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 77205-0068 U.S. and Canada: 800-US SMITH · Tel: 281-443-3370 Fax: 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 Marketing Services 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.

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TABLE OF CONTENTS Bottom-Hole Assemblies ..............................

PREFACE 1

Differential Pressure Sticking ........................ 27 Bit Stabilization ...........................................

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Drill Collar ................................................... 37 Hevi-WateT Drill Pipe ................................... 105 Tool Joints ................................................... 117 Kellys .......................................................... 135 Inspection .................................................... 143 Rotating Drilling Heads ................................ 159 Additional Information ................................. 173 Index ........................................................... 179

This handbook has been altered you should engineers to help rig personnel do a better job. It summarizes proven drilling techniques and technical data that, hopefully, will enable you to drill a usable hole at the lowest possible cost. Carry it in your hip pocket for easy reference. If there are any questions about the Drilling Handbook, just call your nearest Smith representative or talk with our service people when they visit your rig. The Field Operations, Sales, Business Development and Engineering Departments.

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HOW TO USE THIS HANDBOOK The Drilling Assembly Handbook is broken down into eleven (11) major sections, as described in the table of contents. A detailed index is provided starting on page 179. The topics in the index will give the page numbers of information relating to specific drilling problems which you might face on the rig floor. If you have any suggestions on how we can make this handbook work better for you, please send them to us or tell your Smith representative. Refer suggestions to: Reader Service Dept. Smith International P.O. Box 60068 Houston, Texas 77205-0068

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SECTION ONE

BOTTOM-HOLE ASSEMBLIES

Bottom-Hole Assemblies

BOTTOM-HOLE ASSEMBLIES Introductory Comments on Bottom-Hole Assemblies The title of this publication is “Drilling Assembly Handbook” and most of the pages are devoted to the entire drilling assembly, from the swivel to the bit. We have included useful information about the rotary shouldered connections (pins and boxes) that are used on every drill stem member. In this section, however, we are primarily interested in the bottom-hole assembly — the tools between the bit and the drill pipe. Over the years, the bottom-hole assembly has grown from one or two simple drill collars to quite a complex array of tools, stacking up above the bit about 500 to 1,000 ft (150 to 300 m). Our job in this rig floor pocketbook is to simplify the complexities of all these tools. We’ll explain the purposes of each one and how to select and assemble them for maximum effectiveness and minimum trouble. Today the bottom-hole assembly serves several useful purposes, in addition to the simple need to effectively 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 these desirable objectives can be attained.

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STRAIGHT HOLE DRILLING A better title would probably be “Controlled Deviation Drilling” because it has been learned through the years that a perfectly straight hole is virtually impossible to drill. No one knows the exact cause of holes going crooked but some logical theories have been presented. It has been confirmed that the drilling bit will try to climb uphill or updip in laminar formations with dips up to 40° (see Figure No. 1).

Figure No. 1

Another factor to consider is the bending characteristic of the drill stem. With no weight on the bit, the only force acting on the bit is the result of the weight of the portion of the string between the bit and the tangency point. This force tends to bring the hole toward vertical. When weight is applied, there is another force on the bit which tends to direct the hole away from vertical. The resultant of these two forces may be in such a direction as to increase angle, to decrease angle or to maintain constant angle. This was stated by Arthur Lubinski (research engineer for Amoco) at the spring meeting of the Mid-Continent District, Division of Production, in Tulsa, March 1953, and was based upon the assumption that the drill stem lies on the low side of an inclined hole (see Figure No. 2). In general, it is easier to drill a hole in soft formations than in hard formations. In particular, the effect of the drill stem bending may be much less when drilling soft formations, while the hard formations require high bit weights.

Figure No. 2

In a straight hole drilling contract, many of the possible troubles can be prevented by obtaining satisfactory contract terms on deviation and doglegs. It is extremely important, when negotiating the contract itself, that the operator be aware of the advantages in giving the broadest possible limits for deviation. By relaxing deviation clauses to reasonable limits, it is possible to drill a so-called straight hole at high rates of penetration and avoid the costly operations of plugging back and straightening the hole. In addition to the operator’s deviation limits, it may be possible to work with him to select a location so that the well may be allowed to drift into the target area. If it is desired to reach a certain point on the structure, and it is known that the 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 will drift into the target area. From the contractor’s standpoint, valuable time can be spent in planning the drill stem and the bit program along with the hydraulics. Drift planning will include obtaining the largest drill collars that may be safely run in a given hole size and planning for optimum bit weights to get the best rate of penetration. If it is anticipated that there will be a problem maintaining the deviation within the contract limits, there are more extreme methods available which will assure a more nearly vertical hole and still allow relatively high rates of penetration.

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Arthur Lubinski and Henry Woods (research engineer for Hughes Tool Co.) were among the first to apply mathematics to drilling. They stated in the early 1950s that the size of the bottom drill collars would be the 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 OD MEHD = 2 Robert S. Hoch (engineer for Phillips Petroleum Company) theorized that, while drilling with an unstable bit, an abrupt change can occur if hard ledges are encountered (see Figure No. 3). He pointed out that a dogleg of this nature would cause an undersized hole, making it difficult or maybe impossible to run casing. Hoch rewrote Lubinski’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 bit 244.5 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 Minimum permissible drill collar OD = 2 (casing coupling OD) – Bit OD Robert S. Hoch

Drift diameter =

Bit OD + collar OD 2

Woods and Lubinski

Figure No. 3


WHY RESTRICT TOTAL HOLE ANGLE? Total hole angle should be restricted (1) to stay on a particular lease and not drift over into adjacent property; (2) to ensure drilling into a specific pay zone like a stratigraphic trap, a lensing sand, a fault block, etc.; or (3) to drill a near vertical hole to meet legal requirements from regulatory agencies, field rules, etc. The restriction of total hole angle may solve some problems but it is not a cure-all. As can be seen in Figure No. 4, the typical 5° limit does not assure 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 1960s that the rate of hole angle change should be the main concern, not necessarily the maximum hole angle. He expressed this rate of hole angle change in degrees per 100 ft. In 1961 an API study group published a tabular method of determining maximum permissible doglegs that would be acceptable in rotary drilling and completions. Therefore, the main objective is to drill a “useful” hole with a fullgage, smooth bore, free from doglegs, key seats, offsets, spirals and ledges. A key seat is formed after part of the drill pipe string has passed through the dogleg. Since the drill pipe is in tension, it is trying to straighten itself while going around the dogleg. This creates a lateral force that causes the drill pipe to cut into the center of the bow as it is rotated (see Figure No. 5). This force is proportional to the amount of weight hanging below the dogleg. A key seat will be formed only if the formation is soft enough and the lateral force great enough to allow penetration of the drill pipe. When severe doglegs and key seats are formed, many problems can develop.

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6 Dogleg

Key seat

Tension

Tension

Top view of key seat section Lateral force

Bottom-Hole Assemblies age will build up rapidly and failure of the pipe is likely. It can be seen from this plot that if a dogleg is 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 larger change in angle can be tolerated. Endurance Limit for 41/2 in., 16.60 lb/ft Grade E Drill Pipe in 10 lb/gal Mud (Gradual Dogleg)

Tension

Tension

Figure No. 5

PROBLEMS ASSOCIATED WITH DOGLEGS AND KEY SEATS Drill Pipe Fatigue Lubinski presented guidelines in 1961 for the rate of change of hole angles. He said that if a program is designed in such a way that drill pipe damage is avoided while drilling the hole, then the hole will be acceptable for conventional designs of casing, tubing and sucker rod strings as far as dogleg severity is concerned. A classical example of a severe dogleg condition which produces fatigue failures in drill pipe can be seen in Figure No. 5. The stress at Point B is greater than the stress at Point A; but as the pipe is rotated, Point A moves from the inside of the bend to the outside and back to the inside again. Every fiber on the pipe goes from minimum tension to maximum tension and back to minimum tension again. Cyclic stress reversals of this nature cause fatigue failures in drill pipe, usually within the first two feet of the body adjacent to the tool joint, because of the abrupt change of cross section. Lubinski suggested that to avoid rapid fatigue failure of pipe, the rate of change of the hole angle must be controlled. Suggested limits can be seen in Figure No. 6. This graph is a plot of the tension in the pipe versus change in hole angle in degrees per 100 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 represents stress endurance limits of the drill pipe under various tensile loads and in various rates of change in hole angle. If conditions fall to the left of this curve, fatigue damage to the drill pipe will be avoided. To the right of the curve, fatigue dam-

Figure No. 6

If the stress endurance limit of the drill pipe is exceeded because of rotation through a dogleg, an expensive fishing job or a junked hole might develop. Stuck Pipe Sticking can occur by sloughing or heaving of the hole and by pulling the large OD drill collars into a key seat while pulling the drill stem out of the hole. Logging Logging tools and wirelines can become stuck in key seats. The wall of the hole can also be damaged, causing hole problems. Running Casing Running casing through a dogleg can be a very serious problem. If the casing becomes stuck in the dogleg, it will not extend through the productive zone. This would make it necessary to drill out the shoe and set a smaller size casing through the productive interval. Even if running the casing to the bottom through the dogleg is successful, the casing might be severely damaged, thereby preventing the running of production equipment. Cementing The dogleg will force the casing over tightly against the wall of the hole, preventing a good cement bond because no cement can circulate between the wall of the hole and the casing at this point.

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Bottom-Hole Assemblies Casing Wear While Drilling The lateral force of the drill pipe rotating against the casing in the dogleg or dragging through it while tripping can cause a hole to wear through the casing. This could cause drilling problems and/or possible serious blowouts. Production Problems It is better to have a smooth string of casing to produce through. Rod wear and tubing leaks associated with doglegs can cause expensive repair jobs. It may be difficult to run packers and tools in and out 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 possible causes of bit deviation and the problems associated with crooked holes, let’s look at two possible solutions using the pendulum and the packed hole concepts. Pendulum Theory In the early 1950s, Woods and Lubinski collaborated in mathematical examination of the forces on a rock bit when drilling in an inclined hole. In order to make their calculations, they made three basic 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 which it is aimed. Consequently, the forces which act upon the bit can 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 contact with the wall of the hole by the drill collar (pendulum force). Pendulum force is the tendency of the unsupported length of drill collar to swing over against the low side of the hole because of gravity. It is the only force that tends to bring the hole back toward vertical (see Figure No. 7).


(Pendulum force) Restoring force of drill collar weight

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Height to point of tangency

Reaction of formation

Figure No. 7

3. The reaction of the formation to these loads may be resolved into two forces — one parallel to the axis of the hole and one perpendicular to the axis 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 necessary weight for the bit to maintain a certain hole angle. These tables also show the proper placement of a stabilizer to give the maximum pendulum force and the maximum weight for the bit. The effects of using larger drill collars can also be determined. These tables or graphs may be obtained from your Smith representative. They are called “Drilling Straight Holes in Crooked Hole Country,” Publication No. 59 (see page 174 for details). Packed Hole Theory Most people today use a packed hole assembly to overcome crooked hole problems and the pendulum is used only as a corrective measure to reduce angle when the maximum permissible deviation has been reached. The packed hole assembly is sometimes referred to as the “gun barrel” approach because a series of stabilizers is used in the hole already drilled to guide the bit straight ahead. The objective is to select a bottom-hole assembly to be run above the bit with the necessary stiffness and wall contact tools to force the bit to drill in the general direction of the hole already drilled. If the proper selection of drill collars and bottom-hole tools is made, only gradual changes in hole angle

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will develop. This should create a useful hole with a full-gage and smooth bore, free from doglegs, key seats, offsets, spirals and ledges, thereby making it possible to complete and produce the well (see Figure No. 8).

Figure No. 9

Figure No. 8

FACTORS TO CONSIDER WHEN DESIGNING A PACKED HOLE ASSEMBLY Length of Tool Assembly It is important that wall contact assemblies provide sufficient length of contact to assure alignment with the hole already drilled. Experience confirms that a single stabilizer just above the bit generally acts as a fulcrum or pivot point. This will build angle because the lateral force of the unstabilized collars above will cause the bit to push to one side as weight is applied. Another stabilizing point, for example, at 30 ft (10 m) above the bit will nullify some of the fulcrum effect. With these two points, this assembly will stabilize the bit and reduce the tendency to build hole angle. It is, however, not considered the best packed hole assembly. As shown in Figure No. 9, two points will contact and follow a curved line. But add one more point with a stiff assembly, and there is no way you can get three points to contact and follow a sharp curve. Therefore, three or more stabilizing points are needed to form a packed hole assembly.

Stiffness Stiffness is probably the most misunderstood of all the points to be considered about drill collars. Few people realize the importance of diameter and its relationship to stiffness. If you double the diameter of a bar, its stiffness is increased 16 times. For example, if an 8 in. (203.2 mm) diameter bar is deflected 1 in. (25.4 mm) under a certain load, 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 stiffness of popular drill collars of various diameters. OD ID (in.) (in.) 51/4 21/4 1 6 /4 21/4 1 6 /2 21/4

I 29 74 86

OD ID (in.) (in.) 63/4 21/4 1 7 /4 213/16 81/4 213/16

I 100 115 198

OD ID (in.) (in.) 9 213/16 10 313/16 11 313/16

I 318 486 713

Large diameter drill collars will help provide the ultimate in stiffness, so it is important to select the maximum diameter collars that can be safely run. Drill collars increase in stiffness by the fourth power of 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 times stiffer than an 8 in. (203.2 mm) diameter drill collar while all three sizes may be considered appropriate for drilling a 121/4 in. (311.2 mm) hole. Clearance There needs to be a minimum clearance between the wall of the hole and the stabilizers. The closer the stabilizer is to the bit, the more exacting the clearance requirements are. If, for example, 1/16 in. (1.6 mm) undergage from hole diameter is satisfactory just above the bit, then 60 ft (18.3 m) above the bit, 1/8 in. (3.2 mm) clearance may be close enough.

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Bottom-Hole Assemblies In some areas, wear on contact tools and clearance can be a critical factor for a packed hole assembly. Wall Support and the Length of Contact Tool Bottom-hole assemblies must adequately contact the wall of the hole to stabilize the bit and centralize the drill collars. The length of contact needed between the tool and the wall of the hole will be determined by the formation. The surface area in contact must be sufficient to prevent the stabilizing tool from digging 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, a short narrow contact surface is adequate and will ensure proper stabilization. On the other hand, if the formation is soft and unconsolidated, a long blade stabilizer may be required. Hole enlargements in formations that erode quickly tend to reduce effective alignment of the bottom-hole assembly. This problem can be reduced by controlling the annular velocity and mud properties.

PACKED HOLE ASSEMBLIES Proper design of a packed hole assembly requires a knowledge of the crooked hole tendencies and drillability of the formations to be drilled in each particular area. For basic design practices, the following are 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 Country The packed hole assembly shown in Figure No. 10 for mild crooked hole country is considered the minimal assembly for straight hole drilling and bit stabilization. Three points or zones of stabilization are provided by Zone 1 immediately above the bit, Zone 2 above the large diameter short drill collar and Zone 3 atop a standard length large diameter collar. A vibration dampener, when used, should be placed above Zone 2 for the best performance. In very mild crooked hole country the vibration dampener may be run in the place of the short drill


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collar between Zone 1 and Zone 2. When rough drilling conditions are encountered, a vibration dampener will increase penetration rate and add life to the drill bit. Wear and tear on the drilling rig and drill stem will also be reduced. Mild Crooked Hole Country (Minimal Assembly) Zone 3

String stabilizer 30 foot large diameter drill collar Vibration dampener (when used)

Zone 2

String stabilizer Large diameter short drill collar

Zone 1

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

Figure No. 10

Medium Crooked Hole Country A packed hole assembly for medium crooked hole country is similar to that for mild crooked hole conditions but with the addition of a second stabilizing tool in Zone 1. The two tools run in tandem provide increased stabilization of the bit and add stiffness to limit angle changes caused by lateral forces (see Figure No. 11). Medium Crooked Hole Country Zone 3

String stabilizer 30 foot large diameter drill collar Vibration dampener (when used)

Zone 2 Dual stabilizers Zone 1

String stabilizer Large diameter short drill collar String stabilizer Bottom hole stabilizer Bit

Figure No. 11


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Severe Crooked Hole Country In severe crooked hole country three stabilization tools are run in tandem in Zone 1 to provide maximum stiffness and wall contact to aim and guide the bit. In 83/4 in. (222.3 mm) and smaller hole sizes, it is also recommended that a large diameter short collar be used between Zone 2 and Zone 3. This will increase stiffness by reducing the deflection of the total assembly. It will allow the tools in Zone 1 and Zone 2 to perform their function without excessive wear due to lateral thrust or side-loading from excess deflection above (see Figure No. 12). Severe Crooked Hole Country Zone 3

String stabilizer 30 foot large diameter drill collar

*

Vibration dampener (when used) String stabilizer Large diameter short drill collar String stabilizer Zone 1 String stabilizer Bottom hole stabilizer Bit *Note: Use short drill collar in 83/4 in. and smaller holes. Zone 2


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

STABILIZING TOOLS There 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 Blade A rotating blade stabilizer can be a straight blade or spiral blade configuration, and in both cases the blades 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 repairable and (b) rig repairable.

Tandem stabilizers

Stg. RWP

Stg. I.B.

Stg. rig replaceable sleeve

Figure No. 12

Mild, Medium and Severe Crooked Hole Country Figure No. 13 shows all three basic assemblies required to provide the necessary stiffness and stabilization for a packed hole assembly. A short drill collar is used between Zone 1 and Zone 2 to reduce the amount of deflection caused by the drill collar weight. As a general rule of thumb, the short drill collar length in feet is approximately equal to the hole size in inches, plus or minus 2 ft. For example: a short collar length of 6 to 10 ft would be satisfactory in an 8 in. hole. Mild

Medium

Severe

Zone 3

Zone 2 * Short drill collar

*

*

Zone 1 * 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 ft collar in an 8 in. diameter hole.

Figure No. 13

Stg. welded blade

Figure No. 14

a. Shop Repairable The shop repairable tools are either integral blade, welded blade or shrunk on sleeve construction. Welded blade stabilizers are popular in soft formations but are not recommended in hard formations because of rapid fatigue damage in the weld area. b. Rig Repairable Rig repairable stabilizers either have a replaceable metal sleeve like the Ezy-ChangeE stabilizer or replaceable metal wear pads like the RWP T (Replaceable Wear Pad) stabilizer. These tools were originally developed for remote locations but are now used in most areas of the world.


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All rotating stabilizers have fairly good reaming ability and because of recent improvements in hardfacing, have very good wear life. Some of the hardfacing 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 Stabilizer The non-rotating sleeve tool is a very popular stabilizer because it is the safest tool to run from the standpoint of sticking and washover. This type of stabilizer is most effective in areas of hard formations such as lime and dolomite. Since the sleeve is stationary, it acts like a drill bushing and, therefore, will not dig into and damage the wall of the hole. It does have some limitations. The sleeve is not recommended to be used in temperatures over 250°F (121°C). It has no reaming ability and sleeve life may be short in holes with rough walls (see Figure No. 15).


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Figure No. 16

3 point BH reamer

MILD, MEDIUM AND SEVERE CROOKED HOLE COUNTRY IN HARD TO MEDIUM-HARD FORMATIONS In Zone 1-A (directly above the bit), a rolling cutter reamer (see Figure No. 17) should be used when bit gage is a problem in hard and abrasive formations. A six-point tool is required for extreme conditions. In non-abrasive formations, some type of rotating blade tool with hardfacing is desirable. Mild, Medium and Severe Crooked Hole Country Hard to Medium-Hard Formations Zone 3

6 point BH RWP BH reamer 3 point BH rig BH I.B. replaceable BH reamer sleeve

Figure No. 15 Zone 2

Or

Or

Or

Zone 1 Mild Med. Sev.

Non-rotating stabilizer

3. Rolling Cutter Reamer Rolling cutter reamers are used for reaming and added stabilization in hard formations. Wall contact area is very small, but it is the only tool that can ream hard rock effectively. Anytime rock bit gage problems are encountered, the lowest contact tool should definitely be a rolling cutter reamer (see Figure No. 16).

Zone 1-A Zone 1-A (abrasive) (non-abrasive) Note: Use a reamer if the bit gage is a problem. Use a 6 point in extremely hard and abrasive formations.

Figure No. 17


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Rotating blade-type tools are effective in Zone 2 for all three conditions of crooked hole tendencies. In very mild crooked hole country, a non-rotating sleeve-type tool will be all right (see Figure No. 18). Mild, Medium and Severe Crooked Hole Country Hard to Medium-Hard Formations Zone 3

Stg. RWP Stg. rig Stg. I.B. replaceable sleeve

Zone 2

Or

Or


MEDIUM AND SEVERE CROOKED HOLE COUNTRY IN HARD TO MEDIUM-HARD FORMATIONS In Figure No. 20, it is shown that some type of rotating blade stabilizer is recommended in Zone 1-B with hard to medium-hard formations and medium to severe crooked hole tendencies. For severe crooked hole drilling, one of the same types of tools can be used in Zone 1-C. Mild, Medium and Severe Crooked Hole Country Hard to Medium-Hard Formations


Zone 2 Note: In very mild crooked hole country, a non-rotating stabilizer may be used in Zone 2.

Stg. RWP Stg. rig replaceable Stg. I.B. sleeve

Zone 3

Or

Zone 2

Figure No. 18

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Or

Zone 1

With the slightest deviation from vertical, drill collars will lie on the low side of the hole because of their enormous weight. Therefore, the function of Zone 3 is to centralize the drill collars above Zone 2. Both the rotating blade and the non-rotating sleeve stabilizers may be used for this job in hard to medium-hard formations (see Figure No. 19). Mild, Medium and Severe Crooked Hole Country Hard to Medium-Hard Formations Non-rotating Zone 3

Zone 2

Stg. rig replaceable Stg. I.B. sleeve

Or

Or

Zone 1-B Med. Sev.

Note: The same tools would be used in Zone 1-C for severe crooked hole country.

Figure No. 20

MILD, MEDIUM AND SEVERE CROOKED HOLE COUNTRY IN MEDIUM-HARD TO SOFT FORMATIONS Tools for use in medium-hard to soft formations, where the bit gage is no problem, must provide maximum length of wall contact to provide proper stabilization to the drill collars and bit. For all degrees of crooked hole tendencies, rotating blade stabilizers are recommended (see Figure No. 21).

Zone 1 Zone 3 Mild Med. Sev.

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

Figure No. 19 Zone 3

Any stabilizers run above Zone 3 are used only to prevent the drill collars from buckling or becoming “wall stuck,” and in most cases, will have very little effect on directing the bit.

BH RWP Stg. RWP Stg. rig BH I.B. replaceable BH rig Stg. I.B. sleeve replaceable sleeve

Zone 2

Or

Or

Or

Or


Zone 1-A

Figure No. 21

Zone 1-B & C Zone 2 Zone 3


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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 more convenient to work through than one drilled at minimum hole angle with many ledges, offsets and sharp angle changes. 2. Improve bit performance and life by forcing the bit to rotate on a true axis about its design center, thus loading all cones equally. 3. Improve hole conditions for drilling, logging and running casing. Maximum size casing can be run to bottom. 4. Allow use of more drilling weight through formations which cause abnormal drift. 5. Maintain desired hole angle and course in directional drilling. In these controlled situations, high angles can be drilled with minimum danger of key seating or excessive pipe wear.

