drilling assembly handbook

DRILLING ASSEMBLY HANDBOOK

© 1977, 1982, 1987, 1988, 1990, 1992, 1997,1998, 2000 and 2001 Smith International, Inc. All rights reserved.

P.O. Box 60068 · Houston, Texas 77205-0068U.S. and Canada: 800-US SMITH · Tel: 281-443-3370Fax: 281-233-5121 · www.smith.com

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

The following are marks of Smith International, Inc.:Drilco, Grant, Ezy-Change, RWP, Shock Sub, Hevi-Wate, Ezy-Torq and Drilcolog.

TABLE OF CONTENTSBottom-Hole Assemblies .............................. 1

Differential Pressure Sticking ........................ 27

Bit Stabilization ........................................... 31

Drill Collar ................................................... 37

Hevi-WateT Drill Pipe ................................... 105

Tool Joints ................................................... 117

Kellys .......................................................... 135

Inspection .................................................... 143

Rotating Drilling Heads ................................ 159

Additional Information ................................. 173

Index ........................................................... 179

ii iii

PREFACE

This handbook has been altered you should engineers to help rig personnel do a better job.

It summarizes proven drilling techniquesand technical data that, hopefully, willenable you to drill a usable hole at thelowest possible cost. Carry it in your hippocket for easy reference.

If there are any questions about theDrilling Handbook, just call your nearestSmith representative or talk with ourservice people when they visit your rig.

The Field Operations, Sales,Business Development andEngineering Departments.

HOW TO USE THIS HANDBOOKThe Drilling Assembly Handbook is broken downinto eleven (11) major sections, as described inthe table of contents.

A detailed index is provided starting on page 179.The topics in the index will give the page numbersof information relating to specific drilling problemswhich you might face on the rig floor.

If you have any suggestions on how we canmake this handbook work better for you, pleasesend them to us or tell your Smith representative.

Refer suggestions to:Reader Service Dept.Smith InternationalP.O. Box 60068Houston, Texas 77205-0068

iv

BOTTOM-HOLEASSEMBLIES1SECTION ONE

Bottom-Hole Assemblies

BOTTOM-HOLE ASSEMBLIESIntroductory Comments on Bottom-Hole AssembliesThe title of this publication is “Drilling AssemblyHandbook” and most of the pages are devoted tothe entire drilling assembly, from the swivel to thebit. We have included useful information aboutthe rotary shouldered connections (pins andboxes) that are used on every drill stem member.

In this section, however, we are primarilyinterested in the bottom-hole assembly — thetools between the bit and the drill pipe. Over theyears, the bottom-hole assembly has grown fromone or two simple drill collars to quite a complexarray of tools, stacking up above the bit about500 to 1,000 ft (150 to 300 m).

Our job in this rig floor pocketbook is to sim-plify the complexities of all these tools. We’llexplain the purposes of each one and how to selectand assemble them for maximum effectivenessand minimum trouble.

Today the bottom-hole assembly serves severaluseful purposes, in addition to the simple need toeffectively load the bit with drill collar weight.Correctly designed, they can:· Prevent doglegs and key seats.· Produce a smooth bore and full size hole.· Improve bit performance.· Minimize drilling problems.· Minimize harmful vibrations.· Minimize differential pressure sticking.· Reduce production problems.

In the following pages we explain how thesedesirable objectives can be attained.

1


Figure No. 2

In a straight hole drilling contract, many of thepossible troubles can be prevented by obtainingsatisfactory contract terms on deviation and dog-legs. It is extremely important, when negotiatingthe contract itself, that the operator be aware of theadvantages in giving the broadest possible limitsfor deviation. By relaxing deviation clauses to rea-sonable limits, it is possible to drill a so-calledstraight hole at high rates of penetration and avoidthe costly operations of plugging back and straight-ening the hole. In addition to the operator’s devia-tion limits, it may be possible to work with him toselect a location so that the well may be allowed todrift into the target area. If it is desired to reach acertain point on the structure, and it is known thatthe well will drift in a certain direction up-structure,it is desirable to move the location down-dip so,when drilling normally, the bottom of the well willdrift into the target area.

From the contractor’s standpoint, valuable timecan be spent in planning the drill stem and the bitprogram along with the hydraulics.

Drift planning will include obtaining the largestdrill collars that may be safely run in a given holesize and planning for optimum bit weights to getthe best rate of penetration. If it is anticipated thatthere will be a problem maintaining the deviationwithin the contract limits, there are more extrememethods available which will assure a more nearlyvertical hole and still allow relatively high rates of penetration.

3Bottom-Hole Assemblies

STRAIGHT HOLE DRILLINGA better title would probably be “ControlledDeviation Drilling” because it has been learnedthrough the years that a perfectly straight hole isvirtually impossible to drill. No one knows theexact cause of holes going crooked but some logi-cal theories have been presented. It has been con-firmed that the drilling bit will try to climb uphillor updip in laminar formations with dips up to 40° (see Figure No. 1).

Figure No. 1

Another factor to consider is the bending char-acteristic of the drill stem. With no weight on thebit, the only force acting on the bit is the result ofthe weight of the portion of the string between thebit and the tangency point. This force tends tobring the hole toward vertical. When weight isapplied, there is another force on the bit whichtends to direct the hole away from vertical. Theresultant of these two forces may be in such adirection as to increase angle, to decrease angle or to maintain constant angle. This was stated byArthur Lubinski (research engineer for Amoco) atthe spring meeting of the Mid-Continent District,Division of Production, in Tulsa, March 1953, andwas based upon the assumption that the drill stemlies on the low side of an inclined hole (see FigureNo. 2).

In general, it is easier to drill a hole in soft forma-tions than in hard formations. In particular, the effectof the drill stem bending may be much less whendrilling soft formations, while the hard formationsrequire high bit weights.

2


WHY RESTRICT TOTAL HOLE ANGLE?Total hole angle should be restricted (1) to stay on a particular lease and not drift over into adjacentproperty; (2) to ensure drilling into a specific payzone like a stratigraphic trap, a lensing sand, a faultblock, etc.; or (3) to drill a near vertical hole to meetlegal requirements from regulatory agencies, fieldrules, etc.

The restriction of total hole angle may solvesome problems but it is not a cure-all. As can beseen in Figure No. 4, the typical 5° limit does notassure a wellbore free of troublesome doglegs.

Figure No. 4

WHY RESTRICT RATE OF HOLE ANGLE CHANGE?Lubinski pointed out in his work in the early 1960sthat the rate of hole angle change should be themain concern, not necessarily the maximum holeangle. He expressed this rate of hole angle changein degrees per 100 ft. In 1961 an API study grouppublished a tabular method of determining maxi-mum permissible doglegs that would be acceptablein rotary drilling and completions. Therefore, themain objective is to drill a “useful” hole with a full-gage, smooth bore, free from doglegs, key seats,offsets, spirals and ledges.

A key seat is formed after part of the drill pipestring has passed through the dogleg. Since the drillpipe is in tension, it is trying to straighten itself whilegoing around the dogleg. This creates a lateral forcethat causes the drill pipe to cut into the center of thebow as it is rotated (see Figure No. 5). This force is proportional to the amount of weight hangingbelow the dogleg. A key seat will be formed only ifthe formation is soft enough and the lateral forcegreat enough to allow penetration of the drill pipe.When severe doglegs and key seats are formed,many problems can develop.

5Bottom-Hole Assemblies4

Arthur Lubinski and Henry Woods (research engi-neer for Hughes Tool Co.) were among the first toapply mathematics to drilling. They stated in the early1950s that the size of the bottom drill collars would bethe limiting factor for lateral movement of the bit,and the Minimum Effective Hole Diameter (MEHD)could be calculated by the following equation:

Bit size + drill collar ODMEHD =

2Robert S. Hoch (engineer for Phillips Petroleum

Company) theorized that, while drilling with anunstable bit, an abrupt change can occur if hardledges are encountered (see Figure No. 3). Hepointed out that a dogleg of this nature wouldcause an undersized hole, making it difficult ormaybe impossible to run casing. Hoch rewroteLubinski’s equation to solve for the Minimum Permissible Bottom-Hole Drill Collar Outside Diameter (MPBHDCOD), as follows:

MPBHDCOD = 2 (casing coupling OD) - bit OD

For example:Data: 121/4 in. bit

95/8 in. casing (coupling OD = 10.625 in.)Minimum drill collar size = 2 (10.625 in.) - 12.250 in.

= 9 in. OD

Data: 311.2 mm bit244.5 mm casing (coupling OD = 269.9 mm)

Minimum drill collar size = 2 (269.9 mm) - 311.2 mm= 228.6 mm OD

Drill Collar Size Limits Lateral Bit Movement

Figure No. 3

Minimum permissible drill collar OD = 2 (casing coupling OD) – Bit OD

Robert S. Hoch

Bit OD + collar ODDrift diameter =2

Woods and Lubinski


age will build up rapidly and failure of the pipe islikely. It can be seen from this plot that if a doglegis high in the hole, with high tension in the pipe,only a small change in angle can be tolerated.Conversely, if the dogleg is close to total depth,tension in the pipe will be low and a largerchange in angle can be tolerated.

Endurance Limit for 41/2 in., 16.60 lb/ft Grade E Drill Pipein 10 lb/gal Mud (Gradual Dogleg)

Figure No. 6

If the stress endurance limit of the drill pipe isexceeded because of rotation through a dogleg, anexpensive fishing job or a junked hole might develop.

Stuck PipeSticking can occur by sloughing or heaving of thehole and by pulling the large OD drill collars into akey seat while pulling the drill stem out of the hole.

LoggingLogging tools and wirelines can become stuck inkey seats. The wall of the hole can also be damaged,causing hole problems.

Running CasingRunning casing through a dogleg can be a veryserious problem. If the casing becomes stuck in thedogleg, it will not extend through the productivezone. This would make it necessary to drill out theshoe and set a smaller size casing through the pro-ductive interval. Even if running the casing to thebottom through the dogleg is successful, the casingmight be severely damaged, thereby preventing therunning of production equipment.

CementingThe dogleg will force the casing over tightly againstthe wall of the hole, preventing a good cement bondbecause no cement can circulate between the wallof the hole and the casing at this point.


Figure No. 5

PROBLEMS ASSOCIATED WITHDOGLEGS AND KEY SEATSDrill Pipe FatigueLubinski presented guidelines in 1961 for the rateof change of hole angles. He said that if a programis designed in such a way that drill pipe damage isavoided while drilling the hole, then the hole willbe acceptable for conventional designs of casing,tubing and sucker rod strings as far as doglegseverity is concerned. A classical example of asevere dogleg condition which produces fatiguefailures in drill pipe can be seen in Figure No. 5.The stress at Point B is greater than the stress atPoint A; but as the pipe is rotated, Point A movesfrom the inside of the bend to the outside and backto the inside again. Every fiber on the pipe goesfrom minimum tension to maximum tension andback to minimum tension again. Cyclic stressreversals of this nature cause fatigue failures indrill pipe, usually within the first two feet of thebody adjacent to the tool joint, because of theabrupt change of cross section.

Lubinski suggested that to avoid rapid fatiguefailure of pipe, the rate of change of the hole anglemust be controlled. Suggested limits can be seen inFigure No. 6. This graph is a plot of the tension inthe pipe versus change in hole angle in degrees per100 ft (30.5 m). This curve is designed for 41/2

in., 16.60 lb/ft (114.3 mm, 24.7 kg/m) Grade “E”drill pipe in 10 lb/gal (1.2 g/cc) mud. It representsstress endurance limits of the drill pipe under vari-ous tensile loads and in various rates of change inhole angle. If conditions fall to the left of thiscurve, fatigue damage to the drill pipe will beavoided. To the right of the curve, fatigue dam-

6

DoglegTension

Lateralforce

Top view of key seat

section

Key seatTension

Tension Tension


Figure No. 7

3. The reaction of the formation to these loads maybe resolved into two forces — one parallel to theaxis of the hole and one perpendicular to theaxis of the hole.

This work made it possible to utilize gravity as a means of controlling change in the hole angle.Special tables were prepared to show the necessaryweight for the bit to maintain a certain hole angle.These tables also show the proper placement of astabilizer to give the maximum pendulum forceand the maximum weight for the bit. The effects ofusing larger drill collars can also be determined.

These tables or graphs may be obtained from yourSmith representative. They are called “DrillingStraight Holes in Crooked Hole Country,” PublicationNo. 59 (see page 174 for details).

Packed Hole TheoryMost people today use a packed hole assembly toovercome crooked hole problems and the pendu-lum is used only as a corrective measure to reduceangle when the maximum permissible deviationhas been reached. The packed hole assembly issometimes referred to as the “gun barrel” approachbecause a series of stabilizers is used in the holealready drilled to guide the bit straight ahead. Theobjective is to select a bottom-hole assembly to berun above the bit with the necessary stiffness andwall contact tools to force the bit to drill in the gen-eral direction of the hole already drilled. If theproper selection of drill collars and bottom-holetools is made, only gradual changes in hole angle


Casing Wear While DrillingThe lateral force of the drill pipe rotating againstthe casing in the dogleg or dragging through itwhile tripping can cause a hole to wear throughthe casing. This could cause drilling problemsand/or possible serious blowouts.

Production ProblemsIt is better to have a smooth string of casing to pro-duce through. Rod wear and tubing leaks associ-ated with doglegs can cause expensive repair jobs.It may be difficult to run packers and tools in andout of the well without getting stuck because of distorted or collapsed casing.

HOW DO WE CONTROL HOLE ANGLE?Now that we have some ideas as to the possiblecauses of bit deviation and the problems associatedwith crooked holes, let’s look at two possible solutions using the pendulum and the packed hole concepts.

Pendulum TheoryIn the early 1950s, Woods and Lubinski collabo-rated in mathematical examination of the forces on a rock bit when drilling in an inclined hole. Inorder to make their calculations, they made threebasic assumptions:1. The bit is like a ball and socket joint, free to turn,

but laterally restrained.2. The drill collars lie on the low side of the hole

and will remain stable on the low side of the hole.3. The bit will drill in the direction in which it is

pushed, not necessarily in the direction in whichit is aimed.

Consequently, the forces which act upon the bitcan be resolved into:1. The axial load supplied by the weight of the

drill collars.2. The lateral force — the weight of the drill collar

between the bit and the first point of contactwith the wall of the hole by the drill collar (pen-dulum force). Pendulum force is the tendency ofthe unsupported length of drill collar to swingover against the low side of the hole because ofgravity. It is the only force that tends to bring thehole back toward vertical (see Figure No. 7).

8

(Pendulum force)Restoring force of drillcollar weight

Reaction offormation

Height to point of tangency


Figure No. 9

StiffnessStiffness is probably the most misunderstood of allthe points to be considered about drill collars. Fewpeople realize the importance of diameter and itsrelationship to stiffness. If you double the diameterof a bar, its stiffness is increased 16 times.

For example, if an 8 in. (203.2 mm) diameterbar is deflected 1 in. (25.4 mm) under a certainload, a 4 in. (101.6 mm) diameter bar will deflect 16 in. (406.4 mm) under the same load.

Here are some numbers for moments of Inertia (I),proportional to stiffness. They represent the stiffnessof popular drill collars of various diameters.

Large diameter drill collars will help provide theultimate in stiffness, so it is important to select themaximum diameter collars that can be safely run.Drill collars increase in stiffness by the fourth powerof the diameter. For example, a 91/2 in. (241.3 mm)diameter drill collar is four times stiffer than a 7 in.(177.8 mm) diameter drill collar and is two timesstiffer than an 8 in. (203.2 mm) diameter drill collarwhile all three sizes may be considered appropriatefor drilling a 121/4 in. (311.2 mm) hole.

ClearanceThere needs to be a minimum clearance betweenthe wall of the hole and the stabilizers. The closerthe stabilizer is to the bit, the more exacting theclearance requirements are. If, for example, 1/16 in.(1.6 mm) undergage from hole diameter is satisfac-tory just above the bit, then 60 ft (18.3 m) above thebit, 1/8 in. (3.2 mm) clearance may be close enough.


will develop. This should create a useful hole witha full-gage and smooth bore, free from doglegs, keyseats, offsets, spirals and ledges, thereby making itpossible to complete and produce the well (seeFigure No. 8).

Figure No. 8

FACTORS TO CONSIDER WHEN DESIGNINGA PACKED HOLE ASSEMBLYLength of Tool AssemblyIt is important that wall contact assemblies providesufficient length of contact to assure alignmentwith the hole already drilled. Experience confirmsthat a single stabilizer just above the bit generallyacts as a fulcrum or pivot point. This will buildangle because the lateral force of the unstabilizedcollars above will cause the bit to push to one sideas weight is applied. Another stabilizing point, forexample, at 30 ft (10 m) above the bit will nullifysome of the fulcrum effect. With these two points,this assembly will stabilize the bit and reduce thetendency to build hole angle. It is, however, notconsidered the best packed hole assembly.

As shown in Figure No. 9, two points will con-tact and follow a curved line. But add one morepoint with a stiff assembly, and there is no wayyou can get three points to contact and follow asharp curve. Therefore, three or more stabilizingpoints are needed to form a packed hole assembly.

10

OD ID OD ID OD ID(in.) (in.) I (in.) (in.) I (in.) (in.) I51/4 21/4 29 63/4 21/4 100 9 213/16 318

61/4 21/4 74 71/4 213/16 115 10 313/16 486

61/2 21/4 86 81/4 213/16 198 11 313/16 713

collar between Zone 1 and Zone 2. When roughdrilling conditions are encountered, a vibrationdampener will increase penetration rate and addlife to the drill bit. Wear and tear on the drilling rig and drill stem will also be reduced.

Mild Crooked Hole Country (Minimal Assembly)

Figure No. 10

Medium Crooked Hole CountryA packed hole assembly for medium crooked holecountry is similar to that for mild crooked holeconditions but with the addition of a second stabi-lizing tool in Zone 1. The two tools run in tandemprovide increased stabilization of the bit and addstiffness to limit angle changes caused by lateralforces (see Figure No. 11).

Medium Crooked Hole Country

Figure No. 11

Bottom-Hole Assemblies 13Bottom-Hole Assemblies

In some areas, wear on contact tools and clearancecan be a critical factor for a packed hole assembly.

Wall Support and the Length of Contact ToolBottom-hole assemblies must adequately contact thewall of the hole to stabilize the bit and centralizethe drill collars. The length of contact needed betweenthe tool and the wall of the hole will be determinedby the formation. The surface area in contact mustbe sufficient to prevent the stabilizing tool from dig-ging into the wall of the hole. If this should happen,stabilization would be lost and the hole would drift.If the formation is strong, hard and uniform, ashort narrow contact surface is adequate and willensure proper stabilization. On the other hand, ifthe formation is soft and unconsolidated, a longblade stabilizer may be required. Hole enlargementsin formations that erode quickly tend to reduceeffective alignment of the bottom-hole assembly.This problem can be reduced by controlling theannular velocity and mud properties.

PACKED HOLE ASSEMBLIESProper design of a packed hole assembly requires aknowledge of the crooked hole tendencies and drill-ability of the formations to be drilled in each partic-ular area. For basic design practices, the followingare considered pertinent parameters:

Crooked hole drilling tendencies:· Mild crooked hole country.· Medium crooked hole country.· Severe crooked hole country.

Formation firmness:·Hard to medium-hard formations.

– Abrasive.– Non-abrasive.

· Medium-hard to soft formations.

Mild Crooked Hole CountryThe packed hole assembly shown in Figure No. 10for mild crooked hole country is considered theminimal assembly for straight hole drilling and bitstabilization. Three points or zones of stabilizationare provided by Zone 1 immediately above the bit,Zone 2 above the large diameter short drill collarand Zone 3 atop a standard length large diametercollar. A vibration dampener, when used, shouldbe placed above Zone 2 for the best performance.In very mild crooked hole country the vibrationdampener may be run in the place of the short drill

12

Zone 3 String stabilizer

String stabilizer

Bottom hole stabilizerBit

Note: In very mild crooked hole country the vibration dampener may be run in place of the short drill collar.

30 foot large diameter drill collar

Large diameter short drill collar

Vibration dampener (when used)

Zone 2

Zone 1


String stabilizer

String stabilizerBottom hole stabilizerBit




Zone 2

Zone 1

Dual stabilizers


As a general rule of thumb, the short drill collarlength in meters is equal to 12 times the diameterof the hole in meters, plus or minus 0.6 m. Forexample: a short collar length of 1.8 to 3.0 m would be satisfactory in a 203.2 mm hole.

STABILIZING TOOLSThere are three basic types of stabilizing tools: (1) rotating blade, (2) non-rotating sleeve and (3) rolling cutter reamer. Some variations of these tools are as follows:

1. Rotating BladeA rotating blade stabilizer can be a straight bladeor spiral blade configuration, and in both cases theblades can be short or long (see Figure No. 14).

The rotating blade stabilizers shown in Figure No. 14 are available in two types: (a) shop repairableand (b) rig repairable.

Figure No. 14

a. Shop RepairableThe shop repairable tools are either integral

blade, welded blade or shrunk on sleeve construc-tion. Welded blade stabilizers are popular in softformations but are not recommended in hard for-mations because of rapid fatigue damage in theweld area.b. Rig Repairable

Rig repairable stabilizers either have a replace-able metal sleeve like the Ezy-ChangeE stabilizeror replaceable metal wear pads like the RWP T

(Replaceable Wear Pad) stabilizer. These toolswere originally developed for remote locationsbut are now used in most areas of the world.


Severe Crooked Hole CountryIn severe crooked hole country three stabilizationtools are run in tandem in Zone 1 to provide maxi-mum stiffness and wall contact to aim and guide thebit. In 83/4 in. (222.3 mm) and smaller hole sizes, it isalso recommended that a large diameter short collarbe used between Zone 2 and Zone 3. This willincrease stiffness by reducing the deflection of thetotal assembly. It will allow the tools in Zone 1 andZone 2 to perform their function without excessivewear due to lateral thrust or side-loading fromexcess deflection above (see Figure No. 12).

Severe Crooked Hole Country

Figure No. 12

Mild, Medium and Severe Crooked Hole CountryFigure No. 13 shows all three basic assembliesrequired to provide the necessary stiffness and stabi-lization for a packed hole assembly. A short drill col-lar is used between Zone 1 and Zone 2 to reduce theamount of deflection caused by the drill collar weight.

As a general rule of thumb, the short drill collarlength in feet is approximately equal to the hole sizein inches, plus or minus 2 ft. For example: a shortcollar length of 6 to 10 ft would be satisfactory inan 8 in. hole.

Figure No. 13

14


String stabilizer

String stabilizerString stabilizerBottom hole stabilizerBit




Zone 2

*

Zone 1

Tandem stabilizers

*Note: Use short drill collar in 83/4 in. and smaller holes.

Mild

Zone 3

Zone 2*

*

Zone 1

* Short drill collar

* The short drill collar length is determined by the hole size. Hole size(in.) = short drill collar (ft) ± 2 ft. Example: Use approximately an 8 ftcollar in an 8 in. diameter hole.

Medium Severe

Stg. RWP

Stg.weldedblade

Stg. I.B.

Stg. rigreplaceable

sleeve


Figure No. 16

MILD, MEDIUM AND SEVERE CROOKED HOLECOUNTRY IN HARD TO MEDIUM-HARDFORMATIONSIn Zone 1-A (directly above the bit), a rolling cutterreamer (see Figure No. 17) should be used whenbit gage is a problem in hard and abrasive forma-tions. A six-point tool is required for extreme con-ditions. In non-abrasive formations, some type ofrotating blade tool with hardfacing is desirable.

Mild, Medium and Severe Crooked Hole CountryHard to Medium-Hard Formations

Figure No. 17


All rotating stabilizers have fairly good reamingability and because of recent improvements inhardfacing, have very good wear life. Some of thehardfacing materials used today are:· Granular tungsten carbide.· Crushed sintered tungsten carbide.· Sintered tungsten carbide (inlaid).· Pressed-in sintered tungsten carbide compacts.· Diamond-enhanced pressed-in carbide compacts.

2. Rig Replaceable Non-Rotating Sleeve StabilizerThe non-rotating sleeve tool is a very popular sta-bilizer because it is the safest tool to run from thestandpoint of sticking and washover. This type ofstabilizer is most effective in areas of hard forma-tions such as lime and dolomite. Since the sleeve is stationary, it acts like a drill bushing and, there-fore, will not dig into and damage the wall of thehole. It does have some limitations. The sleeve isnot recommended to be used in temperatures over250°F (121°C). It has no reaming ability and sleevelife may be short in holes with rough walls (seeFigure No. 15).

Figure No. 15

3. Rolling Cutter ReamerRolling cutter reamers are used for reaming andadded stabilization in hard formations. Wall con-tact area is very small, but it is the only tool thatcan ream hard rock effectively. Anytime rock bitgage problems are encountered, the lowest con-tact tool should definitely be a rolling cutterreamer (see Figure No. 16).

16

Non-rotating stabilizer

3 point BH reamer

Zone 3

Zone 2

Zone 1

Mild

Or Or Or

BH I.B.

BH RWP

Med. Sev.

3 point BH reamer

6 point BH reamer

BH rigreplaceable

sleeve

Zone 1-A(abrasive)

Zone 1-A(non-abrasive)

Note: Use a reamer if the bit gage is a problem. Use a 6 point in extremely hard and abrasive formations.


MEDIUM AND SEVERE CROOKEDHOLE COUNTRY IN HARD TOMEDIUM-HARD FORMATIONSIn Figure No. 20, it is shown that some type ofrotating blade stabilizer is recommended in Zone 1-B with hard to medium-hard formationsand medium to severe crooked hole tendencies.For severe crooked hole drilling, one of the sametypes of tools can be used in Zone 1-C.


Figure No. 20

MILD, MEDIUM AND SEVERE CROOKEDHOLE COUNTRY IN MEDIUM-HARD TOSOFT FORMATIONSTools for use in medium-hard to soft formations,where the bit gage is no problem, must providemaximum length of wall contact to provide properstabilization to the drill collars and bit. For alldegrees of crooked hole tendencies, rotating bladestabilizers are recommended (see Figure No. 21).

Mild, Medium and Severe Crooked Hole CountryMedium-Hard to Soft Formations

Figure No. 21


Rotating blade-type tools are effective in Zone 2for all three conditions of crooked hole tendencies.In very mild crooked hole country, a non-rotatingsleeve-type tool will be all right (see Figure No. 18).


Figure No. 18

With the slightest deviation from vertical, drillcollars will lie on the low side of the hole because oftheir enormous weight. Therefore, the function ofZone 3 is to centralize the drill collars above Zone 2.Both the rotating blade and the non-rotating sleevestabilizers may be used for this job in hard tomedium-hard formations (see Figure No. 19).


Figure No. 19

Any stabilizers run above Zone 3 are used onlyto prevent the drill collars from buckling or becom-ing “wall stuck,” and in most cases, will have verylittle effect on directing the bit.

18

Zone 3

Zone 2

Zone 1

Mild

Or Or

Stg. I.B.

Stg. RWP

Med. Sev.

Stg. rigreplaceable

sleeve

Zone 2

Note: In very mild crooked holecountry, a non-rotating stabilizermay be used in Zone 2.

