Drill string: pipe, tool joints, drill collars and heavy-weight drill pipe

Quick refresher

The string is drill pipe (almost the whole length) and, at the bottom, the BHA: drill collars, stabilisers, a jar, subs, and sometimes a motor and MWD tools (measurement-while-drilling instruments). Heavy-weight drill pipe (HWDP) goes between the collars and the pipe, so that the stiffness does not change in a jump.
We describe a pipe by its outside diameter, nominal weight, strength grade, length range and tool joint. An example is 127 mm (5″), 19.50 lb/ft, S-135, length range 2, NC50 tool joint. The number in the grade is the minimum yield strength (the stress at which the steel starts to stretch permanently) in thousands of psi. For S-135 it is 931 MPa.
A tool joint is a thickened pin (the threaded male end) and box (the threaded female end), welded to the ends of the pipe. The shoulder, pressed together by the make-up torque (the torque used to tighten the joint), makes the connection tight and stiff. The tapered thread only pulls the shoulders together.
Drill collars are heavy-wall pipes. The driller puts part of their weight on the bit, while the drill pipe above them stays in tension (stretched). The thread of a collar is cut in the body itself, and the connection is its weak point.
The strength of the pipe body in tension is $F_y = Y_p A$ , and in torsion it is $M_y = Y_p J/(\sqrt3\,r)$ , where $r = D/2$ . Wear of the wall by 20% (the limit of the premium class) reduces both by about a fifth. Tension also reduces the allowable torque.
Worn pipes are inspected by electromagnetic, ultrasonic and magnetic particle methods. They are divided into classes by the remaining wall: premium has at least 80%, and class 2 at least 70%.

Key relationships

F_y = Y_p\,\dfrac{\pi}{4}\left(D^2 - d^2\right)

tensile load at which the pipe body reaches the yield strength

M_y = \dfrac{Y_p}{\sqrt3}\cdot\dfrac{J}{D/2}, \quad J = \dfrac{\pi}{32}\left(D^4 - d^4\right)

torque at which the outer surface of the pipe body reaches yield (von Mises criterion)

D_{\text{worn}} = d + 2\beta t

outside diameter of a pipe worn uniformly on the outside: $\beta$ is the fraction of the wall remaining (0.8 at the limit of the premium class)

W = \dfrac{\pi\left(D^4 - d^4\right)}{32\,D}

section modulus in bending: it is used to compare the stiffness of adjacent BHA elements

Common pitfalls

Taking the nominal weight of a pipe (19.50 lb/ft) for the actual weight with tool joints. The actual weight is greater.
Thinking that the thread, not the shoulder, seals the connection.
Using the rated strength of a new pipe for a worn string.
Forgetting that the allowable torque of a string is often limited by the tool joint, not by the pipe body.
Placing the jar at the neutral point or directly above a stabiliser.

After this lesson you can

list the elements of the drill string from top to bottom and explain what each is for
read the designation of a drill pipe (size, nominal weight, strength grade, length range, tool joint type) and use it to find the dimensions of the pipe and the yield strength of the steel
explain how a tool joint is built: why the shoulder, not the thread, seals the connection, and why a tool joint is tightened to a specified torque
explain why drill collars provide the weight on bit, why heavy-weight pipe and a gradual transition in stiffness are needed, and what stabilisers, reamers, jars, shock subs and crossover subs do
calculate the strength of the pipe body in tension and in torsion (twisting), for new and worn pipe, and explain the wear classes and the inspection methods
describe how the string is connected to the kelly or the top drive, and how it is shut off at the top

What the string is made of

A drill string does several jobs at once. It hangs the bit and passes to it part of the weight of the heavy lower pipes. This is the weight on bit. It transmits torque from the top drive or rotary table to the bit. Drilling fluid goes down it to the bit, and the mud-pulse signals of the MWD tools (pressure pulses in the mud that carry data) go up it. Formation testers, fishing tools (for recovering lost tools or pipe) and liners (short casing strings) are run on it, and cement plugs are set through it.