PACKED PENDULUM Because all packed hole assemblies will bend, however small the amount of deflection, a perfectly vertical hole is not possible. The rate of hole angle change will be kept to a minimum but occasionally conditions will arise where total hole deviation must be reduced. When this condition occurs, the pendulum technique is employed. If it is anticipated that the packed hole assembly will be required after reduction of the hole angle, the packed pendulum technique is recommended. In the packed pendulum technique, the pendulum collars are swung below the regular packed hole assembly. When the hole deviation has been reduced to an acceptable limit, the pendulum collars are removed and the packed hole assembly again is run above the bit. It is only necessary to ream the length of the pendulum collars prior to resuming normal drilling. If a vibration dampening device is used in the packed pendulum assembly, it should remain in its original position during the pendulum operations (see Figure No. 22).


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Packed Pendulum Packed hole assembly Vibration dampener

Drill collars

Bit

Pendulum

Figure No. 22

REDUCED BIT WEIGHTS One of the oldest techniques for straightening the hole is to reduce the weight on the bit and speed up the rotary table. By reducing the weight on the bit, the bending characteristics of the drill stem are changed and the hole tends to be straighter. In recent years it has been found that this is not always the best procedure because reducing the bit weight sacrifices considerable penetration rate. Worse, it frequently brings about doglegs as illustrated in Figure No. 23. As a point of caution, the straightening of a hole by reducing bit weight should be done very gradually so the hole will tend to return to vertical without sharp bends and will be much safer for future drilling. A reduction of bit weight is usually required when changing from a packed hole assembly to a pendulum or packed pendulum drilling operation. An under-gage stabilizer is sometimes run immediately above the bit to prevent dropping angle too quickly.

Figure No. 23


22

CONCLUSION In summation, a well-engineered bottom-hole assembly, with the proper selection of stabilizing tools in all three zones, should produce a useful hole with a full-gage, smooth bore free from doglegs, key seats, offsets, spirals and ledges, thereby making it possible to complete and produce the well. Both the drilling contractor and oil company operator should realize additional profits from a well-planned program. 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 successful downhole vibration dampener to meet a very obvious need. Drillers were having 10 to 15 drill collar failures per well in 121/4-in. (311.2 mm) holes going to 6,000 ft (1,830 m) in a rough-running area. Ordinary measures failed to solve the problem. The Shock Sub T or vibration dampener was introduced into the drill stem and the drill collar failures were reduced. A second benefit was increased bit life. A third benefit was then achieved by increasing both rotary speed and bit weight and further stepping up daily drilling depth. In rough-running areas, the downhole 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 bottom of the hole. Using a downhole instrumentation sub, they measured among other things bit weight, rotary speed, vertical vibrations and bending stress in the sub. Without even being aware of it at the surface, small changes in such things as rotary speed, bit weight or formation can cause fantastic gyrations to occur at the bottom of the hole. Vibrations develop that cause impact loads on the bit several times the load indicated at the surface. Bending loads in the sub increase by perhaps 10 times. These events indicate how vague our knowledge of “downhole dynamics” really is. We’ve learned to cope with them to some degree.


IMPROVE HOLE OPENER PERFORMANCE BY USING A VIBRATION DAMPENER AND STABILIZERS Hole opening performance can improve with the use of a vibration dampener and a stabilizer. 1. Stabilizer A stabilizer placed at 60 ft (18.3 m) and 90 ft (27.4 m) in the drill stem will help to minimize drill collar bending. 2. Drill Collar Higher stress concentrations exist in the connection. Add to this the bouncing of the drill stem caused by rough running and the result can be drill collar connection failures. 3. Stabilizers A stabilizer will center the collars in the hole above the hole opener and make the load on the cutters more uniformly distributed. 4. Vibration Dampener A vibration dampener will minimize vibrations caused by the hole opener stumbling over broken formations and reduce the shock loads on the cutters and the drill collars. 5. Hole Openers The collars are so much smaller than the hole, they bend and whip, loading first one cutter, and then the next. They put a terrific side load on the pilot bit, and the hole opener body. The vibration dampener, with the stabilizer can help eliminate this.

23


24 Notes

2

SECTION TWO

DIFFERENTIAL PRESSU STICKING

Differential Pressure Sticking

DIFFERENTIAL PRESSURE STICKING OF DRILL PIPE AND DRILL COLLARS Differential wall sticking is caused by the drill pipe or drill collars blocking the flow of fluid from the borehole into the formation. In a permeable formation, where the mud column hydrostatic head is higher than the pressure in the formation, the fluid loss can be considerable. Associated with the flow of fluid into the formation is a filtering of solids at the wall of the hole and a resultant build up of filter cake. The smooth surfaces of the tools, assisted by the sealing effect of the filter cake, form an effective block to fluid losses into the formation. Depending on length of blocked area, and differences in borehole and formation pressures, this blockage of fluid flow may permit extremely high forces to build up against the tools in the hole, and thus the drill stem becomes differentially wall stuck. The use of a packed hole assembly will eliminate many of the conditions which result in sticking of the drill stem by holding the drill stem off the wall of the hole. Such bit stabilizing assemblies also help prevent sudden hole angle changes, offsets and doglegs which lead to sticking the drill stem 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 centralizers to hold the heavy-wall tube sections off the wall of 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 passage and equalizing of bore pressure around the collars. The box end of all sizes of spiral drill collars 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 of all sizes of drill collars 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.

27

Differential Pressure Sticking

28

Stabilizers (see Figure No. 24) Stabilizers positioned throughout the drill stem are another positive way of preventing differential sticking. Rotating blade, welded blade and nonrotating sleeve-type stabilizers are used to keep the drill collars centered in the hole. Selection of the type of stabilizers and their spacing in the drill stem varies with the formation being drilled, the size of the hole, etc. Your Smith representative can provide field data for your area. Conventional drill collar

IB stabilizer

Hevi-Wate drill pipe

Spiral drill collar Stuck area Hydra-shock® Spiral equalizes pressure in stuck area

IB stabilizer

IB stabilizer (Integral blade)

Near Bit IB Stabilizer

Figure No. 24

3

SECTION THREE

BIT STABILIZATION

Bit Stabilization

BIT STABILIZATION PAYS OFF About 55 years ago, bit engineers wondered why 77/8 in. (200.0 mm) bits performed better than 83/4 in. (222.3 mm) bits. Then they realized both sizes of bits were run with 61/4 in. (158.8 mm) drill collars. The 77/8 in. (200.0 mm) bits were clearly better stabilized than the 83/4 in. (222.3 mm) bits. Since that time the art of bit stabilization has continued to improve. About 40 years ago a case developed where a certain section in offset wells required 2,000 hours to drill in one case, and only 1,200 hours in the other. All of the normally recorded conditions on the bit records were the same. Then it was realized that small limber drill collars were used in the first case and a fairly well-stabilized bottom assembly in the other. More recently drillers have been employing bottom-hole assemblies described on pages 12 through 20 to get the very most out of every bit. The better the bit is stabilized, the better it performs. Large size bits have been notoriously neglected in the application of stabilization techniques. For example, 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, because they only drilled very soft formations with such large bits. Now, in coping with hard formations in these hole sizes, it is becoming quite apparent that the principles developed for smaller holes should also be extended to the larger ones. We suggest you employ the stiff, stabilizing assemblies described in this book with every bit you dull. They’ve been proven in hole sizes all the way up to 120 in. (3,048 mm)!

STABILIZATION IMPROVES BIT PERFORMANCE Rock bits are designed to rotate about the axis of the hole. Their service life is shortened when the axis is misaligned. This misalignment may be parallel or angular. When the axis at the bottom of the hole shifts in a parallel manner, the bit runs off center (see Figure No. 25). This causes the cutting structure to wear pick-shaped. Rings of uncut bottom develop and bit life is drastically reduced.

31

Bit Stabilization

32

If the drill collar directly above the bit leans against the hole wall, angular misalignment occurs. The penalty on bit performance depends on the degree of misalignment. For example, in an 83/4 in. (222.3 mm) hole, 7 in. (177.8 mm) collars reduce the effect to some degree, but misalignment still exists. Angular misalignment permits two very harmful effects to exist. First, the full weight on the bit is shifted from one cone to the other, causing rapid breakdown of tooth structure and bearings. Weight should be evenly distributed on all three cones. The second bad effect is the breakdown of the vital gage cutting surfaces at the tops of the outer tooth rows. “Apple-shape” cones result and bit life suffers greatly (see Figure No. 27). Dramatic improvements in bit life have been observed in shifting from non-stabilized to stabilized bottom-hole assemblies, particularly when diamond bits, PDC bits, journal bearing or sealed bearing bits are being run. Avoid both angular and parallel misalignment with properly selected stabilizing assemblies. The higher the degree of stabilization, the greater the benefits.

Bit Stabilization

Figure No. 27

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

Figure No. 28

Figure No. 28 shows a photograph of a medium formation bit that has suffered gage wear and gage rounding due to angular misalignment.

Figure No. 29

Figure No. 25

Figure No. 26

Parallel Misalignment Parallel misalignment is caused by the use of small drill collars (in relation to the hole size) and no stabilization. The bit can move off center until the drill collars’ OD contacts the wall of the hole. This results in an offset due to drilling off center.

Angular Misalignment Angular misalignment is caused by the use of small drill collars (in relation to the hole size) and no stabilization. Most or all of the bit load is applied to one cone at a time, causing rapid breakdown and failure of both the cutting structure and bearing structure of the bit.

Figure No. 29 shows a photograph of a bit that has suffered severe damage to the gage and OD of the bit itself. The lugs have worn so badly that the shirttails are gone and some of the roller bearings are missing. The bit was run too long in an abrasive 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 be reamed out to the new bit gage.

33

Bit Stabilization

34

Figure No. 30

Figure No. 30 shows a photograph of a broken medium, soft to medium bit that has been run without the support of a dampening device. A vibration dampener run in the bottom-hole assembly will help obtain a faster rate of penetration and increased bit life. When drilling in broken hard formations, excessive vibration, bit bounce and shock loading can cause tooth and tungsten carbide insert breakage and rapid bearing failure. Because of rough-running in some formations, the desired weight and rotating speed cannot be utilized. The use of a vibration dampener will eliminate the damaging shock loading and help maintain a faster rate of penetration and longer bit life.

4

SECTION FOUR

DRILL COLLAR

Drill Collar

DRILL COLLAR CARE AND MAINTENANCE Don’t Ruin Those New Drill Collars Read the following statement. It may save you many headaches in the months ahead. “A new string of drill collars should give many months of trouble-free service, but they can be ruined on the first trip down the hole if they aren’t properly cleaned and lubricated, and made up with measured and controlled makeup torque. In fact, the threads or shoulders can be damaged in picking up or on initial makeup, and be ruined before they are ever run into the hole.” “Proper makeup torque, consistently measured and applied, is essential to satisfactory drill collar joint performance. Nothing that is done in design and manufacture can obviate the necessity for riglevel makeup torque control. It has to be done on the rig!” The above statement is quoted from a series of articles published in the March 1966, Oil & Gas Journal.

IMPORTANCE OF BALANCED DRILL COLLAR PIN AND BOX CONNECTIONS Drill collar manufacturers recommend connection sizes based on the balance of pin and box bending strength ratios. The formula for this calculation is in the API RP 7G. The drill collar connection, more correctly called a rotary shouldered connection, must perform several necessary functions. The connection is a tapered threaded jack screw that forces the shoulders together to form the only seal, and acts as a structural member to make the pin equally as strong, in bending, as the box when made up to the recommended torque. The threads do not form a seal. By design, there is an open channel from the bore to the shoulder seal. This space is there to

37

Drill Collar

38

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

Drill Collar 4. Lift sub pins should be cleaned, inspected and lubricated on each trip. If these pins have been damaged and go unnoticed, they will eventually damage all of the drill collar boxes. Initial Makeup of New Drill Collars 1. 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 collar joint 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.

Figure No. 31

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

RECOMMENDED DRILL COLLAR CARE AND MAINTENANCE Three points that are a must for good drill collar performance 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 Collars 1. Cast-steel thread protectors with a lifting bail, provide a means of dragging the collar into the “V” door and protecting the shoulders and threads. Remember that the pin should also be protected. 2. Connections should be cleaned thoroughly with a solvent and wiped dry with a clean rag. Inspect carefully for any burrs or marks on the shoulders. 3. A good grade of drill collar compound, containing powdered metallic zinc in the amount of 40 to 60% by weight should be applied to the threads and shoulders on both pin and box. Drill pipe lubricants without a minimum of 40 to 50% zinc are not recommended because they normally are made with lead oxide which does not have sufficient body for the high shoulder loads necessary in drill collar makeup.

Torque Control 1. 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 by the line pull in pounds is foot-pounds (ft-lb) of torque. Use feet and tenths of a foot. 1. The length of the tong arm in meters multiplied by 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 times 2,000 lb, or a total of 8,400 ft-lb of torque (see Figure 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 times 907 kg or a total of 1161 kg-m of torque (see Figure No. 32).

39

Drill Collar

40

Drill Collar Recommended Minimum Torque (ft-lb) Bore of Drill Collar (in.) Connection OD Type (in.) 21/4 21/2 213/16 3 31/4 3 NC 50 6 /4 36,700 35,800 32,200 30,000 26,600

90° 4.2 ft 2,000 lb line pull Fully effective tong arm Torque = 4.2 ft x 2,000 lb = 8,400 ft-lb

90° 4.2 ft 3,000 lb line pull Fully effective tong arm Torque = 4.2 ft x 3,000 lb = 12,600 ft-lb

45° ft

4. 2

2 4.

ft

45°

3 ft

3 ft

3,000 lb line pull

3,000 lb line pull

Ineffective tong arm Torque = 3 ft x 3,000 lb = 9,000 ft-lb

Figure No. 32

3. A line pull measuring device must be used in making up drill collars. It is important that line pull be measured when the line is at right angles (90°) to the tong handle. 4. When applying line pull to the tongs, it is better to apply a long steady pull rather than to jerk the line. Hold pull momentarily to make sure all slack is taken up. 5. The proper torque required for a specific drill collar should be taken from a table of recommended torques for drill collars. For a 63/4 in. (171.5 mm) OD x 213/16 in. (71.4 mm) ID with a NC 50 connection, the table indicates a torque of 32,200 ft-lb (4,460 kg-m) (see pages 54 through 65).

6. It should be emphasized that the torque values shown in the table are minimum requirements. The normal torque range is from the tabulated figure to 10% higher. 1. From the example above, the required torque range 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 Collars 1. It is recommended practice to break a different joint on each trip, giving the crew an opportunity to inspect each pin and box every third trip. Inspect the shoulders for signs of loose connections, galls and possible washouts. 2. Thread protectors should be used on both pin and box when picking up or laying down the drill collars. 3. Periodically, based on drilling conditions and experience, a magnetic particle inspection should be performed, using a wet fluorescent and black light method. 4. Before storing the drill collars, they should be cleaned. If necessary, reface the shoulders with a shoulder refacing tool, and remove the fins on the shoulders by beveling. A good rust preventative or drill collar compound should be applied to the connections liberally, and thread protectors installed.

HERE IS THE WAY TO FIGURE THE DRILL COLLAR MAKEUP TORQUE YOU NEED As discussed on pages 38 through 41, you must use the recommended makeup torque and this torque must be measured with an accurate device. There are two steps that must be worked out for all hookups: Step No. 1 Look in the torque tables, pages 54 to 65, and find the minimum torque recommended for the size drill collars (OD and ID) and type of connection.

41

Drill Collar

42

Step No. 2 Divide the torque value by the effective length of the tong arm (see Figure No. 33). This will give the total line pull required. Effective tong arm length

Drill Collar

43

The 8,748 lb (4,000 kg) of line pull is the total pull required on the end of this 4.2 ft (1.27 m) tong. This may or may not be the amount of line pull reading on the torque indicator, as this depends on the location of the indicator. The following pages show 15 examples of hookups used to make up drill collar connections. Select the 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 are of sufficient strength.

90°

The amount of cathead pull will be the same as the line pull reading on your Torque Indicator. Snub line

Figure No. 33

Cathead pull

Example: For 42 in. tongs, divide by 12 in. = 3.5 ft For 48 in. tongs, divide by 12 in. = 4 ft For 50 in. tongs, divide by 12 in. = 4.2 ft For 54 in. tongs, divide by 12 in. = 4.5 ft For collars with 63/4 in. OD x 21/4 in. ID and NC 50 (41/2 in. IF) connections, the tables recommended 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 m For 48 in. tongs, multiply by .0254 = 1.22 m For 50 in. tongs, multiply by .0254 = 1.27 m For 54 in. tongs, multiply by .0254 = 1.37 m For collars with 171.4 mm OD x 57.1 mm ID and NC 50 (41/2 in. IF) connections, the tables recommend 5,080 kg-m of makeup torque. Say the “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

Torque indicator

90°

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

Drill Collar

44

Drill Collar

45

Torque indicator The amount of cathead pull will be the same as the line pull reading on your Torque Indicator.

90°

The amount of cathead pull will be 1/2 of the line pull reading on your Torque Indicator. Snub line


Figure No. 35 Torque indicator

Snub line

90°

Torque indicator

Snub line

90°

Snub line

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. 37


The amount of cathead pull will be the same as the line pull reading on your Torque Indicator.

Torque indicator

90°

Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque by the effective tong length. The answer is pounds pull reading for the line pull indicator when in this position.


Snub line

Figure No. 36

Figure No. 38

Drill Collar

46

Drill Collar

47 The amount of cathead pull will be the same as the line pull reading on your Torque Indicator.


Snub line

Torque indicator

90°

90°

Snub line

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. 39

Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. 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

Torque indicator The amount of cathead pull will be 1/3 of the line pull reading on your Torque Indicator.

90°

Snub line

Torque indicator

The amount of cathead pull will be the same as the line pull reading on your Torque Indicator. Snub line

Snub line

90°


Snub line

Snub line Torque indicator

Figure No. 40

Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 2. This will be the pounds pull reading for line pull indicator when in this position. Figure No. 42

Drill Collar

48 The amount of cathead pull will be the same as the line pull reading on your Torque Indicator.

Snub line

Drill Collar

49

The amount of cathead pull will be the same as the line pull reading on your Torque Indicator.

Snub line

90° Torque indicator Torque indicator

90°

Snub line

Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 2. This will be the pounds pull reading for the line pull indicator when in this position.

Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. this by by 3. 3. This This will Step No. 3 Divide this be pullpull readwillthe be pounds the pounds ing for line pullpull indicator reading for line indiwhen in thisinposition. cator when this position.

Snub line

Figure No. 45 The amount of cathead pull will be 1/2 of the line pull reading on your Torque Indicator.

Figure No. 43 Snub line The amount of cathead pull will be 2/3 of the line pull reading on your Torque Indicator.

Snub line

90° Torque indicator

90°

Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 2. This will be the pounds pull reading for the line pull indicator when in this position.

Snub line

Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this this by by 3, 3, and andmulmultiply 2. This willthe tiply by 2.byThis will be be the pounds pull for pounds pull reading reading for the line pull the line pull indicator when in this position. Torque indicator

Figure No. 46 Snub line

Figure No. 44

Drill Collar

50 The amount of cathead pull will be 1/4 of the line pull reading on your Torque Indicator

Snub line

90°

Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 Divide this by 5, and multiply by 4. This will be the pounds pull reading for the line pull indicator when in this position. Snub line

Torque indicator

Figure No. 47 The amount of cathead pull will be 1/5 of the line pull reading on your Torque Indicator.

Torque indicator

90°

Snub line

Step No. 1 Look up the minimum recommended torque required. Step No. 2 Divide this torque value by the effective tong length. Step No. 3 The answer is pounds pull reading for the line pull indicator when in this position.

Snub line

Figure No. 48

Drill Collar

HOW DO YOU APPLY AND MEASURE MAKEUP TORQUE? Rig Catheads Most drilling rigs have catheads on each side of the drawworks which are used to apply line pull to the tongs. The catheads do not have built in devices to measure the amount of line pull. Line pull measuring devices must be added to the lines between the tongs and the catheads to accomplish this task. The driller is required to release the cathead clutch at the appropriate time in order to ensure the desired pull is not exceeded. This often causes errors in application of the torque. Hydraulic Load Cells For measuring the amount of applied line pull, many rigs use hydraulic load cells. Load cells are simple devices that are generally very reliable. A load cell device usually consists of three parts: (1) a small hydraulic cylinder, (2) a pressure gage that reads pounds of pull, and (3) a rubber hose to connect the cylinder and the gage. One must remember that the gage reads in pounds of force and not in foot-pounds of torque. You must measure the length of the tongs in feet. And then you multiply the gage reading (pounds) by the tong length (feet) to get foot-pounds of torque. Automatic Torque Control System Smith provides a system that eliminates the problems associated with using the rig catheads. This product is called the Automatic Torque Control System (ATCS). The ATCS is a highly accurate solidstate electronic control that automatically terminates makeup of the drill stem connections when the prespecified torque is reached. It can be used on any rig that has manual tongs and air-activated cathead clutches. With a few modifications it can be adapted to hydraulic makeup systems. The ATCS includes an intrinsically safe load cell, explosion-proof air controllers and an airpurged control panel for operation in Class 1, Group D, Divisions 1 and 2 hazardous environments. For operation in all Division 1 situations, a power time delay unit is required.

51

52

Drill Collar How Does the ATCS Help? · Safer - The driller is freed from watching hydraulic torque gages for the make up of each connection, thus letting him focus his attention on the rig floor activities. · Reduces trip time - Automatic application of makeup torque results in faster and optimum rig floor rhythm of movement. · Reduces pin and box damage - Improper torque is the primary cause of swelled boxes, stretched pins, and galled threads and shoulders. · Minimizes risk of fishing jobs - Improper makeup torque causes washouts and twistoffs. · Reduces rig downtime - By eliminating torquerelated failures, you can avoid the expense of laying down damaged pipe and tools, repair or replacement, and loss of costly rig time. Hydraulic Line Pull Devices Sometimes drilling rigs do not have catheads or have catheads with insufficient capacity or simply do not want to use them for the makeup of large rotary shouldered connections. In these cases, the rig must rely on external devices to supply the line pull to the tongs. These devices take the form of hydraulic cylinders and power sources. Ezy-TorqT Hydraulic Cathead In the 1960s Smith developed the Ezy-Torq hydraulic cathead for use on large connections that were beyond the capacity of most rig air catheads. Its primary function is to provide a line pull source for connections that require torques ranging from 40,000 to 150,000 ft-lb. When you use the hydraulic cathead on connections requiring less than 40,000 ft-lb, you should always calibrate the unit with a load cell. The Ezy-Torq hydraulic cathead is available in two 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.

Drill Collar Give This Some Thought Each torque measuring device has a limit for the total amount of line pull it can accurately measure. Know the limit of the instrument you are using and work within the recommended range (see pages 41 through 50). Multiple line hookups can provide many times the normal makeup line pull. Great care should be taken to see that the lines do not become crossed, twisted or fouled. When it comes time for the “big pull*,” be sure everyone is in the clear. *Caution: Know the tong’s rating before the pull is attempted. The slack in the tong safety line should be sufficient for the tongs to obtain full benefit of the pull from the cathead, but short enough to prevent complete rotation of the tongs.

53

Drill Collar

54

Recommended Minimum Makeup Torque (ft-lb) [See Note 2] Size and Type of Connection (in.) API NC 23 23/8 Reg. 27/8 PAC 23/8 IF API NC 26 27/8 SH 27/8 Reg. 27/8 XH 31/2 DSL 27/8 Mod. Open 27/8 IF API NC 31 31/2 SH 31/2 Reg. API NC 35 31/2 XH 4 SH 31/2 Mod. Open 31/2 API IF API NC 38 41/2 SH 31/2 H-90

4 FH API NC 40 4 Mod. Open 41/2 DSL 4 H-90

41/2 Reg.