Zone 3

Zone 2

Zone 1

Mild

Or Or Or Or

BH I.B.Stg. RWPBH RWP

Med. Sev.

BH rigreplaceable

sleeve

Stg. rigreplaceable

sleeve

Zone 1-A Zone 1-B & CZone 2Zone 3

Zone 3

Zone 2

Zone 1

Or Or

Stg. I.B.

Med. Sev.

Stg. rigreplaceable

sleeve

Zone 1-B

Note: The same tools wouldbe used in Zone 1-C forsevere crooked hole country.

Zone 3

Zone 2

Zone 1

Mild

Or Or

Non-rotating Stg. rigreplaceable

sleeve

Med. Sev.Zone 3

Stg. I.B.

Stg. RWP

Stg. I.B.


Figure No. 22

REDUCED BIT WEIGHTSOne of the oldest techniques for straightening thehole is to reduce the weight on the bit and speed upthe rotary table. By reducing the weight on the bit, thebending characteristics of the drill stem are changedand the hole tends to be straighter. In recent years ithas been found that this is not always the best proce-dure because reducing the bit weight sacrifices con-siderable penetration rate. Worse, it frequently bringsabout doglegs as illustrated in Figure No. 23. As apoint of caution, the straightening of a hole by reduc-ing bit weight should be done very gradually so thehole will tend to return to vertical without sharpbends and will be much safer for future drilling. Areduction of bit weight is usually required whenchanging from a packed hole assembly to a pen-dulum or packed pendulum drilling operation. Anunder-gage stabilizer is sometimes run immediatelyabove the bit to prevent dropping angle too quickly.

Figure No. 23


Modern packed hole assemblies, when properly designed and used, will:1. Reduce rate of the hole angle change. A smooth

walled hole with gradual angle change is moreconvenient to work through than one drilled atminimum hole angle with many ledges, offsetsand sharp angle changes.

2. Improve bit performance and life by forcing thebit to rotate on a true axis about its design center,thus loading all cones equally.

3. Improve hole conditions for drilling, loggingand running casing. Maximum size casing canbe run to bottom.

4. Allow use of more drilling weight through formations which cause abnormal drift.

5. Maintain desired hole angle and course in direc-tional drilling. In these controlled situations, highangles can be drilled with minimum danger ofkey seating or excessive pipe wear.

PACKED PENDULUMBecause all packed hole assemblies will bend,however small the amount of deflection, a per-fectly vertical hole is not possible. The rate ofhole angle change will be kept to a minimum butoccasionally conditions will arise where total holedeviation must be reduced. When this conditionoccurs, the pendulum technique is employed. If itis anticipated that the packed hole assembly willbe required after reduction of the hole angle, thepacked pendulum technique is recommended.

In the packed pendulum technique, the pendu-lum collars are swung below the regular packedhole assembly. When the hole deviation has beenreduced to an acceptable limit, the pendulum col-lars are removed and the packed hole assemblyagain is run above the bit. It is only necessary toream the length of the pendulum collars prior toresuming normal drilling.

If a vibration dampening device is used in thepacked pendulum assembly, it should remain in itsoriginal position during the pendulum operations(see Figure No. 22).

20

Packed hole assembly

Drill collars

Bit

Vibration dampener

Pendulum

Packed Pendulum

Bottom-Hole Assemblies 23Bottom-Hole Assemblies

CONCLUSIONIn summation, a well-engineered bottom-holeassembly, with the proper selection of stabilizingtools in all three zones, should produce a useful holewith a full-gage, smooth bore free from doglegs, keyseats, offsets, spirals and ledges, thereby making itpossible to complete and produce the well. Both thedrilling contractor and oil company operator shouldrealize additional profits from a well-planned pro-gram. Careful planning will usually result in the best drill stem for a given job.

DOWNHOLE VIBRATIONS?Back in 1959, Smith began to market the first suc-cessful downhole vibration dampener to meet a veryobvious need. Drillers were having 10 to 15 drill col-lar failures per well in 121/4-in. (311.2 mm) holesgoing to 6,000 ft (1,830 m) in a rough-running area.Ordinary measures failed to solve the problem. TheShock SubT or vibration dampener was introducedinto the drill stem and the drill collar failures werereduced.

A second benefit was increased bit life. A thirdbenefit was then achieved by increasing both rotaryspeed and bit weight and further stepping up dailydrilling depth. In rough-running areas, the down-hole vibration dampener has become a way of life.Its use has been extended to many areas, worldwide.

Downhole data collected by a major oil company,provided a glimpse of what really goes on at the bot-tom of the hole. Using a downhole instrumentationsub, they measured among other things bit weight,rotary speed, vertical vibrations and bending stressin the sub.

Without even being aware of it at the surface,small changes in such things as rotary speed, bitweight or formation can cause fantastic gyrations tooccur at the bottom of the hole. Vibrations developthat cause impact loads on the bit several times theload indicated at the surface. Bending loads in thesub increase by perhaps 10 times.

These events indicate how vague our knowledgeof “downhole dynamics” really is. We’ve learned tocope with them to some degree.

22

IMPROVE HOLE OPENERPERFORMANCE BY USING AVIBRATION DAMPENERAND STABILIZERSHole opening performancecan improve with the useof a vibration dampenerand a stabilizer.

1. StabilizerA stabilizer placed at 60 ft(18.3 m) and 90 ft (27.4 m) inthe drill stem will help to min-imize drill collar bending.

2. Drill CollarHigher stress concentrationsexist in the connection. Add tothis the bouncing of the drillstem caused by rough run-ning and the result can be drillcollar connection failures.

3. StabilizersA stabilizer will center thecollars in the hole above thehole opener and make theload on the cutters moreuniformly distributed.

4. Vibration DampenerA vibration dampener willminimize vibrations causedby the hole opener stum-bling over broken forma-tions and reduce the shockloads on the cutters andthe drill collars.

5. Hole OpenersThe collars are so muchsmaller than the hole, theybend and whip, loading firstone cutter, and then the next.They put a terrific side loadon the pilot bit, and the holeopener body. The vibrationdampener, with the stabilizercan help eliminate this.


Notes

24

DIFFERENTIAL PRESSUSTICKING2SECTION TWO

Differential Pressure Sticking

DIFFERENTIAL PRESSURE STICKING OFDRILL PIPE AND DRILL COLLARSDifferential wall sticking is caused by the drill pipeor drill collars blocking the flow of fluid from theborehole into the formation. In a permeable forma-tion, where the mud column hydrostatic head ishigher than the pressure in the formation, the fluidloss can be considerable. Associated with the flowof fluid into the formation is a filtering of solids atthe wall of the hole and a resultant build up of filtercake. The smooth surfaces of the tools, assisted bythe sealing effect of the filter cake, form an effectiveblock to fluid losses into the formation. Dependingon length of blocked area, and differences in bore-hole and formation pressures, this blockage of fluidflow may permit extremely high forces to build upagainst the tools in the hole, and thus the drill stembecomes differentially wall stuck.

The use of a packed hole assembly will elimi-nate many of the conditions which result in stick-ing of the drill stem by holding the drill stem offthe wall of the hole. Such bit stabilizing assembliesalso help prevent sudden hole angle changes, off-sets and doglegs which lead to sticking the drillstem in key seats.

REDUCING DIFFERENTIAL PRESSURE STICKING

Can Be Effectively Reduced By Using the Following Tools:

Hevi-WateT Drill Pipe (see Figure No. 24)The tool joints at the ends and the integral

upset in the center of the tube act as centralizersto hold the heavy-wall tube sections off the wallof the hole. (For more information see page 105.)

Spiral or Grooved Drill Collars (see Figure No. 24)This tool presents a smaller contact area with the

wall of the hole. The spiral also allows fluid passageand equalizing of bore pressure around the collars.The box end of all sizes of spiral drill collars is leftuncut for a distance of no less than 18 in. (457 mm)and no more than 24 in. (610 mm) below the shoul-der. The pin end of all sizes of drill collars is left uncutfor a distance of no less than 12 in. (305 mm) andno more than 22 in. (559 mm) above the shoulder.

27

Differential Pressure Sticking

Stabilizers (see Figure No. 24)Stabilizers positioned throughout the drill stem

are another positive way of preventing differentialsticking. Rotating blade, welded blade and non-rotating sleeve-type stabilizers are used to keep thedrill collars centered in the hole. Selection of thetype of stabilizers and their spacing in the drillstem varies with the formation being drilled, thesize of the hole, etc. Your Smith representativecan provide field data for your area.

28

Conventional drill collar

Spiral equalizes pressure in stuck area

Stuck area

Hevi-Wate drill pipe

IB stabilizer

IB stabilizer(Integral blade)

Near Bit IB Stabilizer

Spiral drillcollar

BIT STABILIZATION3SECTION THREE

Figure No. 24

Hydra-shock®

IB stabilizer

Bit Stabilization

BIT STABILIZATION PAYS OFFAbout 55 years ago, bit engineers wondered why 77/8 in. (200.0 mm) bits performed better than83/4 in. (222.3 mm) bits. Then they realized bothsizes of bits were run with 61/4 in. (158.8 mm) drillcollars. The 77/8 in. (200.0 mm) bits were clearlybetter stabilized than the 83/4 in. (222.3 mm) bits.

Since that time the art of bit stabilization hascontinued to improve. About 40 years ago a casedeveloped where a certain section in offset wellsrequired 2,000 hours to drill in one case, and only1,200 hours in the other. All of the normally recordedconditions on the bit records were the same. Thenit was realized that small limber drill collars wereused in the first case and a fairly well-stabilizedbottom assembly in the other.

More recently drillers have been employing bottom-hole assemblies described on pages 12through 20 to get the very most out of every bit. Thebetter the bit is stabilized, the better it performs.

Large size bits have been notoriously neglected in the application of stabilization techniques. Forexample, it has been common practice to dull 171/2 in.(444.5 mm) bits with unstabilized 8 in. (203.2 mm)drill collars. That’s like trying to drill a 77/8 in.(200.2 mm) hole with slick 37/8 in. (98.4 mm) drill collars!

People got by with this in years gone by, becausethey only drilled very soft formations with suchlarge bits. Now, in coping with hard formations inthese hole sizes, it is becoming quite apparent thatthe principles developed for smaller holes shouldalso be extended to the larger ones.

We suggest you employ the stiff, stabilizingassemblies described in this book with every bityou dull. They’ve been proven in hole sizes allthe way up to 120 in. (3,048 mm)!

STABILIZATION IMPROVES BIT PERFORMANCERock bits are designed to rotate about the axis ofthe hole. Their service life is shortened when theaxis is misaligned. This misalignment may be parallel or angular.

When the axis at the bottom of the hole shiftsin a parallel manner, the bit runs off center (seeFigure No. 25). This causes the cutting structure towear pick-shaped. Rings of uncut bottom developand bit life is drastically reduced.

31

Bit Stabilization 33Bit Stabilization

If the drill collar directly above the bit leansagainst the hole wall, angular misalignmentoccurs. The penalty on bit performance dependson the degree of misalignment. For example, in an83/4 in. (222.3 mm) hole, 7 in. (177.8 mm) collarsreduce the effect to some degree, but misalignmentstill exists.

Angular misalignment permits two very harm-ful effects to exist. First, the full weight on the bitis shifted from one cone to the other, causing rapidbreakdown of tooth structure and bearings. Weightshould be evenly distributed on all three cones.The second bad effect is the breakdown of the vitalgage cutting surfaces at the tops of the outer toothrows. “Apple-shape” cones result and bit life suffersgreatly (see Figure No. 27).

Dramatic improvements in bit life have beenobserved in shifting from non-stabilized to stabi-lized bottom-hole assemblies, particularly whendiamond bits, PDC bits, journal bearing or sealedbearing bits are being run.

Avoid both angular and parallel misalign-ment with properly selected stabilizing assem-blies. The higher the degree of stabilization,the greater the benefits.

Figure No. 25 Figure No. 26

32

Parallel MisalignmentParallel misalignment is caused by the use ofsmall drill collars (inrelation to the hole size)and no stabilization.The bit can move offcenter until the drill collars’ OD contacts the wall of the hole. This results in an offsetdue to drilling off center.

Angular MisalignmentAngular misalignment is caused by the use ofsmall drill collars (inrelation to the hole size)and no stabilization.Most or all of the bitload is applied to onecone at a time, causingrapid breakdown andfailure of both the cut-ting structure and bear-ing structure of the bit.

Figure No. 27

Figure No. 27 shows a photograph of a brokenmedium, soft to medium formation bit that hasrun off center. Note the cone shell, between rowsof cutting structure, has been grooved by therings of uncut bottom-hole formations.

Figure No. 28

Figure No. 28 shows a photograph of a mediumformation bit that has suffered gage wear and gagerounding due to angular misalignment.

Figure No. 29

Figure No. 29 shows a photograph of a bit thathas suffered severe damage to the gage and OD ofthe bit itself. The lugs have worn so badly that theshirttails are gone and some of the roller bearingsare missing. The bit was run too long in an abra-sive formation. When the bit is pulled like this,the last portion of the hole was drilled undergage.The entire tapered portion of the hole must bereamed out to the new bit gage.

Bit Stabilization34

DRILL COLLAR4SECTION FOUR

Figure No. 30

Figure No. 30 shows a photograph of a brokenmedium, soft to medium bit that has been run with-out the support of a dampening device. A vibrationdampener run in the bottom-hole assembly will helpobtain a faster rate of penetration and increased bitlife. When drilling in broken hard formations, exces-sive vibration, bit bounce and shock loading cancause tooth and tungsten carbide insert breakageand rapid bearing failure. Because of rough-runningin some formations, the desired weight and rotatingspeed cannot be utilized. The use of a vibrationdampener will eliminate the damaging shock load-ing and help maintain a faster rate of penetrationand longer bit life.

Drill Collar

DRILL COLLAR CARE AND MAINTENANCE

Don’t Ruin Those New Drill CollarsRead the following statement. It may save youmany headaches in the months ahead.

“A new string of drill collars should give manymonths of trouble-free service, but they can beruined on the first trip down the hole if they aren’tproperly cleaned and lubricated, and made up withmeasured and controlled makeup torque. Infact, the threads or shoulders can be damaged inpicking up or on initial makeup, and be ruinedbefore they are ever run into the hole.”

“Proper makeup torque, consistently measuredand applied, is essential to satisfactory drill collarjoint performance. Nothing that is done in designand manufacture can obviate the necessity for rig-level makeup torque control. It has to be doneon the rig!”

The above statement is quoted from a series of articles published in the March 1966, Oil & Gas Journal.

IMPORTANCE OF BALANCED DRILL COLLARPIN AND BOX CONNECTIONSDrill collar manufacturers recommend connectionsizes based on the balance of pin and box bend-ing strength ratios. The formula for this calcula-tion is in the API RP 7G.

The drill collar connection, more correctlycalled a rotary shouldered connection, must per-form several necessary functions. The connectionis a tapered threaded jack screw that forces theshoulders together to form the only seal, and actsas a structural member to make the pin equally asstrong, in bending, as the box when made up to therecommended torque. The threads do not form aseal. By design, there is an open channel from thebore to the shoulder seal. This space is there to

37

Drill Collar

4. Lift sub pins should be cleaned, inspected andlubricated on each trip. If these pins have beendamaged and go unnoticed, they will eventuallydamage all of the drill collar boxes.

Initial Makeup of New Drill Collars1. A new joint should be very carefully lubricated.

Any metal-to-metal contact may cause a gall.Application should be generous on shoulders,threads and in the pin relief grooves.

2. Good rig practice is to “walk in” the drill collarjoint using chain tongs.

3. Make up to proper torque.4. Break out connection and inspect for and

repair minor damage.5. Relubricate and make up to proper torque.

Torque Control1. Torque is the measure of the amount of twist

applied to members as they are screwed together.The length of the tong arm in feet multiplied bythe line pull in pounds is foot-pounds (ft-lb) oftorque. Use feet and tenths of a foot.

1. The length of the tong arm in meters multipliedby the line pull in kilograms is kilogram-meters(kg-m) of torque.

2. A 4.2 ft tong arm and 2,000 lb of line pull at the end of the tong, will produce 4.2 ft times2,000 lb, or a total of 8,400 ft-lb of torque (seeFigure No. 32).

1. A 1.28 m tong arm and 907 kg of line pull at the end of the tong, will produce a 1.28 m times907 kg or a total of 1161 kg-m of torque (seeFigure No. 32).

39Drill Collar

accommodate excess thread compound, foreignmatter and thread wear (see Figure No. 31).

Figure No. 31

See the guides and tips for proper selection ofconnections for various ODs and IDs on pages 78through 95.

RECOMMENDED DRILL COLLAR CAREAND MAINTENANCEThree points that are a must for good drill collarperformance are:1. Must properly lubricate shoulders and threads

with drill collar compound.2. Must use proper torque; must be measured.3. Must immediately repair minor damage.

Picking Up Drill Collars1. Cast-steel thread protectors with a lifting bail,

provide a means of dragging the collar into the“V” door and protecting the shoulders andthreads. Remember that the pin should also be protected.

2. Connections should be cleaned thoroughly witha solvent and wiped dry with a clean rag. Inspectcarefully for any burrs or marks on the shoulders.

3. A good grade of drill collar compound, contain-ing powdered metallic zinc in the amount of40 to 60% by weight should be applied to thethreads and shoulders on both pin and box.Drill pipe lubricants without a minimum of 40to 50% zinc are not recommended because theynormally are made with lead oxide which doesnot have sufficient body for the high shoulderloads necessary in drill collar makeup.

38

Drill Collar

Recommended Minimum Torque (ft-lb)

6. It should be emphasized that the torque valuesshown in the table are minimum requirements.The normal torque range is from the tabulatedfigure to 10% higher.

1. From the example above, the required torquerange is 32,200 to 35,400 ft-lb; (32,200 ft-lb) +(32,200 ft-lb x .10) = 35,400 ft-lb.

Rig Maintenance of Drill Collars1. It is recommended practice to break a different

joint on each trip, giving the crew an opportunityto inspect each pin and box every third trip. Inspectthe shoulders for signs of loose connections, gallsand possible washouts.

2. Thread protectors should be used on both pinand box when picking up or laying down thedrill collars.

3. Periodically, based on drilling conditions andexperience, a magnetic particle inspectionshould be performed, using a wet fluorescentand black light method.

4. Before storing the drill collars, they should becleaned. If necessary, reface the shoulders with a shoulder refacing tool, and remove the fins on the shoulders by beveling. A good rust pre-ventative or drill collar compound should beapplied to the connections liberally, and thread protectors installed.

HERE IS THE WAY TO FIGURE THE DRILL COLLARMAKEUP TORQUE YOU NEEDAs discussed on pages 38 through 41, you mustuse the recommended makeup torque and thistorque must be measured with an accurate device.

There are two steps that must be worked outfor all hookups:

Step No. 1Look in the torque tables, pages 54 to 65, and findthe minimum torque recommended for the sizedrill collars (OD and ID) and type of connection.

41Drill Collar

Figure No. 32

3. A line pull measuring device must be used in making up drill collars. It is important thatline pull be measured when the line is at rightangles (90°) to the tong handle.

4. When applying line pull to the tongs, it is bet-ter to apply a long steady pull rather than tojerk the line. Hold pull momentarily to makesure all slack is taken up.

5. The proper torque required for a specific drillcollar should be taken from a table of recom-mended torques for drill collars. For a 63/4 in.(171.5 mm) OD x 213/16 in. (71.4 mm) ID with aNC 50 connection, the table indicates a torque of 32,200 ft-lb (4,460 kg-m) (see pages 54through 65).

40

4.2 ft

2,000 lb line pullFully effective tong armTorque = 4.2 ft x 2,000 lb

= 8,400 ft-lb

90°

4.2 ft

4.2 ft

3 ft

3,000 lb line pullFully effective tong armTorque = 4.2 ft x 3,000 lb

= 12,600 ft-lb

Ineffective tong armTorque = 3 ft x 3,000 lb

= 9,000 ft-lb

90°

4.2 ft

3,000 lb line pull

3 ft

3,000 lb line pull

45°

45°

Connection OD Bore of Drill Collar (in.)Type (in.) 21/4 21/2 213/16 3 31/4

NC 50 63/4 36,700 35,800 32,200 30,000 26,600

Drill Collar 43Drill Collar

Step No. 2Divide the torque value by the effective length

of the tong arm (see Figure No. 33). This will givethe total line pull required.

Figure No. 33

Example:For 42 in. tongs, divide by 12 in. = 3.5 ftFor 48 in. tongs, divide by 12 in. = 4 ftFor 50 in. tongs, divide by 12 in. = 4.2 ftFor 54 in. tongs, divide by 12 in. = 4.5 ft

For collars with 63/4 in. OD x 21/4 in. ID andNC 50 (41/2 in. IF) connections, the tables recom-mended 36,741 ft-lb of makeup torque. Say the“effective” tong arm length is 50 in. then:

50 in. = 4.2 ft

12 in.

36,741 ft-lb= 8,748 lb of line pull

4.2 ft

Example:For 42 in. tongs, multiply by .0254 = 1.07 mFor 48 in. tongs, multiply by .0254 = 1.22 mFor 50 in. tongs, multiply by .0254 = 1.27 mFor 54 in. tongs, multiply by .0254 = 1.37 m

For collars with 171.4 mm OD x 57.1 mm IDand NC 50 (41/2 in. IF) connections, the tablesrecommend 5,080 kg-m of makeup torque. Saythe “effective” tong arm length is 50 in. then:

(50 in.) x (.0254) = 1.27 m

5,080 kg-m= 4,000 kg of line pull

1.27 m

42

Effective tong arm length

90°

Cathead pull

The 8,748 lb (4,000 kg) of line pull is thetotal pull required on the end of this 4.2 ft(1.27 m) tong. This may or may not be the amountof line pull reading on the torque indicator, as thisdepends on the location of the indicator.

The following pages show 15 examples of hookupsused to make up drill collar connections. Selectthe one being used and follow the steps outlined.

Note: In the 15 examples on the following pages,the heavy black arrow is used to indicate cathead pull.

Caution: Before torquing, be sure the tongs areof sufficient strength.

Step No. 1 Look up the minimum recommended torque required.

Step No. 2 Divide this torque value by the effective tong length.

The answer is pounds pull reading for the line pull indicator when in this position.

Figure No. 34

Snub line

The amount of cathead pull willbe the same as the line pullreading on your Torque Indicator.

Torque indicator

90°

Drill Collar 45Drill Collar

Step No. 1 Look up the minimum recommended torquerequired.

Step No. 2 Divide this torque value bythe effective tong length.

The answer is pounds pull reading for theline pull indicator when in this position.

Figure No. 35




Figure No. 36

44

Torque indicator

Snub line90°


Torque indicator

Snub line 90°


Torque indicator

Snub line90°

The amount of cathead pull willbe 1/2 of the line pull reading onyour Torque Indicator.



The answer is pounds pull reading for theline pull indicator when in this position.

Figure No. 37

Step No. 1 Look up the minimumrecommended torquerequired.

Step No. 2 Divide this torque bythe effective tong length.

The answer is pounds pull readingfor the line pull indicator when inthis position.

Figure No. 38

Snubline


Snub line

Snub line

Torque indicator

90°

Drill Collar



Step No. 3 Divide this by 2. This will be the pounds pull reading for the line pull indicator when in this position.

Figure No. 41


Step No. 2 Divide this torque valueby the effective tonglength.

Step No. 3 Divide this by 2. This willbe the pounds pull read-ing for line pull indicatorwhen in this position.

Figure No. 42

47Drill Collar46


Snub line

Torque indicator

90°




Figure No. 39



The answer is pounds pull readingfor the line pull indicator when inthis position.

Figure No. 40

Snubline


Snub line

Torque indicator

90°

Snubline

The amount of cathead pullwill be the same as the linepull reading on your TorqueIndicator.Snub line

Snubline

90°

Torque indicator

Snub line

90°

Snubline

Torque indicator

The amount of cathead pull will bethe same as the line pull readingon your Torque Indicator.

Drill Collar



Step No. 3 Divide this by 3. Thiswill be the pounds pullreading for line pull indi-cator when in this posi-tion.

Figure No. 45



Step No. 3 Divide this by 3, andmultiply by 2. This willbe the pounds pullreading for the line pull

Figure No. 46

49Drill Collar



Step No. 3 Divide this by 2. This willbe the pounds pull readingfor the line pull indicatorwhen in this position.

Figure No. 43



Step No. 3 Divide this by 2. This willbe the pounds pull readingfor the line pull indicatorwhen in this position.

Figure No. 44

48

Snub line

Snubline

Snub line

Snub line

Torque indicator

90°

Torque indicator

90°


Snub line

Torque indicator

90°

Snub line

The amount of cathead pull will bethe same as the line pull readingon your Torque Indicator.

Snub line

Snubline

90°

Torque indicator



Divide this by 3, and mul-tiply by 2. This will be thepounds pull reading forthe line pull indicatorwhen in this position.

Divide this by 3. This willbe the pounds pull read-ing for line pull indicatorwhen in this position.

Drill Collar

HOW DO YOU APPLY AND MEASURE MAKEUPTORQUE?Rig CatheadsMost drilling rigs have catheads on each side of thedrawworks which are used to apply line pull to thetongs. The catheads do not have built in devices tomeasure the amount of line pull. Line pull measur-ing devices must be added to the lines between thetongs and the catheads to accomplish this task.The driller is required to release the cathead clutchat the appropriate time in order to ensure thedesired pull is not exceeded. This often causeserrors in application of the torque.

Hydraulic Load CellsFor measuring the amount of applied line pull,many rigs use hydraulic load cells. Load cells aresimple devices that are generally very reliable. Aload cell device usually consists of three parts: (1)a small hydraulic cylinder, (2) a pressure gagethat reads pounds of pull, and (3) a rubber hoseto connect the cylinder and the gage. One mustremember that the gage reads in pounds of forceand not in foot-pounds of torque. You must mea-sure the length of the tongs in feet. And then youmultiply the gage reading (pounds) by the tonglength (feet) to get foot-pounds of torque.

Automatic Torque Control SystemSmith provides a system that eliminates the prob-lems associated with using the rig catheads. Thisproduct is called the Automatic Torque ControlSystem (ATCS). The ATCS is a highly accurate solid-state electronic control that automatically terminatesmakeup of the drill stem connections when the pre-specified torque is reached. It can be used on anyrig that has manual tongs and air-activated catheadclutches. With a few modifications it can beadapted to hydraulic makeup systems.

The ATCS includes an intrinsically safe loadcell, explosion-proof air controllers and an air-purged control panel for operation in Class 1,Group D, Divisions 1 and 2 hazardous environ-ments. For operation in all Division 1 situations,a power time delay unit is required.

51Drill Collar



Step No. 3 Divide this by 5, and multi-ply by 4. This will be thepounds pull reading for theline pull indicator when inthis position.

Figure No. 47



Step No. 3 The answer is pounds pullreading for the line pull indi-cator when in this position.

Figure No. 48

50

The amount of cathead pull willbe 1/4 of the line pull reading onyour Torque Indicator

Snub line

Snubline Torque indicator

90°


Torque indicator

Snub line

Snub line

90°

Drill Collar

Give This Some ThoughtEach torque measuring device has a limit for thetotal amount of line pull it can accurately measure.Know the limit of the instrument you are using andwork within the recommended range (see pages 41through 50).