Elements of the drill string from top to bottom

Element: Top drive or kelly with valves and a sub (a short connecting piece)
What it is for: rotates the string and feeds mud into it; the valves shut off the string from inside
Where it is: above the rig floor

Element: Drill pipe
What it is for: makes up most of the length; carries the rotation, the mud flow and the overpull
Where it is: from the wellhead to the HWDP

Element: Heavy-weight drill pipe (HWDP)
What it is for: a gradual transition in stiffness; in deviated holes, part of the weight on bit
Where it is: above the drill collars

Element: Jar
What it is for: an upward or downward blow when the pipe is stuck
Where it is: in the HWDP or in the upper part of the drill collars

Element: Drill collars
What it is for: weight on bit, stiffness of the bottom of the string
Where it is: above the bit

Element: Stabilisers and reamers
What it is for: centre the drill collars, set the direction, keep the hole at its full diameter (in gauge)
Where it is: between the drill collars and above the bit

Element: Subs, shock sub, motor, MWD and LWD tools
What it is for: connect different threads, damp vibration, turn the bit, measure
Where it is: in the BHA

Element: Bit
What it is for: breaks the rock
Where it is: at the bottom

Element	What it is for	Where it is
Top drive or kelly with valves and a sub (a short connecting piece)	rotates the string and feeds mud into it; the valves shut off the string from inside	above the rig floor
Drill pipe	makes up most of the length; carries the rotation, the mud flow and the overpull	from the wellhead to the HWDP
Heavy-weight drill pipe (HWDP)	a gradual transition in stiffness; in deviated holes, part of the weight on bit	above the drill collars
Jar	an upward or downward blow when the pipe is stuck	in the HWDP or in the upper part of the drill collars
Drill collars	weight on bit, stiffness of the bottom of the string	above the bit
Stabilisers and reamers	centre the drill collars, set the direction, keep the hole at its full diameter (in gauge)	between the drill collars and above the bit
Subs, shock sub, motor, MWD and LWD tools	connect different threads, damp vibration, turn the bit, measure	in the BHA
Bit	breaks the rock	at the bottom

A BHA is usually from a few tens of metres to two or three hundred metres long. The rest of the length is drill pipe. The lesson Drill bits: types and design covers bits. The lesson Deflection tools and downhole motors covers motors, rotary steerable systems and MWD.

SchematicA drill string from the top drive to the bit (a diagram, not to scale). It shows drill pipe with tool joints, heavy-weight pipe with central upsets and a jar, drill collars with stabilisers, a non-magnetic drill collar with MWD sensors, a bit sub and the bit.

The crew measures every element of the string on the rig and enters it in the pipe tally. The driller knows the depth of the bit only as the sum of the lengths of everything run into the well. We also need the inside diameters from the same tally to calculate the volumes and pressure losses in the string (Circulating pressure losses).

Drill pipe

A drill pipe is a seamless steel pipe. Its wall is thickened at the ends by an upset, which can be internal, external or combined. In English the types are called IU, EU and IEU. In the Russian standard GOST R 50278-92, for pipes with welded tool joints, the types are PV, PN and PK (transliterated here from the Russian letters). Tool joints are friction-welded to the upset ends. There is a pin with an external thread at the bottom of each pipe and a box with an internal thread at the top. The upset is needed so that the weld and the transition to the tool joint are stronger than the pipe body. Pipes are run pin down. Two or three of them are screwed together into stands. When the string is pulled, it is not broken out into single pipes but into stands, which are racked back in the derrick (stood upright against the side of the tower).

A pipe is designated like this: 127 mm (5″), 19.50 lb/ft, S-135, length range 2, NC50 tool joint. The first number is the outside diameter of the pipe body. The second is the nominal weight. It is essentially a conventional indication of the wall thickness. The actual weight of a metre with tool joints and upsets is greater, and we take it from the manufacturer's catalogue. Next come the strength grade, the length range and the tool joint type.