API NC 44

41/2 API FH 41/2 XH API NC 46 4 API IF 5 DSL 41/2 Mod. Open 41/2 H-90

5 H-90

51/2 H-90

51/2 Reg. 41/2 API IF API NC 50 5 XH 5 Mod. Open 51/2 DSL 5 Semi-IF

OD (in.) 3...4 31/8 31/4 33/4 31/8 31/4 33/4 31/8 31/4 31/2 33/4 31/2 33/4 37/8 33/4 37/8 41/8 37/8 41/8 41/4 41/2 41/8 41/4 41/2 41/2 43/4 53/4 41/4 41/2 43/4 53/4 51/4 43/4 53/4 51/4 51/2 43/4 53/4 51/4 51/2 53/4 51/4 51/2 53/4 63/4 51/4 51/2 53/4 63/4 61/4 51/2 53/4 63/4 61/4 53/4 63/4 61/4 61/2 51/2 53/4 63/4 61/4 61/2 53/4 63/4 61/4 61/2 63/4 53/4 63/4 61/4 61/2 63/4 61/4 61/2 63/4 73/4 63/4 73/4 71/4 71/2 63/4 73/4 71/4 71/2 61/4 61/2 63/4 73/4 71/4 71/2

Bore of Drill 1 11/4 2,508† 2,508† 3,330† 3,330† 4,000 3,387 2,241† 3,028† 3,285 3,797† 4,966† 5,206 4,606† 5,501 3,838† 5,766 5,766 4,089† 5,352† 8,059† 4,640† 7,390† 8,858† 10,286 6,466† 7,886† 10,471†

Collars (in.) 11/2 13/4 2,508† 2,647 2,647 2,241† 1,749 2,574 1,749 2,574 1,749 3,797† 2,926 4,151 2,926 4,151 2,926 4,606† 4,668 3,838† 4,951 4,951 4,089† 5,352† 8,059† 4,640† 7,390† 8,858† 9,307 6,466† 7,886† 9,514

3,697 3,697 3,838† 4,002 4,002 4,089† 5,352† 7,433 4,640† 7,390† 8,161 8,161 6,466† 7,886† 8,394 9,038† 12,273 12,273 5,161† 8,479† 12,074† 13,282 13,282 9,986† 13,949† 16,207 16,207 8,786† 12,794† 17,094† 18,524 10,910† 15,290† 19,985† 20,539 20,539

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

Drill Collar

55

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

4,640† 6,853 6,853 6,853 6,466† 7,115 7,115 9,038† 10,825 10,825 5,161† 8,479† 11,803 11,803 11,803 9,986† 13,949† 14,653 14,653 8,786† 12,794† 16,931 16,931 10,910† 15,290† 18,886 18,886 18,886 12,590† 17,401† 22,531† 23,674 23,674 15,576† 20,609† 23,686 23,686 20,895† 25,509 25,509 25,509 12,973† 18,119† 23,605† 27,294 27,294

21/4

21/2

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

5,685 5,685 5,685 9,038† 7,411 9,202 7,411 9,202 7,411 5,161† 5,161† 8,479† 8,311 10,144 8,311 10,144 8,311 10,144 8,311 9,986† 9,986† 12,907 10,977 12,907 10,977 12,907 10,977 8,786† 8,786† 12,794† 12,794† 15,139 13,154 15,139 13,154. 10,910† 10,910† 15,290† 14,969 17,028 14,969 17,028 14,969 17,028 14,969 12,590† 12,590† 17,401† 17,401† 21,717 19,546 21,717 19,546 21,717 19,546 15,576† 15,576† 20,609† 19,601 21,749 19,601 21,749 19,601 20,895† 20,895† 23,493 21,257 23,493 21,257 23,493 21,257 12,973† 12,973† 18,119† 18,119† 23,605† 23,028 25,272 23,028 25,272 23,028 17,738† 17,738† 23,422† 23,422† 28,021 25,676 28,021 25,676 28,021 25,676 18,019† 18,019† 23,681† 23,681† 28,731 26,397 28,731 26,397 28,731 26,397 25,360† 25,360† 31,895† 31,895† 35,292 32,825 35,292 32,825 34,508† 34,508† 41,993† 40,117 42,719 40,117 42,719 40,117 31,941† 31,941† 39,419† 39,419† 42,481 39,866 42,481 39,866 23,003† 23,003† 29,679† 29,679† 36,741† 35,824 38,379 35,824 38,379 35,824 38,379 35,824

8,315 8,315 8,315 8,315 8,786† 10,410 10,410 10,410 10,910† 12,125 12,125 12,125 12,125 12,590† 16,539 16,539 16,539 16,539 15,576† 16,629 16,629 16,629 18,161 18,161 18,161 18,161 12,973† 18,119† 19,920 19,920 19,920 17,738† 22,426 22,426 22,426 22,426 18,019† 23,159 23,159 23,159 23,159 25,360† 29,400 29,400 29,400 34,508† 36,501 36,501 36,501 31,941† 36,235 36,235 36,235 23,003† 29,679† 32,277 32,277 32,277 32,277

12,973† 17,900 17,900 17,900 17,900 17,738† 20,311 20,311 20,311 20,311 18,019† 21,051 21,051 21,051 21,051 25,360† 27,167 27,167 27,167 34,142 34,142 34,142 34,142 31,941† 33,868 33,868 33,868 23,003† 29,679† 29,965 29,965 29,965 29,965

31/2

33/4

23,003† 26,675 26,675 26,675 26,675 26,675

threads and shoulders. Also using the modified screw jack formula as shown in the IADC Drilling Manual and the API Recommended Practice RP 7G. For API connections and their interchangeable connections, makeup torque is based on 62,500 psi stress in the pin or box, whichever is weaker.

56

Drill Collar Recommended Minimum Makeup Torque (ft-lb) [See Note 2] OD Bore of Drill Collars (in.) Size and Type of Connection (in.) (in.) 11/2 13/4 1 11/4 ..... 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 Faces 8*5/8 7 H-90 81/4* 81/2* 81/2* 83/4* 5 7 /8 API Reg. 9*5/8 91/4* 91/2* 9*5/8 5 7 /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 Faces 7 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 2. Normal torque range — tabulated minimum value to 10% greater. Largest diameter shown for each connection is the maximum recommended for that connection. If the connections are used on drill collars larger than the maximum shown, increase the torque values shown by 10% for a minimum value. In addition to the increased minimum torque value, it is also recommended that a fishing neck be machined to the maximum diameter shown. 3. H-90 connections makeup torque is based on 56,200 psi stress and other factors as stated in Note 1. 4. The 27/8 in. PAC makeup torque is based on 87,500 psi stress and other factors as stated in Note 1.

Drill Collar

57

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

21/4

Bore of Drill Collars (in.) 21/2 213/16 3 31/4 32,762† 32,762† 32,762† 32,762† 40,998† 40,998† 40,998† 40,998† 49,661† 47,756 45,190 41,533 51,687 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 42,058 52,115 48,221 45,680 42,058 46,399† 46,399† 46,399† 46,399† 55,627† 53,346 50,704 46,935 57,393 53,346 50,704 46,935 57,393 53,346 50,704 46,935 46,509† 46,509† 46,509† 46,509† 55,707† 55,707† 53,628 49,855 60,321 56,273 53,628 49,855 60,321 56,273 53,628 49,855 55,131† 55,131† 55,131† 55,131† 65,438† 65,438† 65,438† 61,624 72,670 68,398 65,607 61,624 72,670 68,398 65,607 61,624 72,670 68,398 65,607 61,624 56,641† 56,641† 56,641† 56,641† 67,133† 67,133† 67,133† 63,381 74,625 70,277 67,436 63,381 74,625 70,277 67,436 63,381 74,625 70,277 67,436 63,381 74,625 70,277 67,436 63,381 67,789† 67,789† 67,789† 79,544† 79,544† 76,706 83,992 80,991 76,706 83,992 80,991 76,706 83,992 80,991 76,706 75,781† 75,781† 75,781† 88,802† 88,802† 88,802† 102,354† 102,354† 101,107 108,842 105,657 101,107 108,842 105,657 101,107 108,842 105,657 101,107 108,194† 108,194† 124,051† 124,051† 140,491† 140,488 145,476 140,488 145,476 140,488 Connections with Full Faces 53,454† 53,454† 53,454† 63,738† 63,738† 63,738† 72,066 69,265 65,267 60,402† 60,402† 72,169† 72,169† 84,442† 84,442† 88,581 84,221 88,581 84,221 73,017† 73,017† 86,006† 86,006† 99,508† 99,508† 109,345† 109,345† 125,263† 125,263† 141,134 136,146 113,482† 113,482† 130,063† 130,063† Connections with Low Torque Faces 68,061† 68,061† 67,257 74,235 71,361 67,257 73,099† 73,099† 86,463† 86,463† 91,789 87,292 91,789 87,292 91,667† 91,667† 106,260† 106,260† 113,845 109,183 113,845 109,183 112,887† 112,887† 130,676† 130,676† 147,616 142,429 92,960† 92,960† 110,782† 110,782† 129,203† 129,203†

31/2

33/4

56,641† 59,027 59,027 59,027 59,027 59,027 67,789† 67,184 72,102 67,184 72,102 67,184 72,102 67,184 72,102 67,184 75,781† 75,781† 88,802† 88,802† 96,214 90,984 96,214 90,984 96,214 90,984 96,214 90,984 108,194† 108,194† 124,051† 124,051† 135,119 129,375 135,119 129,375 135,119 129,375 53,454† 60,970 60,970 60,402† 60,402† 72,169† 72,169† 79,536 74,529 79,536 74,529 79,536 74,529 73,017† 73,017† 86,006† 86,006† 99,508† 96,284 109,345† 109,345† 125,263† 125,034 130,777 125,034 113,482† 113,482† 130,063† 130,063† 62,845 62,845 73,099† 82,457 82,457 82,457 91,667† 104,166 104,166 104,166 112,887† 130,676† 136,846 92,960† 110,782† 129,203†

73,099† 77,289 77,289 77,289 91,667† 98,799 98,799 98,799 112,887† 130,676† 130,870 92,960† 110,782† 129,203†

*5. Largest diameter shown is the maximum recommended for these full faced connections. If larger diameters are used, machine connections with low torque faces and use the torque values shown under low torque face tables. If low torque faces are not used, see Note 2 for increased torque values. (†)6. Torque figures succeeded by a cross (†) indicate that the weaker member for the corresponding OD and bore is the BOX. For all other torque values the weaker member is the PIN.

Drill Collar

58

Recommended Minimum Makeup Torque (kg-m) [See Note 2] Size and Type of Connection (in.) API NC 23 23/8 Reg. 27/8 PAC 23/8 IF API NC 26 27/8 SH 27/8 Reg. 27/8 XH 31/2 DSL 27/8 Mod. Open 27/8 IF API NC 31 31/2 SH 31/2 Reg. API NC 35 31/2 XH 4 SH 31/2 Mod. Open 31/2 API IF API NC 38 41/2 SH 31/2 H-90 4 FH API NC 40 4 Mod. Open 41/2 DSL

4 H-90

41/2 Reg.

API NC 44


5 H-90

51/2 H-90

51/2 Reg. 41/2 IF API NC 50 5 XH 5 Mod. Open 51/2 DSL 5 Semi-IF

OD (mm) 76.2 79.4 82.6 76.2 79.4 82.6 76.2 79.4 82.6 88.9 95.2 88.9 95.2 98.4 95.2 98.4 104.8 98.4 104.8 107.9 114.3 104.8 107.9 114.3 114.3 120.6 127.0 107.9 114.3 120.6 127.0 133.3 120.6 127.0 133.3 139.7 120.6 127.0 133.3 139.7 127.0 133.3 139.7 146.0 152.4 133.3 139.7 146.0 152.4 168.7 139.7 146.0 152.4 158.7 146.0 152.4 158.7 165.1 139.7 146.0 152.4 158.7 165.1 146.0 152.4 158.7 165.1 171.4 146.0 152.4 158.7 165.1 171.4 158.7 165.1 171.4 177.8 171.4 177.8 184.1 190.5 171.4 177.8 184.1 190.5 158.7 165.1 171.4 177.8 184.1 190.5

Bore 25.4 347† 460† 553

of Drill Collars (mm) 31.7 38.1 44.4 347† 347† 460† 366 468 366 310† 310† 242 419† 356 242 454 356 242 525† 525† 405 687† 574 405 720 574 405 637† 761 531† 797 797 565† 740† 1,114† 641† 1,022† 1,225† 1,422 894† 1,090† 1,448

637† 645 531† 685 685 565† 740† 1,114† 641† 1,022† 1,225† 1,287 894† 1,090† 1,315

511 511 531† 553 553 565† 740† 1,028 641† 1,022† 1,128 1,128 894† 1,090† 1,160 1,250† 1,697 1,697 714† 1,172† 1,669† 1,836 1,836 1,381† 1,929† 2,241 2,241 1,215† 1,769† 2,363† 2,561 1,508† 2,114† 2,763† 2,840 2,840


Drill Collar

59

Recommended Minimum Makeup Torque (kg-m) [See Note 2] 50.8

641† 947 947 947 894† 984 984 1,250† 1,497 1,497 714† 1,172† 1,632 1,632 1,632 1,381† 1,929† 2,026 2,026 1,215† 1,769† 2,341 2,341 1,508† 2,114† 2,611 2,611 2,611 1,741† 2,406† 3,115† 3,273 3,273 2,153† 2,849† 3,275 3,275 2,889† 3,527 3,527 3,527 1,794† 2,505† 3,264† 3,774 3,774

57.1

786 786 786 1,250† 1,272 1,272 714† 1,172† 1,402 1,402 1,402 1,381† 1,785 1,785 1,785 1,215† 1,769† 2,093 2,093 1,508† 2,114† 2,354 2,354 2,354 1,741† 2,406† 3,003 3,003 3,003 2,153† 2,849† 3,007 3,007 2,889† 3,248 3,248 3,248 1,794† 2,505† 3,264† 3,494 3,494 2,452† 3,238† 3,874 3,874 3,874 2,491† 3,274† 3,972 3,972 3,972 3,506† 4,410† 4,879 4,879 4,771† 5,806† 5,906 5,906 4,416† 5,450† 5,873 5,873 3,180 4,103 5,080 5,306 5,306 5,306

Bore of Drill Collars (mm) 63.5 71.4 76.2 82.5

1,025† 1,025 1,025 714† 1,149 1,149 1,149 1,149 1,381† 1,518 1,518 1,518 1,215† 1,769† 1,819 1,819 1,508† 2,070 2,070 2,070 2,070 1,741† 2,406† 2,702 2,702 2,702 2,153† 2,710 2,710 2,710 2,889† 2,939 2,939 2,939 1,794† 2,505† 3,184 3,184 3,184 2,452† 3,238† 3,550 3,550 3,550 2,491† 3,274† 3,650 3,650 3,650 3,506† 4,410† 4,538 4,538 4,771† 5,546 5,546 5,546 4,416† 5,450† 5,512 5,512 3,180† 4,103† 4,953 4,953 4,953 4,953

1,150 1,150 1,150 1,150 1,215† 1,439 1,439 1,439 1,508† 1,676 1,676 1,676 1,676 1,741† 2,287 2,287 2,287 2,287 2,153† 2,299 2,299 2,299 2,511 2,511 2,511 2,511 1,794† 2,505† 2,754 2,754 2,754 2,452† 3,100 3,100 3,100 3,100 2,491† 3,202 3,202 3,202 3,202 3,506† 4,065 4,065 4,065 4,771† 5,046 5,046 5,046 4,416† 5,010 5,010 5,010 3,180† 4,103† 4,462 4,462 4,462 4,462

1,794† 2,475 2,475 2,475 2,475 2,452† 2,808 2,808 2,808 2,808 2,491† 2,910 2,910 2,910 2,910 3,506† 3,756 3,756 3,756 4,720 4,720 4,720 4,720 4,416† 4,682 4,682 4,682 3,180† 4,103† 4,143 4,143 4,143 4,143

88.9

95.2

3,180† 3,688 3,688 3,688 3,688 3,688


60

Drill Collar Recommended Minimum Makeup Torque (kg-m) [See Note 2] OD Bore of Drill Collars (mm) Size and Type of Connection (in.) (mm) 25.4 31.7 38.1 44.4 177.8 184.1 51/2 API FH 190.5 196.8 184.1 API NC 56 190.5 196.8 203.2 190.5 65/8 Reg. 196.8 203.2 209.5 190.5 65/8 H-90 196.8 203.2 209.5 203.2 209.5 API NC 61 215.9 222.2 228.6 203.2 209.5 51/2 IF 215.9 222.2 228.6 234.9 215.9 222.2 65/8 API FH 228.6 234.9 241.3 228.6 234.9 API NC 70 241.3 247.6 254.0 260.3 254.0 260.3 API NC 77 266.7 273.0 279.4 Connections with Full Faces 203.2* 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 Faces 7 H-90 222.2 228.6 234.9 75/8 Reg. 241.3 247.6 254.0 247.6 75/8 H-90 254.0 260.3 266.7 273.0 85/8 Reg. 279.4 285.7 273.0 85/8 H-90 279.4 285.7 2. Normal torque range — tabulated minimum value to 10% greater. Largest diameter shown for each connection is the maximum recommended for that connection. If the connections are used on drill collars larger than the maximum shown, increase the torque values shown by 10% for a minimum value. In addition to the increased minimum torque value, it is also recommended that a fishing neck be machined to the maximum diameter shown. 3. H-90 connections makeup torque is based on 56,200 psi stress and other factors as stated in Note 1. 4. The 27/8 in. PAC makeup torque is based on 87,500 psi stress and other factors as stated in Note 1.

Drill Collar

61

Recommended Minimum Makeup Torque (kg-m) [See Note 2] 50.8

57.1

Bore of Drill 63.5 71.4 4,530† 4,530† 5,668† 5,668† 6,866† 6,603 7,146 6,603 5,599† 5,599† 6,783† 6,667 7,205 6,667 7,205 6,667 6,415† 6,415† 7,691† 7,375 7,935 7,375 7,935 7,375 6,430† 6,430† 7,702† 7,702† 8,340 7,780 8,340 7,780 7,622† 7,622† 9,047† 9,047† 10,047 9,456 10,047 9,456 10,047 9,456 7,831† 7,831† 9,282† 9,282† 10,317 9,716 10,317 9,716 10,317 9,716 10,317 9,716 9,372† 10,997† 11,612 11,612 11,612 10,477† 12,277† 14,151† 15,048 15,048 15,048

Collars (mm) 76.2 82.5 4,530† 4,530† 5,668† 5,668† 6,248 5,742 6,248 5,742 5,599† 5,599† 6,316 5,815 6,316 5,815 6,316 5,815 6,415† 6,415† 7,010 6,489 7,010 6,489 7,010 6,489 6,430† 6,430† 7,414 6,893 7,414 6,893 7,414 6,893 7,622† 7,622† 9,047† 8,520 9,070 8,520 9,070 8,520 9,070 8,520 7,831† 7,831† 9,282† 8,763 9,323 8,763 9,323 8,763 9,323 8,763 9,323 8,763 9,372† 9,372† 10,997† 10,605 11,197 10,605 11,197 10,605 11,197 10,605 10,477† 10,477† 12,277† 12,277† 14,151† 13,979 14,608 13,979 14,608 13,979 14,608 13,979 14,958† 14,958† 17,151† 17,151† 19,424† 19,424† 20,113 19,423 20,113 19,423 Connections with Full Faces 7,390† 7,390† 7,390† 8,812† 8,812† 8,812† 9,963 9,576 9,023 8,351† 8,351† 9,978† 9,978† 11,675† 11,644 12,247 11,644 12,247 11,644 10,095† 10,095† 11,891† 11,891† 13,758† 13,758† 15,117† 15,117† 17,318† 17,318† 19,512 18,823 15,689† 15,689† 7,982† 17,982† Connections with Low Torque Faces 9,410† 9,410† 9,299 10,263 9,866 9,299 10,106† 10,106† 11,954† 11,954† 12,690 12,069 12,690 12,069 12,673† 12,673† 14,691† 14,691† 15,740 15,095 15,740 15,095 15,607† 15,607† 18,067† 18,067† 20,409 19,692 12,852† 12,852† 15,316† 15,316† 17,863† 17,863†

88.9

95.2

7,831† 8,161 8,161 8,161 8,161 8,161 9,372† 9,968 9,968 9,968 9,968 10,477† 12,277† 13,302 13,302 13,302 13,302 14,958† 17,151† 18,681 18,681 18,681

9,289 9,289 9,289 9,289 9,289 10,477† 12,277† 12,579 12,579 12,579 12,579 14,958† 17,151† 17,887 17,887 17,887

7,390† 8,429 8,429 8,351† 9,978† 10,996 10,996 10,996 10,095† 11,891† 13,758† 15,117† 17,318† 18,081 15,689† 17,982†

8,351† 9,978† 10,304 10,304 10,304 10,095† 11,891† 13,312 15,117† 17,287 17,287 15,689† 17,982†

8,689 8,689 10,106† 11,400 11,400 11,400 12,673† 14,401 14,401 14,401 15,607† 18,067† 18,920 12,852† 15,316† 17,863†

10,106† 10,686 10,686 10,686 12,673† 13,659 13,659 13,659 15,607† 18,067† 18,093 12,852† 15,316† 17,863†


Drill Collar

62

Recommended Minimum Makeup Torque (N·m) [See Note 2] Size and Type of Connection (in.) API NC 23 23/8 Reg. 27/8 PAC 23/8 IF API NC 26 27/8 SH 27/8 Reg. 27/8 XH 31/2 DSL 27/8 Mod.Open 27/8 IF API NC 31 31/2 SH 31/2 Reg. API NC 35 31/2 XH 4 SH 31/2 Mod. Open 31/2 API IF API NC 38 41/2 SH 3 1/2 H-90 4 FH API NC 40 4 Mod. Open 41/2 DSL

4 H-90

41/2 Reg.