Multiple line hookups can provide many timesthe normal makeup line pull. Great care should betaken to see that the lines do not become crossed,twisted or fouled. When it comes time for the “bigpull*,” be sure everyone is in the clear.

*Caution: Know the tong’s rating before thepull is attempted.

The slack in the tong safety line should be suffi-cient for the tongs to obtain full benefit of the pullfrom the cathead, but short enough to preventcomplete rotation of the tongs.

53Drill Collar

How Does the ATCS Help?·Safer - The driller is freed from watching

hydraulic torque gages for the make up of eachconnection, thus letting him focus his attentionon the rig floor activities.

·Reduces trip time - Automatic application ofmakeup torque results in faster and optimum rigfloor rhythm of movement.

·Reduces pin and box damage - Impropertorque is the primary cause of swelled boxes,stretched pins, and galled threads and shoulders.

·Minimizes risk of fishing jobs - Impropermakeup torque causes washouts and twistoffs.

·Reduces rig downtime - By eliminating torque-related failures, you can avoid the expense oflaying down damaged pipe and tools, repair orreplacement, and loss of costly rig time.

Hydraulic Line Pull DevicesSometimes drilling rigs do not have catheads orhave catheads with insufficient capacity or simplydo not want to use them for the makeup of largerotary shouldered connections. In these cases, therig must rely on external devices to supply the linepull to the tongs. These devices take the form ofhydraulic cylinders and power sources.

Ezy-TorqT Hydraulic CatheadIn the 1960s Smith developed the Ezy-Torq hydrauliccathead for use on large connections that werebeyond the capacity of most rig air catheads. Its pri-mary function is to provide a line pull source for con-nections that require torques ranging from 40,000 to150,000 ft-lb. When you use the hydraulic catheadon connections requiring less than 40,000 ft-lb, youshould always calibrate the unit with a load cell.

The Ezy-Torq hydraulic cathead is available intwo different configurations:1. One which has its own self-contained power

source.2. One which uses an auxiliary power source

supplied by the user.For either source of power, the hydraulic

cylinder and cylinder installation/arrangement are the same.

52

Drill Collar

Recommended Minimum Makeup Torque (ft-lb) [See Note 2]

55Drill Collar


54

Size and Type OD Bore of Drill Collars (in.)of Connection (in.) (in.) 1 11/4 11/2 13/4

3...4 2,508† 2,508† 2,508†API NC 23 31/8 3,330† 3,330† 2,647

31/4 4,000 3,387 2,64733/4 2,241† 2,241† 1,749

23/8 Reg. 31/8 3,028† 2,574 1,74931/4 3,285 2,574 1,74933/4 3,797† 3,797† 2,926

27/8 PAC 31/8 4,966† 4,151 2,92631/4 5,206 4,151 2,926

23/8 IFAPI NC 26 31/2 4,606† 4,606† 3,69727/8 SH 33/4 5,501 4,668 3,697

31/2 3,838† 3,838† 3,838†27/8 Reg. 33/4 5,766 4,951 4,002

37/8 5,766 4,951 4,00227/8 XH 33/4 4,089† 4,089† 4,089†31/2 DSL 37/8 5,352† 5,352† 5,352†27/8 Mod. Open 41/8 8,059† 8,059† 7,43327/8 IF 37/8 4,640† 4,640† 4,640†API NC 31 41/8 7,390† 7,390† 7,390†31/2 SH 41/4 8,858† 8,858† 8,161

41/2 10,286 9,307 8,16141/8 6,466† 6,466† 6,466†

31/2 Reg. 41/4 7,886† 7,886† 7,886†41/2 10,471† 9,514 8,39441/2 9,038†

API NC 35 43/4 12,27353/4 12,27341/4 5,161†

31/2 XH 41/2 8,479†4 SH 43/4 12,074†31/2 Mod. Open 53/4 13,282

51/4 13,28243/4 9,986†

31/2 API IF 53/4 13,949†API NC 38 51/4 16,20741/2 SH 51/2 16,207

43/4 8,786†31/2 H-90 53/4 12,794†

51/4 17,094†51/2 18,52453/4 10,910†

4 FH 51/4 15,290†API NC 40 51/2 19,985†4 Mod. Open 53/4 20,53941/2 DSL 63/4 20,539

51/4

51/2

4 H-90 53/4

63/4

61/4

51/2

41/2 Reg. 53/4

63/4

61/4

53/4

API NC 44 63/4

61/4

61/2

51/2

53/4

41/2 API FH 63/4

61/4

61/2

41/2 XH 53/4

API NC 46 63/4

4 API IF 61/4

5 DSL 61/2

41/2 Mod. Open 63/4

53/4

63/4

41/2 H-90 61/4

61/2

63/4

61/4

5 H-90 61/2

63/4

73/4

63/4

51/2 H-90 73/4

71/4

71/2

63/4

51/2 Reg. 73/4

71/4

71/2

41/2 API IF 61/4

API NC 50 61/2

5 XH 63/4

5 Mod. Open 73/4

51/2 DSL 71/4

5 Semi-IF 71/2

Bore of Drill Collars (in.)2 21/4 21/2 213/16 3 31/4 31/2 33/4

4,640†6,8536,8536,8536,466† 5,6857,115 5,6857,115 5,6859,038† 9,038† 7,411

10,825 9,202 7,41110,825 9,202 7,4115,161† 5,161† 5,161†8,479† 8,479† 8,311

11,803 10,144 8,31111,803 10,144 8,31111,803 10,144 8,3119,986† 9,986† 9,986† 8,315

13,949† 12,907 10,977 8,31514,653 12,907 10,977 8,31514,653 12,907 10,977 8,3158,786† 8,786† 8,786† 8,786†

12,794† 12,794† 12,794† 10,41016,931 15,139 13,154 10,41016,931 15,139 13,154. 10,41010,910† 10,910† 10,910† 10,910†15,290† 15,290† 14,969 12,12518,886 17,028 14,969 12,12518,886 17,028 14,969 12,12518,886 17,028 14,969 12,12512,590† 12,590† 12,590† 12,590†17,401† 17,401† 17,401† 16,53922,531† 21,717 19,546 16,53923,674 21,717 19,546 16,53923,674 21,717 19,546 16,53915,576† 15,576† 15,576† 15,576†20,609† 20,609† 19,601 16,62923,686 21,749 19,601 16,62923,686 21,749 19,601 16,62920,895† 20,895† 20,895† 18,16125,509 23,493 21,257 18,16125,509 23,493 21,257 18,16125,509 23,493 21,257 18,16112,973† 12,973† 12,973† 12,973† 12,973†18,119† 18,119† 18,119† 18,119† 17,90023,605† 23,605† 23,028 19,920 17,90027,294 25,272 23,028 19,920 17,90027,294 25,272 23,028 19,920 17,900

17,738† 17,738† 17,738† 17,738†23,422† 23,422† 22,426 20,31128,021 25,676 22,426 20,31128,021 25,676 22,426 20,31128,021 25,676 22,426 20,31118,019† 18,019† 18,019† 18,019†23,681† 23,681† 23,159 21,05128,731 26,397 23,159 21,05128,731 26,397 23,159 21,05128,731 26,397 23,159 21,05125,360† 25,360† 25,360† 25,360†31,895† 31,895† 29,400 27,16735,292 32,825 29,400 27,16735,292 32,825 29,400 27,16734,508† 34,508† 34,508† 34,14241,993† 40,117 36,501 34,14242,719 40,117 36,501 34,14242,719 40,117 36,501 34,14231,941† 31,941† 31,941† 31,941†39,419† 39,419† 36,235 33,86842,481 39,866 36,235 33,86842,481 39,866 36,235 33,86823,003† 23,003† 23,003† 23,003† 23,003†29,679† 29,679† 29,679† 29,679† 26,67536,741† 35,824 32,277 29,965 26,67538,379 35,824 32,277 29,965 26,67538,379 35,824 32,277 29,965 26,67538,379 35,824 32,277 29,965 26,675

1. Basis of calculations for recommended makeup torque assumes the use of athread compound containing 40 to 60% by weight of finely powdered metalliczinc with not more than 0.3% total active sulfur, applied thoroughly to all

threads and shoulders. Also using the modified screw jack formula as shown inthe IADC Drilling Manual and the API Recommended Practice RP 7G. For APIconnections and their interchangeable connections, makeup torque is based on62,500 psi stress in the pin or box, whichever is weaker.

Recommended Minimum Makeup Torque (ft-lb) [See Note 2]Size and Type OD Bore of Drill Collars (in.)of Connection (in.) (in.) 1 11/4 11/2 13/4

7.....

51/2 API FH 71/4

71/2

73/4

71/4

API NC 56 71/2

73/4

85/8

71/2

65/8 Reg. 73/4

85/8

81/4

71/2

65/8 H-90 73/4

85/8

81/4

85/8

81/4

API NC 61 81/2

83/4

95/8

85/8

81/4

51/2 IF 81/2

83/4

95/8

91/4

81/2

83/4

65/8 API FH 95/8

91/4

91/2

95/8

91/4

API NC 70 91/2

93/4

105/8

101/4

105/8

101/4

API NC 77 101/2

103/4

115/8

Connections with Full Faces8*5/8

7 H-90 81/4*81/2*81/2*83/4*

75/8 API Reg. 9*5/8

91/4*91/2*9*5/8

75/8 H-90 91/4*91/2*

10*5/8

85/8 API Reg. 101/4*101/2*

85/8 H-90 101/4*101/2*

Connections with Low Torque Faces7 H-90 83/4

95/8

91/4

75/8 Reg. 91/2

93/4

105/8

93/4

75/8 H-90 105/8

101/4

101/2

103/4

85/8 Reg. 115/8

111/4

103/4

85/8 H-90 115/8

111/4

Drill Collar


57Drill Collar56

Bore of Drill Collars (in.)2 21/4 21/2 213/16 3 31/4 31/2 33/4

32,762† 32,762† 32,762† 32,762†40,998† 40,998† 40,998† 40,998†49,661† 47,756 45,190 41,53351,687 47,756 45,190 41,533

40,498† 40,498† 40,498† 40,498†49,060† 48,221 45,680 42,058

52,115 48,221 45,680 42,05852,115 48,221 45,680 42,058

46,399† 46,399† 46,399† 46,399†55,627† 53,346 50,704 46,93557,393 53,346 50,704 46,93557,393 53,346 50,704 46,935

46,509† 46,509† 46,509† 46,509†55,707† 55,707† 53,628 49,85560,321 56,273 53,628 49,85560,321 56,273 53,628 49,855

55,131† 55,131† 55,131† 55,131†65,438† 65,438† 65,438† 61,62472,670 68,398 65,607 61,62472,670 68,398 65,607 61,62472,670 68,398 65,607 61,624

56,641† 56,641† 56,641† 56,641† 56,641†67,133† 67,133† 67,133† 63,381 59,02774,625 70,277 67,436 63,381 59,02774,625 70,277 67,436 63,381 59,02774,625 70,277 67,436 63,381 59,02774,625 70,277 67,436 63,381 59,027

67,789† 67,789† 67,789† 67,789† 67,18479,544† 79,544† 76,706 72,102 67,18483,992 80,991 76,706 72,102 67,18483,992 80,991 76,706 72,102 67,18483,992 80,991 76,706 72,102 67,184

75,781† 75,781† 75,781† 75,781† 75,781†88,802† 88,802† 88,802† 88,802† 88,802†

102,354† 102,354† 101,107 96,214 90,984108,842 105,657 101,107 96,214 90,984108,842 105,657 101,107 96,214 90,984108,842 105,657 101,107 96,214 90,984

108,194† 108,194† 108,194† 108,194†124,051† 124,051† 124,051† 124,051†140,491† 140,488 135,119 129,375145,476 140,488 135,119 129,375145,476 140,488 135,119 129,375

Connections with Full Faces53,454† 53,454† 53,454† 53,454†63,738† 63,738† 63,738† 60,97072,066 69,265 65,267 60,970

60,402† 60,402† 60,402† 60,402†72,169† 72,169† 72,169† 72,169†84,442† 84,442† 79,536 74,52988,581 84,221 79,536 74,52988,581 84,221 79,536 74,529

73,017† 73,017† 73,017† 73,017†86,006† 86,006† 86,006† 86,006†99,508† 99,508† 99,508† 96,284

109,345† 109,345† 109,345† 109,345†125,263† 125,263† 125,263† 125,034141,134 136,146 130,777 125,034

113,482† 113,482† 113,482† 113,482†130,063† 130,063† 130,063† 130,063†

Connections with Low Torque Faces68,061† 68,061† 67,257 62,84574,235 71,361 67,257 62,845

73,099† 73,099† 73,099† 73,099†86,463† 86,463† 82,457 77,28991,789 87,292 82,457 77,28991,789 87,292 82,457 77,289

91,667† 91,667† 91,667† 91,667†106,260† 106,260† 104,166 98,799113,845 109,183 104,166 98,799113,845 109,183 104,166 98,799

112,887† 112,887† 112,887† 112,887†130,676† 130,676† 130,676† 130,676†147,616 142,429 136,846 130,87092,960† 92,960† 92,960† 92,960†

110,782† 110,782† 110,782† 110,782†129,203† 129,203† 129,203† 129,203†

2. Normal torque range — tabulated minimum value to 10% greater. Largest diametershown for each connection is the maximum recommended for that connection. Ifthe connections are used on drill collars larger than the maximum shown, increasethe torque values shown by 10% for a minimum value. In addition to the increasedminimum torque value, it is also recommended that a fishing neck be machined tothe maximum diameter shown.

3. H-90 connections makeup torque is based on 56,200 psi stress and other factorsas stated in Note 1.

4. The 27/8 in. PAC makeup torque is based on 87,500 psi stress and other factorsas stated in Note 1.

*5. Largest diameter shown is the maximum recommended for these full facedconnections. If larger diameters are used, machine connections with low torquefaces and use the torque values shown under low torque face tables. If lowtorque faces are not used, see Note 2 for increased torque values.

(†)6. Torque figures succeeded by a cross (†) indicate that the weaker member forthe corresponding OD and bore is the BOX. For all other torque values theweaker member is the PIN.

Drill Collar

Recommended Minimum Makeup Torque (kg-m) [See Note 2]

59Drill Collar


58

Size and Type OD Bore of Drill Collars (mm)of Connection (in.) (mm) 25.4 31.7 38.1 44.4

76.2 347† 347† 347†API NC 23 79.4 460† 460† 366

82.6 553 468 36676.2 310† 310† 242

23/8 Reg. 79.4 419† 356 24282.6 454 356 24276.2 525† 525† 405

27/8 PAC 79.4 687† 574 40582.6 720 574 405

23/8 IFAPI NC 26 88.9 637† 637† 51127/8 SH 95.2 761 645 511

88.9 531† 531† 531†27/8 Reg. 95.2 797 685 553

98.4 797 685 55327/8 XH 95.2 565† 565† 565†31/2 DSL 98.4 740† 740† 740†27/8 Mod. Open 104.8 1,114† 1,114† 1,02827/8 IF 98.4 641† 641† 641†API NC 31 104.8 1,022† 1,022† 1,022†31/2 SH 107.9 1,225† 1,225† 1,128

114.3 1,422 1,287 1,128104.8 894† 894† 894†

31/2 Reg. 107.9 1,090† 1,090† 1,090†114.3 1,448 1,315 1,160114.3 1,250†

API NC 35 120.6 1,697127.0 1,697107.9 714†

31/2 XH 114.3 1,172†4 SH 120.6 1,669†31/2 Mod. Open 127.0 1,836

133.3 1,83631/2 API IF 120.6 1,381†API NC 38 127.0 1,929†41/2 SH 133.3 2,241

139.7 2,241120.6 1,215†

31/2 H-90 127.0 1,769†133.3 2,363†139.7 2,561

4 FH 127.0 1,508†API NC 40 133.3 2,114†4 Mod. Open 139.7 2,763†41/2 DSL 146.0 2,840

152.4 2,840133.3139.7

4 H-90 146.0152.4168.7139.7

41/2 Reg. 146.0152.4158.7146.0

API NC 44 152.4158.7165.1139.7146.0

41/2 API FH 152.4158.7165.1

41/2 XH 146.0API NC 46 152.44 API IF 158.75 DSL 165.141/2 Mod. Open 171.4

146.0152.4

41/2 H-90 158.7165.1171.4158.7

5 H-90 165.1171.4177.8171.4

51/2 H-90 177.8184.1190.5171.4

51/2 Reg. 177.8184.1190.5

41/2 IF 158.7API NC 50 165.15 XH 171.45 Mod. Open 177.851/2 DSL 184.15 Semi-IF 190.5

Bore of Drill Collars (mm)50.8 57.1 63.5 71.4 76.2 82.5 88.9 95.2

641†947947947

894† 786984 786984 786

1,250† 1,250† 1,025†1,497 1,272 1,0251,497 1,272 1,025714† 714† 714†

1,172† 1,172† 1,1491,632 1,402 1,1491,632 1,402 1,1491,632 1,402 1,149

1,381† 1,381† 1,381† 1,1501,929† 1,785 1,518 1,1502,026 1,785 1,518 1,1502,026 1,785 1,518 1,150

1,215† 1,215† 1,215† 1,215†1,769† 1,769† 1,769† 1,4392,341 2,093 1,819 1,4392,341 2,093 1,819 1,439

1,508† 1,508† 1,508† 1,508†2,114† 2,114† 2,070 1,6762,611 2,354 2,070 1,6762,611 2,354 2,070 1,6762,611 2,354 2,070 1,676

1,741† 1,741† 1,741† 1,741†2,406† 2,406† 2,406† 2,2873,115† 3,003 2,702 2,2873,273 3,003 2,702 2,2873,273 3,003 2,702 2,287

2,153† 2,153† 2,153† 2,153†2,849† 2,849† 2,710 2,2993,275 3,007 2,710 2,2993,275 3,007 2,710 2,299

2,889† 2,889† 2,889† 2,5113,527 3,248 2,939 2,5113,527 3,248 2,939 2,5113,527 3,248 2,939 2,511

1,794† 1,794† 1,794† 1,794† 1,794†2,505† 2,505† 2,505† 2,505† 2,4753,264† 3,264† 3,184 2,754 2,4753,774 3,494 3,184 2,754 2,4753,774 3,494 3,184 2,754 2,475

2,452† 2,452† 2,452† 2,452†3,238† 3,238† 3,100 2,8083,874 3,550 3,100 2,8083,874 3,550 3,100 2,8083,874 3,550 3,100 2,808

2,491† 2,491† 2,491† 2,491†3,274† 3,274† 3,202 2,9103,972 3,650 3,202 2,9103,972 3,650 3,202 2,9103,972 3,650 3,202 2,910

3,506† 3,506† 3,506† 3,506†4,410† 4,410† 4,065 3,7564,879 4,538 4,065 3,7564,879 4,538 4,065 3,756

4,771† 4,771† 4,771† 4,7205,806† 5,546 5,046 4,7205,906 5,546 5,046 4,7205,906 5,546 5,046 4,720

4,416† 4,416† 4,416† 4,416†5,450† 5,450† 5,010 4,6825,873 5,512 5,010 4,6825,873 5,512 5,010 4,6823,180 3,180† 3,180† 3,180† 3,180†4,103 4,103† 4,103† 4,103† 3,6885,080 4,953 4,462 4,143 3,6885,306 4,953 4,462 4,143 3,6885,306 4,953 4,462 4,143 3,6885,306 4,953 4,462 4,143 3,688



Drill Collar


61Drill Collar


60


177.851/2 API FH 184.1

190.5196.8184.1

API NC 56 190.5196.8203.2190.5

65/8 Reg. 196.8203.2209.5190.5

65/8 H-90 196.8203.2209.5203.2209.5

API NC 61 215.9222.2228.6203.2209.5

51/2 IF 215.9222.2228.6234.9215.9222.2

65/8 API FH 228.6234.9241.3228.6234.9

API NC 70 241.3247.6254.0260.3254.0260.3

API NC 77 266.7273.0279.4

Connections with Full Faces203.2*

7 H-90 209.5*215.9*215.9*222.2*

75/8 API Reg. 228.6*234.9*241.3*228.6*

75/8 H-90 234.9*241.3*254.0*

85/8 API Reg. 260.3*266.7*

85/8 H-90 260.3*266.7*

Connections with Low Torque Faces7 H-90 222.2

228.6234.9

75/8 Reg. 241.3247.6254.0247.6

75/8 H-90 254.0260.3266.7273.0

85/8 Reg. 279.4285.7273.0

85/8 H-90 279.4285.7


4,530† 4,530† 4,530† 4,530†5,668† 5,668† 5,668† 5,668†6,866† 6,603 6,248 5,7427,146 6,603 6,248 5,742

5,599† 5,599† 5,599† 5,599†6,783† 6,667 6,316 5,8157,205 6,667 6,316 5,8157,205 6,667 6,316 5,815

6,415† 6,415† 6,415† 6,415†7,691† 7,375 7,010 6,4897,935 7,375 7,010 6,4897,935 7,375 7,010 6,489

6,430† 6,430† 6,430† 6,430†7,702† 7,702† 7,414 6,8938,340 7,780 7,414 6,8938,340 7,780 7,414 6,893

7,622† 7,622† 7,622† 7,622†9,047† 9,047† 9,047† 8,52010,047 9,456 9,070 8,52010,047 9,456 9,070 8,52010,047 9,456 9,070 8,5207,831† 7,831† 7,831† 7,831† 7,831†9,282† 9,282† 9,282† 8,763 8,16110,317 9,716 9,323 8,763 8,16110,317 9,716 9,323 8,763 8,16110,317 9,716 9,323 8,763 8,16110,317 9,716 9,323 8,763 8,161

9,372† 9,372† 9,372† 9,372† 9,28910,997† 10,997† 10,605 9,968 9,289

11,612 11,197 10,605 9,968 9,28911,612 11,197 10,605 9,968 9,28911,612 11,197 10,605 9,968 9,289

10,477† 10,477† 10,477† 10,477† 10,477†12,277† 12,277† 12,277† 12,277† 12,277†14,151† 14,151† 13,979 13,302 12,57915,048 14,608 13,979 13,302 12,57915,048 14,608 13,979 13,302 12,57915,048 14,608 13,979 13,302 12,579

14,958† 14,958† 14,958† 14,958†17,151† 17,151† 17,151† 17,151†19,424† 19,424† 18,681 17,887

20,113 19,423 18,681 17,88720,113 19,423 18,681 17,887


8,351† 8,351† 8,351† 8,351†9,978† 9,978† 9,978† 9,978†

11,675† 11,644 10,996 10,30412,247 11,644 10,996 10,30412,247 11,644 10,996 10,304

10,095† 10,095† 10,095† 10,095†11,891† 11,891† 11,891† 11,891†13,758† 13,758† 13,758† 13,31215,117† 15,117† 15,117† 15,117†17,318† 17,318† 17,318† 17,28719,512 18,823 18,081 17,287

15,689† 15,689† 15,689† 15,689†7,982† 17,982† 17,982† 17,982†


10,106† 10,106† 10,106† 10,106†11,954† 11,954† 11,400 10,68612,690 12,069 11,400 10,68612,690 12,069 11,400 10,686

12,673† 12,673† 12,673† 12,673†14,691† 14,691† 14,401 13,65915,740 15,095 14,401 13,65915,740 15,095 14,401 13,659

15,607† 15,607† 15,607† 15,607†18,067† 18,067† 18,067† 18,067†20,409 19,692 18,920 18,093

12,852† 12,852† 12,852† 12,852†15,316† 15,316† 15,316† 15,316†17,863† 17,863† 17,863† 17,863†






Drill Collar

Recommended Minimum Makeup Torque (N·m) [See Note 2]

63Drill Collar


62


76.2 3,400† 3,400† 3,400†API NC 23 79.4 4,514† 4,514† 3,589

82.5 5,423 4,592 3,58976.2 3,039† 3,039† 2,371

23/8 Reg. 79.4 4,105† 3,490 2,37182.5 4,454 3,490 2,37176.2 5,148† 5,148† 3,968

27/8 PAC 79.4 6,733† 5,629 3,96882.5 7,058 5,629 3,968

23/8 IFAPI NC 26 88.9 6,245† 6,245† 5,01327/8 SH 95.2 7,458 6,329 5,013

88.9 5,204† 5,204† 5,204†27/8 Reg. 95.2 7,817 6,713 5,426

98.4 7,817 6,713 5,42627/8 XH 95.2 5,544† 5,544† 5,544†31/2 DSL 98.4 7,256† 7,256† 7,256†27/8 Mod.Open 104.8 10,927† 10,927† 10,07727/8 IF 98.4 6,291† 6,291† 6,291†API NC 31 104.8 10,019† 10,019† 10,019†31/2 SH 107.9 12,010† 12,010† 11,065

114.3 13,946 12,619 11,065104.8 8,766† 8,766† 8,766†

31/2 Reg. 107.9 10,692† 10,692† 10,692†114.3 14,197 12,900 11,380114.3 12,255†

API NC 35 120.6 16,640127.0 16,640107.9 6,997†

31/2 XH 114.3 11,495†4 SH 120.6 16,370†31/2 Mod. Open 127.0 18,009

133.3 18,00931/2 API IF 120.6 13,540†API NC 38 127.0 18,913†41/2 SH 133.3 21,974

139.7 21,974120.6 11,912†

3 1/2 H-90 127.0 17,346†133.3 23,176†139.7 25,115

4 FH 127.0 14,793†API NC 40 133.3 20,731†4 Mod. Open 139.7 27,096†41/2 DSL 146.0 27,847

152.4 27,847133.3139.7

4 H-90 146.0152.4158.7139.7

41/2 Reg. 146.0152.4158.7146.0

API NC 44 152.4158.7165.1139.7146.0

41/2 API FH 152.4158.7165.1

41/2 XH 146.0API NC 46 152.44 API IF 158.75 DSL 165.141/2 Mod. Open 171.4

146.0152.4

41/2 H-90 158.7165.1171.4158.7

5 H-90 165.1171.4177.8171.4

51/2 H-90 177.8184.1190.5171.4

51/2 Reg. 177.8184.1190.5

41/2 API IF 158.7API NC 50 165.15 XH 171.45 Mod. Open 177.851/2 DSL 184.15 Semi-IF 190.5


6,291†9,2929,2929,292

8,766† 7,7089,646 7,7089,646 7,708

12,255† 12,255† 10,04814,677 12,477 10,04814,677 12,477 10,0486,997† 6,997† 6,997†

11,495† 11,495† 11,26816,003 13,753 11,26816,003 13,753 11,26816,003 13,753 11,268

13,540† 13,540† 13,540† 11,27418,913† 17,500 14,883 11,27419,867 17,500 14,883 11,2741,9867 17,500 14,883 11,274

11,912† 11,912† 11,912† 11,912†17,346† 17,346† 17,346† 14,11422,956 20,526 17,834 14,11422,956 20,526 17,834 14,114

14,793† 14,793† 14,793† 14,793†20,731† 20,731† 20,295 16,43925,607 23,086 20,295 16,43925,607 23,086 20,295 16,43925,607 23,086 20,295 16,439

