmaster-dressed Piranha Mills are only avail-able on a rental basis in conjunction with Smith job supervision.

U.S. Patent Numbers: Carbide Insert Milling Tool – 4,710,074 Piranha Mill – 5,074,356

Carbide inserts

Downhole Milling28

PiRAnhA MillThe Piranha Mill is a tool which has been solely designed for the efficient removal of downhole casing strings. Millmaster technology ensures maxi-mum ROP, ideal cutting size and extended milling duration.

Offshore Slot RecoveryToday, many fields are either reaching the end of their useful lives or are beyond the break-even point for production. Smith has worked closely with many major oil companies and their engineering divisions to develop a platform slot recovery system.

This system provides an economical method to re-drill non-producing wells to a new target. Abandonment is eliminated by recovering existing slots.

The main objective is the successful removal of the intermediate casing strings back to the surface string/conductor pipe. Depending on the quality of the casing cement job, a combination of retrieval and milling operations are normally employed. Where casing strings are cemented back to the casing spools, milling must be used exclusively.

The need to remove the intermediate string of casing is carried out to ex-pose a clear string of conductor pipe and formation around the shoe. This allows the well to be deviated as per normal practices.

Description of the Piranha Mill• The cutting structure consists of Millmaster carbide arranged in a brick

pattern. The carbide, being specially developed for downhole application, prevents premature wear and breakage.

• The blade is manufactured from high-grade alloy steel and positions the cutting edge at the precise angle for maximum cutting efficiency.

• Extended blade length provides maximum footage per mill.

Slot Recovery Operating ParametersAs with all types of downhole milling, some specific guidelines must be followed to obtain optimum performance from the tool. The Millmaster cutting structure differs in its requirements from the “conventional” crushed tungsten carbide type.• The two major components to be considered when deciding on param-

eters are RPM and weight-on-bit. The rotary speed is calculated as found on page 3 of the Data Handbook using the optimum cutting surface speed for tungsten carbide (250 to 340 ft/min.) vs. the outside diameter of the casing.

• The effective milling weights for the Piranha have been found to be in the range of 5,000 to 10,000 lb.

Downhole Milling 29

Mill Stability• Stabilization is necessary to optimize the overall performance of the Pira-

nha. An Ezy-Change™ sleeve-type stabilizer is included in the tool’s de-sign. This allows the stabilizer to be changed at the rig site. Interchange-ability is important, especially when milling eccentric casing strings.

• In deviated hole sections, or where a casing string has been forced to one side, the blade design will not skin the next casing string.

• Included in the stabilization is a standard taper mill, running directly ahead of the Piranha Mill and a stabilizer the same diameter as the Piranha Mill run immediately above the Piranha Mill. The taper mill is used to give the assembly the capability of clearing any junk or enlarging the stub of the casing. The OD and stabilization diameter is calculated to prevent damage to outer casing strings.

Tool Series

Casing Sizes

Body Dia.

Blade Dia.

No. of Blades

Top Pin Conn.Fishing Neck

Length

Fishing Neck Dia.

Overall Length

Wt. (lb.)

4500 41⁄2 43⁄4 5.250 3 31⁄2 IF BU 12 43⁄4 36 100

5000 51⁄2 43⁄4 5.813 3 31⁄2 IF BU 12 43⁄4 36 110

5500 51⁄2 43⁄4 6.300 3 31⁄2 IF BU 12 43⁄4 36 120

6000 61⁄2 43⁄4 6.875 3 31⁄2 IF BU 12 43⁄4 42 150

6600 65⁄8 53⁄4 7.640 3 41⁄2 IF BU 12 53⁄4 42 175

7000 71 53⁄4 7.906 3 41⁄2 Reg. BU 12 53⁄4 42 190

7600 75⁄8 61⁄4 8.750 5 41⁄2 IF BU 18 61⁄4 48 250

8600 85⁄8 63⁄4 9.875 5 51⁄2 Reg. BU 18 63⁄4 48 275

9600 95⁄8 81⁄2 10.875 5 65⁄8 Reg. BU 18 81⁄2 60 300

10700 103⁄4 91⁄2 12.000 5 75⁄8 Reg. BU 18 91⁄2 60 325

11700 113⁄4 101⁄4 13.000 5 85⁄8 Reg. BU 18 101⁄4 60 375

13300 133⁄8 111⁄2 14.625 5 85⁄8 Reg. BU 18 111⁄2 72 400

16000 161⁄2 141⁄2 17.250 5 85⁄8 Reg. BU 18 141⁄2 72 425


unless otherwise stated.2. All weights are approximate.3. Pilot stabilization dressed to casing

drift diameter.4. Guide mill or taper mill dressed to

casing drift diameter.5. Ezy-Change II stabilizer sleeve avail-

able on casing sizes 75⁄8 in. and larger.

Ordering Instructions:When ordering or requesting quotations on Piranha Mills please specify:1. Tool series2. Size and weight of casing to be milled3. Top pin connection

Piranha Mill Specifications

Downhole Milling30

Conventional

Conebuster

Super

Junk Mill

Dressing Options

Downhole Milling 31

JunK MillingThe junk mills chew their way through the toughest materials. Junk mills are said to be the true workhorse of downhole milling operations.

When drill pipe is cemented inside and out, a junk mill is the only tool that will do the work. However, if the drill collars or drill pipe are not collapsed and the ID is open, a pilot mill can sometimes be used to better advantage.

When casing has been milled with a pilot mill or section mill to the point where it begins to rotate, it can often be pounded down and milled using a junk mill made up at the end of a joint of slightly eccentric or bent drill pipe.

Junk mills can be used to mill almost anything in the hole, including cement and rubber products.

Junk Milling Procedures1. Tag bottom and pick up three ft. Begin circulating as for normal drilling

conditions.2. Begin rotation at 60 to 80 RPM.3. Apply weight at 4,000 RPM.4. If there is an indication junk may be turning, spud two or three times.5. After milling one to two ft., pick up the kelly 15 to 20 ft. off bottom

and reduce pump pressure or shut off pumps (depending on hole condi-tions). This action will let the loose junk settle to the bottom.

6. Once again feel for the bottom and spud. Begin rotation at 80 to 100 RPM using normal pump pressure. Begin weight at 4,000 to 6,000 lb.

7. Repeat steps three and four every few feet. Procedures from here on will be governed by feel.

Note: In hard formation it will take fewer feet of the hole to mill up the junk than in softer formation. This difference is due to the junk’s ability to lodge itself into the softer formation.

General GuidelinesWhen milling loose junk, operations can be improved by frequent spud-ding. This action will pound the junk onto the bottom, positioning it for more effective milling.

Never permit a sliver or piece of junk to lodge next to the mill. Force it down by spudding the mill. A noticeable increase in torque will indicate that a sliver or piece of junk is alongside the mill. Picking up the mill and lowering it periodically will decrease the possibility of a deep wear pattern develop-ing, thus evening the wear on the mill face.

When milling cast-iron bridge plugs, the mill OD should be approximately 1 ⁄8 in. under the size of the bridge plug — this will prevent “skinning” the casing.

Downhole Milling32

Loose Junk in Open Hole• Use a junk mill with an OD of 1 ⁄8 in. less than hole diameter.• Use at least 10,000 lb. of drill collars.• Run a junk sub directly above the mill. In soft formation consider the use

of a Junk Master to prevent inadvertant sidetracking.Note: Junk subs for 43 ⁄4 in. along with smaller drill collars are not strong

enough for repeated spudding.• Frequent spudding improves milling efficiency on loose junk. To spud the

junk and force it down, proceed as follows:1. Determine the neutral or zero point. Mark the kelly at the top

of the kelly bushing.2. Pick up the kelly four to six ft. (four ft. in shallow holes, six ft. in deeper

holes).3. Drop the kelly and catch (not slow down, but catch it) with the brake

about 18 to 20 in. above the zero mark. (Example: Pick up ten ft. and drop it 81⁄2 ft.) This action causes the drillstring to stretch and spud the junk on bottom with great force while the string is still in a state of ten-sion. This prevents damage to the string which might be expected if the string is in compression at the moment of impact.

4. Spud the junk three or four times, turning the mill a quarter-turn each time between drops.

Stationary Junk in Open Hole• Use a junk mill with a diameter about 1 ⁄8 in. less than the hole diameter.• Mill with 4,000 to 10,000 lb. of weight, depending upon the strength of

the junk being milled.• After three to five ft. of junk milled, pick up the mill ten to 15 ft. and ream

the hole down to the junk.• After reaming the hole down, always set down on the junk while turning

and bring the weight up to milling weight. Never apply weight first and then start rotating.

Loose and Stationary Junk in Open HoleProcedures for running a junk mill inside the casing are the same except for the following:• Run a stabilizer directly above the mill which has the same OD as the

mill.• The mill head OD should be the same as the drift diameter of the casing.• Wear pads having the same OD as the diameter of the mill head are

provided on the junk mill. These will eliminate possible damage to the casing.

Downhole Milling 33

Fishing neck

diameter

Top pin connection

Fishing neck

length

Dressed diameter

Junk Mill

Downhole Milling34

Junk Mill Specifications

StandardCutting Dia.

Top Pin Conn API Reg.

Junk Mill and Cone

Buster

Overall LengthFishing

Neck Dia.Wt. (lb.)Super

Junk Mill

Fishing Neck

Length31⁄2 - 41⁄2 23⁄8 20 20 12 3 45

41⁄2 - 51⁄2 27⁄8 21 21 12 33⁄4 62

51⁄2 - 55⁄8 31⁄2 23 21 12 41⁄4 95

53⁄4 - 71⁄2 31⁄2 23 21 12 43⁄4 105

71⁄2 - 9 41⁄2 27 27 12 53⁄4 180

91⁄2 - 121⁄4 65⁄8 29 29 12 73⁄4 350

13 - 15 65⁄8 or 75⁄8 30 30 12 73⁄4 or 91⁄2 500

17 - 171⁄2 65⁄8 or 75⁄8 33 33 12 73⁄4 or 91⁄2 625

181⁄2 - 26 65⁄8 or 75⁄8 37 37 12 73⁄4 or 91⁄2 1,200

Notes:1. All dimensions are given in inches unless otherwise stated.2. All weights are approximate.

Ordering Instructions:When ordering or requesting quotations on junk mills, please specify:1. Mill diameter2. Size and weight of casing to be run through, if available3. Top connection

Downhole Milling 35

Junk Sub

Bore diameter

Body diameter

under sleeve

Sleeve length

Mud bleed holes

Bottom box connection

Body diameter

Top pin connection

Fishing neck

diameter

Downhole Milling36

JunK SuBSJunk subs capture and trap junk too heavy to circulate. They are designat-ed to be used in the drill collar string just above the rock bit or milling tool. The tool consists of a steel mandrel with an oversized sleeve or “skirt” at-tached over the mandrel. The “skirt” is welded at the lower end. The “skirt” will trap the large cuttings and junk which are too heavy to be circulated out the hole. The “skirt” is manufactured with bleed holes to allow the mud to drain once it is brought out of the hole. It is recommended that two junk subs be run in tandem to decrease the possibility of junk bypassing a single junk sub. A stabilizer should be run above the junk subs to reduce bending through their bodies.

Junk Sub Specifications

Body Dia.Top and Bottom Conn.

Overall Length

Fishing Neck Dia.

Body Dia. Under Sleeve

Bore Dia.

Sleeve Length

Wt. (lb.)

35⁄8 23⁄8 33 31⁄16 2 1 12 50

4 23⁄8 33 31⁄2 21⁄2 11⁄4 12 62

4 27⁄8 37 35⁄8 21⁄2 11⁄4 12 66

41⁄2 27⁄8 37 37⁄8 21⁄2 11⁄4 12 91

5 31⁄2 38 43⁄8 31⁄4 11⁄2 12 120

51⁄2 31⁄2 38 45⁄8 31⁄4 11⁄2 15 144

61⁄2 41⁄2 48 57⁄8 41⁄2 2 15 261

65⁄8 41⁄2 48 57⁄8 41⁄2 2 15 270

63⁄4 41⁄2 48 57⁄8 41⁄2 2 15 280

7 41⁄2 48 6 41⁄2 2 15 298

81⁄2 65⁄8 50 71⁄2 53⁄4 213⁄16 15 438

85⁄8 65⁄8 50 71⁄2 53⁄4 213⁄16 15 451

95⁄8 65⁄8 50 81⁄2 53⁄4 213⁄16 15 529

103⁄4 75⁄8 51 95⁄8 75⁄8 3 15 806

123⁄4 75⁄8 51 115⁄8 75⁄8 3 15 1,065

Notes: 1. All dimensions are given in inches

unless otherwise stated.2. All weights are approximate.3. Standard API regular connections.

Other sizes and lengths available upon customer request.

Ordering Instructions:When ordering or requesting quotations on junk subs, please specify:1. Tool size2. Top and bottom connections

Downhole Milling 37

tAPeR MillSTaper mills are generally used to eliminate restrictions or to mill through “pinched” or collapsed casing. They are equipped with a tapered or a short blunt nose which serves as a guide. Smith offers a CP taper mill or a CT taper mill.

CP Taper Mill Designed for the Toughest Taper Mill JobThe CP taper mill features a blunt-nose design that makes it useful in those taper milling applications where the possibility of using a longer tapered nose might break. The CP mill generates considerably less torque than a conventional taper mill because of its shorter taper section. Because of this low-torque feature, the CP mill can be run with more weight when neces-sary.

CT Taper Mill Perfect for Milling RestrictionsThe CT taper mill was designed for milling through restrictions. The spiral blades and the pointed nose make the CT ideal for reaming out collapsed casing and liners, cleaning up permanent whipstock windows, milling through jagged or split shoes and enlarging restrictions through retainers and adapters.

CP

CT

Taper Mills

Downhole Milling38

General Guidelines for Using a Taper Mill• Start rotation at 75 RPM above the collapsed area.• Taper milling RPM is governed by torque. To overcome torque

problems, maintain at least 75 RPM.• Use less weight when running a taper mill than a junk or pilot mill. After

you have entered the collapse, increase the weight slowly from 1,000 to 2,000 lb. Watch for any torque increase.

How to Clean Up Whipstock Windows Using a Taper Mill1. Use a taper mill of the same diameter as the largest mill used

to mill the window (or slightly larger than the bit to be used).2. Run the taper mill into the hole to within five ft. from the top of

the window.3. Rotate slowly 40 RPM, down the full length of the whipstock.

Do not attempt to make hole using this tool.4. Keep weight under 1,000 lb. Excessive weight may cause the

taper mill to slip out of the window prematurely.5. To clean up all rough edges, repeat the above procedure

several times until the mill runs smoothly for the full length of the whipstock which is indicated by minimal torque.

Procedures for Reaming Out Collapsed Casing1. Determine the approximate diameter using a bit that will pass through

the collapsed interval. Do not use a taper mill if the collapsed interval has passed center.

2. Use a taper mill about 1 ⁄4 in. larger than the minimum ID of the collapse and mill out in stages. In other words, if the collapse is great, use several different sizes of mills to bring the ID of the pipe to full gauge. This will minimize any tendency to sidetrack.

3. A string taper mill can be used if there is any danger of sidetracking.

4. Begin milling at a table speed of about 50 RPM.5. The milling weight is governed by the torque encountered. In most

cases, milling weights of around 2,000 to 3,000 lb. are used.6. Where the pipe is greatly collapsed, the lower portion of the col-

lapsed interval may act as a whipstock. The taper mill, in this case, may cut through the upper portion of the collapsed interval and be deflected into the formation by the lower section of the dam-aged casing. In some cases of extreme collapsed pipe, it is bet-ter to run a stabilized, rigid hookup with a junk mill. Use very light weight with a table speed of about 125 RPM to mill out the col-lapsed portion and enter the undamaged casing below.

Downhole Milling 39

Enlarging Restriction Through Retainers and Adapters1. Use a taper mill with a diameter equal to the desired enlargement (usu-

ally the drift ID of the casing).2. Mill about 70 RPM and with weight from 2,000 to 6,000 lb. Both the speed

and the weight should be governed by the torque. If the torque is high, speed and weight should be reduced until the mill turns with minimal torque.

3. After milling through the restriction, increase speed to between 80 and 100 RPM. Rotate up and down through the interval several times until it is smooth and nearly torque free.

Using a Taper Mill to Ream Out Guide ShoesIn some cases, the bull plug on the bottom of liners or casing may be jag-ged or split to such degree that the string hangs up coming out of the hole. This condition can be remedied by reaming through the guide shoe with a taper mill. Follow the procedure recommended above for enlarging restric-tions through retainers and adapters.

Fishing neck

diameterTop pin

connection

CP

Fishing neck

diameter

Top pin connection

Fishing neck

length

Fishing neck

length

Dressed diameter

CTDressed diameter

CP/CT Taper Mill

Downhole Milling40

Dressed Dia.

Pin Conn. API Reg.

Overall Length

Fishing Neck

Length

Fishing Neck Dia.

Wt. (lb.)

CT CP CT CP

131⁄4 - 137⁄8 23⁄8 34 30 10 3 80 60

14 - 43⁄8 23⁄8 34 30 10 31⁄8 90 70

141⁄2 - 153⁄8 27⁄8 38 31 10 33⁄4 106 75

151⁄2 - 155⁄8 31⁄2 42 32 13 41⁄4 155 115

153⁄4 - 163⁄8 31⁄2 44 32 13 43⁄4 160 120

161⁄2 - 173⁄8 31⁄2 46 34 13 43⁄4 170 130

171⁄2 - 177⁄8 41⁄2 54 36 13 53⁄4 250 185

183⁄8 - 191⁄2 41⁄2 54 36 14 53⁄4 280 220

193⁄8 - 197⁄8 41⁄2 or 65⁄8 54 36 14 53⁄4 or 73⁄4 345 280

103⁄8 - 11 65⁄8 57 38 14 73⁄4 415 355

111⁄2 - 121⁄4 65⁄8 60 40 14 73⁄4 455 390

143⁄4 - 15 65⁄8 70 60 18 73⁄4 525 460

17 - 171⁄2 65⁄8 70 60 18 73⁄4 595 530

20 - 26 65⁄8 or 75⁄8 76 66 18 73⁄4 or 91⁄2 1,250 1,125

Notes: 1. All dimensions are given in inches unless otherwise stated.2. All weights are approximate.

Taper Mill Specifications

Downhole Milling 41

SPeCiAl MillS

EconomillEconomills are a low-cost alternative for light-duty milling jobs. Dressed with tungsten carbide, Economills are an effective tool for milling packers, retainers, bridge plugs and cement. Manufactured with standard API con-nections, the mill is made up and broken out with a standard bit breaker. No additional subs are required. Circulation is directed along each cutting blade and through the center of the head for proper cutting removal and cooling.

Stabilizing ribs immediately above the cutting blades prevents damage to the casing. Note: Economills are fabricated from a casting and should not

be used as junk mills. The cast products do not have the same material strength!

Top pin connection

Dressed diameter

Economill Specifications

Tool Series

Dressed Dia.

Top Pin Conn. API Reg.

Overall Length

Wt. (lb.)

Recommended Torque (ft/lb.)

3000 31⁄4 - 43⁄8 23⁄8 75⁄8 17 3,000 - 3,500

4000 41⁄2 - 53⁄8 27⁄8 85⁄8 26 6,000 - 7,000

5000 51⁄2 - 73⁄8 31⁄2 9 40 7,000 - 9,000

7000 71⁄2 - 83⁄4 41⁄2 111⁄2 76 12,000 - 16,000

10000 101⁄4 - 121⁄4 65⁄8 161⁄2 125 28,000 - 32,000


unless otherwise stated.2. All weights are approximate.

Ordering Instructions:When ordering or requesting quotations on Economills, please specify:1. Mill dressed diameter2. Size and weight of casing to be run

through, if available3. Protective subs available upon request

Downhole Milling42

DrillmillThe cast Drillmill is a rugged tubing mill designed for reaming hardened cement, sand and scale out of tubing or drill pipe with maximum efficiency, even when wireless and other light junk inside the tubing or pipe must be milled simultaneously. A wall contact area of three square inches ensures proper stabilization and eliminates possible damage to tubing or pipe walls

Drillmills are available for all sizes of tubing and drill pipe and can be supplied in a wide selection of drill rod tool joints.

Top pin connection

Wall contact area 3 in.2

Dressed diameter

Drillmill Specifications

Series Number Length Dressed Dia. Standard Pin Connections*

2800 53⁄8 13⁄4 - 3 Drill rod: A, B, AW, EW, E

3800 53⁄8 23⁄4 - 37⁄8 Drill rod: N, NW

* Other connections made to customer specifications can be furnished.Note: All dimensions are given in inches unless otherwise stated.

Downhole Milling 43

Fishing neck

diameter

Top pin connection

Skirt OD

Skirt ID

ID

Fishing neck

length

Junk Master

Downhole Milling44

Tool Series

Skirt OD*

Skirt ID**


Fishing Neck Dia.

Length (ft.)

Wt. (lb.)

3500 31⁄2 27⁄8 23⁄8 31⁄4 46 45

4000 45⁄8 37⁄8 27⁄8 33⁄4 46 70

4500 41⁄2 33⁄4 27⁄8 33⁄4 46 80

5700 53⁄4 55⁄8 31⁄2 43⁄4 47 110

7000 75⁄8 53⁄4 41⁄2 53⁄4 47 165

7600 73⁄4 61⁄2 41⁄2 53⁄4 47 220

10700 103⁄4 93⁄8 65⁄8 73⁄4 59 368

11700 113⁄4 103⁄8 65⁄8 73⁄4 59 417

* OD of skirt can be dressed larger.** ID of skirt can be dressed smaller.Notes: 1. All dimensions are given in inches unless otherwise stated.2. All weights are approximate.3. Standard API regular connections. Others available upon

customer request.Ordering Instructions:When ordering or requesting quotations on the Junk Master, please specify:1. Dressed OD and ID of skirt2. Size and weight of casing to be run through, if available3. Tooth design of skirt (Tooth type, V-notch, perforated type or fishing lip type, etc.)4. Top connection

Junk MasterJunk Master is a three-piece, demountable skirted junk mill. It is the ideal tool for milling inside casing or milling up torn or plugged tubular junk. The three-piece design of the Junk Master-driver sub, Economill and skirt, per-mits a worn part to be replaced without discarding the complete tool. The thrifty Economill can be replaced for a fraction of the cost of a one-piece skirted junk mill. The skirt slips over distorted or split pipe and the fish to protect the casing while keeping the Economill from slipping off the top of the fish.

Four designs are available: Tooth type, V-notch, perforated type or fishing lip type. Both the Economill and skirts are dressed with tungsten carbide.

Three-piece Skirted Junk Mill Specifications

Downhole Milling 45

tungSten CARBiDe PRoDuCtSSince the early 1950s, we have been providing our customers with the nec-essary hardmetal and dressed tools to effectively perform their operations. Only the highest quality carbides are selected for all the tungsten carbide products.

Tungsten Carbide “S”

An “S” grade carbide is composed of tungsten, titanium and tantalum carbides as a binder.

The tungsten carbide rod is made up of sharp particles of tungsten carbide suspended in a resilient nickel-silver alloy matrix. This matrix protects the carbide from extreme shock conditions while exposing new sharp edges for the cutting operation. The rod is deposited to the base material with an oxy-acetylene torch. Tungsten Carbide “S” is available in concentrate form (approximately two lb. rod bare) or composite (approximately 11/2 lb. rod, flux coated or bare. Kits are available, including tungsten carbide, with the necessary flux and tinning rod to prepare the base metal before application (see tables on page 48).

Tungsten Carbide Rod Application1. The material to which tungsten carbide is to be applied should be thor-

oughly cleaned and be free from corrosion and other foreign matter. Grit blasting is the preferred method, but grinding, wire brushing or sanding is also satisfactory.

Note: Sandblasting the surface will cause difficulty in tinning.2. Arrange the work area so the tool is positioned for down hand welding;

when possible, secure the tool in a suitable turning jig fixture.

3. Staying three to four in. off surface, slowly preheat to approximately 600°F (316°C) to 800°F (427°C); maintain a minimum of 600°F (316°C).

4. Use a spoon or spatula to sprinkle the surface to be dressed with brazing flux. The flux will bubble and boil if the surface of work piece is suffi-ciently heated. This flux will help to prevent the formation of oxides in the molten matrix during dressing.

4.CAUTION: Make sure that the working area is well ventilated so that any gases generated from the flux or filler are carried off and away from the welder. These gases are toxic and prolonged inhalation may produce nausea or sickness. The welder must wear a face shield, long sleeves and gloves during applica-tion.

Downhole Milling46

5. Use an oxy-acetylene torch; tip selection will depend upon situation: No. 8 or 9 for dressing large areas; No. 5, 6 or 7 for smaller areas or tight corners. Adjust the torch flame to a low-pressure neutral flame, one in which the light blue excess acetylene feather just disappears.

6. Continue to heat the surface to be dressed until the brazing flux is fluid and clear.

7. Staying three to four in. off surface, localize the heat in one area to a dull cherry red, 1,600°F (871°C). Begin tinning by melting on about 1 ⁄32 to 1⁄16 in. thick cover of filler rod. If the surface is hot enough, the filler rod will flow and spread to follow the heat; if not, the molten metal will bead up. Continue to heat and tin the surface to be dressed as fast as the molten filler metal will bond.

8. Separate tungsten carbide composite or concentrate rod into small pads, 1⁄2 to 1 in. sections. This can be done by heating a rod on a non-stick surface (carbon block) until the matrix becomes molten.

9. For easier handling, heat the composite of concentrate rod and tack the filler rod to the pad. Dip the rod in the brazing flux, heat tinned surface with torch and place the tungsten carbide piece in position. Heat tung-sten carbide and base steel just enough to melt the matrix, then move the torch away from the surface, continuously moving across the area to keep the matrix molten. The filler rod is used to help position the carbide for proper concentration.

CAUTION: Do not use excessive amount of filler rod as it will only dilute the carbide. Do not overheat carbides or matrix. Never permit the dark blue inner cone of the flame to contact the carbide as the heat is too high in this portion of the flame. If carbides refuse to tin, they must be flipped out of the puddle and kicked off.

10. Both tungsten carbide composite and concentrate rods are available in a number of graded fragment sizes; the desired buildup can usually be made with a single layer of the correct particle size. More experienced welders prefer to apply one layer, float it and then apply a second. The deposit thickness should never exceed the thickness of the steel being dressed. Proper application and positioning will reduce the amount of grinding necessary for sizing.

11. After each blade has the proper amount of tungsten carbide dressed, apply a light overlay of filler rod. Use care and do not heat the carbides or matrix already in place.

12. Once dressing is complete, cool the tool slowly in vermiculite. Never cool with a liquid. Do not reheat the dressed area by performing any welding near it.

Downhole Milling 47

Tungsten Carbide RemovalWhen removing tungsten carbide dress, use the same size torch tip used in the application. Heat the tungsten carbide until it is just molten, then flip it off the surface using a suitable rod.CAUTION: Under no condition should the operator attempt to melt the

tungsten carbide enough to make it flow or run off. Never at-tempt to re-use tungsten carbide which has been previously used or applied.



Ordering Instructions:When ordering or requesting quotations on tungsten carbide furnace products, please specify:1. Composite or concentrate rod2. Quantity (lb.)3. Carbide particle size4. Tinning rod and flux quantities

(20 lb. tinning rod and five lb. flux per 100 lb. composite)

Carbide Concentrate Rod 1/2 x 1 x 151/2

Composite Rod 3/8 x 15

Wt. (lb.) Wt. (lb.)3⁄8 x 3⁄8 2.0 0.765⁄16 x 1⁄4 2.0 0.531⁄4 x 3⁄16 2.0 0.533⁄16 x 1⁄8 1.88 0.531⁄8 x 1⁄16 1.5 0.53

10/20 Mesh N/A 0.53

Tungsten Carbide Furnace Products

Downhole Milling48

Kit Number Size and Type Kit Will Redress (in.)W5 (1) 5 in. OD shoe

W6 (1) 6 in. OD shoe


W8 (1) 8 in. or (2) 5 in. OD shoes


W10 (1) 10 in. or (2) 6 in. OD shoes

W11 (1) 11 in. or (3) 5 in. OD shoes


Ordering Instructions:When ordering or requesting quotations on tungsten carbide “S” field kits, please specify:1. Number of kits2. Kit number

Tungsten Carbide “S” Field KitsMills

Tungsten Carbide “S” Field Kits Washover Shoes Mills

Kit Number Size and Type Kit Will Redress (in.)J6 (1) 6 in. junk mill or (2) 41⁄2 in. junk mills or

(1) 5 in. pilot mill

J7 (1) 75⁄8 in. junk mill or (2) 55⁄8 in. junk mills or (1) 6 in. pilot mill

J8 (1) 85⁄8 in. junk mill or (2) 6 in. junk mills or (1) 71⁄2 in. pilot mill

J9 (1) 95⁄8 in. junk mill or (2) 75⁄8 in. junk mills or (1) 81⁄2 in. pilot mill

J10 (1) 105⁄8 in. junk mill or (2) 81⁄4 in. junk mills

J12 (1) 121⁄4 in. junk mill or (2) 85⁄8 in. junk mills or (3) 75⁄8 in. junk mills or (1) 12 in. pilot mill

J14 (1) 15 in. junk mill or (2) 105⁄8 in. junk mills or (1) 15 in. pilot mill


Downhole Milling48

Kit Number Size and Type Kit Will Redress (in.)W5 (1) 5 in. OD shoe



W8 (1) 8 in. or (2) 5 in. OD shoes


W10 (1) 10 in. or (2) 6 in. OD shoes

W11 (1) 11 in. or (3) 5 in. OD shoes


Ordering Instructions:When ordering or requesting quotations on tungsten carbide “S” field kits, please specify:1. Number of kits2. Kit number

Tungsten Carbide “S” Field KitsMills

Tungsten Carbide “S” Field Kits Washover Shoes Mills

Kit Number Size and Type Kit Will Redress (in.)J6 (1) 6 in. junk mill or (2) 41⁄2 in. junk mills or

(1) 5 in. pilot mill

J7 (1) 75⁄8 in. junk mill or (2) 55⁄8 in. junk mills or (1) 6 in. pilot mill

J8 (1) 85⁄8 in. junk mill or (2) 6 in. junk mills or (1) 71⁄2 in. pilot mill


J10 (1) 105⁄8 in. junk mill or (2) 81⁄4 in. junk mills

J12 (1) 121⁄4 in. junk mill or (2) 85⁄8 in. junk mills or (3) 75⁄8 in. junk mills or (1) 12 in. pilot mill

J14 (1) 15 in. junk mill or (2) 105⁄8 in. junk mills or (1) 15 in. pilot mill


49Whipstock Operations

WhipstocksDue to the increased cost of drilling, technology for sidetracking has rapidly accelerated. The tool used in this application is referred to as a whipstock. Today most whips are retrievable, whether they are a packer-type, anchor-type or mechanical-set bottom trip. With more and more multilaterals being drilled, the whipstock generally suits this application.

In the future, milling assemblies will be capable of setting the whip, milling the window and drilling as much as 500 to 1,000 ft. of new hole. Sidetracking is and will continue to be a very important part of well drilling, whether it is for enhanced oil recovery, explora-tion, redrilling or utilizing an old well in multilateral applications.

RetRievable pack-stock™

This system, developed through years of experience, is a one-trip, combina-tion packer/whipstock sidetracking system. It’s a patented tool that offers sig-nificant advantages over the original, mechanically set whipstocks prevalent since the 1930s, and it’s an attractive alternative to conventional sidetrack-ing procedures. The Pack-Stock® system yields significant savings in both time and cost.

It’s ideal for sidetracking cased holes during re-drill or re-entry in old or marginal wells. The Pack-Stock can be set at any depth, immediately above a casing collar. The system offers substantial advantages over the conven-tional two-trip whipstock/packer assembly:• Economical and efficient – one trip to locate packer depth, orient, set packer

and start milling.• The custom-designed packer prevents movement or rotation of the Pack-

Stock.• Clearance provided minimizes hole-swabbing or hang-ups.• The shear bolt ensures setting of the packer prior to milling.• A large slip area reduces casing stress and provides a more positive anchor

set.• The ability to mill through two strings of casing.• A proven three degree face angle to provide positive kickoff,

regardless of formation or hole angle.• Retrievable in one trip.

Operational RecommendationsThe Pack-Stock system is run in the hole to depth on a starter mill. For a preferred angle or direction, a muleshoe sub can be run and surveyed with an orienting device. If orientation in a specific direction is required, or if the hole angle will exceed four degrees, the Pack-Stock assembly should be set 90 degrees or less to the right or left of the hole’s high side.

50 Whipstock Operations

Retrievable Pack-Stock

Pack-Stock

Length Body OD

Packer Length

Whipstock Bypass Valve

Face Length

Face Angle

(°)

Wt. (lb.)

Length OD Wt. (lb.)

51⁄2 182 43⁄16 76 106 3 585 25 33⁄8 40

75⁄8 216 55⁄8 84 133 3 980 43 43⁄4 150

75⁄8 229 515⁄16 84 146 3 1,400 43 43⁄4 150

95⁄8 261 85⁄8 84 178 3 2,500 46 63⁄4 240

133⁄8 338 113⁄4 87 251 3 6,595 38 81⁄4 400


Retrievable Pack-Stock


RetRievable anchoR-stock ™

When a packer is not required, the hydraulically set Anchor-Stock® casing sidetrack system can be used. It is a combination whipstock and anchor.

The custom-designed anchor meets the same operating criteria as the Pack-Stock packer except for hole sealing; it is also very cost-effective. The procedure for using an Anchor-Stock hookup is identical to that for a Pack-Stock system.• Fewer hole cleaning problems because cutting a window with the Anchor-

Stock system removes only five percent of the metal required for a 60 ft. section.

• Retrievable in one trip.• No troublesome plugs to set.• Less time required to complete a job; packer (or anchor), starter mill and

whip in one trip.• Typical cost is less than a section milled below 10,000 ft.

The Anchor-Stock system also offers these user benefits when compared to conventional, two-trip whipstock and packer assembly systems:• Custom-designed anchor utilizes one-piece mandrel with anti-rotation keys,

locking tapers between the cone and slips, and ratchet ring to prevent rota-tion or vertical movement of the whipstock.

• Larger slip area reduces casing stress and provides a more positive anchor.

• A strong shear bolt verifies complete setting of the packer prior to milling.

This system must be run in the hole to depth on a starter mill. If you have a preferred angle and direction for the sidetrack, a muleshoe sub may be run and surveyed with an orienting device. If orientation in a specific direc-tion is required or if the hole angle exceeds four degrees at setting depth, we recommend that the Anchor-Stock assembly be set not more than 90 degrees to the right or left of the hole’s high side.

Two Other Unique AdvantagesWith an Anchor-Stock system, you can also:• Mill through two strings of casing.• All whipstocks have a proven three degree face angle to provide positive

kickoff regardless of formation or hole angle.


Retrievable Anchor-Stock

Retrievable Anchor-Stock

Anchor-Stock

Length Body OD

Anchor Length

Whipstock Bypass Valve

Face Length

Face Angle

(°)

Wt. (lb.)

Length OD Wt. (lb.)

51⁄2 165 43⁄169 591⁄16 74 3 535 25 33⁄8 40

75⁄8 197 53⁄ 89 633⁄49 95 3 895 43 43⁄4 150

75⁄8 210 515⁄16 633⁄49 107 3 1,380 43 43⁄4 150

85⁄8 229 71⁄ 89 643⁄49 124 3 1,875 43 43⁄4 150

95⁄8 241 81⁄ 89 643⁄49 142 3 2,285 46 63⁄4 240

133⁄8 322 117⁄ 89 711⁄ 89 212 3 6,200 38 81⁄4 400



anchoR-stock/pack-stock Running pRoceduRe1. Make gauge ring and casing scraper run utilizing a watermelon mill. Make

collar locator run or cement bond log if cement bond is questionable. (Bottom of Anchor-Stock must be set two to six ft. above collar.)