API NC 44


5 H-90

51/2 H-90

51/2 Reg. 41/2 API IF API NC 50 5 XH 5 Mod. Open 51/2 DSL 5 Semi-IF

OD (mm) 76.2 79.4 82.5 76.2 79.4 82.5 76.2 79.4 82.5 88.9 95.2 88.9 95.2 98.4 95.2 98.4 104.8 98.4 104.8 107.9 114.3 104.8 107.9 114.3 114.3 120.6 127.0 107.9 114.3 120.6 127.0 133.3 120.6 127.0 133.3 139.7 120.6 127.0 133.3 139.7 127.0 133.3 139.7 146.0 152.4 133.3 139.7 146.0 152.4 158.7 139.7 146.0 152.4 158.7 146.0 152.4 158.7 165.1 139.7 146.0 152.4 158.7 165.1 146.0 152.4 158.7 165.1 171.4 146.0 152.4 158.7 165.1 171.4 158.7 165.1 171.4 177.8 171.4 177.8 184.1 190.5 171.4 177.8 184.1 190.5 158.7 165.1 171.4 177.8 184.1 190.5

Bore of Drill 25.4 31.7 3,400† 3,400† 4,514† 4,514† 5,423 4,592 3,039† 4,105† 4,454 5,148† 6,733† 7,058 6,245† 7,458 5,204† 7,817 7,817 5,544† 7,256† 10,927† 6,291† 10,019† 12,010† 13,946 8,766† 10,692† 14,197

Collars (mm) 38.1 44.4 3,400† 3,589 3,589 3,039† 2,371 3,490 2,371 3,490 2,371 5,148† 3,968 5,629 3,968 5,629 3,968 6,245† 6,329 5,204† 6,713 6,713 5,544† 7,256† 10,927† 6,291† 10,019† 12,010† 12,619 8,766† 10,692† 12,900

5,013 5,013 5,204† 5,426 5,426 5,544† 7,256† 10,077 6,291† 10,019† 11,065 11,065 8,766† 10,692† 11,380 12,255† 16,640 16,640 6,997† 11,495† 16,370† 18,009 18,009 13,540† 18,913† 21,974 21,974 11,912† 17,346† 23,176† 25,115 14,793† 20,731† 27,096† 27,847 27,847


Drill Collar

63

Recommended Minimum Makeup Torque (N·m) [See Note 2] 50.8

6,291† 9,292 9,292 9,292 8,766† 9,646 9,646 12,255† 14,677 14,677 6,997† 11,495† 16,003 16,003 16,003 13,540† 18,913† 19,867 1,9867 11,912† 17,346† 22,956 22,956 14,793† 20,731† 25,607 25,607 25,607 17,070† 23,593† 30,548† 32,097 32,097 21,118† 27,943† 32,113 32,113 28,330† 34,586 34,586 34,586 17,589† 24,566† 32,004† 37,006 37,006

57.1

7,708 7,708 7,708 12,255† 12,477 12,477 6,997† 11,495† 13,753 13,753 13,753 13,540† 17,500 17,500 17,500 11,912† 17,346† 20,526 20,526 14,793† 20,731† 23,086 23,086 23,086 17,070† 23,593† 29,445 29,445 29,445 21,118† 27,943† 29,487 29,487 28,330† 31,853 31,853 31,853 17,589† 24,566† 32,004† 34,264 34,264 24,049† 31,755† 37,991 37,991 37,991 24,431† 32,107† 38,955 38,955 38,955 34,383† 43,244† 47,849 47,849 46,787† 56,935† 57,919 57,919 43,306† 53,445† 57,597 57,597 31,188† 40,240† 49,814† 52,035 52,035 52,035

Bore of Drill Collars (mm) 63.5 71.4 76.2 82.5

10,048 10,048 10,048 6,997† 11,268 11,268 11,268 11,268 13,540† 14,883 14,883 14,883 11,912† 17,346† 17,834 17,834 14,793† 20,295 20,295 20,295 20,295 17,070† 23,593† 26,501 26,501 26,501 21,118† 26,575 26,575 26,575 28,330† 28,820 28,820 28,820 17,589† 24,566† 31,222 31,222 31,222 24,049† 31,755† 34,811 34,811 34,811 24,431† 32,107† 35,790 35,790 35,790 34,383† 43,244† 44,504 44,504 46,787† 54,391 54,391 54,391 43,306† 53,445† 54,051 54,051 31,188† 40,240† 48,570 48,570 48,570 48,570

11,274 11,274 11,274 11,274 11,912† 14,114 14,114 14,114 14,793† 16,439 16,439 16,439 16,439 17,070† 22,424 22,424 22,424 22,424 21,118† 22,546 22,546 22,546 24,623 24,623 24,623 24,623 17,589† 24,566† 27,008 27,008 27,008 24,049† 30,405 30,405 30,405 30,405 24,431† 31,400 31,400 31,400 31,400 34,383† 39,861 39,861 39,861 46,787† 49,489 49,489 49,489 43,306† 49,128 49,128 49,128 31,188† 40,240† 43,762 43,762 43,762 43,762

17,589† 24,269 24,269 24,269 24,269 24,049† 27,538 27,538 27,538 27,538 24,431† 28,541 28,541 28,541 28,541 34,383† 36,833 36,833 36,833 46,291 46,291 46,291 46,291 43,306† 45,918 45,918 45,918 31,188† 40,240† 40,628 40,628 40,628 40,628

88.9

95.2

31,188† 36,167 36,167 36,167 36,167 36,167


64

Drill Collar Recommended Minimum Makeup Torque (N·m) [See Note 2] OD Bore of Drill Collars (mm) Size and Type of Connection (in.) (mm) 25.4 31.7 38.1 44.4 177.8 184.1 51/2 API FH 190.5 196.8 184.1 API NC 56 190.5 196.8 203.2 190.5 65/8 Reg. 196.8 203.2 209.5 190.5 65/8 H-90 196.8 203.2 209.5 203.2 209.5 API NC 61 215.9 222.2 228.6 203.2 209.5 51/2 IF 215.9 222.2 228.6 234.9 215.9 222.2 65/8 API FH 228.6 234.9 241.3 228.6 234.9 API NC 70 241.3 247.6 254.0 260.3 254.0 260.3 API NC 77 266.7 273.0 279.4 Connections with Full Faces 203.2* 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 Faces 7 H-90 222.2 228.6 234.9 75/8 Reg. 241.3 247.6 254.0 247.6 75/8 H-90 254.0 260.3 266.7 273.0 85/8 Reg. 279.4 285.7 273.0 85/8 H-90 279.4 285.7 2. Normal torque range — tabulated minimum value to 10% greater. Largest diameter shown for each connection is the maximum recommended for that connection. If the connections are used on drill collars larger than the maximum shown, increase the torque values shown by 10% for a minimum value. In addition to the increased minimum torque value, it is also recommended that a fishing neck be machined to the maximum diameter shown. 3. H-90 connections makeup torque is based on 56,200 psi stress and other factors as stated in Note 1. 4. The 27/8 in. PAC makeup torque is based on 87,500 psi stress and other factors as stated in Note 1.

Drill Collar

65

Recommended Minimum Makeup Torque (N·m) [See Note 2] 50.8

57.1

Bore of Drill Collars (mm) 63.5 71.4 76.2 82.5 44,419† 44,419† 44,419† 44,419† 55,586† 55,586† 55,586† 55,586† 67,331† 64,748 61,270 56,311 70.078 64,748 61,270 56,311 54,908† 54,908† 54,908† 54,908† 66,517† 65,379 61,934 57,024 70,658 65,379 61,934 57,024 70,658 65,379 61,934 57,024 62,909† 62,909† 62,909† 62,909† 75,420† 72,327 68,745 63,636 77,815 72,327 68,745 63,636 77,815 72,327 68,745 63,636 63,057† 63,057† 63,057† 63,057† 75,529† 75,529† 72,710 67,594 81,785 76,296 72,710 67,594 81,785 76,296 72,710 67,594 74,747† 74,747† 74,747† 74,747† 88,722† 88,722† 88,722† 83,551 98,527 92,735 88,951 83,551 98,527 92,735 88,951 83,551 98,527 92,735 88,951 83,551 76,795† 76,795† 76,795† 76,795† 91,021† 91,021† 91,021† 85,933 101,178 95,283 91,431 85,933 101,178 95,283 91,431 85,933 101,178 95,283 91,431 85,933 101,178 95,283 91,431 85,933 91,909† 91,909† 91,909† 107,848† 107,848† 104,000 113,878 109,809 104,000 113,878 109,809 104,000 113,878 109,809 104,000 102,745† 102,745† 102,745† 120,400† 120,400† 120,400† 138,773† 138,773† 137,082 147,569 143,251 137,082 147,569 143,251 137,082 147,569 143,251 137,082 146,692† 146,692† 168,191† 168,191† 190,480† 190,476 197,239 190,476 197,239 190,476 Connections with Full Faces 72,474† 72,474† 72,474† 86,417† 86,417† 86,417† 97,708 93,911 88,490 81,894† 81,894† 97,848† 97,848† 114,489† 114,189 120,099 114,189 120,099 114,189 98,997† 98,997† 116,609† 116,609† 134,915† 134,915† 148,251† 148,251† 169,834† 169,834† 191,352 184,589 153,860† 153,860† 176,341† 176,341† Connections with Low Torque Faces 92,279† 92,279† 91,188 100,650 96,753 91,188 99,109† 99,109† 117,228† 117,228† 124,449 118,352 124,449 118,352 124,284† 124,284† 144,069† 144,069† 154,354 148,033 154,354 148,033 153,054† 153,054† 177,174† 177,174† 200,140 193,108 126,037† 126,037† 150,200† 150,200† 175,176† 175,176†

88.9

95.2

76,795† 80,029 80,029 80,029 80,029 80,029 91,909† 97,757 97,757 97,757 97,757 102,745† 120,400† 130,449 130,449 130,449 130,449 146,692† 168,191† 183,197 183,197 183,197

91,090 91,090 91,090 91,090 91,090 102,745† 120,400† 123,357 123,357 123,357 123,357 146,692† 168,191† 175,409 175,409 175,409

72,474† 82,665 82,665 81,894† 97,848† 107,836 107,836 107,836 98,997† 116,609† 134,915† 148,251† 169,834† 177,310 153,860† 176,341†

81,894† 97,848† 101,048 101,048 101,048 98,997† 116,609† 130,544 148,251† 169,523 169,523 153,860† 176,341†

85,206 85,206 99,109† 111,796 111,796 111,796 124,284† 141,230 141,230 141,230 153,054† 177,174† 185,538 126,037† 150,200† 175,176†

99,109† 104,789 104,789 104,789 124,284† 133,953 133,953 133,953 153,054† 177,174† 177,437 126,037† 150,200† 175,176†


Drill Collar

66

KNOW FIELD SHOP WORK When it becomes necessary to repair drill collars in field shops, every effort should be made to rethread the drill collar with a joint equivalent to the manufacturer’s new joint. Use only field shops that are equipped with high-quality, hardened-and-ground gages; with thread mills or lathes that use pre-formed threading inserts, cold rolling equipment and chemical coating baths. Use the following checklist to ensure that a field shop’s repair work is of high quality. Straightness Collars should be inspected by supporting near each end and checking for run-out. As a rule of thumb, collars with more than 1/4 in. (6 mm) run-out should be straightened. Threading Threads should be gaged with high-quality, hardened-and-ground gages. Thread form, lead and taper should be inspected, using approved gages. Thread roots should be free from sharp notches (see page 97 for oilfield thread forms). Cold Working Thread roots should be cold worked in accordance with procedures established for rolling or peening. Threads must be gaged for standoff prior to cold working. Cold working should be completed prior to cutting stress-relief contours so the last scratch of the run-out or imperfect thread root can be cold worked. Facts About Cold Working Drill collar joint life can be improved by prestressing the thread roots of drill collar joints by cold working. Cold working is done with a hydraulic ram which forces a roller into the thread root (see Figure No. 49). The roller is then moved down the thread spiral. Cold worked metal surfaces have greater resistance to fatigue failure. After thread rolling is completed, the fibers in the thread roots remain in compression and can withstand higher bending loads without cracking in fatigue. Note: For comments related to the effect of cold working and gage standoff, refer to API Specification No. 7.

Drill Collar

67

Load

After rolling, these fibers remain in compression

Figure No. 49

Gall-Resistant Coating A gall-resistant coating should be applied to all newly cut threads and shoulders. This conditions the shiny threads and shoulders so that lubricant will adhere to the surface. Newly machined threads are bright and shiny before 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 appearance (see Figure No. 50). Such a coating acts as a lubricant, separates the metal surfaces during the initial makeup and assists in holding lubricant in place under makeup loads.

Figure No. 50

Drill Collar

68

Stress Relief Contours The API relief groove pin and the API Bore Back box remove unengaged threads in highly stressed areas of the drill collar joint (see Figure No. 51). This provides a more flexible joint, less likely to crack in fatigue, because bending in the joint occurs in areas of smooth relief surfaces. Smooth surfaces and radii, free of tool marks, permit higher bending loads without fatigue cracking. Serial numbers must not be stamped in relief grooves.

Last scratch of box thread covered by pin; no thread roots exposed to corrosive drilling fluid.

Large radii reduce stress concentrations.

Figure No. 51

SPECIAL DRILL COLLAR FEATURES Spiral Drill Collars The 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

Drill Collar Slip and Elevator Recesses Slip and elevator recesses are designed to cut drill collar handling 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 recesses may be used together or separately (see Figure No. 53).

69

Cold work

Figure No. 53

Low Torque Faces To prevent shoulder separation, the compressive stress created by the makeup torque must be of such a magnitude that the shoulders remain together under all downhole conditions. On large diameter drill collars the shoulder can become so wide that the makeup torque required for an adequate compressive stress can not be obtained. Low torque faces are used to achieve an increase in the compressive shoulder stress at the shoulder bevel when a connection smaller than optimum is used on large drill collars. The low torque face feature was designed to accommodate the problem of reducing the area of the total shoulder face without creating a notch effect 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 balance of fatigue life between the pin and box, nor can it increase the shoulder load holding the connection together. It should be noted that the term “Low Torque Feature” does not mean that less makeup torque will be required when the feature is used on a particular connection on a given size collar.

Drill Collar

70

Figure No. 54 is a comparison of the shoulder widths of a connection with and without a low torque feature.

Figure No. 54

BUOYANCY EFFECT OF DRILL COLLARS IN MUD All picked up drill collar weight is not available to load the bit in fluid drilled holes due to the buoyancy effect. Buoyancy Factors Mud (lb/gal) 8.34 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

BF = 1 –

Weight (lb/ft3) 62.3 67.3 74.8 82.3 89.8 97.2 104.7 112.2 119.7 127.2 134.6 142.1 149.6 157.1 164.6 172.1 179.5

g/cc or sp gr 1.00 1.08 1.20 1.32 1.44 1.56 1.68 1.80 1.92 2.04 2.16 2.28 2.40 2.52 2.64 2.76 2.88

Buoyancy Correction Factor .873 .862 .847 .832 .817 .801 .786 .771 .755 .740 .725 .710 .694 .679 .664 .649 .633

Mud lb/gal 65.5

Buoyancy Factors To find the corrected or buoyed drill collar weight, use the above Buoyancy Correction Factor for the mud weight to be used.

Drill Collar

71

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 FACTOR Drill pipe will be subjected to serious damage if run in compression. To make sure the drill pipe is always in tension, the top 10 to 15% of the drill collar string must also be in tension. This will put the change over from tension to compression, or neutral zone, down in the stiff drill collar string where 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, the maximum weight available to run on the bit would be: Buoyed weight Maximum bit weight available = 1.15 (15% SF) = 64,543 lb 1.15 = 56,124 lb Buoyed weight Maximum bit weight available= 1.15 (15% SF) = 29,276 kg 1.15 = 25,457 kg Bit weight x SF BF In soft formations with little or no bouncing, or when running a vibration dampener, a 10% safety factor will probably be sufficient. In areas of hard and rough drilling it may be desirable to increase this safety factor to 25% (1.25).

Drill collar air weight

=

Drill Collar

72 Weight of 31 ft Drill Collar (lb)

1

11/8

31/2

662.2

640.2

31/8

725.5

703.6

679.0

1

791.5

769.5

73

Drill Collar Weights (lb/ft)

Bore of Drill Collar (in.)

Drill Collar OD (in.)

Drill Collar

Bore of Drill Collar (in.)

Drill Collar OD (in.)

1

11/8

31/2

21

21

622.1

31/8

23

23

22

21

744.9

688.0

31/4

26

25

24

22

33/8

813.5

756.6

689.3

33/8

26

24

22

31/2

884.6

827.7

760.5

31/2

29

27

25

33/4

1,034.6

977.7

910.5

33/4

33

32

29

37/8

1,113.5 1,056.6

989.4

911.8

823.8

37/8

36

34

32

30

27

41/2

1,138.1 1,070.9

993.3

905.3

41/2

37

35

32

29

41/8

1,222.2 1,154.9 1,077.3

3 /4

11/4

11/2

13/4

2

21/4

21/2

213/16

3

31/4

11/4

11/2

13/4

2

21/4

21/2

213/16

3

31/4

989.4

41/8

39

37

35

32

1

4 /4

1,308.8 1,241.6 1,164.0 1,076.0

41/4

42

40

38

35

41/2

1,489.9 1,422.6 1,345.0 1,257.1

41/2

48

46

43

41

43/4

1,681.3 1,614.0 1,536.4 1,448.5 1,350.2

43/4

54

52

50

47

51/2

1,883.0 1,815.8 1,738.2 1,650.3 1,552.0

51/2

61

59

56

53

50

51/4

2,095.2 2,027.9 1,950.3 1,862.4 1,764.1 1,626.7

51/4

68

65

63

60

57

53

51/2

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

51/2

75

73

70

67

64

60

57

53/4

2,550.4 2,483.1 2,405.5 2,317.6 2,219.3 2,081.9 1,991.7

53/4

83

80

78

75

72

67

64

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

61/2

90

88

85

83

79

75

72

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

61/4

98

96

94

91

88

83

80

76

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

61/2

107

105

102

99

96

92

88

85

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

63/4

116

114

111

108

105

101

98

94

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

71/2

125

123

120

117

114

110

107

103

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

71/4

134

132

130

127

124

119

116

112

1

7 /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

71/2

144

142

140

137

134

129

126

122

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

73/4

154

152

150

147

144

139

136

132

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

81/2

165

163

160

157

154

150

147

143

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

81/4

176

174

171

168

165

161

158

154

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

81/2

187

185

182

179

176

172

169

165

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

83/4

198

196

194

191

188

183

180

176

91/2

6,451.0 6,373.4 6,285.4 6,187.2 6,049.7 5,959.5 5,830.2

91/2

208

206

203

200

195

192

188

91/4

6,628.6 6,751.0 6,663.1 6,564.8 6,427.4 6,337.2 6,207.9

91/4

220

218

215

212

207

204

200

1

9 /2

7,216.6 7,139.0 7,051.1 6,952.8 6,815.4 6,725.2 6,595.8

91/2

233

230

228

224

220

217

213

93/4

7,615.0 7,537.4 7,449.4 7,351.1 7,213.7 7,123.5 6,994.2

93/4

246

243

240

237

233

230

226

101/2

7,946.1 7,858.1 7,759.8 7,622.4 7,532.2 7,402.9

101/2

256

254

250

246

243

239

1

10 /4

8,365.1 8,277.1 8,178.8 8,041.4 7,951.2 7,821.9

101/4

270

267

264

259

257

252

101/2

8,794.5 8,706.5 8,608.2 8,470.8 8,380.6 8,251.3

101/2

284

281

278

273

270

266

103/4

9,234.2 9,146.2 9,047.9 8,910.5 8,820.3 8,691.0

103/4

298

295

292

287

285

280

111/2

9,498.0 9,360.6 9,270.4 9,141.1

111/2

306

302

299

295

1

11 /4

9,958.4 9,821.0 9,730.8 9,601.5

111/4

321

317

314

310

111/2

10,429.2 10,291.8 10,201.6 10,072.2

111/2

336

332

329

325

44

68

113/4

10,910.3 10,772.9 10,682.7 10,553.3

113/4

352

348

345

340

121/2

11,401.8 11,264.3 11,174.1 11,044.8

121/2

368

363

361

356

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 of steel will displace 1 ft3 2,747 lb of steel will displace 1 bbl

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 of steel will displace 1 ft3 2,747 lb of steel will displace 1 bbl

Drill Collar

74 Weight of 9.4 m Drill Collar (kg) Drill Collar OD in. (mm) 31/2 (76.20) 31/8 (79.37) 31/4 (82.55) 33/8 (85.72) 31/2 (88.90) 33/4 (95.25) 37/8 (98.42) 41/2 (101.60) 41/8 (104.77) 4 1/4 (107.95) 41/2 (114.30) 43/4 (120.65) 51/2 (127.00) 51/4 (133.35) 51/2 (139.70) 5 3/4 (146.05) 61/2 (152.40) 61/4 (158.75) 61/2 (165.10) 63/4 (171.45) 71/2 (177.80) 71/4 (184.15) 71/2 (190.50) 73/4 (196.85) 81/2 (203.20) 81/4 (209.55) 81/2 (215.90) 83/4 (222.25) 91/2 (228.60) 91/4 (234.95) 91/2 (241.30) 93/4 (247.65) 101/2 (254.00) 101/4 (260.35) 101/2 (266.70) 103/4 (273.05) 111/2 (279.40) 111/4 (285.75) 111/2 (292.10) 113/4 (298.45) 121/2 (304.80)

Drill Collar

75

Drill Collar Weights (kg/m)

Bore of Drill Collar in. (mm) 11/4 11/2 13/4 2 21/4 21/2 213/16 3 31/4 1 11/8 (25.40) (28.57) (31.75) (38.10) (44.45) (50.80) (57.15) (63.50) (71.44) (76.20) (82.55) 298.8

288.9

327.4

317.5

306.4

280.7

357.2

347.2

336.2

310.5

367.1

341.4

311.1

399.2

373.5

343.2

466.9

441.2

410.9

502.5

476.8

446.5

411.4

371.8

513.6

483.2

448.2

408.5

551.5

521.2

486.1

446.5

590.6

560.3

525.2

485.6

672.3

642.0

606.9

567.3

758.7

728.3

693.3

653.6

849.7

819.4

784.4

744.7

700.3

945.4

915.1

880.1

840.4

796.0

734.0

1,045.8 1,015.5

980.4

940.8

896.4

834.4

793.7

1,150.9 1,120.5 1,085.5 1,045.8 1,001.5

939.5

898.7

609.3

1,260.6 1,230.2 1,195.2 1,155.5 1,111.2 1,049.2 1,008.5

950.1

1,375.0 1,344.6 1,309.6 1,269.9 1,225.6 1,163.6 1,122.8 1,064.5 1,494.0 1,463.7 1,428.7 1,389.0 1,344.6 1,282.6 1,241.9 1,183.5 1,617.7 1,587.4 1,552.4 1,512.7 1,468.3 1,406.3 1,365.6 1,307.3 1,746.1 1,715.8 1,680.8 1,641.1 1,596.7 1,534.7 1,494.0 1,435.7 1,879.2 1,848.8 1,813.8 1,774.1 1,729.8 1,667.8 1,627.1 1,568.7 2,016.9 1,986.6 1,951.6 1,911.9 1,867.5 1,805.5 1,764.8 1,706.4 2,159.3 2,129.0 2,094.0 2,054.3 2,009.9 1,947.9 1,907.2 1,848.8 2,306.4 2,276.0 2,241.0 2,201.3 2,157.0 2,095.0 2,054.3 1,995.9 2,458.1 2,427.8 2,392.8 2,353.1 2,308.7 2,246.7 2,206.0 2,147.7 2,614.5 2,584.2 2,549.2 2,509.5 2,465.1 2,403.1 2,362.4 2,304.1 2,775.6 2,745.3 2,710.2 2,670.6 2,626.2 2,564.2 2,523.5 2,465.1 2,911.0 2,876.0 2,836.3 2,791.9 2,729.9 2,689.2 2,630.9 3,081.4 3,046.4 3,006.7 2,962.4 2,900.3 2,859.6 2,801.3 3,256.5 3,221.5 3,181.8 3,137.4 3,075.4 3,034.7 2,976.4 3,436.2 3,401.2 3,361.5 3,317.2 3,255.2 3,214.5 3,156.1 3,585.6 3,546.0 3,501.6 3,439.6 3,398.9 3,340.5 3,774.7 3,735.0 3,690.7 3,628.7 3,588.0 3,529.6 3,968.5 3,928.8 3,884.4 3,822.4 3,781.7 3,723.4 4,166.9 4,127.2 4,082.9 4,020.9 3,980.2 3,921.8 4,286.0 4,223.9 4,183.2 4,124.9 4,493.7 4,431.7 4,391.0 4,332.6 4,706.2 4,644.1 4,603.4 4,545.1 4,923.2 4,861.2 4,820.5 4,762.2 5,145.0 5,083.0 5,042.3 4,983.9

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 of steel will displace 1 ft3; 2,747 lb of steel will displace 1 bbl

Bore of Drill Collar in. (mm) Drill Collar OD 11/4 11/2 13/4 2 21/4 21/2 213/16 3 31/4 in. 1 11/8 (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 31 31/8 (79.37) 31/4 (82.55) 33/8 (85.72) 31/2 (88.90) 33/4 (95.25) 37/8 (98.42) 41/2 (101.60) 41/8 (104.77) 41/4 (107.95) 41/2 (114.30) 43/4 (120.65) 51/2 (127.00) 51/4 (133.35) 51/2 (139.70) 53/4 (146.05) 61/2 (152.40) 61/4 (158.75) 61/2 (165.10) 63/4 (171.45) 71/2 (177.80) 71/4 (184.15) 71/2 (190.50) 73/4 (196.85) 81/2 (203.20) 8 1/4 (209.55) 81/2 (215.90) 83/4 (222.25) 91/2 (228.60) 91/4 (234.95) 91/2 (241.30) 93/4 (247.65) 101/2 (254.00) 101/4 (260.35) 101/2 (266.70) 103/4 (273.05) 111/2 (279.40) 111/4 (285.75) 111/2 (292.10) 113/4 (298.45) 121/2 (304.80)

35

34

33

30

38

37

36

33

39

36

33

43

40

37

50

47

44

54

51

48

44

40

55

51

48

44

59

55

52

48

63

60

56

52

72

68

65

60

81

78

74

70

65

90

87

83

79

75

101

97

94

89

85

111

108

104

100

95

89

84

122

119

116

111

107

100

96

78

134

131

127

123

118

112

107

101

146

143

139

135

130

124

120

113

159

156

152

148

143

136

132

126

172

169

165

161

156

150

145

139

186

183

179

175

170

163

159

153

200

197

193

189

184

177

173

167

215

211

208

203

199

192

188

182

230

227

223

219

214

207

203

197

245

242

238

234

230

223

219

212

262

258

255

250

246

239

235

229

278

275

271

267

262

256

251

245

295

292

288

284

279

273

269

262

310

306

302

297

290

286

280

328

324

320

315

309

304

298

346

343

339

334

327

323

317

366

362

358

353

346

342

336

382

377

373

366

362

355

402

397

393

386

382

376

422

418

413

407

403

396

443

439

434

428

423

417

456

449

445

439

478

472

467

461

501

494

490

484

524

517

513

507

547

541

536

530

76

Drill Collar

Drill Collar

PREVENTING PIN AND BOX FAILURES IN DOWNHOLE TOOLS

IF YOU HAVE AN EPIDEMIC OF DRILL COLLAR FAILURES THAT YOU CAN’T EXPLAIN:

The first rotary shouldered connection (pin by box) was used in drilling in 1909. It’s simple and rugged and nobody has designed anything basically better, since. However, it is subject to fatigue failures if it’s asked to work beyond its endurance limit, or if a few simple rules are not followed in its manufacture and use. We’ve written detailed booklets on care and use of drill collars. You can have one by writing to us, as suggested on the following page. However, if you’ll follow a few simple rules, listed below, and briefly detailed on the following pages, you can stay out of trouble.