Common drill pipe sizes

Outside diameter: 88.9 mm (3½″)
Nominal weight: 13.30 lb/ft
Wall and bore, mm: 9.35; 70.2
Typical tool joint: NC38

Outside diameter: 114.3 mm (4½″)
Nominal weight: 16.60 lb/ft
Wall and bore, mm: 8.56; 97.2
Typical tool joint: NC46

Outside diameter: 127.0 mm (5″)
Nominal weight: 19.50 lb/ft
Wall and bore, mm: 9.19; 108.6
Typical tool joint: NC50

Outside diameter: 139.7 mm (5½″)
Nominal weight: 21.90 lb/ft
Wall and bore, mm: 9.17; 121.4
Typical tool joint: 5½ FH

Outside diameter: 168.3 mm (6⅝″)
Nominal weight: 25.20 lb/ft
Wall and bore, mm: 8.38; 151.5
Typical tool joint: 6⅝ FH

Outside diameter	Nominal weight	Wall and bore, mm	Typical tool joint
88.9 mm (3½″)	13.30 lb/ft	9.35; 70.2	NC38
114.3 mm (4½″)	16.60 lb/ft	8.56; 97.2	NC46
127.0 mm (5″)	19.50 lb/ft	9.19; 108.6	NC50
139.7 mm (5½″)	21.90 lb/ft	9.17; 121.4	5½ FH
168.3 mm (6⅝″)	25.20 lb/ft	8.38; 151.5	6⅝ FH

The dimensions of the pipe body are from API Spec 5DP (ISO 11961). Every diameter also comes in heavier-wall pipes. The tool joint for a given pipe size may be a different one. 1 lb/ft = 1.488 kg/m.

As with casing (strength grades), the steel of drill pipe is divided into strength grades. The letter names the grade, and the number is the minimum yield strength in thousands of psi (ksi). For drill pipe the standard also sets an upper limit of the yield strength and a minimum tensile strength (the stress at which the steel breaks).

Strength grades of the drill pipe body

Grade: E-75
Yield strength, MPa: 517–724
Minimum tensile strength, MPa: 689

Grade: X-95
Yield strength, MPa: 655–862
Minimum tensile strength, MPa: 724

Grade: G-105
Yield strength, MPa: 724–931
Minimum tensile strength, MPa: 793

Grade: S-135
Yield strength, MPa: 931–1138
Minimum tensile strength, MPa: 1000

Grade	Yield strength, MPa	Minimum tensile strength, MPa
E-75	517–724	689
X-95	655–862	724
G-105	724–931	793
S-135	931–1138	1000

From API Spec 5DP (ISO 11961), with the values rounded. 1 ksi = 6.895 MPa. The steel of tool joints has at least 827 MPa (120 ksi). For ultra-deep wells and wells with a large departure (a long reach sideways), stronger pipes are also made, for example grades Z-140 and V-150. The interstate standard GOST 32696-2014 is built on ISO 11961. Russia (in force since 2016), Belarus, Kyrgyzstan and Tajikistan, among others, have adopted it. It has the same grades E, X, G and S, and also D and V, and versions for hydrogen sulfide service. In the Russian GOST R 50278-92 the strength grades are designated by the letters D, E, L, M and R (Russian letters, transliterated).

Length ranges of drill pipe

Length range: 1
Length of pipe with tool joints, m: 6.10–7.01
Feet: 20–23

Length range: 2
Length of pipe with tool joints, m: 8.84–9.75
Feet: 29–32

Length range: 3
Length of pipe with tool joints, m: 12.19–13.72
Feet: 40–45

Length range	Length of pipe with tool joints, m	Feet
1	6.10–7.01	20–23
2	8.84–9.75	29–32
3	12.19–13.72	40–45

From API Spec 5DP (ISO 11961, GOST 32696). This is the length of the pipe with welded tool joints, from the end of the box to the shoulder of the pin. Older reference books often give the ranges by the length of the pipe body: 18–22, 27–30 and 38–45 ft. Length range 2, about 9.5 m, is the one most often used. Each pipe is measured anyway, because lengths within a range differ.

Stronger is not always better. The stronger and harder the steel, the more easily it suffers sulfide stress cracking when hydrogen sulfide is present. The mechanism is the same as for casing. S-135 pipe can crack in such an environment without noticeable wear. So where hydrogen sulfide may be met, the crew uses pipes of a special grade with limited hardness, keeps the mud alkaline, and adds hydrogen sulfide scavengers (chemicals that bind the gas), for example zinc compounds.