2. As an option, if the casing is unbonded, a block squeeze should be consid-ered at this point because if left unsupported will cause excessive vibration and hamper milling performance. Squeeze the zone around the kickoff point or move to step three.

3. Condition mud to provide good milling parameters and weight required to drill new hole section. Pull out of hole.

4. Pick up one joint of high-grade drill pipe.5. Pick up whip running assembly and Anchor-Stock.6. Pick up assembly and scribe a line to align the face of the Anchor-Stock

along the assembly to the orientation sub; orient sub with the scribed line. Drill collars and Hevi-Wate™ IDs must be checked for proper clearance for orienting tools. Note: Depending on depth and angle, drill collars and Hevi-Wate

can be reduced or eliminated from the Bottom Hole Assembly (BHA) and run with straight drill pipe with hydraulically set Anchor-Stocks or Pack-Stocks.

7. Trip in hole slowly to setting depth, monitoring hole drag.8. At depth work string up and down to work out torque.9. Orient Anchor-Stock to your specification. (Either run surface

readout gyro or multi-shot surveys.)10. Gradually apply 3,000/3,500 psi pressure and hold.11. Work shear bolt up and down four to five times. Shear off

Anchor-Stock.12. Make starter mill cut out.13. Pull out of hole, lay down starter mill and running assembly.14. Trip in hole with Tri-Mill system on drill collars or drill pipe to clean

and elongate window and drill four to six ft. of formation.15. Pull out of hole. Lay down Tri-Mill.Note: Do not rotate a bit or stabilizer down the face of the whip.

If window is to be squeezed it must be reopened with a window mill, not a roller cone bit.


RetRievable econo-stock™

The Econo-Stock® is a retrievable, mechanically set whipstock that offers substantial design improvements over competing products. Activation occurs when 3,600 lb. of weight are set down after a trigger rod contacts a plug in the casing. Applying additional weight sets the anchor and shears the starter mill bolt. The starter mill and shear bolt block are newly designed features. A “shear-down” shoulder prevents the starter mill from jamming and enhances the setting of the anchor. Multiple slips provide excellent load and torque capacity. The slips are held in position by a ratchet ring that provides equal loading in all directions.

To release the anchor, the whip is engaged using the same retrieving tool as the field-proven Retrievable Anchor-Stock. An upward pull releases the anchor, and the slips fully retract as the tool is pulled from the well.

Unlike many competing “economy” tools, the Econo-Stock provides a full complement of important benefits:• Anchor setting requires no hydraulic pressure.• Retrievable with conventional tools.• Multiple tongue-and-groove slip design provides uniform stress-

loading on casing and maximizes anti-rotation capabilities.• Simultaneously activated, full-contact slips centralize the anchor assembly

in the casing.• Retractable slips prevent casing drag during retrieval.• Ratchet ring and nut ensure and maintain “set”.• Bi-directional loading capability.


standaRd econo-stock Running pRoceduRe1. Make gauge ring and casing scraper run utilizing a watermelon mill. Make

collar locator run or cement bond log if cement bond is questionable. (Bottom of Econo-Stock must be set two to six ft. above collar.)

2. If the casing is unbonded, a block squeeze should be considered at this point because if left unsupported will cause excessive vibration and ham-per milling performance. Squeeze the zone around the kickoff point or move to step three.

3. Condition mud to provide good milling parameters and weight required to drill new hole section. Pull out of hole.

4. Pick up one joint of high-grade drill pipe.5. Pick up whip running assembly and Econo-Stock in mouse hole.6. Pick up assembly and scribe a line to align the face of the Econo-Stock

along the assembly to the orientation sub; orient sub with the scribed line. Drill collars and Hevi-Wate IDs must be checked for proper clearance for orienting tools. Note: Depending on depth and angle, enough drill collar or Hevi-Wate

weight must be calculated for shearing purposes when setting the Econo-Stock.

7. Trip in hole slowly to setting depth, monitoring hole drag.8. At depth work string up and down to work out torque.9. Orient Econo-Stock to your specification. (Either run surface

readout gyro or multi-shot surveys.)10. Apply 15,000 to 20,000 lb. of shear down force to shear bolt and

set anchor.11. Work BHA up and down to ensure shear bolt has sheared off the Econo-

Stock.12. Make starter mill cut out.13. Pull out of hole, lay down starter mill and running assembly.14. Trip in hole with Tri-Mill system on drill collars or drill pipe to clean and

elongate window and drill four to six ft. of formation.15. Pull out of hole. Lay down Tri-Mill.Note: Do not rotate a bit or stabilizer down the face of the whip. If win-

dow is to be squeezed it must be reopened with a window mill, not a roller cone bit.


Retrievable Econo-Stock



Length Body OD

Anchor Length

Whipstock

Face Length

Face Angle

(°)

Wt. (lb.)

5 – 51⁄2 1423⁄8 45⁄16 351⁄8 74 3 570

7 1721⁄8 57⁄16 381⁄8 95 3 875

85⁄8 1891⁄2 77⁄16 431⁄2 124 3 1,175

Notes:1. All dimensions are given in inches unless otherwise stated.2. All weights are approximate.3. Product can also be set permanently.4. 75⁄8 and 95⁄8 in. Econo-Stock available upon request.


tips foR a successful Re-entRy

Whipstock Sidetracking

Casing PreparationEnsure that casing scraper, gauge ring and collar locator runs are made. Often the gauge ring and collar locator runs can be combined for efficiency.

Cement BondA cement bond log can be run if desired. A good cement bond enhances milling rates, but is not absolutely required for a successful sidetrack.

Window PlacementA sidetrack window can be located in any type of formation. If the formation is extremely consolidated, diamond mills may be needed to mill the window. It is imperative that the window not be cut through a casing collar. Try to position the bottom of the anchor or packer about five ft. above the collar.

Hole AngleOn holes with more than four degrees of deviation, the whipstock face should not be oriented more than 105 degrees to either side of the well’s high side.

Mud PropertiesMilling mud is not needed for a successful sidetrack, and many jobs have been completed using water. High-viscosity sweeps can be used periodically to clean the hole if desired. No specific annular velocities are needed due to the small quantity and fine size of the cuttings.

Rig, Pump and DrillstringThe rig must have sufficient capacity to handle the drillstring weight and have enough reserve capacity to shear the shear bolt.

The rig pump must have the capability to apply the 3,000 to 3,500 psi setting pressure to the drillstring.

The drill pipe and rotation device (power swivel or rotary table) must have enough capacity to turn milling tools downhole without stalling. This will vary with depth of kickoff point and hole straight-ness. Generally, a 3.5 power swivel and 23 ⁄8 in. drill pipe is required for 51 ⁄2 in. casing, 31 ⁄2 in. drill pipe and a rotary table for 7 and 75 ⁄8 in. casing, 41 ⁄2 in. drill pipe and a rotary table for 85 ⁄8 and 95 ⁄8 in. casing, and 5 in. drill pipe and a rotary table for 133 ⁄8 in. casing.


Milling SequenceThe whipstock is run in hole and set on a starter mill. After setting, a shear bolt is sheared, separating the starter mill from the whipstock. Rotation is begun and the starter mill is slacked off until the tapered nose cams the tungsten carbide blades into the wall. It is imperative for the proper length of starter mill travel be attained to assure subsequent efficient milling runs.

The window is then milled using a window mill. Run the window “limber” (one joint of drill pipe above the mill followed by drill collars). This will allow the window mill to flex off the face of the whipstock as it mills into formation. The window is then “polished” or elongated using a window mill and one or two watermelon mills run directly below the drill collars. Make enough open hole below the bottom of the window to provide adequate room for subse-quent drilling assemblies.

Post-Window Milling PrecautionsNever rotate a bit or stabilizer down the face of the whipstock. Treat a whip-stock window as a casing shoe. Slack off and pull through the window slowly, carefully noting any unusual drag. If drag is encountered when run-ning bent housing motors through a window, pull up, rotate the drillstring slightly and then slack off through the window. When the bend in the motor aligns with the whip, the BHA will pass through the window with minimal drag.

General PlanningPre-job planning meetings (pre-spud meetings) to coordinate with the service companies involved in a sidetrack will result in a more efficient operation.


tRackmasteR® opeRations

Trackmaster: The Only One-trip Window Milling SystemThe Trackmaster is the only full-gauge system that lets you open a sidetrack window in just one trip. It’s a self-contained unit that reduces sidetracking costs by as much as 50 percent. In a single trip in and out of the hole, you accomplish all seven of the major steps needed for cutting a sidetrack win-dow:• Run the assembly.• Orient the whipstock (with Measurement While Drilling (MWD)).• Set the whipstock hydraulically.• Shear the mill from the whipstock assembly.• Mill and dress the window.• Drill a full-gauge rathole.• Pull out of the hole.

The result is a full-size window completed in minimal time, providing a full-gauge rathole for the directional assembly.

The Trackmaster system is available in a full range of sizes for 41⁄2 through 133⁄8 in. casing. The system includes all necessary auxiliary equipment.

Special meritorious engineering award for innovation and efficiency.


Trackmaster System DescriptionThe system is comprised of four major components: the bypass valve, run-ning tool, milling tool and the whip assembly.

High-Flow Bypass ValveThe high-flow bypass valve performs several functions for the systems. First, it allows for circulation of drilling fluid so the whip assembly may be oriented with MWD. The high-flow bypass valve can then be closed to facilitate hydrau-lic setting of the anchor. Last, after shear-off, the valve closes each time cir-culation is started so all the drilling fluid goes to the mill where it is needed for cooling and cuttings removal. When not with a mud, a standard bypass valve may be used.

Running ToolThe running tool is used for the actual setting of the whip assembly. It pro-vides a barrier between the drilling mud and the oil in the whip assembly to ensure the setting mechanism stays clean and free of debris.

Milling ToolThe milling tool includes three mills each with different objectives and dressed with high-performance carbide.

Lead MillThe lead mill is a full-gauge mill designed to initiate the cut-out and mill the window further as it slides down the whip face. It also drills the rathole.

Follow MillThe follow mill is also a full-gauge mill and engages with the casing as the lead mill travels down the ramp and elongates the window.

Dress MillThe dress mill is a full-gauge mill and is designed to dress the window as the entire assembly passes through the casing.

Each mill is dressed with Millmaster carbide for consistent and efficient milling performance.

Whip AssemblyThe whip assembly consists of a whipstock attached to an anchoring assembly. The whipstock has a multi-ramp design to guide the milling tool effectively and expediently through the casing and into the formation.


Conclusions• Using Trackmaster will save time and money.• MWD orientation eliminates the need for a wireline trip.• The bypass valve controls drilling fluid for maximum

efficiency of the Trackmaster components.• Millmaster carbide on dressed mills ensures consistent and efficient window

cutting.Note: The Trackmaster retrievable whip can be attached to any anchor-

ing assembly, i.e., Pack-Stock, Anchor-Stock or Econo-Stock. These products provide you with the option of mechanical anchor, hydraulic packer or mechanical bottom trip. In addition, a big bore inflatable packer can also be attached to the whip for open hole application.

One-trip Sidetracking System

Trackmaster Whipstock

Anchor-Stock Pack-Stock Econo-Stock (Bottom trip)


ObjectivesThe objective of the Trackmaster is to accomplish the following steps in a single trip:• Run the assembly.• Orient the whipface (with MWD or gyro).• Set the whip assembly (hydraulically).• Shear the mill from the whip assembly.• Mill the window.• Drill the rathole.• Pull out of hole.

The result is a full size usable window with a minimum of milling time and a full-gauge rathole for the directional drilling assembly.


tRackmasteR

Benefits• Eliminate starter mill run.• Aggressive initial ramp to ensure quick efficient cut out.• Millmaster technology for consistent milling performance.• Mid-whip ramp to reduce core problems and milling time.• Full-gauge mills to ensure full-gauge window and rathole.• Entire procedure is finished in one trip into the hole.

Typical Running Assembly for 95/8 in. Trackmaster

MWD63⁄4 in. OD

63⁄4 in. OD

5 in. OD

61⁄2 in. OD

61⁄2 in. OD

Mill gauge 81⁄2 in. diam-eter

Bypass valve

HWDP

Running tool

Mill

Whipstock


Notes:

65Concentric Hole Enlargement

UnderreamingUnderreaming is the process of enlarging a section of wellbore beneath a restriction. The most frequently encountered restrictions are the inside diam-eter (ID) of the casing and the size of the wellhead. Both limit the maximum outside diameter (OD) of the tools that can pass through.

The term “hole opening” is often used interchangeably with underreaming. Essentially, both operations enlarge the existing pilot hole. Hole opening involves enlarging the wellbore starting from the surface. Therefore, hole openers have cutters rigidly attached to the body on a fixed diameter. No hydraulic actuation is needed for the tool operation.

Underreaming takes place at some point below the surface. Since the tool has to first pass through the restricted bore, it incorporates expandable cutters which stay collapsed while the tool is run in and once the tool has cleared the casing and wellhead, the cutters expand into the formation by utilizing the differential pressure of the drilling fluid or pneumatic medium.

Once the hole is underreamed to the desired depth, the pumps are turned off, allowing the arms to collapse back into the body. The tool is then pulled out of the hole through the restricted section.

Application of UnderreamersUnderreamers are used whenever it is necessary to open the diameter of a portion of the borehole, beginning somewhere below the surface. Typical applications include:• Opening the hole below the casing shoe to provide a larger annular space

for cementing the next casing string. This permits the use of a larger inter-mediate casing diameter than could be used otherwise.

• BOP or wellhead size restricts the tool diameter.• Enlarging the hole annulus within the producing zone for gravel-pack com-

pletions.• Opening a pocket to start a sidetrack.• Enlarging “heaving areas” through problem fault zones.• Reducing dogleg severity.Selection of an underreamer depends on the formation and on whether or not simultaneous drilling is required. Smith offers a Reamaster® underreamer capable of simultaneous Underreaming While Drilling (UWD), a Drilling-Type Underreamer (DTU), a Rock-Type Underreamer (RTU) and a Drag-Type Underreamer (SPX®).

Concentric Hole Enlargement66

General Guidelines for underreaminG

Formation Considerations• ROP of soft formation reacts better to rotary speed.• ROP of PDC cutters react better to rotary speed.• ROP of medium-hard formation reacts better to weight.• Soft formations underream faster than the pilot-hole bit

(25 ft/hr. average).• Medium formations underream equal to the pilot-hole bit

(10 to 25 ft/hr. average).• Hard formations underream slower to the pilot-hole bit

(10 ft/hr. average).

Maximum Weight on Tools with Milled Tooth/TCI Cutters• Drag-type — 700 lb. x body diameter• Rock-type — 1,000 lb. x body diameter• Drilling-type with bullnose — 1,000 lb. x body diameter• Drilling-type with bit — 1,500 lb. x body diameter• Reamaster with bit or bullnose — 4,000 lb. x body diameter

Maximum Weight on Tools with PDC-type Cutters• Drag-type with SPX/PDC — 500 lb. x number of PDCs• Rock- and drilling-type with Bearclaw™ PDC — 500 lb. x number

of PDCs• Reamaster-type with parabolic PDC — 500 lb. x number

of PDCs*

* This pertains to PDCs in contact with formation excluding redundant gauge coverage.

Anticipated Life of Cutters Cutter Life Maximum (hr.) RPM 15 - 20 Crushed carbide 180 20 - 30 Open roller 130 30 - 40 Sealed roller 140 40 - 50 Sealed journal 100 50 - 60 SPX/PDC 140 60 - 80 Bearclaw/PDC 180 60 - 80 Reamaster/parabolic-PDC 200


• Optimum circulation rate is 35 GPM times underreamed diameter.• Reamaster circulation rate is 50 GPM times underreamed diameter.• Fluid velocity in the RTU/DTU and drag-type underreamers should not

exceed 150 ft/sec.• Fluid velocity in Reamaster underreamers should not exceed 75

ft/sec.

Tool SelectionIn recent years Smith has made several improvements to underreamers. Several internal parts have been redesigned to improve performance, extend component life, reduce maintenance and decrease cost. Cutter arm selection has been expanded to include the following.• Cutting Structures

Tungsten carbideMilled toothTCI (Tungsten Carbide Inserts)SPX-PDC (Polycrystalline Diamond Compacts)Bearclaw-PDCParabolic-PDC

• Bearing PackagesOpen-roller bearingSealed-roller bearingSealed-journal bearingWe can provide a variety of underreamers, depending on customer

requirements and performance needs, either unaccompanied or with experi-enced operators who maximize tool performance.

The cutting structures available for underreamers are illustrated on the following page.


DTU/RTU Underreamer Cutters

DS, K2

DG, C4V2

Bearclaw

F1 TCI

DT

Parabolic


Note: Bearclaw/PDC or parabolic-PDC Superdome cutter heads may be fabricated for any of the above underreamers.

IADC Code

Milled Tooth TCI IADC Code1-1 1-2 1-3 2-1 4-3 5-1

Open (1) Sealed (4) Journal (6)

K2 K2

K2

DS DS

DT

DT C4

C4

DG

V2

F1

F2

Journal (7)

Underreamer Series

Bit Cone Size (in.)

3600 RTU 3600 DTU

X X 35/8

4500 RTU 5700 DTU

X X

X X

X X

X X 41/2

5700 RTU 7200 DTU 8200 DTU

X X X

X X X

X X X

X X X

X X X

55/8

7200 RTU 8200 RTU 9500 DTU

X X X

X X X

63/4

8200 RTU X X 73/8

9500 RTU 11700 DTU

X X

X X

X X

X X

X X 91/2

11700 RTU 15000 DTU 15000 RTU 17000 DTU

X X X X

X X X X

X X X X

X X X X

X X X X

121/4

15000 RTU 17000 DTU

X X

X X 133/4

17000 DTU X 143/4

22000 DTU X X 15

22000 RTU X 171/2

DTU/RTU Underreamer Cone Availability


TCI

Milled Tooth

Parabolic (PDC)

Reamaster (XTU)

Cutter Types


reamaster (Xtu)

Innovative Design Improves UnderreamingA major addition to the Smith line of underreamers, the Reamaster Underreamer* or XTU is the result of years of development and testing. The objective was to develop an underreamer that far exceeded the inher-ent limitations of conventional underreamers: low weight-carrying capacity, short bearing life and marginal hydraulics. The Reamaster tool has achieved these improvements and excels over conventional underreamers. It fea-tures:• Sustained drilling weight equivalent to bit.• Larger cones and bearings for extended on-bottom time.• Enhanced hydraulics for better hole cleaning.• Capable of simultaneous Underreaming While Drilling (UWD).

Substantially Reduces Overall Casing and Cementing CostsNow you can save money by optimizing casing sizes on multiple string wells. The Reamaster underreamer is specifically designed to underream long intervals and provide the cementing space needed to run minimum clearance casing programs. You can design a slimmer top hole for a given diameter production zone or for a larger than standard production zone for a given hole size.

Refer to the chart on page 73 to show possible combinations of cas-ing with minimum clearance. Based upon recommendations provided by cementing firms and casing manufacturers, the chart assumes minimum clearance of less than 1 ⁄2 in. between outer string drift diameter and inner string coupling diameter for cased holes.

* Reamaster systems are only available on a rental basis in conjunction with Smith job supervision.

Features

One-piece Forged Arms• One-piece forged arms with integral journals to hold cutters.• Simple and strong internal components.• Carry four to five times more drilling weight than

conventional tools.• Withstand high shock loads and torque downhole.• Increase penetration rates.• Positive lock keeps arms in open position.• Feature large diameter single-hinge pin.


Customized Cutters• Cutters and cutting structures designed exclusively for underreaming.• Cutters available with milled tooth, TCI or PDC cutting structures.• Large sealed bearings.• Milled tooth and TCI cutters are designed with compensated

sealed bearings.• Specially designed large cutters achieve lower RPM, resulting in

longer bearing life.• Optimum journal angle provided during drilling, plus other

features, substantially increases bearing life for longer on-bottom time and increased penetration rates.

Improved Hydraulics• Unique internal design more than doubles allowable drilling

fluid flow through the tool.• Features four nozzles, two jetting directly on the bench and one

on top of each cutter.• Increases amount of hydraulic energy for better hole cleaning

efficiency and faster penetration rate.• Strategic placement of nozzles keeps cutters clean and cool.


Outer Casing Size (in.)

Largest Inner Casing Size (in.)

Underreaming (in.)

Min. Pilot Hole

Underreamed Dia.

Reamaster Tool Series

24 20 181 ⁄2 26 16000

20 16 171 ⁄2 22 16000

16 133 ⁄8 143 ⁄4 171 ⁄2 11750

133 ⁄8 (48 - 68 lb.) 103 ⁄4 121 ⁄4 15 11750

113 ⁄4 85 ⁄8 105 ⁄8 121 ⁄4 9500

95 ⁄8 (29.3 lb.) 75 ⁄8 83 ⁄4 111 ⁄2 8250

85 ⁄8 (24 - 32 lb.) 65 ⁄8 75 ⁄8 91 ⁄2 7200

85 ⁄8 (36 - 49 lb.) 6 73 ⁄8 9 5750

75 ⁄8 51 ⁄2 61 ⁄4 81 ⁄2 5750

7 (17 - 32 lb.) 5 6 8 5750

Note: Recommendations are based on:• The minimum clearance of 0.400 in. on diameter between the outer string drift diam-

eter and inner string coupling diameter.• The clearance between the hole wall and the coupling OD is at least two in. on diam-

eter. Less clearance than this may create a back pressure which will dehydrate the cement so that it cannot be pumped.

Recommendations to Set Small Clearance Consecutive Strings of Casings


Reamaster Operating ParametersThe following operating parameters will serve as a guideline for all Reamaster jobs:1. Smallest jet to be used in system is 12⁄32 in. If possible, the lowest jet in

system should be the largest. A variety of jets, including blanks, should be provided for all components. Diverging jets are required for cone pocket jets in the 9500 and smaller series Reamasters. The maximum flow per jet will be limited to 250 GPM. A float sub is always recommended when the BHA allows.

2. Flow velocities through the Reamaster will be limited to the following pro-viding that solids control is in effect including desanders and desilters.

100 ft/sec. < 12 lb/gal. mud75 ft/sec. > 12 lb/gal. mud

Upper body or bench jets should be used to divert sufficient flow to achieve acceptable main bore velocities.

3. Lateral force on cutters derived from BHA analysis will be maintained below the following:

Reamaster Series PDC Cutters (lb.) Milled Tooth/TCI (lb.)5750 1,000 500

7200 1,000 500

8250 1,500 750

9500 1,500 750

11750 2,000 1,000

16000 2,000 1,250

Note: The lateral force exerted on the cutters should always be minimized if possible through BHA analysis.


4. Although formation characteristics will normally determine the appropri-ate RPM, the following is to be used as a guideline:

5. Bottom hole temperatures in excess of 300°F require the use of Viton packings.

6. BHA recommendations should be as follows: Underream only — Undergauge stabilizer should be run above the underreamer at a distance to minimize lateral force at underreamer cut-ters. The assembly below the underreamer should be an undergauge bit or slick bullnose. Minimum diametral clearance for either bit or bull-nose should be one inch in pilot hole. Any full-gauge assemblies will require BHA analysis to meet lateral force requirements. Drill and underream — The BHA will be determined by BHA analysis for lateral force requirements and directional objectives.

7. Flow distribution and pressure drop should be maintained on the follow-ing guidelines based on 12 lb/gal. mud:

Underreamed Dia. (in.)

PDC Dia. (mm) Milled Tooth/TCI RPM9 13 16

Recommended RPM97⁄8 140 160 n/a 80 - 150

121⁄4 130 155 n/a 80 - 150

143⁄4 110 130 n/a 80 - 150

171⁄2 n/a 110 130 80 - 150

20 n/a 95 110 80 - 150

26 n/a 75 85 80 - 150

Pilot Hole (in.)

Underreamed (in.)

Underream Only Drill and Underream

GPM psi GPM psi61 ⁄2 97⁄8 340 400 n/a n/a

97⁄8 121 ⁄4 430 475 600 525

105 ⁄8 143 ⁄4 520 550 740 600

121 ⁄4 171 ⁄2 600 600 900 700

143 ⁄4 20 750 700 1,000 850

171 ⁄2 26 1,050 850 1,300 1,000


Flow distribution between underreamer and bit/bullnose should be based upon application as follows: Underream only — Minimum of 65 degrees of total flow rate should exit the Reamaster underreamer. Drill and underream — Minimum of 20 degrees of the total flow rate should be directed to the bit. The balance of the flow rate should be divided between the bit and underreamer based on the area of forma-tion removed by each.

8. Hydraulic horsepower per square in. should be maintained at the following:Underream only - 1.3 hhp/in.2 for underreamer

- .5 for bit or bullnoseDrill and underream - 1.3 hhp/in.2 for underreamer

- 1.0 hhp/in.2 for bit9. Effective weight-on-bit should be determined by allowable torque available

based on the limitations of drillstring components. Maximum PDC weight is based on the number of PDC inserts that actually contact the under-reamed bench area excluding redundant gauge cutters.

Reamaster Series

PDC Dia. (mm) Max. Wt. Milled Tooth/TCI (lb.)9 13 16

Max. Wt./PDC (lb.)5750 600 500 n/a 15,000

7200 600 500 n/a 25,000

8250 600 500 n/a 30,000

9500 n/a 500 400 35,000

11750 n/a 500 400 50,000

16000 n/a 500 400 60,000


Reamaster Underreaming GuidelinesThe tool is normally run above the bit or bullnose. However, it can also be run in the drill collars string, up to 90 ft. above the bit.1. Lower the tool into the hole until it reaches the top of the section to be

enlarged. Take care when running in the hole, as surge pressures can start opening the arms, which may damage the casing.

2. Rotate the tool slowly (30 to 50 RPM) after reaching the desired shoul-der cut-out depth.

3. While rotating the drillstring, start pumps and establish flow.4. Gradually increase flow rate and RPM until desired operating param-

eters are reached.

Cutting the Shoulder 1. After correct pump pressure is reached, rotate the tool at 80 to 150

RPM maximum. Mark the kelly for three feet and drill off slowly. Rotate for five to ten minutes.

2. Disengage rotary table and pick back up while pump is still on.3. Cutter arms should be fully open now. To make quite sure, repeat the

above steps. When you reach the shoulder, you should start taking weight, indicating that you have a shoulder.

UnderreamingWith the arms in the full open position the pilot hole can be underreamed. Maintain constant drilling weight. A good rule of thumb is 1,500 to 2,000 lb/in. of body diameter.

Example: 12,375 to 16,500 lb. for a 81 ⁄4 in. tool.

Reduce table speed to 80 RPM and proceed as follows:• Allow drum to “creep”. Do not drill off.• Establish a constant ROP and proceed.• Do not spud tool.• Pull at the first sign of dulling (look for the same signs as on

a dull rock bit). Running time will depend on formation and cutter type.

• When a hard streak layer of formation is encountered, reduce speed and add weight in order to maximize penetration rate.


Adding a Connection1. After adding a connection, lower the kelly bushing so that it is barely in the

table, and engage the rotary at slow speed.2. Apply pump pressure.3. Disengage rotary and lower tool to shoulder.4. Set down on shoulder and apply weight to check if cutter arms have

reopened.5. Pick back up about two feet, engage rotary, bring to operating RPM and

continue underreaming.

Tripping Out of the HolePick up a few feet and turn pumps off. Allow five to ten minute rotations before coming out of the hole or into the casing shoe. Always pull into the casing slowly. Be sure hydrostatic head in the drillstring is allowed to equal-ize before pulling into the casing; otherwise, forces of the fluid column may expand cutter arms during entry.

Reamaster Disassembly1. Unscrew the hinge pin retaining screw and remove the washer

and cap.2. With snap ring pliers, remove the bail and slide the seat out of the hinge

pin hole.3. Using the long bolt supplied in the tool kit, pull the hinge pin out of the tool.4. Slide the arm set out of the tool.5. Break out the top sub and remove it from the tool. If a bit sub, bit or bull-

nose is made up to the tool, remove it also.6. Break out the connection between the upper body and lower body. CAUTION: When breaking out this connection special care should

be taken to keep the bodies perfectly aligned. Otherwise, severe damage caused by galling could occur. It is advis-able to stand the tool in the vertical position to unscrew the connection. (On 16000 Reamaster, DO NOT torque on the sleeve. Remove the upper body to expose the inside of the tool. Remove the sleeve at this time.)


7. Using the small screw supplied in the tool kit, remove the two guide pins. 8. Slide the piston bore sleeve out of the lower body. 9. Insert the piston assembly tool, found in the tool kit, into the slot on top of

the piston and hold in place with a bar.10. Unscrew the cam and slide it out of the piston bore sleeve on 16000

Reamaster. Remove the floating seal cartridge at this time. CAUTION: DO NOT vise on the thin wall of the piston bore sleeve.

11. Remove the piston assembly tool and slide the piston and spring out of the piston bore sleeve.

12. Unscrew the arm stop retaining screw and remove the arm stops and washers.

13. Unscrew the orifice retainer and remove the orifices and O-rings. Remove and discard all O-rings, packings and screws used in the tool. Thoroughly clean all parts and check for damage. Replace parts if neces-sary.

Tool Series Make-up Torque (ft/lb.)5750 10,500

7200 33,000

8250 43,000

9500 63,000

11750 88,000

16000 88,000

XTU Underreamer Make-up Torque Specifications — Upper Body to Lower Body


Top sub

Piston bore sleeve

Upper body

Guide pin

Arm stop

Lower body

Piston

Spring

Cam

Hinge pin

Cutter arm

Reamaster Components


Reamaster AssemblyWhen the tool is assembled all parts should be thoroughly lubricated. Any light grease is adequate.1. Install packings on piston. Make sure the packings are installed

facing upward.2. Slide the spring and the piston into the piston bore sleeve.3. Install the O-rings on the piston bore sleeve. (On 16000 Reamaster install

the O-ring onto the floating seal cartridge and slide it onto the piston bore and sleeve at this time. Make sure the holes in the floating seal cartridge are aligned with the holes in the piston bore sleeve.)

4. Slide the cam through the lower end of the piston bore sleeve and screw it into the piston. To prevent the piston from turning during tightening, install the piston assembly tool into the piston and retain it with a bar. CAUTION: DO NOT vise on the thin wall of the piston bore sleeve.

5. When the cam is tight, remove the piston assembly tool. Continue to turn the cam until its slots are aligned with the holes in the piston bore sleeve.

6. Next, slide the piston bore sleeve into the lower body. Align the holes in the piston bore sleeve with the holes in the lower body and install the two guide pins.

7. Install the O-rings onto the lower body. (On 16000 Reamaster slide the sleeve onto the lower body and install the O-ring into the upper body at this time.)

8. Slide the upper body over the piston bore sleeve and down onto the lower body. Make-up the connection between the lower body and the upper body. CAUTION: When making up this connection special care should be taken

to keep the bodies perfectly aligned. Otherwise, severe dam-age caused by galling could occur. It is advisable to stand the tool in the vertical position while installing the upper body. (On 16000 Reamaster DO NOT torque on the sleeve.)

9. Install the O-rings, orifices and orifice retainers into the lower body.10. Put the arm stops in place and install the washers and screws to hold

them in place.NOTE: Hold the arm stops against the top of the slots in

the lower body to ensure adequate clearance for the arm set.

11. Slide the arm set into the tool, one arm assembly in each side.12. Slide the hinge pin into the tool and through the two arm

assemblies.13. Install the hinge pin retainer seat, bail and pin. Make sure the

gap in the bail straddles the hinge pin retainer pin.14. Install the cap, washer and screw and tighten down.


NOTE: Make sure the arm assemblies swing freely before continuing.

15. Pull both arm assemblies out to the fully extended position and slide the proper sized ring gauge over the cutters to ensure proper opening size.

Reamaster Underreamer (XTU) Specifications


unless otherwise stated.2. All weights are approximate.3. Optional opening diameter available

upon customer request.4. Standard cutters are sealed-bearing

milled tooth. TCI or PDC cutting structures must be specified.

5. The 5750 Series replaces the 5700, the 8250 replaces the 8200 and the 11750 replaces the 11700 Series.

U.S. Patent Number: Underreamer – 4,660,637 PDC Underreamer – 4,431,065

Ordering Instructions:When ordering or requesting quota-tions on the Reamaster Underreamer (XTU), please specify:1. Top and bottom connections2. Fishing neck diameter3. Expanded diameter4. Size and weight of casing to be run

through, if available5. Bullnose ordered separately6. Type of cutting structure (milled

tooth, TCI or PDC)

Tool Series

Opening Dia. Pilot Hole Size

Body/Coll. Dia.

Fishing Neck Overall Length

Top Pin/Bottom

Box Conn.

API Reg.

Wt. (lb.)

Length Dia.

5750 81⁄2, 9 57⁄8 - 61⁄2 53⁄4 18 43⁄4 90 31⁄2 500

7200 97⁄8, 11, 113⁄4, 121⁄4

71⁄2 - 11 71⁄4 18 53⁄4 99 41⁄2 700

8250 97⁄8, 105⁄8, 11, 121⁄4, 131⁄2

81⁄2 - 97⁄8 81⁄4 18 53⁄4 123 41⁄2 900

9500 121⁄4, 131⁄2, 15, 16

97⁄8 - 121⁄4 91⁄2 24 85 136 65⁄8 1,100

11750 14, 15, 16, 171⁄2

121⁄4 - 141⁄2 113⁄4 20 85 130 65⁄8 1,700

16000 20, 22, 24, 26 171⁄2 - 22 165⁄ 20 10 140 85⁄8 3,200


Overall length

Body diameter


Opening diameter


Top pin connection

Fishing neck length

Reamaster Underreamer (XTU)


DS, K2

DG, C4 V2

Bearclaw PDCF1 TCI

DT

Drilling-Type Underreamer (DTU)

Cutter Options


drillinG-type underreamer (dtu)The Smith DTU will underream previously drilled pilot holes. A bottom box connection allows either a bit or bullnose to be run below the underreamer. The DTU may be used to drill and underream simultaneously.

The tool design allows mud flow to the bit or bullnose. Flow can be divided depending upon application. Orifice jets can be selected in order to better utilize existing hydraulics. The jetting placement aids in keeping the cutters cool, and in annular lift of the cuttings. Selections include jetted bull-nose and a jetted top sub in order to divert additional flow when necessary. These tools can be operated with water, mud, air, aerated mud or any other circulating medium.

Operating Guidelines1. Lower the tool into the hole until it reaches the top of the section to be


2. Rotate the tool slowly (30 to 50 RPM) after reaching the desired shoulder cut-out depth.

3. While rotating the drillstring, start pumps and establish flow.4. Gradually increase flow rate and RPM until desired operating parameters

are reached.

Cutting the Shoulder1. After correct pump pressure is reached, rotate the tool at 80 to

150 RPM maximum. Mark the kelly for three ft. and drill off slowly. Rotate for five to ten minutes.

2. Disengage rotary table and pick back up while pump is still on.3. Cutter arms should be fully open now. To make quite sure,

repeat the above steps. When you reach the shoulder, you should start taking weight, indicating that you have a shoulder.


UnderreamingWith the arms in the full open position the pilot hole can be underreamed. Maintain constant drilling weight. A good rule of thumb is 1,000 lb/in. of body diameter:

Example: 9,500 lb. for a 91 ⁄2 in. tool.Reduce table speed to 80 RPM and proceed as follows:• Allow drum to “creep”. Do not drill off.• Establish a constant ROP and proceed.• Do not spud tool.• Pull at the first sign of dulling (look for same signs as on a dull rock bit).