First, get a copy of Smith’s Publication No. 39, “How to Drill a Usable Hole” which was compiled from a series of articles published in World Oil magazine. This brochure of pictures and examples explains controlling of hole deviation, the reasons holes become crooked and the problems that can result. If you would like a copy of this brochure, we will be glad to send you one. Just indicate the publication number and address your request to: Smith Services — Drilco Group Product Management P.O. Box 60068 Houston, Texas 77205-0068

Rule — Use Correct Makeup Torque Our experience indicates that perhaps 80% or more of all premature connection failures are due to incorrect makeup torque (see pages 37 through 65).

Second, to solve a drill collar problem, call your area Smith representative. This person has been trained in the care and maintenance of drill collars. Also, you can call anyone with Smith for information to help find a solution to such problems. After all, helping customers solve drill collar problems is the way our company started. Suppose you need help right now! Call Smith and tell our telephone operator “I have a drill collar problem and I want to talk with someone who can help me.” If you have time, write a letter giving us all the facts.* We will answer promptly. Smith is interested in your drill collar problems, both solving them and helping to prevent them in the future. *Smith Services Product Management P.O. Box 60068 Houston, Texas 77205-0068

Rule — Use Proper Thread Compound A good grade of drill collar compound contains powdered metallic zinc in the amount of 40 to 60% by weight (see page 38). Rule — Proper Tong Position Position tongs 8 in. (203 mm) below the box shoulder. Torque indicator should be located in snub line 90° to tong arm (see pages 42 through 50). Rule — Use Systematic Inspection Fatigue is an accumulative and progressive thing. Cracks ordinarily exist a long time before ultimate failure, and can be detected by proper inspection methods (see pages 143 and 152). Rule — Require Best Joint Design and Processing Much has been learned about how joint design and machining methods affect fatigue resistance (stress level) (see pages 37 through 70). Rule — Get Factory Quality From Field Shops To the extent possible, require the same machining and processing used by drill collar manufacturers (see page 66). Rule — Treat Tools Like Machinery, Not Pipe! Guard pins and boxes from damage and lubricate them properly. They’ll give lots of trouble-free service!

When writing or calling about a drill collar problem, 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.

77

Drill Collar

GUIDES FOR EVALUATING DRILL COLLAR OD, ID AND CONNECTION COMBINATIONS The BSR (Bending Strength Ratio) is used in the following charts as a basis for evaluating compatibility of drill collar OD, ID and connection combinations. The BSR is a number descriptive of the relative capacity of the pin and box to resist bending fatigue failures. It is generally accepted that a BSR of 2.50:1 is the right number for the average balanced connection, when drilling conditions are average. If you study the BSR ratios in the API RP 7G, you will realize that very few of the ODs and IDs commonly used on drill collars result in a BSR of 2.50:1 exactly, so the following charts were prepared using the following guidelines: 1. For small drill collars 6 in. (152.4 mm) OD and below, try to avoid BSRs above 2.75:1 or below 2.25:1. 2. For high rpm, soft formations and when drill collar 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 drill collar 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 as 3.40:1 will perform satisfactorily. 4. For very abrasive conditions where loss of OD is severe, favor combinations of 2.50:1 to 3.00:1. 5. For extremely corrosive environments, favor combinations of 2.50:1 to 3.00:1.81 How to Use the Connection Selection Charts on Pages 80 through 95. The charts appearing on pages 80 to 95 were prepared with the BSR guidelines as reference. 1. The best group of connections are defined as those that appear in the shaded sections of the charts. Also the nearer the connection lies to the reference line, the more desirable is its selection. 2. The second best group of connections are those that lie in the unshaded section of the charts on the left. The nearer the connection lies to the reference line, the more desirable is its selection.

Drill Collar

79

3. The third best group of connections are those that lie in the unshaded section of the charts on the right. The nearer the connection lies to the reference line, the more desirable is its selection. Example: Suppose you want to select the best connection 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). 213/16 in. ID Reference line

2nd choice

10

1st choice OD (in.)

78

3rd choice 93/4

75/8 H-90

91/2

NC 70 75/8 Reg. (Low torque)† 65/8 FH

Figure No. 55

For average conditions, you should select in this 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 order of 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 the strongest box. This connection should be considered as possible first choices for very abrasive formations or corrosive conditions.

Drill Collar

80

81

63/4

53/4

53/4

51/2

51/2

51/4

51/4

53/4

2.25

2.50

2.75

2.25

2.50

13/4 in. ID 2.75

11/2 in. ID

Drill Collar

NC 38 53/4

43/4

NC 38

31/2 XH 43/4

NC 35

41/2

31/2 XH NC 35

41/4

OD (in.)

OD (in.)

41/2

41/4

NC 31 31/2 Reg. 27/8 XH

43/4

NC 31 31/2 Reg. 43/4

33/4 31/2 PAC

27/8 XH 33/4

31/2 PAC

31/2

31/2

27/8 Reg. NC 26

31/4 27/8 Reg. NC 26

31/4

33/4 27/8 PAC

33/4

27/8 PAC

23/4

23/4

23/8 Reg. 23/8 PAC

21/2

21/2

23/8 PAC

21/4

Reference line

Reference line

Drill Collar

82

Drill Collar

83

2.25

2.50

3.00

2.25

2.50

2.75

3.00 61/2

2.75

21/4 in. ID

2 in. ID

7 3/4

NC 46

61/4

51/2 FH

71/2

NC 56

63/4

71/4

NC 44 53/4

73/4 51/2 Reg.

51/2

NC 50

63/4

51/4

61/2

NC 40

53/4

61/4 NC 46 OD (in.)

OD (in.)

NC 38 43/4

63/4

31/2 XH 41/2

NC 35

41/4

53/4 NC 44

51/2

43/4

51/4 NC 31 31/2 Reg. 27/8 XH

33/4

NC 40

53/4

31/2 PAC NC 38 31/2

43/4

31/4

41/2

31/2 XH NC 35

NC 26 33/4

41/4

Reference line

Reference line

Drill Collar

84

85

2.25

2.50

2.75

3.00

2.25

2.50

2.75

21/2 in. ID 3.00

21/2 in. ID

Drill Collar

73/4

10

51/2 Reg. 9 3/4

NC 50

63/4

91/2

61/2

NC 70

91/4

61/4 NC 46 75/8 Reg.*

93/4

63/4

65/8 FH 83/4

53/4

81/2 51/2 IF

OD (in.)

OD (in.)

NC 44 51/2

7 H-90* 81/4

NC 61

51/4 NC 40

83/4

53/4 65/8 H-90 65/8 Reg.

7 3/4

43/4 NC 38

51/2 FH

71/2

41/2

NC 56

31/2 XH

73/4

43/4

g. Re

50

Reference line

NC 35

1 2

5/

41/4

NC

71/4

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

Reference line

Drill Collar

86

87

2.25

2.50

2.75

3.00

2.50

3.00

111/2

2.25

213/16 in. ID 2.75

213/16 in. ID

Drill Collar

81/4 NC 61 83/4

111/4

65/8 H-90 73/4

113/4

65/8 Reg.

85/8 H-90* 71/2

51/2 FH

103/4

NC 56 1

7 /4 101/2

NC 77 85/8 Reg.* 73/4

OD (in.)

101/4 51/2 Reg. 63/4 NC 50

OD (in.)

10 61/2 93/4 61/4 75/8 H-90*

91/2

63/4 NC 70 NC 46

91/4 53/4

93/4 75/8 Reg.*

51/2

NC 44

65/8 FH 83/4

51/4 Reference line

81/2 51/2 IF 7 H-90* NC

5 8

6/

5 8

6/

81/4

61

90 H-

g. Re

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

Drill Collar

88

89

2.25

2.50

2.75

3.00

2.25

2.50

113/4

2.75

3 in. ID 3.00

3 in. ID

Drill Collar

81/2 51/2 IF

1

11 /2

1

8 /4

7 H-90 NC 61

111/4

83/4

113/4

73/4

65/8 H-90 65/8 Reg.

85/8 H-90*

103/4

71/2 51/2 FH NC 56

101/2 NC 77 85/8 Reg.*

OD (in.)

101/4

OD (in.)

71/4

73/4

63/4

10

51/2 Reg. NC 50

3

1

9 /4

6 /2

75/8 H-90*

91/2

61/4

NC 70 91/4

63/4

NC 46

53/4

93/4 5

7 /8 Reg.* 65/8 FH 51/2

83/4

NC

F 1 2I 5 / 90* 7 H 61 NC

Reference line


44

Reference line 81/2

Drill Collar

90

91

2.25

2.50

2.75

3.00

2.25

2.50

123/4

2.75

31/4 in. ID 3.00

31/4 in. ID

Drill Collar

83/4

113/4

81/2

111/2

81/4

111/4

83/4

113/4

7 3/4

51/2 IF 7 H-90* NC 61

65/8 H-90 65/8 Reg.

85/8 H-90*

71/2

OD (in.)

103/4

1

OD (in.)

10 /2

51/2 FH 1

7 /4

NC 56

NC 77 85/8 Reg.* 1

73/4

10 /4

63/4

10

51/2 Reg.

65/8 IF 93/4

NC 50

61/2

75/8 H-90* 91/2

61/4 NC 70 63/4

1

9 /4

53/4

93/4 5

7 /8 Reg.* 65/8 FH

83/4 IF 1 2 * 5/ -90 7H 1 6 NC

Reference line


NC 46 51/2 Reference line


Drill Collar

92

93

2.25

2.50

2.75

3.00

2.25

2.50

113/4

2.75

31/2 in. ID 3.00

31/2 in. ID

Drill Collar

83/4 65/8 FH

111/2

81/2

111/4

81/4

51/2 IF 7 H-90*

113/4

83/4

NC 61

85/8 H-90*

103/4

7 3/4

OD (in.)

65/8 H-90 101/2

NC 77 85/8 Reg.*

51/2 FH

71/4

OD (in.)

101/4

65/8 Reg.

71/2

NC 56 73/4

10

65/8 IF 93/4

63/4

91/2

75/8 H-90*

51/2 Reg.

61/2

NC 50 NC 70

1

9 /4

1

6 /4 Reference line

93/4 75/8 Reg.* 3

8 /4 5 8

6/ FH

IF 1 2 5/ * -90 7H 1 6 NC

Reference line



Drill Collar

94

53/4 2 21/4 21/2 213/16

51/2

51/4

71/4

31/2 H-90

53/4

1

2 /4 21/2 213/16 3

61/2

61/4

ID (in.)

63/4

ID (in.)

51/2 OD (in.)

73/4

OD (in.)

ID (in.)

63/4

OD (in.)

21/4 21/2 213/16 3 31/4 31/2

73/4

ID (in.)

71/4

61/2

51/4 2 21/4 21/2

3

5 /4

43/4

31/4 31/2

Reference line

63/4

Caution: The use of the 90° thread form on drill collar sizes less than 71/2 in. OD may result in hoop stresses high enough to cause swelled boxes. For this reason the API 60° thread form is preferred over the above sizes of the 90° thread form.

73/4

4 /2 H-90

2.25

61/4

63/4

1

2.50

61/2

71/2

5 H-90

2.75

3.00

4 H-90

73/4

OD (in.)

95

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

2.25

2.50

51/2 H-90

2.75

3.00

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

Drill Collar

63/4

H-90 Thread

60° Thread

ID (in.)

OD (in.)

61/2

2 21/4 21/2

61/4

63/4 213/16 3 31/4

53/4

51/2 Reference line

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

Drill Collar

96

Internal Flush (IF)

Full Hole (FH)

Extra Hole (XH) (EH)

Slim Hole (SH)

Double Streamline (DSL)

Num. Conn. (NC)

External Flush (EF)

Thread Form*

97

OILFIELD THREAD FORMS

Rotary Shouldered Connection Interchange List Common Name Pin Base Size Diameter Threads Taper Style (in.) (tapered) per In. (in./ft)

Drill Collar

Same As or Interchanges 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**

31/2

4.016

4

2

V-0.065 41/2 SH (V-0.038 rad) NC 38**

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

4

4.280

4

2

V-0.065 41/2 DSL (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 (V-0.038 rad) 41/2 EF

41/2

4.834

4

2

V-0.065 4 IF (V-0.038 rad) NC 46**

5

5.250

4

2

V-0.065 41/2 IF (V-0.038 rad) NC 50** 51/2 DSL

7

3

2 /8

2.876

4

2

V-0.065 2 /8 IF (V-0.038 rad) NC 26**

31/2

3.391

4

2

V-0.065 27/8 IF (V-0.038 rad) NC 31**

4

3.812

4

2

V-0.065 31/2 XH (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**

1

7

3 /2

3.327

4

2

V-0.065 2 /8 XH (V-0.038 rad)

41/2

4.280

4

2

V-0.065 4 FH (V-0.038 rad) NC 40**

51/2

5.250

4

2

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

26

2.876

4

2

V-0.038 rad

23/8 IF 27/8 SH

31

3.391

4

2

V-0.038 rad

27/8 IF 31/2 SH

38

4.016

4

2

V-0.038 rad

31/2 IF 41/2 SH

40

4.280

4

2

V-0.038 rad

4 FH 41/2 DSL

46

4.834

4

2

V-0.038 rad

4 IF 41/2 XH

50

5.250

4

2

V-0.038 rad

41/2 IF 5 XH 51/2 DSL

41/2

3.812

4

2

V-0.065 4 SH (V-0.038 rad) 31/2 XH

** Connections with two thread forms shown may be machined with either thread form without affecting gaging or interchangeability. ** Numbered Connections (NC) may be machined only with the V-0.038 radius thread form.

The following thread forms are used on practically all oilfield rotary shouldered connections. Only the 60° thread form is an API thread. The Modified V-0.065 (not shown) has been replaced and is interchangeable with the API V-0.038R. V-0.038R 2 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-0.038R 3 in. Taper Per Foot (TPF) on Diameter

4 Threads Per In. (TPI) Thread profile gage must be marked: V-0.038, 4 TPI, 3 in. TPF Used with: API NC 56, 61, 70 and 77

Figure No. 57

Drill Collar

98

Drill Collar

99

V-0.040 3 in. Taper Per Foot (TPF) on Diameter

H-90 2 in. Taper Per Foot (TPF) on Diameter

5 Threads Per In. (TPI)

31/2 Threads Per In. (TPI)

Thread profile gage must be marked: V-0.040, 5 TPI, 3 in. TPF

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

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

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

Figure No. 61

Figure No. 58


H-90 3 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 4 Threads Per In. (TPI) Thread profile gage must be marked: V-0.050, 4 TPI, 2 in. TPF Used with: API Reg. 65/8 in. API FH 51/2 and 65/8 in.

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

Figure No. 62 Figure No. 59


4 Threads Per In. (TPI) Thread profile gage must be marked: V-0.050, 4 TPI, 3 in. TPF Used with: API Reg. 51/2, 75/8 and 85/8 in.

Figure No. 60

Drill Collar

100

Drill Collar

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

101

Pin base diameter 1 /2 in. To flank of first full depth thread (max.) (H-90 and 27/8 in. XH = 3/8 in.; PAC = 1/4 in.)

30°

To flank of first full depth thread (min)

Diameter of counterbore

Pin length

Dimensional Identification of Box Connections (Not for Machining Purposes) Connection Size (in.) †23/8 PAC †27/8 PAC †NC 23 †23/8 Reg. †23/8 IF †27/8 Reg. †27/8 XH, EH †27/8 IF †31/2 Reg. †NC 35 †31/2 XH, EH †31/2 FH †31/2 IF †31/2 H-90 †4 FH †4 H-90 †NC 44 †41/2 Reg. †41/2 FH †41/2 H-90 †41/2 XH, EH †5 H-90 †41/2 IF †51/2 H-90 †51/2 Reg. †51/2 FH †NC 56 †65/8 Reg. †65/8 H-90 †51/2 IF †NC 61 †7 H-90 †65/8 FH †75/8 Reg. †NC 70 †75/8 H-90 †65/8 IF †85/8 Reg. †NC 77 †85/8 H-90

Threads per In. 4 4 4 5 4 5 4 4 5 4 4 5 4 31/2 4 31/2 4 5 5 31/2 4 31/2 4 31/2 4 4 4 4 31/2 4 4 31/2 4 4 4 31/2 4 4 4 31/2

Taper per In. 11/2 11/2 2 3 2 3 2 2 3 2 2 3 2 2 2 2 2 3 3 2 2 2 2 2 3 2 3 2 2 2 3 3 2 3 3 3 2 3 3 3

Full Depth Thread (in.) 21/2 21/2 31/8 31/8 31/8 35/8 41/8 35/8 37/8 37/8 35/8 37/8 41/8 41/8 45/8 43/8 45/8 43/8 41/8 45/8 45/8 47/8 45/8 47/8 47/8 51/8 51/8 51/8 51/8 51/8 55/8 55/8 51/8 53/8 61/8 61/4 51/8 51/2 65/8 63/4

Diameter of the Counterbore (in.) 213/32 219/32 25/8 211/16 215/16 31/16 323/64 329/64 39/16 313/16 37/8 43/64 45/64 43/16 411/32 49/16 411/16 411/16 47/8 457/64 429/32 511/64 55/16 57/16 537/64 529/32 515/16 61/16 61/16 629/64 61/2 69/16 6 27/32 73/32 73/8 729/64 733/64 83/64 81/16 821/64

Pin end diameter

Pin cylindrical diameter

Dimensional Identification of Pin Connections (Not for Machining Purposes) Connection Size Threads (in.) per In. 3 †2 /8 PAC 4 †27/8 PAC 4 †NC 23 4 †23/8 Reg. 5 †23/8 IF 4 †27/8 Reg. 5 †27/8 XH, EH 4 7 †2 /8 IF 4 †31/2 Reg. 5 †NC 35 4 †31/2 XH, EH 4 †31/2 FH 5 †31/2 IF 4 †31/2 H-90 31/2 †4 FH 4 †4 H-90 31/2 †NC 44 4 †41/2 Reg. 5 †41/2 FH 5 †41/2 H-90 31/2 †41/2 XH, EH 4 †5 H-90 31/2 1 †4 /2 IF 4 †51/2 H-90 31/2 1 †5 /2 Reg. 4 †51/2 FH 4 †NC 56 4 †65/8 Reg. 4 †65/8 H-90 31/2 †51/2 IF 4 †NC 61 4 †7 H-90 31/2 5 †6 /8 FH 4 †75/8 Reg. 4 †NC 70 4 †75/8 H-90 31/2 †65/8 IF 4 †85/8 Reg. 4 †NC 77 4 5 31/2 †8 /8 H-90

Taper per Foot (in.) 11/2 11/2 2 3 2 3 2 2 3 2 2 3 2 2 2 2 2 3 3 2 2 2 2 2 3 2 3 2 2 2 3 3 2 3 3 3 2 3 3 3

Pin Length (in.) 21/4 21/4 27/8 27/8 27/8 33/8 37/8 33/8 35/8 35/8 33/8 35/8 37/8 37/8 43/8 41/8 43/8 41/8 37/8 43/8 43/8 45/8 43/8 45/8 45/8 47/8 47/8 47/8 47/8 47/8 53/8 53/8 47/8 51/8 57/8 6 47/8 51/4 63/8 61/2

Pin End Pin Cyl. Pin Base Diameter Diameter Diameter (in.) (in.) (in.) 25/64 25/16 23/8 21/4 231/64 217/32 25/64 229/64 29/16 129/32 233/64 25/8 225/64 249/64 27/8 25/32 257/64 3 211/16 37/32 321/64 53 9 25 2 /64 3 /32 3 /64 219/32 325/64 31/2 29/64 35/8 347/64 31/4 345/64 313/16 33/32 357/64 4 33/8 329/32 41/64 331/64 315/16 41/8 39/16 411/64 49/32 313/16 45/16 41/2 357/64 433/64 45/8 319/32 433/64 45/8 353/64 411/16 451/64 47/64 441/64 453/64 47/64 423/32 453/64 421/64 459/64 57/64 433/64 59/64 51/4 439/64 53/16 53/8 423/64 513/32 533/64 51/64 523/32 553/64 421/64 523/32 57/8 511/64 57/8 6 53/16 513/16 6 537/64 69/32 625/64 3 9 7 5 /32 6 /32 6 /16 55/32 65/16 61/2 15 41 5 /16 6 /64 63/4 523/32 657/64 7 527/32 75/32 75/16 557/64 713/64 725/64 641/64 711/32 729/64 641/64 727/32 761/64 613/32 727/32 8 641/64 85/64 817/64

Low Torque Face

Dimensional Identification for Low Torque Modification 7 H-90 75/8 Reg. 85/8 Reg. 75/8 H-90 85/8 H-90

31/2 4 4 31/2 31/2

3 3 3 3 3

55/8 53/8 51/2 61/4 63/4

†See page 96 for interchangeable connections.