17,070† 17,070† 17,070† 17,070†23,593† 23,593† 23,593† 22,42430,548† 29,445 26,501 22,42432,097 29,445 26,501 22,42432,097 29,445 26,501 22,42421,118† 21,118† 21,118† 21,118†27,943† 27,943† 26,575 22,546

32,113 29,487 26,575 22,54632,113 29,487 26,575 22,546

28,330† 28,330† 28,330† 24,62334,586 31,853 28,820 24,62334,586 31,853 28,820 24,62334,586 31,853 28,820 24,623

17,589† 17,589† 17,589† 17,589† 17,589†24,566† 24,566† 24,566† 24,566† 24,26932,004† 32,004† 31,222 27,008 24,26937,006 34,264 31,222 27,008 24,26937,006 34,264 31,222 27,008 24,269

24,049† 24,049† 24,049† 24,049†31,755† 31,755† 30,405 27,53837,991 34,811 30,405 27,53837,991 34,811 30,405 27,53837,991 34,811 30,405 27,538

24,431† 24,431† 24,431† 24,431†32,107† 32,107† 31,400 28,54138,955 35,790 31,400 28,54138,955 35,790 31,400 28,54138,955 35,790 31,400 28,541

34,383† 34,383† 34,383† 34,383†43,244† 43,244† 39,861 36,83347,849 44,504 39,861 36,83347,849 44,504 39,861 36,833

46,787† 46,787† 46,787† 46,29156,935† 54,391 49,489 46,29157,919 54,391 49,489 46,29157,919 54,391 49,489 46,291

43,306† 43,306† 43,306† 43,306†53,445† 53,445† 49,128 45,91857,597 54,051 49,128 45,91857,597 54,051 49,128 45,918

31,188† 31,188† 31,188† 31,188† 31,188†40,240† 40,240† 40,240† 40,240† 36,16749,814† 48,570 43,762 40,628 36,16752,035 48,570 43,762 40,628 36,16752,035 48,570 43,762 40,628 36,16752,035 48,570 43,762 40,628 36,167



Drill Collar


65Drill Collar


64


177.851/2 API FH 184.1

190.5196.8184.1

API NC 56 190.5196.8203.2190.5

65/8 Reg. 196.8203.2209.5190.5

65/8 H-90 196.8203.2209.5203.2209.5

API NC 61 215.9222.2228.6203.2209.5

51/2 IF 215.9222.2228.6234.9215.9222.2

65/8 API FH 228.6234.9241.3228.6234.9

API NC 70 241.3247.6254.0260.3254.0260.3

API NC 77 266.7273.0279.4

Connections with Full Faces203.2*

7 H-90 209.5*215.9*215.9*222.2*

75/8 API Reg. 228.6*234.9*241.3*228.6*

75/8 H-90 234.9*241.3*254.0*

85/8 API Reg. 260.3*266.7*

85/8 H-90 260.3*266.7*

Connections with Low Torque Faces7 H-90 222.2

228.6234.9

75/8 Reg. 241.3247.6254.0247.6

75/8 H-90 254.0260.3266.7273.0

85/8 Reg. 279.4285.7273.0

85/8 H-90 279.4285.7


44,419† 44,419† 44,419† 44,419†55,586† 55,586† 55,586† 55,586†67,331† 64,748 61,270 56,31170.078 64,748 61,270 56,311

54,908† 54,908† 54,908† 54,908†66,517† 65,379 61,934 57,02470,658 65,379 61,934 57,02470,658 65,379 61,934 57,024

62,909† 62,909† 62,909† 62,909†75,420† 72,327 68,745 63,63677,815 72,327 68,745 63,63677,815 72,327 68,745 63,636

63,057† 63,057† 63,057† 63,057†75,529† 75,529† 72,710 67,59481,785 76,296 72,710 67,59481,785 76,296 72,710 67,594

74,747† 74,747† 74,747† 74,747†88,722† 88,722† 88,722† 83,55198,527 92,735 88,951 83,55198,527 92,735 88,951 83,55198,527 92,735 88,951 83,551

76,795† 76,795† 76,795† 76,795† 76,795†91,021† 91,021† 91,021† 85,933 80,029101,178 95,283 91,431 85,933 80,029101,178 95,283 91,431 85,933 80,029101,178 95,283 91,431 85,933 80,029101,178 95,283 91,431 85,933 80,029

91,909† 91,909† 91,909† 91,909† 91,090107,848† 107,848† 104,000 97,757 91,090113,878 109,809 104,000 97,757 91,090113,878 109,809 104,000 97,757 91,090113,878 109,809 104,000 97,757 91,090

102,745† 102,745† 102,745† 102,745† 102,745†120,400† 120,400† 120,400† 120,400† 120,400†138,773† 138,773† 137,082 130,449 123,357147,569 143,251 137,082 130,449 123,357147,569 143,251 137,082 130,449 123,357147,569 143,251 137,082 130,449 123,357

146,692† 146,692† 146,692† 146,692†168,191† 168,191† 168,191† 168,191†190,480† 190,476 183,197 175,409197,239 190,476 183,197 175,409197,239 190,476 183,197 175,409


81,894† 81,894† 81,894† 81,894†97,848† 97,848† 97,848† 97,848†

114,489† 114,189 107,836 101,048120,099 114,189 107,836 101,048120,099 114,189 107,836 101,04898,997† 98,997† 98,997† 98,997†

116,609† 116,609† 116,609† 116,609†134,915† 134,915† 134,915† 130,544148,251† 148,251† 148,251† 148,251†169,834† 169,834† 169,834† 169,523191,352 184,589 177,310 169,523

153,860† 153,860† 153,860† 153,860†176,341† 176,341† 176,341† 176,341†


99,109† 99,109† 99,109† 99,109†117,228† 117,228† 111,796 104,789124,449 118,352 111,796 104,789124,449 118,352 111,796 104,789

124,284† 124,284† 124,284† 124,284†144,069† 144,069† 141,230 133,953154,354 148,033 141,230 133,953154,354 148,033 141,230 133,953

153,054† 153,054† 153,054† 153,054†177,174† 177,174† 177,174† 177,174†200,140 193,108 185,538 177,437

126,037† 126,037† 126,037† 126,037†150,200† 150,200† 150,200† 150,200†175,176† 175,176† 175,176† 175,176†






Drill Collar

Figure No. 49

Gall-Resistant CoatingA gall-resistant coating should be applied to allnewly cut threads and shoulders. This conditionsthe shiny threads and shoulders so that lubricantwill adhere to the surface.

Newly machined threads are bright and shinybefore being coated. The gall-resistant compound is usually a manganese or zinc phosphate coating,produced by immersing in a hot chemical solution,which gives the threads and shoulders a dark appear-ance (see Figure No. 50). Such a coating acts as a lubricant, separates the metal surfaces during theinitial makeup and assists in holding lubricant inplace under makeup loads.

Figure No. 50

67Drill Collar

KNOW FIELD SHOP WORKWhen it becomes necessary to repair drill collars infield shops, every effort should be made to rethreadthe drill collar with a joint equivalent to the manu-facturer’s new joint. Use only field shops that areequipped with high-quality, hardened-and-groundgages; with thread mills or lathes that use pre-formedthreading inserts, cold rolling equipment andchemical coating baths.

Use the following checklist to ensure that afield shop’s repair work is of high quality.

StraightnessCollars should be inspected by supporting neareach end and checking for run-out. As a rule ofthumb, collars with more than 1/4 in. (6 mm) run-out should be straightened.

ThreadingThreads should be gaged with high-quality, hard-ened-and-ground gages. Thread form, lead andtaper should be inspected, using approved gages.Thread roots should be free from sharp notches(see page 97 for oilfield thread forms).

Cold WorkingThread roots should be cold worked in accordancewith procedures established for rolling or peening.Threads must be gaged for standoff prior to cold working.

Cold working should be completed prior to cut-ting stress-relief contours so the last scratch of therun-out or imperfect thread root can be cold worked.

Facts About Cold WorkingDrill collar joint life can be improved by prestress-ing the thread roots of drill collar joints by coldworking. Cold working is done with a hydraulicram which forces a roller into the thread root (seeFigure No. 49). The roller is then moved down thethread spiral. Cold worked metal surfaces havegreater resistance to fatigue failure. After threadrolling is completed, the fibers in the thread rootsremain in compression and can withstand higherbending loads without cracking in fatigue.

Note: For comments related to the effect of cold working and gage standoff, refer to APISpecification No. 7.

66

Load

After rolling, these fibersremain in compression

Drill Collar

Slip and Elevator RecessesSlip and elevator recesses are designed to cut drill collar han-dling time by eliminating lift subs and safety clamps. Extreme care is taken in machining smooth radii, free of tool marks. Added fatigue life is obtained by cold rolling the radii at the upper shoulder with a specially designed cold rolling tool. Slip and elevator recessesmay be used together or sepa-rately (see Figure No. 53).

Figure No. 53

Low Torque FacesTo prevent shoulder separation, the compressivestress created by the makeup torque must be of sucha magnitude that the shoulders remain togetherunder all downhole conditions. On large diameterdrill collars the shoulder can become so wide thatthe makeup torque required for an adequate com-pressive stress can not be obtained.

Low torque faces are used to achieve an increasein the compressive shoulder stress at the shoulderbevel when a connection smaller than optimumis used on large drill collars.

The low torque face feature was designed toaccommodate the problem of reducing the area ofthe total shoulder face without creating a notcheffect that would occur if a larger bevel is used.

Instead of increasing bevel size to decrease the shoulder face area; the counterbore of the box is machined to a larger diameter to reduce the compressive box section at the shoulder.

The low torque feature cannot create a balanceof fatigue life between the pin and box, nor can itincrease the shoulder load holding the connectiontogether.

It should be noted that the term “Low TorqueFeature” does not mean that less makeup torquewill be required when the feature is used on a particular connection on a given size collar.

69Drill Collar

Stress Relief ContoursThe API relief groove pin and the API Bore Backbox remove unengaged threads in highly stressedareas of the drill collar joint (see Figure No. 51).This provides a more flexible joint, less likely tocrack in fatigue, because bending in the jointoccurs in areas of smooth relief surfaces.

Figure No. 51

SPECIAL DRILL COLLAR FEATURES

Spiral Drill CollarsThe purpose of the spiral drill collar is to prevent differential sticking (see page 27). The reduction of wall contact between the drill collars and the wall of the hole greatly reduces the chances of the collars becoming wall stuck.

The box end is left uncut for a distance of no less than 18 in. (457 mm) and no more than 24 in. (610 mm) below the shoulder.

The pin end is left uncut for a distance of no less than 12 in. (305 mm) and no more than 22 in. (559 mm) above the shoulder.

Note: The weight of a round drill collar will be reduced approximately 4% by spiraling.

Figure No. 52

68

Smooth surfaces and radii, free of tool marks, permit higher bendingloads without fatigue cracking. Serial numbers must not be stamped inrelief grooves.

Large radii reduce stressconcentrations.

Coldwork

Last scratch of box threadcovered by pin; no threadroots exposed to corrosivedrilling fluid.

Drill Collar

Example:If a drill collar string weight is 79,000 lb in air,

how much will it weigh in 12 lb/gal mud?

Buoyed drill collar weight = Drill collar weight x

correction factor= 79,000 lb x .817= 64,543 lb

Example:If a drill collar string weight is 35,830 kg in air,

how much will it weigh in 1.44 g/cc mud?

Buoyed drill collar weight = Drill collar weight x

correction factor= 35,834 kg x .817= 29,276 kg

DRILL PIPE — DRILL COLLAR SAFETY FACTORDrill pipe will be subjected to serious damage ifrun in compression. To make sure the drill pipe isalways in tension, the top 10 to 15% of the drillcollar string must also be in tension. This will putthe change over from tension to compression, orneutral zone, down in the stiff drill collar stringwhere it is desirable and can be tolerated. A 10%Safety Factor (SF) should be written as 1.10, 15%as 1.15, etc.

From the above buoyancy effect example, themaximum weight available to run on the bit would be:

Buoyed weightMaximum bit weight available =

1.15 (15% SF)

= 64,543 lb1.15

= 56,124 lb

Buoyed weightMaximum bit weight available=

1.15 (15% SF)

= 29,276 kg1.15

= 25,457 kg

Bit weight x SFDrill collar air weight =

BFIn soft formations with little or no bouncing,

or when running a vibration dampener, a 10%safety factor will probably be sufficient. In areasof hard and rough drilling it may be desirable toincrease this safety factor to 25% (1.25).

71Drill Collar

Figure No. 54 is a comparison of the shoulderwidths of a connection with and without a lowtorque feature.

Figure No. 54

BUOYANCY EFFECT OFDRILL COLLARS IN MUDAll picked up drill collar weight is not available toload the bit in fluid drilled holes due to the buoy-ancy effect.

Buoyancy Factors

Mud lb/galBF = 1 –

65.5

Buoyancy FactorsTo find the corrected or buoyed drill collar weight,use the above Buoyancy Correction Factor for themud weight to be used.

70

g/cc BuoyancyMud Weight or Correction

(lb/gal) (lb/ft3) sp gr Factor8.34 62.3 1.00 .873

9 67.3 1.08 .862

10 74.8 1.20 .847

11 82.3 1.32 .832

12 89.8 1.44 .817

13 97.2 1.56 .801

14 104.7 1.68 .786

15 112.2 1.80 .771

16 119.7 1.92 .755

17 127.2 2.04 .740

18 134.6 2.16 .725

19 142.1 2.28 .710

20 149.6 2.40 .694

21 157.1 2.52 .679

22 164.6 2.64 .664

23 172.1 2.76 .649

24 179.5 2.88 .633

Drill Collar 73Drill Collar72

Drill Collar Weights (lb/ft)

Drill Bore of Drill Collar (in.)

CollarOD

(in.) 1 11/8 11/4 11/2 13/4 2 21/4 21/2 213/16 3 31/4

31/2 21 21

31/8 23 23 22 21

31/4 26 25 24 22

33/8 26 24 22

31/2 29 27 25

33/4 33 32 29

37/8 36 34 32 30 27

41/2 37 35 32 29

41/8 39 37 35 32

41/4 42 40 38 35

41/2 48 46 43 41

43/4 54 52 50 47 44

51/2 61 59 56 53 50

51/4 68 65 63 60 57 53

51/2 75 73 70 67 64 60 57

53/4 83 80 78 75 72 67 64

61/2 90 88 85 83 79 75 72 68

61/4 98 96 94 91 88 83 80 76

61/2 107 105 102 99 96 92 88 85

63/4 116 114 111 108 105 101 98 94

71/2 125 123 120 117 114 110 107 103

71/4 134 132 130 127 124 119 116 112

71/2 144 142 140 137 134 129 126 122

73/4 154 152 150 147 144 139 136 132

81/2 165 163 160 157 154 150 147 143

81/4 176 174 171 168 165 161 158 154

81/2 187 185 182 179 176 172 169 165

83/4 198 196 194 191 188 183 180 176

91/2 208 206 203 200 195 192 188

91/4 220 218 215 212 207 204 200

91/2 233 230 228 224 220 217 213

93/4 246 243 240 237 233 230 226

101/2 256 254 250 246 243 239

101/4 270 267 264 259 257 252

101/2 284 281 278 273 270 266

103/4 298 295 292 287 285 280

111/2 306 302 299 295

111/4 321 317 314 310

111/2 336 332 329 325

113/4 352 348 345 340

121/2 368 363 361 356

1,000 lb of steel will displace .364 bbl65.5 lb of steel will displace 1 gal7.84 kg of steel will displace 1 liter490 lb of steel will displace 1 ft3

2,747 lb of steel will displace 1 bbl

Weight of 31 ft Drill Collar (lb)

Drill Bore of Drill Collar (in.)

CollarOD

(in.) 1 11/8 11/4 11/2 13/4 2 21/4 21/2 213/16 3 31/4

31/2 662.2 640.2

31/8 725.5 703.6 679.0 622.1

31/4 791.5 769.5 744.9 688.0

33/8 813.5 756.6 689.3

31/2 884.6 827.7 760.5

33/4 1,034.6 977.7 910.5

37/8 1,113.5 1,056.6 989.4 911.8 823.8

41/2 1,138.1 1,070.9 993.3 905.3

41/8 1,222.2 1,154.9 1,077.3 989.4

41/4 1,308.8 1,241.6 1,164.0 1,076.0

41/2 1,489.9 1,422.6 1,345.0 1,257.1

43/4 1,681.3 1,614.0 1,536.4 1,448.5 1,350.2

51/2 1,883.0 1,815.8 1,738.2 1,650.3 1,552.0

51/4 2,095.2 2,027.9 1,950.3 1,862.4 1,764.1 1,626.7

51/2 2,317.6 2,250.3 2,172.7 2,084.8 1,986.5 1,849.1 1,758.9

53/4 2,550.4 2,483.1 2,405.5 2,317.6 2,219.3 2,081.9 1,991.7

61/2 2,793.5 2,726.3 2,648.7 2,560.7 2,462.4 2,325.0 2,234.8 2,105.5

61/4 3,047.0 2,979.8 2,902.2 2,814.2 2,715.9 2,578.5 2,488.3 2,359.0

61/2 3,310.9 3,243.6 3,166.0 3,078.1 2,979.8 2,842.4 2,752.1 2,622.8

63/4 3,585.0 3,517.8 3,440.2 3,352.2 3,253.9 3,116.5 3,026.3 2,897.0

71/2 3,869.6 3,802.3 3,724.7 3,636.8 3,538.5 3,401.1 3,310.9 3,181.5

71/4 4,164.4 4,097.2 4,019.6 3,931.6 3,833.3 3,695.9 3,605.7 3,476.4

71/2 4,469.7 4,402.4 4,324.8 4,236.9 4,138.6 4,001.2 3,910.9 3,781.6

73/4 4,785.2 4,718.0 4,640.4 4,552.4 4,454.1 4,316.7 4,226.5 4,097.2

81/2 5,111.1 5,043.9 4,966.3 4,878.3 4,780.0 4,642.6 4,552.4 4,423.1

81/4 5,447.4 5,380.1 5,302.5 5,214.6 5,116.3 4,978.9 4,888.7 4,759.4

81/2 5,794.0 5,726.7 5,649.1 5,561.2 5,462.9 5,325.5 5,235.3 5,106.0

83/4 6,150.9 6,083.7 6,006.1 5,918.2 5,819.9 5,682.4 5,592.2 5,462.9

91/2 6,451.0 6,373.4 6,285.4 6,187.2 6,049.7 5,959.5 5,830.2

91/4 6,628.6 6,751.0 6,663.1 6,564.8 6,427.4 6,337.2 6,207.9

91/2 7,216.6 7,139.0 7,051.1 6,952.8 6,815.4 6,725.2 6,595.8

93/4 7,615.0 7,537.4 7,449.4 7,351.1 7,213.7 7,123.5 6,994.2

101/2 7,946.1 7,858.1 7,759.8 7,622.4 7,532.2 7,402.9

101/4 8,365.1 8,277.1 8,178.8 8,041.4 7,951.2 7,821.9

101/2 8,794.5 8,706.5 8,608.2 8,470.8 8,380.6 8,251.3

103/4 9,234.2 9,146.2 9,047.9 8,910.5 8,820.3 8,691.0

111/2 9,498.0 9,360.6 9,270.4 9,141.1

111/4 9,958.4 9,821.0 9,730.8 9,601.5

111/2 10,429.2 10,291.8 10,201.6 10,072.2

113/4 10,910.3 10,772.9 10,682.7 10,553.3

121/2 11,401.8 11,264.3 11,174.1 11,044.8

1,000 lb of steel will displace .364 bbl65.5 lb of steel will displace 1 gal7.84 kg of steel will displace 1 liter490 lb of steel will displace 1 ft3

2,747 lb of steel will displace 1 bbl


Drill Collar Weights (kg/m)

Drill Bore of Drill Collar in. (mm)Collar

OD in. 1 11/8 11/4 11/2 13/4 2 21/4 21/2 213/16 3 31/4

(mm) (25.40) (28.57) (31.75) (38.10) (44.45) (50.80) (57.15) (63.50) (71.44) (76.20) (82.55)31/2

(76.20) 32 3131/8

(79.37) 35 34 33 3031/4

(82.55) 38 37 36 3333/8

(85.72) 39 36 3331/2

(88.90) 43 40 3733/4

(95.25) 50 47 4437/8

(98.42) 54 51 48 44 4041/2

(101.60) 55 51 48 4441/8

(104.77) 59 55 52 4841/4

(107.95) 63 60 56 5241/2

(114.30) 72 68 65 6043/4

(120.65) 81 78 74 70 6551/2

(127.00) 90 87 83 79 7551/4

(133.35) 101 97 94 89 85 7851/2

(139.70) 111 108 104 100 95 89 8453/4

(146.05) 122 119 116 111 107 100 9661/2

(152.40) 134 131 127 123 118 112 107 10161/4

(158.75) 146 143 139 135 130 124 120 11361/2

(165.10) 159 156 152 148 143 136 132 12663/4

(171.45) 172 169 165 161 156 150 145 13971/2

(177.80) 186 183 179 175 170 163 159 15371/4

(184.15) 200 197 193 189 184 177 173 16771/2

(190.50) 215 211 208 203 199 192 188 18273/4

(196.85) 230 227 223 219 214 207 203 19781/2

(203.20) 245 242 238 234 230 223 219 2128 1/4

(209.55) 262 258 255 250 246 239 235 22981/2

(215.90) 278 275 271 267 262 256 251 24583/4

(222.25) 295 292 288 284 279 273 269 26291/2

(228.60) 310 306 302 297 290 286 28091/4

(234.95) 328 324 320 315 309 304 29891/2

(241.30) 346 343 339 334 327 323 31793/4

(247.65) 366 362 358 353 346 342 336101/2

(254.00) 382 377 373 366 362 355101/4

(260.35) 402 397 393 386 382 376101/2

(266.70) 422 418 413 407 403 396103/4

(273.05) 443 439 434 428 423 417111/2

(279.40) 456 449 445 439111/4

(285.75) 478 472 467 461111/2

(292.10) 501 494 490 484113/4

(298.45) 524 517 513 507121/2

(304.80) 547 541 536 530

Weight of 9.4 m Drill Collar (kg)

1,000 lb of steel will displace .364 bbl; 65.5 lb of steel will displace 1 gal; 7.84 kg of steel will displace 1 liter; 490 lb ofsteel will displace 1 ft3; 2,747 lb of steel will displace 1 bbl

Drill Bore of Drill Collar in. (mm)Collar

OD in. 1 11/8 11/4 11/2 13/4 2 21/4 21/2 213/16 3 31/4

(mm) (25.40) (28.57) (31.75) (38.10) (44.45) (50.80) (57.15) (63.50) (71.44) (76.20) (82.55)31/2

(76.20) 298.8 288.931/8

(79.37) 327.4 317.5 306.4 280.731/4

(82.55) 357.2 347.2 336.2 310.533/8

(85.72) 367.1 341.4 311.131/2

(88.90) 399.2 373.5 343.233/4

(95.25) 466.9 441.2 410.937/8

(98.42) 502.5 476.8 446.5 411.4 371.841/2

(101.60) 513.6 483.2 448.2 408.541/8

(104.77) 551.5 521.2 486.1 446.54 1/4

(107.95) 590.6 560.3 525.2 485.641/2

(114.30) 672.3 642.0 606.9 567.343/4

(120.65) 758.7 728.3 693.3 653.6 609.351/2

(127.00) 849.7 819.4 784.4 744.7 700.351/4

(133.35) 945.4 915.1 880.1 840.4 796.0 734.051/2

(139.70) 1,045.8 1,015.5 980.4 940.8 896.4 834.4 793.75 3/4

(146.05) 1,150.9 1,120.5 1,085.5 1,045.8 1,001.5 939.5 898.761/2

(152.40) 1,260.6 1,230.2 1,195.2 1,155.5 1,111.2 1,049.2 1,008.5 950.161/4

(158.75) 1,375.0 1,344.6 1,309.6 1,269.9 1,225.6 1,163.6 1,122.8 1,064.561/2

(165.10) 1,494.0 1,463.7 1,428.7 1,389.0 1,344.6 1,282.6 1,241.9 1,183.563/4

(171.45) 1,617.7 1,587.4 1,552.4 1,512.7 1,468.3 1,406.3 1,365.6 1,307.371/2

(177.80) 1,746.1 1,715.8 1,680.8 1,641.1 1,596.7 1,534.7 1,494.0 1,435.771/4

(184.15) 1,879.2 1,848.8 1,813.8 1,774.1 1,729.8 1,667.8 1,627.1 1,568.771/2

(190.50) 2,016.9 1,986.6 1,951.6 1,911.9 1,867.5 1,805.5 1,764.8 1,706.473/4

(196.85) 2,159.3 2,129.0 2,094.0 2,054.3 2,009.9 1,947.9 1,907.2 1,848.881/2

(203.20) 2,306.4 2,276.0 2,241.0 2,201.3 2,157.0 2,095.0 2,054.3 1,995.981/4

(209.55) 2,458.1 2,427.8 2,392.8 2,353.1 2,308.7 2,246.7 2,206.0 2,147.781/2

(215.90) 2,614.5 2,584.2 2,549.2 2,509.5 2,465.1 2,403.1 2,362.4 2,304.183/4

(222.25) 2,775.6 2,745.3 2,710.2 2,670.6 2,626.2 2,564.2 2,523.5 2,465.191/2

(228.60) 2,911.0 2,876.0 2,836.3 2,791.9 2,729.9 2,689.2 2,630.991/4

(234.95) 3,081.4 3,046.4 3,006.7 2,962.4 2,900.3 2,859.6 2,801.391/2

(241.30) 3,256.5 3,221.5 3,181.8 3,137.4 3,075.4 3,034.7 2,976.493/4

(247.65) 3,436.2 3,401.2 3,361.5 3,317.2 3,255.2 3,214.5 3,156.1101/2

(254.00) 3,585.6 3,546.0 3,501.6 3,439.6 3,398.9 3,340.5101/4

(260.35) 3,774.7 3,735.0 3,690.7 3,628.7 3,588.0 3,529.6101/2

(266.70) 3,968.5 3,928.8 3,884.4 3,822.4 3,781.7 3,723.4103/4

(273.05) 4,166.9 4,127.2 4,082.9 4,020.9 3,980.2 3,921.8111/2

(279.40) 4,286.0 4,223.9 4,183.2 4,124.9111/4

(285.75) 4,493.7 4,431.7 4,391.0 4,332.6111/2

(292.10) 4,706.2 4,644.1 4,603.4 4,545.1113/4

(298.45) 4,923.2 4,861.2 4,820.5 4,762.2121/2

(304.80) 5,145.0 5,083.0 5,042.3 4,983.9


IF YOU HAVE AN EPIDEMIC OF DRILL COLLARFAILURES THAT YOU CAN’T EXPLAIN:First, get a copy of Smith’s Publication No. 39, “Howto Drill a Usable Hole” which was compiled from aseries of articles published in World Oil magazine.This brochure of pictures and examples explainscontrolling of hole deviation, the reasons holesbecome crooked and the problems that can result. Ifyou would like a copy of this brochure, we will beglad to send you one. Just indicate the publicationnumber and address your request to:

Smith Services — Drilco GroupProduct ManagementP.O. Box 60068Houston, Texas 77205-0068

Second, to solve a drill collar problem, call yourarea Smith representative. This person has beentrained in the care and maintenance of drill collars.Also, you can call anyone with Smith for informa-tion to help find a solution to such problems. Afterall, helping customers solve drill collar problems isthe way our company started.