Running time will depend on formation and cutter type.• When a hard streak layer of formation is encountered, reduce speed and

add weight in order to optimize the penetration rate.


table, and engage the rotary at slow speed.2. Apply pump pressure.3. Disengage rotary and lower tool to shoulder.4. Set down on shoulder and apply weight to check if cutter arms have

reopened.5. Pick back up about two ft., engage rotary, bring to operating RPM and


Tripping Out of the HolePick up a few feet and turn pumps off. Allow five to ten minute rotations before coming out of the hole or into the casing shoe. Always pull into the casing slowly. Be sure hydrostatic head in the drillstring is allowed to equal-ize before pulling into the casing; otherwise, forces of the fluid column may expand cutter arms during entry.

Underreaming Key Seats1. Locate the DTU in the middle of the drill collars.2. Diameters of the expanded arms must be equal to the bit size

or larger.3. Place a full gauge stabilizer 60 to 90 ft. above and another 60 to

90 ft. below the underreamer.


4. Slowly begin underreaming about 30 ft. above the key seat.5. After underreaming the key seat, circulate for about five to ten minutes

for tool clean-up. Stop circulation and wait a few minutes for pressure to equalize. This will allow the arms to collapse.

6. Slowly pull up. If you still have drag, repeat steps four and five.

DTU Disassembly1. Remove top sub. Break connections while tool is still in the rotary.2. Remove hinge pin retaining screws, stop pins and hinge pins.3. Slide cutter arm down and out. (DO NOT remove arm lugs

unless necessary.)4. Remove cam retainer.5. Remove piston from body. Cam will slide off lower end of piston and may

be removed through cone pockets.6. Remove piston spring from body.7. Remove bit or bullnose.8. Remove snap ring from lower bore of tool body.9. Remove piston stem packing housing from lower bore of tool body.


Piston stop

Piston springCutter arm

hinge pin and retaining screw

Piston

Jet nozzles

Cam and cam retainer

Piston housing

Piston packing

Body

Top sub

Cutter arm lug

Lug retaining screws

Cutter arm

Cutter arm stop pin and retaining screw

Piston stem

Piston stem housing packing

Piston housing retainer

Bottom box connection (shown with bit sub and bit)

Drilling-Type Underreamer (DTU) Components


Drilling-Type Underreamer (DTU) Assembly1. Thoroughly lubricate all parts with a light grease.2. Replace O-rings and the packing in the piston stem housing.

Be sure the V-lips of the packing face the bottom of the tool.3. Slide piston stem housing into lower bore of tool body.4. Replace snap ring below piston stem housing.5. Replace piston packing on piston head. Be sure V-lips face

top of tool.6. Place piston spring over piston stem and slide piston into body.7. Reach through cone pocket and slide cam over lower end of

piston stem. Move into position against shoulder. Be sure angle of cam faces down.

8. Replace cam retainer.9. Replace cutter arms.

10. Replace hinge pins and stop pins.11. Replace pin retaining screws.12. Open and close tool with pneumatic air to check that all

moving parts are functioning properly.13. Ring gauge the arms in open position.


Standard opening diameter


Optional rock bit

or bullnose

Top pin connection

Fishing neck

length

Body diameter


Drilling-Type Underreamer (DTU)


Drilling-Type Underreamer (DTU) SpecificationsTool

SeriesStandard Opening

Dia.

Optional Opening Dia.

Body Dia.

Collapsed Dia.

Through Casing Dia. x wt. (lb/ft.)

3600 6 51 ⁄2 - 6 35 ⁄8 35 ⁄8 41 ⁄2 x 155700 83 ⁄4 7 - 83 ⁄4 53 ⁄4 6 7 x 387200* 11 9 - 11 71 ⁄4 71 ⁄2 85 ⁄8 x 408200* 14 10 - 14 81 ⁄4 81 ⁄4 95 ⁄8 x 539500* 15 12 - 15 91 ⁄2 101 ⁄4 113 ⁄4 x 71

11700* 171 ⁄2 143 ⁄4 - 20 113 ⁄4 113 ⁄4 133 ⁄8 x 9215000* 171 ⁄2 - 26 171 ⁄2 - 26 143 ⁄4 143 ⁄4 16 x 7517000* 32 24 - 32 17 17 185 ⁄8 x 7822000 36 28 - 36 22 22 241 ⁄2 x 113

* Available with PDC Bearclaw cutters.Notes:1. All dimensions are given in inches


upon customer request.4. Standard cutters are open bearing

milled tooth. TCI or PDC Bearclaw cutting structures must be specified.

Ordering Instructions:When ordering or requesting quotations on the DTU, please specify:1. Tool series2. Top and bottom connections3. Fishing neck diameter4. Opening diameter5. Size and weight of casing to be

run through, if available6. Bullnose or bits are ordered

separately7. Type of cutting structure

(milled tooth, TCI or PDC)

Tool Series

Fishing Neck Length

Fishing Neck Dia.

Overall Length


Wt. (lb.)

3600 8 33 ⁄8 35 23 ⁄8 1705700 18 43 ⁄4 70 31 ⁄2 3607200* 18 53 ⁄4 74 41 ⁄8 7708200* 18 53 ⁄4 or 8 79 41 ⁄2 or 65 ⁄8 9009500* 18 8 82 65 ⁄8 1,150

11700* 20 8 96 65 ⁄8 1,67015000* 20 8 or 9 97 65 ⁄8 or 75 ⁄8 2,80017000* 20 9 or 10 87 75 ⁄8 or 85 ⁄8 3,00022000 20 9 or 10 100 75 ⁄8 or 85 ⁄8 4,400

Drilling-Type Underreamer (DTU) Specifications (continued)


DS, K2

DG, C4

Bearclaw PDC

Rock-Type Underreamer (RTU)

Cutter Options

V2

F1 TCI

DT


rock-type underreamer (rtu)The Smith RTU is a rugged three-cone underreamer. The large cones enable the RTU to underream a hole nearly twice its own body diameter. A complete range of cone availability ensures proper cutter to formation selec-tion. A variety of orifice sizes enable the operator to tailor performance to hydraulics and other conditions at the rig. The tool can be serviced on loca-tion, and the cutter arms can be quickly and easily changed on the rig floor. The tool design allows full volume circulation at all times. The RTUs can be operated with water, mud, air, aerated mud, foam or any other circulating medium.

Operating Guidelines1. Lower the tool into the hole until it reaches the top of the section to be


2. Rotate the tool slowly (30 to 50 RPM) after reaching the desired shoulder cut-out depth.

3. While rotating the drillstring, start pumps and establish flow.4. Gradually increase flow rate and RPM until desired operating parameters

are reached.

Cutting the Shoulder1. After correct pump pressure is reached, rotate the tool at 80 to 150 RPM

maximum. Mark the kelly for three ft. and drill off slowly. Rotate for five to ten minutes.

2. Disengage rotary table and pick back up while pump is still on.3. Cutter arms should be fully open now. To make quite sure, repeat the

above steps. When you reach the shoulder, you should start taking weight, indicating that you have a shoulder.

Flo-Tel Equipped Rock-Type Underreamer (RTU)Rotate the tool at 80 to 150 RPM with maximum pump pressure. Flo-Tel equipped underreamers indicate when the cutter arms are fully extended and the tool is underreaming at full gauge. Flo-Tel effectively substitutes for a larger orifice when the cutter arms are extended. Pressure on the mud pump gauge then drops by about 200 to 250 psi or the number of pump strokes increases. These clear signals from Flo-Tel assure that the hole has the right diameter every time, eliminating second trips. Flo-Tel is especially recommended for cutting shoulder in hard formations.


Underreaming the IntervalHaving cut the shoulder, add weight. A good rule of thumb is 1,000 lb. for each in. of body diameter.

Example: 6,000 lb. for a six in. tool.

Reduce speed to 80 RPM and proceed with underreaming.• Allow drum to “creep”. Do not drill off.• DO NOT allow tool to penetrate faster then 100 ft/hr. or the hole

may not open to the desired drift gauge.• DO NOT spud the tool.• Pull the underreamer at first sign of dulling (look for same signs

as on a dull rock bit). Running time will depend on formation and cutter type.

• In a sidetracking operation, remove the cement ring with an underreamer whose cutter opening is slightly larger than the original hole.

• When you encounter a hard streak formation layer, reduce table speed and add weight.


table, and engage the rotary at slow speed.2. Apply pump pressure for normal underreaming operations.3. Disengage table and lower tool to shoulder.4. Set down on shoulder and apply weight to check whether cutter arms have

reopened.5. Pick back up about two ft., engage table, bring to operating RPM and con-

tinue underreaming.Follow the above procedure after each connection.

Tripping Out of the HolePick up a few feet and turn pump off. Allow five to ten minute rotations before coming out of the hole or into the casing. Always pull into the casing shoe slowly. Be sure hydrostatic head in the drillstring is allowed to equal-ize before pulling into the casing; otherwise, forces of the fluid column may expand cutter arms during entry.


Rock-Type Underreamer (RTU) Disassembly1. Remove top sub. Break connection while tool is still in the drillstring.2. Remove Flo-Tel retainer, if applicable.3. The Flo-Tel unit may now be withdrawn from the body.4. Remove pin retaining screws. Remove arm stop pins and arm

hinge pins.5. Remove cutter arms. Do not remove cutter arm lugs.6. Use wrenches furnished with tool kit to remove cam locknut

and cam.7. Withdraw piston and spring from the body.

Rock-Type Underreamer (RTU) Assembly1. Thoroughly lubricate all parts with a light grease.2. Assemble piston:

• Replace piston packing with V-lips facing top end of tool.• Replace orifice, orifice O-ring and orifice retainer.

3. Place spring over piston stem and slide piston assembly into body.4. Depress piston to full open position.5. Insert cam through cone pockets, and assemble cam on the piston with cam

wrench furnished in tool kit.6. Install the cam locknut firmly.7. Install arms. Use new hinge pins and retaining screws.8. Open and close tool with pneumatic air to check that all moving parts are

functioning properly.9. Ring gauge the arms in open position.


Top sub

Body

Piston stem

Arm lug

Orifice O-ring and assembly

Cutter arm

Cam

Spring

Piston

Piston packing

Arm lug retaining screw

Arm hinge pin and retaining screw

Arm stop pin and retaining screw

Spade

Rock-Type Underreamer (RTU) Components


Rock-Type Underreamer (RTU) Components


Body diameter

Top pin connection

Fishing neck

length

Fishing neck

diameter


Rock-Type Underreamer (RTU) SpecificationsTool Series Standard

Opening Dia.Optional

Opening Dia.Body Dia.

Collapsed Dia.

Through Casing Dia. x wt. (lb/ft.)

3600 6 43 ⁄4 - 61 ⁄2 35 ⁄8 33 ⁄4 41 ⁄2 x 154500 61 ⁄2, 81 ⁄2 6 - 9 41 ⁄2 45 ⁄8 51 ⁄2 x 205700 11 8 - 11 53 ⁄4 57⁄8 7 x 385800 11 8 - 11 57⁄8 57⁄8 65 ⁄8 x 206000 12 11 - 12 6 61 ⁄8 7 x 266100 12 11 - 12 61 ⁄8 61 ⁄8 7 x 206200 12 11 - 13 61 ⁄4 61 ⁄4 7 x 177200* 14 9 - 14 71 ⁄4 73 ⁄8 85 ⁄8 x 408200* 16 10 - 16 81 ⁄4 83 ⁄8 95 ⁄8 x 479500* 171 ⁄2 13 - 18 91 ⁄2 93 ⁄4 103 ⁄4 x 45

11700* 171 ⁄2 143 ⁄4 - 22 113 ⁄4 121 ⁄4 133 ⁄8 x 6815000 LP* 26 171 ⁄2 - 30 143 ⁄4 143 ⁄4 16 x 7522000 32 - 40 32 - 40 22 22 241 ⁄2 x 113

* Available with PDC Bearclaw cutters.Notes:1. All dimensions are given in inches


upon customer request.4. Standard API regular pin connec-

tions. Others available upon customer request.

Ordering Instructions:When ordering or requesting quotations on the RTU, please specify:1. Tool series2. Top and bottom connections3. Fishing neck diameter4. Opening diameter5. Size and weight of casing to be run

through, if available6. Bullnose or bits ordered separately7. Type of cutting structure (milled tooth,

TCI or PDC)

Tool Series Fishing Neck Length

Fishing Neck Dia.

Overall Length


Wt. (lb.)

3600 8 33 ⁄8 261 ⁄2 23 ⁄8 1754500 18 41 ⁄8 67 27⁄8 2355700 18 43 ⁄4 761 ⁄2 31 ⁄2 3805800 18 43 ⁄4 761 ⁄2 31 ⁄2 3806000 18 43 ⁄4 781 ⁄2 31 ⁄2 3806100 18 43 ⁄4 781 ⁄2 31 ⁄2 3806200 18 43 ⁄4 781 ⁄2 31 ⁄2 3807200* 18 53 ⁄4 86 41 ⁄2 7758200* 18 53 ⁄4 or 8 89 41 ⁄2 or 65 ⁄8 9209500* 18 8 91 65 ⁄8 1,160

11700* 20 8 91 65 ⁄8 1,67015000 LP* 20 8 or 9 97 65 ⁄8 or 75 ⁄8 2,80022000 20 9 or 10 1241 ⁄4 75 ⁄8 or 85 ⁄8 5,900

Rock-Type Underreamer (RTU) Specifications (continued)


SPX/Drag-Type Underreamer

Special meritorious engineering award for innovation and efficiency.


spX/draG-type underreamerSPX (PDC) cutters on the cutting edge of the drag tool provides the hard-ness and wear resistance of man-made polycrystalline diamond, backed by the strength and toughness of cemented tungsten carbide. These cutters shear through soft to medium-hard formations faster than conventional tools would, and require less tool weight.

The tool features a special circulation jet nozzle which directs a portion of the flow out of each arm pocket. This action effectively cleans the cut-ting surfaces, improves removal of cuttings and dissipates frictional heat. Advantages of using the SPX/drag-type underreamer are:• Increased penetration rate• Increased on bottom time• Reduced rig time due to faster penetration• Reduced total cost per ft.• Faster penetration through producing zones minimizes formation damage

and hole stability problemsDrag-type underreamers are used in poorly consolidated soft to medium

formations where larger diameter intervals are required for gravel packing or cementing. Pilot holes can be enlarged up to three times body diameter in a single trip.

These tools can be operated with water, mud, air, aerated mud, foam or any other circulating medium. Low-cost cutter arms and orifices can be replaced in the field.

The arms of drag-type tools are dressed with long wearing cutting grade tungsten carbide.

Operating InstructionsLower the tool into the hole until it reaches the top of the section to be enlarged. Take care when running in the hole, as surge pressures can start opening the arms, which may damage the casing.

Cutting the Shoulder1. Begin rotation at 40 to 60 RPM.2. Turn on the mud pump; gradually increase flow rate 250 to

450 GPM.3. Begin to apply weight at 3,000 lb.4. Continue rotating the tool until the cutter arms are fully extended. Models

with Flo-Tel will show a sudden drop in pump pressure or increase in pump strokes.

5. Mark the kelly for three ft. and drill off slowly.6. After three ft. drill off, rotate the tool for five to ten minutes.7. Disengage rotary and pick up while the pump is still on.8. Cutter arms should be fully open now. To make sure, repeat the above

steps. When you reach the shoulder, you should start taking weight. Adjust weight and speed for optimum ROP.


Flo-Tel Equipped SPX/Drag-Type UnderreamerRotate the tool at 80 to 150 RPM with a maximum pump pressure. Flo-Tel equipped underreamers indicate when the cutter arms are fully extended and the tool is underreaming at full gauge. Flo-Tel effectively substitutes for a larger orifice when the cutter arms are extended. Pressure on the mud pump gauge then drops by about 200 to 250 psi or the number of pump stroke increases. These clear signals from Flo-Tel assure that the hole has the right diameter every time, eliminating second trips. Flo-Tel is especially recommended for cutting a shoulder in hard formations.

Underreaming the Interval1. When the cutter arms are fully extended, apply weight. Begin with 3,000

lb. and increase up to 10,000 lb.2. Continue rotating until completing the section of the hole or until a new

joint of pipe has to be added to the drillstring.


table and engage the rotary at slow speed.2. Apply pump pressure.3. Disengage rotary and lower tool to shoulder.4. Set down on shoulder and apply weight to check whether cutter arms have

reopened.5. Pick back up about two ft., engage rotary, bring to operating RPM and


Tripping Out of the HolePick up a few feet and turn pumps off. Allow five to ten minute rotations before coming out of the hole or into the casing shoe. Always pull into the casing shoe slowly. Be sure hydrostatic head in the drillstring is allowed to equalize before pulling into the casing; otherwise, forces of the fluid column may expand cutter arms during entry.

SPX/Drag-Type Underreamer Disassembly1. Remove Flo-Tel retaining ring and Flo-Tel assembly, if applicable.2. Push piston down to open cutter arms.3. Remove hinge pin retaining screws and hinge pins.4. Remove arms.5. Remove arm stops.6. Release piston and remove from tool.7. Remove piston tube retaining ring, piston head, O-rings

and packing.


Body

Piston stem retaining screw

Top sub

O-ring

Piston stem

Arm stop

Three-way jet nozzle

Flo-Tel assemblyPiston head

Piston packing

Spring

Spade

Arm stop retaining screws

Cutter arm

Arm hinge pin and retaining screw

SPX/Drag-Type Underreamer Components


SPX/Drag-Type Underreamer Assembly1. Thoroughly lubricate all parts with light grease.2. Assemble piston:

• Replace piston packing with V-lips, facing up.• Replace orifice, packing, washer and retainer.

3. Place spring over piston stem and slide assembly into body.

4. Push piston down to full open position.5. Install arms in open position using new hinge pins and

retaining screws.6. Open and close tool with pneumatic air to check that all

moving parts are functioning properly.7. Ring gauge the arms in open position.


Expanded diameter

Body diameter

Fishing neck

length

Fishing neck

diameter

SPX/Drag-Type Underreamer


SPX/Drag-Type Underreamer Specifications


unless otherwise stated.2. All weights are approximate.3. Other expanded diameters available

upon request.4. Orifices other than standard available

upon request.5. Standard API pin connections. Others

available upon request.

Ordering Instructions:When ordering or requesting quotations on the SPX/Drag-Type Underreamer, please specify:1. Tool series2. Top and bottom connections3. Fishing neck diameter4. Opening diameter5. Size and weight of casing to be run

through, if available6. Bullnose or bits are ordered separately7. Type of cutting structure (milled tooth,

TCI or PDC)

Tool Series

Body Dia.

Min. Recom. Pilot Hole

Dia.

Std. Expanded Dia. Fishing Neck Overall Length

Top Pin Conn. API Wt. (lb.)SPX Tungsten

CarbideLength Dia.

3600 33 ⁄8 33 ⁄4 N/A 9 8 33 ⁄8 261 ⁄2 23 ⁄8 Reg. 185

4500 41 ⁄2 43 ⁄4 61⁄2, 63⁄4, 81⁄2

Upon request 18 41 ⁄4 69 31 ⁄2 IF 230

4700 43 ⁄4 5 Upon request 12 18 41 ⁄8 67 27⁄8 Reg. 250

5700 53 ⁄4 6 71⁄2, 8, 81⁄2, 12, 13 16 18 43 ⁄4 70 31 ⁄2 Reg. 350

7200 71 ⁄4 75 ⁄810, 121⁄4, 13, 14, 15, 16

22 18 53 ⁄4 78 41 ⁄2 Reg. 750

8200 81 ⁄4 81 ⁄210, 121⁄4, 14, 15, 16, 17

23 18 53 ⁄4, 8 78 41 ⁄2 or 65 ⁄8

Reg. 900

9500 91 ⁄2 97⁄8 121⁄4, 171⁄2 28 18 8 78 65 ⁄8 Reg. 1,100

11700 113 ⁄4 121 ⁄4 Upon request 36 18 8, 9 86 65 ⁄8 or 75 ⁄8

Reg. 1,400


Gauge Diameter Tolerances — Underreamers

Size Tolerance6 - 9 (Incl.) + 1 ⁄16 - 0

91 ⁄2 - 13 (Incl.) + 3 ⁄32 - 0

14 - 18 (Incl.) + 1 ⁄8 - 0

20 - 30 (Incl.) + 3 ⁄16 - 0

Notes:1. All dimensions are given in inches unless otherwise stated.2. The above gauge diameters apply to a set of arms in open position

when assembled in a tool.3. The specification covers arm sets used on all RTU, DTU, Drag and

XTU underreamers.4. The specification applies to milled tooth, TCI and PDC cutting structures.


rhino® reamer systemThe Rhino Reamer System is Smith Services’ latest technology endeavor that will enable an operator to enlarge the wellbore below a restriction. The most frequently encountered restrictions are the drift diameter of the casing and the size of the wellhead. Both limit the maximum outside diameter (OD) of the tools that can pass through.

The Rhino Reamer System is capable of drilling the float equipment and continuing onward to begin hole enlargement. Hole enlargement takes place at some point below the surface. Since the tool has to first pass through the restricted bore, it incorporates expandable cutter sets which stay collapsed while the tool is run into wellbore. Once the tool has cleared the casing and wellhead, the cutter sets expand into the formation by uti-lizing the differential pressure of the drilling fluid or pneumatic medium.

The Rhino Reamer utilizes a patented Z-Drive actuation system that traverses the cutter sets to a pre-selected diameter, and then hydraulically clamps them into position. This eliminates cutter block movement and vibration, which improves PDC cutting structure life. The actuation system uses a parallel tongue and groove (Pocket Slip technology) profile machined on each side of the cutter block as well as in the tool body to guide and control cutter block deploy-ment. The Z-Drive and cutter block system eliminates conventional hinge pins and long cutter sets limited to only one opening diameter.

The Rhino Reamer uses a threaded sleeve inside the bore of the tool to adjust opening diameter. Limiting the distance the cutter block can traverse dictates the opening diameter within the designed range.


The tool is dependent on hydraulic pressure to both deploy the cutter sets and to cool and clean the cutting structure. Jet nozzles are strategically placed adjacent to each cutter block and actually travel with the cutter sets to ensure optimum cleaning at any opening diameter. The jet nozzles open only when the cutter sets are fully actuated, providing an indication at sur-face that the Rhino Reamer is open.

Once the hole is enlarged to the desired depth, the pumps are turned off allowing the cutter sets to collapse into the body. The tool is then pulled out of the hole through the restricted section.

Rhino Reamer System


Rhino Reamer Specifications Tool

SeriesMin. Pilot Hole Size

Hole Opening

Size

Max. Body

OD

Min. Collapsed

Dia.

Std. Fishing

Neck Dia.

Fishing Neck

Length Min.

Max. Thru Flow

(in.) (in.) (in.) (in.) (in.) (in.) (GPM)

3500 3M\, 4 - 4Z\x 3Z\x 3Z\x 3C\, 6Z\x 140

5750 6 6Z\x - 7Z\x 5C\v 5C\v 4C\v 18 350

6125 6Z\v 7 - 8Z\v 6Z\, 6Z\, 4C\v 18 350

8000 8C\, 9Z\v - 10 8 8 6Z\x 18 750

9250 9Z\x 10Z\x - 11C\v 9Z\v 9Z\v 6Z\x 18 750

10000 10Z\x 11Z\v - 12Z\v 10 10 8Z\v 18 1,200

11625 12 13 - 14C\v 11B\, 11B\, 8Z\v, 9Z\x 18 1,200

11750 12Z\, 13Z\v - 15 11C\v 11C\v 8Z\v, 9Z\x 18 2,000

14250 14C\v 15C\v - 17Z\x 14Z\v 14Z\v 9Z\x 18 2,000

16000 16Z\x 17Z\x - 20 16 16 9Z\x 18 2,000

16000 18Z\x 19Z\x - 22 16 18 9Z\x 18 2,000

Pre-job Planning and PreparationPre-job planning and preparation is vital to the successful deployment of the Rhino Reamer. Accurate hydraulic requirements of the tools above and below the Rhino Reamer are critical.

Mechanical AnalysisPerform a mechanical analysis on all Rhino Reamer bottom hole assem-blies to optimize the tool and stabilizer placement.

Pre-run ChecklistPrior to running the equipment, perform the pre-run checklist.• Review and evaluate job objectives with the on-site customer represen-

tative.• Verify that all necessary equipment has been delivered to the location.• Check and verify tool joint connections.• Inspect all equipment for possible damage during shipment. Inform the

customer immediately of shortages or damage.• Caliper tool, gauge drop ball (if required), and record all equipment

dimensions that will be used on the job. Record on strap sheet.• Verify the pipe tally with drilling personnel and/or customer representa-

tive to determine the starting depth for tool operation.


• Review, verify and record hydraulic requirements in order to achieve optimum performance.

General Procedure for Making up the Rhino ReamerClean and grease the API pin and box connections on the mating BHA components. If applicable, set the BHA components to be run below the tool in the rotary table. Use lifting sub and elevators to pick up Rhino Reamer tool and lower onto lower BHA. Make-up to the specified torque listed in Table 1.

Table 1 Make-up Torque of Top and Bottom Subs to Rhino Reamer Body

Tool Series Description Make-up Torque

5625, 5750, 6125 4Z\x Reg. Box x 4Z\x Reg. Box

13,000 ft/lb.

8000 6B\, Reg. Box x 6B\, Reg. Box

45,600 ft/lb.

9250 6B\, Reg. Box x 6B\, Reg. Box

56,200 ft/lb.

10000, 10375 T-38 Box x T-38 Box 66,000 ft/lb.

11625 6B\, IF Box x 6B\, IF Box 97,800 ft/lb.

11750, 14250, 16000 T-20 Box x T-20 Box 107,600 ft/lb.

CAUTION: Never place the tongs over the cutter sets. See figure 3 for tong placement.

Figure 3 Tong Placement

Place tongs here Place tongs here


Rhino Reamer Make-up and Surface Test Procedure for Lockout Mechanism and Hole Enlargement While Drilling Only• Pick up the pre-made up rotary BHA components to be tested, make-up

the drill bit and lower it in the hole. DO NOT make-up the Rhino Reamer.• Pick up and make-up a crossover sub and/or pup joint and make-up to

the top drive.• Test the rotary steerable system and/or Measuring While Drilling

(MWD) assembly per manufacturer specifications.• Lay down the crossover sub and/or pup joint.• Pick up the Rhino Reamer assembly.• Pick up and make-up a crossover sub and/or pup joint and make-up to

the top drive.• Slack off until the Rhino Reamer cutter sets are below the

rotary table.• Bring the mud pumps online and gradually increase the flow rate to the

pre-established value as specified in the hydraulic analysis for drill out (H3).

• Verify that the cutter sets have not activated.From the time the Rhino Reamer goes through the rotary table until

it reaches bottom, care must be taken when tripping in the hole. Care should also be taken when running through diverters, blowout preven-ters (BOP), wellheads and casing shoes.


Drilling the Casing Shoe Track• Lower the BHA into the hole until it reaches the top of the cement plug. • Tag the cement plug with the drill bit and pick up approximately ten ft. off

bottom.• Start pumps and establish flow to the drill out flow rate as specified in

the hydraulic analysis (HB3 or H3) and then rotate the tool slowly (30 to 50 RPM).

• Increase RPM until desired operating parameters are reached. Ream and wash down to the top of the cement. Drill the casing shoe track with the customer specified drill out flow rate (HB3 or H3).

• Back ream and re-ream every 30 ft. of the casing shoe track drilled in an attempt to prevent the hole from packing off.

• After the casing shoe has been drilled out and a successful Formation Integrity Test is taken, it is recommended to drill ahead with the Rhino Reamer closed until the tool is 20 to 30 ft. below the casing shoe while noting torque, WOB and ROP required to drill.

CAUTION: Be aware that while drilling ahead with the Rhino Reamer closed over an extended period of time, cuttings can accu-mulate in the upper portion of the tool, possibly inhibiting full opening diameter.

• Lower the BHA into the hole until the Rhino Reamer is ten to 15 ft. below the casing shoe.

• Bring up pumps to shear out flow rate as established by the hydraulic analysis (HB4). Shut the pumps off.

• The cutter blocks should be activated now. If not sure, repeat the activa-tion steps using the shear out flow rate (HB4).

• If unable to activate the cutter sets using the shear out flow rate (HB4), drop the ball in the drill pipe.

Note: When using the ball drop mechanism, the Smith Services operator is required to gauge the drop ball to ensure that it will pass through all drill string components, i.e. float valve, PBL sub, etc. In order to drop a ball and activate the tool the Rhino Reamer must be located above the MWD.

• Slowly pump the ball down the drill string until the ball seats in the catch. • Increase the pump pressure to shear the shear pins and activate the

cutter sets.


• A decrease in pump pressure should be seen at the surface to signal that the cutter blocks are activated.

• Once the tool function is verified, proceed with cutout.Note: A pull test at the casing shoe can be performed to verify that

the cutters blocks are activated.

Cutting the Shoulder• Lower the BHA into the hole until the Rhino Reamer is ten to 15 ft.

below the casing shoe. • Rotate the tool slowly (30 to 50 RPM) and very slowly bring pumps up to

the appropriate drill ahead flow rate (H1 or HB1) to perform the cut-out. Rotate while working the tool up and down approximately five to ten ft. until a cut-out is established.

Note: The time required to initiate a cut-out will vary depending on formation type and properties.

• Establish the cut-out while noting weight and torque. • Once the cut-out is complete, with the pumps on and the rotary off,

slowly lower the Rhino Reamer towards the bottom of the cut-out.• Weight should be seen on the indicator at the bottom of the cutout

bench, verifying cutter block activation.Note: The bit should be off bottom at this time to ensure that the

weight noted is at the Rhino Reamer cutter blocks.• Drill off slowly while noting weight and torque.

Hole Enlargement• With the cutter blocks activated, the pilot hole can be enlarged. Maintain

constant drilling weight.

Tripping Out of the Hole• Perform a pull test at the casing shoe to verify that the tool is functioning

properly. Take care while pulling into the casing and other restrictions.• At the surface, thoroughly flush the inside of the tool and the cutter pock-

ets with water.The following operating parameters will serve as a guideline for all

Rhino Reamer jobs.


conventional, drill and ream, rotary steerable systemsBHA recommendations should be as follows:• Ream only — An under gauge stabilizer should be run above the under-

reamer at a distance to minimize lateral force at the underreamer cutters. The assembly below the underreamer should be an under gauge bit or slick bullnose. Minimum diameter clearance for either bit or bullnose should be one inch in pilot hole. Any full-gauge assem-blies will require BHA analysis to meet lateral force requirements.

• Hole Enlargement While Drilling (HEWD) - The BHA will be determined by mechanical analysis for lateral force requirements and directional objec-tives.

Flow distribution between reamer and bit/bullnose should be based upon application as follows:• Ream only — Minimum of 65 percent of the total flow rate should exit the

Rhino Reamer.• HEWD — Minimum of 20 percent of the total flow rate should be directed to

the bit. The balance of the flow rate should be divided between the bit and Rhino Reamer, based on the area of formation removed by each.


Table 2

Recommended HEWD Flow DistributionTool Series Min. Pilot Hole

Size (in.)Opening Dia. (in.)

% Flow to Bit % Flow to Rhino

562553/4 61/2 88 12

53/4 7 71 29

57506 61/2 88 12

6 71/2 71 29

612561/4 63/4 85 15

61/4 81/4 66 34

800083/8 91/4 85 15

83/8 10 76 24

925091/2 10 90 10

91/2 113/4 73 27

10000101/2 111/4 90 10

101/2 121/4 76 23

10375105/8 113/4 87 13

105/8 131/2 71 29

11625121/8 13 90 10

121/8 143/4 74 26

11750121/4 131/4 87 13

121/4 15 73 27

14250143/4 153/4 90 10

143/4 171/2 76 24

16000161/2 171/2 90 10

161/2 20 75 25

Note: The rig capacity and job specifications will dictate the actual hydraulics avail-able to the tool.


The optimal hydraulic horsepower per square in. should be maintained at the following:Ream only – 1.3 hhp/in.² for reamer – 0.5 hhp/in.² for bit or bullnose

HEWD – 1.3 hhp/in.² for reamer – 1.0 hhp/in.² for bit

Operating ParametersEffective weight-on-bit (WOB) should be determined by allowable torque available based on the number of PDC inserts that actually contact the underreamed bench area excluding redundant gauge cutters.

As the PDC cutters wear down, the wear flats generated will con-tinuously absorb more of the applied weight and ROP will diminish. A gradual increase of weight will usually be necessary to re-establish the ROP. Generally an increase in WOB should be implemented before rotary speed, so the PDC cutters will attain a minimum depth of cut.

For any occurrences of high torque and vibrations, adjustments in WOB and/or RPM should be considered to reduce the chances of high impact loading on the Rhino Reamer and other downhole components.

Maximum Flow Rate through the Rhino ReamerTool Series 5750

612580009250

100001037511625

11750 14250

16000

Max. through flow rate at 75 ft/sec., GPM

350 734 1147 2249 2249

Max. through flow rate at 100 ft/sec., GPM

466 979 1530 2999 2999

Available nozzle sizes (ID) 1/32 in. 5 -13 7 - 20 7 - 24 7 - 24 8 - 32

Max. flow rate through each nozzle 75 ft/sec., GPM

35 72 141 141 207

Max. flow rate through three nozzles 75 ft/sec., GPM

105 216 423 423 621

Note: The parameters stated above are recommended and actual drilling conditions may require alternate parameters.

117Hydraulics Hydraulics

Bit HydraulicsHydraulic and mechanical energy are needed for efficient rock cutting and removal when drilling. The hydraulic energy is pro-vided by the drilling medium or mud being pumped down the ID of the drillstring. The mechanical energy is supplied by the speed or RPM at which the string turns and the amount of weight applied to the bit. The weight-on-bit (WOB) controls the chip size and quantity of the cuttings. The RPM controls the fracture rate or ROP. The removal of these cuttings is both mechani-cal and hydraulic; the teeth of the bit being mechanical and the hydraulics of the orifice to lift the cuttings away from the bit and up the annulus. In order to increase the hydraulic energy nec-essary at the bit, select the correct orifice. Once the orifice is selected, consider other factors which will affect cutting removal.• Particle slip velocity • Mud properties (density, viscosity) • Circulation rate (annular velocity) • WOB • Drillstring rotation (RPM) • Pump pressure • Formation type

Once all these factors are taken into consideration we can pro-ceed with our drilling objectives, confident we will have optimum performance from our mechanical and hydraulic energy available.

The Flow of Fluid Under PressureMost noted for his study of the effects of flowing fluid under pressure was Mr. Daniel Bernoulli. Bernoulli, an eighteenth century scien-tist, was a member of a famous European family of scientists and mathematicians. He devoted a good portion of his life to studying hydraulics and the flow of fluid under pressure. He is most famous for his theory or equation (Bernoulli’s Theorem): when a fluid is flow-ing under high pressure it has a slow velocity or slow traveling time. Once restricted down to a smaller diameter, the pressure is less and velocity is increased or the fluid travels much faster. For example, let’s put some numbers to this to make it clearer.

We are pumping 300 GPM through our drillstring and return flow is 300 GPM. In the larger diameter (our drillstring ID) let’s say we have 1,000 psi pressure and a velocity, or traveling time, of 20 ft/sec. Once the fluid reaches the smaller diameter (orifice jet in bit), the psi pressure would drop to 800 psi and our velocity would exceed 100 ft/sec. — low pressure/high velocity. Thus, we have created a pressure drop or pressure differential of 200 psi (1,000 – 800 psi = 200 psi) at the orifice of the bit.

118 HydraulicsHydraulics

Underreamer HydraulicsHaving explained bit hydraulics and factors involved, let us move on to underreamer hydraulics.