*71/8 *73/4 *9 *8 *93/8

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

102

Drill Collar

MATERIAL AND WELDING PRECAUTIONS FOR DOWNHOLE TOOLS Generally, the materials used in the manufacture of downhole tools (stabilizers, vibration dampeners, reamers, subs, drill collars, kellys and tool joints) are AISI 4137 H, 4140 H or 4145 H. These materials are purchased by Smith with customized chemistries to assure that they will have the hardenability necessary to heat treat to desired mechanical properties for each product. By customizing chemistries and in-house heat treatment of these materials to a specification suitable for each product or product component, strength levels are assured to (1) minimize swelled boxes and stretched pins, (2) prolong fatigue life, (3) retard crack propagation rates, and (4) support tensile loads. All of the above mentioned products are manufactured by Smith using these types of material which are alloy materials in the heat treated state. They cannot be welded in the field without metallurgical change to the welded area. Any metallurgical change induced by welding in the field will reduce the benefits of customizing purchases and in-house heat treatment described in the paragraph above. Preheat procedures can be used to prevent cracking while welding and post-heat procedures can be used to recondition sections where welding has been performed; but, it should be emphasized that field welded sections can only be reconditioned and cannot be restored to their original state, free of metallurgical change.

5

SECTION FIVE

HEVI-WATET DRILL PIPE

Hevi-Wate Drill Pipe

WHAT IS HEVI-WATE DRILL PIPE? Smith’s Hevi-Wate drill pipe is an intermediateweight drill stem member. It consists of heavy-wall tubes attached to special extra-length tool joints. It has drill pipe dimensions for ease of handling. Because of its weight and construction, Hevi-Wate drill pipe can be run in compression the same as drill collars in small diameter holes and in highly deviated and horizontal wells. Although special lengths are available, the pipe is normally furnished in 301/2 ft (9.3 m) lengths in six sizes from 31/2 to 65/8 in. (88.9 to 168.3 mm) OD. One outstanding feature is the integral center wear pad which protects the tube from abrasive wear. This wear pad acts as a stabilizer and is a factor in the overall stiffness and rigidity of one or more 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 weighs approximately 41 lb/ft. As another comparison, 61/2 in. OD, 21/4 in. ID drill collars weigh 100 lb/ft. Example: An approximate weight of 114.3 mm OD drill pipe is 24.7 kg/m; 114.3 mm Hevi-Wate drill pipe weighs approximately 61.1 kg/m. As another comparison, 165.1 mm OD, 57.2 mm ID drill collars weigh 148.8 kg/m. When a number of drill collars are used in directional drilling, they produce a great amount of contact area with the low side of the hole. As the collars are rotated, this high friction contact with the hole wall causes the collars to climb the side of the wall. Many people feel this rotation climbing action of the bottom collar causes the bit to turn hole direction to the right. Hevi-Wate drill pipe provides stability and much less wall contact. This results in the directional driller being able to “lock-in” and better control both hole angle and direction.

105


106

Using Hevi-Wate Drill Pipe for Bit Weight on Small Rigs Hevi-Wate drill pipe, run in compression for bit weight, 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 is run in compression, the more rigid Hevi-Wate drill pipe will allow more bit weight to be run with less likelihood 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 string of Hevi-Wate drill pipe will eliminate many of the problems associated with drill collars normally used on the smaller rigs.

Hevi-Wate Drill Pipe Stands back in the rack like regular drill pipe.

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

Requires only drill pipe elevators to handle on the rig.

Figure No. 64

USING HEVI-WATE DRILL PIPE IN THE TRANSITION ZONE BETWEEN THE DRILL COLLARS AND THE DRILL PIPE Many drill pipe failures occur in the drill stem because of fatigue damage previously accumulated when the failed joint of pipe was run directly above the drill collars. This accelerated fatigue damage is attributed to the bending stress concentration in the limber drill pipe rotating next to the stiff drill collars. Two factors that cause extreme bending stress concentration 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 vertical bounce and vibrations of the drill collars, that are transmitted up to the bottom joint of drill pipe.

No safety clamp is required and regular drill pipe slips are used.

Figure No. 63

107

108

Hevi-Wate Drill Pipe When drill pipe is subjected to compressive buckling these stress concentrations are much more severe. Many drillers periodically move the bottom joint of drill pipe to a location higher up in the drill pipe string. Moving these joints to other drill string locations does not remove the cumulative fatigue damage that has been done, and may or may not prolong the time until failure will occur. Hevi-Wate drill pipe is an intermediate-weight drill stem member, with a tube wall approximately 1 in. (25.4 mm) thick. This compares to approximately 3/8 in. (9.5 mm) wall thickness for regular drill pipe and approximately 2 in. (50.8 mm) wall thickness for drill collars. Hevi-Wate drill pipe provides a graduated change in stiffness between the limber drill pipe above and the rigid drill collars below. This graduated change in stiffness reduces the likelihood of drill pipe fatigue failures when Hevi-Wate drill pipe is run in the critical transition “zone of destruction.” Performance records compiled during the past few years show that running Hevi-Wate drill pipe above the drill collars definitely reduces drill pipe fatigue failures. Hevi-Wate drill pipe’s heavy-wall design, long tool joints and long center upset section resist the high-stress concentration and center body OD wear which causes failures in regular drill pipe. Because of its construction, Hevi-Wate drill pipe can be inspected by the same technique used to prevent drill collar failures. The number of joints of pipe that should be run in the transition zone is important. Based on successful field experience, a minimum of 18 to 21 joints of Hevi-Wate drill pipe are recommended between the drill collars and the regular drill pipe in vertical holes. Thirty (30) or more joints are commonly used in directional holes.


109

(18 joints or more) Hevi-Wate drill pipe Additional drill collars

Integral blade stabilizer

Drill collar Hydra-shock®

IB Stabilizer (Integral Blade) Short drill collar

Near bit Stabilizer

3-Point Borrox reamer

Figure No. 65

110


USING HEVI-WATE DRILL PIPE IN DIRECTIONAL DRILLING Excessive drill collar connection failures result from collars bending as they rotate through doglegs and hole angle changes. Drill collars lay to the low side of high-angle holes. 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 very high-rotating torque and excessive bending loads at the threaded connections. Hevi-Wate drill pipe bends primarily in the tube. This reduces the likelihood of tool joint fatigue failures occurring in the Hevi-Wate drill pipe as it rotates through doglegs and hole angle changes. Hevi-Wate drill pipe design offers less wall contact area between the pipe and hole wall which results in: · Less rotary torque. · Less chance of differential sticking. · Less vertical drag. · Better directional control.


111

Hevi_Wate Drill pipe

IB stabilizer Spiral drill collar Hydra-Shock®

IB stabilizer (Integral Blade)

Near bit IB stabilizer

Figure No. 66


112

Capacity and Displacement Table — Hevi-Wate Drill Pipe

Tube Displacement

Gal BBL Gal BBL Gal BBL Gal BBL per per per per per per per per 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

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

.828

5

11.23 .267

37.5

51/2

14.26 .340

47.5 1.132 25.92 .617 86.41 2.057

65/8

25.01

83.4 1.985 32.17 .766 107.24 2.553

.596

113

Dimensional Data Range III

Capacity Nominal Size (in.)


.892 22.46 .535 74.87 1.783

Mechanical Properties Tube Section

Nominal Tube Dimension Nom. Size (in.)

ID (in.)

41/2

23/4

5

3

Wall Thickness (in.)

Center Elevator Tensile Area Upset Upset Yield (in2) (in.) (in.) (lb)

.875

9.965

1.000

12.566

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

Tube

Mechanical Properties Tube Section

Nominal Tube Dimension

ID (in.)

Wall Thickness (in.)

Center Elevator Tensile Area Upset Upset Yield 2 (in ) (in.) (in.) (lb)

Torsional Yield (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

691,185

56,495

814,660

74,140

5

3

1.000

12.566

5 /2

51/8

51/2

33/8

1.063

14.812

6

511/16

65/8

41/2

1.063

18.567

71/8

63/4

1

Tool Joint

Mechanical Properties Nom. Size (in.)

Connection Size OD ID (in.) (in.) (in.)

Tensile Yield (lb)

1,021,185 118,845

Approx. Weight [Including Tube & Joints (lb)]

Torsional Yield Wt/ (ft-lb) ft

Wt/ Jt.

Makeup Torque (ft-lb)

31/2 NC 38 (31/2 IF) 43/4

23/8

675,045

17,575

23.4

721

10,000

NC 40 (4 FH) 51/4

211/16

711,475

23,525

29.9

920

13,300

4 41/2 5

45/8

548,075

40,715

51/8

691,185

56,495

Mechanical Properties Nom. Size (in.) 41/2 5

Connection Size OD ID (in.) (in.) (in.)

Tensile Yield (lb)

Approx. Weight [Including Tube & Joints (lb)]

Torsional Makeup Yield Wt/ Wt/Jt. Torque (ft-lb) ft 30 ft (ft-lb)

NC 46 (4 IF) 61/4

27/8

1,024,500

38,800

39.9

1,750

21,800

NC 50 (41/2 IF) 65/8

31/16

1,266,000

51,375

48.5

2,130

29,200

See page 123 for metric conversions.

TAPERED DRILL STRINGS

Dimensional Data Range II

Nom. Size (in.)

5 51/2

Tool Joint

*Capacity and displacement per joint numbers are based on 30 ft shoulder to shoulder joints. xx With 21/4 in. ID.

Torsional Yield (ft-lb)

NC 46 (4 IF) 61/4

27/8

1,024,500

38,800

41.1

1,265

21,800

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.

The ratios of I/C or section moduli between drill collars and Hevi-Wate drill pipe or drill pipe should be considered to prevent fatigue damage to these members. Experience has indicated that these members perform best when this ratio is less than 5.5. Tapered drill collar strings are often necessary to maintain an acceptable ratio. The chart on the next page is based on maintaining an acceptable I/C ratio between Hevi-Wate drill 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 Holes a. Enter chart from bottom at 41/2 in. (114.3 mm) Hevi-Wate drill pipe and proceed upward to the “suggested upper limit for directional holes” curve. Read to the left the maximum drill collar size. b. Suggested maximum drill collar size = 73/4 in. (196.9 mm) OD x standard bore. 2. For Straight Holes a. Enter chart from bottom at 41/2 in. (114.3 mm) Hevi-Wate drill pipe and proceed upward to the “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.


114

81/4

Suggested upper limit for directional holes

81/2 73/4

Drill collar OD (in.)

71/2 71/4 1

Suggested upper limit for straight holes

6

7 /2 63/4 61/2

SECTION SIX

61/4 61/2

51/2 Suggested upper limit for severe drilling conditions

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

5

3. For Severe Drilling Conditions (Corrosive Environment and/or Hard Formations) a. Enter chart from bottom at 41/2 in. (114.3 mm) Hevi-Wate drill pipe and proceed upward to the “suggested upper limit for severe conditions” curve. Read to the left the maximum drill 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 select drill collar ODs above the suggested upper limits for each condition. Fatigue failures are more likely if these limits are exceeded. If drill collars larger than the maximum suggested size are to be used, run at least three drill collars of the maximum suggested size (or smaller) between the larger drill collars and the Hevi-Wate drill pipe.

TOOL JOINTS

Tool Joints

TOOL JOINTS One of the primary purposes of drill pipe is to transmit drilling torque from the rotary table drive bushing and kelly to the drilling bit at the bottom of the hole. It also provides a means whereby fluid may be circulated for lubricating and cooling the bit and for the removal of cuttings from the wellbore. Drill pipe connections require different treatment than drill collar connections. Drill pipe tool joints are much stiffer and stronger than the tube and seldom experience bending fatigue damage in the connection. Therefore, tool joint connections are normally selected based on torsional strength of the pin connection and tube and not on bending strength ratios as in drill collar connections. Drill collar connections differ in that they are a sacrificial element and can never be made as strong as the drill collar body. The repair is also different. A drill collar connection can be renewed by cutting off the old connection and completely remachining a new one; whereas a drill pipe connection can only be reworked by chasing the threads and refacing the shoulder because of its short length. The most common damage occurring to drill pipe tool joints is caused by leaking fluid, careless handling, thread wear or galling, and swelled boxes due to outside diameter wear. As with drill collars, the break-in of new drill pipe tool joints is extremely important for long life. Newly machined surfaces are more susceptible to galling until they become work hardened. Therefore, the connections should be chemically etched by a gallresistant coating (see page 67) to hold the thread compound and protect the newly machined surfaces on the initial makeup. Extra care is essential to ensure long and trouble-free service. Thread protectors should be used while drill pipe is being picked up, laid down, moved or stored. Be sure to thoroughly clean all threads and shoulders of any foreign material or protective coating and inspect for damage before the first makeup. If kerosene, diesel or other liquid is used, allow sufficient drying time before applying thread compound to the connections. When applying thread compound, be sure to cover thoroughly the entire surface of the threads and shoulders of both

117

118

Tool Joints pin and box connections. It is preferable to use a good grade of zinc thread compound that contains no more than 0.3% sulfur. (A thread compound containing 40 to 60% by weight of finely powdered metallic zinc is recommended in API RP 7G.) Proper initial makeup is probably the most important factor effecting the life of the tool joint connections. Here are some recommendations to follow: 1. Proper makeup torque is determined by the connection type, size, OD and ID, and may be found in torque tables (see pages 130 and 131). 2. Make up connections slowly, preferably using chain tongs. (High-speed kelly spinners or the spinning chain used on initial makeup can cause galling of the threads.) 3. Tong them up to the predetermined torque using a properly working torque gage to measure the required line pull (see page 41). 4. Stagger breaks on each trip so that each connection can be checked, redoped and made up every second or third trip, depending on the length of drill pipe and size of rig. A new string of drill pipe deserves good surface handling equipment and tools. Check slips and master bushings before damage occurs to the tube (see the IADC Drilling Manual for correct measurement). Do not stop the downward movement of the drill string with the slips. This can cause crushing or necking down of the drill pipe tube. The drill pipe can also be damaged by allowing the slips to ride the pipe on trips out of the hole. Good rig practices will help eliminate time consuming trips in the future, looking for washouts or fishing for drill pipe lost in the hole. For more information refer to the IADC Drilling Manual.

Tool Joints

119

RECOMMENDED PRACTICE FOR MARKING ON TOOL JOINTS FOR IDENTIFICATION OF DRILL STRING COMPONENTS Company, Month Welded, Year Welded, Pipe Manufacturer and Drill Pipe Grade Symbols to be Stencilled at Base of Pin. Sample Markings: 1 D

2 9

3 99

4 V

5 E

1 — Company 2 — Month welded 9 = September 3 — Year welded 99 = 1999 4 — Pipe manufacturers V = Vallourec 5 — Drill pipe grade E = Grade E drill pipe Month Year 1 through 12 Last two digits of year Pipe Manufacturers (Pipe Mills or Processors) Symbols Pipe Mill Symbol Active Algoma ........................................................... X British Steel Seamless Tubes LTD ..................... B Dalmine S.P.A. ................................................ D Falck ............................................................... F Kawasaki ........................................................ H Nippon ............................................................. I NKK ................................................................ K Mannesmann ................................................. M Reynolds Aluminum ...................................... RA Sumitomo ........................................................ S Siderca .......................................................... SD TAMSA ............................................................ T U.S. Steel ........................................................ N Vallourec ......................................................... V Used ............................................................... U Inactive Armco ............................................................. A American Seamless ........................................ AI B & W ............................................................ W C F & I ............................................................ C J & L Steel ........................................................ J Lone Star ......................................................... L Ohio ............................................................... O Republic .......................................................... R TI .................................................................... Z

Tool Joints

120

Tool Joints

121

Tubemuse ..................................................... TU Voest ............................................................. VA Wheeling Pittsburgh ........................................ P Youngstown .................................................... Y Processor Symbol Grant TFW ................................................. TFW Omsco ....................................................... OMS Prideco ........................................................... PI Drill Pipe Grades and Their Symbols Grade Symbol D 55 D E 75 E X 95 X G 105 G S 135 S V 150 V Used U

Minimum Yield 55,000 75,000 95,000 105,000 135,000 150,000 —

Figure No. 67

Note: Heavy-weight drill pipe to be stencilled at base of pin with double pipe grade code. Figure No. 68

It is suggested that a bench mark be provided for the determination of the amount of material which may be removed from the tool joint shoulder, if it is refaced. This bench mark should be stencilled on 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 the circle parallel to the shoulder. The distance from the shoulder to the bar should be 1/8 in. (3.2 mm). The bench mark should be positioned in the box counterbore and on the base of the pin as shown in Figure Nos. 67 and 68. It is good practice not to remove more than 1 /32 in. (0.8 mm) from a box or pin shoulder at any one refacing and not more than 1/16 in. (1.6 mm) cumulatively.

122

Tool Joints

RECOMMENDED IDENTIFICATION GROOVE AND MARKING OF DRILL PIPE Note: 1. Standard weight Grade E drill pipe designated by an asterisk (*see page 123) in the drill pipe weight code table will have no groove or milled slot for identification. The API identification for Grade E heavy-weight drill pipe manufactured after January 1, 1995, is a milled slot only beginning 1/2 in. from the intersection of the 18° taper and the tool joint OD. The API identification for Grade E heavy-weight drill pipe manufactured before January 1, 1995, was a milled slot only in the center of the tong space. ISO marking is per the before January 1, 1995, style. 2. See API Recommended Practice RP 7G for depth of grooves and slots. 3. Stencil grade code symbol and weight code number 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 with drill pipe hanging in elevators.

Tool Joints

123

Drill Pipe Weight Code 1 OD Size (in.) 23/8 27/8 31/2

41/2

41/2

51/2

51/2 65/8

2 Nominal Weight (lb/ft) 4.85 6.65* 6.85 10.40* 9.50 13.30* 15.50 11.85 14.00* 15.70 13.75 16.60* 20.00 22.82 24.66 25.50 16.25 19.50* 25.60 19.20 21.90* 24.70 25.20*

3 Wall Thickness (in.) .190 .280 .217 .362 .254 .368 .449 .262 .330 .380 .271 .337 .430 .500 .550 .575 .296 .362 .500 .304 .361 .415 .330

*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.

4 Weight Code Number 1 2 1 2 1 2 3 1 2 3 1 2 3 4 5 6 1 2 3 1 2 3 2

Tool Joints

124

Tool Joints

125

Standard Weight High-Strength Drill Pipe API Before January 1, 1995

Standard Weight Grade E Drill Pipe

(page 122)


Heavy-Weight Grade E Drill Pipe API Before January 1, 1995

Heavy-Weight High-Strength Drill Pipe API Before January 1, 1995

(page 122) (page 122)


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

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

Tool Joints

126 Heavy-Weight Grade E Drill Pipe API After January 1, 1995

Tool Joints

127

Standard Weight Grade X Drill Pipe API After January 1, 1995

See Note 2 (page 122)



Heavy-Weight Grade X Drill Pipe API After January 1, 1995


Figure No. 75

Tool Joints

128 Standard Weight Grade G Drill Pipe API After January 1, 1995

Tool Joints

129

Standard Weight Grade S Drill Pipe API After January 1, 1995



Figure No. 76

Figure No. 78

Heavy-Weight Grade G Drill Pipe API After January 1, 1995

Heavy-Weight Grade S Drill Pipe API After January 1, 1995


Figure No. 77


Figure No. 79

Tool Joints

130

Torque Chart Drill Pipe Tool Joint Recommended Minimums

Tool Joints

131

Torque Chart Drill Pipe Tool Joint Recommended Minimums Used

New Drill Pipe Size (in.)

23/8

27/8

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

Type Connection (in.) NC 26 (IF) OH OH SL H-90 WO PAC 7 2 /8 SH (NC 26) OH

Box OD (in.) 33/8 31/4 31/8 31/4 33/8 27/8 33/8 33/4

Pin ID (in.) 13/4 13/4 2 2 2 13/8 13/4 27/16

Makeup Torque (ft-lb) 4,125 3,783 2,716 3,077 2,586 2,813 4,125 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

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

NC 38 (IF)

43/4

211/16

10,864

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

NC 40 (4 FH)

53/8

27/16

NC 40 (4 FH)

51/2

21/4

SH (3 1/2 XH)

45/8

29/16

OH

51/4

315/32

13,186

OH

51/2

31/4

16,320

NC 40 (4 FH)

51/4

213/16

NC 40 (4 FH)

51/4

211/16

7,688 31/2

16,656

17,958

19,766

9,102

14,092

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.

Box OD (in.) 31/4 31/16 3 231/32 1 3 /16 225/32 33/8 31/2 319/32 317/32 319/32 31/8 35/8 323/32 311/16 329/32 41/16 4 43/16 43/8 49/32 43/8 43/8 43/8 419/32 421/32 423/32 415/16 5 53/32 7 4 /16 431/32 51/32 413/16 415/16 5 5 7 5 /32 5 5 /16 57/16 515/32 59/32 59/16 55/8 55/8 515/32 53/8 59/16 55/8 513/32 519/32 525/32 523/32 529/32 523/32 513/16 515/16 67/32 57/8 61/32 63/32 63/16 69/32 621/32 623/32 615/16 617/32 65/8 625/32 71/32

Makeup Torque (ft-lb) 3,005 2,216 1,723 1,998 1,994 2,455 4,125 3,282 4,410 3,767 4,529 3,443 3,216 4,357 3,154 5,723 7,694 6,893 5,521 8,742 5,340 7,000 5,283 5,283 8,826 9,875 10,957 11,363 12,569 14,419 8,782 7,500 8,800 9,017 11,363 12,569 12,569 7,827 9,937 12,813 13,547 9,228 15,787 17,311 17,311 12,300 12,125 16,391 17,861 12,080 16,546 21,230 19,626 16,626 11,571 14,082 17,497 25,547 15,776 20,120 21,914 24,645 27,429 25,474 27,619 35,446 21,238 24,412 29,828 38,892

Box OD (in.) 33/16 31/32 231/32 231/32 3 223/32 5 3 /16 37/16 317/32 317/32 317/32 31/16 39/16 321/32 321/32 313/16 331/32 329/32 41/8 49/32 47/32 45/16 411/32 411/32 41/2 49/16 45/8 413/16 47/8 415/16 411/32 429/32 431/32 423/32 413/16 47/8 47/8 55/32 57/32 55/16 53/8 53/16 57/16 51/2 51/2 53/8 59/32 57/16 515/32 55/16 515/32 55/8 59/16 525/32 521/32 523/32 527/32 61/16 525/32 529/32 531/32 61/32 61/8 61/2 69/16 63/4 67/16 61/2 65/8 627/32


Box OD (in.) 35/32 231/32 215/16 231/32 231/32 221/32 31/4 313/32 315/32 37/16 315/32 231/32 317/32 35/8 321/32 33/4 37/8 327/32 43/32 47/32 45/32 41/4 49/32 49/32 47/16 415/32 417/32 43/4 425/32 427/32 49/32 427/32 429/32 421/32 43/4 425/32 425/32 55/32 53/16 51/4 59/32 55/32 53/8 513/32 513/32 55/16 53/16 511/32 53/8 51/4 53/8 51/2 515/32 523/32 519/32 521/32 53/4 515/16 511/16 513/16 527/32 515/16 6 613/32 615/32 65/8 611/32 613/32 617/32 611/16


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.

132

Tool Joints A large portion of the information found on pages 119 through 129 was taken directly out of the IADC Drilling Manual (eleventh edition) and the API Spec. RP 7G (fifteenth edition). Credit should be given to the International Association of Drilling Contractors and the American Petroleum Institute. Smith extends our thanks to IADC and API for allowing us to reprint this information.