Here are the loads that a drill pipe must withstand, and the reasons why it fails:

Tension. It comes from the weight of the string below the section and from the overpull when pulling out and working a stuck string.
Torsion. It comes from the resistance of the bit to rotation and the friction of the string against the walls, especially in deviated holes.
Alternating bending. In a curved section of the hole, a rotating pipe is stretched and compressed in turn, on the outer and inner sides of the bend, at every revolution. This is how fatigue (damage from repeated stress) builds up.
Vibrations. They can be axial (bit bounce), torsional (jerky “stick–slip”) or lateral (the string striking the walls).
Pressure. It acts from inside when pumping, and from outside when running an empty string, for example with a drill stem test.
Corrosion. It comes from oxygen, carbon dioxide, hydrogen sulfide and salts dissolved in the mud. It is especially dangerous together with fatigue: cyclic bending destroys protective films, and cracks grow faster (corrosion fatigue). Oxygen scavengers, for example sodium sulfite, are added to the mud against oxygen.
Wear. It is friction of the tool joints and the pipe body against the casing and the rock, and slip marks (marks left by the slips that grip the pipe).

A typical failure starts with a fatigue crack. It is most often in the pipe body not far from the upset, where the section changes, or in the zone gripped by the slips. Mud begins to break through the crack. This is a washout. If nobody notices it, the crack grows until the string twists off (breaks in two). The part left in the hole has to be recovered by fishing. A sign of a washout is a fall in standpipe pressure at an unchanged pump rate.

Tool joints and tool joint threads

Tool joints are the massive threaded ends of a pipe: a pin at the bottom and a box at the top. The outside diameter of a tool joint is larger than that of the pipe body, and its bore is smaller. The wall must hold the thread and withstand the make-up torque. Tongs (large wrenches) and slips grip the pipe at the tool joint or next to it. The elevator (a clamp that lifts the pipe) holds it under the tapered shoulder of the box.

Pin and box: The external and internal parts of the connection. The pin is on the lower end of the pipe, and the box is on the upper end.
Shoulder: The flat ring-shaped faces of the box and pin that are pressed against each other when the joint is made up. Only this interface seals the connection, and its preload gives the tool joint its stiffness in bending.
Rotary shouldered connection: A coarse tapered thread. In the common NC connections it has 4 threads per inch and a taper of 1 : 6. The pin enters the box deeply and is made up in a few turns.
Elevator shoulder: The tapered transition from the box of the tool joint to the pipe body, at an angle of 18°. The elevator rests on it when running in and pulling out.
Hardbanding: A wear-resistant band on the outside of the tool joint. It protects the tool joint from abrasion against the rock and the casing. In cased holes, casing-friendly hardbanding is used.

SchematicA made-up drill pipe tool joint in longitudinal section (a diagram, not to scale). The pin of the upper pipe has entered the box of the lower one. The tapered thread pulls the connection together, and the shoulder gives the seal. The upsets, the welds, the elevator shoulder and the hardbanding on the box are visible.

Why does the shoulder seal, and not the thread? There are gaps between the turns of the coarse tapered thread, and thread compound (the grease on the thread) does not hold high pressure. But when the joint is made up, the thread acts as a screw jack. The make-up torque is converted into a large axial force that presses the faces against each other. This force is called the preload. As long as the preload is greater than the force with which bending and tension try to open the interface, the faces do not separate, the mud does not get through, and the alternating stresses in the thread are small.

Too little torque. When the joint is bent in a curved hole, the interface opens on one side. The mud erodes the faces and the thread (a washout at the tool joint). The pin sees alternating stresses and fails by fatigue.
Too much torque. The steel of the tool joint yields (starts to deform permanently): the box swells, the pin stretches and the shoulders are crushed.
A working torque greater than the make-up torque. The connections are tightened further in the hole and can yield in the same way as when over-tightened. So the torque limit on the top drive is set below the make-up torque of the weakest connection in the string.

Manufacturers and standards calculate the recommended make-up torque so that the stress in the weaker element, the pin or the box, is about 60% of the yield strength of the tool joint steel. The torque that gives the specified preload depends on the thread compound. Compounds with metal powder (zinc, copper) and metal-free ones have different friction factors, so the rated torque is given for a particular compound. The torsional strength of a tool joint can be greater than that of the pipe body, or noticeably less. The aim is usually that it should be at least about 0.8 of the body strength, but it can be lower. For a 127 mm S-135 pipe with an NC50 tool joint of 168 × 83 mm it is about 0.7, and in torsion such a string is limited by the tool joint. For wells with a large departure, where torques are especially high, manufacturers make double-shoulder connections with an additional internal shoulder.