Suppose you need help right now! Call Smithand tell our telephone operator “I have a drill collarproblem and I want to talk with someone who canhelp me.”

If you have time, write a letter giving us all thefacts.* We will answer promptly. Smith is inter-ested in your drill collar problems, both solvingthem and helping to prevent them in the future.

*Smith Services Product ManagementP.O. Box 60068Houston, Texas 77205-0068

When writing or calling about a drill collarproblem, please specify:1. Connection size and type, relief features,

and length.2. OD and ID of drill collars.3. Torque applied.4. Length of tongs.5. Type of torque indicator.6. Service time of connections.7. Location of failure (pin or box).8. Type of thread compound.9. Drilling conditions.

PREVENTING PIN AND BOX FAILURES INDOWNHOLE TOOLSThe first rotary shouldered connection (pin bybox) was used in drilling in 1909. It’s simple andrugged and nobody has designed anything basi-cally better, since. However, it is subject to fatiguefailures if it’s asked to work beyond its endurancelimit, or if a few simple rules are not followed inits manufacture and use.

We’ve written detailed booklets on care and useof drill collars. You can have one by writing to us,as suggested on the following page. However, ifyou’ll follow a few simple rules, listed below, andbriefly detailed on the following pages, you canstay out of trouble.

Rule — Use Correct Makeup TorqueOur experience indicates that perhaps 80% or moreof all premature connection failures are due toincorrect makeup torque (see pages 37 through 65).

Rule — Use Proper Thread CompoundA good grade of drill collar compound containspowdered metallic zinc in the amount of 40 to 60%by weight (see page 38).

Rule — Proper Tong PositionPosition tongs 8 in. (203 mm) below the box shoul-der. Torque indicator should be located in snub line90° to tong arm (see pages 42 through 50).

Rule — Use Systematic InspectionFatigue is an accumulative and progressive thing.Cracks ordinarily exist a long time before ultimatefailure, and can be detected by proper inspectionmethods (see pages 143 and 152).

Rule — Require Best Joint Design and ProcessingMuch has been learned about how joint designand machining methods affect fatigue resistance(stress level) (see pages 37 through 70).

Rule — Get Factory Quality From Field ShopsTo the extent possible, require the same machiningand processing used by drill collar manufacturers(see page 66).

Rule — Treat Tools Like Machinery, Not Pipe!Guard pins and boxes from damage and lubricatethem properly. They’ll give lots of trouble-free service!


3. The third best group of connections are thosethat lie in the unshaded section of the charts onthe right. The nearer the connection lies to thereference line, the more desirable is its selection.

Example:Suppose you want to select the best connec-

tion for 93/4 in. (247.7 mm) x 213/16 in. (71.4 mm)ID drill collars.

Referring to the following chart (see Figure No. 55).

Figure No. 55

For average conditions, you should select inthis order of preference:1. Best = NC 70 (shaded area and nearest

reference line).2. Second best = 75/8 in. Reg. (low torque) (light

area to left and nearest to reference line).3. Third best = 75/8 in. H-90 (light area to right

and nearest to reference line).But in extremely abrasive and/or corrosive

conditions, you might want to select in this orderof preference:1. Best = 75/8 in. Reg. (low torque) =

strongest box†.2. Second best = NC 70 = second strongest box.3. Third best = 75/8 in. H-90 = weakest box.

† The connection furthest to the left on the chart has thestrongest box. This connection should be considered as possible first choices for very abrasive formations or corrosive conditions.

Reference line

2nd choice

1st choice

3rd choice

75/8 H-90

75/8 Reg.(Low torque)†

65/8 FH

NC 70

10

93/4

91/2O

D (

in.)

213/16 in. ID

GUIDES FOR EVALUATING DRILL COLLAR OD,ID AND CONNECTION COMBINATIONSThe BSR (Bending Strength Ratio) is used in thefollowing charts as a basis for evaluating compati-bility of drill collar OD, ID and connection combi-nations. The BSR is a number descriptive of therelative capacity of the pin and box to resist bend-ing fatigue failures. It is generally accepted that aBSR of 2.50:1 is the right number for the averagebalanced connection, when drilling conditions are average.

If you study the BSR ratios in the API RP 7G, youwill realize that very few of the ODs and IDs com-monly used on drill collars result in a BSR of 2.50:1exactly, so the following charts were prepared usingthe following guidelines:1. For small drill collars 6 in. (152.4 mm) OD and

below, try to avoid BSRs above 2.75:1 or below2.25:1.

2. For high rpm, soft formations and when drill col-lar OD is small compared to hole size (example: 8 in. (203.2 mm) OD in 121/4 in. (311.2 mm) hole,6 in. (152.4 mm) OD in 81/4 in. (209.6 mm)hole), avoid BSRs above 2.85:1 or below 2.25:1.

3. For hard formations, low rpm and when drillcollar OD is close to hole size (example: 10 in.(254.0 mm) OD in 121/4 in. (311.2 mm) hole, 81/4 in. (209.6 mm) OD in 97/8 in. (250.8 mm)hole), avoid BSRs above 3.20:1 or below 2.25:1.However, when low torque features (see page 69)are used on large drill collars, BSRs as large as3.40:1 will perform satisfactorily.

4. For very abrasive conditions where loss of OD issevere, favor combinations of 2.50:1 to 3.00:1.

5. For extremely corrosive environments, favorcombinations of 2.50:1 to 3.00:1.81

How to Use the Connection Selection Charts on Pages 80through 95.The charts appearing on pages 80 to 95 were pre-pared with the BSR guidelines as reference.1. The best group of connections are defined as

those that appear in the shaded sections of thecharts. Also the nearer the connection lies to thereference line, the more desirable is its selection.

2. The second best group of connections are thosethat lie in the unshaded section of the charts onthe left. The nearer the connection lies to thereference line, the more desirable is its selection.


13/4 in. ID

2.75

2.252.

50

53/4

51/2

51/4

53/4

43/4

41/2

41/4

43/4

33/4

31/2

31/4

33/4

23/4

21/2

21/4

OD

(in

.)

NC 38

31/2 XH

NC 35

NC 3131/2 Reg.

31/2 PAC

27/8 XH

27/8 Reg.

27/8 PAC

23/8 PAC

Reference line

NC 26

11/2 in. ID

2.75

2.252.

50

63/4

53/4

51/2

51/4

53/4

43/4

41/2

41/4

43/4

33/4

31/2

31/4

33/4

23/4

21/2

OD

(in

.)

NC 38

31/2 XH

NC 35

NC 3131/2 Reg.

31/2 PAC

27/8 XH

27/8 Reg.

27/8 PAC

23/8 Reg.

23/8 PAC

Reference line

NC 26


21/4 in. ID

2.75

2.25

2.50

3.00

73/4

71/2

71/4

73/4

63/4

61/2

61/4

63/4

53/4

51/2

51/4

53/4

43/4

41/2

41/4

OD

(in

.)

51/2 FH

NC 56

51/2 Reg.

NC 50

NC 46

31/2 XH

NC 44

NC 35

Reference line

NC 40

NC 38

2 in. ID

2.75

2.25

2.50

3.00

61/2

61/4

63/4

53/4

51/2

51/4

53/4

43/4

41/2

41/4

43/4

33/4

31/2

31/4

33/4

OD

(in

.)

NC 46

NC 44

NC 40

NC 38

31/2 XH

31/2 Reg.

31/2 PAC

NC 35

27/8 XH

NC 26

Reference line

NC 31


21/2 in. ID

2.75

2.25

2.50

3.00

73/4

63/4

61/2

61/4

63/4

53/4

51/2

51/4

53/4

43/4

41/2

41/4

43/4

OD

(in

.)

51/2 Reg.

NC 50

NC 46

NC 44

NC 40

31/2 XH

NC 38

NC 35

Reference line

21/2 in. ID

2.75

2.25

2.50

3.00

93/4

91/2

91/4

93/4

83/4

81/2

81/4

83/4

73/4

71/2

71/4

73/4

OD

(in

.)

NC 70

75/8 Reg.*

65/8 FH

65/8 H-90

65/8 Reg.

51/2 IF

51/2 FH

5 1/2 Reg.

NC

50

NC 56

7 H-90*

NC 61

Reference line

* On ODs where these connections are noted by a dotted line, theymust be machined with a low torque face for proper makeup. (Seepage 69 for explanation of low torque face.)

10


213/16 in. ID

2.75

2.25

2.50

3.00

81/4

83/4

73/4

71/2

71/4

73/4

63/4

61/2

61/4

63/4

53/4

51/2

51/4

OD

(in

.)

NC 61

65/8 H-90

65/8 Reg.

51/2 FH

51/2 Reg.

NC 50

NC 56

NC 46

NC 44

Reference line

213/16 in. ID

2.75

2.25

2.50

3.00

111/2

111/4

113/4

103/4

101/2

101/4

10

93/4

91/2

91/4

93/4

83/4

81/2

81/4

OD

(in

.)

85/8 H-90*

NC 7785/8 Reg.*

75/8 H-90*

75/8 Reg.*

65/8 FH

51/2 IF

7 H-90*NC

61

6 5/8 H-90

6 5/8 Reg.

NC 70

Reference line



3 in. ID

2.75

2.25

2.50

3.00

81/2

81/4

83/4

73/4

71/2

71/4

73/4

63/4

61/2

61/4

63/4

53/4

51/2

OD

(in

.)

51/2 IF

7 H-90

NC 61

65/8 H-90

65/8 Reg.

51/2 FH

51/2 Reg.

NC 50

NC 56

NC 46

NC 44

Reference line

3 in. ID

2.75

2.25

2.50

3.00

113/4

111/2

111/4

113/4

103/4

101/2

101/4

10

93/4

91/2

91/4

93/4

83/4

81/2

OD

(in

.)

85/8 H-90*

NC 7785/8 Reg.*

75/8 H-90*

75/8 Reg.*

65/8 FH

5 1/2 IF

7 H-90*

NC

61

NC 70

Reference line




31/4 in. ID

2.75

2.25

2.50

3.00

83/4

81/2

81/4

83/4

73/4

71/2

71/4

73/4

63/4

61/2

61/4

63/4

53/4

51/2

OD

(in

.)

51/2 IF

7 H-90*

NC 61

65/8 H-90

65/8 Reg.

51/2 FH

51/2 Reg.

NC 50

NC 56

NC 46

Reference line

31/4 in. ID

2.75

2.25

2.50

3.00

123/4

113/4

111/2

111/4

113/4

103/4

101/2

101/4

10

93/4

91/2

91/4

93/4

83/4

OD

(in

.)

85/8 H-90*

NC 7785/8 Reg.*

65/8 IF

75/8 H-90*

75/8 Reg.*

65/8 FH

5 1/2 IF

7 H-90*

NC

61

NC 70

Reference line




31/2 in. ID

2.75

2.25

2.50

3.00

83/4

81/2

81/4

83/4

73/4

71/2

71/4

73/4

63/4

61/2

61/4

OD

(in

.)

51/2 IF7 H-90*

NC 61

65/8 H-90

65/8 FH

65/8 Reg.

51/2 FH

51/2 Reg.

NC 50

NC 56

Reference line

31/2 in. ID

2.75

2.25

2.50

3.00

113/4

111/2

111/4

113/4

103/4

101/2

101/4

10

93/4

91/2

91/4

93/4

83/4

OD

(in

.)

85/8 H-90*

NC 7785/8 Reg.*

65/8 IF

75/8 H-90*

75/8 Reg.*

6 5/8 FH

5 1/2 IF

7 H-90*

NC

61

NC 70

Reference line


Drill Collar 95

31/2 H-90 to 51/2 H-90 Selection Charts

2.75

2.25

2.50

3.00

61/2

61/4

63/4

53/4

51/2

51/4

OD

(in

.)

ID (

in.)

21/42

21/2213/16

ID (

in.)

53/4

51/2

51/4

53/4

43/4

OD

(in

.)

21/4

2

21/2

Reference line

Caution: The use of the 90° thread form on drill collar sizes less than71/2 in. OD may result in hoop stresses high enough to cause swelledboxes. For this reason the API 60° thread form is preferred over theabove sizes of the 90° thread form.

H-90 Thread 60° Thread

In order to produce the same shoulder load (L) — see illustration — on connections of the same size but with different threads (H-90 and60°), the makeup torque must produce a greater force (F90) for an H-90 thread than for a 60° thread (F60). This means the torquerequirement is greater for the H-90 thread than the 60° thread, if theconnections are equal size. When the makeup torque produces thesame shoulder load on both connections, then the force on the H-90box (F swell) is greater than the force on the 60° box (F swell). Thisresults in high hoop stresses in boxes with H-90 threads.

31/2 H-90

4 H-90

Drill Collar94

31/2 H-90 to 51/2 H-90 Selection Charts

2.75

2.25

2.50

3.00

73/4

71/2

71/4

73/4

63/4

61/2

OD

(in

.)

ID (

in.)

ID (

in.)

21/4

31/431/2

31/2

21/2213/16

3

71/4

73/4

63/4

61/2

61/4

63/4

OD

(in

.)

21/4

31/4

21/2213/16

3

ID (

in.)

73/4

63/4

61/2

61/4

63/4

53/4

51/2

OD

(in

.)

21/42

31/4

21/2

213/16

3

Reference line

51/2 H-90

41/2 H-90

5 H-90

Drill Collar96 Drill Collar 97

OILFIELD THREAD FORMSThe following thread forms are used on practicallyall oilfield rotary shouldered connections. Only the 60° thread form is an API thread. The ModifiedV-0.065 (not shown) has been replaced and is interchangeable with the API V-0.038R.

V-0.038R2 in. Taper Per Foot (TPF) on Diameter

4 Threads Per In. (TPI)

Thread profile gage must be marked: V-0.038, 4 TPI, 2 in. TPF

Used with:API NC 23, 26, 31, 35, 38, 40, 44, 46 and 50 API IF 23/8, 27/8, 31/2, 4, 41/2, 51/2 and 65/8 in.API FH 4 in.XH 27/8 and 31/2 in.

Figure No. 56

V-0.038R3 in. Taper Per Foot (TPF) on Diameter



Used with:API NC 56, 61, 70 and 77

Figure No. 57

Rotary Shouldered Connection Interchange ListCommon Name Pin Base Same As or

Size Diameter Threads Taper Thread InterchangesStyle (in.) (tapered) per In. (in./ft) Form* With (in.)

23/8 2.876 4 2 V-0.065 27/8 SH(V-0.038 rad) NC 26**

27/8 3.391 4 2 V-0.065 31/2 SH(V-0.038 rad) NC 31**

Internal 31/2 4.016 4 2 V-0.065 41/2 SHFlush (V-0.038 rad) NC 38**(IF) 4 4.834 4 2 V-0.065 41/2 XH

(V-0.038 rad) NC 46**

41/2 5.250 4 2 V-0.065 5 XH(V-0.038 rad) NC 50**

51/2 DSL

FullHole 4 4.280 4 2 V-0.065 41/2 DSL(FH) (V-0.038 rad) NC 40**

27/8 3.327 4 2 V-0.065 31/2 DSL(V-0.038 rad)

31/2 3.812 4 2 V-0.065 4 SH

Extra (V-0.038 rad) 41/2 EF

Hole 41/2 4.834 4 2 V-0.065 4 IF(XH) (V-0.038 rad) NC 46**(EH) 5 5.250 4 2 V-0.065 41/2 IF

(V-0.038 rad) NC 50**51/2 DSL

27/8 2.876 4 2 V-0.065 23/8 IF(V-0.038 rad) NC 26**

31/2 3.391 4 2 V-0.065 27/8 IF

Slim (V-0.038 rad) NC 31**

Hole 4 3.812 4 2 V-0.065 31/2 XH(SH) (V-0.038 rad) 41/2 EF

41/2 4.016 4 2 V-0.065 31/2 IF(V-0.038 rad) NC 38**

31/2 3.327 4 2 V-0.065 27/8 XH

Double (V-0.038 rad)

Stream- 41/2 4.280 4 2 V-0.065 4 FHline (V-0.038 rad) NC 40**(DSL) 51/2 5.250 4 2 V-0.065 41/2 IF

(V-0.038 rad) 5 XHNC 50**

26 2.876 4 2 V-0.038 rad 23/8 IF27/8 SH

31 3.391 4 2 V-0.038 rad 27/8 IF31/2 SH

38 4.016 4 2 V-0.038 rad 31/2 IF

Num. 41/2 SH

Conn. 40 4.280 4 2 V-0.038 rad 4 FH(NC) 41/2 DSL

46 4.834 4 2 V-0.038 rad 4 IF41/2 XH

50 5.250 4 2 V-0.038 rad 41/2 IF5 XH51/2 DSL

External 41/2 3.812 4 2 V-0.065 4 SHFlush (V-0.038 rad) 31/2 XH(EF)

** Connections with two thread forms shown may bemachined with either thread form without affecting gaging or interchangeability.

** Numbered Connections (NC) may be machined only with the V-0.038 radius thread form.

Drill Collar 99

H-902 in. Taper Per Foot (TPF) on Diameter

31/2 Threads Per In. (TPI)

Thread profile gage must be marked: H-90, 31/2 TPI, 2 in. TPF

Used with:H-90, 31/2, 4, 41/2, 5, 51/2 and 65/8 in.

Figure No. 61

H-903 in. Taper Per Foot (TPF) on Diameter

31/2 Threads Per In. (TPI)

Thread profile gage must be marked: H-90, 31/2 TPI, 3 in. TPF

Used with:H-90, 7, 75/8 and 85/8 in.

Figure No. 62

Drill Collar98

V-0.0403 in. Taper Per Foot (TPF) on Diameter



Used with:API Reg. 23/8, 27/8, 31/2 and 41/2 in.API FH 31/2 and 41/2 in.

Figure No. 58




Used with:API Reg. 65/8 in.API FH 51/2 and 65/8 in.

Figure No. 59




Used with:API Reg. 51/2, 75/8 and 85/8 in.

Figure No. 60

Drill Collar 101

Dimensional Identification of Pin Connections (Not for Machining Purposes)

To flank of first full depth thread (max.) (H-90 and 27/8 in. XH = 3/8 in.; PAC = 1/4 in.)

Pinlength

Pin enddiameter Pin cylindrical

diameter

1/2 in.

Connection Taper Pin Pin End Pin Cyl. Pin BaseSize Threads per Foot Length Diameter Diameter Diameter(in.) per In. (in.) (in.) (in.) (in.) (in.)

†23/8 PAC 4 11/2 21/4 25/64 25/16 23/8

†27/8 PAC 4 11/2 21/4 21/4 231/64 217/32

†NC 23 4 2 27/8 25/64 229/64 29/16

†23/8 Reg. 5 3 27/8 129/32 233/64 25/8

†23/8 IF 4 2 27/8 225/64 249/64 27/8

†27/8 Reg. 5 3 33/8 25/32 257/64 3†27/8 XH, EH 4 2 37/8 211/16 37/32 321/64

†27/8 IF 4 2 33/8 253/64 39/32 325/64

†31/2 Reg. 5 3 35/8 219/32 325/64 31/2

†NC 35 4 2 35/8 29/64 35/8 347/64

†31/2 XH, EH 4 2 33/8 31/4 345/64 313/16

†31/2 FH 5 3 35/8 33/32 357/64 4†31/2 IF 4 2 37/8 33/8 329/32 41/64

†31/2 H-90 31/2 2 37/8 331/64 315/16 41/8

†4 FH 4 2 43/8 39/16 411/64 49/32

†4 H-90 31/2 2 41/8 313/16 45/16 41/2

†NC 44 4 2 43/8 357/64 433/64 45/8

†41/2 Reg. 5 3 41/8 319/32 433/64 45/8

†41/2 FH 5 3 37/8 353/64 411/16 451/64

†41/2 H-90 31/2 2 43/8 47/64 441/64 453/64

†41/2 XH, EH 4 2 43/8 47/64 423/32 453/64

†5 H-90 31/2 2 45/8 421/64 459/64 57/64

†41/2 IF 4 2 43/8 433/64 59/64 51/4

†51/2 H-90 31/2 2 45/8 439/64 53/16 53/8

†51/2 Reg. 4 3 45/8 423/64 513/32 533/64

†51/2 FH 4 2 47/8 51/64 523/32 553/64

†NC 56 4 3 47/8 421/64 523/32 57/8

†65/8 Reg. 4 2 47/8 511/64 57/8 6†65/8 H-90 31/2 2 47/8 53/16 513/16 6†51/2 IF 4 2 47/8 537/64 69/32 625/64

†NC 61 4 3 53/8 53/32 69/32 67/16

†7 H-90 31/2 3 53/8 55/32 65/16 61/2

†65/8 FH 4 2 47/8 515/16 641/64 63/4

†75/8 Reg. 4 3 51/8 523/32 657/64 7†NC 70 4 3 57/8 527/32 75/32 75/16

†75/8 H-90 31/2 3 6 557/64 713/64 725/64

†65/8 IF 4 2 47/8 641/64 711/32 729/64

†85/8 Reg. 4 3 51/4 641/64 727/32 761/64

†NC 77 4 3 63/8 613/32 727/32 8†85/8 H-90 31/2 3 61/2 641/64 85/64 817/64

Low Torque Face

†See page 96 for interchangeable connections.*See page 69 for low torque face details.

Pin base diameter

Drill Collar100

Dimensional Identification of Box Connections (Not for Machining Purposes)

Depth of counterbore = 5/8 in.Except PAC = 3/8 in.

Diameter ofcounterbore

To flank of firstfull depththread (min)

Full DiameterConnection Threads Taper Depth of the

Size per per Thread Counterbore(in.) In. In. (in.) (in.)

†23/8 PAC 4 11/2 21/2 213/32

†27/8 PAC 4 11/2 21/2 219/32

†NC 23 4 2 31/8 25/8

†23/8 Reg. 5 3 31/8 211/16

†23/8 IF 4 2 31/8 215/16

†27/8 Reg. 5 3 35/8 31/16

†27/8 XH, EH 4 2 41/8 323/64

†27/8 IF 4 2 35/8 329/64

†31/2 Reg. 5 3 37/8 39/16

†NC 35 4 2 37/8 313/16

†31/2 XH, EH 4 2 35/8 37/8

†31/2 FH 5 3 37/8 43/64

†31/2 IF 4 2 41/8 45/64

†31/2 H-90 31/2 2 41/8 43/16

†4 FH 4 2 45/8 411/32

†4 H-90 31/2 2 43/8 49/16

†NC 44 4 2 45/8 411/16

†41/2 Reg. 5 3 43/8 411/16

†41/2 FH 5 3 41/8 47/8

†41/2 H-90 31/2 2 45/8 457/64

†41/2 XH, EH 4 2 45/8 429/32

†5 H-90 31/2 2 47/8 511/64

†41/2 IF 4 2 45/8 55/16

†51/2 H-90 31/2 2 47/8 57/16

†51/2 Reg. 4 3 47/8 537/64

†51/2 FH 4 2 51/8 529/32

†NC 56 4 3 51/8 515/16

†65/8 Reg. 4 2 51/8 61/16

†65/8 H-90 31/2 2 51/8 61/16

†51/2 IF 4 2 51/8 629/64

†NC 61 4 3 55/8 61/2

†7 H-90 31/2 3 55/8 69/16

†65/8 FH 4 2 51/8 627/32

†75/8 Reg. 4 3 53/8 73/32

†NC 70 4 3 61/8 73/8

†75/8 H-90 31/2 3 61/4 729/64

†65/8 IF 4 2 51/8 733/64

†85/8 Reg. 4 3 51/2 83/64

†NC 77 4 3 65/8 81/16

†85/8 H-90 31/2 3 63/4 821/64

30°

7 H-90 31/2 3 55/8 *71/8

75/8 Reg. 4 3 53/8 *73/4

85/8 Reg. 4 3 51/2 *975/8 H-90 31/2 3 61/4 *885/8 H-90 31/2 3 63/4 *93/8

†See page 96 for interchangeable connections.

Dimensional Identification for Low Torque Modification

HEVI-WATET

DRILL PIPE5SECTION FIVE

Drill Collar102

MATERIAL AND WELDING PRECAUTIONS FORDOWNHOLE TOOLSGenerally, the materials used in the manufacture ofdownhole tools (stabilizers, vibration dampeners,reamers, subs, drill collars, kellys and tool joints) areAISI 4137 H, 4140 H or 4145 H. These materials arepurchased by Smith with customized chemistries toassure that they will have the hardenability neces-sary to heat treat to desired mechanical properties for each product.

By customizing chemistries and in-house heattreatment of these materials to a specification suit-able for each product or product component,strength levels are assured to (1) minimize swelledboxes and stretched pins, (2) prolong fatigue life,(3) retard crack propagation rates, and (4) supporttensile loads.

All of the above mentioned products are manu-factured by Smith using these types of materialwhich are alloy materials in the heat treated state.They cannot be welded in the field without metal-lurgical change to the welded area. Any metallurgi-cal change induced by welding in the field willreduce the benefits of customizing purchases andin-house heat treatment described in the paragraphabove. Preheat procedures can be used to preventcracking while welding and post-heat procedurescan be used to recondition sections where weldinghas been performed; but, it should be emphasizedthat field welded sections can only be reconditionedand cannot be restored to their original state, free ofmetallurgical change.

Hevi-Wate Drill Pipe 105

WHAT IS HEVI-WATE DRILL PIPE?Smith’s Hevi-Wate drill pipe is an intermediate-weight drill stem member. It consists of heavy-walltubes attached to special extra-length tool joints. It has drill pipe dimensions for ease of handling.Because of its weight and construction, Hevi-Watedrill pipe can be run in compression the same asdrill collars in small diameter holes and in highlydeviated and horizontal wells.

Although special lengths are available, the pipeis normally furnished in 301/2 ft (9.3 m) lengthsin six sizes from 31/2 to 65/8 in. (88.9 to 168.3 mm)OD. One outstanding feature is the integral centerwear pad which protects the tube from abrasivewear. This wear pad acts as a stabilizer and is afactor in the overall stiffness and rigidity of one ormore joints of Hevi-Wate drill pipe.

An example of Hevi-Wate drill pipe as an intermediate-weight drill stem member follows:

Example:An approximate weight of 41/2 in. OD drill pipe

is 16.60 lb/ft; 41/2 in. Hevi-Wate drill pipe weighsapproximately 41 lb/ft. As another comparison, 61/2 in. OD, 21/4 in. ID drill collars weigh 100lb/ft.

Example:An approximate weight of 114.3 mm OD drill

pipe is 24.7 kg/m; 114.3 mm Hevi-Wate drill pipeweighs approximately 61.1 kg/m. As another com-parison, 165.1 mm OD, 57.2 mm ID drill collarsweigh 148.8 kg/m.

When a number of drill collars are used indirectional drilling, they produce a great amountof contact area with the low side of the hole. Asthe collars are rotated, this high friction contactwith the hole wall causes the collars to climb theside of the wall. Many people feel this rotationclimbing action of the bottom collar causes thebit to turn hole direction to the right.