Smith underreamers are hydraulically actuated. The mud pumped down the string flows into the tool’s piston bore. The pressure then moves the piston (with attached cam) down the tool, mechanically actuating the cutter arms by contact on the cam ramp. These arms will stay open as long as the pumps are on; once shut off, the piston will retract due to the piston spring moving back into a free state. All underreamers can be actuated by a minimal amount of pneumatic pressure (65 psi shop air), but we recommend a minimum pressure differential of 350 to 650 psi to maintain the open position of the tool downhole. Note: This will be higher during Underreaming While

Drilling™ (UWD™) operations.In order to maintain the proper pressure differential or pres-

sure drop we must select the correct orifice. (See example in this handbook on pages 126 through 129.) In addition to maintaining the tool open, we also rely on hydraulics in underreaming to cool and clean the cutters and lift the cutting up the annulus. So our orifice selection has to be very accurate. Problems can arise if the orifice jet is incorrect or we are pumping high flow rates (GPMs). In addition, if our mud has a high solid content, premature erosion or a washout can take place. This action can cause excessive tool damage and, due to the need to trip out of the hole, costly rig time. All Smith underreamers use 70 or 95 Series jets. The 70 Series is the jet model, a second number such as 1 ⁄2 or 16 (16 ⁄32) will be given to denote size. Based on all the same factors as we discussed in Bit Hydraulics (factors one through seven) we will be able to choose the necessary jets to keep the underreamer open, cool, clean the cutters, and lift the cuttings up the annulus, keep-ing our hole clean. If we attach a bit or bullnose to the bottom of our DTU, we must also take into consideration any extra jets which might change our pressure differential or pressure drop. So as you can see, underreamer hydraulics, like bit hydraulics, are very critical to the tool performance.

In order to determine opening force of underreamer cutters against formation use the following chart and formula.

Hydraulics 119Hydraulics Hydraulics

Hydraulic Tool Opening Force Piston Head Area (in.2)

Tool Series

DTU RTU Reamaster Drag PDC

3600 3.142 3.142

4100

4500 7.069

4700 8.296

5500 12.566

5700 12.566 12.566 9.621 12.566 12.566

5800 12.566

6000 12.566

6100 12.566

6200 12.566

7200 18.655 19.635 9.621 18.665

8200 18.655 18.665 19.635 18.665

9200

9500 30.680 18.665 30.680

10500 19.635

11000 30.680 50.266

11700 50.266 50.266 38.485 38.485

15000 30.680 50.266

16000 38.485

17000 50.266

22000 50.266 50.266

Hydraulic tool opening force: Fh = PD Ap

Where:Fh = Hydraulic opening force, lb.PD = Pressure drop across tool, psiAp = Piston head area, in.2


In order to select a flow that will not erode tool prematurely, opening force of underreamer cutters, use the following chart and formula:Maximum Hydraulic Tool Flow Rate Piston Bore TFA (in.2)

Tool Series

DTU RTU Drag K-Mill PDC

3600 .624 .624 .307

4100 .442

4500 .442 .442

4700 .307

5500 .4425700 .442 .442 .442 .442 .785

5800 .442

6100 .442 .4426200 .442

7200 1.227 .785 1.485 .4428200 1.227 .785 2.406 .442 1.227

9200 .4429500 1.227 .785 3.143 1.227

10500 .994 1.227

11000 .785 3.143 1.227

11700 3.142 1.624 .994 1.227

15000 3.142 1.624

17000 3.142

22000 3.142 7.069

Maximum hydraulic tool flow rate: VAbGPMm = 0.32

Where:GPMm = Maximum flow rate, GPMV = Piston bore velocity, ft/sec.V = 150 all tools except 45 to 117 kmV = 200, 45 to 117 kmAb = Area of piston bore, in.2Notes:1. Reamaster is not included since bore velocity depends on nozzle TFA.2. Use a piston bore velocity of 150 ft/sec. to prevent erosion.3. Values in bold under K-Mills may use 200 ft/sec. velocity due to anti-wash tubes.


The Reamaster velocity should not exceed 75 ft/sec., whereas velocity in the DTUs and RTUs should not exceed 150 ft/sec.

In order to determine velocity through underreamers and minimize erosion, use the following equation.

Piston Bore Velocity 0.32 GPMVp = Ab

Where:Vp = Piston bore velocity, ft/sec.GPM = Flow rate Ab = Area of piston bore, in.2

In order to determine pressure drop across the underreamer pis-ton use the following equation.

Hydraulic Tool Pressure Loss (MW) (GPM)

2

PD = 10,858 (TFA)2

Where:PD = Pressure drop across piston, psiMW = Mud weight, lb/gal.GPM = Pump volume through toolTFA = Total flow area of jet nozzles, in.2

The chart on the following page will determine the ratio of forma-tion removed between the underreamer (or hole opener) vs. the previously drilled pilot hole. This chart can be used to determine the correct jet nozzle selection based on the percentage of formation removed between the two holes.


Net Annular Area Removed with Underreamer or Hole Opener vs. Bit Pilot HoleBit Size

AreaOpening Dia. (in.)

6.50 7.87 8.50 9.00 9.87 11.00 12.25 13.00 13.50 14.75 16.00 17.50 20.00in. in.2 33.18 48.71 56.75 63.62 76.59 95.03 117.86 132.73 143.14 170.87 201.06 240.53 314.1641⁄8 13.36 19.843⁄4 17.72 15.4 30.957⁄8 27.11 21.5 35.2 38.567⁄8 28.27 20.3 28.4 35.361⁄8 29.47 19.1 27.2 34.1 47.0 65.5 88.3 103.261⁄4 30.68 26.0 32.9 45.8 64.3 87.1 102.061⁄2 33.18 23.5 30.4 43.3 61.8 84.6 99.563⁄4 35.79 27.8 40.7 59.2 82.0 96.977⁄8 48.71 27.8 46.3 69.1 84.083⁄8 55.09 39.9 61.9 77.6 88.081⁄2 56.75 38.2 61.1 75.9 86.483⁄4 60.13 34.8 57.7 72.5 83.0 110.7 140.991⁄2 70.88 24.1 46.9 61.8 72.2 99.9 130.197⁄8 76.59 18.4 44.3 56.1 66.6 94.3 124.5 163.9 237.6

105⁄8 88.64 29.1 44.0 54.4 82.2 112.3 151.8 225.5117⁄8 95.03 37.6 48.1 75.8 106.0 145.4 219.1121⁄4 117.86 53.0 83.1 122.6 196.2131⁄2 143.14 27.7 57.9 97.3 171.0143⁄4 170.87 30.1 69.6 143.2171⁄2 240.53 73.6207⁄8 314.16227⁄8 380.13247⁄8 452.39267⁄8 530.93287⁄8 615.75

Area = R2, where = 3.141592654.

Note: Opening area minus pilot area equals total area to be removed by under-reamer or hole opener.


Net Annular Area Removed with Underreamer or Hole Opener vs. Bit Pilot HoleBit Size

AreaOpening Dia. (in.)

22.00 24.00 26.00 28.00 30.00 32.00 36.00 38.00 40.00 42.00in. in.2 380.13 452.39 530.93 615.75 706.86 804.25 1,017.88 1,134.12 1,256.64 1,385.44

41⁄8 13.3643⁄4 17.7257⁄8 27.1167⁄8 28.2761⁄8 29.4761⁄4 30.6861⁄2 33.1863⁄4 35.7977⁄8 48.7183⁄8 55.0981⁄2 56.7583⁄4 60.1391⁄2 70.8897⁄8 76.59

105⁄8 88.64117⁄8 95.03121⁄4 117.86 262.2131⁄2 143.14 236.9143⁄4 170.87 209.2171⁄2 240.53 139.5 211.8 290.3 375.2 465.9207⁄8 314.16 138.2 216.7 301.5 392.3227⁄8 380.13 72.3 150.8 235.6 326.7 424.1 637.8 754.0 876.5 1,005.3247⁄8 452.39 78.5 163.3 254.1 351.8 565.5 681.7 804.3 933.1267⁄8 530.93 84.8 175.5 273.2 486.9 603.2 726.6 854.5287⁄8 615.75 91.1 188.5 402.1 518.4 640.9 769.7

Area = R2, where = 3.141592654.

Note: Opening area minus pilot area equals total area to be removed by underreamer or hole opener.


HydraulicsTo ensure a successful underreaming job, it is very important to select the proper orifice sizes for the underreamer, bit or bullnose. Different jobs will require different orifice sizes based on parameters such as pilot hole size, underreamer opening diameter, flow rate, mud weight, etc.

A good rule of thumb for flow is the following: 35 GPM x hole size = minimum; 50 GPM x hole size = maximum.

Example: 105/8 in. hole to be underreamed to 121 ⁄4 in.: 35 x 121 ⁄4 in. = 429 minimum GPM 50 x 121 ⁄4 in. = 612 maximum GPM

Correct Orifice SelectionOrifice size controls the force at the top of the piston which pushes the cam down and opens the cutter. In a Reamaster or DTU, the total flow area of the combination of jets in the underreamer and bit or bullnose will determine the pressure drop in the system. The cor-rect orifice size or TFA is necessary for proper operation of the tool. The following charts and examples will help you select the proper orifice size for your flow requirements.

Reamaster and Drilling-Type Underreamers (DTU)Example: 16 in. duplex mud pump with 61 ⁄4 in. liner rated at 50 GPM1. Find flow rate in GPM from pump volume tables located in the

conversion/data tables (Section 7).2. Use orifice curves on Page 126. Flow 400 GPM line into shaded

area, until the GPM line intersects an orifice size line. This estab-lishes the TFA for efficient tool operation. In this case, a combina-tion of three (12⁄32 or twelve) .330 TFA in a DTU and three (12⁄32 or 12) in the bit .330 TFA will provide a system TFA of .660. This would be a 50/50 percent flow split. The corresponding pressure drop would be 340 psi at the piston. The 340 psi added to the total drillstring system losses will determine your actual stand-pipe pressure i.e., 1,600 psi losses in system plus 340 psi drop at tool = approximately 1,940 psi standpipe indication. When the GPM line intersects more than one orifice size line, either size is correct; but when available, an intersection at mid-range of the shaded area is recommended.


K-Mill, SPX/Drag- and Rock-Type UnderreamersExample: 16 in. duplex mud pump with 61 ⁄4 in. liner rated at 50 GPM1. Find flow rate in GPM from pump volume tables located in the

conversion data tables (Section 7). Flow rate is 350 GPM.2. Use orifice curves on Page 126. Follow 350 GPM line into shaded

area, until the GPM line intersects an orifice size line. This estab-lishes the correct orifice size for efficient tool operation. In this case, either a 26 ⁄32 in. (TFA .590) or a 28 ⁄32 in. (TFA .601) orifice may be used. Corresponding pressure drops are 310 and 390 psi, respectively. When the GPM line intersects more than one orifice size line, either size is correct; but when available, an intersection at mid-range of the shaded area is recommended.

SPX/Drag- and Rock-Type Underreamers with Flo-TelFlo-Tel equipped underreamers signal the operator that the cutter arms are fully extended and the tool is underreaming at full gauge. The Flo-Tel device effectively substitutes a larger orifice when the cutter arms are extended. As a result, pressure on the pump gauge drops by approximately 200 lb. or the number of pump strokes increases. These clear signals from the Flo-Tel assure that the arms have opened completely, thus eliminating the need for any re-ream-ing or additional trips. We recommend using the Flo-Tel, especially when cutting a shoulder in hard formation.


Orifice SizeTFA

GPM

500.186 .330.389.450.518 .588 .665 .744 .831 .918 1.015 1.113 1.217 1.323

400

300

200

100

100 200 300 400 500 600 700 800 900 1,000 0

Pres

sure

dro

p (p

si)

Orifice coefficient .9510 lb/gal 75 lb/ft3

Orifice Sizes for Drilling-Type and Reamaster Underreamers

Orifice coefficient .9510 lb/gal 75 lb/ft3

Orifice SizeTFA

GPM

.110.150.196.249 .307 .371 .441 .518 .601 .690 .785 .994

Pres

sure

dro

p (p

si)

Orifice Sizes for K-Mill, SPX Drag- and Rock-Type Underreamers

500

400

300

200

100

100 200 300 400 500 600 700 0

12/3214/32

16/3218/32

20/3222/32

24/3226/32

28/3230/32

32/32 11/8

Orifice Sizes for Drilling-Type and Reamaster Underreamers

Orifice Sizes for K-Mill, SPX Drag- and Rock-Type Underreamers


Determining System HydraulicsTo calculate total system pressure (the standpipe pressure gauge reading) after selecting the correct orifice, use the following procedure.• While marking a bit run before underreaming, run the

mud pump at the underreaming flow rate (GPM).• Record the standpipe pressure with a bit at the approximate

underreaming depth.Refer to orifice curves on page 126. Find the top of the curve for

the TFA of the bit. The intersection of the flow-rate line (GPM) with the orifice curves indicates the bit pressure drop at left, correct for mud weight other than ten lb/gal. See page 126. Subtract this bit pressure drop from the standpipe pressure previously recorded. This yields the bore and annular pressure losses. Add this number to the expected reading of standpipe pressure when underreaming. See the following example.

Rock-Type Underreamer, Pumping Rate 250 gPMGiven: 1. Approximate depth of bit 5,428 ft. 2. Number and size of bit nozzles 3 - 14 ⁄32 in. (.450 TFA) 3. Flow rate when opening hole 250 GPM 4. Standpipe pressure at 250 GPM 600 psi

(from pump gauge)Find: 5. Bit pressure drop

(from orifice curves) 280 psi 6. Bore and annular pressure losses 320 psi 7. Flow rate (from #3) 250 GPM 8. Pressure drop across underreamer 290 psi

(from orifice curves, 24 ⁄32 in. = .441 TFA orifice — see page 126)

9. Expected standpipe 610 psi pressure (add #6 and #8)


Pressure Drops for Mud Weights Other than Ten lb/gal. Mud Weight Volume

Flow Rate in gPM

Pressure Drop (P) Across Nozzle of Indicated Dia. P in psi (in.)

12/32 14/32 16/32 18/32 20/32 22/32 24/32 26/32 28/32 32/32 11/8 11/4

TFA .110 .150 .196 .249 .307 .371 .441 .519 .601 .785 .994 1.227

50 18960 27270 370 20080 483 26190 611 330

100 408 239110 493 289120 587 344 215130 689 404 252140 468 292 192150 537 336 220160 611 382 251180 483 317 217200 597 391 267 189220 474 323 228240 564 385 272 197260 661 452 319 232280 524 370 269 200300 601 425 308 229320 684 483 351 261340 545 396 294360 611 444 330380 495 368 216400 548 408 239450 694 516 303 189500 637 374 233600 538 336 220700 457 300800 597 392900 496

1,000 612


Pressure Drops for Mud Weights Other than Ten lb/gal.Pressure from across the orifice is directly proportional to the mud weight. Therefore, if the circulating fluid has weight other than ten lb/gal., the correct pressure drop can be determined by multiplying the figure obtained for the table by the factor:

Actual mud weight (lb/gal.)10

Example: If 130 GPM of 12.5 lb/gal. fluid is being circulated through a 16⁄32 in. (.196 TFA) nozzle, the pressure drop is as follows:1. From the table (130 GPM, 16 ⁄32 in. nozzle):

Pressure drop = 404 psi (for ten lb/gal. mud)2. 404 x 12.5 = 505 psi 10

The correct pressure drop of 130 GPM of 12.5 lb/gal. mud, circulated through a 16 ⁄32 in. nozzle, is 505 psi.


Jet Combinations for Hydraulic ToolsJet Size (in.) Number of Jet Nozzles

Diffuser Jet

Std. Jet32 1 2 3 4 5 6 7 8 9 10 11 127 0.038 0.076 0.114 0.152 0.190 0.228 0.266 0.304 0.342 0.380 0.418 0.4568 0.049 0.098 0.147 0.196 0.245 0.294 0.343 0.392 0.441 0.490 0.539 0.5889 0.062 0.124 0.186 0.248 0.310 0.372 0.434 0.496 0.558 0.620 0.682 0.744

8/32 10 0.077 0.154 0.231 0.308 0.385 0.462 0.539 0.616 0.693 0.770 0.847 0.9249/32 11 0.093 0.186 0.279 0.372 0.465 0.558 0.651 0.744 0.837 0.930 1.023 1.11610/32 12 0.110 0.220 0.330 0.440 0.550 0.660 0.770 0.880 0.990 1.100 1.210 1.32011/32 13 0.130 0.260 0.390 0.520 0.650 0.780 0.910 1.040 1.170 1.300 1.430 1.56012/32 14 0.150 0.300 0.450 0.600 0.750 0.900 1.050 1.200 1.350 1.500 1.650 1.800

15 0.173 0.346 0.519 0.692 0.865 1.038 1.211 1.384 1.557 1.730 1.903 2.07613/32 16 0.196 0.392 0.588 0.784 0.980 1.176 1.372 1.568 1.764 1.960 2.156 2.35214/32 17 0.222 0.444 0.666 0.888 1.110 1.332 1.554 1.77615/32 18 0.249 0.498 0.747 0.996 1.245 1.494 1.743 1.99216/32 19 0.277 0.554 0.831 1.108 1.385 1.662

20 0.307 0.614 0.921 1.228 1.535 1.84222 0.371 0.742 1.113 1.484 1.855 2.22624 0.442 0.884 1.326 1.768 2.210 2.65226 0.519 1.038 1.557 2.076 2.595 3.11428 0.601 1.202 1.803 2.404 3.005 3.60630 0.690 1.380 2.070 2.760 3.450 4.14032 0.785 1.570 2.355 3.140 3.925 4.71011⁄16 0.887 1.774 2.66111⁄8 0.994 1.988 2.98211⁄4 1.227 2.454 3.68113⁄8 1.485 2.970 4.45511⁄2 1.767 3.534 5.301

Area = r2, where = 3.141592654.


Mud Weight (7 to 13.9 lb/gal.) (52.36 to 103.97 lb/ft.3)

lb/gal. bl/ft.3pt Specific gravity

gradient psi/100 ft.

depth

lb/gal. lb/ft.3 Specific gravity


depth7.0 52.36 0.84 36.33 10.5 78.54 1.26 54.517.1 53.11 0.85 36.86 10.6 79.29 1.27 55.037.2 53.86 0.86 37.38 10.7 80.04 1.28 55.557.3 54.60 0.88 37.89 10.8 80.78 1.30 56.067.4 55.35 0.89 38.41 10.9 81.53 1.31 56.587.5 56.10 0.90 38.93 11.0 82.28 1.32 57.107.6 56.85 0.91 39.45 11.1 83.03 1.33 57.627.7 57.60 0.92 39.97 11.2 83.78 1.34 58.147.8 58.34 0.94 40.49 11.3 84.52 1.36 58.667.9 59.09 0.95 41.01 11.4 85.27 1.37 59.188.0 59.84 0.96 41.53 11.5 86.02 1.38 59.708.1 60.59 0.97 42.05 11.6 86.77 1.39 60.228.2 61.34 0.98 42.57 11.7 87.52 1.40 60.748.3 62.08 0.99 43.08 11.8 88.26 1.42 61.258.4 62.38 1.00 43.29 11.9 89.01 1.43 61.778.5 63.58 1.02 44.12 12.0 89.76 1.44 62.298.6 64.33 1.03 44.65 12.1 90.51 1.45 62.818.7 65.08 1.04 45.17 12.2 91.26 1.46 63.338.8 65.82 1.06 45.68 12.3 92.00 1.48 63.858.9 66.57 1.07 46.20 12.4 92.75 1.49 64.379.0 67.32 1.08 46.72 12.5 93.50 1.50 64.899.1 68.07 1.09 47.24 12.6 94.25 1.51 65.419.2 68.82 1.10 47.76 12.7 95.00 1.52 65.939.3 69.56 1.12 48.27 12.8 95.74 1.54 66.449.4 70.31 1.13 48.80 12.9 96.49 1.55 66.969.5 71.06 1.14 49.32 13.0 97.24 1.56 67.489.6 71.81 1.15 49.84 13.1 97.99 1.57 68.019.7 72.56 1.16 50.36 13.2 98.74 1.58 68.539.8 73.30 1.18 50.87 13.3 99.48 1.60 69.049.9 74.05 1.19 51.39 13.4 100.23 1.61 69.5610.0 74.80 1.20 51.91 13.5 100.98 1.62 70.0810.1 75.55 1.21 52.43 13.6 101.73 1.63 70.6010.2 76.30 1.22 52.95 13.7 102.48 1.64 71.1210.3 77.04 1.24 53.47 13.8 103.22 1.66 71.6310.4 77.79 1.25 53.99 13.9 103.97 1.67 72.16


lb/gal.

lb/ft.3 Specific gravity


depth

lb/gal. lb/ft.3 Specific gravity


depth14.0 104.72 1.68 72.68 17.0 127.16 2.04 88.2514.1 105.47 1.69 73.20 17.1 127.91 2.05 88.7714.2 106.22 1.70 73.72 17.2 128.66 2.06 89.2914.3 106.96 1.72 74.32 17.3 129.40 2.08 89.8014.4 107.71 1.73 74.75 17.4 130.15 2.09 90.3214.5 108.46 1.74 75.27 17.5 130.90 2.10 90.84

14.6 109.21 1.75 75.79 17.6 131.65 2.11 91.3714.7 109.96 1.76 76.31 17.7 132.40 2.12 91.8914.8 110.70 1.78 76.83 17.8 133.14 2.14 92.4014.9 111.45 1.79 77.35 17.9 133.89 2.15 92.9215.0 112.20 1.80 77.87 18.0 134.64 2.16 93.4415.1 112.95 1.81 78.39 18.1 135.39 2.17 93.9615.2 113.70 1.82 78.91 18.2 136.14 2.18 94.4815.3 114.44 1.84 79.42 18.3 136.88 2.20 94.9915.4 115.19 1.85 79.94 18.4 137.63 2.21 95.5115.5 115.94 1.86 80.46 18.5 138.38 2.22 96.0415.6 116.69 1.87 80.98 18.6 139.13 2.23 96.5615.7 117.44 1.88 81.50 18.7 139.88 2.24 97.0815.8 118.18 1.90 82.07 18.8 140.62 2.26 97.5915.9 118.93 1.91 82.54 18.9 141.37 2.27 98.1116.0 119.68 1.92 83.06 19.0 142.12 2.28 98.6316.1 120.43 1.93 83.58 19.1 142.87 2.29 99.1516.2 121.18 1.94 84.10 19.2 143.62 2.30 99.6716.3 121.92 1.96 84.61 19.3 144.36 2.32 100.1916.4 122.67 1.97 85.13 19.4 145.11 2.33 100.7116.5 123.42 1.98 85.65 19.5 145.86 2.34 101.2316.6 124.17 1.99 86.17 19.6 146.61 2.35 101.7516.7 124.92 2.00 86.89 19.7 147.36 2.36 102.2716.8 125.66 2.02 87.21 19.8 148.10 2.38 102.7816.9 126.41 2.03 87.73 19.9 148.85 2.39 103.30

20.0 149.60 2.40 103.82

Mud Weight (14 to 20 lb/gal.) (104.72 to 149.60 lb/ft.3)


Areas of Circles and Nozzles (in.)Nozzle Size

Dia. Area Dia. Area Dia. Area Dia. Area

— 1⁄32 .000767 11⁄8 .9940 51⁄8 20.629 91⁄8 65.397

— 1⁄16 .003068 11⁄4 1.2272 51⁄4 21.648 91⁄4 67.201

— 3⁄32 .006903 13⁄8 1.4849 53⁄8 22.691 93⁄8 69.029

— 1⁄8 .01227 11⁄2 1.7671 51⁄2 23.758 91⁄2 70.882

— 5⁄32 .01917 15⁄8 2.0739 55⁄8 24.850 95⁄8 72.760

— 3⁄16 .02761 13⁄4 2.4053 53⁄4 25.967 93⁄4 74.662

7 7⁄32 .03758 17⁄8 2.7612 57⁄8 27.109 97⁄8 76.589

8 1⁄4 .04909 2 3.1416 6 28.274 10 78.540

9 9⁄32 .06213 21⁄8 3.5466 61⁄8 29.465 101⁄8 80.516

10 5⁄16 .07670 21⁄4 3.9761 61⁄4 30.680 101⁄4 82.516

11 11⁄32 .09281 23⁄8 4.4301 63⁄8 31.919 103⁄8 84.541

12 3⁄8 .1104 21⁄2 4.9088 61⁄2 33.183 101⁄2 86.590

13 13⁄32 .1296 25⁄8 5.4119 65⁄8 34.472 105⁄8 88.664

14 7⁄16 .1503 23⁄4 5.9396 63⁄4 35.785 103⁄4 90.763

15 15⁄32 .1726 27⁄8 6.4918 67⁄8 37.122 107⁄8 92.886

16 1⁄2 .1963 3 7.0686 7 38.485 11 95.033

17 17⁄32 .2217 31⁄8 7.6699 71⁄8 39.871 111⁄8 97.205

18 9⁄16 .2485 31⁄4 8.2958 71⁄4 41.282 111⁄4 99.402

— 19⁄32 .2769 33⁄8 8.9462 73⁄8 42.718 113⁄8 101.623

20 5⁄8 .3068 31⁄2 9.6212 71⁄2 44.179 111⁄2 103.869

— 21⁄32 .3382 35⁄8 10.3206 75⁄8 45.664 115⁄8 106.139

22 11⁄16 .3712 33⁄4 11.0447 73⁄4 47.173 113⁄4 108.434

— 23⁄32 .4057 37⁄8 11.7933 77⁄8 48.707 117⁄8 110.753

24 3⁄4 .4418 4 12.566 8 50.266 12 113.10

— 25⁄32 .4794 41⁄8 13.364 81⁄8 51.849 121⁄8 115.47

26 13⁄16 .5185 41⁄4 14.186 81⁄4 53.456 121⁄4 117.86

— 27⁄32 .5591 43⁄8 15.033 83⁄8 55.088 123⁄8 120.28

28 7⁄8 .6013 41⁄2 15.904 81⁄2 56.745 121⁄2 122.72

— 29⁄32 .6450 45⁄8 16.800 85⁄8 58.426 125⁄8 125.19

— 15⁄16 .6903 43⁄4 17.721 83⁄4 60.132 123⁄4 127.68

— 31⁄32 .7371 47⁄8 18.665 87⁄8 61.862 127⁄8 130.19

— 1 .7854 5 19.635 9 63.617 13 132.73

Area = r2, where = 3.141592654.

134 Hydraulics

Areas of Circles and Nozzles (in.) (continued)Nozzle Size

Dia. Area Dia. Area Dia. Area Dia. Area

— 131⁄8 135.30 163⁄8 210.60 195⁄8 302.49 227⁄8 410.97

— 131⁄4 137.89 161⁄2 213.82 193⁄4 306.35 23 415.48

— 133⁄8 140.50 165⁄8 217.08 197⁄8 310.24 231⁄8 420.00

— 131⁄2 143.14 163⁄4 220.35 20 314.16 231⁄4 424.56

— 135⁄8 145.80 167⁄8 223.65 201⁄8 318.10 233⁄8 429.13

— 133⁄4 148.49 17 226.98 201⁄4 322.06 231⁄2 433.74

— 137⁄8 151.20 171⁄8 230.33 203⁄8 326.05 235⁄8 438.36

— 14 153.94 171⁄4 233.71 201⁄2 330.06 233⁄4 443.01

— 141⁄8 156.70 173⁄8 237.10 205⁄8 334.10 237⁄8 447.69

— 141⁄4 159.48 171⁄2 240.53 203⁄4 338.16 24 452.39

— 143⁄8 162.30 175⁄8 243.98 207⁄8 342.25 241⁄8 457.11

— 141⁄2 165.13 173⁄4 247.45 21 346.36 241⁄4 461.86

— 145⁄8 167.99 177⁄8 250.95 211⁄8 350.50 243⁄8 466.64

— 143⁄4 170.87 18 254.47 211⁄4 354.66 241⁄2 471.44

— 147⁄8 173.78 181⁄8 258.02 213⁄8 358.84 245⁄8 476.26

— 15 176.71 181⁄4 261.59 211⁄2 363.05 243⁄4 481.11

— 151⁄8 179.67 183⁄8 265.18 215⁄8 367.28 247⁄8 485.98

— 151⁄4 182.65 181⁄2 268.80 213⁄4 371.54 25 490.87

— 153⁄8 185.66 185⁄8 272.45 217⁄8 375.83 211⁄8 495.79

— 151⁄2 188.69 183⁄4 276.12 22 380.13 251⁄4 500.74

— 155⁄8 191.75 187⁄8 279.81 221⁄8 384.46 253⁄8 505.71

— 153⁄4 194.33 19 283.53 221⁄4 388.82 251⁄2 510.71

— 157⁄8 197.93 191⁄8 287.27 223⁄8 393.20 255⁄8 515.72

— 16 201.06 191⁄4 291.04 221⁄2 397.61 253⁄4 520.77

— 161⁄8 204.22 193⁄8 294.83 225⁄8 402.04 257⁄8 525.84

— 161⁄4 207.39 191⁄2 298.65 223⁄4 406.49 26 530.93

Area = r2, where = 3.141592654.

135Hole Opening Hole Opening

Definintion of Hole openingHole opening is defined as enlarging the wellbore with a cutter of a fixed diameter, unlike an underreamer which is activated hydraulically to a predetermined diameter and then closed to a smaller diameter once interval is completed.

Hole openers are typically used to enlarge previously drilled pilot holes. This enlargement is often necessary to ensure adequate clearance for the casing and cement.

For example, a 121 ⁄4 in. bit would drill the pilot hole. A 171 ⁄2 in. hole opener would then be run in order to provide enough room to run and cement the 133 ⁄8 in. casing.

Smith offers a full range of hole openers, as well as the complete line of hole enlargers:• Fixed Diameter Hole Opener (FDHO) with GTA cutters up to

40 in. opening diameter.• Master Driller™ with cone segment cutters opening up to

36 in. diameter.• Master Driller available with Polycrystalline Diamond

Compact (PDC) cutters in requested sizes.• Hole enlargers available in 26 varying sizes up to 26 in.

opening diameter.

136 Hole OpeningHole Opening

GTA — Hole Openers/Hole Enlargers

Size Tolerance77⁄8 - 133⁄4 (Incl.) + 1⁄16 - 1⁄32

14 - 171⁄2 (Incl.) + 3⁄32 - 1⁄16

18 - 26 (Incl.) + 1⁄8 - 1⁄16

27 - 42 (Incl.) + 5⁄32 - 1⁄16

43 and Larger + 3⁄16 - 1⁄16

Notes:1. All dimensions given in inches unless otherwise stated.2. The above gauge diameters apply to GTA, STA, Master Driller and

hole enlargers.3. Unlike rock bits, the gauge area of the cutters is “as dressed” and not ground.4. Above gauge tolerances are not applicable to those orders that require specific

gauge diameters. (Some applications may require tighter gauge control.)5. The above gauge diameters apply to milled tooth and TCI cutting structures.

Weights and Rotary Recommendations for Hole Openers/Hole Enlargers

Hole Size Cutter Type Weight (lb.) Rotary Speed (RPM)Soft Formations (Soft Shale, Sand, Red Beds):

57⁄8 - 77⁄8 Milled Tooth 5,000 - 10,000 50 - 7581⁄8 - 11 Milled Tooth 10,000 - 15,000 90 - 120

111⁄4 - 151⁄4 Milled Tooth 10,000 - 25,000 125 - 150151⁄2 - 191⁄2 Milled Tooth 10,000 - 25,000 125 - 150193⁄4 - 26 Milled Tooth 15,000 - 25,000 125 - 150

Medium Formations (Medium Shale, Sand, Lime):57⁄8 - 77⁄8 Milled Tooth 5,000 - 10,000 50 - 7581⁄8 - 11 Milled Tooth 10,000 - 20,000 90 - 100

111⁄4 - 151⁄4 Milled Tooth 15,000 - 30,000 90 - 100151⁄2 - 191⁄2 Milled Tooth 15,000 - 30,000 90 - 100193⁄4 - 26 Milled Tooth 20,000 - 35,000 75 - 85

Hard Formations (Hard Lime, Dolomite, Quartzite):57⁄8 - 77⁄8 Button Type 10,000 - 15,000 50 - 75

81⁄8 - 11 Button Type 25,000 - 30,000 25,000 - 30,000*

60 - 65 35 - 40

111⁄4 - 151⁄4 Button Type 35,000 - 45,000 30,000 - 45,000*

60 - 65 35 - 45

151⁄2 - 191⁄2 Button Type 35,000 - 50,000 30,000 - 50,000*

60 - 65 35 - 45

193⁄4 - 26 Button Type 35,000 - 45,000 30,000 - 45,000*

50 - 60 30 - 40

*TCI button type for extremely hard formations.Note: All dimensions are given in inches unless otherwise stated.

Hole Opening 137Hole Opening Hole Opening

Master Driller Hole Opener


Master DrillerThe Master Driller is well suited for soft to medium-hard formations where a variety of hole sizes and formations are encountered. The tool is also used where rotary table size restrictions exist.• One body can accommodate several sizes for arms; an advantage

in locations with limited rig space or logistics problems.• Cutter arms may be installed below the rotary table when rotary

table size restrictions exist.• The tool utilizes specifically designed cones for hole openers. A

large selection of cones including milled tooth, TCI and PDC cutters.• All Master Driller hole openers feature replaceable nozzles to

assure effective hole cleaning and to cool cutter cones.• Bottom box connection allows the selection of bit or bullnose

for guidance.

Master Driller Tool Servicing• It is advisable to clean the tool after use and before storage. Steam

cleaning is preferred but washing in petroleum solvent or diesel fuel is acceptable.

• If the tool is painted prior to storage, avoid letting paint run into the arm pin holes and into the cone bearing races.

• Coat the tool joint connections with a good grade of thread lubricant and reinstall the thread protectors supplied with tool.

Changing Cutters• Remove 3 ⁄8 in. arm pin retaining screws, 1 ⁄2 in. for Series 15000-2

Master Driller.• Using drift punch furnished with tool, knock the arm pins out toward

arm pin retaining screw holes.• Discard arm pins and arm pin retaining screws as new pins and

screws are furnished with each set of arms.• Replace new cutter arm in pocket, grease lightly and install new

arm pins and new arm pin retaining screws.

Changing Jet Orifice• Clean threads in orifice seat.• Install new O-ring packing in O-ring groove on jet, grease lightly and

screw jet into seat.• Jet nozzles are available in all standard sizes (32nd increments).


Changing Arm Pin Bushings• After a number of sets of cutters have been run in the

tool, the arm pins will become loose when installed in the arm pin holes. This is due to wear in the arm pin bush-ings, and the bushings should be replaced.

• These bushings may be pressed or driven out and replaced by new bushings.

• The bushing on the side with the arm pin retaining screw may be removed in either direction. The bushing on the other side can only be removed toward the arm pocket.

• Heat is neither necessary nor desirable in the removal of the bushings.

• After the arm pin holes have been cleaned and lightly greased, the greased arm pin bushings may be replaced by pressing or driv-ing into place. Replace the short bushing in the side without the arm pin retaining screw first.

Body• Examine the body for excessive wear. Critical areas are as follows:

1. The hardfaced edge of the pilot wiper pads.2. The shirttail area of the cutter segment.3. Jet nozzles and jet nozzle retainer sleeves.


Master Driller

Fishing neck

diameter

Overall length

Fishing neck

length

Top pin connection

Body diameter


Bottom neck

diameterStandard opening diameter


Body Series

Std. Opening

Dia.

Min. Pilot Hole

Body Dia.

Fishing Neck Overall Length

Connections API Reg.

Wt. (lb.)