7

SECTION SEVEN

KELLYS

Kellys

135

KELLYS Kellys are manufactured with one of two basic configurations — square or hexagonal. Kelly Sizes The size of a kelly is determined by the distance across the drive flats (see Figure Nos. 80 and 81).

Like this

Not like this

Figure No. 80

Figure No. 81

Kelly Lengths API kellys are manufactured in two standard lengths: (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 Top Connection

Top OD

Bottom Bottom Connection OD

API Nom. Size (in.)

Std. (LH) (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

Optional (LH) Std. Optional Std. (RH) (in.) (in.) (in.) (in.)

41/4

65/8 Reg.

41/2 Reg.

73/4

53/4

51/4

65/8 Reg.

41/2 Reg.

73/4

53/4

**6

65/8 Reg.

—

73/4

—

**6 in. square kelly not API.

Std (in.)

NC 46

6

NC 50

61/8

51/2 FH NC 56 6 5/8 FH

7 73/4

Kellys

136

Kellys

137

Hexagon Kellys Top Connection API Nom. Size (in.)

Std. (LH) (in.)

3

65/8 Reg.

1

3 /2 1

4 /4

5

6 /8 Reg. 5

6 /8 Reg.

Top OD

Bottom Bottom Connection OD

Optional (LH) Std. Optional Std. (RH) (in.) (in.) (in.) (in.)

Std (in.)

41/2 Reg. 1 1

4 /2 Reg. 4 /2 Reg.

73/4

53/4

NC 26

33/8

3

7 /4

3

5 /4

NC 31

41/8

3

3

NC 38

43/4

7 /4

5 /4

51/4

65/8 Reg.

—

73/4

—

6

65/8 Reg.

—

73/4

—

NC 46

6

NC 50

61/8

51/2 FH NC 56

7

Measurement of New Kellys

Figure No. 83

Hexagon Kellys API Nom. Size (in.)

Max. Bore A (in.)

Across Flats B (in.)

Across Corner C (in.)

Radius R* (in.)

Radius Rc (in.)

3

11/2

3

3.375

1

111/16

31/2

13/4

31/2

3.937

1

/4

131/32

1

4 /4

1

2 /4

1

4 /4

4.781

5

/16

225/64

51/4

31/4

51/4

5.900

3

261/64

6

31/2

6

6.812

3

313/32

/4

/8 /8

* Corner configuration at manufacturer’s option.

HOW TO BREAK IN A NEW KELLY

Figure No. 82

Square Kellys API Nom. Size (in.)

Max. Bore A (in.)

Across Flats B (in.)

Across Corner C (in.)

21/2

11/4

21/2

3.250

5

/16

15/8 115/16

3

Radius R* (in.)

Radius Rc (in.)

3

1 /4

3

3.875

3

31/2

21/4

31/2

4.437

1

27/32

41/4

213/16

41/4

5.500

1

23/4

51/4

31/4

51/4

6.750

5

33/8

**6

1

7.625

3

13

3 /2

6

/8 /2 /2 /8 /4

** Corner configuration at manufacturer’s option. ** 6 in. square kelly not API.

3 /16

When Picking Up a New Kelly Before picking up a new kelly, check your kelly bushing. The rollers, pins or bearings may need replacing to return the drive assembly to like new status. Also check the bushing body for journal area wear and body spreading. A loose fitting drive unit can badly damage a new kelly on the first well drilled. Remember to lubricate kelly drive surfaces. Check Wear Pattern on Corners of Kelly The major cause for a kelly to wear out is the rounding off of the drive corners. This rate of wear is a function of the clearance or fit between the kelly and the rollers in the kelly bushing. The closer the kelly and rollers fit, the broader will be the wear pattern. A narrow wear pattern on the kelly’s corners usually indicates a loose fit between the two.

Kellys

138

Kellys

139

Rollers must fit the largest spot on the kelly flats. The API tolerances on distance across flats are quite large and bushings fitting properly in one place may actually appear loose at another point. Generally kellys made from forgings have wide variations in tolerances, making it impossible to fit the roller closely at all points. Kellys manufactured by full length machining are made to closer tolerances and fit the rollers best. Maximum Wear Pattern Width for New Kellys with New Drive Assembly (in.) Figure No. 86

Kelly after considerable use with only new drive assembly. The drive edge will have a flat pattern of reduced width and increased contact angle. A curved surface will be visible on the kelly near the roller center.

Figure No. 84

Figure No. 87

Worn kelly with worn drive assembly. The drive edge is a curvature with a high contact angle. Figure No. 85

New kelly with new drive assembly. The drive edge will have a wide flat pattern with a small contact angle.

Inspection At regular intervals, have the kelly’s threaded connections checked by your Drilco inspector. Remember these connections are subject to fatigue cracks the same as drill collar connections. Also, the drive section and upset areas should be inspected for cracks and wear patterns. Kelly Saver Subs Kelly saver subs protect the lower kelly connection from wear caused by making and breaking the drill pipe connection each time a joint is drilled down. They also protect the top joint of casing against excessive wear, if fitted with a rubber protector, as

Kellys

140

well as provide an area to tong on when making up or breaking out the kelly. When you need a new stabilizer rubber, an old sub re-worked or a brand new one, mention this to your Smith representative before you are ready to pick up that new kelly.

WHAT CAN YOU DO WITH THAT OLD KELLY? Use the Other Corners By employing a temperature controlled stubbing procedure, we can change ends on your kelly. This allows the kelly to drive against new corners. Welding is done only in the large diameter round sections. We do not recommend welding on the hexagonal or square surfaces of the kelly. Remachine Drive Surfaces With 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 your kelly must be small enough to allow enough wall thickness for remachining. Ask your Smith representative for more information. Straightening an Old Kelly A bent kelly takes a beating as it is forced through the rotary drive bushings. Smith repair centers have straightening presses that can straighten a kelly and accurately check the run-out. If Your Kelly is Too Far Gone Your best bet is to buy a new kelly from your Smith representative.

8

SECTION EIGHT

INSPECTION

Inspection

SYSTEMATIC FIELD INSPECTION A systematic approach to proper inspection, maintenance and repair of downhole drilling tools is a necessity for proper operation and to prolong the useful life of the equipment. Most downhole drilling tool failures and resultant fishing jobs can be avoided by the use of periodic inspections and by providing maintenance and repair to the primary areas of fatigue within the tool. The primary areas of fatigue are areas on the tool that are likely to receive the highest concentration of stress while operating. The majority of stress is concentrated in several common areas on these tools such as: connections, slip areas, upset areas, weld areas, radius changes, tube body, etc. Smith Field Inspection Services regularly utilizes several types of nondestructive testing (NDT) methods to inspect these primary areas for potential problems. Visual (VT), magnetic particle (MT), liquid penetrant (PT), ultrasonic (UT) and electromagnetic (ET) testing methods are all utilized for efficiency and detection capabilities. When inspecting the threaded connections on drill collars, Hevi-Wate, stabilizers, reamers, hole openers, kellys, as well as other downhole drilling tools, the primary NDT method of inspection is the magnetic particle inspection method. This common method utilizes fluorescent magnetic particles to detect cracks in the threaded area of the connection or other locations as necessary. To illustrate the principle of magnetic particle inspection, you can sprinkle magnetic particles on a bar which has been magnetized. The magnetized bar acts as a magnet with a north pole at one end and a south pole at the other end. The magnetic particles will be attracted to the poles of the magnet. If the bar is notched, each side of the notch becomes a pole of a

143

Inspection

144

magnet (see Figure No. 88). If the notch is narrow, the magnetized particles will form a bridge between the poles. Cracks in threaded connections or in other locations behave the same way when magnetized.

Inspection

145

Proper maintenance and inspection of downhole tools begins with proper cleaning. The threaded areas are cleaned by a wire brush adapted to an electric drill (see Figure No. 90). It is essential that all thread lubricant, dirt and corrosion be removed from the threads and shoulders prior to inspection.

Figure No. 90

Particle buildup

Figure No. 88

All connections are magnetized with DC magnetizing coils utilizing the continuous method of particle application. The continuous method provides for magnetizing the part to be inspected at the same time of magnetic particle application, thus ensuring proper magnetization and superior defect detection (see Figure No. 91). Magnetic particles are attracted to any cracks present by the principle shown in Figure No. 88.

Smith’s field inspectors are thoroughly trained in the principles and techniques of defect detection, correction and prevention. Rugged trucks, complete with calibrated and certified inspection equipment, provide access to remote locations (see Figure No. 89).

Figure No. 91

Figure No. 89

Inspection

146

Using ultraviolet light, the inspector’s experienced eye detects any build up of magnetic particles in the thread roots of the pin connection (see Figure No. 92). A magnifying mirror enables the inspector to look into the thread roots of the box connection.

Inspection

147

As part of the inspection record, the drill collar serial number, tally length, OD and ID are noted. Also connection size and type, field repairs made, and number of connections inspected are recorded. Joints requiring shop repairs are clearly marked to ensure proper identification of the repair required (see Figure No. 94). Tools are marked with the appropriate color paint to conform with API and/or customer requirements. Red marking is used on cracked collars and yellow on collars with other defects. White markings, along with the well-recognized “OK Drilco,” are used to indicate acceptable equipment.

Figure No. 92

If a crack indication is found, the inspector polishes it with a soft fibrous wheel to verify the presence of a fatigue crack (see Figure No. 93). He then re-cleans, re-magnetizes and re-sprays the connection with fluorescent magnetic particles and re-inspects with the blacklight to verify that the indication is a crack.

Figure No. 94

Drill Pipe Inspection The DrilcologE inspection unit is an electromagnetic system for inspecting used drill pipe and tubing (see Figure No. 95). The system incorporates a dual function inspection system consisting of both transverse flaw detection and wall loss capabilities. Sixteen (16) independent electronic channels, eight for transverse flaws and eight for wall loss, are utilized for detection and display of internal and external corrosion, cracks, cuts and other transverse, three-dimensional and wall loss defects. Figure No. 93

Figure No. 95

Inspection

148

Ultrasonic End Area Inspection Ultrasonic techniques may be used to inspect the slip areas and other high-stress areas of the drill pipe tube (see Figure No. 96). These high-stress areas, located in the 36 in. section of tube nearest either tool joint, are areas of major concern when inspecting drill pipe. Smith’s ultrasonic equipment can locate internal fatigue cracks and washed areas before they become problems.

Inspection

149

SHOULDER REFACING The Smith portable, electric powered shoulder refacing tools are designed to repair minor shoulder connection damage in the field (see Figure No. 97). Drill collar and drill pipe shoulder faces are smoothed with adhesive-backed emery paper, leaving a surface that is flat and smooth. Many connection shoulders can be repaired at the rig when such damage would normally require costly machine shop attention. Caution: Throughout the entire refacing operation, the inspector should wear eye protection.

Figure No. 96

OTHER SERVICES AND SPECIFICATIONS In addition to the specific services shown above, other types of drilling tools, rig hoisting equipment and other types of equipment may be inspected by your Smith field inspection technician. Ask your Smith representative for details. API standards along with Smith’s own inspection specifications are used to provide the best inspection possible. Customer specifications and in-house procedures may be used at your request. Either way, Smith’s highly trained inspectors will provide the highest quality service for your inspection dollar.

FIELD REPAIR In addition to the inspection process, Smith field inspectors are also highly trained in the maintenance and field repair of downhole tools. Field repair may eliminate the costly need to ship equipment to the machine shop for repair. Trained technicians can remove minor thread and shoulder blemishes which, if left unrepaired will cause damage to other connections in the string.

Figure No. 97

Inspection

150

Inspection

151

True alignment of the shoulder, perpendicular to the center line of the threads, is assured as the refacing tool mandrel is screwed on or into the connection threads (see Figure No. 98).

Figure No. 98

The adhesive-backed refacing discs are easy to apply and replace (see Figure No. 99).

Figure No. 99

The refacing tool is rotated by a heavy-duty electric sander and the pressure is applied by the operator along the axis of the threaded connection (see Figure No. 100). The drive tube is made from aluminum, thereby reducing the weight of the assembly. Caution: The sander should not be used unless properly grounded.

Figure No. 100

Care should be taken in removing only the minimum amount of material. When making field repairs, operators should be skilled and understand service conditions of the product to assure proper application of the refacing tool. It is a good practice not to remove more than 1/32 in. (0.8 mm) from a box or pin shoulder at any refacing and not more than 1/16 in. (1.6 mm) cumulatively (see API Recommended Practice RP 7G, current edition). Note: Portable equipment used to repair threaded connections in the field will not restore the product within the tolerances of a new part.

Inspection

152

Copper Sulfate Solution After refacing, an anti-gall coating of copper sulfate, is applied to the shoulder surface (see Figure No. 101 and solution mixing instructions on page 153). Caution: Eye protection and appropriate hand protection should be worn when mixing or handling copper sulfate solution. Always pour acid into water. Mix the solution in an area with an eye wash fountain or where large amounts of water are available for flushing, in case solution comes in contact with any part of the body.

Figure No. 101

After completion of the inspection and repair operation, a rust preventative is applied to all connections on tools that are to be stored before the next use (see Figure No. 102). On tools that are to be used immediately, an API thread compound is applied to the threads and shoulders (see Figure No. 103).

Inspection

153

Figure No. 103

How to Mix Copper Sulfate Anti-Gall Solution The copper sulfate solution is prepared by dissolving 4 heaping tablespoons (53 cc) of blue vitriol (blue stone 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 hand protection should be worn when mixing or handling copper sulfate solution. Always pour acid into water. Mix the solution in an area with eye wash fountain, or where large amounts of water are available for flushing, in case solution comes in contact with any part of the body.

HOW TO USE YOUR TOOL JOINT IDENTIFIER 1. With the thread form, determine the number of threads per inch in the pin or box (see Figure No. 104). On the scale, threads per inch are indicated by the number following the type of joint.


Inspection

154

2. On pins without a relief-groove or turned cylindrical diameter, caliper diameter at base (see Figure No. 105).

Inspection

155

4. On identifier scale, find the type of joint which corresponds to the pin base diameter measured in Figure Nos. 105 and 106 (see Figure No. 107). Place one end of caliper in the notch and read the corresponding connection size at the other end of the caliper tip.

Figure No. 105

3. To measure tapered diameter of pins with reliefgrooves or cylindrical diameters, ask someone to hold two straight edges against threads and caliper at shoulder as shown (see Figure No. 106).

Figure No. 107

5. To find the type of box, hold the end of the scale marked box to mouth of counterbore, as shown, and read the nearest size and type of joint having corresponding number of threads per inch (see Figure No. 108).


Inspection

156

Pin base diameters vary widely on same size joints, but no difficulty will be experienced if the nearest size is taken having the correct number of threads per inch. For example 31/2 in. FH, 31/2 in. IF and 31/2 in. H-90 have nearly the same pin base diameter, but can be easily distinguished by the number of threads per inch.

INTERNATIONAL INSPECTION SERVICES Smith Services — Drilco Group inspection systems are air portable, self supporting and quickly available from strategic locations around the world. Experienced inspectors are trained in defect detection and downhole tool maintenance and field repair. Inspectors are qualified to train the customer’s operating personnel in field maintenance and defect prevention. Special compact and light-weight equipment allows travel to offshore and remote locations (see Figure No. 109).

Figure No. 109

9

SECTION NINE

ROTATING DRILLING HEADS

Rotating Drilling Heads

ROTATING DRILLING HEADS Conventionally, one will drill a well and use heavy drilling fluids to control the well pressures and to control the flow of cuttings from the well. There are times when it is beneficial for you to use air or gas as the circulating medium or use a light mud to drill in an underbalanced condition. When drilling with air or gas or underbalanced, you must use a rotating drilling head. Rotating drilling heads are used to safely divert air, gas, dust or drilling muds away from the rig floor. The head has a rubber device, called a stripper rubber, that provides a continuous seal around the drill stem components, thus directing the drilling medium through a side outlet on the body and away from the rig floor. Rotating drilling heads are also used for closed loop circulating systems in environmentally sensitive areas. Note: You should always remember that rotating drilling heads are diverters and that you must never use them as a blowout preventer.

Figure No. 110

APPLICATIONS Air and Gas Drilling Air and gas drilling were the first applications for rotating drilling heads. Typically, air and gas drilling are used in very hard formations and formations which are extremely fractured. Benefits of air and gas drilling include: · Faster penetration rates, sometimes threefold to fourfold compared to mud drilling.

159

160

Rotating Drilling Heads · Reduced formation damage. · Fewer wellbore problems such as lost circulation and sloughing of sensitive shales. · Immediate indication of zone productivity. · Reduced mud cost. Underbalanced Drilling Underbalanced drilling is where the hydrostatic pressure created by the drilling fluid column is less than the formation pressure. Benefits of underbalanced drilling 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.


161

System Components The Smith Services rotating drilling head consists of five major components (see Figure No. 111). (1) (a) Bowl with integral inlet and outlet flanges or (b) body with separate spool having inlet and 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).

Drive bushing

Stripper rubber

Flow Drilling Flow drilling is the process of producing the well while drilling. You drill the producing zone underbalanced to allow flow from the formation into the 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 Drilling Geothermal drilling is where you drill into steam producing formations thus allowing steam to flow up the wellbore to the surface. The steam must be diverted from the rig floor for safety. Rotating drilling heads specifically designed for geothermal drilling typically have two sealing elements (stripper rubbers). The upper stripper rubber seals around the kelly while drilling and the drill pipe and tool joints when tripping in and out of the hole. The lower stripper rubber has a larger ID to allow sealing around the larger drill stem components such as drill collars.

Bearing assembly

Bowl

Figure No. 111

Bowl Assembly with Integral Inlet and Outlet Flanges (Models 7068 and 7368) The bowl assembly installs on top of the BOP stack and below the rotary table. The bowl is stationary and has a clamp assembly that locks the drive ring and bearing assembly firmly to the body. Body Assembly with Separate Spool Having Inlet and Outlet Flanges (Models DHS 1400, 8068 and RDH 2500) The spool is installed on top of the BOP and the body fits on top of the spool. The two are held together by a clamp assembly (Models DHS 1400 and RDH 2500) or by clamping dogs (Model 8068). Both the spool and the body are stationary.


162

Stripper Rubber The stripper rubber is either fastened to the bottom of the drive bushing or molded integral with the assembly. The purpose of the stripper rubber is to provide a seal around the kelly as it is rotated and to seal around the drill pipe while tripping in and out of the hole. It is easily changed by opening the clamp and lifting the drive bushing assembly (and stripper rubber) out of the bowl. Stripper rubbers are available in different elastomer compounds for the various drilling environments such as high temperatures and oil-base muds. Stripper Rubber Elastomer Compound Selection Oil-Base Mud Below 140°F

Oil-Base Mud Above 140°F

Steam or Hot Water

Poor

Fair

Compound Type

Air

Cold Water

Natural rubber

Good

Best

Poor

Butyl

Good

Good

Poor

Poor

Best

Urethane

Best

Good

Best

Poor

Poor

Nitrile

Good

Good

Good

Best

Poor

Drive Ring and Bearing Assembly The drive ring and bearing assembly supports the torsional and axial loads on the rotating drilling head and also provides low torque rotation. The bearing assembly consists of two heavy-duty tapered roller bearings, an upper and lower. The bearing assembly is sealed to keep contaminants out of the bearings while at the same time retaining the lubricating oil around the bearings. Drive Bushing Assembly The drive bushing engages a lug on the drive ring and is then clamped onto the drive ring. The drive bushing drives the drive ring and bearing assembly. The drive bushing itself is driven by the kelly bushing which is fitted onto the kelly. The kelly bushing automatically engages when the kelly is lowered into the drive bushing. The drive bushing has a rubber insert to absorb lateral shock loads which are transmitted from the kelly to the kelly bushing. Lubricator System The lubricator system must be used in conjunction with the bearing assembly. The lubricator provides oil under pressure to the bearings for cooling and longer bearing life. Lubricating systems can be circulating or non-circulating. Circulating lubricating systems are recommended for high-temperature operations such as geothermal drilling.


163

SPECIFICATIONS Standard Rotating Drilling Heads DHS 1400 Drilling Head: The drive bushing and stripper rubber are retrievable through a 171/2 in. rotary. The sealed bearing assembly is retrievable through a 221/2 in. rotary table. It can be used with single or dual rotating stripper rubbers. The hydraulic accumulator operates on rig air supply. Model DHS 1400 Drilling Head Maximum speed ................................ 100 rpm Through 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 heights Std. 135/8 in. - 3/5,000 inlet spool with no outlet ................................ 341/2 Std. 135/8 in. - 5,000 inlet with 71/16 in. - 2/3,000 outlet .......... 501/4 Std. 11 in. - 3/5,000 inlet with 71/16 in. - 2/3,000 outlet .......... 501/4 Short 135/8 in. - 5,000 inlet with 71/16 in. - 2/3,000 outlet ......... 421/16 Short 135/8 in. - 5,000 inlet with 7 in. casing thread outlet ........ 403/4 Short 11 in. - 3/5,000 inlet with 7 in. casing thread outlet ........ 393/4 Short 11 in. - 3/5,000 inlet with 71/16 in. - 2/3,000 outlet .......... 393/4

in. in. in. in. in. in. in.

Rotating test pressure ........................... 400 psi


164

Model 7068: On this model the body is integral with the spool and has a side outlet and a lower flange 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 rotary table. It is available with single or dual rotating stripper rubbers. Model 7068


165

Model 8068: On this model, the body does not have an integral side outlet or mounting flange. It is attached by clamping dogs to a spool with flanges for 135/8, 16 and 20 in. BOPs. The drive bushing/stripper rubber assembly passes through a 171/2 in. rotary table. The rotating drilling head passes through a 271/2 in. rotary table. It can be used with mudline casing suspension systems when attached to a 30 in. mounting flange. It is available with single or dual stripper rubbers.

Height Lower Flange (in.)

Maximum Bore (in.)

Side Outlet (in.)

w/Stand. Bushing (in.)

w/Short Bushing (in.)

11 - 3,000/5,000 Combination

111/4

71/16 - 2,000

36

297/8

11 11 - 3,000/5,000 Shorty Combination

113/4

7 Threaded (Male)

14

71/16 - 2,000

Size (in.) 11

135/8 135/8

135/8 - 3,000 135/8 - 5,000

135/8

9 - 2,000

243/4 36 38

297/8 317/8

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.

Model 7368: This model also has a body that is integral with the spool and has a side outlet and a lower flange for mounting on the BOP. It has the same basic design features of larger models and is ideal for slim-hole applications and workover jobs because of its shorter height. The drive bushing/ stripper rubber is a one-piece assembly and can pass through a 101/2 in. rotary table. Model 7368 Size (in.)

Lower Flange (in.)

Maximum Bore (in.)

71/16

71/16 - 2,000/3,000/5,000

71/16

Side Outlet (in.)

Height (in.)

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.)

Model 8068 Height Size (in.)

Lower Flange (in.)

Maximum Bore (in.)

Side Outlet (in.)

w/Stand. Bushing (in.)

w/Short Bushing (in.)

163/4

163/4 - 2,000

163/4

9 - 3,000

423/4

365/8

203/4

9 - 3,000

423/4

365/8

3

3

203/4 203/4 - 2,000/3,000 30

None*

28 /32

None**

25 /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.

