As the drill string moves downhole, it is subjected to a variety of stresses, including tension,
compression, vibration, torsion, friction, formation pressure and circulating fluid pressure. It
is also exposed to abrasive solids and corrosive fluids.
The drill string not only must be sturdy enough to withstand this hostile environment, but it
must be lightweight and manageable enough to be efficiently handled within the limits of
the rig's hoisting system. At the same time, it must:
provide weight to the bit;
allow control over wellbore deviation;
help ensure that the hole stays "in gauge".
Drilling rates tend to increase with increasing weight on bit — although this statement is an
oversimplification, it is valid within certain limits. The drill string is the source of this applied bit weight. Drill
string design depends largely on the amount of bit weight that is desirable and practical for a given
Drilling engineers have long observed that there is no such thing as a perfectly straight or
vertical hole. Formation characteristics, along with the rotary drilling process itself, cause
wells to "drill crooked," making a certain amount of wellbore deviation inevitable. A major
consideration in drill string design is to control the amount and direction of this deviation,
either to stay as close to vertical as possible or to direct the well along a programmed
directional or horizontal course.
Proper drill string design is also important in avoiding doglegs (abrupt changes in hole
angle) and key seats (slots worn into the side of the borehole by the drill string). These
conditions can lead not only to stuck pipe and possible fishing jobs, but to difficulty in
running casing and even to future production problems.
Bit gauge wear, sloughing formations or heaving shales may result in a hole diameter that is
considerably less than the nominal diameter of the bit. This undergauge condition can lead
to such problems as stuck pipe and an inability to run casing. Selection of the right drill
string tools can alleviate this condition and help produce a smooth bore, full-size, problem-
The length and makeup of the drill string depends on such factors as well depth, hole size,
operating parameters and directional considerations. Its major components are the kelly (
or top-drive unit ), drill pipe and bottomhole assembly (
A kelly is a square or hexagonal length of pipe that fits into a bushing in the rig's rotary
table. As the rotary table turns to the right, the kelly turns with it.
The main function of a kelly is to transfer energy from the rotary table to the rest of the drill
string. On modern rigs, this function is more commonly performed by a top drive unit,
power swivel or power sub located directly below a conventional swivel. Of course, when a
downhole mud motor is used for directional or other applications, there is normally no drill
The longest portion of the drill string consists of connected lengths of drill pipe. The primary
purposes of drill pipe are to provide length to the drill string and transmit rotational energy
from the kelly to the bottomhole assembly and the drill bit. Drill pipe also serves as a
conduit for the drilling fluid.
The bottomhole assembly is that portion of the drill string between the drill pipe and the
drill bit. Its individual components may be arranged in any number of ways to promote
drilling objectives, and can include:
drill collars, which provide weight and stability to the drill bit, maintain tension on the drill pipe
and help keep the hole on a straight course;
• heavy wall drill pipe, which serves as an intermediate-weight drill string member
between the drill pipe and the much heavier drill collars, thereby reducing fatigue
failures, providing additional hole stability and aiding in directional control;
• stabilizers, which centralize the drill collars, help maintain the hole at full-gauge
diameter and aid in directional control;
• jars, which can provide sharp upward or downward impact to free stuck pipe;
• rotary reamers, which help maintain a full-gauge hole diameter;
• crossover subs, which join components having different types of connections.
Some bottomhole assemblies may also include vibration dampeners, or shock subs which, under certain
conditions, can help absorb shock loads and vibrations that might otherwise contribute to drill string
A well-designed bottomhole assembly helps maximize drilling rates, produce a smooth, full-
size borehole, prevent drill pipe failure, maintain directional control, avoid drilling problems,
and prevent future completion and production problems.
The kelly is a primary link between the drilling rig's surface equipment and the bit, and is
therefore a critical component of the rotary system. Although top drive systems have
replaced kelly/rotary table combinations on many rigs, some knowledge of their
manufacture and operation is useful.
Kellys are manufactured with either square or hexagonal cross sections (
Their angled surfaces, or drive flats, are designed to fit into a drive roller assembly on the
kelly bushing, so that as the rotary table turns to the right, the kelly turns with it. To allow
for normal right-hand rotation of the drill string, kellys have right-hand threads on their
bottom connections and left-hand threads on their top connections
The American Petroleum Institute has established manufacturing and design standards for
kellys, and has included them in API RP 7G, Recommended Practice for Drill Stem Design
and Operating Limits.
API kellys come in two standard lengths:
1. 40 ft overall, with a 37 ft working space;
2. 54 ft overall, with a 51 ft working space.
The ability of a kelly to turn the drill string depends on how well it fits into the kelly bushing.
More specifically, it depends on the clearance between the drive flat surfaces and the rollers
in the kelly bushing. For the kelly to perform properly, this clearance needs to be kept to a
Kellys most commonly wear out due to a rounding-off of the drive corners, as shown in
(new kelly with new drive assembly) and
(worn kelly with worn drive
This rounding is a natural wear process caused by the compressive force of the rollers on
the drive flats and accelerated by rotary torque.
As rounding progresses, it further accelerates the wear process by increasing the clearance
and the contact angle between the drive flats and the rollers.
For minimal rounding, there must be a close fit between the kelly and the roller assembly,
with the rollers fitting the largest spot on the kelly flats. Manufacturing techniques and rig
operating practices play important roles in determining this fit.