Here are the designations of tool joint threads. In the standard NC connections (numbered connection), the number is the pitch diameter of the pin thread at the gauge point, in tenths of an inch. For NC50 it is about 5.0″ (128 mm). Many of them are interchangeable with older types: NC50 with 4½″ IF, NC46 with 4″ IF and NC38 with 3½″ IF. There are also REG (regular, on bits and subs) and FH (full hole) threads. In the CIS standard (the standard of the Commonwealth of Independent States, the group of former Soviet republics; GOST 28487), a tool joint thread is designated by the letter Z (a Russian letter, transliterated) and the diameter of the larger base of the pin cone in millimetres, for example Z-133. Connections of different types are made up only through a crossover sub.

Drill collars and heavy-weight drill pipe

Drill collars are heavy-wall pipes about 9–9.5 m long with a small bore. A metre of drill collar weighs several times as much as a metre of drill pipe. The driller lowers the string and so puts part of the weight of the collars on the bit. The drill pipe above them stays in tension. Compressed drill pipe loses stability and bends in a wave, and when it rotates it quickly builds up fatigue. We calculate separately where the boundary between the stretched and the compressed part of the string lies (the neutral point), and how many collars are needed for a given weight (Drill string design).

The second job of drill collars is stiffness. Thick pipes bend less under load and keep the bit on the axis of the hole. Together with the stabilisers, they decide whether the hole will build, hold or drop angle (assemblies without a motor).

Mass of a metre of drill collar

m = \rho_{\text{steel}}\,\frac{\pi}{4}\left(D^2 - d^2\right)

where:

$m$ mass of a metre of plain drill collar (not allowing for grooves and spiral flutes), kg/m
$\rho_{\text{steel}}$ density of steel, 7850 kg/m³, kg/m³
$D,\ d$ outside diameter and bore diameter, m

Units: SI

Holds when

The pipe is plain and cylindrical. Grooves, spiral flutes and threads reduce the mass a little.
To get the weight in mud, multiply by the buoyancy factor $1 - \rho_m/\rho_{\text{steel}}$ (it allows for the lift of the mud), as for casing.

The mass grows with the square of the outside diameter. So for the same length, large collars give a far greater weight than drill pipe.

In other unit systems (2)

Metric units

m\,[\text{kg/m}] = 0.006165\left(D^2 - d^2\right)\;[\text{mm}]

$D$ and $d$ are in mm.

$0.006165 = 7850\cdot\pi/4\cdot 10^{-6}$ .

Oilfield units

m\,[\text{lb/ft}] = 2.67\left(D^2 - d^2\right)\;[\text{in}]

$D$ and $d$ are in inches.

$2.67 = 490\cdot\pi/4/144$ . Steel weighs 490 lb/ft³, and a square foot has 144 square inches.

Some drill collar sizes and the mass of a metre by the formula

Drill collar: diameter × bore: 120.7 × 57.2 mm (4¾ × 2¼″)
Mass, kg/m: 70
lb/ft: 47
Typical hole: 152–156 mm

Drill collar: diameter × bore: 165.1 × 71.4 mm (6½ × 2 13/16″)
Mass, kg/m: 137
lb/ft: 92
Typical hole: 215.9 mm

Drill collar: diameter × bore: 203.2 × 71.4 mm (8 × 2 13/16″)
Mass, kg/m: 223
lb/ft: 150
Typical hole: 311.1 mm

Drill collar: diameter × bore: 241.3 × 76.2 mm (9½ × 3″)
Mass, kg/m: 323
lb/ft: 217
Typical hole: 444.5 mm

Drill collar: diameter × bore	Mass, kg/m	lb/ft	Typical hole
120.7 × 57.2 mm (4¾ × 2¼″)	70	47	152–156 mm
165.1 × 71.4 mm (6½ × 2 13/16″)	137	92	215.9 mm
203.2 × 71.4 mm (8 × 2 13/16″)	223	150	311.1 mm
241.3 × 76.2 mm (9½ × 3″)	323	217	444.5 mm

The mass is that of a plain pipe, from the formula above. Catalogues give rounded values. For comparison, the body of a 127 × 9.19 mm drill pipe weighs 26.7 kg/m, and with tool joints about 31–35 kg/m, depending on the tool joint.

