Drilling Assembly Handbook 2001

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.
ii
iii
TABLE OF CONTENTS
Bottom-Hole Assemblies ..............................
PREFACE
1
Differential Pressure Sticking ........................ 27
Bit Stabilization ...........................................
31
Drill Collar ................................................... 37
Hevi-WateT Drill Pipe ................................... 105
Tool Joints ................................................... 117
Kellys .......................................................... 135
Inspection .................................................... 143
Rotating Drilling Heads ................................ 159
Additional Information ................................. 173
Index ........................................................... 179
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.
iv
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
1
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.
1
Bottom-Hole Assemblies
2
Bottom-Hole Assemblies
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.
3
Bottom-Hole Assemblies
4
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
Bottom-Hole Assemblies
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.
5
Bottom-Hole Assemblies
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.
7
8
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).
Bottom-Hole Assemblies
(Pendulum force)
Restoring force of drill
collar weight
9
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
10
Bottom-Hole Assemblies
Bottom-Hole Assemblies
11
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.
12
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
Bottom-Hole Assemblies
13
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
Bottom-Hole Assemblies
14
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
Bottom-Hole Assemblies
15
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.
Bottom-Hole Assemblies
16
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).
Bottom-Hole Assemblies
17
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
Bottom-Hole Assemblies
18
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
Bottom-Hole Assemblies
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 1
Mild Med. Sev.
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
19
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
Mild Med. Sev.
Zone 1-A
Figure No. 21
Zone 1-B & C
Zone 2
Zone 3
Bottom-Hole Assemblies
20
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).
Bottom-Hole Assemblies
21
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
Bottom-Hole Assemblies
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.
Bottom-Hole Assemblies
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
Bottom-Hole Assemblies
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
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. 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 1/3 of the line pull reading on
your Torque Indicator.
Snub line
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.
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.
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.
The amount of cathead pull will
be 1/2 of the line pull reading on
your Torque Indicator.
Snub line
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°
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.
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
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 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
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
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
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.
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†
*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
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
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
(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
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
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
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.
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†
*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
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
* 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.)
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
* 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.)
NC 46
51/2
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
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
* 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.)
* 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
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
V-0.050
2 in. Taper Per Foot (TPF) on Diameter
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
V-0.050
3 in. Taper Per Foot (TPF) on Diameter
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
Hevi-Wate Drill Pipe
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.
Hevi-Wate Drill Pipe
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
Hevi-Wate Drill Pipe
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.
Hevi-Wate Drill Pipe
111
Hevi_Wate
Drill pipe
IB stabilizer
Spiral drill collar
Hydra-Shock®
IB stabilizer
(Integral Blade)
Near bit
IB stabilizer
Figure No. 66
Hevi-Wate Drill Pipe
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.)
Hevi-Wate Drill Pipe
.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.
Hevi-Wate Drill Pipe
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)
Figure No. 69
Figure No. 71
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)
Figure No. 70
Figure No. 72
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)
See Note 2
(page 122)
Figure No. 74
Figure No. 73
Heavy-Weight Grade X Drill Pipe
API After January 1, 1995
See Note 2
(page 122)
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
See Note 2
(page 122)
See Note 2
(page 122)
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
See Note 2
(page 122)
Figure No. 77
See Note 2
(page 122)
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
Makeup
Torque
(ft-lb)
2,467
1,967
1,481
1,998
1,500
2,055
3,558
2,794
3,752
3,767
3,770
3,427
2,500
3,664
2,804
4,597
6,500
5,726
4,491
7,107
4,600
6,000
4,786
4,786
7,274
8,300
9,348
9,017
10,179
11,363
7,342
6,200
7,500
7,300
9,017
10,179
10,179
6,476
7,827
9,937
11,363
7,147
12,813
14,288
14,288
10,375
10,066
13,523
14,214
9,937
13,554
17,311
15,787
13,239
9,955
11,571
14,933
21,018
13,239
16,626
18,346
20,127
22,818
20,205
22,294
28,737
18,146
20,205
24,412
32,031
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
Makeup
Torque
(ft-lb)
2,204
1,600
1,244
1,998
1,300
1,667
3,005
2,481
3,109
2,666
3,029
2,801
2,200
3,324
2,804
3,867
5,345
4,969
3,984
6,045
3,700
4,868
3,838
3,838
6,268
6,769
7,785
7,877
8,444
9,595
6,406
5,000
6,200
6,200
7,877
8,444
8,444
6,476
7,157
8,535
9,228
6,476
11,363
12,080
12,080
8,600
8,071
11,418
12,125
8,535
11,363
14,281
13,554
11,571
8,365
9,955
12,415
17,497
10,773
14,082
14,933
17,497
19,244
17,118
19,147
24,413
15,086
17,118
21,238
26,560
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.
Figure No. 102
Figure No. 104
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).
Figure No. 106
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.
Rotating Drilling Heads
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.
Rotating Drilling Heads
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.
Rotating Drilling Heads
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
Rotating Drilling Heads
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
Rotating Drilling Heads
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
Rotating Drilling Heads
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
Rotating Drilling Heads
168
Rotating Drilling Heads
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.
Rotating Drilling Heads
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