Hevi-Wate drill pipe provides stability andmuch less wall contact. This results in the direc-tional driller being able to “lock-in” and bettercontrol both hole angle and direction.


Figure No. 64

USING HEVI-WATE DRILL PIPE IN THETRANSITION ZONE BETWEEN THE DRILL COLLARSAND THE DRILL PIPEMany drill pipe failures occur in the drill stembecause of fatigue damage previously accumulatedwhen the failed joint of pipe was run directly abovethe drill collars. This accelerated fatigue damage isattributed to the bending stress concentration in thelimber drill pipe rotating next to the stiff drill collars.

Two factors that cause extreme bending stressconcentration in the bottom joint of drill pipe are:1. Cyclic torsional whipping that moves down

through the rotating drill pipe into the stiff drill collars.

2. Side to side movement, as well as the verticalbounce and vibrations of the drill collars, that aretransmitted up to the bottom joint of drill pipe.

Stands back in the rack like regular drill pipe.

Wear pad reduces the wear on center section of drill pipe.

Hevi-Wate Drill Pipe106

Using Hevi-Wate Drill Pipe for Bit Weight on Small RigsHevi-Wate drill pipe, run in compression for bitweight, can reduce the hook load of the drill stem,making it ideal for smaller rigs drilling deeper holes.In shallow drilling areas, where regular drill pipe isrun in compression, the more rigid Hevi-Wate drillpipe will allow more bit weight to be run with lesslikelihood of fatigue damage.

Hevi-Wate drill pipe should not be used for bit weight in vertical holes larger than those listed below:·5 in. Hevi-Wate pipe — maximum vertical

hole 101/16 in.·41/2 in. Hevi-Wate pipe — maximum vertical

hole 91/16 in.·4 in. Hevi-Wate pipe — maximum vertical

hole 81/8 in.·31/2 in. Hevi-Wate pipe — maximum vertical

hole 7 in.The ease in handling saves both rig time and

trip time (see Figure Nos. 63 and 64). A long stringof Hevi-Wate drill pipe will eliminate many of theproblems associated with drill collars normallyused on the smaller rigs.

Figure No. 63

Requires only drill pipe elevators to handle on the rig.

No safety clamp is requiredand regular drill pipe slips are used.


Figure No. 65

(18 joints or more)Hevi-Wate drill pipe

Integral blade stabilizer

Drill collar

Short drill collar

Additional drill collars

IB Stabilizer(Integral Blade)

Hydra-shock®


When drill pipe is subjected to compressivebuckling these stress concentrations are muchmore severe. Many drillers periodically move thebottom joint of drill pipe to a location higher up inthe drill pipe string. Moving these joints to otherdrill string locations does not remove the cumula-tive fatigue damage that has been done, and mayor may not prolong the time until failure will occur.

Hevi-Wate drill pipe is an intermediate-weightdrill stem member, with a tube wall approximately1 in. (25.4 mm) thick. This compares to approxi-mately 3/8 in. (9.5 mm) wall thickness for regulardrill pipe and approximately 2 in. (50.8 mm) wallthickness for drill collars. Hevi-Wate drill pipe pro-vides a graduated change in stiffness between thelimber drill pipe above and the rigid drill collarsbelow. This graduated change in stiffness reducesthe likelihood of drill pipe fatigue failures whenHevi-Wate drill pipe is run in the critical transition“zone of destruction.” Performance records com-piled during the past few years show that runningHevi-Wate drill pipe above the drill collars definitelyreduces drill pipe fatigue failures. Hevi-Wate drillpipe’s heavy-wall design, long tool joints and longcenter upset section resist the high-stress concentra-tion and center body OD wear which causes failuresin regular drill pipe. Because of its construction,Hevi-Wate drill pipe can be inspected by the sametechnique used to prevent drill collar failures.

The number of joints of pipe that should be run in the transition zone is important. Based onsuccessful field experience, a minimum of 18 to 21 joints of Hevi-Wate drill pipe are recommendedbetween the drill collars and the regular drill pipein vertical holes. Thirty (30) or more joints arecommonly used in directional holes.

Near bitStabilizer

3-Point Borroxreamer


Hevi_WateDrill pipe

Spiral drill collar

IB stabilizer(Integral Blade)

Hydra-Shock®

Figure No. 66

IB stabilizer

Near bit IB stabilizer


USING HEVI-WATE DRILL PIPE IN DIRECTIONALDRILLINGExcessive drill collar connection failures resultfrom collars bending as they rotate throughdoglegs and hole angle changes.

Drill collars lay to the low side of high-angleholes. This results in:· Increased rotary torque.· Increased possibility of differential sticking.· Increased vertical drag.·Excessive wall friction that creates rolling action

and affects directional control.Rotating big, stiff collars through doglegs,

developed in directional drilling, can cause veryhigh-rotating torque and excessive bending loadsat the threaded connections.

Hevi-Wate drill pipe bends primarily in thetube. This reduces the likelihood of tool jointfatigue failures occurring in the Hevi-Wate drillpipe as it rotates through doglegs and hole anglechanges.

Hevi-Wate drill pipe design offers less wallcontact area between the pipe and hole wallwhich results in:· Less rotary torque.· Less chance of differential sticking.· Less vertical drag.· Better directional control.


Dimensional Data Range III

See page 123 for metric conversions.

TAPERED DRILL STRINGSThe ratios of I/C or section moduli between drillcollars and Hevi-Wate drill pipe or drill pipe shouldbe considered to prevent fatigue damage to thesemembers. Experience has indicated that these mem-bers perform best when this ratio is less than 5.5.Tapered drill collar strings are often necessary tomaintain an acceptable ratio.

The chart on the next page is based on main-taining an acceptable I/C ratio between Hevi-Watedrill pipe and the drill collars directly below.

Example of chart use for 41/2 in. (114.3 mm)Hevi-Wate drill pipe:

1. For Directional Holesa. Enter chart from bottom at 41/2 in. (114.3 mm)

Hevi-Wate drill pipe and proceed upward tothe “suggested upper limit for directionalholes” curve. Read to the left the maximumdrill collar size.

b. Suggested maximum drill collar size = 73/4

in. (196.9 mm) OD x standard bore.

2. For Straight Holesa. Enter chart from bottom at 41/2 in. (114.3 mm)

Hevi-Wate drill pipe and proceed upward tothe “suggested upper limit for straight holes”curve. Read to the left the maximum drill collar size.

b. Suggested maximum drill collar size = 71/4

in. (184.2 mm) OD x standard bore.

Tube MechanicalProperties

Nominal Tube TubeDimension Section

Wall Tor-Nom. Thick- Center Elevator Tensile sionalSize ID ness Area Upset Upset Yield Yield(in.) (in.) (in.) (in2) (in.) (in.) (lb) (ft-lb)

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

Tool Joint Approx.Weight

[IncludingMechanical Tube & Properties Joints (lb)]

Nom. Connection Tensile Torsional MakeupSize Size OD ID Yield Yield Wt/ Wt/Jt. Torque(in.) (in.) (in.) (in.) (lb) (ft-lb) ft 30 ft (ft-lb)

41/2 NC 46 (4 IF) 61/4 27/8 1,024,500 38,800 39.9 1,750 21,800

5 NC 50 (41/2 IF) 65/8 31/16 1,266,000 51,375 48.5 2,130 29,200


Capacity and Displacement Table — Hevi-Wate Drill Pipe

Capacity — The volume of fluid necessary to fillthe ID of the Hevi-Wate drill pipe.Displacement — The volume of fluid displacedby the Hevi-Wate drill pipe run in open ended(metal displacement only).

Dimensional Data Range II

Capacity Displacement

Nominal Gal BBL Gal BBL Gal BBL Gal BBLSize per per per per per per per per(in.) Joint*Joint* 100 ft 100 ft Joint*Joint* 100 ft 100 ft

31/2xxx 6.36 .151 21.2 .505 10.44 .248 34.78 .828

4 8.21 .195 27.4 .652 13.40 .319 44.66 1.063

41/2 9.48 .226 31.6 .753 18.34 .437 61.12 1.455

5 11.23 .267 37.5 .892 22.46 .535 74.87 1.783

51/2 14.26 .340 47.5 1.132 25.92 .617 86.41 2.057

65/8 25.01 .596 83.4 1.985 32.17 .766 107.24 2.553

*Capacity and displacement per joint numbers are based on 30 ft shoulder to shoulder joints.

xxWith 21/4 in. ID.

Tube MechanicalProperties

Nominal Tube TubeDimension Section

Wall Tor-Nom. Thick- Center Elevator Tensile sionalSize ID ness Area Upset Upset Yield Yield(in.) (in.) (in.) (in2) (in.) (in.) (lb) (ft-lb)

31/2 21/4 .625 5.645 4 35/8 310,475 18,460

4 29/16 .719 7.410 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

51/2 33/8 1.063 14.812 6 511/16 814,660 74,140

65/8 41/2 1.063 18.567 71/8 63/4 1,021,185 118,845

Tool Joint Approx.Weight

[IncludingMechanical Tube & Properties Joints (lb)]

Nom. Connection Tensile Torsional MakeupSize Size OD ID Yield Yield Wt/ Wt/ Torque(in.) (in.) (in.) (in.) (lb) (ft-lb) ft Jt. (ft-lb)

31/2 NC 38 (31/2 IF) 43/4 23/8 675,045 17,575 23.4 721 10,000

4 NC 40 (4 FH) 51/4 211/16 711,475 23,525 29.9 920 13,300

41/2 NC 46 (4 IF) 61/4 27/8 1,024,500 38,800 41.1 1,265 21,800

5 NC 50 (41/2 IF) 65/8 31/16 1,266,000 51,375 50.1 1,543 29,200

51/2 51/2 FH 7 31/2 1,349,365 53,080 57.8 1,770 32,800

65/8 65/8 FH 8 45/8 1,490,495 73,215 71.3 2,193 45,800

See page 123 for metric conversions.

TOOL JOINTS6SECTION SIX


3. For Severe Drilling Conditions (Corrosive Environmentand/or Hard Formations)a. Enter chart from bottom at 41/2 in. (114.3 mm)

Hevi-Wate drill pipe and proceed upward tothe “suggested upper limit for severe condi-tions” curve. Read to the left the maximumdrill collar size.

b. Suggested maximum drill collar size = 61/2 in.(165.1 mm) OD x standard bore.

Note: Caution should be exercised not to selectdrill collar ODs above the suggested upperlimits for each condition. Fatigue failuresare more likely if these limits are exceeded.If drill collars larger than the maximumsuggested size are to be used, run at leastthree drill collars of the maximum sug-gested size (or smaller) between the largerdrill collars and the Hevi-Wate drill pipe.

Suggested upper limit for directional holes

Suggested upper limit for straight holes

81/4

81/2

73/4

71/2

71/4

71/263/4

61/2

61/461/2

51/2Suggested upper limit

for severe drilling conditions

31/2 4 41/2 5Hevi-Wate drill pipe size (in.)

Dril

l col

lar

OD

(in

.)

Tool Joints 117

TOOL JOINTSOne of the primary purposes of drill pipe is to trans-mit drilling torque from the rotary table drive bush-ing and kelly to the drilling bit at the bottom of thehole. It also provides a means whereby fluid may becirculated for lubricating and cooling the bit and forthe removal of cuttings from the wellbore.

Drill pipe connections require different treat-ment than drill collar connections. Drill pipe tooljoints are much stiffer and stronger than the tubeand seldom experience bending fatigue damage inthe connection. Therefore, tool joint connectionsare normally selected based on torsional strengthof the pin connection and tube and not on bendingstrength ratios as in drill collar connections.

Drill collar connections differ in that they are asacrificial element and can never be made as strongas the drill collar body. The repair is also different.A drill collar connection can be renewed by cuttingoff the old connection and completely remachininga new one; whereas a drill pipe connection can onlybe reworked by chasing the threads and refacingthe shoulder because of its short length. The mostcommon damage occurring to drill pipe tool jointsis caused by leaking fluid, careless handling, threadwear or galling, and swelled boxes due to outsidediameter wear.

As with drill collars, the break-in of new drill pipetool joints is extremely important for long life. Newlymachined surfaces are more susceptible to gallinguntil they become work hardened. Therefore, theconnections should be chemically etched by a gall-resistant coating (see page 67) to hold the threadcompound and protect the newly machined surfaceson the initial makeup. Extra care is essential toensure long and trouble-free service. Thread protec-tors should be used while drill pipe is being pickedup, laid down, moved or stored.

Be sure to thoroughly clean all threads andshoulders of any foreign material or protectivecoating and inspect for damage before the firstmakeup. If kerosene, diesel or other liquid is used,allow sufficient drying time before applying threadcompound to the connections. When applyingthread compound, be sure to cover thoroughly theentire surface of the threads and shoulders of both

Tool Joints 119

RECOMMENDED PRACTICE FOR MARKINGON TOOL JOINTS FOR IDENTIFICATION OF DRILLSTRING COMPONENTS

Company, Month Welded, Year Welded, Pipe Manufacturer and Drill Pipe Grade Symbols to be Stencilled at Base of Pin. Sample Markings:

1 — Company 2 — Month welded

9 = September3 — Year welded

99 = 19994 — Pipe manufacturers

V = Vallourec5 — Drill pipe grade

E = Grade E drill pipe

Month Year1 through 12 Last two digits of year

Pipe Manufacturers (Pipe Mills or Processors) SymbolsPipe Mill SymbolActiveAlgoma ........................................................... XBritish Steel Seamless Tubes LTD ..................... BDalmine S.P.A. ................................................ DFalck ............................................................... FKawasaki ........................................................ HNippon ............................................................. INKK ................................................................ KMannesmann ................................................. MReynolds Aluminum ...................................... RASumitomo ........................................................ SSiderca .......................................................... SDTAMSA ............................................................ TU.S. Steel ........................................................ NVallourec ......................................................... VUsed ............................................................... UInactiveArmco ............................................................. A American Seamless ........................................ AI B & W ............................................................ W C F & I ............................................................ C J & L Steel ........................................................ J Lone Star ......................................................... L Ohio ............................................................... O Republic .......................................................... R TI .................................................................... Z

1 2 3 4 5D 9 99 V E

Tool Joints118

pin and box connections. It is preferable to use agood grade of zinc thread compound that containsno more than 0.3% sulfur. (A thread compoundcontaining 40 to 60% by weight of finely powderedmetallic zinc is recommended in API RP 7G.)

Proper initial makeup is probably the mostimportant factor effecting the life of the tool jointconnections. Here are some recommendations to follow:1. Proper makeup torque is determined by the

connection type, size, OD and ID, and may befound in torque tables (see pages 130 and 131).

2. Make up connections slowly, preferably usingchain tongs. (High-speed kelly spinners or thespinning chain used on initial makeup cancause galling of the threads.)

3. Tong them up to the predetermined torque usinga properly working torque gage to measure therequired line pull (see page 41).

4. Stagger breaks on each trip so that each con-nection can be checked, redoped and made upevery second or third trip, depending on thelength of drill pipe and size of rig.A new string of drill pipe deserves good surface

handling equipment and tools. Check slips and mas-ter bushings before damage occurs to the tube (seethe IADC Drilling Manual for correct measurement).

Do not stop the downward movement of thedrill string with the slips. This can cause crushingor necking down of the drill pipe tube. The drillpipe can also be damaged by allowing the slips toride the pipe on trips out of the hole.

Good rig practices will help eliminate time con-suming trips in the future, looking for washouts or fishing for drill pipe lost in the hole. For moreinformation refer to the IADC Drilling Manual.

Tool Joints 121

Figure No. 67

Figure No. 68

Tool Joints120

Tubemuse ..................................................... TU Voest ............................................................. VA Wheeling Pittsburgh ........................................ P Youngstown .................................................... Y

Processor SymbolGrant TFW ................................................. TFWOmsco ....................................................... OMSPrideco ........................................................... PI

Drill Pipe Grades and Their SymbolsGrade Symbol Minimum YieldD 55 D 55,000E 75 E 75,000X 95 X 95,000G 105 G 105,000S 135 S 135,000V 150 V 150,000Used U —

Note: Heavy-weight drill pipe to be stencilled atbase of pin with double pipe grade code.

It is suggested that a bench mark be provided forthe determination of the amount of material whichmay be removed from the tool joint shoulder, if itis refaced. This bench mark should be stencilledon a new or recut tool joint after facing to gage.The form of the bench mark should be a 3/16 in.(4.8 mm) diameter circle with a bar tangent to thecircle parallel to the shoulder. The distance fromthe shoulder to the bar should be 1/8 in. (3.2 mm).The bench mark should be positioned in the boxcounterbore and on the base of the pin as shownin Figure Nos. 67 and 68.

It is good practice not to remove more than1/32 in. (0.8 mm) from a box or pin shoulder atany one refacing and not more than 1/16 in. (1.6 mm) cumulatively.

Tool Joints 123

Drill Pipe Weight Code1 2 3 4

OD Nominal Wall WeightSize Weight Thickness Code(in.) (lb/ft) (in.) Number

4.85 .190 123/86.65* .280 2

6.85 .217 127/810.40* .362 2

9.50 .254 131/2 13.30* .368 2

15.50 .449 3

11.85 .262 141/2 14.00* .330 2

15.70 .380 3

13.75 .271 116.60* .337 220.00 .430 3

41/2 22.82 .500 424.66 .550 525.50 .575 6

16.25 .296 151/2 19.50* .362 2

25.60 .500 3

19.20 .304 151/2 21.90* .361 2

24.70 .415 3

65/8 25.20* .330 2

*Designates standard weight for drill pipe size.

Multiply inches by 25.4 to obtain mm.Multiply ft-lb by 1.356 to obtain N·m.Multiply ft-lb by .1383 to obtain kg-m.

Tool Joints122

RECOMMENDED IDENTIFICATION GROOVEAND MARKING OF DRILL PIPENote:1. Standard weight Grade E drill pipe designated

by an asterisk (*see page 123) in the drill pipeweight code table will have no groove or milledslot for identification. The API identification forGrade E heavy-weight drill pipe manufacturedafter January 1, 1995, is a milled slot only begin-ning 1/2 in. from the intersection of the 18° taperand the tool joint OD. The API identification forGrade E heavy-weight drill pipe manufacturedbefore January 1, 1995, was a milled slot onlyin the center of the tong space. ISO marking isper the before January 1, 1995, style.

2. See API Recommended Practice RP 7G fordepth of grooves and slots.

3. Stencil grade code symbol and weight code num-ber corresponding to grade and weight of pipe in milled slot of pin. Stencil with 1/4 in. (6.4 mm)high characters so marking may be read withdrill pipe hanging in elevators.

Tool Joints 125

Figure No. 71

Standard Weight High-Strength Drill PipeAPI Before January 1, 1995

Figure No. 72

Heavy-Weight High-Strength Drill PipeAPI Before January 1, 1995

(page 122)

(page 122)

LPB = Pin tong space length (see API Spec. 7).

Tool Joints124

Standard Weight Grade E Drill Pipe

Figure No. 69

Figure No. 70

Heavy-Weight Grade E Drill PipeAPI Before January 1, 1995

(page 122)

LPB = Pin tong space length (see API Spec. 7).

See Note 2(page 122)

Tool Joints 127

Figure No. 74

Standard Weight Grade X Drill PipeAPI After January 1, 1995


Figure No. 75

Heavy-Weight Grade X Drill PipeAPI After January 1, 1995

Tool Joints126

Figure No. 73

Heavy-Weight Grade E Drill PipeAPI After January 1, 1995


Tool Joints 129Tool Joints128

Figure No. 78

Standard Weight Grade S Drill PipeAPI After January 1, 1995

Figure No. 79

Heavy-Weight Grade S Drill PipeAPI After January 1, 1995

Figure No. 76

Standard Weight Grade G Drill PipeAPI After January 1, 1995

Figure No. 77

Heavy-Weight Grade G Drill PipeAPI After January 1, 1995





Tool Joints 131Tool Joints130

Torque Chart Drill Pipe Tool Joint Recommended Minimums

2. Makeup torque is based on the use of 40 to 60% by weight of finely powdered metallic zinc, applied to all threads and shoulders.

Used(Box Outside Diameters Do Not Represent Tool Joint Inspection Class)

Box Makeup Box Makeup Box MakeupOD Torque OD Torque OD Torque

(in.) (ft-lb) (in.) (ft-lb) (in.) (ft-lb)31/4 3,005 33/16 2,467 35/32 2,20431/16 2,216 31/32 1,967 231/32 1,600

3 1,723 231/32 1,481 215/16 1,244231/32 1,998 231/32 1,998 231/32 1,99831/16 1,994 3 1,500 231/32 1,300225/32 2,455 223/32 2,055 221/32 1,66733/8 4,125 35/16 3,558 31/4 3,00531/2 3,282 37/16 2,794 313/32 2,481

319/32 4,410 317/32 3,752 315/32 3,109317/32 3,767 317/32 3,767 37/16 2,666319/32 4,529 317/32 3,770 315/32 3,02931/8 3,443 31/16 3,427 231/32 2,80135/8 3,216 39/16 2,500 317/32 2,200

323/32 4,357 321/32 3,664 35/8 3,324311/16 3,154 321/32 2,804 321/32 2,804329/32 5,723 313/16 4,597 33/4 3,86741/16 7,694 331/32 6,500 37/8 5,345

4 6,893 329/32 5,726 327/32 4,96943/16 5,521 41/8 4,491 43/32 3,98443/8 8,742 49/32 7,107 47/32 6,04549/32 5,340 47/32 4,600 45/32 3,70043/8 7,000 45/16 6,000 41/4 4,86843/8 5,283 411/32 4,786 49/32 3,83843/8 5,283 411/32 4,786 49/32 3,838

419/32 8,826 41/2 7,274 47/16 6,268421/32 9,875 49/16 8,300 415/32 6,769423/32 10,957 45/8 9,348 417/32 7,785415/16 11,363 413/16 9,017 43/4 7,877

5 12,569 47/8 10,179 425/32 8,44453/32 14,419 415/16 11,363 427/32 9,59547/16 8,782 411/32 7,342 49/32 6,406431/32 7,500 429/32 6,200 427/32 5,00051/32 8,800 431/32 7,500 429/32 6,200413/16 9,017 423/32 7,300 421/32 6,200415/16 11,363 413/16 9,017 43/4 7,877

5 12,569 47/8 10,179 425/32 8,4445 12,569 47/8 10,179 425/32 8,444

57/32 7,827 55/32 6,476 55/32 6,47655/16 9,937 57/32 7,827 53/16 7,15757/16 12,813 55/16 9,937 51/4 8,535515/32 13,547 53/8 11,363 59/32 9,22859/32 9,228 53/16 7,147 55/32 6,47659/16 15,787 57/16 12,813 53/8 11,36355/8 17,311 51/2 14,288 513/32 12,08055/8 17,311 51/2 14,288 513/32 12,080

515/32 12,300 53/8 10,375 55/16 8,60053/8 12,125 59/32 10,066 53/16 8,07159/16 16,391 57/16 13,523 511/32 11,41855/8 17,861 515/32 14,214 53/8 12,125

513/32 12,080 55/16 9,937 51/4 8,535519/32 16,546 515/32 13,554 53/8 11,363525/32 21,230 55/8 17,311 51/2 14,281523/32 19,626 59/16 15,787 515/32 13,554529/32 16,626 525/32 13,239 523/32 11,571523/32 11,571 521/32 9,955 519/32 8,365513/16 14,082 523/32 11,571 521/32 9,955515/16 17,497 527/32 14,933 53/4 12,41567/32 25,547 61/16 21,018 515/16 17,49757/8 15,776 525/32 13,239 511/16 10,77361/32 20,120 529/32 16,626 513/16 14,08263/32 21,914 531/32 18,346 527/32 14,93363/16 24,645 61/32 20,127 515/16 17,49769/32 27,429 61/8 22,818 6 19,244621/32 25,474 61/2 20,205 613/32 17,118623/32 27,619 69/16 22,294 615/32 19,147615/16 35,446 63/4 28,737 65/8 24,413617/32 21,238 67/16 18,146 611/32 15,08665/8 24,412 61/2 20,205 613/32 17,118

625/32 29,828 65/8 24,412 617/32 21,23871/32 38,892 627/32 32,031 611/16 26,560

Torque Chart Drill Pipe Tool Joint Recommended MinimumsNew

DrillPipe Type Box Pin MakeupSize Connection OD ID Torque(in.) (in.) (in.) (in.) (ft-lb)

NC 26 (IF) 33/8 13/4 4,125OH 31/4 13/4 3,783OH 31/8 2 2,716

23/8 SL H-90 31/4 2 3,077WO 33/8 2 2,586PAC 27/8 13/8 2,813

27/8 SH (NC 26) 33/8 13/4 4,125OH 33/4 27/16 3,33

OH 37/8 25/32 5,26

SL H-90 37/8 27/16 4,57

SL H-90 37/8 25/32 6,77

27/8 PAC 31/8 11/2 3,44

WO 41/8 27/16 4,31

XH 41/4 17/8 7,96

NC 31 (IF) 41/8 2 1/8 7,12

NC 31 (IF) 41/8 2 7,91

NC 31 (IF) 43/8 15/8 10,167

31/2 SH (NC 31) 41/8 21/8

7,122

SL H-90 45/8 3 7,59

SL H-90 45/8 211/16 11,142

OH 43/4 3 7,21

OH 43/4 211/16 10,387

NC 38 (WO) 43/4 3

7,688

NC 38 (IF) 43/4 211/16 10,864

31/2 NC 38 (IF) 5 29/16 12,196

NC 38 (IF) 5 27/16 13,328

NC 38 (IF) 5 21/8 15,909

NC 40 (4 FH) 51/4 29/16

16,656

NC 40 (4 FH) 53/8 27/16

17,958

NC 40 (4 FH) 51/2 21/4

19,766

SH (3 1/2 XH) 45/8 29/16

9,102

OH 51/4 315/32 13,186

OH 51/2 31/4 16,320

NC 40 (4 FH) 51/4 213/16

14,092

NC 40 (4 FH) 51/4 211/16

15,404

Note:*1. The use of Outside Diameters (OD) smaller than those

listed in the table may be acceptable on Slim-Hole (SH)tool joints due to special service requirements.

Tool Joints132

KELLYS7SECTION SEVEN

A large portion of the information found onpages 119 through 129 was taken directly out of theIADC Drilling Manual (eleventh edition) and theAPI Spec. RP 7G (fifteenth edition). Credit shouldbe given to the International Association of DrillingContractors and the American Petroleum Institute.Smith extends our thanks to IADC and API forallowing us to reprint this information.

Kellys 135

KELLYSKellys are manufactured with one of two basic configurations — square or hexagonal.

Kelly SizesThe size of a kelly is determined by the distanceacross the drive flats (see Figure Nos. 80 and 81).

Kelly LengthsAPI kellys are manufactured in two standardlengths: (1) 40 ft (12.2 m) overall with a 37 ft (11.3 m) working space or (2) 54 ft (16.5 m) overall with a 51 ft (15.5 m) working space.