Both square and hexagonal kellys are manufactured either from bars with an "as-forged"
drive section, or from bars with fully-machined drive sections. While forged kellys are
cheaper to manufacture, machined kellys offer the following features, which tend to result in
longer useful life:
Machined kellys, unlike forged kellys, are not subject to the metallurgical process of
decarburization, or decarb. Decarburization leaves a relatively soft layer of material
(approximately V16" thick) on the drive surface that can accelerate the rounding process and
increase the potential for fatigue cracks;
• Machined kellys, because they are made to closer tolerances than forged kellys, are
more likely to closely fit the roller assembly throughout their length.
A square drive section normally tolerates a greater clearance between flats and rollers than does a
hexagonal drive section.
To minimize rounding, rig personnel should follow these guidelines (Brinegar, 1977):
Always use new drive-bushing roller assemblies to break in a new kelly;
• If the rollers are adjustable, adjust them to provide minimum clearance;
• Frequently inspect and periodically replace drive assemblies to ensure that
clearance and contact angle between the kelly and the rollers is held to a minimum;
• Lubricate drive surfaces to reduce friction and binding at the rollers, and to allow
the kelly to slide freely through the kelly bushing.
Because of the high-quality steels used in manufacturing kellys, fatigue failures are not often a problem.
Nevertheless, kellys should be regularly inspected for cracks and other signs of wear, particularly within
the threaded connections, in the areas where the flats join the upper and lower upsets and in the center
of the drive section.
The areas of highest stress concentration — and therefore the most likely locations for
fatigue failure — are the areas where the drive flats join the upper and lower upsets.
In general, the stress level for a given tensile load is less in the drive section of a hexagonal
kelly than in the drive section of a square kelly of comparable size. Hexagonal kellys are
thus likely to last longer than square kellys before failing under a given bending load.
Kellys can become crooked or bent due to improper handling. Examples of mishandling
dropping the kelly;
• misaligning the kelly in the rathole exerting a side pull on the kelly;
• using poor tie-down practices during rig moves;
• not using the kelly scabbard;
• using improper loading/unloading techniques.
Depending on where the bend is located, it may cause fatigue damage not only to the kelly but to the rest
of the drill string, and can also result in uneven wear on the kelly bushing.
Unusual side motions or swaying of the swivel are good indicators of a crooked kelly. A good
field service shop has equipment for straightening bent kellys, making this an easily-
Up to a certain point, a worn kelly can be repaired either by reversing the ends, (
or by remachining it to a smaller size.
A kelly saver sub should always be run between the kelly and the top joint of drill pipe. This
protects the kelly's lower connection threads from wear, as joints of drill pipe are continually
made up and broken out. A saver sub is much less expensive and much easier to replace
than the kelly itself, and it can also be equipped with a rubber protector to help keep the
kelly centralized and to protect the top joint of casing against wear.
A kelly cock is a valve installed above or below the kelly, which prevents fluid from escaping
through the drill string if the well should begin to flow or "kick." As an extra well control
precaution, an upper kelly cock (having left-hand threads) should be installed directly above
the kelly, while a lower kelly cock (having right-hand threads) should be installed below the
kelly. Installing two kelly cocks ensures that at least one of them is always accessible,
regardless of the kelly's position.
Automatic check valves, designed to close when the mud pumps are shut off, are also
available, and can be installed below the kelly to prevent mud from spilling onto the rig floor
Dimensions and Strengths
Like other oilfield tubulars, drill pipe comes in a variety of lengths, outside diameters,
weights and grades of steel. Drill pipe is also specified according to its upset (i.e., the type
of end section that is provided for weld-on connections or tool joints).
Hole size, well depth, casing and cementing requirements, subsurface pressures, circulating
system and drilling mud parameters, hoisting capacity, pipe availability and contract
provisions are among the factors that influence drill pipe selection.
The American Petroleum Institute has established standards for drill pipe manufacturing
practices, dimensions, strengths and performance properties. These standards appear in the
• API Spec 5D, Specification for Drill Pipe;
• API Bul 5C2, Bulletin on Performance Properties of Casing, Tubing and Drill Pipe;
• API RP 7G, Recommended Practice for Drill Stem Design Operating Limits.
API-standard drill pipe is available in three length ranges: Range 1(18-22 ft), Range 2 (27-30 ft) and
Range 3 (38-45 ft). Range 2 is the length most commonly used, making the "average" length of a drill
pipe joint about 30 feet.
Table 1., below, lists outside diameters and nominal weights for API standard drill pipe.
Note that these diameters and weights apply only to the drill pipe tube-in drilling
operations, the engineer also must account for the weight and diameter of the tool joints
and upsets. This information is available in API Spec SD and API RP 7G.
Outside diameter, inches
Nominal weights, lb/ft*
Table 1. Diameters and nominal weights of API-standard drill pipe.
There are four standards for measuring drill pipe strength:
torsional yield strength, a measure of the pipe's resistance to torque, or "twisting" force;
tensile yield strength, a measure of the pipe's resistance to axial tension, or "pulling" force;
collapse resistance, a measure of the pipe's ability to withstand external pressures;
internal yield, a measure of the pipe's ability to withstand internal pressure.
The strength of a drill pipe joint depends on its dimensions and configuration, and on the grade of steel
used in its manufacture. Table 2., below, lists some standard grades of steel used in drill pipe, along with
their minimum yield strengths.
Minimum Yield, psi
Table 2. Standard steel grades for drill pipe.
"Upset" refers to the end portions of a joint of drill pipe, to which are attached its threaded
connections, or tool joints. These upset areas have thicker walls than the rest of the drill
pipe tube to provide for stronger welds. Drill pipe upsets can be either internal, external or