Length Dia. Top Pin

Bottom Box

8200 121⁄4 81⁄2 81⁄4 24 8 60 65⁄8 41⁄2 640

9500121⁄4 81⁄2 91⁄2 24 8 67 65⁄8 65⁄8 915143⁄4 91⁄2 91⁄2 24 8 67 65⁄8 65⁄8 915

11000171⁄2 91⁄2 115⁄8 24 8 70 65⁄8 65⁄8 1,100225⁄8 91⁄2 115⁄8 24 8 70 65⁄8 65⁄8 1,100

15000171⁄2 91⁄2 155⁄8 24 10 74 75⁄8 75⁄8 1,900265⁄8 121⁄4 155⁄8 24 10 74 75⁄8 75⁄8 1,900365⁄8 245⁄8 155⁄8 24 10 74 75⁄8 75⁄8 1,900



Ordering Instructions:When ordering or requesting quotations on the Master Driller, please specify:1. Body series2. Hole opening size3. Pilot hole size4. Top and bottom connections, if

other than standard 5. Fishing neck diameter, if other

than standard 6. Type of formation (soft, medium)

Master Driller Specifications


GTA Fixed Diameter Hole Openers


gta fixeD DiaMeter Hole openersThese tools are primarily used for surface holes and conductor cas-ing. The selection of cutters allows the tool to handle a wide range of formations from soft to hard-abrasive.

Features• GTA cutter sizes available from 26 to 42 in.• The GTA hole openers feature demountable cutters which are easily

replaced on the rig floor.• GTA hole openers are available with sealed bearing milled tooth or

tungsten carbide insert cutters.• Tools feature long fishing necks which can be made up below the

rotary because of size limitations.• All GTA hole openers feature replaceable nozzles to assure effective

hole cleaning.

GTA Tool Servicing• Wash down the hole opener as soon as possible after it is pulled.

Clean the mud and cuttings off the cutters, from between each cut-ter, the leg bearing surfaces and out from the cutter in the throat of the leg. Clean the wrench slots in the jet nozzle retainer.

• Flush the circulation passages with water until full flow can be seen from all nozzles and the ID to the box con nection. Allow the hole opener to drain dry. Blow out the circulation passages, if possible.

Nozzles• Use the jet nozzle wrench to remove the nozzle retainer from

the sleeve.• Clean and inspect all jet nozzle sleeve threads. Check the O-ring

seal surface at the bottom of the bore. Make sure that the surfaces are clean and undamaged. If the threads are damaged, rechase them with a 11 ⁄2 in. 12 NF tap to a minimum depth of 3 ⁄4 in.

• Inspect the O-ring for cuts, abrasion or other damage. If the O-ring is damaged or shows signs of permanent set, replace it.

• Check the retainer and jet nozzle. Make sure that the threads and O-ring sealing surfaces are clean and undamaged. Examine the jet nozzle for cracks, nicks and erosion damage. If either the retainer or the jet nozzle appear damaged, replace the assembly with a Smith Tool 95 Series jet nozzle with the required orifice diameter.

• To replace the jet nozzle, first grease the O-ring and install it in the sleeve below the threaded section and then grease the sleeve threads. Apply a coat of grease to the O-ring sealing surface and the threads of the retainer and screw the retainer into the sleeve. Tighten the retainer with the jet nozzle wrench.


Cutters and Legs• If the cutters are reusable, regrease immediately. Remove the outer

retainer pin for access to the lube fitting, and pump a high-quality molydenum disulfide-base grease through the main pin into the cen-ter of the bearing sleeve. Rotate the cutter while pumping to distrib-ute the grease through the bearing.

• If necessary, remove the cutters to inspect the legs and main pins for wear or damage. The cutters may be removed as follows:

1. GTA main pins are released by removing the 7⁄8 in. 12 NF set screw in the main pin end then slip the retainer pin sideways out of the main pin and leg.

Note: A single retainer pin is used in the outer leg on small diameter hole openers. The inner end of the main pin is inaccessible.

2. The main pin can now be pulled with the main pin puller. On GTA main pins use the 7⁄8 in. set screw hole threads.

3. Use the sliding hammer portion of the puller to jar the main pin until it slides free of the cutter assembly and the leg. The cutter will now lift out of the body.

4. Use solvent to wash clean the entire main pin, cutter assembly bore, leg faces and leg bores. Inspect all mating surfaces for galling, damage or excessive wear.

5. If the main pin is worn or damaged it must be replaced. Replacement main pins are furnished with new grease fitting, retaining pins and set screws.

6. If the cutter bearing sleeve is damaged, rebuild the cutter in accor-dance with the tool kit manual. Rebuilding the sleeve and the leg should not exceed .040 in.

7. The clearance between the end of the cutter bearing sleeve and the leg should not exceed .040 in.

• The leg should be replaced if:1. The main pin bore is damaged or measures in excess of 2.520 in.2. The anti-rotation flat (for the sleeve) on the leg is deformed in

excess of .060 in.• Any cracks are detected by magnetic particle inspection.

Replacement will be as follows.• Welding materials

1. Use 1 ⁄8 or 3 ⁄16 in. AWS E7018 low hydrogen rod.2. Weld rod coating must be kept dry to prevent hydrogen embrittle-

ment. Store at 200°F (93°C) after opening container. If rod has been exposed to humid air, bake rod one hr. at 700°F (371°C). DO NOT bake at any temperature over 800°F (427°C).


3. Use machine setting of 30 to 35 volts at 130 to 150 amps for 3 ⁄16 in. rod.

• Leg removal1. Use 3 ⁄8 in. carbon arc for removal and shop air at 90 psi mini-

mum. Machine setting is 70 to 80 volts at 300 to 350 amps.2. Start leg removal by air arcing a gouge on front of the leg 1 ⁄8 in.

above the base plate to locate the seam. Remove the weld all the way around leaving the weld across the back until last. This pro-cedure is also correct for leg removal.

3. Grind remaining base as required to remove all slag and carbon deposits.

• Leg attachment1. All legs are supplied with temporary steel straps welded on both

sides of the leg to minimize distortion. Leave the straps in place until assembly welding is done.

2. Leg base weld bevels should be ground or air arced to remove any precipitated carbides prior to welding.

3. Remove all grease, dirt or paint from the areas to be welded.4. Set dowel pins and position the legs. Check the correct hole

opener gauge diameter with new cutter assemblies temporarily in place.

5. Tack weld the leg with one in. long beads on all four sides. Use 1 ⁄8 or 3 ⁄16 in. AWS E7018 rod.

6. Preheat the base of the leg to 150°F (66°C) and verify tempera-ture with a TEMPSTIK. Deposit root pass using 3 ⁄16 in. AWS E7018 rod. Make alternate or staggered pass pattern on sides of leg. All welds will be multiple pass fillet or bevel welds. Interpass temper ature on all welds will be 250°F (121°C). Machine setting: 30 to 35 volts at 130 to 150 amps.

7. Remove slag and peen welds. Peening of all welds is recom-mended to induce favorable residual stresses and prevent crack-ing. Peening should be hard enough to cause the surface to yield. Peening, however, will not remove locked-in stress if the weld metal is cool when peened. It is recommended that each pass be peened immediately after depositing weld metal.

8. Magnetic particle inspect all welds and repair as required.9. Remove the straps and grind off excess tack welds.

10. Leg attachment is done as per paragraphs two through eight using a special leg positioning fixture. Anchor and fixture main pin to the body with a rod or bolt. Slip a cutter assembly and the new leg onto the fixture main pin with a 0.040 in. shim between the cutter and the leg. Put the tapered block, washer and nut on the pin and tighten the entire assembly into position. Weld as specified above.


11. Final ring gauging is required using new cutters to ensure that the correct hole opener diameter has been maintained (see hole opener gauge tolerances on page 136).

• Leg tolerances1. After installing a new cutter assembly and main pin, the total

clearance between the cutter bearing sleeve and the leg face should be no greater than 0.040 in. nor less than 0.020 in.

2. Peening: Straightening of a leg by peening is recommended when necessary. Opening of leg for proper clearance is done by peening on the inside of the yoke. For closing the leg, peen on the outside.

3. Heating: Straightening a leg by heating, although satisfactory, requires extreme care that the carburized main pin bores do not exceed 425°F (218°C) at any time. The leg uprights may be heated to a maximum of 1,200°F (649°C), if necessary, providing the 425°F (218°C) temperature of the pin bore is not exceeded. Temperatures during this procedure shall be verified by TEMPSTIK.

Body Repair• Examine the body for excessive wear. Critical areas are as follows:

1. The hardfaced edge of the pilot hole reamer plates supporting the circulation jet nozzles

2. The shirttail area of the leg3. Nozzle retainer sleeves4. The milled surface on the outer portion of the leg

• Hardfaced surfaces may be repaired in the field. The resulting metal deposit will not equal the hardness of the tungsten carbide, but if properly applied, it will give additional wear protection to the hole opener body.

1. Use welding rods equivalent to Servcotube 40 to 60 mesh in 3 ⁄16 or 5 ⁄32 in. diameters.

2. Set the welding machine for 150 to 200 amp at 30 to 40 volts for 5 ⁄32 in. rod, 200 to 260 amp at 30 to 40 volts for 3 ⁄16 in. rod. AC or DC, either polarity may be used.

3. Preheat the area to be resurfaced to 300°F (149°C) to 400°F (204°C). CAUTION: DO NOT heat the carburized bore of the leg above

425°F (218°C), under any conditions.4. Apply the hardfacing as stringer or weaving beads in two passes

to a maximum thickness of 1 ⁄4 in. If weaving beads are applied, the bead width shall not exceed 21 ⁄2 times the rod diameter.


Cutter Installation• Wipe a light coat of grease on the main pin, leg bores and

cutter bearing sleeve bore (be sure O-rings are in place in the sleeve bore).

• Position the cutter in the leg with the anti-rotation lug flush on the flat on the outer portion of the leg.

• Push the main pin through the leg and bearing sleeve bore and into the inner leg until the retaining pin holes are aligned. CAUTION: The square end of the gauge main pin is the inboard

end and the beveled end will be flush or slightly below the outboard face of the leg.

• Using the notch in the end of the main pin, rotate the main pin until the retainer pin holes are aligned with the holes in the leg.

• Insert the retainer pins with the flat side out toward the set screw hole and centered on the set screw hole. The screwdriver slot in the end of the retainer pin is parallel with the flat to help with align-ment. Tighten the set screws to 100 ft/lb. torque maximum.

• Cutters from stock should already be fully greased. However, the cutters may be regreased while on the body.

Corrosion PreventionAfter thorough cleaning, coat the following surfaces with a quality rust-preventative compound.• Tool joint threads and shoulders• Inner faces of the legs or in the case of smaller bodies, the leg and

body faces• Main pin bores of the leg• Cutter bearing sleeve ends and main bore


GTA Hole Opener

Overall length

Fishing neck length

Top pin connection

Fishing neck

diameter


Bottom neck length


Bottom neck

diameter


GTA Hole Opener SpecificationsStd.

Opening Dia.

Min. Pilot Hole Dia.

Fishing Neck Bottom Neck BodyLength Dia. Top Pin

Conn. API Reg.

Length Dia. Bottom Box

Conn. API Reg.

Length Min. Bore Dia.

26 14 60 191⁄2 65⁄8 - 75⁄8 12 91⁄2 75⁄8 96 1

28 16 60 197⁄8 65⁄8 - 75⁄8 12 91⁄2 75⁄8 96 1

30 18 60 197⁄8 65⁄8 - 75⁄8 12 91⁄2 75⁄8 100 2

32 20 60 10 75⁄8 - 85⁄8 15 91⁄2 85⁄8 100 2

34 22 60 10 75⁄8 - 85⁄8 15 91⁄2 85⁄8 101 2

36 24 60 10 75⁄8 - 85⁄8 15 91⁄2 85⁄8 103 3

38 26 60 10 85⁄8 15 91⁄2 85⁄8 106 3

40 28 60 10 85⁄8 15 91⁄2 85⁄8 106 3

42 30 60 10 85⁄8 15 91⁄2 75⁄8 106 3


unless otherwise stated.2. All weights are approximate.3. Replacement cutter sets include all

parts necessary for replacement.4. Cutter bearing rebuild kits are

available on special order.

Ordering Instructions for Cutters:When ordering or requesting quotations on cutters, please specify:

1. Hole size2. Soft or medium formation3. Milled tooth or tungsten carbide insert

type cutter. Tungsten carbide insert

cutters are available for GTA and STA hole openers.

Ordering Instructions:When ordering or requesting quotations on the GTA hole opener, please specify: 1. Pilot hole size2. Hole opening size3. Top and bottom connections, if

other than standard4. Fishing neck diameter, if other

than standard5. Specifications for intermediate

sizes or sizes larger than 42 in. are available upon request.


Directional model hole enlarger

with one-piece body

Model 6980 hole enlarger, standard type, with pin up/box down

Hole Enlargers


Hole enlargerHole enlargers are available in 26 sizes to provide hole enlarge-ments from six through 36 in.

Body Types• Standard model furnished box down for use with a rock bit as the

pilot, but also may be used with a bullnose. Bullnoses specified either round or sidehill.

• Directional model has an integral bullnose or stinger down.• Cluster model, with four to six cutters, is for holes larger than 26 in.,

opening a 171 ⁄2 in. hole to 36 or 42 inches in a single pass.

Features• Rigid locking system improves safety and service life of cutter by

eliminating rotation of the sleeve, yet allowing the cutter to rotate freely on ball and roller bearings.

• Jet circulation and efficient tool design provides low cost-per-foot cutting. Jet nozzles, positioned between each of the three cutter’s direct flow to shoulder of enlarged hole, can be changed to accommodate pump capacities or hydraulics programs.

• Rig floor cutter replacement is fast and easy with no need for cutting torches or welding.

• Cutter interchangeability allows a given cutter size to be used in more than one body size.

• Long-term reliability provided by ease of part replacement or repair of cutter arms and jet holders, ensuring long life and full return on tool investment.

• Ability to match to formation provides the correct cutting structure for the rock type, thus maximizing tool performance.


0625-2600 M6980 Hole enlarger BoDies fielD repair anD service proceDures

Design and Construction Background1. 0625-1250 — Machined bar stock bodies, three pocket jets (recent

mfg. 1250 has three wing jets)2. 1550-2600 — Cast-steel bodies, three pocket jets and three wing

jets (two types of wing-jet holder designs available)3. 1550-2600 — Bar stock bodies, three pocket jets and three wing

jets (two types of wing-jet holder designs)4. Jets behind the pockets are mounted in a jet holder that is welded

into the body. Standard wing jets are held by wash pipes that are welded into position in a channel formed by a pair of wing jet guardrails. The water passage is completed by cover plates between the body and the wash pipe. A plate is also welded at the top of the wash pipe to the guardrails as a mechanical protector — prevents wash pipe damage.

5. In the factory, the bodies are assembled using gauges, fixtures, etc. For field repair, actual new cutter may be used as a gauge.

6. Cross lock pins (holds cutter pin to the arm)a. Double spring pins — best suited for soft digging jobs using soft

milled tooth cutters or medium formation — hard formation milled tooth cutters.

On 1550 and larger tools, a second type is in use:b. Solid pins held in place by concentric (double) short spring pins.

Intended for button cutters or hard digging jobs. It is the intent of the design that arm pins and bushings are the main expend-able wear components in the service life of the tool body. In soft digging, body will generally come out with no body repair required so the arm-bushing servicing is a long-range require-ment. On the other hand, in extremely hard digging, the arms as well as bushings may require the same servicing as the cut-ters.


RepairsAfter each run or prior to the next run, inspect the tool.Wash cutters and tool body. Mag inspect tool/joints. Visually evaluate the following wear areas:1. If cutter is in good shape and will be rerun (i.e. will not be removed

from the body) the body must meet the following criteria:a. Check arms shirttail area — negligible wear since cutter must be

to gauge.b. Check cutter pin to arm hole clearance. Should be less than

1 ⁄64 in.c. Check cross pin locks. If using double spring pins and no sign of

corrosion, and cutter pin end appears properly oriented, one can assume spring pins are ok. It is prudent precaution to replace if time permits.

d. No signs of washout on body, jets/holders area.e. Wings hardface still visible.f. No lower necks, excessive wear or cracks on bit strap’s welds.g. Tool/joints passes mag inspection.

2. If cutter has some degree of wear and decision is not to rerun, wash body and cutter and arrange to remove cutters from body as soon as possible to prevent parts from being rust frozen.a. Bushings — remove and replace if:

• Cam ear damaged (cracked, deformed).• Hole for pin is worn oversized or elongated.• Use a new pin to check. Maximum clearance 1⁄32 in.• Evidence of cracks in weldment.

b. Washpipes — If any indication of leaks past seals of jets, remove snap rings, O-rings and jets. While the jet nozzles are out of the washpipe, check ID of washpipe for traces of erosion, washout and plugging. If ok, replace O-rings, jet nozzles and snap rings. Grease O-rings to facilitate assembly. Grease jet nozzle cavities in the washpipe ends. If indications of washout are present, return to service facility for repair.

c. Pocket jet holders — Erosion cutting across O-ring grooves and excessive body cutter pocket wear could necessitate replacing the holder. If required, return to service facility for repair.

d. Lower neck — Regular bodies (box joint). Due to the practice of strapping pilot bits to the hole enlarger lower neck, cracks are generated on the welds/edge of welds. This is probably due to the use of welding rods not compatible with the material of the body or welding procedure. If cracks are present, return to a service facility for repair.


1. Type ‘SM’ for soft to medium formations:Non-sealed: IADC Code 121Sealed: IADC Code 124

2. Type ‘H’ for medium-hard to hard formations:Non-sealed: IADC Code 321Sealed: IADC Code 324

3.Chisel button type for medium formations:Sealed only: IADC Code 415

4. Conical button type for medium-hard to hard formations:Sealed only: IADC Code 515

5. Ovoid/ogive button type for hard formations:Sealed only: IADC Code 725

1. SM 2. H

4. Conical Button 5. Ovoid/Ogive Button

3. Chisel Button


3600 M6980 Hole enlarger BoDies fielD repair anD service proceDure

Design BackgroundThe 3600 Hole Enlarger cluster-type bodies are made of 4142 alloy bar machined to receive washpipes and flanges. The gussets and flanges are mild steel plates.

Typically, cluster-type hole enlarger bodies use 1750 cutters in four to six clusters, with four jets directed to the shelf (a fifth jet is a lift booster pointed upward on 3600).

Cutters are mounted on saddles which are composed of upper arm (1750 arm), lower arm and bushing.

Cutters are radially positioned to a predetermined gauge diame-ter. Cutters on the same gauge diameter are positioned at the same height from the flange.

Cross lock pins hold cutters to saddles. Two types are in use:1. Solid retained by short concentric spring pins for button cutters in

hard formation jobs.2. Concentric spring pins.

It is the intent of the design that the saddles are the major replaceable components of the body.

InspectionAfter each run and prior to a new run, inspect the overall tool condition. If cutter will be rerun make sure:1. All pins/lock pins are secure.2. No indication of damage to the cutters or body (tool joints, jets,

body welds, necks).3. Check pilot bit.4. Wash cutters, air dry and lubricate bearings.5. Check tool joints by magnetic inspection and thread gauging.

If cutters need to be replaced, remove cutters promptly so as to avoid being rust frozen. Wash body and inspect the body for wear on the following areas:Saddle evaluation (the cutter saddle is serviced as a unit). 1. Bushing — cam ear wear or damage.2. Saddle shirttail area — pin hole fit to cutter pin tight or at worse

no more than 1 ⁄64 in. clearance. Cross lock pin hole. No visual damage. No cracks between holes or edges of holes. Shirttail hardfacing is not worn.


cHanging cutter asseMBlies

Removal of Old Assembly1. Wash hole enlarger thoroughly when removing from the hole.2. Unlock the eccentric cam locking segment by turning slightly in

the direction of the drillstring rotation, using the driving bar and hammer (See photo A, page 157).

3. Drive out the lock pin using drift pin and a hammer (See photo B, page 157).

4. Screw puller assembly into cutter pin (See photo C, page 157). Force cutter pin out with several sharp thrusts of the sliding knocker (See photo D, page 157).

5. Slide and/or pry out the used cutter.6. Inspect circulation jet, bushing, snap ring and O-ring. If necessary,

replace these parts.7. Clean body surfaces adjacent to cutter and cutter pin hole.

Installing New Assembly1. Set the new cutter assembly in the pocket with the flat in the

locking segment toward the bottom end of the body.2. Adjust the locking segment until the pin holes in the cutter and arm

are in alignment.3. Screw pin assembly wrench into cutter pin and insert to bottom of

pocket, rotating slowly until lock pin slot in the cutter pin lines up with the lock pin hole in the cutter arm.

4. Drive in outer lock pin with hammer. Then the inner lock is driven inside the outer lock pin.

5. Unscrew and remove pin assembly wrench.6. The eccentric cam locking segment will now be in the “relaxed”

position. The cam will automatically lock itself with cutter rotation.

Arm ReplacementThe Model 6980 hole enlarger is machined from a high-quality alloy steel and heat treated to metallurgical standards. Occasionally cutter arms may have to be replaced. New cutter arms, reusable welding fixtures and complete instructions are available for this type of repair. Contact a local Smith Services representative.


A. Eccentric cam is loosened by driving seg-ment in direction of drillstring rotation.

B. Locking pin is driven out through the side of the cutter arm.

C. Pin puller assembly is screwed into cutter pin and tightened.

D. Cutter pin is removed by jarring upward with several sharp thrusts of knocker.

158 Hole Opening

Size No. Enlarging

Range

Min.

Pilot

Hole

Size

Dia.

Reqd.

Upper

Neck

Dia.(s)

Upper

Neck

Length

Lower

Pilot

Dia.(s)

Lower

Neck

Length

No. of

Cutters

Body Assy. Wt.

w/Cutters (lb.)

Cutter

Assy. Wt.

Per Set

(lb.)

From To

0625 67⁄ 61⁄4 47⁄ 43⁄4 36 31⁄4 15 3 200 - 230 80675 61⁄2 63⁄4 41⁄2 43⁄4 36 31⁄4 15 5 220 - 250 10

†0787 61⁄2 77⁄8 57⁄8 53⁄4 36 41⁄2 15 3 270 - 300 140862 83⁄8 85⁄8 51⁄8 53⁄4 36 41⁄4 15 3 280 - 310 160900 83⁄4 9⁄ 51⁄2 53⁄4 36 41⁄4 15 3 285 - 315 160950 91⁄4 91⁄2 67⁄ 53⁄4 - 73⁄4 36 41⁄4 15 3 295 - 325 230987 95⁄8 97⁄8 61⁄2 53⁄4 - 73⁄4 36 41⁄4 15 3 310 - 440 35

†1062 101⁄2 105⁄8 71⁄4 73⁄4 - 81⁄4 36 51⁄2 15 3 400 - 490 35†1100 107⁄8 11 75⁄8 73⁄4 - 81⁄4 36 51⁄2 15 3 405 - 600 351250 107⁄8 121⁄4 73⁄4 73⁄4 - 81⁄4 36 51⁄2 15 3 490 - 690 55

†1375 107⁄8 131⁄2 97⁄ 73⁄4 - 81⁄4 36 51⁄2 15 3 670 - 830 55†1400 107⁄8 133⁄4 91⁄4 73⁄4 - 81⁄4 36 73⁄4 15 3 680 - 840 551550 143⁄4 151⁄2 91⁄4 73⁄4 - 10 36 73⁄4 - 10 15 3 835 - 995 100

†1650 153⁄4 161⁄2 101⁄4 73⁄4 - 9 36 73⁄4 - 9 15 3 915 - 1,075 1001750 153⁄4 171⁄2 101⁄4 73⁄4 - 10 36 73⁄4 - 10 15 3 995 - 1,155 155

†1850 153⁄4 181⁄2 111⁄4 73⁄4 - 10 36 73⁄4 - 10 15 3 1,075 - 1,235 155†2000 153⁄4 207⁄8 123⁄4 73⁄4 - 10 36 73⁄4 - 10 15 3 1,245 - 1,405 155†2100 153⁄4 217⁄8 133⁄4 73⁄4 - 10 36 73⁄4 - 10 15 3 1,260 - 1,420 1552200 153⁄4 227⁄8 113⁄4 73⁄4 - 10 36 73⁄4 - 10 15 3 1,445 - 1,605 235

†2300 153⁄4 237⁄8 123⁄4 73⁄4 - 10 36 73⁄4 - 10 15 3 1,645 - 1,805 2352400 153⁄4 247⁄8 133⁄4 73⁄4 - 10 36 73⁄4 - 10 15 3 1,845 - 2,005 2352500 153⁄4 257⁄8 143⁄4 73⁄4 - 10 36 73⁄4 - 10 15 3 1,895 - 2,055 2352600 153⁄4 267⁄8 157⁄8 73⁄4 - 10 36 73⁄4 - 10 15 3 1,945 - 2,105 425

†*3000 153⁄4 307⁄8 171⁄2 9 - 10 36 9 - 10 15 4 2,095 - 2,255 205*3600 153⁄4 367⁄8 171⁄2 9 - 10 36 9 - 10 15 6 2,405 - 2,565 310

*Over 2600 — cluster arm-type construction.† Available on special order only.Notes:1. All dimensions are given in inches


Ordering Instructions:When ordering or requesting quotations please specify:1. Body type: “standard” or “directional”

type; if “directional” type, specify “round” or “sidehill”

bullnose, or “extra-long stinger”. Also specify whether it is to be solid or if circulation through bullnose or stinger is required.

2. Body size number, pilot hole size and enlarged hole size

3. Upper and lower neck diameters and connection sizes

4. If tool is to be dressed and cutter type desired

Hole Enlarger Specifications

159Well Abandonment

Well AbAndonment - GenerAl InformAtIonWell abandonment is a specialized art. It requires experienced per-sonnel who can handle any kind of equipment, on any kind of rig, in any type of situation, as well as the right type of equipment. Smith well abandonment professionals are available worldwide to perform these critical services with the excellent tools we describe below.

Shortcut 97/8 In. cut & Pull ASSembly WIth SeAl ASSembly retrIevInG toolAssembly • Hydrauliccasingcutter• Hightorquelowspeedmudmotor• Sixft.strokebumperjar• Spear• 18in.strokebumperjar• Drillcollar,twostandsminimum• Drillpipespaceout• Sealassemblyretrievingtool• DrillpipetosurfaceNote: Allow for enough space out to strip seal assembly to riser.

Procedure • TIHuntilsealassemblyretrievingtoolisaboveseal.Note: Go on compensator before landing out with retrievable

tool.• Engagesealassemblywithretrievingtool.• Pullsealassemblyandstripupintoriser.• Spotcasingcutteratdesiredcuttingdepth.• Applyslightleft-handtorquetoengagespear(one-quarterturn).• Pullenoughoverpulltoallowforcompensation.• Startpumpandslowlyincreaseflowratetopropergallonsper

minute to run motor and cut casing.• Aftercasingcutisachievedslackofftostringweight.• Rotateone-quarterturntotherighttodisengagespear.• Pulloutofholeuntilspearisjustbelowwellhead.• Applyleft-handtorqueengagingspear.• Pulloutofholewithcasing.• Layoutsealassemblyandretrievingtoolatsurface.• Pulloutofholeuntilcasinghangerislandedoutonrotarytable.Note: Space out so spear assembly can be racked in derrick.

160 Well Abandonment

• Disengagespear.• Rackbackinderrick.• Rigup,laydowncasing.Note: We will need estimated mud weight that will be used to cut

casings with motor before job ships to run hydraulics and properly jet tools.

Shortcut Cut & Pull Assembly

Shortcut Plug & Abandonment System Spear Specifications

TheP&ASpearisaspecialpurposespearforcut&pulloperations.Thespearallowstheoperator to enter and slide to a pre-established depth without dragging the slips in the casing. Aslongastheoperatormaintainslowright-handtorqueinthereleaseslotposition,theopera-tor can raise and lower the spear without engaging the slips in the casing. Once at depth, the operator can begin low-torque left-hand rotation and slowly pick up to enter into the engage-mentslottoenterthecasing.Onceengaged,theoperatorcanpullthecasing.Thefrictionblocks maintain a constant drag on the casing that allows the operator to engage the slots by holding the weight of the outer housing.

OD(in.) 8ID(in.) 21⁄4OverallLength(in.) 126ToolJointConnection(in.) 41⁄2 IFTensileYield-SlipsEngaged(lbf.)

1,500,000

TensileYield-LugsEngaged(lbf.)

200,000

TorsionalYield-LugsEngaged(lbf-ft.)

40,000

TorsionalYield-Mandrel(lbf-ft.)

61,000

EstimatedTensileDragfromFrictionBlocks(lbf.)

1,000

EstimatedTorsionalDragfromFrictionBlocks(lbf-ft.)

<500

Note: TheP&ASpearisdesignedforstraight push/pull only. It is not designed as a back-off spear.

Bumper sub

Shortcut spear

Hydraulic pipe cutter

Mud motor

Hydra-Stroke®

161Well Abandonment

PIPe cutterSPipecuttersfeaturetungstencarbidedressed-cuttingarms.Thearms are expanded into cutting position when actuated by pump pressure.

TheP-cuttercanbeequippedwithaFlo-Teldevice,whichsignals the operator that a string has been cut through with a sud-dendropinpumppressure.Thispreventsskinningthecasingorcoming out of the hole before the cut is complete.

Pipecuttersareavailableinthreepopularsizeswithvariousarmlengthsenablingtheoperatortocutfromsixto58in.diame-ters.P-cutterscanbeusedtocutconcentricoreccentricallyhungstrings of casing, cemented or not, both quickly and safely. Unlike explosiveparting,theP-cutterassuresacleancut.

Pipe Cutting Operating Parameters•Forbestresults,runarmslongenoughtocutonlyonestringofpipeeachtrip(seepage171).

•Atthepointofcut-out,beginrotationat50RPM.Typicallytherotarywillbe50to80RPM,andwhencuttingknivesencountercasing,therewillbeanoticeableincreaseintorque.Thediffer-ence from free rotating torque will depend upon casing condition, cementintegrity,depthandotherwellconditions.Afterrotaryisestablished, torque will become more erratic until severed. Once cut through, torque and rotary will smooth out.•Aweightgainisnoticedonallcutsfollowingthefirststring.Slackoffslightlytorelievethehydraulicdraw-downofthetool.Theresult will be faster cutting.•Becauseoftheeccentricityofmultiplecasingstrings,circulationcanbelostafterthecutispartiallymade.Thisisnormal,however, cuttings are still being removed and the cutter arms are being lubricated.

•AttimestheP-cutterFlo-Telactiondoesnotshowagoodpumppressure drop at the surface because of the shallow depth. However,pumpstrokeswillincrease,indicatingfullcut-out.•MillingupwardwithaP-cuttercanresultinbackingoffashort

length of the casing above the cutter arms. In the event this hap-pens and cement in the annulus prevents pulling the upper sec-tion of the pipe, move the tool up and re-cut above the point of back-off.

•Themostseveretorqueandnoiseoccursjustpriortothefinal parting of the string.


Series No. Begin Cut-out While Cutting

GPM RPM GPM RPM5700-V 125-175 50 250-300 100-120

8200-2 125-175 50 250-325 80-100

11700-V 250-450 50 400-600 60-80

Recommended Flow Rates and Rotary Speeds

Jack-ups and SubmersiblesP-cuttersarerelativelysimpletooperateontheserigs.Therigisstationary, therefore all vertical changes in depths can be made by the length of kelly used below the rotary bushing. When the cutter reaches the predetermined cutting depth, the rotary is started and broughttothecorrectRPMtocutthatsizeofcasing.Therotarytorque should be recorded. Start the pump slowly and bring pres-sureuptorecommendedlevelforthesizeofcutterused.Therotarytorquewillincreasewhenpumppressureisapplied,andtheRPMwillusuallyslowdown.IncreaserotarytobringtheRPMbackuptothe desired speed. When the torque has more than doubled, this is an indication that the cutter has parted the casing.

Atypicalstringwouldconsistofthepipecuttingassemblyonbot-tom,crossoversubanddrillpipe.Whencutting133 ⁄8 in. and larger casing, a top sub with stabilizer blades should be used.

Semi-submersibles and Drill ShipsTocompensatefortheverticalmovementoffloaters,itisnecessaryto run the marine support swivel above the pipe cutter assembly asillustratedonpage163.Inordertohavethecutteratthecorrectdepth, the distance between the landing ring and cutter should be adjusted.Itisalsonecessarytorunalong-strokebumpersubabovethemarinesupportswivel.Thiswillallowthecuttertoremainataconstantdepthwhiletherigmovesupanddown.Abumpersubwitha six ft. stroke will compensate for the rig movement. It is not neces-sary to use the bumper sub on those rigs equipped with a motion compensator.Setthemotioncompensatortoallowfor5,000to8,000lb.ofweightrestingonthelandingring.

163Well Abandonment

Casing head

Marine swivel

30 in. casing

20 in. casing

133⁄8 in. casing

95⁄8 in. casing

Spacer sub

Pipe cutter

Drill collar or drill pipe

Stabilizer or conventional

top sub

Pipe Cutter Assembly for Floaters

Pipe Cutter Assembly for FloatersThefollowingillustrationshowsourrecommendedassembly.Smith’s well abandonment systems consist of the marine support swivel,thestabilizertopsubandthepipecutter.Thepipecut-ter assembly is located below the marine support swivel in the wellhead.Themarinesupportswivelpermitstheoperatortoverti-cally position the pipe cutter assembly and maintain that position duringoperation.Thestabilizertopsubisusedtocenterthepipecutter in the casing.

Selecting P-Cutter Lengths and DiametersThetablebelowwilldeterminearmlengthforcuttingeccentricpipe. It is recommended to add one to three in. of arm length allowing for extreme eccentric condition.


Spacer Sub Length Sizing

Calculating Spacer Sub Lengths for P CuttersWhen cutting multiple strings of casing and using a marine support swivel as a landing device, it is necessary to use shorter spacer subsasthelengthofthearmincreases.Thisallowsthenewarmtoenter the window in casing already cut.

Theformulashownbelowdeterminesthelengthofsubrequiredfor the next run using a longer set of arms.

LR=LU–(dr – du+1)

Where:LR =RequiredsublengthfornextrunLU =Lengthofsubusedonlastrundr =Armlengthfromcenterofpinholetocuttertiprequiredfor

next rundu =Armlengthfromcenterofpinholetocuttertipusedon

last run

Examples of Spacer Sub Length SizingGiven:LU =33in.

Armopeningsizesrequiredare12,16and24in.Therequiredsublengthsare33in.(12in.opening),30in.(16in.opening)and24in.(24in.opening).

Note: Tolerancesof±1⁄4 in. on sub length are acceptable.

Arm Opening Size (in.)

Arm Length (d)

dr – du + 1 LU LR

12 41⁄4 — 33 —

16 61⁄2 31⁄4 33 30

24 111⁄4 53⁄4 30 24

165Well Abandonment

Drillstring

Spacer sub

Pipe cutter

Short arms 1st cut

Long arms 2nd cut

dudr

LULR

Spacer Sub Arrangement


Eccentric Diameters (dimensions shown in inches)

Selecting P-Cutter Lengths and DiametersThetablebelowwilldeterminearmlengthforcuttingeccentricpipe. It is recommended to add one to three in. of arm length allowing for extreme eccentric condition.

Casing Combinations Eccentric Dia.

Casing Combinations Eccentric Dia.Size A Size B Size C Size A Size B Size C

195⁄8 133⁄8 20 27.881 133⁄8 26 30 49.873

195⁄8 133⁄8 24 34.839 133⁄8 26 36 55.873

195⁄8 163⁄8 20 27.916 163⁄8 20 26 32.290

195⁄8 163⁄8 24 34.874 163⁄8 20 30 40.290

195⁄8 163⁄8 26 38.874 163⁄8 20 36 52.290

103⁄4 163⁄8 20 26.791 163⁄8 24 30 41.248

103⁄4 163⁄8 24 33.749 163⁄8 24 36 53.248

103⁄4 163⁄8 26 37.749 163⁄8 26 30 41.248

133⁄8 203⁄8 26 34.915 163⁄8 26 36 53.248

133⁄8 203⁄8 30 42.915 203⁄8 24 30 37.248

133⁄8 203⁄8 36 54.915 203⁄8 24 36 49.248

133⁄8 243⁄8 30 43.873 203⁄8 26 30 37.248

133⁄8 243⁄8 36 55.873 203⁄8 26 36 49.248

For combination of casings not listed in the preceding table, the eccentric diameter can be calculated by the following formula:DECC=DBID+DCID+DCCOUP.–DACOUP.–DBCOUP.