End Connections Square Kellys

Like this Not like this

Figure No. 80 Figure No. 81

Top Connection Top Bottom BottomOD Connection OD

APINom. Std. OptionalSize (LH) (LH) Std. Optional Std. (RH) Std(in.) (in.) (in.) (in.) (in.) (in.) (in.)

21/2 65/8 Reg. 41/2 Reg. 73/4 53/4 NC 26 33/8

3 65/8 Reg. 41/2 Reg. 73/4 53/4 NC 31 41/8

31/2 65/8 Reg. 41/2 Reg. 73/4 53/4 NC 38 43/4

41/4 65/8 Reg. 41/2 Reg. 73/4 53/4NC 46 6

NC 50 61/8

51/4 65/8 Reg. 41/2 Reg. 73/4 53/451/2 FH

7NC 56

**6 65/8 Reg. — 73/4 — 6 5/8 FH 73/4

**6 in. square kelly not API.

Kellys 137Kellys136

Figure No. 83

Hexagon Kellys

HOW TO BREAK IN A NEW KELLYWhen Picking Up a New KellyBefore picking up a new kelly, check your kellybushing. The rollers, pins or bearings may needreplacing to return the drive assembly to like newstatus. Also check the bushing body for journalarea wear and body spreading. A loose fitting driveunit can badly damage a new kelly on the first welldrilled. Remember to lubricate kelly drive surfaces.

Check Wear Pattern on Corners of KellyThe major cause for a kelly to wear out is therounding off of the drive corners. This rate of wearis a function of the clearance or fit between thekelly and the rollers in the kelly bushing.

The closer the kelly and rollers fit, the broaderwill be the wear pattern. A narrow wear patternon the kelly’s corners usually indicates a loose fitbetween the two.

API Max. Across AcrossNom. Bore Flats Corner Radius RadiusSize A B C R* Rc(in.) (in.) (in.) (in.) (in.) (in.)

3 11/2 3 3.375 1/4 111/16

31/2 13/4 31/2 3.937 1/4 131/32

41/4 21/4 41/4 4.781 5/16 225/64

51/4 31/4 51/4 5.900 3/8 261/64

6 31/2 6 6.812 3/8 313/32

* Corner configuration at manufacturer’s option.

Hexagon Kellys

Measurement of New Kellys

Figure No. 82

Square Kellys

Top Connection Top Bottom BottomOD Connection OD

APINom. Std. OptionalSize (LH) (LH) Std. Optional Std. (RH) Std(in.) (in.) (in.) (in.) (in.) (in.) (in.)

3 65/8 Reg. 41/2 Reg. 73/4 53/4 NC 26 33/8

31/2 65/8 Reg. 41/2 Reg. 73/4 53/4 NC 31 41/8

41/4 65/8 Reg. 41/2 Reg. 73/4 53/4 NC 38 43/4

51/4 65/8 Reg. — 73/4 —NC 46 6

NC 50 61/8

6 65/8 Reg. — 73/4 —51/2 FH

7NC 56

API Max. Across AcrossNom. Bore Flats Corner Radius RadiusSize A B C R* Rc(in.) (in.) (in.) (in.) (in.) (in.)

21/2 11/4 21/2 3.250 5/16 15/8

3 13/4 3 3.875 3/8 115/16

31/2 21/4 31/2 4.437 1/2 27/32

41/4 213/16 41/4 5.500 1/2 23/4

51/4 31/4 51/4 6.750 5/8 33/8

**6 31/2 6 7.625 3/4 313/16

** Corner configuration at manufacturer’s option.** 6 in. square kelly not API.

Kellys 139Kellys138

Figure No. 86

Kelly after considerable use with only newdrive assembly. The drive edge will have a flatpattern of reduced width and increased contactangle. A curved surface will be visible on thekelly near the roller center.

Figure No. 87

Worn kelly with worn drive assembly. Thedrive edge is a curvature with a high contact angle.

InspectionAt regular intervals, have the kelly’s threaded connec-tions checked by your Drilco inspector. Rememberthese connections are subject to fatigue cracks thesame as drill collar connections. Also, the drivesection and upset areas should be inspected forcracks and wear patterns.

Kelly Saver SubsKelly saver subs protect the lower kelly connectionfrom wear caused by making and breaking the drillpipe connection each time a joint is drilled down.They also protect the top joint of casing againstexcessive wear, if fitted with a rubber protector, as

Rollers must fit the largest spot on the kelly flats.The API tolerances on distance across flats are quitelarge and bushings fitting properly in one place mayactually appear loose at another point. Generallykellys made from forgings have wide variations intolerances, making it impossible to fit the rollerclosely at all points. Kellys manufactured by fulllength machining are made to closer tolerances and fit the rollers best.

Maximum Wear Pattern Width for New Kellys with New DriveAssembly (in.)

Figure No. 84

Figure No. 85

New kelly with new drive assembly. The driveedge will have a wide flat pattern with a small contact angle.

Kellys140

INSPECTION8SECTION EIGHT

well as provide an area to tong on when making upor breaking out the kelly. When you need a newstabilizer rubber, an old sub re-worked or a brandnew one, mention this to your Smith representativebefore you are ready to pick up that new kelly.

WHAT CAN YOU DO WITHTHAT OLD KELLY?

Use the Other CornersBy employing a temperature controlled stubbingprocedure, we can change ends on your kelly.This allows the kelly to drive against new cor-ners. Welding is done only in the large diameterround sections. We do not recommend weldingon the hexagonal or square surfaces of the kelly.

Remachine Drive SurfacesWith the Heli-Mill, we can remachine a kelly.This amounts to taking a clean-up cut on each driving surface.Note: Oversize rotary drive rollers are used with a

remachined kelly. The bore diameter of yourkelly must be small enough to allow enoughwall thickness for remachining. Ask yourSmith representative for more information.

Straightening an Old KellyA bent kelly takes a beating as it is forced throughthe rotary drive bushings. Smith repair centershave straightening presses that can straighten akelly and accurately check the run-out.

If Your Kelly is Too Far GoneYour best bet is to buy a new kelly from your Smith representative.

Inspection 143

SYSTEMATIC FIELD INSPECTIONA systematic approach to proper inspection,maintenance and repair of downhole drilling tools is a necessity for proper operation and toprolong the useful life of the equipment.

Most downhole drilling tool failures and resul-tant fishing jobs can be avoided by the use of peri-odic inspections and by providing maintenance andrepair to the primary areas of fatigue within thetool. The primary areas of fatigue are areas on thetool that are likely to receive the highest concentra-tion of stress while operating. The majority of stressis concentrated in several common areas on thesetools such as: connections, slip areas, upset areas,weld areas, radius changes, tube body, etc.

Smith Field Inspection Services regularly util-izes several types of nondestructive testing (NDT)methods to inspect these primary areas for poten-tial problems. Visual (VT), magnetic particle (MT),liquid penetrant (PT), ultrasonic (UT) and electro-magnetic (ET) testing methods are all utilized forefficiency and detection capabilities.

When inspecting the threaded connections ondrill collars, Hevi-Wate, stabilizers, reamers, holeopeners, kellys, as well as other downhole drillingtools, the primary NDT method of inspection is themagnetic particle inspection method. This com-mon method utilizes fluorescent magnetic parti-cles to detect cracks in the threaded area of theconnection or other locations as necessary.

To illustrate the principle of magnetic particleinspection, you can sprinkle magnetic particles on abar which has been magnetized. The magnetized baracts as a magnet with a north pole at one end and asouth pole at the other end. The magnetic particleswill be attracted to the poles of the magnet. If the baris notched, each side of the notch becomes a pole of a

Inspection 145Inspection144

Proper maintenance and inspection of downholetools begins with proper cleaning. The threadedareas are cleaned by a wire brush adapted to anelectric drill (see Figure No. 90). It is essential thatall thread lubricant, dirt and corrosion be removedfrom the threads and shoulders prior to inspection.

Figure No. 90

All connections are magnetized with DC mag-netizing coils utilizing the continuous method ofparticle application. The continuous method pro-vides for magnetizing the part to be inspected atthe same time of magnetic particle application,thus ensuring proper magnetization and superiordefect detection (see Figure No. 91). Magneticparticles are attracted to any cracks present bythe principle shown in Figure No. 88.

Figure No. 91

magnet (see Figure No. 88). If the notch is narrow,the magnetized particles will form a bridge betweenthe poles. Cracks in threaded connections or in otherlocations behave the same way when magnetized.

Figure No. 88

Smith’s field inspectors are thoroughly trainedin the principles and techniques of defect detec-tion, correction and prevention. Rugged trucks,complete with calibrated and certified inspectionequipment, provide access to remote locations (see Figure No. 89).

Figure No. 89

Particlebuildup


As part of the inspection record, the drill collar ser-ial number, tally length, OD and ID are noted. Alsoconnection size and type, field repairs made, andnumber of connections inspected are recorded. Jointsrequiring shop repairs are clearly marked to ensureproper identification of the repair required (seeFigure No. 94). Tools are marked with the appropri-ate color paint to conform with API and/or customerrequirements. Red marking is used on cracked collarsand yellow on collars with other defects. White mark-ings, along with the well-recognized “OK Drilco,”are used to indicate acceptable equipment.

Figure No. 94

Drill Pipe InspectionThe DrilcologE inspection unit is an electromag-netic system for inspecting used drill pipe and tub-ing (see Figure No. 95). The system incorporates adual function inspection system consisting of bothtransverse flaw detection and wall loss capabilities.Sixteen (16) independent electronic channels, eightfor transverse flaws and eight for wall loss, are uti-lized for detection and display of internal and exter-nal corrosion, cracks, cuts and other transverse,three-dimensional and wall loss defects.

Figure No. 95

Using ultraviolet light, the inspector’s experi-enced eye detects any build up of magnetic particlesin the thread roots of the pin connection (see FigureNo. 92). A magnifying mirror enables the inspectorto look into the thread roots of the box connection.

Figure No. 92

If a crack indication is found, the inspector polishesit with a soft fibrous wheel to verify the presence of afatigue crack (see Figure No. 93). He then re-cleans,re-magnetizes and re-sprays the connection with flu-orescent magnetic particles and re-inspects with theblacklight to verify that the indication is a crack.

Figure No. 93


SHOULDER REFACINGThe Smith portable, electric powered shoulder

refacing tools are designed to repair minor shoul-der connection damage in the field (see Figure No. 97). Drill collar and drill pipe shoulder facesare smoothed with adhesive-backed emery paper,leaving a surface that is flat and smooth. Manyconnection shoulders can be repaired at the rigwhen such damage would normally require costlymachine shop attention.

Caution: Throughout the entire refacing opera-tion, the inspector should wear eye protection.

Figure No. 97

Ultrasonic End Area InspectionUltrasonic techniques may be used to inspect theslip areas and other high-stress areas of the drillpipe tube (see Figure No. 96). These high-stressareas, located in the 36 in. section of tube nearesteither tool joint, are areas of major concern wheninspecting drill pipe. Smith’s ultrasonic equipmentcan locate internal fatigue cracks and washed areasbefore they become problems.

Figure No. 96

OTHER SERVICES AND SPECIFICATIONSIn addition to the specific services shown above,other types of drilling tools, rig hoisting equipmentand other types of equipment may be inspectedby your Smith field inspection technician. Askyour Smith representative for details.

API standards along with Smith’s own inspectionspecifications are used to provide the best inspectionpossible. Customer specifications and in-house pro-cedures may be used at your request. Either way,Smith’s highly trained inspectors will provide thehighest quality service for your inspection dollar.

FIELD REPAIRIn addition to the inspection process, Smith fieldinspectors are also highly trained in the mainte-nance and field repair of downhole tools. Fieldrepair may eliminate the costly need to ship equip-ment to the machine shop for repair. Trained tech-nicians can remove minor thread and shoulderblemishes which, if left unrepaired will cause damage to other connections in the string.


Figure No. 100

Care should be taken in removing only the min-imum amount of material. When making fieldrepairs, operators should be skilled and understandservice conditions of the product to assure properapplication of the refacing tool. It is a good prac-tice not to remove more than 1/32 in. (0.8 mm)from a box or pin shoulder at any refacing and notmore than 1/16 in. (1.6 mm) cumulatively (see APIRecommended Practice RP 7G, current edition).

Note: Portable equipment used to repairthreaded connections in the field will not restore the product within the tolerances of a new part.

True alignment of the shoulder, perpendicularto the center line of the threads, is assured as therefacing tool mandrel is screwed on or into theconnection threads (see Figure No. 98).

Figure No. 98

The adhesive-backed refacing discs are easy toapply and replace (see Figure No. 99).

Figure No. 99

The refacing tool is rotated by a heavy-duty electricsander and the pressure is applied by the operatoralong the axis of the threaded connection (see FigureNo. 100). The drive tube is made from aluminum,thereby reducing the weight of the assembly.

Caution: The sander should not be usedunless properly grounded.


Figure No. 103

How to Mix Copper Sulfate Anti-Gall SolutionThe copper sulfate solution is prepared by dissolving4 heaping tablespoons (53 cc) of blue vitriol (bluestone copper sulfate crystals or powder) in 2/3 quart(600 cc) of water and adding 3 tablespoons (40 cc) of sulfuric acid.

Caution: Eye protection and appropriate handprotection should be worn when mixing or han-dling copper sulfate solution. Always pour acidinto water. Mix the solution in an area with eyewash fountain, or where large amounts of waterare available for flushing, in case solution comes in contact with any part of the body.

HOW TO USE YOUR TOOLJOINT IDENTIFIER1. With the thread form, determine the number

of threads per inch in the pin or box (see FigureNo. 104). On the scale, threads per inch are indi-cated by the number following the type of joint.

Figure No. 104

Copper Sulfate SolutionAfter refacing, an anti-gall coating of copper sulfate,is applied to the shoulder surface (see Figure No. 101and solution mixing instructions on page 153).

Caution: Eye protection and appropriate handprotection should be worn when mixing or han-dling copper sulfate solution. Always pour acidinto water. Mix the solution in an area with aneye wash fountain or where large amounts ofwater are available for flushing, in case solutioncomes in contact with any part of the body.

Figure No. 101

After completion of the inspection and repairoperation, a rust preventative is applied to all con-nections on tools that are to be stored before thenext use (see Figure No. 102). On tools that are to be used immediately, an API thread compound isapplied to the threads and shoulders (see FigureNo. 103).

Figure No. 102


4. On identifier scale, find the type of joint whichcorresponds to the pin base diameter measuredin Figure Nos. 105 and 106 (see Figure No. 107).Place one end of caliper in the notch and readthe corresponding connection size at the otherend of the caliper tip.

Figure No. 107

5. To find the type of box, hold the end of thescale marked box to mouth of counterbore, asshown, and read the nearest size and type ofjoint having corresponding number of threadsper inch (see Figure No. 108).

Figure No. 108

2. On pins without a relief-groove or turned cylin-drical diameter, caliper diameter at base (seeFigure No. 105).

Figure No. 105

3. To measure tapered diameter of pins with relief-grooves or cylindrical diameters, ask someone to hold two straight edges against threads andcaliper at shoulder as shown (see Figure No. 106).

Figure No. 106

Inspection156

ROTATING DRILLING HEADS9SECTION NINE

Pin base diameters vary widely on same sizejoints, but no difficulty will be experienced if thenearest size is taken having the correct number ofthreads per inch. For example 31/2 in. FH, 31/2 in. IFand 31/2 in. H-90 have nearly the same pin basediameter, but can be easily distinguished by thenumber of threads per inch.

INTERNATIONAL INSPECTION SERVICESSmith Services — Drilco Group inspection sys-tems are air portable, self supporting and quicklyavailable from strategic locations around theworld. Experienced inspectors are trained indefect detection and downhole tool maintenanceand field repair. Inspectors are qualified to train thecustomer’s operating personnel in field mainte-nance and defect prevention.

Special compact and light-weight equipmentallows travel to offshore and remote locations (see Figure No. 109).

Figure No. 109

Rotating Drilling Heads 159

ROTATING DRILLING HEADSConventionally, one will drill a well and use heavydrilling fluids to control the well pressures and tocontrol the flow of cuttings from the well. Thereare times when it is beneficial for you to use air orgas as the circulating medium or use a light mudto drill in an underbalanced condition. When drillingwith air or gas or underbalanced, you must use arotating drilling head.

Rotating drilling heads are used to safely divertair, gas, dust or drilling muds away from the rigfloor. The head has a rubber device, called a strip-per rubber, that provides a continuous seal aroundthe drill stem components, thus directing the drill-ing medium through a side outlet on the body andaway from the rig floor.

Rotating drilling heads are also used for closedloop circulating systems in environmentally sensitive areas.

Note: You should always remember that rotatingdrilling heads are diverters and that you mustnever use them as a blowout preventer.

Figure No. 110

APPLICATIONSAir and Gas DrillingAir and gas drilling were the first applications forrotating drilling heads. Typically, air and gas drill-ing are used in very hard formations and forma-tions which are extremely fractured. Benefits ofair and gas drilling include:· Faster penetration rates, sometimes threefold to

fourfold compared to mud drilling.

Rotating Drilling Heads 161Rotating Drilling Heads160

System ComponentsThe Smith Services rotating drilling head consistsof five major components (see Figure No. 111).(1) (a) Bowl with integral inlet and outlet flanges

or (b) body with separate spool having inletand outlet flanges.

(2) Stripper rubber.(3) Drive ring and bearing assembly .(4) Drive bushing assembly with kelly drive

bushing and clamp.(5) Lubricator system (not shown).

Figure No. 111

Bowl Assembly with Integral Inlet and Outlet Flanges (Models7068 and 7368)The bowl assembly installs on top of the BOP stackand below the rotary table. The bowl is stationaryand has a clamp assembly that locks the drivering and bearing assembly firmly to the body.

Body Assembly with Separate Spool Having Inlet and OutletFlanges (Models DHS 1400, 8068 and RDH 2500)The spool is installed on top of the BOP and the bodyfits on top of the spool. The two are held together bya clamp assembly (Models DHS 1400 and RDH 2500)or by clamping dogs (Model 8068). Both the spooland the body are stationary.

· Reduced formation damage.· Fewer wellbore problems such as lost circulation

and sloughing of sensitive shales.· Immediate indication of zone productivity.· Reduced mud cost.

Underbalanced DrillingUnderbalanced drilling is where the hydrostatic pres-sure created by the drilling fluid column is less thanthe formation pressure. Benefits of underbalanceddrilling include:· Reduced formation damage.· Accurate and immediate evaluation of

well potential.· Improved production rates.· Increased penetration rates.· Reduction in drilling problems associated

with pressure depleted zones such as stuck pipe and lost circulation.

· Reduced drilling time and costs.

Flow DrillingFlow drilling is the process of producing the wellwhile drilling. You drill the producing zone under-balanced to allow flow from the formation intothe wellbore. Flow drilling is used primarily for:· Horizontal wells with fractured formations.· Preventing damage to producing formation(s).· Preventing plugging of fractures while drilling

and well completion.· Reducing drilling time and costs.

Geothermal DrillingGeothermal drilling is where you drill into steamproducing formations thus allowing steam to flowup the wellbore to the surface. The steam must bediverted from the rig floor for safety. Rotating drill-ing heads specifically designed for geothermal drill-ing typically have two sealing elements (stripperrubbers). The upper stripper rubber seals aroundthe kelly while drilling and the drill pipe and tooljoints when tripping in and out of the hole. Thelower stripper rubber has a larger ID to allow seal-ing around the larger drill stem components suchas drill collars.

Drive bushing

Stripper rubber

Bearing assembly

Bowl


SPECIFICATIONSStandard Rotating Drilling Heads

DHS 1400 Drilling Head: The drive bushing andstripper rubber are retrievable through a 171/2 in.rotary. The sealed bearing assembly is retrievablethrough a 221/2 in. rotary table. It can be used with single or dual rotating stripper rubbers. Thehydraulic accumulator operates on rig air supply.

Model DHS 1400 Drilling Head

Maximum speed ................................ 100 rpmThrough bore of wellhead adapter assembly

11 in. - 3/5,000 ............................... 111/4 in.135/8 in. - 5,000 .............................. 135/8 in.

Through bore standard ................................ 14

Overall heightsStd. 135/8 in. - 3/5,000 inlet spool

with no outlet ................................ 341/2 in.Std. 135/8 in. - 5,000 inlet

with 71/16 in. - 2/3,000 outlet .......... 501/4 in.Std. 11 in. - 3/5,000 inlet

with 71/16 in. - 2/3,000 outlet .......... 501/4 in.Short 135/8 in. - 5,000 inlet

with 71/16 in. - 2/3,000 outlet ......... 421/16 in.Short 135/8 in. - 5,000 inlet

with 7 in. casing thread outlet ........ 403/4 in. Short 11 in. - 3/5,000 inlet

with 7 in. casing thread outlet ........ 393/4 in.Short 11 in. - 3/5,000 inlet

with 71/16 in. - 2/3,000 outlet .......... 393/4 in.

Rotating test pressure ........................... 400 psi

Stripper RubberThe stripper rubber is either fastened to the bottomof the drive bushing or molded integral with theassembly. The purpose of the stripper rubber is toprovide a seal around the kelly as it is rotated and toseal around the drill pipe while tripping in and out ofthe hole. It is easily changed by opening the clampand lifting the drive bushing assembly (and stripperrubber) out of the bowl. Stripper rubbers are avail-able in different elastomer compounds for the vari-ous drilling environments such as high temperaturesand oil-base muds.

Stripper Rubber Elastomer Compound Selection

Drive Ring and Bearing AssemblyThe drive ring and bearing assembly supports thetorsional and axial loads on the rotating drilling headand also provides low torque rotation. The bearingassembly consists of two heavy-duty tapered rollerbearings, an upper and lower. The bearing assemblyis sealed to keep contaminants out of the bearingswhile at the same time retaining the lubricating oilaround the bearings.

Drive Bushing AssemblyThe drive bushing engages a lug on the drive ringand is then clamped onto the drive ring. The drivebushing drives the drive ring and bearing assembly.The drive bushing itself is driven by the kelly bush-ing which is fitted onto the kelly. The kelly bushingautomatically engages when the kelly is loweredinto the drive bushing. The drive bushing has a rub-ber insert to absorb lateral shock loads which aretransmitted from the kelly to the kelly bushing.

Lubricator SystemThe lubricator system must be used in conjunctionwith the bearing assembly. The lubricator providesoil under pressure to the bearings for cooling andlonger bearing life. Lubricating systems can be cir-culating or non-circulating. Circulating lubricatingsystems are recommended for high-temperatureoperations such as geothermal drilling.

Oil-Base Oil-Base Mud Mud Steam

Compound Cold Below Above or HotType Air Water 140°F 140°F Water

Natural rubber Good Best Poor Poor Fair

Butyl Good Good Poor Poor Best

Urethane Best Good Best Poor Poor

Nitrile Good Good Good Best Poor


Model 8068: On this model, the body does nothave an integral side outlet or mounting flange. It is attached by clamping dogs to a spool withflanges for 135/8, 16 and 20 in. BOPs. The drivebushing/stripper rubber assembly passes through a 171/2 in. rotary table. The rotating drilling headpasses through a 271/2 in. rotary table. It can beused with mudline casing suspension systemswhen attached to a 30 in. mounting flange. It isavailable with single or dual stripper rubbers.

Model 8068Height

Lower Maximum Side w/Stand. w/ShortSize Flange Bore Outlet Bushing Bushing(in.) (in.) (in.) (in.) (in.) (in.)

163/4 163/4 - 2,000 163/4 9 - 3,000 423/4 365/8

203/4 203/4 - 2,000/3,000 203/4 9 - 3,000 423/4 365/8

30 None* 283/32 None** 253/4 195/8

30 - 36 None* 269/32 None** 253/4 195/8

**Mounting flange welded directly to conductor pipe.**Installed on conductor pipe.

Notes:1. Kelly bushings are available in 31/2 in. hex or square, 41/4 in.

hex or square, and 51/4 in. hex only.2. Stripper rubbers are available in 27/8, 31/2, 41/2, 5 and 51/2 in.

(Stationary casing stripper rubbers from 65/8 through 103/4 in.on special order.) Other sizes available upon request.

Model 7068: On this model the body is integralwith the spool and has a side outlet and a lowerflange for mounting on BOP. The drive bushing/stripper rubber assembly will pass through 171/2 in.rotary table. The 11 in. size is available in a “shorty”version when space is limited beneath the rotarytable. It is available with single or dual rotatingstripper rubbers.

Model 7068

Model 7368: This model also has a body that isintegral with the spool and has a side outlet and alower flange for mounting on the BOP. It has thesame basic design features of larger models and isideal for slim-hole applications and workover jobsbecause of its shorter height. The drive bushing/stripper rubber is a one-piece assembly and canpass through a 101/2 in. rotary table.

Model 7368

Height

Lower Maximum Side w/Stand. w/ShortSize Flange Bore Outlet Bushing Bushing(in.) (in.) (in.) (in.) (in.) (in.)

11 11 - 3,000/5,000 111/4 71/16 - 2,000 36 297/8

Combination

11 11 - 3,000/5,000 113/4 7 Threaded 243/4

Shorty Combination (Male)

135/8 135/8 - 3,000 14 71/16 - 2,000 36 297/8

135/8 135/8 - 5,000 135/8 9 - 2,000 38 317/8

Notes:1. Kelly bushings are available in 31/2 in. hex or square, 41/4 in.

hex or square, and 51/4 in. hex only.2. Stripper rubbers are available in 27/8, 31/2, 41/2, 5 and 51/2 in.

(Stationary casing stripper rubbers from 65/8 through 103/4

in. on special order.) Other sizes available upon request.

Maximum Size Lower Flange Bore Side Outlet Height(in.) (in.) (in.) (in.) (in.)

71/16 71/16 - 2,000/3,000/5,000 71/16 41/16 - 2,000/3,000 237/8

Combination

Notes:1. Kelly bushings are available in 31/2 in. hex or square.2. Stripper rubbers are available in 23/8, 27/8 and 31/2 in. (Special

stripper rubbers for wireline service, are available upon request.)


if either electrical or air supply is interrupted.There is no electrical wiring required beneath the rig floor.

Model RDH 2500 - High-Pressure Drilling Head

Alignment: Stack alignment is critical to theperformance and life of the rotating drilling headbearings and stripper rubber. Check alignment byslowly lowering the kelly until kelly bushingengages the drive bushing in the rotating head.The kelly drive bushing should go into the drivebushing freely without having to force the kellysideways. If the kelly drive bushing does not freelyengage into the drive bushing of the rotating drill-ing head, then BOP stack and rig rotary should beproperly aligned.

Maximum speed ................................ 100 rpmThrough bore of wellhead

adapter assembly ................................ 133/8

Through bore of drilling head assembly .......................................... 9

Through bore of stripper rubber .................... 6Maximum OD .......................................... 271/4

Overall heights135/8 in. - 3,000 inlet spool

with no outlet ..................................... 531/2

135/8 in. - 5,000 inlet with 71/16 in. - 2/3,000 outlet ................575/8

11 in. - 5,000 inlet with 71/16 in. - 2/3,000 outlet ............... 577/8

71/16 in. - 5,000 inlet with 71/16 in. - 2/3,000 outlet ............... 587/8

Rotating test pressure ........................ 1,500 psi

SPECIAL ROTATING DRILLING HEADSGeothermal Well Drilling Head: This drillinghead incorporates two stripper rubbers — upperrubber rotates with the kelly and seals around thedrill pipe and tool joints as connections are madestripping in and out of the hole. The lower stripperrubber seals on the large diameter string compo-nents such as drill collars. The body is equippedwith a port for water injection to cool and lubri-cate the stripper rubbers and exposed seals whilestripping in and out. The elastomer componentsare formulated for high-temperature service.