166


SPECIAL ROTATING DRILLING HEADS Geothermal Well Drilling Head: This drilling head incorporates two stripper rubbers — upper rubber rotates with the kelly and seals around the drill pipe and tool joints as connections are made stripping in and out of the hole. The lower stripper rubber seals on the large diameter string components such as drill collars. The body is equipped with a port for water injection to cool and lubricate the stripper rubbers and exposed seals while stripping in and out. The elastomer components are formulated for high-temperature service. Model RDH 2500 High-Pressure Drilling Head: Rated at 1,500 psi rotating test pressure. This rating is for the body and seals only and does not include the stripper rubber. In actual field use there are many variables which can affect the life and pressure capability of the stripper rubber. For example, if the drilling head and BOP are misaligned with the rig, the performance of the stripper rubber is adversely affected. Other factors such as high temperature, higher pressures, etc., also adversely affect the life of the stripper rubber. The stripper rubber is a special mechanically energized stripper rubber. The bearing chamber is sealed with low-pressure seals against atmospheric pressure. There is a separate high-pressure seal assembly to contain wellbore pressure. Note: This product, regardless of pressure rating, is a diverter and not a blowout preventor. The high-pressure seal assembly contains a redundant set of seals. The high-pressure drilling head is available with single or dual stripper rubbers. We have different elastomer components available for oil and gas or geothermal drilling. The high-pressure drilling head utilizes a hydraulic skid unit to supply low-pressure circulating lubrication to the bearings, and a separate lubrication system to supply high-pressure lubrication to the high-pressure seals. The high-pressure lubricant system maintains hydraulic pressure at a slightly higher pressure than the wellbore to properly lubricate the high-pressure seal assembly. The hydraulic skid is located away from the rig and requires 110 volts and an air supply from the rig. A back-up air compressor automatically engages if the rig air is disconnected. A redundant system assures that hydraulic fluid flow continues

Rotating Drilling Heads 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 Maximum speed ................................ 100 rpm Through bore of wellhead adapter assembly ................................ 133/8 Through bore of drilling head assembly .......................................... 9 Through bore of stripper rubber .................... 6 Maximum OD .......................................... 271/4 Overall heights 135/8 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 1 7 /16 in. - 5,000 inlet with 71/16 in. - 2/3,000 outlet ............... 587/8 Rotating test pressure ........................ 1,500 psi Alignment: Stack alignment is critical to the performance and life of the rotating drilling head bearings and stripper rubber. Check alignment by slowly lowering the kelly until kelly bushing engages the drive bushing in the rotating head. The kelly drive bushing should go into the drive bushing freely without having to force the kelly sideways. If the kelly drive bushing does not freely engage into the drive bushing of the rotating drilling head, then BOP stack and rig rotary should be properly aligned.

167


168


169

API Ring Joint Flange Data Flange Nominal Size and Pressure Rating (in.)

Bolts

“Old” Nominal Size and Series Service (in.)

OD (in.)

Thickness (in.)

Dia. Bolt Circle (in.)

71/16 x 2,000

6 x 600

14

23/16

71/16 x 3,000

6 x 900

15

71/16 x 5,000

6 x 1,500

71/16 x 10,000

API Ring

Bolt Quantity

Bolt Dia. (in.)

Bolt Length (in.)

Ring No.

12

1

7

45

111/2

12

11/8

8

45

21/2

121/2

12

13/8

103/4

46

151/2

35/8

121/2

12

11/2

111/4

BX 156

187/8

41/16

157/8

12

11/8

8

49 49

9 x 2,000

8 x 600

161/2

21/2

133/4

12

13/8

9

9 x 3,000

8 x 900

181/2

213/16

151/2

12

15/8

12

50

9 x 5,000

8 x 1,500

19

41/16

151/2

16

11/2

13

BX 157

213/4

47/8

183/4

16

11/4

83/4

53

11 x 2,000

10 x 600

20

213/16

17

16

13/8

91/2

53

11 x 3,000

10 x 900

211/2

31/16

181/2

12

17/8

133/4

54

11 x 5,000

10 x 1,500

23

411/16

19

12

2

161/2

91

*

10 x 2,900

203/4

511/16

163/4

16

13/4

15

BX 158

253/4

59/16

221/4

20

11/4

9

57

22

215/16

191/4

20

13/8

101/4

57

9 x 10,000

11 x 10,000 135/8 x 2,000

12 x 600

135/8 x 3,000

12 x 900

24

37/16

21

16

15/8

121/2

BX 160

135/8 x 5,000

261/2

47/16

231/4

20

17/8

171/4

BX 159

135/8 x 10,000

301/4

65/8

261/2

20

11/2

101/4

65

163/4 x 2,000

16 x 600

27

35/16

233/4

20

15/8

113/4

66

163/4 x 3,000

16 x 900

273/4

315/16

241/4

16

17/8

141/2

BX 162

163/4 x 5,000

303/8

51/8

265/8

24

17/8

171/2

BX 162

163/4 x 10,000

345/16

65/8

309/16

24

15/8

113/4

73

211/4 x 2,000

20 x 600

32

37/8

281/2

20

2

141/2

74

203/4 x 3,000

20 x 900

333/4

43/4

291/2

24

2

183/4

BX 165

24

21/2

241/2

BX 165

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.


170 Notes

10

SECTION TEN

ADDITIONAL INFORMATION

Additional Information “Maximum Permissible Doglegs in Rotary Boreholes” by Arthur Lubinski, Publication No. 55, February 1960. This paper presents means for specifying maximum permissible changes of hole angle to ensure a trouble-free hole. “What You Should Know About Kellys” by Doyle W. Brinegar, Publication No. 81 (reprinted from Oil & Gas Journal, May 1977). This article answers a number of questions pertaining to kellys, including: why kellys become unusable, the effects of manufacture on kelly performance, interpreting drive edge wear patterns and kelly repair. “Qualified Inspectors: The Key to Maximum Drill Collar Life” by W.R. Garrett, Publication No. 82 (reprinted from World Oil, March 1977) explains the importance of inspection services, in terms of obtaining the maximum amount of trouble-free service out of a drill collar before needing repair. “Down-Hole Failure of Drilling Tools” by B.P. Faas, Publication No. 32 (reprinted from Drilling Contractor, May and June 1970). In this article, the author summarizes a study conducted by Standard Oil Co. which examines the cause of downhole drilling equipment failures. This detailed examination attempts to determine if there are any deficiencies in steel or fabrication procedures which could be corrected so that the likelihood 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 the nature of drill pipe failure, and identifies seven steps that can be taken to minimize fatigue damage. “Drill Stem Failures Due to H2S” by H.M. Rollins, Publication No. 52 (reprinted from Oil & Gas Journal, January 1966), discusses the results of many investigations involving tubing failures, talks about drill pipe failures specifically and recommends 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 Go Crooked” and what you can do to prevent excessive hole angle build-up.

173

174

Additional Information “How to Drill a Usable Hole” by Gerald E. Wilson, Publication No. 39 (reprinted from World Oil, September 1976). This brochure of pictures and examples explains how to control hole deviation, reasons holes become crooked and problems that can result. “Drilling Straight Holes in Crooked Hole Country” Publication No. 59. These tables will permit you to predict the effect on hole inclination, changes in weight, drill collar size and the use of stabilizers. “Using Large Drill Collars Successfully” by Doyle Brinegar and Sam Crews, Publication No. 21 (reprinted from Journal of Petroleum Technology, August 1970). Article discusses use of large drill collars in the 9 to 11 in. size range. “How to Bridge Drill Pipes’ Zone of Destruction” by Charlie Miller, Publication No. 72 (reprinted from Drilling DCW Magazine, June 1973). The author explains the major causes of twistoffs and washouts 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 Drill Stem” 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 Bit Life” by G.M. Purswell, Publication No. 50 (reprinted from Oilweek, December 1967), recognizes that bit stabilization is an effective method for prolonging rock bit life and obtaining greater penetration rates. Purswell points out that stabilization “forces the bit to rotate around its own center.” Numerous configurations of semi-packed or packed bottom-hole assemblies are reviewed and discussed as to their application for bit stabilization. “How to Select Bottom Hole Drilling Assemblies” by Gerald E. Wilson, Publication No. 62 (reprinted from Petroleum Engineer, April 1979), identifies and compares a number of bottom-hole assemblies that can be used when drilling in crooked hole areas. The primary factor affecting selection of the assembly is the crooked hole tendencies of the formations to be penetrated.

Additional Information “Predicting Bottomhole Assembly Performance” by J.S. Williamson and A. Lubinski, Publication No. 98 (reprinted IADC/SPE 14764 from IADC/SPE Drilling Conference, February 1986). This paper discusses a computer program for the prediction of bottom-hole assembly performance. Input parameters include: formation dip, hole and collar size, stabilizer spacing, etc. Output may be hole curvature, hole angle or WOB. “An Engineering Approach to Stabilization Selection” by G.K. McKown and J.S. Williamson, Publication No. 99 (reprinted IADC/SPE 14766 from IADC/SPE Drilling Conference, February 1986). This paper discusses a means of selecting stabilizers based on applications and drilling conditions. Experimental wear data and computer analyses 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 of degassing. It outlines the problems and discusses the steps that must be taken to remove the gas. There are several ways to take each step because there are different types of degassers shown, yet each can do the job. Some examples of mud problems are also shown. “A User’s Guide to Drill String Hardfacing” by J. Steve Williamson and Jim B. Bolton, Publication No. 100 (reprinted from Petroleum Engineering International, September 1983). This paper discusses drill string hardfacings, welding processes and important metallurgical variables involved. The importance of proper tungsten carbide selection is emphasized. Experimental results are discussed for casing wear by hardfacings and for hardfacing wear resistance. Guidelines are given for hardfacing selection based on tests and field experience.

175

176

Additional Information “What is the Condition of Your Downhole Tools and How Are They Being Repaired” by Doyle W. Brinegar, Publication No. DR - 1009 (reprinted from SPE/IADC No. 18702 presented at the SPE/IADC Drilling Conference, March 1989). This paper discusses the repair and reuse of downhole drilling equipment, along with inspection methods. One of the objectives of this paper is to review repair methods that are used to increase the life of downhole tools. Particular attention is paid to welding procedures. “Drill String Design Optimization for HighAngle Wells” by George K. McKown, Publication No. DR-1002 (reprinted from SPE/IADC Drilling Conference, March 1989). This paper discusses drill string design for high-angle wells and how to optimize for all the required functions of the drill string. Practical considerations for drill string design for high-angle wells and systematic approaches to the design process are presented. When ordering publications from Smith, please indicate the publication number you are interested in and address your request to: Smith International Reader Service Dept. P.O. Box 60068 Houston, TX 77205-0068 Or call your Smith representative.

11

SECTION ELEVEN

INDEX

Index

179

Index Introduction ................................................. i Table of contents .......................................... ii Letter from operations .................................. iii How to use this handbook ............................ iv

A ANGLE How to control hole angle ........................ 8 Rate of hole angle .................................... 5 Total hole angle ........................................ 5 ANTI-GALL Anti-gall protection of connections ............ 67 ASSEMBLIES Bottom-hole assemblies ............................ 1 Packed hole assembly - length of tool assembly ........................................ 10

B BENDING STRENGTH RATIO Guides for evaluating drill collar OD, ID and connection combinations ........... BHA Bottom-hole assemblies ............................ Conclusion ............................................... Downhole vibrations ................................ Factors to consider when designing a packed hole assembly ........................ How to control hole angle ........................ Improve hole opener performance by using a vibration dampener and stabilizers ................................... Minimum permissible bottom-hole drill collar outside diameter formula ...... Packed hole assembly - clearance between wall of hole and stabilizers ...... Packed hole assembly - length of tool assembly ........................................ Packed hole assembly - medium crooked hole country ............................ Packed hole assembly - mild crooked hole country ......................................... Packed hole assembly - mild, medium and severe crooked hole country ........... Packed hole assembly - severe crooked hole country ......................................... Packed hole assembly - stiffness of drill collars ...........................................

78 1 22 22 10 8

23 4 11 10 13 12 14 14 11

Index

180

BHA continued Packed hole assembly - wall support and length of contact tool ......... 12 Packed hole theory ................................... 9 Packed pendulum ..................................... 20 Pendulum theory ...................................... 8 Problems associated with doglegs and key seats ........................................ 6 Rate of hole angle change ......................... 5 Reduced bit weights ................................. 21 Stabilizing tools ........................................ 15 Total hole angle ........................................ 5 BIT Bit stabilization - angular misalignment .... 32 Bit stabilization - parallel misalignment ..... 32 Bit stabilization pays off ........................... 31 Stabilization 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 IN How to break in a new kelly ..................... 137 BUOYANCY Buoyancy effect of drill collars in mud ...... 70

C CAPACITY Capacity and displacement table Hevi-Wate drill pipe .............................. COLLARS Hookups used to make up drill collar connections ................................. Packed hole assembly - stiffness of drill collars ........................................... Stress Relief .............................................. CONNECTIONS Anti-gall protection ................................... Dimensional identification of box connections .................................... Dimensional identification of pin connections .................................... Drill pipe and drill collar safety factor tension, compression and neutral zone .. Facts about cold working .......................... Guides for evaluating drill collar OD, ID and connection combinations ........... Using the connection selection charts .......

112

43 11 68 67 100 101 71 66 78 78

Index CONNECTIONS continued Preventing pin and box gailures in downhole tools ..................................... 76 Rotary shouldered connection interchange list ..................................... 96 Torque chart drill pipe tool joint recommended minimums ...................... 130 CROOKED 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 .................... 17 Mild, 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

D DIFFERENTIAL PRESSURE Differential pressure sticking of drill pipe and drill collars ...................... 27 DIMENSIONAL DATA Hexagon kellys ......................................... 136 Square 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 ................................... 67 Automatic torque control system ............... 51 Buoyancy effects of drill collars in mud ..... 70 Drill collar care and maintenance ............. 37 Minimum permissible bottom-hole drill collar outside diameter formula ............. 4 Pipe - drill pipe - drill collar safety factor tension, compression, neutral zone ........ 71

181

182

Index DRILL COLLARS continued Dimensional identification of box connections .................................... 100 Dimensional identification of pin connections .................................... 101 Drill collar weights [kg/m] ....................... 75 Drill collar weights [lb/ft] ......................... 73 Ezy-Torq hydraulic cathead ....................... 52 Facts about cold working .......................... 66 Guides for evaluating drill collar OD, ID and connection combinations ........... 78 How to figure the drill collar makeup torque needed ....................................... 41 Hookups used to make up drill collar connections ................................. 43 How to apply and measure makeup torque ...................................... 51 How does the ATCS help .......................... 52 How to use the connection selection charts ..................................... 78 Hydraulic line pull devices ........................ 52 Hydraulic load cells .................................. 51 Drill collar failures .................................... 77 Know field shop work .............................. 66 Low torque faces ...................................... 69 Oilfield thread forms ................................ 97 Picking up drill collars .............................. 38 Recommended minimum drill collar makeup torque [ft-lb] ............................ 54 Recommended minimum drill collar makeup torque [kg-m] .......................... 58 Recommended minimum drill collar makeup torque [N·m] ........................... 62 Refacing a drill collar shoulder .................. 149 Rig catheads ............................................. 51 Rig maintenance ...................................... 41 Slip and elevator recesses ......................... 69 Special drill collars ................................... 68 Stress relief .............................................. 68 Torque Control ......................................... 39 Weight of 31 ft drill collar [lb] ................... 72 Weight 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 DRILL PIPE continued Dimensional identification heavy-weight grade E drill pipe ............. 124 Dimensional identification heavy-weight grade E drill pipe ............. 126 Dimensional identification heavy-weight grade G drill pipe ............. 128 Dimensional identification heavy-weight grade S drill pipe .............. 129 Dimensional identification heavy-weight grade X drill pipe ............. 127 Dimensional identification heavy-weight, high-strength drill pipe .... 125 Dimensional identification standard weight grade E drill pipe ......... 124 Dimensional identification standard weight grade G drill pipe ......... 128 Dimensional identification standard weight grade S drill pipe ......... 129 Dimensional identification standard weight grade X drill pipe ......... 127 Dimensional identification standard weight, high-strength drill pipe ........................................... 125 Pipe mill codes to be stencilled at base of pin ............................................ 119 Pipe weight code ...................................... 123 Recommended identification groove and marking of drill pipe ....................... 122 Recommended practice for marking on tool joints for identification of drill string components ............................. 119 Tapered drill Strings .................................. 113 Tool joints ................................................ 117 Torque chart drill pipe tool joint recommended minimums ...................... 130 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 drill pipe ................... 107 What is Hevi-Wate drill pipe ..................... 105 Straight hole drilling ................................. 2

F FIELD INSPECTION Systematic field inspection ........................ 143

183

Index

184

FORMATIONS Medium and severe crooked hole country in hard to mediumhard formations ................................. 19 Mild, medium and severe crooked hole country in hard to mediumhard formations ................................. 17 Mild, medium and severe crooked hole country in medium-hard to soft formations .............................. 19

G GRADE CODE Pipe grade codes to be stencilled at base of tool joint pin ......................... 120

H HEVI-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 ............. 107 What is Hevi-Wate drill pipe ..................... 105 HEXAGON KELLYS Dimensional data ..................................... 136 HOLE How to control hole angle ........................ 8 Rate of hole angle change ......................... 5 Total hole angle ........................................ 5

I IDENTIFICATION 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 IDENTIFICATION continued Pipe grade codes to be stencilled at base of tool joint pin ............................. 120 Pipe mill codes to be stencilled at base of tool joint pin ............................. 119 Recommended identification groove and marking of drill pipe ....................... 122 Recommended practice for marking on tool joints for identification of drill string components ...................... 119 IDENTIFIER How to use the tool joint identifier ........... 152 INFORMATION Additional technical information ............... 173 INSPECTION International inspection services ............... 155 Systematic field inspection ........................ 143 INTERCHANGE LIST Rotary shouldered connection interchange list ..................................... 96

K KELLYS Hexagon kellys - dimensional data ............ 136 How to break in a new kelly ..................... 137 New kellys - measurements ...................... 136 Square kellys - dimensional data ............... 136 What can you do with that old kelly ......... 140 KEY SEATS Problems associated with doglegs and key seats ........................................ 6

M MAINTENANCE Drill collar care and maintenance ............. 37 If you have an epidemic of drill collar failures that you can't explain ...... 77 Know field shop work .............................. 66 Preventing pin and box failures in downhole tools ..................................... 76 Refacing a drill collar shoulder .................. 149 Rig maintenance of drill collars ................. 41 Systematic field inspection ........................ 143 MAKEUP Automatic torque control system ............... 51 Ezy-Torq hydraulic cathead ....................... 52 How to figure the drill collar makeup torque needed .......................... 41

185

Index

186

MAKEUP continued Hookups used to make up drill collar connections .......................... 43 How to apply and measure makeup torque ...................................... 51 How does the ATCS help .......................... 52 Hydraulic line pull devices ........................ 52 Hydraulic load cells .................................. 51 Initial makeup of new drill collars ............. 39 Recommended minimum drill collar makeup torque [ft-lb] ............................ 54 Recommended minimum drill collar makeup torque [kg-m] .......................... 58 Recommended minimum drill collar makeup torque [N·m]............................ 62 Rig Catheads ............................................ 51 Recommended identification groove and marking of drill pipe ..................... 122 Recommended 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 .......................... 136 MILL CODES Pipe mill codes to be stencilled at base of tool joint pin ............................. 119

P PACKED HOLE ASSEMBLY Clearance between wall of hole and stabilizers ....................................... Considerations when designing a packed hole assembly .......................... Length of tool assembly ............................ Medium crooked hole country .................. Mild crooked hole country ........................ Mild, medium and severe crooked hole country ......................................... Severe crooked hole country ..................... Stiffness of drill collars ............................. Wall support and length of contact tool ........................................... PACKED HOLE THEORY ...................................... PACKED PENDULUM .......................................... PARALLEL MISALIGNMENT Bit stabilization - parallel misalignment ..... PENDULUM THEORY ..........................................

11 10 10 13 12 14 14 11 12 9 20 32 8

Index PIN Dimensional identification of drill collar pin connections .................................... 101 PUBLICATIONS Additional technical information ............... 173

R REFACING Refacing a drill collar shoulder .................. 149 ROTATING DRILLING HEADS Air drilling ............................................... 159 API ring joint flange data .......................... 168 Applications ............................................. 159 Body assembly ......................................... 161 Bowl assembly ......................................... 161 Drive bushing assembly ............................ 162 Drive ring and bearing assembly ............... 162 Flow drilling ............................................. 160 Gas drilling .............................................. 159 Geothermal drilling .................................. 160 Geothermal model .................................... 166 Lubricator system ..................................... 162 Model 7068 .............................................. 164 Model 7368 .............................................. 164 Model 8068 .............................................. 165 Model DHS 1400 ...................................... 163 Model RDH 2500 - high-pressure drilling head ......................................... 166 Stack alignment ........................................ 167 Standard heads ........................................ 163 Stripper rRubber ....................................... 162 System components .................................. 161 Underbalanced drilling ............................. 160 RSC Rotary shouldered connection interchange list ..................................... 96

S SERVICES International inspection services ............... 156 SHOCK ABSORBERS Downhole vibrations ................................ 22 Improve hole opener performance using a vibration dampener and stabilizers ................................ 23 SHOP WORK Know field shop work .............................. 66 SHOULDER REFACING Refacing a drill collar shoulder .................. 149

187

Index

188

SLIP Slip and elevator recesses on drill collars ........................................... 69 SPIRAL Spiral drill collars ..................................... 68 SQUARE KELLY Dimensional data ..................................... 136 STABILIZATION Bit stabilization - angular misalignment .... 32 Bit stabilization - parallel misalignment ..... 32 Bit stabilization pays off ........................... 31 Bottom-hole assemblies - stabilization ....... 15 medium and severe crooked hole country in hard to mediumhard formations .............................. 19 Mild, 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 Stabilization improves bit performance ..... 31 Packed hole assembly - clearance between wall of hole and stabilizers ...... 11 STIFFNESS Packed hole assembly - stiffness of drill collars ....................................... 11 STRAIGHT HOLE DRILLING .................................. 2 STRESS RELIEF Stress relief of drill collar connections ....... 68 SYSTEMATIC FIELD INSPECTION ............................ 143

T TAPERED DRILL STRINGS .................................... 113 TENSION Drill pipe and drill collar safety factor tension, compression and neutral zone .. 71 THREAD FORMS Oilfield thread forms ................................ 97 TOOL JOINT IDENTIFIER .................................... 153 TOOL 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

Index

189

TOOL JOINTS continued Pipe mill codes to be stencilled at base of tool joint pin ............................. 119 Pipe weight code ...................................... 123 Recommended identification groove and marking of drill pipe ....................... 122 Recommended practice for marking on tool joints for identification of drill string components ...................... 119 TORQUE Automatic torque control system ............... 51 Ezy-Torq hydraulic cathead ....................... 52 How to figure the drill collar makeup torque needed ....................................... 41 Hookups used to make up drill collar connections ................................. 43 Apply and measure makeup torque .......... 51 How does the ATCS help .......................... 52 Hydraulic line pull devices ........................ 52 Hydraulic load cells .................................. 51 Recommended minimum drill collar makeup torque [ft-lb] ............................ 54 Recommended minimum drill collar makeup torque [kg-m] .......................... 58 Recommended minimum drill collar makeup torque [N·m] ........................... 62 Rig catheads ............................................. 51 Torque chart drill pipe tool joint recommended minimums ...................... 130 Torque control - drill collars ...................... 39 TRANSITION ZONE Using Hevi-Wate drill pipe in the transition zone between drill collars and drill pipe .......................... 107

V VIBRATION DAMPENERS Downhole vibrations ................................ 22 Improve hole opener performance using a vibration dampener and stabilizers ..... 23

W WEIGHTS Drill collar weight [kg/m] ......................... Drill collar weight [lb/ft] .......................... Weight of 31 ft drill collar [lb] ................... Weight of 9.4 m drill collar [kg] ................

75 73 72 74

Index

190 Notes

Drilling Assembly Handbook

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