Example of Arm Size SelectionCasingA:95 ⁄8in.,CasingB:133 ⁄8in.,CasingC:20in.Eccentricdiameter:28in.Cutterarmopeningdiameter:29to31in.

167Well Abandonment

Casing C

Casing B

Casing A

Tool and casing A

C L

DACOUP. =

Coupling diameter of A

DBID =

ID of casing B

DBCOUP. =

Coupling diameter of B

DCID =

ID of casing C

DCCOUP. =

Coupling diameter of C

DECC = Eccentric diameter

Eccentric Diameters


Pipe Cutter Components

Piston spring

Stabilizer (optional)

Piston

Body

Cutter arm

Piston packing

Hinge pin

169Well Abandonment

Pipe Cutter Disassembly1.Removehingepinretainerscrews.2.Removehingepins.3.Removecutterarms.4.RemoveFlo-Telsnapring,ifapplicable.5.RemoveFlo-Tel,ifapplicable.6.Removepiston.Removeandinspectpistonpacking.7.Removepistonspringandpistonstopring.

ServicingThetoolshouldbedisassembledandthoroughlycleanedafterthecompletionofeachjob.Steamcleaningispreferred;however,whenfacilitiesarenotavailable,cleaningsolventsmaybeused.Thepis-ton packing should be inspected after cleaning and replaced if any wearisvisible.ItisessentialforproperperformancethattheV-typelips face the top of the tool.Note: Before the tool is reassembled, all parts should be

thoroughly lubricated. Any type of light grease is suitable.

Assembly1.Replacepistonspringandstopring.2.Replacepiston.3.ReplaceFlo-Tel,ifapplicable.4.ReplaceFlo-Telsnapring,ifapplicable.5.Replacecutterarms,hingepinsandhinge

pin retaining screws.



Top pin connection

Body diameter

(Shown with optional stabilizer)

Fishing neck length

Maximum cutting

diameter

Pipe Cutter

Ordering Instructions:When ordering or requesting quotations on pipe cutters, please specify:1.Toolseries2. Standard or stabilizer top sub3.Fishingneckdiameter4.Size(s)andweight(s)ofcasing

to be cut5.Typeofrig(drillship,semi,jack-up,etc.)

6.Ifknown,specifywhethercas-ing is concentric or eccentric and whether it is cemented

171Well Abandonment

Specifications

Recommended Stabilizer Blade Diameters

Casing Size Stabilizer Blade Dia.133⁄8 123⁄8163⁄8 143⁄4203⁄8 181⁄2263⁄8 233⁄8303⁄8 273⁄8363⁄8 333⁄8

Tool Series Body Dia. Blade Length Max. Exp. Dia.

5700-V

131⁄2 101⁄2161⁄4 143⁄4

153⁄4 101⁄4 213⁄4121⁄4 251⁄4

8200-2

131⁄2 121⁄4171⁄4 191⁄4

181⁄4 101⁄2 261⁄4

161⁄2 381⁄4

221⁄4 491⁄2

11700-V

161⁄4 171⁄2101⁄4 241⁄2161⁄4 351⁄4

113⁄4 201⁄4 413⁄4221⁄4 451⁄4261⁄4 521⁄4301⁄4 591⁄4

Note: Alldimensionsaregivenininchesunlessotherwisestated.

*Recommendedwhenusing133⁄8 in. casing and larger.Notes:1.Alldimensionsaregivenininchesunlessotherwisestated.2.Allweightsareapproximate.3.Includestoolandtopsub.

Tool Series

Body Dia.

Top Pin Conn.

API Reg.

Cutting Dia.

Stabilizer Top Sub Standard Top Sub*

Min. ID

Max. OD

Fishing Neck Dia.

Fishing Neck

Length

Overall Length

Wt. (lb.)

Fishing Neck

Length

Overall Length

Wt. (lb.)

5700-V 153⁄4 31⁄2 16 25 43⁄4 18 70 350

Removablestabilizersfor75⁄8 in. casing are included with

pipe cutter8200-2 181⁄4 65⁄8 181⁄2 48 8 18 89 925 18 115 1,40011700-V 113⁄4 65⁄8, 75⁄8 121⁄2 58 8-9 20 107 1,885 32 134 2,400

Pipe Cutter Arms Specifications


cASInG bAck-off toolTheCasingBack-offToolfacilitatesback-offofuncementedcasingstumps at a selected coupling location downhole after a section has beencutandretrieved.Thisprocesscaneffectivelybeachievedinvertical or horizontal wells.

Thetoolfeaturesninesub-assemblies,includingtwohydraulicanchorsandatorquegenerator.ThehydraulicanchorsallowtheBack-offTooltobeusedinhorizontalwellsbecausedrillcollarweightisnotrequiredtoholdtheanchorsopen.Thetooliscycled,and using hydraulic pressure only, the torque generator and anchors work in tandem to breakout and unscrew the casing threaded con-nectors with approximately one-half turn per cycle. When connec-tiontorqueissufficientlylowered,theBack-offToolispulledoutof the hole, and a casing spear is run to complete the unscrewing andrecoveryofthecasingstump.Athreadedconnectionremainsdownhole for the new casing string to be stabbed into and made up.

Smith Services can also supply subs for aligning the old and new casing strings to facilitate proper make-up downhole.

Features and Benefits•Hydraulicanchoreliminatesneedfordrillcollarweighttoachieve

back-off, making the system ideal for horizontal wells.•Capableofgeneratingupto60,000ft-lbs.oftorque.•Leavesathreadedconnectionforre-engagingnewcasingstring

after worn casing is removed.•Maintainsoriginalcasingstrengthandintegrity.•Eliminatesreducedcasingdriftdiameterresultingfrominternal

casing patches.•Eliminatesleft-handdrillpipe•Eliminatesneedforovertorquingconnectionsinaleft-handwork

string on a “blind” back-off from surface.

Applications•Replacingwornordamagedsectionsofcasingbyunscrewing

uncemented casing at a selected coupling location after it has been cut and retrieved, in vertical or horizontal wells

173Well Abandonment

Casing Back-Off Tool


mArIne SuPPort SWIvelThemarinesupportswiveldesignallowsfreeandfullrotationoftools while preventing vertical movement and allows for full circula-tiondownhole.Thebearingdesignwillwithstandthemostseverethrust and radial loads encountered during cutting operations.

Marine Support Swivel Disassembly1.Removesocketheadcapscrewsandseatingplate.2.Removeallsocketheadcapscrewsandbottomretainingplate.3.ChecktheO-ringandthepackingsinthebottomretainerplate.4.Removeallsocketheadcapscrewsandtwosocketsetscrews

from the top retaining plate.5.ChecktheO-ringandthepackingsinthetopretainerplate.6.Slidethebearinghousingoffthetopofmandrel.7.Removethrustbearing.8.Removebothradialbearingandbearingspacer.

ServicingThetoolshouldbethoroughlycleanedafterthecompletionofeachjob.Steamcleaningisthepreferredmethod.However,wherethesefacilitiesarenotavailable,cleaningsolventcanbeused.Allpackingsand O-rings should be inspected after cleaning and replaced if any wear is visible.

Afterthesepartshavebeencleanedwithsolvent,theymustbelubricatedwithanti-gallingcompound.Allbearingsmustbepackedwithgrease.Allrotaryshoulderedconnectionsmustbelubricatedwith a thread compound.

Assembly1.Slideradialbearing,bearingspacerandsecondradialbearing

from the top end of mandrel into position.2. Slide thrust bearing from the bottom end of mandrel.3.Slidebearinghousingoverthemandrel.4. Install all packings and O-rings.5.Replacethetopretainingplatepackings,makingsuretheV-type

lipsofthepackingfaceup.ReplaceO-ring.6.Slidetopretainingplateintoplace,securewithcapscrews.7.Replacetwothreadprotectorsetscrews.8.Installseatingplateandsecureinplacewithscrews.9.FillbearinghousingwithS.A.E.90-weightoilorequivalent.Install

grease fitting and relief valve.10.Checkforleakageafterplugsareinstalled,andsmoothturningof

the bearing housing assembly over the mandrel.

175Well Abandonment

Bearing housing diameter

Fishing neck

diameter

ODbottom neck

diameter

Bottom pin

connection

ID bore

diameter

Seating plate

diameter

Fishing neck

length

Marine Support Swivel


Tool Series

Bearing House Dia.

Std. Seating Plate Dia.

Fishing Neck Dia.

Fishing Neck

Length

Bottom Neck Dia.

Top and Bottom Conn.

API Reg.

Overall Length

Bore Wt. (lb.)

6200-2 121⁄4 135⁄8 or143⁄8 61⁄4 36 61⁄4 41⁄2 IF 78 213⁄16 8507700-2 1315⁄16 143⁄8, 24, 30 73⁄4 or8 36 73⁄4 65⁄8 Reg. 82 213⁄16 1,300

Notes:1.Alldimensionsaregivenininchesunlessotherwisestated.2.Allweightsareapproximate.

Ordering Instructions:When ordering or requesting quotations on the marine support swivel, please specify the seating plate diameter, or make and model of subsea casing head.

Specifications

177Well Abandonment

the duAl PluG And AbAndonment SyStem – only SmIth hAS It

Mechanical Cutting vs. Explosive SeveringThousandsofplugandabandonmentjobshaveshownusthattheycan both be the best way. If you are trying to decide which method is best suited to your particular plug and abandonment requirements, it makes good sense to talk to the one company that can offer you either or both services anywhere in the world. We have been saving operatorstimeandmoneyonoffshoreplugandabandonmentjobsformorethan25years,sowefeelqualifiedtorecommendthe combination that is right for your well.

One-trip Cut and RecoveryFeatures •Reducesrigoperationtimebecausespearandcasingcutterarerun

in the same trip.•Bumperringrestsoncasinghangersothatspeargrappleandouter

housing remain stationary in the casing hanger during rotation of the cutting string, thus reducing the possibility of damage.

•Uniquegrappledesigneliminatesgrappledamagetowellhead.•Ruggedthree-bladecutterdesigncutsfast.•Cutterarmsexpanduptofivetimesthetooldiameterandachieve

maximum stability under adverse cutting conditions such as hard spots, eccentricity and interrupted cuts.

•Armsretractedbystoppingcirculationandpickingupdrillstring.•OptionalpatentedTensionCutandRecoverySystemcutsfaster

because casing is held in tension rather than compression.


Dual Plug and Abandonment System

179Well Abandonment

Wellhead Severing System


dynA-cut® deePWAter WellheAd SeverInG SyStem

Features •PatentedDeepwaterWellheadSeveringSystemoperableinwaterdepthsbeyond10,000ft.

•One-tripseverandretrieveoperation.•Seversmultiplestringsofcasing.•Usedinpipesizessevenin.orlarger.•Reducesrig-upandrunningtimebecauseelectricalcable

is eliminated.•Electricalpowertofirechargeremovedfromchargeexceptwhen

detonation is desired.•Electricalpowerconveyedtochargebydroppingunitthrough

drill pipe or by running unit on slickline or sandline.•Removablepowersourcepermitssaferecoveryofdownhole

charge should a malfunction occur.•Backupmethodofdownholedisconnectionprovidesadditional

protection should retrieval of power source be necessary.•Shallowwatersystemusingcable-fireddetonationisalsoavailable.

TheDyna-CutWellheadSeveringSystemchargeisstoredinseparatecontainersasaflammableliquid(nitromethane)andasacorrosiveacid(diethylenetriamine).Botharebiodegradableandarenot explosive until combined in the proper percentages by a Smith technician.TheExploding Bridge Wire (EBW) detonators contain no primary explosives and can only be actuated by the power unit. Since the detonators cannot be actuated by extraneous sources such as radio signals, the rig can maintain full communication throughouttheoperation.Theunarmedchargeisrunintotheholeon drill pipe and armed only after it is safely positioned below the wellhead.

181Reference Tables

API Casing DataCasing Specifications Drift ID Bit Size

Casing OD Coupling OD

Wt. with Coupling (lb/ft.)

Casing ID

41⁄2 5.0009.50 4.090 3.965 37⁄8

11.60 4.000 3.875 37⁄813.50 3.920 3.795 33⁄4

5 5.563

11.50 4.560 4.435 41⁄413.00 4.494 4.369 41⁄415.00 4.408 4.283 41⁄418.00 4.276 4.151 41⁄8

51⁄2 6.050

13.00 5.044 4.919 43⁄414.00 5.012 4.887 43⁄415.50 4.950 4.825 43⁄417.00 4.892 4.767 43⁄420.00 4.778 4.653 45⁄823.00 4.670 4.545 41⁄2

6 6.62515.00 5.524 5.399 43⁄418.00 5.424 5.299 43⁄420.00 5.352 5.227 43⁄423.00 5.240 5.115 43⁄4

65⁄8 7.390

17.00 6.135 6.010 620.00 6.049 5.924 57⁄824.00 5.921 5.796 55⁄828.00 5.791 5.666 55⁄832.00 5.675 5.550 55⁄8

7 7.656

17.00 6.538 6.413 61⁄420.00 6.456 6.331 61⁄423.00 6.366 6.241 61⁄426.00 6.276 6.151 61⁄829.00 6.184 6.059 632.00 6.094 5.969 635.00 6.004 5.879 57⁄838.00 5.920 5.795 53⁄4

75⁄8 8.500

20.00 7.125 7.000 63⁄424.00 7.025 6.900 63⁄426.40 6.969 6.844 63⁄429.70 6.875 6.750 63⁄433.70 6.765 6.640 65⁄839.00 6.625 6.500 61⁄4


182 Reference Tables

API Casing Data (continued)Casing Specifications Drift ID Bit Size

Casing OD Coupling OD

Wt. with Coupling (lb/ft.)

Casing ID

85⁄8 9.625

24.00 8.097 7.972 77⁄828.00 8.017 7.892 77⁄832.00 7.921 7.796 75⁄836.00 7.825 7.700 75⁄840.00 7.725 7.600 75⁄844.00 7.625 7.500 73⁄849.00 7.511 7.386 73⁄8

95⁄8 10.625

29.30 9.063 8.907 83⁄432.30 9.001 8.845 83⁄436.00 8.921 8.765 83⁄440.00 8.835 8.679 85⁄843.50 8.755 8.599 85⁄847.00 8.681 8.525 81⁄253.50 8.535 8.379 83⁄8

103⁄4 11.750

32.75 10.192 10.036 97⁄840.50 10.050 9.894 97⁄845.50 9.950 9.794 93⁄451.00 9.850 9.694 95⁄855.50 9.760 9.604 95⁄860.70 9.660 9.504 91⁄265.70 9.560 9.404 91⁄2

113⁄4 12.750

38.00 11.150 10.994 113⁄842.00 11.084 10.928 103⁄447.00 11.000 10.844 103⁄454.00 10.880 10.724 105⁄860.00 10.772 10.616 105⁄8

133⁄8 14.375

48.00 12.715 12.559 121⁄454.50 12.615 12.459 121⁄461.00 12.515 12.359 121⁄468.00 12.415 12.259 121⁄472.00 12.347 12.191 123⁄8

163⁄8 17.000

55.00 15.376 15.188 153⁄865.00 15.250 15.062 153⁄875.00 15.124 14.936 143⁄484.00 15.010 14.822 143⁄494.00 19.124 18.936 171⁄2

203⁄8 21.000 106.50 19.000 18.812 171⁄2133.00 18.730 18.542 171⁄2

183Reference Tables

Maximum Cone Dimensions for Three-cone Rock BitsRock Bit Comparison Chart

Size Range

Max. Dia.

Max. Length.

Milled Tooth

TCI Wt.

in. mm in. mm in. mm lb. kg lb. kg31⁄2 – 137⁄8 189 – 198 23⁄8 60 15⁄8 41 10 5 12 5

143⁄4 121 27⁄8 73 21⁄8 54 15 7 20 9157⁄8 – 161⁄4 149 – 159 41⁄4 108 31⁄8 79 35 16 45 20161⁄2 – 163⁄4 165 – 172 41⁄2 114 31⁄2 89 45 20 55 25173⁄8 – 181⁄8 187 – 203 51⁄4 133 41⁄8 102 75 34 85 39181⁄8 – 181⁄2 206 – 216 57⁄8 149 41⁄8 105 90 41 95 43185⁄8 – 191⁄8 219 – 229 61⁄8 156 45⁄8 117 95 43 100 45191⁄8 – 191⁄2 232 – 241 61⁄2 165 43⁄8 111 125 57 130 59195⁄8 – 197⁄8 245 – 251 63⁄4 171 43⁄4 121 135 61 145 66101⁄8 – 105⁄8 254 – 270 71⁄4 184 51⁄2 140 165 75 175 80111⁄8 – 117⁄8 279 – 302 77⁄8 200 57⁄8 149 195 89 210 95121⁄8 – 121⁄4 305 – 311 81⁄8 203 61⁄8 156 205 93 225 102131⁄4 – 151⁄8 337 – 381 95⁄8 244 75⁄8 194 345 157 380 173161⁄8 406 101⁄4 260 81⁄8 206 410 186 450 205171⁄2 445 111⁄2 292 85⁄8 219 515 234 545 248181⁄2 470 121⁄8 305 91⁄8 229 525 239 570 259201⁄8 508 121⁄2 318 95⁄8 244 625 284 700 318221⁄8 559 133⁄4 349 101⁄2 267 1,000 455 1,170 532241⁄8 610 151⁄4 387 111⁄4 286 1,385 629 1,400 636261⁄8 660 161⁄8 406 123⁄4 324 1,450 659 1,550 704281⁄8 711 171⁄8 432 131⁄8 330 1,550 704 1,650 750


Recommended Rock Bit Make-up TorqueSize Range API Pin Size Recommended Make-up Torque

in. mm in. mm ft/lb. N•m31⁄2 – 41⁄2 89 – 114 23⁄8 Reg. 60 3,000 – 13,500 4,000 – 14,800

45⁄8 – 5 118 – 127 27⁄8 Reg. 73 6,000 – 17,000 8,000 – 19,500

51⁄8 – 73⁄8 137 – 187 31⁄2 Reg. 89 7,000 – 19,000 9,500 – 12,000

75⁄8 – 9 194 – 229 41⁄2 Reg. 114 12,000 – 16,000 16,000 – 22,000

91⁄2 – 28* 241 – 711 65⁄8 Reg. 168 28,000 – 32,000 38,000 – 43,000

143⁄4 – 28* 375 – 711 65⁄8 Reg. or

75⁄8 Reg.

168 or

194

34,000 – 40,000 46,000 – 54,000

181⁄2 – 28* 470 – 711 75⁄8 Reg. or

85⁄8 Reg.

194 or

219

40,000 – 60,000 54,000 – 81,000

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

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

185Reference Tables

Nozzle Types and Applications for Smith Bits

Milled Tooth Series Jet/Air Series

Bit Size (in.)

Open Bearing Sealed Bearing Journal Bearing

Open Bearing

131⁄2 – 143⁄4 55

157⁄8 – 163⁄4 65 70

173⁄8 – 175⁄8 95 95

177⁄8 – 183⁄8 95 95 95 95

181⁄2 – 183⁄4 95 95 95 95

191⁄2 – 197⁄8 95 95 95 95

105⁄8 – 121⁄4 95 95 95 95

131⁄2 – 143⁄4 100 100 100

161⁄2 – 171⁄2 100 100 100

201⁄2 – 281⁄2 100 100 100

TCI Series All Three-Cone Bits

Bit Size (in.)

A1, Two-cone Outer Jets

Sealed/Journal Bearing

Full Center

Jets

Ext. Nozzles

Mini Jets

MT TCI

131⁄2 – 143⁄4 55

157⁄8 – 163⁄4 70

173⁄8 – 175⁄8 95

177⁄8 – 183⁄8 75 95 65 97 98

181⁄2 – 183⁄4 75 95 70 97 98

191⁄2 – 197⁄8 95 95 65 97 98

105⁄8 – 121⁄4 100 95 95 70 97/98 98

131⁄2 – 143⁄4 100 100 95 70 105 105

161⁄2 – 171⁄2 100 100 95 95 105 105

201⁄2 – 281⁄2 95/100 105 105

Nozzle Types and Applications for Smith Bits (cont.)

186 Reference TablesRo

ck B

it Co

mpa

rison

Cha

rt

Mill

ed T

ooth

1.

Sta

ndar

d

R

olle

r Bea

ring

Fo

rmat

ions

Smith

Hu

ghes

Re

ed

Secu

rity

1

DSJ

R

1 Y1

1 S3

SJ

Soft

Form

atio

ns/

1

Low

-com

pres

sive

2

DTJ

R

2 Y1

2 S3

J

St

reng

th

S3TJ

3

DG

J R

3 Y1

3 S4

J

S4T

S4

TJ

M

ediu

m to

Med

ium

- 1

V2J

R4

M

4NJ

Har

d Fo

rmat

ions

/

2 H

igh-

com

pres

sive

2

D

R5

M

4

St

reng

th

3

1

R7

H

7

H7J

Har

d, S

emi-a

bras

ive

2

3 Fo

rmat

ions

3

4

Series

Types

4.

Sea

led

5. S

eale

d R

olle

r Bea

ring

R

olle

r Bea

ring

Gau

ge P

rote

cted

Sm

ith

Hugh

es

Reed

Se

curit

y Sm

ith

Hugh

es

Reed

Se

curit

y

SD

S AT

X1

S11

S33S

M

SDSH

AT

XG1

MS1

1G

S33S

G

GTX

1

SS33

S M

SDSS

H

MAX

G1

SS

33SG

M

S33S

M

SDSH

OD

MAX

GT1

S3

3

S33G

SS

33G

ATX3

S44

SDG

H

ATXG

3 S1

3G

S44G

G

TX3

MSD

GH

M

AXG

3 M

S13G

SS

44G

MSD

GHO

D M

AXG

T3

M

44N

SV

H

S2

1G

M44

NG

MSV

H

M

S21G

M

M44

NG

H77

S3

1G

H77

SG

187Reference TablesRo

ck B

it Co

mpa

rison

Cha

rt (co

ntin

ued)

M

illed

Too

th

6. S

eale

d

Fr

ictio

n B

earin

g

Form

ation

s Sm

ith

Hugh

es

Reed

Se

curit

y

1

FDS

ATJ1

, GT1

H

P11

S33S

F

FD

S+

ATJ1

S H

P11+

FD

SS+

ATM

1

ATM

1S

Soft

Form

atio

ns/

1

Low

-com

pres

sive

2

FDT

ATJ2

H

P12

S33F

St

reng

th

EH

P12

3

FDG

J3

S44F

M

ediu

m to

Med

ium

- 1

FV

J4

M

44N

F

H

ard

Form

atio

ns/

2

Hig

h-co

mpr

essi

ve

2

St

reng

th

3

1

H77

F

Har

d, S

emi-a

bras

ive

2

3 Fo

rmat

ions

3

4

Series

Types

7.

Sea

led

Fric

tion

Bea

ring

G

auge

Pro

tect

ed

Smith

Hu

ghes

Re

ed

Secu

rity

M

FDSH

AT

MG

1 M

HP1

1G

S33S

GF

MFD

SSH

AT

MG

1S

MFD

SHO

D A

TJG

1H

ATM

GT1

G

TG1

JG2

S3

3GF

S33T

GF

SS33

GF

FD

GH

JG

3 H

P13G

S4

4GF

M

FDG

H

ATM

G3

MH

P13G

M

FDG

HOD

FV

H

JG4

HP2

1G

M44

NG

F

JG7

HP3

1G

H77

SGF

JG8


TCI

2. R

olle

r Bea

ring

Air

Coo

led

Fo

rmat

ions

Smith

Hu

ghes

Re

ed

Secu

rity

1

Soft

Form

atio

ns/

2

4 Lo

w-c

ompr

essi

ve

Stre

ngth

3

4

Series

Types

5.

Sea

led

Rol

ler B

earin

g 7.

Sea

led

Fric

tion

Bea

ring

G

auge

Pro

tect

ed

Gau

ge P

rote

cted

Sm

ith

Hugh

es

Reed

Se

curit

y Sm

ith

Hugh

es

Reed

Se

curit

y

M

01S

MAX

00

MS4

1A

SS80

M

F02

ATJ0

0 EH

P41A

S8

0F

M01

SOD

M

AXG

T00

AT

M00

M02

S G

TX03

GT0

0

EHP4

1H

M02

SOD

M

AX03

ATM

GT0

0

M

AXG

T03

G

T03

ATM

GT0

3

AT

X05

AT

J05

MAX

05

AT

M05

M

05S

SS81

F0

5 AT

J05C

S81F

MF0

5 AT

M05

C

F0

7 G

T03C

M

1S

GTX

09

S43A

S8

2 F1

AT

J11

HP4

3 S8

2F

M

1SO

D

MAX

09

MS4

3A

SS82

M

F1

ATM

11

SS

82F

MAX

GT0

9

F1

OD

AT

J11S

H

P43A

S8

2CF

M

F10D

AT

M11

HG

EH

P43A

AT

X11

G

T09

HP4

3H

HZS

82F

MAX

11

AT

MG

T09

EHP4

3H

ATX1

1H

AT

J11H

M

AX11

H

AT

M11

H

15JS

AT

X11C

S4

4A

SS83

F1

5, F

15D

AT

J11C

H

P44A

S8

3F

M

15S

M

S44A

F15O

D, M

F15

ATM

11C

SS83

F

M15

SD

MA

15, M

F15D

ATM

11C

G

M15

SOD

MF1

5OD

G

T09C

Rock

Bit

Com

paris

on C

hart

(cont

inue

d)

189Reference Tables

TC

I 2.

Rol

ler B

earin

g

A

ir C

oole

d

Form

ation

s Sm

ith

Hugh

es

Reed

Se

curit

y

1

Soft

to M

ediu

m-

5

hard

For

mat

ions

/

Lo

w-c

ompr

essi

ve

2

St

reng

th

3

4

S8

JA

5.

Sea

led

Rol

ler B

earin

g 7.

Sea

led

Fric

tion

Bea

ring

G

auge

Pro

tect

ed

Gau

ge P

rote

cted

Sm

ith

Hugh

es

Reed

Se

curit

y Sm

ith

Hugh

es

Reed

Se

curit

y

A1

JSL

ATX2

2 S5

1A

2SS8

2 A1

, F15

H

ATJ2

2 H

P51

S84F

MA1

SL

MAX

22

MS5

1A

F2

, F2H

AT

M22

H

P51A

SS

84F

2J

S G

TX18

,

S84

F17,

F25

AT

M18

H

P51H

S8

4CF

M

2S

MAX

GT1

8

SS84

F2

5A

ATM

GT1

8 H

P51X

D

S84F

M2S

D

M

F2, F

2D

GT1

8 EH

P51A

H

ZS84

F

MF2

D

ATM

GT2

0 EH

P51H

2S

82F

ATJ2

2S

HP5

1XM

SS

84FD

AT

M22

G

M27

S AT

X22C

S5

2A

SS85

F2

7 AT

J22C

H

P52

S85F

M27

SD

F2

71

ATM

22C

H

P52A

MF2

7 G

T18C

H

P52X

S8

5CF

M

F27D

AT

M28

3J

S AT

X33

S53A

S8

6 F3

, MF3

AT

J33

HP5

3 S8

6F

M

3S

SS86

M

F3D

AT

M33

EH

P53

SS86

F

M3S

OD

AT

X33A

F3

H

ATJ3

3A

HP5

3A

S86C

F

MF3

H

ATJ3

3S

EHP5

3A

F3

D

ATJ3

5 H

P53A

M

M

F30D

ATX3

3C

S8

8 F3

5 AT

J33C

H

P54

S88F

G

S88

F35A

AT

M33

C

S8

8FA

SS88

C

F37,

MF3

7 AT

J35C

S88C

F

F37A

S8

8CFH

F37D

MF3

7D

Series

Types

Rock

Bit

Com

paris

on C

hart

(cont

inue

d)


TCI

2. R

olle

r Bea

ring

Air

Coo

led

Fo

rmat

ions

Smith

Hu

ghes

Re

ed

Secu

rity

1

4GA

G44

M

ediu

m-h

ard

Form

atio

ns/

2 5G

A

Y62J

A M

8JA

6

Hig

h-co

mpr

essi

ve

Stre

ngth

47JA

3

G

55

Y63J

A

4

1

H

ard,

Sem

i-abr

asiv

e 2

7

and

Abra

sive

3

7GA

G77

Y7

3JA

Form

atio

ns

4

H8J

A

1

H9J

A

Ex

trem

ely

Har

d 2

8

and

Abra

sive

3

9JA

G99

Y8

3JA

H10

JA

Form

atio

ns

4

5.

Sea

led

Rol

ler B

earin

g 7.

Sea

led

Fric

tion

Bea

ring

G

auge

Pro

tect

ed

Gau

ge P

rote

cted

Sm

ith

Hugh

es

Reed

Se

curit

y Sm

ith

Hugh

es

Reed

Se

curit

y

4J

S AT

X44

M

84

F4, F

4H

ATJ4

4 H

P61

M84

F

F4A

ATJ4

4A

EHP6

1 M

84FA

F45A

HP6

1A

M84

CF

F4

5H

EH

P61A

F47,

F47

A

M

85F

5J

S AT

X44C

S6

2A

M88

F4

7H, F

5 AT

J44C

H

P62

M88

F

G

M88

F5

OD

EHP6

2 M

88FA

47JS

M

89T

MF5

HP6

2A

M89

TF

M

F5D

EHP6

2A

F57,

F57

A AT

J55

HP6

3 M

89F

F5

7D, F

57OD

AT

J55A

EH

P63

F5

7DD

AT

J55R

M90

F

F67O

D

ATJ6

6

F7

, F7O

D

ATJ7

7 H

P73

H87

F

MF7

EHP7

3

H

88

AT

J88

H

88F

F8

OD, F

8DD

H99

F

H10

0 F9

AT

J99

HP8

3 H

100F

H

H10

0

ATJ9

9A

EHP8

3

Series

Types

Rock

Bit

Com

paris

on C

hart

(cont

inue

d)

191Reference Tables

PrefixesF = Journal (pfinodal) bearing

M = Steerable-motor bit bearing

S = Sealed roller bearing

SuffixesA = Designed for air applications

C = Center jet

D = Diamond-enhanced gauge inserts

DD = Fully diamond-enhanced cutting structure

E = Full-extended nozzles

G = Super D-Gun coating

H = Heel inserts on milled tooth bits. Different, high wear-resistant grade of carbide on TCI bits for abrasive formations

L = Lug pads

N = Nominal gauge diameter

OD = Diamond-enhanced heel row inserts

P = Carbide compact in the leg back

PD = Diamond SRT in the back of the leg

Q = “Flow Plus” extended nozzles

R = SRT inserts pressed in leg for stabilization

S = Sealed roller bearing

Milled Tooth Cutting Structure DesignationsDS = Very soft formation cutting structure

DT = Soft formation cutting structure

DG = Medium formation cutting structure

V = Medium-hard formation cutting structure

TCI Cutting Structure Designations01 = Very soft formation chisel crest cutting

structure

02 = Very soft formation chisel crest cutting structure

05 = Very soft formation chisel crest cutting structure

07 = Soft formation conical cutting structure

1 = Soft formation chisel crest cutting structure

15 = Soft-medium formation chisel crest cutting structure

17 = Soft-medium formation conical cutting structure

2 = Soft-medium formation chisel crest cut-ting structure

25 = Medium formation chisel crest cutting structure

27 = Medium formation conical cutting structure



37 = Medium formation conical cutting structure


45 = Medium-hard formation chisel crest cut-ting structure

47 = Medium-hard formation conical cutting structure

5 = Medium-hard formation chisel crest cutting structure

57 = Medium-hard formation conical cutting structure

67 = Hard formation conical cutting structure




Smith Bits Drill Bit Nomenclature


Cutti

ng S

truct

ure

Bear

ings

/

Oth

er D

ull

Reas

on

Inne

r O

uter

Du

ll Cha

r. Lo

catio

n Se

als

Gau

ge

Char

. Pu

lled

1

2 3

4 5

6 7

8

IADC

Dul

l Bit

Grad

ing

Loca

tion

(4)

Rol

ler C

one

N -

Nos

e R

owM

- M

iddl

e R

owG

- G

auge

Row

A - A

ll R

ows

Con

e #

1

2

3

Fixe

d C

utte

rC

- C

one

N -

Nos

eT

- Tap

erS

- Sho

ulde

rG

- G

auge

A - A

ll Are

as

Inne

r Cut

ting

Stru

ctur

e (1

) (A

ll Inn

er R

ows)

(For

fixe

d cu

tter b

its, u

se th

e

inne

r 2/ 3

of th

e bi

t rad

ius)

Out

er C

uttin

g St

ruct

ure

(2)

(Gau

ge R

ow O

nly)

(For

fixe

d cu

tter b

its, u

se th

e

oute

r 1/ 3

of th

e bi

t rad

ius)

In c

olum

ns 1

and

2 a

line

ar s

cale

from

0 to

8

is u

sed

to d

escr

ibe

the

cond

ition

of t

he

cutti

ng s

truct

ure

acco

rdin

g to

the

follo

win

g:

Stee

l Too

th B

itsA

mea

sure

of l

ost t

ooth

hei

ght d

ue to

abr

a-sio

n an

d/or

dam

age

0 - N

o Lo

ss o

f Too

th H

eigh

t8

- Tot

al L

oss

of T

ooth

Hei

ght

Inse

rt Bi

tsA

mea

sure

of t

otal

cut

ting

stru

ctur

e re

duc-

tion

due

to lo

st, w

orn

and/

or b

roke

n in

serts

0 - N

o Lo

st, W

orn

and/

or B

roke

n In

serts

8 - A

ll In

serts

Los

t, W

orn

and/

or B

roke

n

Fixe

d C

utte

r Bits

A m

easu

re o

f los

t, w

orn

and/

or b

roke

n

cutti

ng s

truct

ure

0 - N

o Lo

st, W

orn

and/

or B

roke

n C

uttin

g St

ruct

ure

8 - A

ll of

Cut

ting

Stru

ctur

e Lo

st, W

orn

and/

or B

roke

n

Dul

l Cha

ract

eris

tics

(3)

(Use

onl

y cu

tting

stru

ctur

e re

late

d co

des)

*BC

- Bro

ken

Cone

*BF

- Bon

d Fa

ilure

*BT

- Bro

ken

Teet

h/Cu

tters

*BU

- Bal

led

Up B

it*C

C - C

rack

ed C

one

*CD

- Con

e Dr

agge

d*C

I - C

one

Inte

rfere

nce

*CR

- Cor

ed*C

T - C

hipp

ed T

eeth

/Cu

tters

*ER

- Ero

sion

*FC

- Fla

t Cre

sted

W

ear

*HC

- Hea

t Che

ckin

g*J

D - J

unk

Dam

age

*LC

- Los

t Con

e*L

N - L

ost N

ozzle

*LT

- Los

t Tee

th/

Cutte

rs*O

C - O

ff Ce

nter

Wea

r*P

B - P

inch

ed B

it*P

N - P

lugg

ed N

ozzle

/Fl

ow P

assa

ge*R

G -

Rou

nded

Gau

ge*R

O -

Rin

g O

ut*S

D - S

hirtt

ail D

amag

e*S

S - S

elf S

harp

enin

g W

ear

*TR

- Tra

ckin

g*W

O -

Was

hed

Out

BIt

*WT

- Wor

n Te

eth/

Cutte

rs*N

O -

No

Dull

Char

acte

ristic

* Sho

w co

ne n

umbe

r(s)

unde

r loc

atio

n (4

)

Rea

son

Pulle

d or

R

un T

erm

inat

ed (8

)BH

A -

Chan

ge B

otto

m H

ole

Asse

mbl

yDM

F - D

ownh

ole

Mot

or

Failu

reDT

F -

Down

hole

Too

l Fa

ilure

DSF

- Dr

illstri

ng F

ailu

reDS

T -

Drill

Stem

Tes

tDP

-

Drill

Plug

CM -

Con

ditio

n M

udCP

-

Core

Poi

ntFM

-

Form

atio

n Ch

ange

HP

- Ho

le P

robl

ems

LIH

- Le

ft in

Hol

eHR

-

Hour

s on

Bit

LOG

- Ru

n Lo

gsPP

-

Pum

p Pr

essu

rePR

-

Pene

tratio

n Ra

teRI

G -

Rig

Rep

air

TD

- To

tal D

epth

/Cas

ing

Dept

hTW

- T

wist

Off

TQ

- To

rque

WC

- W

eath

er C

ondi

tions

Bear

ings

/Sea

ls (5

)

Gau

ge (6

)M

easu

re to

nea

rest

1/

16 o

f an

in.