Model RDH 2500 High-Pressure Drilling Head:Rated at 1,500 psi rotating test pressure. This rat-ing is for the body and seals only and does notinclude the stripper rubber. In actual field usethere are many variables which can affect the lifeand pressure capability of the stripper rubber. Forexample, if the drilling head and BOP are mis-aligned with the rig, the performance of the strip-per rubber is adversely affected. Other factors suchas high temperature, higher pressures, etc., alsoadversely affect the life of the stripper rubber. Thestripper rubber is a special mechanically energizedstripper rubber. The bearing chamber is sealedwith low-pressure seals against atmospheric pres-sure. There is a separate high-pressure seal assem-bly to contain wellbore pressure.

Note: This product, regardless of pressure rat-ing, is a diverter and not a blowout preventor.

The high-pressure seal assembly contains a redun-dant set of seals. The high-pressure drilling headis available with single or dual stripper rubbers. Wehave different elastomer components available foroil and gas or geothermal drilling.

The high-pressure drilling head utilizes a hydrau-lic skid unit to supply low-pressure circulating lubri-cation to the bearings, and a separate lubricationsystem to supply high-pressure lubrication to thehigh-pressure seals. The high-pressure lubricant sys-tem maintains hydraulic pressure at a slightly higherpressure than the wellbore to properly lubricate thehigh-pressure seal assembly.

The hydraulic skid is located away from the rig and requires 110 volts and an air supply fromthe rig. A back-up air compressor automaticallyengages if the rig air is disconnected. A redundantsystem assures that hydraulic fluid flow continues


Bolts API Ring

Bolt BoltBolt Dia. Length

Quantity (in.) (in.) Ring No.

12 1 7 45

12 11/8 8 45

12 13/8 103/4 46

12 11/2 111/4 BX 156

12 11/8 8 49

12 13/8 9 49

12 15/8 12 50

16 11/2 13 BX 157

16 11/4 83/4 53

16 13/8 91/2 53

12 17/8 133/4 54

12 2 161/2 91

16 13/4 15 BX 158

20 11/4 9 57

20 13/8 101/4 57

16 15/8 121/2 BX 160

20 17/8 171/4 BX 159

20 11/2 101/4 65

20 15/8 113/4 66

16 17/8 141/2 BX 162

24 17/8 171/2 BX 162

24 15/8 113/4 73

20 2 141/2 74

24 2 183/4 BX 165

24 21/2 241/2 BX 165

API Ring Joint Flange DataFlange

Nominal Size “Old” Nominaland Pressure Size and Series Dia. Bolt

Rating Service OD Thickness Circle(in.) (in.) (in.) (in.) (in.)

71/16 x 2,000 6 x 600 14 23/16 111/2

71/16 x 3,000 6 x 900 15 21/2 121/2

71/16 x 5,000 6 x 1,500 151/2 35/8 121/2

71/16 x 10,000 187/8 41/16 157/8

9 x 2,000 8 x 600 161/2 21/2 133/4

9 x 3,000 8 x 900 181/2 213/16 151/2

9 x 5,000 8 x 1,500 19 41/16 151/2

9 x 10,000 213/4 47/8 183/4

11 x 2,000 10 x 600 20 213/16 17

11 x 3,000 10 x 900 211/2 31/16 181/2

11 x 5,000 10 x 1,500 23 411/16 19

* 10 x 2,900 203/4 511/16 163/4

11 x 10,000 253/4 59/16 221/4

135/8 x 2,000 12 x 600 22 215/16 191/4

135/8 x 3,000 12 x 900 24 37/16 21

135/8 x 5,000 261/2 47/16 231/4

135/8 x 10,000 301/4 65/8 261/2

163/4 x 2,000 16 x 600 27 35/16 233/4

163/4 x 3,000 16 x 900 273/4 315/16 241/4

163/4 x 5,000 303/8 51/8 265/8

163/4 x 10,000 345/16 65/8 309/16

211/4 x 2,000 20 x 600 32 37/8 281/2

203/4 x 3,000 20 x 900 333/4 43/4 291/2

211/4 x 5,000 39 71/8 347/8

211/4 x 10,000 45 91/2 401/4

* Not a current API size.

Rotating Drilling Heads170

ADDITIONALINFORMATION10SECTION TEN

Notes

Additional Information 173

“Maximum Permissible Doglegs in RotaryBoreholes” by Arthur Lubinski, Publication No. 55,February 1960. This paper presents means for spec-ifying maximum permissible changes of hole angleto ensure a trouble-free hole.

“What You Should Know About Kellys” by DoyleW. Brinegar, Publication No. 81 (reprinted from Oil& Gas Journal, May 1977). This article answers anumber of questions pertaining to kellys, includ-ing: why kellys become unusable, the effects ofmanufacture on kelly performance, interpretingdrive edge wear patterns and kelly repair.

“Qualified Inspectors: The Key to Maximum DrillCollar Life” by W.R. Garrett, Publication No. 82(reprinted from World Oil, March 1977) explainsthe importance of inspection services, in terms ofobtaining the maximum amount of trouble-freeservice out of a drill collar before needing repair.

“Down-Hole Failure of Drilling Tools” by B.P. Faas, Publication No. 32 (reprinted fromDrilling Contractor, May and June 1970). In thisarticle, the author summarizes a study conductedby Standard Oil Co. which examines the cause of downhole drilling equipment failures. Thisdetailed examination attempts to determine ifthere are any deficiencies in steel or fabricationprocedures which could be corrected so that thelikelihood of additional failures could be reduced.

“Drill Pipe Fatigue Failure” by H.M. Rollins,Publication No. 34 (reprinted from Oil & Gas Journal,April 1966). The author in the article explains thenature of drill pipe failure, and identifies seven stepsthat can be taken to minimize fatigue damage.

“Drill Stem Failures Due to H2S” by H.M. Rollins,Publication No. 52 (reprinted from Oil & GasJournal, January 1966), discusses the results ofmany investigations involving tubing failures,talks about drill pipe failures specifically and rec-ommends practices that help to cope with H2S.

“Straight Hole Drilling” by H.M. Rollins,Publication No. 18 (reprinted from World Oil,March and April 1963), covers “Why Holes GoCrooked” and what you can do to prevent exces-sive hole angle build-up.

Additional Information 175Additional Information174

“Predicting Bottomhole Assembly Performance”by J.S. Williamson and A. Lubinski, PublicationNo. 98 (reprinted IADC/SPE 14764 from IADC/SPEDrilling Conference, February 1986). This paper dis-cusses a computer program for the prediction ofbottom-hole assembly performance. Input parame-ters include: formation dip, hole and collar size,stabilizer spacing, etc. Output may be hole curva-ture, hole angle or WOB.

“An Engineering Approach to StabilizationSelection” by G.K. McKown and J.S. Williamson,Publication No. 99 (reprinted IADC/SPE 14766from IADC/SPE Drilling Conference, February1986). This paper discusses a means of selectingstabilizers based on applications and drilling con-ditions. Experimental wear data and computeranalyses of the effects of stabilizer design on bottom-hole assembly performance are offered.

“Degassing of Drilling Fluids” by Walter E.Liljestrand, Publication No. 43 (reprinted from Oil & Gas Journal, February 1980). The purpose of this paper is to broadly cover the subject ofdegassing. It outlines the problems and discussesthe steps that must be taken to remove the gas.There are several ways to take each step becausethere are different types of degassers shown, yeteach can do the job. Some examples of mud problems are also shown.

“A User’s Guide to Drill String Hardfacing” byJ. Steve Williamson and Jim B. Bolton, PublicationNo. 100 (reprinted from Petroleum EngineeringInternational, September 1983). This paper dis-cusses drill string hardfacings, welding processesand important metallurgical variables involved. Theimportance of proper tungsten carbide selection isemphasized. Experimental results are discussedfor casing wear by hardfacings and for hardfacingwear resistance. Guidelines are given for hardfac-ing selection based on tests and field experience.

“How to Drill a Usable Hole” by Gerald E. Wilson,Publication No. 39 (reprinted from World Oil,September 1976). This brochure of pictures andexamples explains how to control hole deviation,reasons holes become crooked and problems thatcan result.

“Drilling Straight Holes in Crooked HoleCountry” Publication No. 59. These tables willpermit you to predict the effect on hole inclina-tion, changes in weight, drill collar size and theuse of stabilizers.

“Using Large Drill Collars Successfully” by DoyleBrinegar and Sam Crews, Publication No. 21(reprinted from Journal of Petroleum Technology,August 1970). Article discusses use of large drillcollars in the 9 to 11 in. size range.

“How to Bridge Drill Pipes’ Zone of Destruction” by Charlie Miller, Publication No. 72 (reprintedfrom Drilling DCW Magazine, June 1973). Theauthor explains the major causes of twistoffs andwashouts in the drill string, and offers solutions for correcting the problem — namely Drilco’s Hevi-Wate drill pipe.

“Heavy-Wall Drill Pipe A Key Member of the DrillStem” by Morris E. Rowe, Publication No. 45,September 1976, discusses currently available drilling technologies utilizing heavy-wall drill pipe,and attempts to solve fatigue failure problems.

“Bit Stabilization Effective Method to Prolong BitLife” by G.M. Purswell, Publication No. 50 (reprintedfrom Oilweek, December 1967), recognizes that bitstabilization is an effective method for prolongingrock bit life and obtaining greater penetration rates.Purswell points out that stabilization “forces the bitto rotate around its own center.” Numerous config-urations of semi-packed or packed bottom-holeassemblies are reviewed and discussed as to theirapplication for bit stabilization.

“How to Select Bottom Hole Drilling Assemblies”by Gerald E. Wilson, Publication No. 62 (reprintedfrom Petroleum Engineer, April 1979), identifiesand compares a number of bottom-hole assembliesthat can be used when drilling in crooked hole areas.The primary factor affecting selection of the assem-bly is the crooked hole tendencies of the formationsto be penetrated.

Additional Information176

INDEX11SECTION ELEVEN

“What is the Condition of Your DownholeTools and How Are They Being Repaired”by Doyle W. Brinegar, Publication No. DR - 1009(reprinted from SPE/IADC No. 18702 presented atthe SPE/IADC Drilling Conference, March 1989).This paper discusses the repair and reuse of down-hole drilling equipment, along with inspectionmethods. One of the objectives of this paper is toreview repair methods that are used to increase thelife of downhole tools. Particular attention is paidto welding procedures.

“Drill String Design Optimization for High-Angle Wells” by George K. McKown, PublicationNo. DR-1002 (reprinted from SPE/IADC DrillingConference, March 1989). This paper discussesdrill string design for high-angle wells and how tooptimize for all the required functions of the drillstring. Practical considerations for drill string designfor high-angle wells and systematic approaches tothe design process are presented.

When ordering publications from Smith, pleaseindicate the publication number you are interestedin and address your request to:

Smith InternationalReader Service Dept.P.O. Box 60068Houston, TX 77205-0068

Or call your Smith representative.

Index 179

IndexIntroduction ................................................. iTable of contents .......................................... iiLetter from operations .................................. iiiHow to use this handbook ............................ iv

AANGLE

How to control hole angle ........................ 8Rate of hole angle .................................... 5Total hole angle ........................................ 5

ANTI-GALL

Anti-gall protection of connections ............ 67ASSEMBLIES

Bottom-hole assemblies ............................ 1Packed hole assembly - length of

tool assembly ........................................ 10

BBENDING STRENGTH RATIO

Guides for evaluating drill collar OD, ID and connection combinations ........... 78

BHABottom-hole assemblies ............................ 1Conclusion ............................................... 22Downhole vibrations ................................ 22Factors to consider when designing

a packed hole assembly ........................ 10How to control hole angle ........................ 8Improve hole opener performance

by using a vibration dampener and stabilizers ................................... 23

Minimum permissible bottom-hole drill collar outside diameter formula ...... 4

Packed hole assembly - clearance between wall of hole and stabilizers ...... 11

Packed hole assembly - length of tool assembly ........................................ 10

Packed hole assembly - medium crooked hole country ............................ 13

Packed hole assembly - mild crooked hole country ......................................... 12

Packed hole assembly - mild, medium and severe crooked hole country ........... 14

Packed hole assembly - severe crookedhole country ......................................... 14

Packed hole assembly - stiffness of drill collars ........................................... 11

Index 181Index180

CONNECTIONS continuedPreventing pin and box gailures in

downhole tools ..................................... 76Rotary shouldered connection

interchange list ..................................... 96Torque chart drill pipe tool joint

recommended minimums ...................... 130CROOKED HOLES

Medium and severe crooked hole country in hard to medium-hard formations ....... 19

Mild, medium and severe crooked hole country in hard to

medium-hard formations .................... 17Mild, medium and severe crooked

hole country in medium-hard to soft formations .................................. 19

Packed hole assembly - medium crooked hole country ............................ 13

Packed hole assembly - mild crooked hole country ............................ 12

Packed hole assembly - mild, medium and severe crooked hole country ........... 14

Packed hole assembly - severe crooked hole country ............................ 14

DDIFFERENTIAL PRESSURE

Differential pressure sticking of drill pipe and drill collars ...................... 27

DIMENSIONAL DATA

Hexagon kellys ......................................... 136Square kellys ............................................ 136

DOGLEGS

Problems associated with doglegs and key seats ........................................ 6

DOWNHOLE TOOLS

Preventing pin and box failures in downhole tools ..................................... 76

DRILL COLLAR

Anti-gall protection ................................... 67Automatic torque control system ............... 51Buoyancy effects of drill collars in mud ..... 70Drill collar care and maintenance ............. 37Minimum permissible bottom-hole drill

collar outside diameter formula ............. 4Pipe - drill pipe - drill collar safety factor -

tension, compression, neutral zone ........ 71

BHA continuedPacked hole assembly - wall

support and length of contact tool ......... 12Packed hole theory ................................... 9Packed pendulum ..................................... 20Pendulum theory ...................................... 8Problems associated with doglegs

and key seats ........................................ 6Rate of hole angle change ......................... 5Reduced bit weights ................................. 21Stabilizing tools ........................................ 15Total hole angle ........................................ 5

BIT

Bit stabilization - angular misalignment .... 32Bit stabilization - parallel misalignment ..... 32Bit stabilization pays off ........................... 31Stabilization improves bit performance ..... 31

using Hevi-Wate drill pipe for bit weight on small rigs .......................... 106

BOX

Dimensional identification of drill collar box connections .......................... 100

BREAK INHow to break in a new kelly ..................... 137

BUOYANCY

Buoyancy effect of drill collars in mud ...... 70

CCAPACITY

Capacity and displacement table - Hevi-Wate drill pipe .............................. 112

COLLARS

Hookups used to make up drill collar connections ................................. 43

Packed hole assembly - stiffness of drill collars ........................................... 11

Stress Relief .............................................. 68CONNECTIONS

Anti-gall protection ................................... 67Dimensional identification of

box connections .................................... 100Dimensional identification of

pin connections .................................... 101Drill pipe and drill collar safety factor -

tension, compression and neutral zone .. 71Facts about cold working .......................... 66Guides for evaluating drill collar OD,

ID and connection combinations ........... 78Using the connection selection charts ....... 78

Index 183Index182

DRILL PIPE continuedDimensional identification -

heavy-weight grade E drill pipe ............. 124Dimensional identification -

heavy-weight grade E drill pipe ............. 126Dimensional identification -

heavy-weight grade G drill pipe ............. 128Dimensional identification -

heavy-weight grade S drill pipe .............. 129Dimensional identification -

heavy-weight grade X drill pipe ............. 127Dimensional identification -

heavy-weight, high-strength drill pipe .... 125Dimensional identification -

standard weight grade E drill pipe ......... 124Dimensional identification -

standard weight grade G drill pipe ......... 128Dimensional identification -

standard weight grade S drill pipe ......... 129Dimensional identification -

standard weight grade X drill pipe ......... 127Dimensional identification -

standard weight, high-strength drill pipe ........................................... 125

Pipe mill codes to be stencilled at base of pin ............................................ 119

Pipe weight code ...................................... 123Recommended identification groove

and marking of drill pipe ....................... 122Recommended practice for marking on

tool joints for identification of drill string components ............................. 119

Tapered drill Strings .................................. 113Tool joints ................................................ 117Torque chart drill pipe tool joint

recommended minimums ...................... 130Using Hevi-Wate drill pipe for

bit weight on small rigs ......................... 106Using Hevi-Wate drill pipe in

directional drilling ................................. 110Using Hevi-Wate drill pipe in

the transition zone between the drill collars and drill pipe ................... 107

What is Hevi-Wate drill pipe ..................... 105Straight hole drilling ................................. 2

FFIELD INSPECTION

Systematic field inspection ........................ 143

DRILL COLLARS continuedDimensional identification of

box connections .................................... 100Dimensional identification of

pin connections .................................... 101Drill collar weights [kg/m] ....................... 75Drill collar weights [lb/ft] ......................... 73Ezy-Torq hydraulic cathead ....................... 52Facts about cold working .......................... 66Guides for evaluating drill collar OD,

ID and connection combinations ........... 78How to figure the drill collar makeup

torque needed ....................................... 41Hookups used to make up drill

collar connections ................................. 43How to apply and measure

makeup torque ...................................... 51How does the ATCS help .......................... 52How to use the connection

selection charts ..................................... 78Hydraulic line pull devices ........................ 52Hydraulic load cells .................................. 51Drill collar failures .................................... 77Know field shop work .............................. 66Low torque faces ...................................... 69Oilfield thread forms ................................ 97Picking up drill collars .............................. 38Recommended minimum drill collar

makeup torque [ft-lb] ............................ 54Recommended minimum drill collar

makeup torque [kg-m] .......................... 58Recommended minimum drill collar

makeup torque [N·m] ........................... 62Refacing a drill collar shoulder .................. 149Rig catheads ............................................. 51Rig maintenance ...................................... 41Slip and elevator recesses ......................... 69Special drill collars ................................... 68Stress relief .............................................. 68Torque Control ......................................... 39Weight of 31 ft drill collar [lb] ................... 72Weight of 9.4 m drill collar [kg] ................ 74

DRILL PIPE

Capacity and displacement table - Hevi-Wate drill pipe .............................. 112

Dimensional data - range II Hevi-Wate drill pipe .............................. 112

Dimensional data - range III Hevi-Wate drill pipe ............................... 113

Index 185Index184

IDENTIFICATION continuedPipe grade codes to be stencilled at

base of tool joint pin ............................. 120Pipe mill codes to be stencilled at

base of tool joint pin ............................. 119Recommended identification groove

and marking of drill pipe ....................... 122Recommended practice for marking

on tool joints for identification of drill string components ...................... 119

IDENTIFIER

How to use the tool joint identifier ........... 152INFORMATION

Additional technical information ............... 173INSPECTION

International inspection services ............... 155Systematic field inspection ........................ 143

INTERCHANGE LIST

Rotary shouldered connection interchange list ..................................... 96

KKELLYS

Hexagon kellys - dimensional data ............ 136How to break in a new kelly ..................... 137New kellys - measurements ...................... 136Square kellys - dimensional data ............... 136What can you do with that old kelly ......... 140

KEY SEATS

Problems associated with doglegs and key seats ........................................ 6

MMAINTENANCE

Drill collar care and maintenance ............. 37If you have an epidemic of drill

collar failures that you can't explain ...... 77Know field shop work .............................. 66Preventing pin and box failures in

downhole tools ..................................... 76Refacing a drill collar shoulder .................. 149Rig maintenance of drill collars ................. 41Systematic field inspection ........................ 143

MAKEUP

Automatic torque control system ............... 51Ezy-Torq hydraulic cathead ....................... 52How to figure the drill collar

makeup torque needed .......................... 41

FORMATIONS

Medium and severe crooked hole country in hard to medium-

hard formations ................................. 19Mild, medium and severe crooked

hole country in hard to medium-hard formations ................................. 17

Mild, medium and severe crooked hole country in medium-hard

to soft formations .............................. 19

GGRADE CODE

Pipe grade codes to be stencilled at base of tool joint pin ......................... 120

HHEVI-WATE DRILL PIPE

Capacity and displacement table - range II Hevi-Wate drill pipe .................. 112

Dimensional data - range III Hevi-Wate drill pipe .............................. 113

Using Hevi-Wate drill pipe for bit weight on small rigs .............................. 106

Using Hevi-Wate drill pipe in directional drilling ................................. 110

Using Hevi-Wate drill pipe in the transition zone between the

drill collars and the drill pipe ............. 107What is Hevi-Wate drill pipe ..................... 105

HEXAGON KELLYS

Dimensional data ..................................... 136HOLE

How to control hole angle ........................ 8Rate of hole angle change ......................... 5Total hole angle ........................................ 5

IIDENTIFICATION

Dimensional identification - heavy-weight, grade E drill pipe ............ 124

Dimensional identification - heavy-weight, high-strength drill pipe .... 125

Dimensional identification - standard weight, grade E drill pipe ........ 124

Dimensional identification - standard weight, high-strength

drill pipe ........................................... 125

Index 187Index186

PIN

Dimensional identification of drill collar pin connections .................................... 101

PUBLICATIONS

Additional technical information ............... 173

RREFACING

Refacing a drill collar shoulder .................. 149ROTATING DRILLING HEADS

Air drilling ............................................... 159API ring joint flange data .......................... 168Applications ............................................. 159Body assembly ......................................... 161Bowl assembly ......................................... 161Drive bushing assembly ............................ 162Drive ring and bearing assembly ............... 162Flow drilling ............................................. 160Gas drilling .............................................. 159Geothermal drilling .................................. 160Geothermal model .................................... 166Lubricator system ..................................... 162Model 7068 .............................................. 164Model 7368 .............................................. 164Model 8068 .............................................. 165Model DHS 1400 ...................................... 163Model RDH 2500 - high-pressure

drilling head ......................................... 166Stack alignment ........................................ 167Standard heads ........................................ 163Stripper rRubber ....................................... 162System components .................................. 161Underbalanced drilling ............................. 160

RSC Rotary shouldered connection

interchange list ..................................... 96

SSERVICES

International inspection services ............... 156SHOCK ABSORBERS

Downhole vibrations ................................ 22Improve hole opener performance

using a vibration dampener and stabilizers ................................ 23

SHOP WORK

Know field shop work .............................. 66SHOULDER REFACING

Refacing a drill collar shoulder .................. 149

MAKEUP continuedHookups used to make up

drill collar connections .......................... 43How to apply and measure

makeup torque ...................................... 51How does the ATCS help .......................... 52Hydraulic line pull devices ........................ 52Hydraulic load cells .................................. 51Initial makeup of new drill collars ............. 39 Recommended minimum drill collar



makeup torque [N·m]............................ 62Rig Catheads ............................................ 51Recommended identification groove

and marking of drill pipe ..................... 122Recommended practice for marking on

tool joints for identification of drill string components ...................... 119

MATERIAL

Material and welding precautions for downhole tools ..................................... 102

MEASUREMENTS

New kelly measurements .......................... 136MILL CODES

Pipe mill codes to be stencilled at base of tool joint pin ............................. 119

PPACKED HOLE ASSEMBLY

Clearance between wall of hole and stabilizers ....................................... 11

Considerations when designing apacked hole assembly .......................... 10

Length of tool assembly ............................ 10Medium crooked hole country .................. 13Mild crooked hole country ........................ 12Mild, medium and severe crooked

hole country ......................................... 14Severe crooked hole country ..................... 14Stiffness of drill collars ............................. 11Wall support and length of

contact tool ........................................... 12PACKED HOLE THEORY ...................................... 9PACKED PENDULUM .......................................... 20PARALLEL MISALIGNMENT

Bit stabilization - parallel misalignment ..... 32PENDULUM THEORY .......................................... 8

Index 189Index188

TOOL JOINTS continuedPipe mill codes to be stencilled at

base of tool joint pin ............................. 119Pipe weight code ...................................... 123Recommended identification groove

and marking of drill pipe ....................... 122Recommended practice for marking

on tool joints for identification of drill string components ...................... 119

TORQUE

Automatic torque control system ............... 51Ezy-Torq hydraulic cathead ....................... 52How to figure the drill collar makeup

torque needed ....................................... 41Hookups used to make up drill

collar connections ................................. 43Apply and measure makeup torque .......... 51How does the ATCS help .......................... 52Hydraulic line pull devices ........................ 52Hydraulic load cells .................................. 51Recommended minimum drill collar



makeup torque [N·m] ........................... 62Rig catheads ............................................. 51Torque chart drill pipe tool joint

recommended minimums ...................... 130Torque control - drill collars ...................... 39

TRANSITION ZONE

Using Hevi-Wate drill pipe in thetransition zone between drill

collars and drill pipe .......................... 107

VVIBRATION DAMPENERS

Downhole vibrations ................................ 22Improve hole opener performance using

a vibration dampener and stabilizers ..... 23

WWEIGHTS

Drill collar weight [kg/m] ......................... 75Drill collar weight [lb/ft] .......................... 73Weight of 31 ft drill collar [lb] ................... 72Weight of 9.4 m drill collar [kg] ................ 74

SLIP

Slip and elevator recesses on drill collars ........................................... 69

SPIRAL

Spiral drill collars ..................................... 68SQUARE KELLY

Dimensional data ..................................... 136STABILIZATION

Bit stabilization - angular misalignment .... 32Bit stabilization - parallel misalignment ..... 32Bit stabilization pays off ........................... 31Bottom-hole assemblies - stabilization ....... 15

medium and severe crooked hole country in hard to medium-

hard formations .............................. 19Mild, medium and severe crooked

hole country in hard to medium-hard formations .................... 17

Mild, medium and severe crooked hole country in medium-hard

to soft formations .............................. 19Stabilization improves bit performance ..... 31Packed hole assembly - clearance

between wall of hole and stabilizers ...... 11STIFFNESS

Packed hole assembly - stiffness of drill collars ....................................... 11

STRAIGHT HOLE DRILLING .................................. 2STRESS RELIEF

Stress relief of drill collar connections ....... 68SYSTEMATIC FIELD INSPECTION ............................ 143

TTAPERED DRILL STRINGS .................................... 113TENSION

Drill pipe and drill collar safety factor - tension, compression and neutral zone .. 71

THREAD FORMS

Oilfield thread forms ................................ 97TOOL JOINT IDENTIFIER .................................... 153TOOL JOINTS ................................................... 117

Dimensional identification - heavy-weight, grade E drill pipe ............ 124

Dimensional identification - heavy-weight, high-strength drill pipe .... 125

Dimensional identification - standard weight, grade E drill pipe ........ 124

Dimensional identification - standard weight, high-strength drill pipe ................. 125

Pipe grade codes to be stencilled at base of tool joint pin .......................... 120

Index190

Notes

drilling assembly handbook

Documents

hole assembly

usable hole

size hole

drilling handbook

entire drilling assembly

drill collar weight

specific drilling problems

controlled deviation