I - I

n G

auge

1 - 1

/16"

Out

of G

auge

2 - 2

/16"

Out

of G

auge

4 - 4

/16"

Out

of G

auge

Oth

er D

ull

Cha

ract

eris

tics

(7)

Ref

er to

col

umn

3 co

des

Non-

Seale

d Be

aring

sA

linea

r sca

le es

timati

ng

bear

ing lif

e us

ed0

- No

Life

Used

8 - A

ll Life

Use

d, i.e

. no

be

aring

life

rema

ining

Seale

d Be

aring

sE

- Sea

ls Ef

fectiv

eF

- Sea

ls Fa

iled

N - N

ot Ab

le to

Grad

eX

- Fixe

d Cu

tter B

it (B

earin

gles

s)

193Reference Tables

How to Convert “wags” to swags”Listed on the next five pages are bit selection, bit weight and RPM, hydraulic and drilling fluid property equations for the benefit of other “SWAG” users. Many should be used with a sprinkling of good judgement and a liberal amount of common sense.


A. Bit Selection Equations1. Cost per foot

B1 + R1 (T1 + t)C1 = F1

2. Breakeven time, at constant rate of penetration B2 + R1 (t) T2 = F1 C1 – R1 (T1)

B. Bit Weight-Rotational Speed Equations1. Drilling rate (soft formation)

ROP = kf1 WR2. Drilling rate (hard formation)

ROP = kf1 W1.2 R0.5

3. Bit size vs. penetration ratea. Up to 171⁄2 in.

D1ROP2 = ROP1 (D2)b. 171⁄2 to 36 in.

D1ROP2 = ROP1 x 1.25 (D2)4. Bearing wear constant

HoursCB = 100 W x R W – (1,000 100) 1,000

5. Tooth wear constant Hours x e(.01 R + .0032 W)

CT = 189.26. Mechanical horsepower at bit

HP = kb Wb1.5 Db2.5 R7. Bit weight-RPM relationship to bit pressure drop

From Fullerton, for (WbR)<250∆Pb = 0.678 Dh (WbR)0.5 f o r 250<(WbR)<350∆Pb = 0.044 Dh (WbR) f o r (WbR)>350∆Pb = 0.80 Dh (WbR)0.5

for

for

195Reference Tables

C. Hydraulic Calculation Equations1. Drill stem bore pressure losses (turbulent flow)

a. From Fanning f V2L

∆P = 25.8db. From Security

0.000061 LQ1.86 ∆P = d4.86

c. From Smith .0000765PV0.18 0.82 Q1.82 L

∆P =

d4.82

2. Bit hydraulic horsepower ∆Pb x QBHHP = 1,714

3. Jet nozzle pressure loss Q2

∆Pb = 10,858 (An)2 4. Total nozzle area

Q ( ) 0.5

An = 104.2 ∆Pb

5. Jet velocity 0.32QVn = An

6. Jet impact forceIf = 0.000516 QVn

If = 0.0173Q ∆PB x 7. Bottom hole pressure

BHP = 0.052 L8. Bottom hole circulating pressure

BHCP = BHP + ∆Pa

9. Annular pressure lossesa. From Hagan-Poiseuille for Newtonian laminar flow

µLV∆Pa = 1,500 (Dh – Dp)2

= 0.0173Q ∆PB x


C. Hydraulic Calculation Equations (continued)b. From Beck, Nuss and Dunn for plastic laminar flow

LYP VLPV∆Pa = + 225(Dh – Dp) 1,500(Dh – Dp)2

c. From Fanning for turbulent flow f LV2

25.8(Dh – Dp)d. From Security for turbulent flow

(1.4327 x 10-7) LAV2

∆Pa = Dh – Dpe. From Smith for turbulent flow

0.0000765PV0.18 0.82 Q1.82 L∆Pa =

(Dh – Dp)3 (Dh + Dp)1.82

10. Equivalent circulating density BHCPECD = .052L

11. Reynolds’ numbera. Newtonian fluids

928 VdRe = Mb. Plastic fluids (to determine “f”)

2,970 VdRe = PV

12. Average annulus flow velocity 24.5QAV = (Dh

2 – Dp2)

13. Annulus critical velocity 1.08PV + 1.08 PV2 + 9.3(Dh – Dp)2YP

Vc = (Dh – Dp)

14. Optimum annular velocityFrom Fullerton

11,800AVo = Dh

∆Pa =

197Reference Tables

C. Hydraulic Calculation Equations (continued)15. Optimum flow rate

From Fullerton 482(Dh

2 – Dp2)

Qo = Dh

16. Rock chip slip velocitya. From Stokes for laminar flow, spherical chips

8,310dC2( C – )VS = µ

b. From Pigott for laminar flow, spherical chips 3,226dC2( C – )

VS = µc. From Rittinger for turbulent flow, spherical chips

dC( C – )VS = 155.9

d. From Pigott for tubulent flow, flat chips

dC( C – )VS = 60.6

17. Effective viscositya. Viscosity definition

Ssµ = Srb. Bingham Plastic

399 YP (Dh – Dp)µ = PV + AV

c. Shear stress, Power Law fluidsSs = kSr

n

d. Effective viscosity, Power Lawµe = kSr

n–1

e. Annular shear rate 2.4 AVSr = Dh – Dp

f. Consistency index 511 (YP + PV)k = 511n


C. Hydraulic Calculation Equations (continued)g. Power Law Index

YP + 2PVn = 3.32 log10 (YP + PV)27. Total system losses or pump discharge pressure

∆Pt = ∆Ps + ∆Pc + ∆Pp + ∆Pb + ∆Pca + ∆Ppa

D. Drilling Fluid Property Equations1. Effects of plastic viscosity

ROP2 = ROP1 x 10.003(PV1 – PV2)

2. Bentonite clay effects

ROP2 = ROP1 x e.051(vol%1 – vol%2)3. Total solids effects

ROP2 = ROP1 x 10.0066(vol%1 – vol%2)4. Effects of water loss

WL2 + 35ROP2 = ROP1 x WL1 + 355. Oil content effects (vol% oil < 30%)

sin(10.6 vol%2 – 4.83) + 10.33ROP2 = ROP1 [sin(10.6 vol%1 – 4.83) + 10.33]6. Total drilling fluid effects (density, viscosity, solids,

pressure loss)For depths from 8,000 to 12,000 ft.

ROP2 = ROP1e 0.382( 1 2)

7. From Fullerton for density effectslog10kf2 = .000208(BHP1 – BHP2) + log10kf1

199Reference Tables

NomenclatureAn = Total nozzle area, in.2

AV, AVo = Average, optimum annulus velocity, fpmBHP = Bottom hole pressure, psiBHCP = Bottom hole circulating pressure, psiBHHP = Bit hydraulic horsepower, hpB1, B2 = Cost of control, proposed bit, dollarsC1 = Cost per foot of control bit, dollars/ft.CB = Bearing wearing wear constantCn = Nozzle coefficient, 95 percentCT = Tooth wear constantd = Inside pipe diameter, in.Db = Bit diameter, in.dc = Chip diameter, in.D1, D2 = Smaller, larger bit diameter, in.Dh = Hole diameter, in.Dp = Outside pipe diameter, in.e = 2.718 Naperian baseECD = Equivalent circulating density, lb/gal.f = Fanning friction factorF1 = Footage drilled, ft.k = Consistency indexkb = Formation factor for horsepower calculation ranging

from 4 x 10–5 for very hard to 14 x 10–5 for very soft formations

kf1, kf2

= Apparent, corrected formation drillability factorL = Pipe length or hole depth, ft.n = Power Law IndexPV = Plastic viscosity, cPPV1, PV2 = Initial, final plastic viscosity, cP

= Mud density, lb/gal. c = Density of cuttings, lb/gal.

1, 2 = Initial, final mud density, lb/gal.


Nomenclature (continued)∆P = Pressure loss, psi∆Pa = Annulus pressure loss, psi∆Pc, ∆Pca = Drill collar bore, annulus pressure loss, psi∆Pp, ∆Ppa = Drill pipe bore, pipe annulus pressure loss, psi∆Ps = Surface connection pressure loss, psi∆Pt = Total system losses, psi∆Pb = Bit pressure loss, psiQ = Pump volume, GPMQo = Optimum flow rate, GPMR = Bit rotational speed, RPMR1 = Rig cost or operating rate, dollars/hr.Re = Reynolds number, dimensionlessROP = Rate of penetration, ft/hr.ROP1, ROP2 = Initial, final rate of penetration, ft/hr.SS = Shear stress, dynes/cm2

Sr = Shear rate, sec.–1

t = Round trip time, hr.T1, T2 = Rotating time for control, proposed bit, hr.µ, µe = Apparent, effective viscosity, cPV = Fluid velocity, fpsVc = Critical velocity in annulus, fpsVn = Nozzle velocity, fpsVS = Chip velocity, fpmW = Weight per inch of bit diameter, lb/in.Wb = Bit weight, 1,000 lb/in. of bit diameterWL1, WL2 = Initial, final water loss, cm3/30 min.YP = Yield point, lb/100 ft.2

201Reference Tables

Recommended Minimum Make-up Torque (ft/lb.) [See Note 2 — page 203]

Notes:1. All dimensions are given in inches unless otherwise stated.

Size and Type of Connection

OD Bore of Drill Collars1 11⁄4 11⁄2 13⁄4

API NC 233 31⁄8

31⁄4

2,500† 3,300† 4,000

2,500† 3,300† 3,400

2,500† 2,600 2,600

27⁄8 PAC (See Note 4)

3 31⁄8

31⁄4

3,800† 4,900† 5,200

3,800† 4,200 4,200

2,900 2,900 2,900

23⁄8 API IF API NC 26 27⁄8 SH

31⁄2

33⁄4

4,600† 5,500

4,600† 4,700

3,700 3,700

27⁄8 XH31⁄2 DSL27⁄8 MoD. oPeN

33⁄437⁄841⁄8

4,100†5,300†8,000†

4,100†5,300†8,000†

4,100†5,300†7,400


37⁄841⁄841⁄441⁄2

4,600†7,300†8,800†10,000†

4,600†7,300†8,800†9,300

4,600†7,300†8,1008,100

API NC 3541⁄243⁄45

8,900†12,10012,100

31⁄2 XH 4 SH 31⁄2 Mod. Open

41⁄441⁄243⁄4551⁄4

5,100†8,400†11,900†13,20013,200


43⁄4551⁄451⁄2

9,900†13,800†16,00016,000

31⁄2 H-90 (See Note 3)

43⁄4551⁄451⁄2

8,700†12,700†16,900†18,500

4 FH API NC 40 4 Mod. Open 41⁄2 DSL

551⁄451⁄253⁄46

10,800†15,100†19,700†20,40020,400

4 H-90 (See Note 3)

51⁄451⁄253⁄4661⁄4


Recommended Minimum Make-up Torque (continued) (ft/lb.) [See Note 2]Bore of Drill Collars

2 21⁄4 21⁄2 213⁄16 3 31⁄4 31⁄2 313⁄16

4,600†6,8006,8006,8008,900†10,80010,800

8,900†9,2009,200

7,400†7,400†7,400†

5,100†8,400†11,70011,70011,700

5,100†8,400†10,00010,00010,000

5,100†8,2008,2008,2008,200

9,900†13,80014,60014,600

9,900†12,80012,80012,800

9,900†10,90010,90010,900

8,3008,3008,3008,300

8,700†12,700†16,70016,700

8,700†12,700†15,00015,000

8,700†12,700†13,10013,100

8,700†10,400†10,400†10,400†

10,800†15,100†18,60018,60018,600

10,800†15,100†16,90016,90016,900

10,800†14,80014,80014,80014,800

10,800†12,10012,10012,10012,100

12,500†17,300†22,300†23,500†23,500†

12,500†17,300†21,50021,50021,500

12,500†17,300†19,40019,40019,400

12,500†16,50016,50016,50016,500

203Reference Tables

Recommended Minimum Make-up Torque (ft/lb.) [See Note 2]

2. Basis of calculations for recommended make-up torque assumed the use of a thread compound containing 40 to 60 percent by weight of finely powdered metal-lic zinc or 60 percent by weight of finely powdered metallic lead, applied thor-oughly to all threads and shoulders.



41⁄2 API Reg

51⁄2 53⁄4

6 61⁄4

API NC 44

53⁄4 6

61⁄4

61⁄2

41⁄2 API FH

51⁄2 53⁄4

6 61⁄4 61⁄2

41⁄2 XH API NC 46 4 API IF 5 DSL 41⁄2 Mod. Open

53⁄4 6 61⁄4 61⁄2

63⁄4

41⁄2 H-90 (See Note 3)

53⁄4 6 61⁄4 61⁄2

63⁄4

5 H-90 (See Note 3)

61⁄4 61⁄2 63⁄4 7

51⁄2 H-90 (See Note 3)

63⁄4 771⁄4 71⁄2

51⁄2 API Reg.

63⁄4771⁄471⁄2

41⁄2 API IF API NC 50 5 XH 5 Mod. Open 51⁄2 DSL

61⁄4 61⁄2 63⁄4 7 71⁄4



2 21⁄4 21⁄2 213⁄16 3 31⁄4 31⁄2 33⁄4

15,400† 20,300† 23,400 23,400

15,400† 20,300† 21,600 21,600

15,400† 19,400 19,400 19,400

15,400† 16,200 16,200 16,200

20,600† 25,000 25,000 25,000

20,600† 23,300 23,300 23,300

20,600† 21,200 21,200 21,200

18,000 18,000 18,000 18,000

12,900† 17,900† 23,300† 27,000 27,000

12,900† 17,900† 23,300† 25,000 25,000

12,900† 17,900† 22,800 22,800 22,800

12,900† 17,900† 19,800 19,800 19,800

12,900† 17,700† 17,700† 17,700† 17,700†

17,600† 23,200† 28,000 28,000 28,000

17,600† 23,200† 25,500 25,500 25,500

17,600† 22,200 22,200 22,200 22,200

17,600† 22,200 22,200 22,200 22,200

17,600† 23,400† 28,500 28,500 28,500

17,600† 23,400† 26,000 26,000 26,000

17,600† 23,000 23,000 23,000 23,000

17,600† 21,000 21,000 21,000 21,000

25,000† 31,500† 35,000 35,000

25,000† 31,500† 33,000 33,000

25,000† 29,500 29,500 29,500

25,000† 27,000 27,000 27,000

34,000† 41,500† 42,500 42,500

34,000† 40,000 40,000 40,000

34,000† 36,500 36,500 36,500

34,000† 34,000† 34,000† 34,000†

31,500† 39,000† 42,000 42,000

31,500† 39,000† 39,500 39,500

31,500† 36,000 36,000 36,000

31,500† 33,500 33,500 33,500

22,800† 29,500† 36,000† 38,000 38,000

22,800† 29,500† 35,500 35,500 35,500

22,800† 29,500† 32,000 32,000 32,000

22,800† 29,500† 30,000 30,000 30,000

22,800† 26,500 26,500 26,500 26,500

Also using the modified jack screw formula as shown in the IADC Tool Pusher’s Manual and the API Spec. RP 7G (seventh edition, April 1976) and a unit stress of 62,500 psi in the box or pin, whichever is weaker.

205Reference Tables

Recommended Minimum Make-up Torque (continued) (ft/lb.) [See Note 2]



51⁄2 API FH

7 71⁄4

71⁄2 73⁄4

API NC 56

71⁄4

71⁄2 73⁄4

81

65⁄8 API Reg.

71⁄2 73⁄4

8 81⁄4

65⁄8 H-90 (See Note 3)

71⁄2 73⁄4 8 81⁄4

API NC 61

8 81⁄4 81⁄2 83⁄4

9

51⁄2 API IF

8 81⁄4 81⁄2 83⁄4 9 91⁄4

65⁄8 API FH

81⁄2 83⁄4 9 91⁄4

91⁄2

API NC 70

9 91⁄4

91⁄2 93⁄410101⁄4

API NC 77

10 101⁄4 101⁄2 103⁄4 11



2 21⁄4 21⁄2 213⁄16 3 31⁄4 31⁄2 33⁄4

32,500†40,500†49,000†51,000

32,500†40,500†47,00047,000

32,500†40,500†45,00045,000

32,500†40,500†41,50041,500

40,000†48,500†51,00051,000

40,000†48,00048,00048,000

40,000†45,00045,00045,000

40,000†42,00042,00042,000

46,000†55,000†57,00057,000

46,000†53,00053,00053,000

46,000†50,00050,00050,000

46,000†47,00047,00047,000

46,000†55,000†59,50059,500

46,000†55,000†56,00056,000

46,000†53,00053,00053,000

46,000†49,50049,50049,500

54,000†64,000†72,00072,00072,000

54,000†64,000†68,00068,00068,000

54,000†64,000†65,00065,00065,000

54,000†61,00061,00061,00061,000

56,000†66,000†74,00074,00074,00074,000

56,000†66,000†70,00070,00070,00070,000

56,000†66,000†67,00067,00067,00067,000

56,000†63,00063,00063,00063,00063,000

56,000†59,00059,00059,00059,00059,000

67,000†78,000†83,00083,00083,000

67,000†78,000†80,00080,00080,000

67,000†76,0007,600076,00076,000

67,000†72,00072,00072,00072,000

66,50066,50066,50066,50066,500

75,000†88,000†101,000†107,000107,000107,000

75,000†88,000†101,000†105,000105,000105,000

75,000†88,000†100,000100,000100,000100,000

75,000†88,000†95,00095,00095,00095,000

75,000†88,000†90,00090,00090,00090,000

107,000†122,000†138,000†143,000143,000

107,000†122,000†138,000†138,000138,000

107,000†122,000†133,000133,000133,000

107,000†122,000†128,000128,000128,000

207Reference Tables

Recommended Minimum Make-up Torque (continued) (ft/lb.) [See Note 2]Size and Type of Connection

OD Bore of Drill Collars1 11⁄4 11⁄2 13⁄4 2 21⁄4

Connections with Full Face7 H-90 (See Note 3)

8*5

81⁄4*81⁄2*

⁄8

75⁄8 API Reg. 81⁄2* 83⁄4*9*91⁄4* 91⁄2*

⁄8

75⁄8 H-90 (See Note 3)

9*5

91⁄4*91⁄2*⁄8

85⁄8 API Reg. 10*5

101⁄4*⁄101⁄2*8

85⁄8 H-90 (See Note 3)

101⁄4*101⁄2*

Connections with Low Torque Face7 H-90 (See Note 3)

83⁄495

⁄8

75⁄8 API Reg. 91⁄491⁄293⁄4

105

⁄8

75⁄8 H-90 (See Note 3)

93⁄4105

101⁄4101⁄2

⁄8

85⁄8 API Reg. 103⁄4115

⁄8

85⁄8 H-90 (See Note 3)

103⁄411111⁄4

5⁄

3. Normal torque range — tabulated minimum value to ten percent greater. Largest diameter shown for each connection is the maximum recommended for that con-nection. If the connections are used on drill collars larger than the maximum shown, increase the torque values shown by ten percent for a minimum value. In addition to the increased minimum torque value, it is also recommended that a fishing neck be machined to the maximum diameter shown.

4. H-90 connection make-up torque based on 56,250 psi stress and other factors as stated in note 1.

5. 27/8 in. PAC make-up torque based on 87,500 psi stress and other factors as stated in note 1.

Bore of Drill Collars2 21⁄4 21⁄2 213⁄16 3 31⁄4 31⁄2 33⁄4

32,500†40,500†49,000†51,000

32,500†40,500†47,00047,000

32,500†40,500†45,00045,000

32,500†40,500†41,50041,500

40,000†48,500†51,00051,000

40,000†48,00048,00048,000

40,000†45,00045,00045,000

40,000†42,00042,00042,000

46,000†55,000†57,00057,000

46,000†53,00053,00053,000

46,000†50,00050,00050,000

46,000†47,00047,00047,000

46,000†55,000†59,50059,500

46,000†55,000†56,00056,000

46,000†53,00053,00053,000

46,000†49,50049,50049,500

54,000†64,000†72,00072,00072,000

54,000†64,000†68,00068,00068,000

54,000†64,000†65,00065,00065,000

54,000†61,00061,00061,00061,000

56,000†66,000†74,00074,00074,00074,000

56,000†66,000†70,00070,00070,00070,000

56,000†66,000†67,00067,00067,00067,000

56,000†63,00063,00063,00063,00063,000

56,000†59,00059,00059,00059,00059,000

67,000†78,000†83,00083,00083,000

67,000†78,000†80,00080,00080,000

67,000†76,0007,600076,00076,000

67,000†72,00072,00072,00072,000

66,50066,50066,50066,50066,500

75,000†88,000†101,000†107,000107,000107,000

75,000†88,000†101,000†105,000105,000105,000

75,000†88,000†100,000100,000100,000100,000

75,000†88,000†95,00095,00095,00095,000

75,000†88,000†90,00090,00090,00090,000

107,000†122,000†138,000†143,000143,000

107,000†122,000†138,000†138,000138,000

107,000†122,000†133,000133,000133,000

107,000†122,000†128,000128,000128,000


Recommended Minimum Make-up Torque (continued) (ft/lb.) [See Note 2]

*6. Largest diameter shown is the maximum recommended for those full face connec-tions. If larger diameters are used, machine connections with low torque faces and use the torque values shown under low torque face tables. If low torque faces are not used, see note 2 for increased torque values.

†7. Torque figures succeeded by a cross (†) indicate that the weaker member for the corresponding outside diameter and bore is the BOX. For all other torque values the weaker member is the PIN.

Bore of Drill Collars21⁄2 213⁄16 3 31⁄4 31⁄2 33⁄4

Connections with Full Face⁄8 53,000†

63,000† 71,500

53,000† 63,000† 68,500

53,000† 63,000† 68,500

53,000† 60,500 68,500

60,000† 71,000† 83,000† 88,000 88,000

60,000† 71,000† 83,000† 83,000† 83,000†

⁄860,000† 71,000† 79,000 79,000 79,000

60,000† 71,000† 74,000 74,000 74,000

72,000† 85,500† 98,000†

72,000† 85,500† 98,000†

72,000† 85,500† 98,000†

72,000† 85,500† 95,500

108,000† 123,000 139,000

108,000† 123,000 134,000

108,000† 123,000 129,000

108,000† 123,000 123,000

112,500† 128,500†

112,500† 128,500†

112,500† 128,500†

112,500† 128,500†

Connections with Low Torque Face⁄867,500† 74,000

67,500† 71,000

66,500†

66,500†62,000† 62,000†

72,000† 85,000† 91,000 91,000

72,000† 85,000† 87,000 87,000

72,000† 82,000† 82,000† 82,000†

⁄72,000† 877,000 77,000 77,000

⁄8 91,000† 105,000† 112,500 112,500

91,000† 105,000† 108,000 108,000

91,000† 103,500 103,500 103,500

91,000† 98,000 98,000 98,000

⁄8 112,000† 129,000†

112,000† 129,000†

112,000† 129,000†

112,000† 129,000†

5⁄ 92,500† 110,000† 128,000†

92,500† 110,000† 128,000†

92,500† 110,000† 128,000†

92,500† 110,000† 128,000†

209Reference Tables

Rotary Shouldered Connection Interchange List

Common Name Pin Base Dia. (tapered)

Threads per in.

Taper (in/ft.)

Thread Form* Same As or Interchanges WithStyle Size

Internal Flush (IF)

23⁄8 2.876 4 2 V-0.065 (V-0.038 rad)

27⁄8 SH NC 26**

27⁄8 3.391 4 2 V-0.065 (V-0.038 rad)

31⁄2 SH NC 31**

31⁄2 4.016 4 2 V-0.065 (V-0.038 rad)

41⁄2 SH NC 38**

4 4.834 4 2 V-0.065 (V-0.038 rad)

41⁄2 XH NC 46**

41⁄2 5.250 4 2 V-0.065 (V-0.038 rad)

5 XH NC 50** 51⁄2 DSL

Full Hole (FH) 4 4.280 4 2 V-0.065

(V-0.038 rad)41⁄2 DSL NC 40**

Extra Hole (XH) (EH)

27⁄8 3.327 4 2 V-0.065 (V-0.038 rad) 31⁄2 DSL

31⁄2 3.812 4 2 V-0.065 (V-0.038 rad)

4 SH 41⁄2 EF

41⁄2 4.834 4 2 V-0.065 (V-0.038 rad)

4 IF NC 46**

5 5.250 4 2 V-0.065 (V-0.038 rad)

41⁄2 IF NC 50** 51⁄2 DSL

Slim Hole (SH)

27⁄8 2.876 4 2 V-0.065 (V-0.038 rad)

23⁄8 IF NC 26**

31⁄2 3.391 4 2 V-0.065 (V-0.038 rad)

27⁄8 IF NC 31**

4 3.812 4 2 V-0.065 (V-0.038 rad)

31⁄2 XH 41⁄2 EF

41⁄2 4.016 4 2 V-0.065 (V-0.038 rad)

31⁄2 IF NC 38**

Double Stream- line (DSL)

31⁄2 3.327 4 2 V-0.065 (V-0.038 rad) 27⁄8 XH

41⁄2 4.280 4 2 V-0.065 (V-0.038 rad)

4 FH NC 40**

51⁄2 5.250 4 2 V-0.065 (V-0.038 rad)

41⁄2 IF 5 XH NC 50**


Rotary Shouldered Connection Interchange List (continued)

Common Name Pin Base Dia. (tapered)

Threads per in.

Taper (in/ft.)

Thread Form* Same As or Interchanges WithStyle Size

NumberedConn. (NC)

26 2.876 4 2 V-0.038 rad 27⁄8 SH

23⁄8 IF

31 3.391 4 2 V-0.038 rad 31⁄2 SH

27⁄8 IF

38 4.016 4 2 V-0.038 rad 31⁄2 IF 41⁄2 SH

40 4.280 4 2 V-0.038 rad 4 FH 41⁄2 DSL

46 4.834 4 2 V-0.038 rad 41⁄2 XH

4 IF

50 5.250 4 2 V-0.038 rad 41⁄2 IF 5 XH 51⁄2 DSL

External Flush (EF)

41⁄2 3.812 4 2 V-0.065 (V-0.038 rad)

4 SH31⁄2 XH

** Connections with two thread forms shown may be machined with either thread form without affecting gauging or interchangeability.

** NC may be machined only with the V-0.038 radius thread form.


211Reference Tables

Top Sub Make-up Torque Table (ft/lb.)

Series Tool Connection

Tool Top Sub Make-up Torque (ft/lb.)OD ID

3600 23⁄8 IF 35⁄8 1.00 5,700

4500 31⁄2 IF 41⁄2 1.25 2.25

6,350 6,350

5700 5800 4 IF 53⁄4 1.50

2.2517,800 17,800

6000 6100 4 IF 61⁄2 1.50

2.2523,500 23,500

7200 51⁄2 IF 71⁄4 2.25 3.00

28,000 28,000

8200 65⁄8 Reg. 81⁄22.25 3.00 2.81

60,600 51,500 54,000

9500 65⁄8 Reg. 81⁄22.81 3.00 2.25

54,000 51,500 60,600

11700 Servco T-20 111⁄2 3.00 88,000

15000 Servco T-20 75⁄8 Reg. 111⁄2 3.00

3.0088,000 88,000

22000 Servco T-20 133⁄8 3.00 3.50

88,000 88,000



Recommended Maximum-Minimum Tool Joint Dimensions (in.)

Joints Nom. OD

Nom. ID

“A” Max.

“B” Max.

“C”Min. Max.

23⁄8API Reg. 31⁄8 1 11⁄8 15⁄8 215⁄16 31⁄4API IF 33⁄8 13⁄4 13⁄4 2 33⁄16 35⁄8Hydril IF 33⁄8 13⁄4 13⁄4 17⁄8 31⁄8 35⁄8

27⁄8

API Reg. 33⁄4 11⁄4 13⁄8 17⁄8 31⁄2 47⁄8API FH 41⁄4 21⁄8 21⁄8 23⁄8 41⁄16 45⁄8API IF 41⁄8 21⁄8 21⁄8 21⁄2 37⁄8 43⁄8Hydril IF 37⁄8 21⁄8 23⁄16 23⁄16 35⁄8 41⁄8Hughes XH 41⁄4 17⁄8 17⁄8 21⁄8 4 45⁄8

3 Union Tool 41⁄4 11⁄2 11⁄2 21⁄8 33⁄4 41⁄2

31⁄2

API Reg. 41⁄4 11⁄2 13⁄4 21⁄4 4 45⁄8API FH 45⁄8 27⁄16 27⁄16 23⁄4 41⁄2 57⁄8API IF 43⁄4 211⁄16 211⁄16 3 41⁄2 57⁄8Hydril IF 41⁄2 23⁄4 23⁄4 213⁄16 43⁄8 47⁄8Hughes XH 43⁄4 27⁄16 27⁄16 23⁄4 41⁄2 57⁄8

4API FH 51⁄4 213⁄16 213⁄16 31⁄4 5 53⁄8API IF 53⁄4 31⁄4 35⁄16 31⁄2 51⁄2 67⁄8Union Tool 53⁄4 21⁄4 27⁄8 31⁄2 53⁄8 67⁄8

41⁄2

API Reg. 53⁄4 21⁄4 25⁄8 31⁄4 53⁄8 67⁄8API FH 53⁄4 3 35⁄32 31⁄2 51⁄2 67⁄8API IF 61⁄8 33⁄4 33⁄4 41⁄8 57⁄8 61⁄2Hydril IF 67⁄8 33⁄4 37⁄8 4 513⁄16 61⁄4Hughes XH 67⁄8 31⁄4 31⁄4 33⁄8 55⁄8 61⁄4

51⁄2API Reg. or UT 63⁄4 23⁄4 31⁄4 37⁄8 63⁄8 77⁄8API FH 77⁄8 4 4 41⁄2 61⁄2 71⁄4API IF 73⁄8 413⁄16 413⁄16 51⁄4 71⁄8 77⁄8

65⁄8API Reg. or UT 73⁄4 31⁄2 4 43⁄4 71⁄8 77⁄8API FH 87⁄8 5 5 51⁄2 71⁄2 81⁄4API IF 81⁄2 529⁄32 529⁄32 61⁄4 83⁄8 97⁄8

75⁄8 API Reg. 87⁄8 4 41⁄4 51⁄4 81⁄8 97⁄885⁄8 API Reg. 107⁄8 43⁄4 51⁄4 61⁄4 9 101⁄8

CA B

213Reference Tables

Drill PiPe Data

Internal Upset

Size Pipe OD

Wt. (lb.)

ID Pipe

ID Upset

23⁄82.375 4.80 2.000 1.437

2.375 6.65 1.815 1.125

27⁄82.875 6.45 2.469 1.875

2.875 8.35 2.323 1.625

2.875 10.40 2.151 1.187

31⁄2

3.500 8.50 3.063 2.437

3.500 11.20 2.900 2.125

3.500 13.30 2.764 1.875

3.500 15.50 2.602 1.750

44.000 14.00 3.340 2.375

4.000 15.70 3.240 2.250

41⁄2

4.500 12.75 4.000 3.250

4.500 13.75 3.958 3.156

4.500 16.60 3.826 2.812

4.500 18.10 3.754 2.687

4.500 20.00 3.640 2.812

Size Pipe OD

Wt. (lb.)

ID Pipe

ID Upset

5 5.000 19.50 4.276 3.781

51⁄25.500 21.90 4.778 3.812

5.500 24.70 4.670 3.500

59⁄16

5.563 19.00 4.975 4.125

5.563 22.20 4.859 3.812

5.563 25.25 4.733 3.500

65⁄86.625 22.20 6.065 5.187

6.625 25.20 5.965 5.000

6.625 31.90 5.761 4.625

75⁄8 7.625 29.25 6.969 6.000

85⁄8 8.625 40.00 7.825 6.625

External Upset

Size Pipe OD

Wt. (lb.)

ID Pipe

ID Upset

23⁄8 2.375 6.65 1.815 2.656

27⁄8 2.875 10.40 2.151 3.219

31⁄23.500 13.30 2.764 3.824

3.500 15.50 2.602 3.824

44.000 14.00 3.340 4.500

4.000 15.70 3.240 4.500

Size Pipe OD

Wt. (lb.)

ID Pipe

ID Upset

41⁄24.500 16.60 3.826 5.000

4.500 20.00 3.640 5.000

59⁄165.563 22.20 4.859 6.063

5.563 25.25 4.733 6.063

65⁄8 6.625 25.20 5.965 7.125



Hevi-wate Drill PiPe

Capacity and Displacement Table — Hevi-Wate Drill Pipe

Nom. Size (in.)

Capacity Displacement

gal. per

Joint*

bbl per

Joint*

gal. per

100 ft.

bbl per

100 ft.

gal. per

Joint*

bbl per

Joint*

gal. per

100 ft.

bbl per

100 ft.31⁄2 5.30 .126 17.7 .421 11.61 .276 38.7 .921

4 8.13 .194 27.1 .645 13.62 .325 45.4 1.082

41⁄2 9.37 .223 31.2 .743 18.82 .448 62.7 1.493

5 11.14 .265 37.1 .883 22.62 .539 75.4 1.796

* Capacity and displacement per joint numbers are based on 30 ft. joints.

215Reference Tables

Hevi-wate Drill PiPe

Dimensional Data Range II

Nom. Size

Tube Mechanical Properties Tube SectionNormal Tube Dim. Center

UpsetElevator UpsetID Wall

ThicknessArea (in.2)

Tensile Yield (lb.)

Torsional Yield (ft/lb.)

31⁄2 21⁄16 .719 6.280 4 35⁄8 345,400 19,575

4 29⁄16 .719 7.409 41⁄2 41⁄8 407,550 27,635

41⁄2 23⁄4 .875 9.965 5 45⁄8 548,075 40,715

5 3 1.000 12.566 51⁄2 51⁄8 691,185 56,495


Nom. Size

Tool Joint Approx. Wt. Incl. Tube and Joints

(lb.)

Make-up

Torque (ft/lb.)

Connection Size

OD ID Mechanical Properties

Tensile Yield (lb.)

Torsional Yield

(ft/lb.)

wt/ft. 30 ft. wt/jt.

31⁄2 NC 38(31⁄2 IF) 43⁄4 23⁄16 748,750 17,575 25.3 760 9,900

4 NC 40(4 FH) 51⁄4 211⁄16 711,475 23,525 29.7 880 13,250

41⁄2 NC 46(4 IF) 61⁄4 27⁄8 1,024,500 38,800 41.0 1,230 21,800

5 NC 50(41⁄2 IF) 61⁄2 31⁄16 1,266,000 51,375 49.3 1,480 29,400

Dimensional Data Range II


tubing Data

Non-upset

API Size OD lb. ID Coupling OD1.900 1.900 2.75 1.610 2.200

23⁄8 2.375 4.00 2.041 2.875

23⁄8 2.375 4.60 1.995 2.875

27⁄8 2.875 6.40 2.441 3.500

31⁄2 3.500 7.70 3.068 4.250

31⁄2 3.500 9.20 2.992 4.250

31⁄2 3.500 10.20 2.922 4.250

4 4.000 9.50 3.548 4.750

41⁄2 4.500 12.60 3.958 5.200

External Upset


API Size OD lb. ID Coupling OD1.660 1.660 2.40 1.380 2.200

1.900 1.900 2.90 1.610 2.500

23⁄8 2.375 4.70 1.995 3.063

27⁄8 2.875 6.50 2.441 3.668

31⁄2 3.500 9.30 2.992 4.500

4 4.000 11.00 3.476 5.000

41⁄2 4.500 12.75 3.958 5.563

217Reference Tables

Drill Collar weigHts (lb/ft.)

To obtain the weights of spiral collars, subtract four percent.

Collar Bore of Collar (in.)OD 11⁄2 13⁄4 2 21⁄4 21⁄2 23⁄4 3 31⁄4 31⁄2 33⁄4 433⁄8 24.4 22.231⁄2 26.7 24.533⁄4 31.5 29.337⁄8 34.0 31.9 29.4 26.543⁄8 36.7 34.5 32.0 29.241⁄8 39.4 37.2 34.7 31.941⁄4 42.2 40.0 37.5 34.741⁄2 48.0 45.8 43.3 40.543⁄4 54.2 52 49.5 46.7 43.553⁄8 60.1 58.5 55.9 53.1 49.951⁄4 67.5 65.3 62.8 59.9 56.8 53.351⁄2 74.7 72.5 69.9 67.2 63.9 60.5 56.753⁄4 82.1 79.9 77.5 74.6 71.5 67.9 64.163⁄8 89.9 87.8 85.3 82.5 79.3 75.8 71.9 67.8 63.361⁄4 98.1 95.9 93.5 90.6 87.5 83.9 80.1 75.9 71.561⁄2 106.6 104.5 101.9 99.1 95.9 92.5 88.6 84.5 79.963⁄4 115.5 113.3 110.8 107.9 104.8 101.3 97.5 93.3 88.873⁄8 124.6 122.5 119.9 117.1 113.9 110.5 106.6 102.5 97.9 93.1 87.971⁄4 134.1 131.9 129.5 126.6 123.5 119.9 116.1 111.9 107.5 102.6 97.571⁄2 143.9 141.7 139.3 136.5 133.3 129.8 125.9 121.8 117.3 112.5 107.373⁄4 154.1 151.9 149.5 146.6 143.5 139.9 136.1 131.9 127.5 122.6 117.583⁄8 164.6 162.5 159.9 157.1 153.9 150.5 146.6 142.5 137.9 133.1 127.981⁄4 175.4 173.3 170.8 167.9 164.8 161.3 157.5 153.3 148.8 143.9 138.881⁄2 186.6 184.4 181.9 179.1 175.9 168.6 172.5 164.5 159.9 155.1 149.983⁄4 198.1 195.9 193.9 190.6 187.4 183.9 180.1 175.9 171.4 166.6 161.593⁄8 207.8 205.3 202.4 199.3 195.8 191.9 187.8 183.3 178.5 173.391⁄2 232.4 229.9 227.1 223.9 220.4 216.6 212.4 207.9 203.1 197.9103⁄8 255.9 253.1 249.9 246.4 242.6 238.4 233.9 229.1 223.9101⁄2 283.3 280.4 277.3 273.8 269.9 265.8 261.3 256.4 251.3113⁄8 305.9 302.4 298.6 294.4 289.9 285.1 279.9


weigHts of 30 ft. Drill Collars (lb.)Collar Bore of Collar (in.)

OD 11⁄2 13⁄4 2 21⁄4 21⁄2 23⁄4 3 31⁄4 31⁄2 33⁄4 433⁄8 730 66531⁄2 799 73433⁄4 944 87937⁄8 1,020 955 880 79541⁄2 1,099 1,034 959 87441⁄8 1,180 1,115 1,040 95541⁄4 1,264 1,199 1,124 1,03941⁄2 1,439 1,374 1,299 1,21443⁄4 1,624 1,559 1,484 1,399 1,30451⁄2 1,819 1,754 1,679 1,594 1,49951⁄4 2,024 1,959 1,884 1,799 1,704 1,59951⁄2 2,239 2,174 2,099 2,014 1,919 1,814 1,69953⁄4 2,464 2,399 2,324 2,239 2,144 2,039 1,92461⁄2 2,699 2,634 2,559 2,474 2,379 2,274 2,159 2,034 1,89961⁄4 2,944 2,879 2,804 2,719 2,624 2,519 2,404 2,279 2,14461⁄2 3,199 3,134 3,059 2,974 2,879 2,774 2,659 2,534 2,39963⁄4 3,463 3,398 3,323 3,238 3,143 3,039 2,924 2,799 2,66471⁄2 3,738 3,673 3,598 3,513 3,418 3,313 3,199 3,074 2,939 2,794 2,63971⁄4 4,023 3,958 3,883 3,798 3,703 3,598 3,483 3,358 3,223 3,078 2,92471⁄2 4,318 4,253 4,178 4,093 3,998 3,893 3,778 3,653 3,518 3,373 3,21973⁄4 4,623 4,558 4,483 4,398 4,303 4,198 4,083 3,958 3,823 3,678 3,52381⁄2 4,938 4,873 4,798 4,713 4,618 4,513 4,398 4,273 4,138 3,993 3,83881⁄4 5,263 5,198 5,123 5,038 4,943 4,838 4,723 4,598 4,463 4,318 4,16381⁄2 5,598 5,533 5,458 5,373 5,278 5,058 5,173 4,933 4,798 4,653 4,49883⁄4 5,943 5,878 5,803 5,718 5,623 5,518 5,403 5,278 5,143 4,998 4,84391⁄2 6,233 6,158 6,073 5,978 5,873 5,758 5,633 5,498 5,353 5,19891⁄2 6,972 6,897 6,812 6,498 6,717 6,613 6,373 6,238 6,093 5,938101⁄2 7,677 7,592 7,497 7,392 7,277 7,152 7,017 6,872 6,717101⁄2 8,497 8,412 8,317 8,212 8,097 7,972 7,837 7,692 7,537111⁄2 9,177 9,072 8,957 8,832 8,697 8,552 8,397

To obtain the weights of spiral collars, subtract four percent.

219Reference Tables

buoyanCy faCtor anD safety faCtor

Buoyancy Effect on the DrillstringDue to the buoyancy effect, all drill collar weight is not actually avail-able for loading the bit in fluid-drilled holes. To find the corrected, or buoyed, drill collar weight, use the buoyancy correction factor from the Buoyancy Factors table on page 220 of this section.

Example:A drill collar string weighs 79,000 lb. in air. How much will it weigh

in 12 lb/gal. mud?Buoyed drill collar weight =Drill collar weight x buoyancy factor =79,000 lb. x .817 = 64,543 lb.

Safety FactorDrill pipe can be seriously damaged if run in compression. To make sure the drill pipe is always in tension, the top ten to 15 percent of the drillstring has to be in tension. This will shift the point of change-over from tension to compression, i.e., the neutral zone, down to the stiff drill collar string, where it can be tolerated. The calculation of the maximum bit weight available therefore has to include a ten to 15 percent Safety Factor (SF), written as 1.10 or 1.15. In harder forma-tions, the SF should increase up to 25 percent.

Example: Using the same example as above:Maximum bit weight available =

Buoyed drill collar weight = 1.15 64,543 lb. = 1.15

56,124 lb.

The buoyed weight of the drill collar string, incorporating the SF, is thus 56,124 lb.


buoyanCy faCtorsMud

Weight lb/gal.

Buoyancy Factor

Mud Weight lb/gal.

Buoyancy Factor

Mud Weight lb/gal.

Buoyancy Factor

8.4 .872 13.0 .801 17.6 .731

8.6 .869 13.2 .798 17.8 .728

8.8 .866 13.4 .795 18.0 .725

9.0 .863 13.4 .795 18.2 .723

9.2 .860 13.6 .792 18.4 .720

9.4 .856 14.0 .786 18.6 .717

9.6 .853 14.2 .783 18.8 .714

9.8 .850 14.4 .780 19.0 .711

10.0 .847 14.6 .777 19.2 .708

10.2 .844 14.8 .774 19.4 .705

10.4 .841 15.0 .771 19.6 .702

10.6 .838 15.2 .768 19.8 .698

10.8 .835 15.4 .765 20.0 .694

11.0 .832 15.6 .76 20.2 .691

11.2 .829 15.8 .759 20.4 .688

11.4 .826 16.0 .755 20.6 .685

11.6 .823 16.2 .753 20.8 .682

11.8 .820 16.4 .750 21.0 .679

12.0 .817 16.6 .747 22.0 .664

12.2 .814 16.8 .744 23.0 .649

12.4 .811 17.0 .740 24.0 .633

12.6 .808 17.2 .737

12.8 .805 17.4 .734

221Reference Tables

10 in. Duplex Pump

Strokes per Min.

Gallons per Minute Using Liner Shown

3 31⁄2 4 41⁄2 5 51⁄4 51⁄2 53⁄4 6 61⁄4 61⁄2 63⁄4 7 71⁄4 71⁄2 8

25 30 40 50 60 80 90 90 100 110 120 130 140 150 170 180 200

30 30 40 60 70 90 100 110 120 140 150 160 170 190 200 210 240

35 40 50 70 90 110 120 130 140 160 170 190 200 220 230 250 280

40 40 50 70 90 120 130 140 160 170 190 200 220 230 250 270 310

45 40 60 80 110 130 150 160 180 190 210 230 240 260 280 300 350

50 50 70 90 120 150 160 180 200 210 230 250 270 290 310 340 380

55 50 70 100 130 160 180 200 220 230 260 280 300 320 350 370 420

60 60 80 110 140 180 190 210 230 260 280 300 330 350 380 400 460

65 60 90 120 150 190 210 230 250 280 300 330 350 380 410 440 500

70 70 100 130 160 200 230 250 270 300 330 350 380 410 440 470 540

75 70 100 140 180 220 240 270 290 320 350 380 410 440 470 510 580

80 80 110 150 190 230 260 290 310 340 370 400 440 470 500 540 620

85 80 120 150 200 250 280 300 330 360 390 430 460 500 540 570 650

Pump Volume vs. Liner SizeLiner sizes vary depending on the pump size, strokes per minute and required circulation rate in GPM. The following tables give the circula-tion rates possible when various sizes of duplex and triplex pumps are used, based on the pumps volumetric efficiency of 95 percent.

GPM calculated in ten GPM increments for purposes of reading curves and proper orifice selection.


12 in. Duplex Pump

Strokes per Min.


41⁄2 43⁄4 5 51⁄4 5 51⁄2 53⁄4 6 61⁄4 61⁄2 63⁄4 7 71⁄4

25 70 80 90 100 110 120 130 140 160 170 180 200 150

30 90 100 110 120 130 150 160 170 190 200 220 240 190

35 100 110 130 140 150 170 190 200 220 240 260 280 220

40 110 120 140 150 170 180 200 220 240 260 280 300 230

45 120 140 150 170 190 210 230 250 270 290 310 340 260

50 140 150 170 190 210 230 250 270 300 320 350 370 290

55 150 170 190 210 230 250 280 300 330 350 380 410 320

60 160 180 200 230 250 280 300 330 360 390 420 450 350

65 180 200 220 250 270 300 330 360 390 420 450 490 380

70 190 210 240 270 290 320 350 380 420 450 490 520 410

14 in. Duplex Pump

Strokes per Min.


43⁄4 5 51⁄4 51⁄2 53⁄4 6 61⁄4 61⁄2 63⁄4 7 71⁄4 71⁄2 73⁄4

25 90 100 110 130 140 150 170 180 190 210 230 240 260

30 110 120 140 150 170 180 200 220 230 250 270 290 310

35 130 140 160 180 190 210 230 250 270 290 320 340 360

40 140 150 170 190 210 230 250 270 290 320 340 370 390

45 150 170 190 210 240 260 280 310 330 360 390 410 440

50 170 190 210 240 260 290 310 340 370 400 430 460 490

55 190 210 240 260 290 320 340 370 410 440 470 510 540

60 210 230 260 290 310 340 380 410 440 480 510 550 590

65 220 250 280 310 340 370 410 440 480 520 560 600 640

70 240 270 300 330 370 400 440 480 520 560 600 640 690

223Reference Tables

16 in. Duplex Pump

15 in. Duplex Pump

Strokes per Min.

Gallons per Minute Using Liner Shown5 51⁄4 51⁄2 53⁄4 6 61⁄4 61⁄2 63⁄4 7 71⁄4 71⁄2 73⁄4

25 110 120 130 150 160 180 190 210 230 240 260 280

30 130 150 160 180 190 210 230 250 270 290 310 330

35 150 170 190 210 230 250 270 290 320 340 360 390

40 170 180 200 220 250 270 290 320 340 370 390 420

45 190 210 230 250 280 300 330 360 380 410 440 480

50 210 230 250 280 310 340 360 400 430 460 490 530

55 230 250 280 310 340 370 400 430 470 510 540 580

60 250 280 310 340 370 400 440 470 510 550 590 630

65 270 300 330 360 400 440 470 510 550 600 640 690

70 290 320 360 390 430 470 510 550 600 640 690 740

Stroke per Min.

Gallons per Minute Using Liner Shown43⁄4 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

25 100 110 130 140 150 170 190 200 220 240 260 270 290 310 340 360

30 120 140 150 170 190 200 220 240 260 280 310 330 350 380 400 430

35 140 160 180 200 220 240 260 280 310 330 360 380 410 440 470 500

40 150 170 190 210 230 260 280 310 330 360 390 420 450 480 510 540

45 170 190 220 240 260 290 320 340 370 400 440 470 500 540 570 610

50 190 210 240 270 290 320 350 380 420 450 480 520 560 600 640 680

55 210 240 260 290 320 350 390 420 460 490 530 570 610 660 700 740

60 230 260 290 320 350 390 420 460 500 540 580 620 670 720 760 810

65 250 280 310 350 380 420 460 500 540 580 630 680 720 770 830 880

70 270 300 330 370 410 450 490 540 580 630 680 730 780 830 890 950


20 in. Duplex Pump

18 in. Duplex Pump

Stroke per Min.


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 81⁄2

25 130 140 160 170 190 210 230 250 270 290 310 330 350 380 400 360

30 150 170 190 210 230 250 270 300 320 340 370 400 420 450 480 430

35 180 200 220 240 270 290 320 350 370 400 430 460 500 530 560 500

40 190 220 240 260 290 320 340 370 400 440 470 500 540 570 610 540

45 220 240 270 300 330 360 390 420 450 490 530 560 600 640 690 610

50 240 270 300 330 360 400 430 470 510 540 590 630 670 720 760 680

55 270 300 330 360 400 440 470 510 560 600 640 690 740 790 840 740

60 290 320 360 400 430 480 520 560 610 650 700 750 800 860 910 810

65 310 350 390 430 470 510 560 610 660 710 760 820 870 930 990 880

70 340 380 420 460 510 550 600 650 710 760 820 880 940 1,0001,070 950

Stroke per Min.


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 81⁄2

25 140 160 180 190 210 220 250 270 300 320 340 370 390 420 450 360

30 170 190 210 230 250 260 300 330 360 380 410 440 470 500 540 430

35 200 220 250 270 300 310 350 380 410 450 480 510 550 590 630 500

40 210 240 270 290 320 350 380 420 450 480 520 560 600 640 680 540

45 240 270 300 330 360 400 430 470 510 540 590 630 670 720 760 610

50 270 300 330 370 400 440 480 520 560 610 650 700 750 790 850 680

55 290 330 370 400 440 480 530 570 620 670 720 770 820 870 930 740

60 320 360 400 440 480 530 570 620 670 730 780 840 890 950 1,020 810

65 350 390 430 480 520 570 620 680 730 790 850 910 970 1,030 1,100 880

70 370 420 460 510 560 620 670 730 790 850 910 980 1,040 1,110 1,180 950

225Reference Tables

7 in. Stroke, Triplex Pump

Strokes per

Minute


41⁄2 5 51⁄2 6 61⁄2 7

40 60 70 80 100 120 130

60 80 100 120 150 170 200

70 100 120 140 170 200 230

80 110 140 160 200 230 270

90 120 150 180 220 260 300

100 140 170 200 240 290 330

110 150 190 230 270 320 370

120 170 200 250 290 340 400

140 190 240 290 340 400 470

160 220 270 330 390 460 530


Strokes per

Minute


3 31⁄4 31⁄2 4 41⁄2 5 51⁄2 6 61⁄4

40 30 30 40 50 60 80 100 110 120

60 40 50 60 80 90 120 140 170 180

70 50 60 70 90 110 140 160 200 210

80 60 70 80 100 130 160 190 220 240

90 60 70 90 110 140 170 210 250 270

100 70 80 100 120 160 190 240 280 300

110 80 90 110 140 170 210 260 310 330

120 80 100 120 150 190 230 280 340 360

140 100 120 130 170 220 270 330 390 430

160 110 130 150 200 250 310 380 450 490

180 130 150 170 220 280 350 420 500 550



81/2 in. Stroke, Triplex Pump

Strokes per

Minute


41⁄4 41⁄2 43⁄4 5 51⁄4 51⁄2 53⁄4 6 61⁄4

40 60 70 70 80 90 100 110 120 130

60 90 100 110 120 140 150 160 180 190

70 100 120 130 140 160 170 190 210 230

80 120 130 150 160 180 200 220 240 260

90 130 150 170 190 200 220 250 270 290

100 150 170 190 210 230 250 270 300 320

110 160 180 200 230 250 270 300 330 350

120 180 200 220 250 270 300 330 360 390

140 210 230 260 290 320 350 380 420 450

160 240 270 300 330 360 400 440 470 520

180 270 300 330 370 410 450 490 530 580

Strokes per

Minute


41⁄4 41⁄2 43⁄4 5 51⁄4

40 70 90 110 130 140

60 110 130 160 190 200

70 120 150 180 220 240

80 140 170 210 250 270

90 160 200 240 280 310

100 180 220 260 310 340

110 190 240 290 350 370

120 210 260 320 380 410

130 230 280 340 410 440

140 250 310 370 440 480

150 270 330 390 470 510

227Reference Tables


91/4 in. Stroke, Triplex Pump

Strokes per

Minute


41⁄2 43⁄4 5 51⁄4 51⁄2 53⁄4 6 61⁄4

40 70 80 90 100 110 120 130 140

60 110 120 130 150 160 180 190 210

70 130 140 160 170 190 210 230 250

80 150 160 180 200 220 240 260 280

90 160 180 200 220 240 270 290 320

100 180 200 220 250 270 300 320 350

110 200 220 250 270 300 330 360 390

120 220 240 260 300 330 360 390 420

130 240 260 290 320 350 390 420 460

150 270 300 340 370 410 450 490 530

170 310 340 380 420 460 510 550 600

Strokes per

Minute


51⁄4 51⁄2 53⁄4 6 61⁄4

40 70 90 110 130 140

40 110 120 130 140 150

60 160 180 190 210 230

70 190 210 220 240 280

80 210 230 260 280 300

90 240 260 290 310 340

100 270 290 320 350 380

110 290 320 350 380 420

120 320 350 390 420 450

130 350 380 420 450 490

140 370 410 450 490 530

160 430 470 510 560 610




Strokes per

Minute


51⁄2 6 61⁄2 7

40 130 150 180 210

50 160 190 230 260

60 190 230 270 310

70 230 270 320 370

80 260 310 360 420

90 290 350 410 470

100 320 380 450 520

110 350 420 500 580

120 390 460 540 630

130 420 500 590 680

Strokes per

Minute


51⁄2 53⁄4 6 61⁄4 61⁄2 63⁄4 7 71⁄4

40 140 150 170 180 200 210 230 240

50 180 190 210 230 250 270 290 310

60 210 230 250 270 300 320 340 370

70 250 270 290 320 340 370 400 430

80 280 310 330 360 390 420 460 490

90 320 350 380 410 440 480 510 550

100 350 390 420 450 490 530 570 610

110 390 420 460 500 540 580 630 670

120 420 460 500 550 590 640 680 730

130 460 500 540 590 640 690 740 800

140 490 540 590 640 690 740 800 860

229Reference Tables

Rockwell Brinell Rockwell Brinell

C No. C B No.66 31 293

65 745 30 285

64 712 29 277

62 682 28 269

60 653 27 262

59 627 25 255

58 601 24 248

57 578 23 100 241

55 555 22 99 235

54 534 21 98 229

52 514 19 97 223

51 495 18 96 217

50 477 16 96 212

49 461 15 95 207

47 444 14 94 201

46 429 13 93 197

45 415 12 92 192

43 401 10 91 187

42 388 9 90 183

40 375 8 89 179

39 363 6 88 174

38 352 5 87 170

37 341 4 86 167

36 331

34 321

33 311

32 302

Hardness Conversion Table - Approximate Values


Impression Diameter Hardness TableBrinell Rockwell

Dia.500 kg B.H.N.

3,000 kg C B Tensile

2.00 158 946Rockwell hardness and tensile strengths apply only to B.H.N. with 3,000 kg load

2.05 150 8962.10 143 8572.15 136 8172.20 130 782 68 3682.25 124 744 67 3602.30 119 713 65 3542.35 114 683 63 3412.40 109 652 62 3292.45 105 627 60 3172.50 100 600 58 3052.55 96 578 56 2952.60 93 555 55 120 2842.65 89 532 53 119 2732.70 86 512 52 119 2632.75 83 495 50 117 2532.80 80 477 48 116 2422.85 77 460 47 116 2332.90 74 444 46 115 2212.95 72 430 44 114 2113.00 70 418 43 114 2023.05 67 402 42 113 1933.10 65 387 41 112 1853.15 63 375 39 112 1783.20 61 364 38 110 1713.25 59 351 37 110 1653.30 57 340 36 109 1593.35 55 332 35 108 1543.40 54 321 34 108 1483.45 52 311 32 107 1433.50 50 302 31 106 1393.55 49 293 30 105 1353.60 48 286 29 104 1313.65 46 277 28 104 1273.70 45 269 27 104 1243.75 44 262 26 103 1213.80 43 255 25 102 1173.85 41 248 24 102 1153.90 40 241 23 100 1123.95 39 235 22 99 109

231Reference Tables

Impression Diameter Hardness Table (continued)Brinell Rockwell

Dia. 500 kg B.H.N.

3,000 kg C B Tensile

4.00 38.0 228 21 98 1074.05 37.0 223 20 97 1054.10 36.0 217 18 96 1034.15 35.0 212 17 96 1004.20 34.5 207 16 95 984.25 33.6 202 15 94 964.30 32.6 196 14 93 954.35 32.0 192 12 92 934.40 31.2 187 12 91 914.45 30.4 183 11 90 894.50 29.7 179 10 89 874.55 29.1 174 9 88 854.60 28.4 170 8 87 844.65 27.8 166 7 86 824.70 27.2 163 6 85 814.75 26.5 159 5 84 794.80 25.9 156 4 83 784.85 25.4 153 3 82 764.90 24.9 149 2 81 754.95 24.4 146 1 80 745.00 23.8 143 0 79 725.05 23.3 140 -2 78 715.10 22.8 137 -3 77 705.15 22.3 134 76 685.20 21.8 131 74 665.25 21.5 128 73 655.30 21.0 126 72 645.35 20.6 124 71 635.40 20.1 121 70 625.45 19.7 118 69 615.50 19.3 116 68 605.55 19.0 114 67 595.60 18.6 112 66 585.65 18.2 109 65 565.70 17.8 107 64 555.75 17.5 105 62 545.80 17.2 103 61 535.85 16.9 101 60 525.90 16.6 99 59 515.95 16.2 97 57 50


Conversion faCtors - fraCtion to DeCimal1⁄64 .0156 17⁄64 .2656 33⁄64 .5156 49⁄64 .76561⁄32 .0312 9⁄32 .2812 17⁄32 .5312 25⁄32 .78123⁄64 .0468 19⁄64 .2968 35⁄64 .5468 51⁄64 .79681⁄16 .0625 5⁄16 .3125 9⁄16 .5625 13⁄16 .81255⁄64 .0781 21⁄64 .3281 37⁄64 .5781 53⁄64 .82813⁄32 .0937 11⁄32 .3437 19⁄32 .5937 27⁄32 .84377⁄64 .1093 23⁄64 .3593 39⁄64 .6093 55⁄64 .85931⁄8 .1250 3⁄8 .3750 5⁄8 .6250 7⁄8 .87509⁄64 .1406 25⁄64 .3906 41⁄64 .6406 57⁄64 .89065⁄32 .1562 13⁄32 .4062 21⁄32 .6562 29⁄32 .906211⁄64 .1718 27⁄64 .4218 43⁄64 .6718 59⁄64 .92183⁄16 .1875 7⁄16 .4375 11⁄16 .6875 15⁄16 .937513⁄64 .2031 29⁄64 .4531 45⁄64 .7031 61⁄64 .95317⁄32 .2187 15⁄32 .4687 23⁄32 .7187 31⁄32 .968715⁄64 .2343 31⁄64 .4843 47⁄64 .7343 63⁄64 .98431⁄4 .2500 1⁄2 .5000 3⁄4 .7500 1 1.0000

233Reference Tables

Conversion faCtors - englisH anD metriC

Multiply By To ObtainAcres 43,560 Square feetAcres 0.001562 Square milesAcres 4,840 Square yardsBarrels, water 31.5 GallonsBarrels, water 263 PoundsBarrels, oil (API) 42.0 GallonsBarrels per day 0.02917 Gallons per minuteCentimeter 0.3937 InchesCubic centimeters 0.006102 Cubic inchesCubic feet 1,728 Cubic inchesCubic feet 0.03704 Cubic yardsCubic feet 7.481 GallonsCubic feet 0.1781 Barrels (oilfield)Cubic feet 28.3160 LitersCubic feet 0.03704 Cubic yardsCubic feet per minute 0.4719 Liter per secondCubic inches 16.3871 Cubic centimetersCubic yards 27 Cubic feetCubic yards 0.764555 Cubic metersDegrees (angle) 0.01745 RadiansDegree Fahrenheit (F) [Degree F-32]÷1.8 (or x 5/9) Degree Celsius (C)Feet 30.48 CentimetersFeet 12 InchesFeet 0.3048 MetersFeet .0001894 MilesFeet of water (depth) .4335 Pounds per square inchFeet 0.3048 MetersFoot pounds 1.35582 JoulesFoot pounds 0.138255 Meter-kilogramsFurlongs 660 FeetGallons(imperial) 1.209 Gallons (U.S.)Gallons (imperial) 4.54609 LitersGallons (U.S.) 3,785.434 Cubic centimetersGallons (U.S.) .02381 Barrels, oilGallons (U.S.) .1337 Cubic feetGallons (U.S.) 3.785 LitersGallons per minute .002228 Cubic feet per secondGallons per minute 34,286 Barrels per dayGrains 64.79891 MilligramsGrams .03527 OuncesInches .08333 FeetInches 25.4 MillimetersInches of water .03613 Pounds per square inch


Conversion faCtors (ContinueD) - englisH anD metriC

Multiply By To ObtainKilometers 3,281 FeetKilometers .6214 MilesKilometers per hour .6214 Miles per hourKnots 6,080 FeetKnots 1.152 MilesKnots per hour 1.152 Miles per hourLiters .03531 Cubic feetLiters .2642 GallonsMeters 3.281 FeetMeters 39.37 InchesMeters 1.094 YardsMiles 5,280 FeetMiles 1.609 KilometersMiles 1,760 YardsMiles per hour 88 Feet per minuteMiles per hour 1.609 Kilometers per hourMiles per hour .8684 Knots per hourMinutes .01667 HoursMinutes (angle) .0002909 RadiansMinutes (angle) 60 Seconds (angle)Ounces (fluid) 1.805 Cubic inchesOunces per cubic inch 1.72999 Grams per cubic centimeterPaschal (unit or force, pressure) 1.0 Newton per square meterPints 28.87 cubic inchesPints .125 GallonsPounds 453.6 GramsPounds .4536 KilogramsPounds of water .01602 Cubic feet of waterPounds of water 27.68 Cubic inches of waterPounds of water .1198 GallonsPounds per cubic foot .01602 Grams per cubic centimeterPounds per cubic foot 16.0185 Kilograms per cubic meterPounds per square foot 4.88241 Kilograms per square meterPounds per square foot 47.8803 Newtons per square meterPounds per square inch 2.307 Feet of waterPounds per square inch 2.036 Inches of mercuryPounds per square inch 0.689476 Newtons per square cmQuarts (U.S.) 57.75 Cubic inchesQuarts (U.S.) 946.4 Cubic centimetersQuarts (U.S.) 0.946331 LitersRadians 57.30 DegreesRadians per second 9.549 Revolutions per minute

235Reference Tables

Conversion faCtors (ContinueD) - englisH anD metriC

Multiply By To ObtainSquare centimeters .1550 Square inches

Square feet 144 Square inches

Square feet .00002296 Acres

Square feet 929 Square centimetersSquare inches 6.4516 Square centimetersSquare inches .006944 Square feetSquare miles 640 Acres

Square miles 2.59 Square kilometers

Square kilometer 247.1 Acres

Square meters 10.76 Square feet

Square meters .0002471 Acres

Square yards 9 Square feet

Square yards .8361 Square meters

Temperature (˚C) 1.8 (add 32˚) Temp. (˚F)

Temperature (˚F)5/9 or 0.5556(subtract 32˚) Temp. (˚C)

Tons (long) 2,240 Pounds

Tons (metric) 2,205 Pounds

Tons (short) 2,000 Pounds

Yards .9144 Meters

Yards 91.44 Centimeters


Notes:

Index of Product References

Anchor-Stock, Retrievable .................................................... 67API Casing Data ................................................................. 232Areas of Circle and Nozzles ............................................... 151Bit Selection Equations ....................................................... 247Bit Weight — Rotational Speed Equations ......................... 247Bouyancy Factors ............................................................... 274Casing Data, API ................................................................ 232Casing, Dimensions ............................................................ 232Casing, Eccentric Diameter ................................................ 214Casings, Recommendations to Set Small

Clearance Consecutive Strings ......................................... 93Connection Interchange List, Rotary Shouldered ............... 262Conversion Factors, English and Metric ............................. 290Conversion Factors, Fraction to Decimal ........................... 289Conversion Factors, Hardness ........................................... 286Conversion Factors, Mud Weight ....................................... 149Drill Collar Weights ............................................................. 271Drill Mill Specifications .......................................................... 53Drill Pipe Data ..................................................................... 266Drill Pipe Data, Hevi-Wate .................................................. 267Drilling Fluid Property Equations ........................................ 251Drilling-Type Underreamer Specifications (DTU) ................ 115DTU Underreamer Cone Availability ..................................... 89Dull Bit Grading, IADC ........................................................ 244Duplex Mud Pump Data ..................................................... 275Eccentric Diameter, Casing ................................................ 214Economill Specifications ....................................................... 52Econo-Stock, Retrievable ..................................................... 70Equations, Hydraulic Calculation ........................................ 248Gauge Diameter Tolerances — Hole Openers/Hole Enlargers 157Gauge Diameter Tolerances — Underreamers .................. 132GTA Hole Opener Specifications ........................................ 181Hardness Conversion Table ............................................... 286Hardness Impression Diameter .......................................... 287Hevi-Wate Drill Pipe Data ................................................... 267Hole Enlarger Specifications .............................................. 203Hole Opener, GTA Specifications ....................................... 181Hole Opener, Master Driller Specifications ......................... 163Hole Opener, Net Annular Area Removed .......................... 140Hole Opener, SDD Specifications ....................................... 171Hole Openers/Hole Enlargers, Gauge Diameter Tolerances ..... 157Hole Openers/Hole Enlargers,


Weights and Rotary Recommendations ......................... 156Hydraulic Calculation Equations ......................................... 248Hydraulic Tool Flow Rate, Minimum ................................... 138Hydraulic Tool Opening Force ............................................ 137Hydraulic Tools, Jet Combinations ..................................... 148IADC Dull Bit Grading ......................................................... 244Impression Diameter, Hardness ......................................... 287Jet Combinations for Hydraulic Tools ................................. 148Jet Nozzle Area .................................................................. 148Junk Mill Specifications ........................................................ 43Junk Sub Specifications ....................................................... 45Junkmaster Specifications .................................................... 55K-Mill, Casing Specifications ................................................ 14K-Mill, Flow Rates ................................................................... 9K-Mill Specifications ............................................................. 14Makeup Torque, Recommended Minimum ......................... 254Makeup Torque, Top Sub .................................................... 264Marine Pipe Cutter, Cutter Length Specifications ............... 220Marine Pipe Cutter, Flow Rates .......................................... 209Marine Pipe Cutter, Specifications ...................................... 218Marine Support Swivel, Specifications ............................... 223Master Driller Specifications ............................................... 163Milling, General Operating Recommendations ....................... 5Milling, Normal Rates ............................................................. 5Mud Pump Data, Duplex .................................................... 275Mud Pump Data, Triplex ..................................................... 282Mud Weight ........................................................................ 149Mud Weight, Bouyancy Factors .......................................... 273Mud Weight, Conversion Factors ....................................... 149Net Annular Area Removed with

Underreamer or Hole Opener ......................................... 140Nozzle/Orifice Area ............................................................. 151One-trip Trackmaster ............................................................ 74Orifice Sizes for Drilling-Type and Reammaster ................. 143Orifice Sizes for K-Mill, SPX/Drag- and Rock-Type ............ 144Pack-Stock, Retrievable ....................................................... 65Pilot Mill Specifications ......................................................... 32Pipe Cutter, Cutter Length Specifications ........................... 220Pipe Cutter, Flow Rates and Rotary Speeds ...................... 209Pipe Cutter, Specifications .................................................. 219Pressure Drop Across One Orifice ..................................... 146Reamaster Operating Parameters ........................................ 94Reamaster Underreamer (XTU) Specifications .................. 105Retrievable Anchor-Stock ..................................................... 67

Retrievable Econo-Stock ...................................................... 70Retrievable Pack-Stock ........................................................ 65Rock Bit Comparison Chart ................................................ 234Rock-Type Underreamer (RTU) ......................................... 123Rotary Shouldered Connection Interchange List ................ 262RTU Underreamer Cone Availability ..................................... 89SDD Hole Opener Specifications ....................................... 171Section Mill, Flow Rates ......................................................... 9Section Mill Specifications .................................................... 27Servcoloy Composite Rod .................................................... 59Servcoloy Concentrate Rod .................................................. 59Servcoloy “S” Field Kits ........................................................ 60Skirted Junk Mill, Specifications ........................................... 55Small Clearance Consecutive Strings of

Casings, Recommendations ............................................. 93Spacer Sub Length Sizing .................................................. 212SPX/Drag-Type Underreamer Specifications ..................... 131Stabilizer Top Sub, Blade Diameters .................................. 220Stabilizer Top Sub, Specifications ...................................... 219Swivel, Marine Support Specifications ............................... 223Taper Mill Specifications ....................................................... 51Tool Joint Dimensions, Recommended Min-Max ............... 265Torque, Recommended Minimum Makeup ......................... 254Torque, Top Sub Makeup .................................................... 264Total Flow Area (TFA) ......................................................... 223Trackmaster .......................................................................... 74Triplex Mud Pump Data ...................................................... 282Tubing Data ........................................................................ 270Underreamer, Cone Availability ............................................ 89Underreamer, Drilling-Type (DTU) Specifications ................ 115Underreamer, Net Annular Area Removed ......................... 140Underreamer, Reamaster (XTU) Specifications ................. 105Underreamer, Rock-Type (RTU) Specifications ................. 123Underreamer, SPX/Drag-Type Specifications .................... 131Underreamer, STU Makeup Torque Specifications .............. 99Underreamer, XTU Makeup Torque Specifications .............. 99Underreamers, Gage Diameter Tolerances ........................ 132Washover Shoes, Specifications .......................................... 60Weights and Rotary Recommendations for

Hole Openers/Hole Enlargers ......................................... 156XTU Underreamer Makeup Torque Specifications ............... 99


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