Drill collar connections. Collars have no tool joints. The thread is cut directly in the body, and this is the weak point of the pipe. The bending of the stiff pipe falls on the thread. So collar connections are made up strictly to torque, lubricated with a compound containing metal powder, and fitted with stress-relief features. These are a groove on the pin (stress-relief groove) and a bore in the box beyond the thread (boreback). The dimensions of the connection are chosen so that neither the box nor the pin is noticeably weaker than the other. The measure is the bending strength ratio, which is the ratio of the section moduli of the box and the pin. Experience shows that a connection with a ratio of about 2.5 is balanced. When the box wears at its outside diameter, the ratio falls and the connection begins to fail at the box. With a ratio well above the norm, the pin becomes the weak point.

Slick drill collars are round along their whole length. They are the most common.
Spiral drill collars have spiral grooves on the outer surface. They are hardly lighter than slick ones. But they touch the wall over a much smaller area, so they stick to it less often when the mud pressure is greater than the formation pressure (differential sticking).
Square drill collars have a section that is almost the full width of the hole. They give the greatest stiffness and are rarely used.
Non-magnetic drill collars are made of non-magnetic stainless steel (formerly of the nickel–copper alloy Monel). The MWD direction sensors are placed in them, so that the steel of the string does not distort the readings of the magnetometers (what the driller sees).
Pony collars (short collars) and collars with slip and elevator recesses are used for adjusting the distances between stabilisers and for handling without a lift sub.

Heavy-weight drill pipe (HWDP) is the intermediate link between drill collars and drill pipe. In 127 mm HWDP the bore is about 76 mm (3″). The tool joints are extended, about 168 mm (6⅝″) in diameter. In the middle of the pipe there is a central upset, a thickening of about 140 mm (5½″) that keeps the pipe body off the wall. A metre with tool joints has a mass of about 75 kg/m. That is more than drill pipe but much less than drill collars. The outside diameter of the body and the type of tool joint are the same as for drill pipe of the same size, so the crew handles HWDP with the same tools. HWDP has three purposes:

A smooth transition in stiffness. At the transition from the very stiff drill collars to the flexible drill pipe, the bending concentrates in the first few pipes, and they quickly build up fatigue. HWDP divides this jump into two steps (see the example below).
Weight on bit in deviated and horizontal holes. There the wall of the hole supports the pipe, so HWDP can work in compression until it buckles, and it replaces part of the drill collars. This means less torque and drag when pulling out, and a lower risk of sticking. In a vertical hole compressed pipe buckles at a small load, so there HWDP, like drill pipe, is kept in tension.
A place for the jar. It goes above the drill collars, where it does not fall on the neutral point.

Worked exampleThe jump in stiffness at the transition from drill collars to drill pipe

Given (assumed data)

Drill collars: 203 × 80 mm — from the pendulum assembly of the lesson on deflection tools; if needed, another section of 165.1 × 71.4 mm
HWDP: body 127 × 76.2 mm
Drill pipe: 127 × 9.19 mm, bore 108.62 mm

Solution

Section modulus (a measure of stiffness in bending) $W = \pi(D^4 - d^4)/(32D)$ : drill collar 203 × 80 mm, 801.5 cm³. HWDP, 175.0 cm³. Drill pipe, 93.5 cm³.
If drill pipe is screwed straight onto the drill collars, the ratio of the section moduli at the transition is $801.5/93.5 = 8.57$ .
With HWDP between them there are two steps: from drill collars to HWDP, 4.58, and from HWDP to drill pipe, 1.87.
Suppose another section of drill collars, 165.1 × 71.4 mm ( $W$ = 426.4 cm³), is put between the large collars and the HWDP. Then the steps are 1.88, 2.44 and 1.87.
For comparison, the mass of a metre: drill collar 203 × 80 mm, 214.6 kg/m. Drill pipe body, 26.7 kg/m.

Answer: A direct transition gives a jump in the section modulus by a factor of 8.57. With HWDP the largest step is 4.58, and with an intermediate section of drill collars it is 2.44.

What it means. In practice the rule is that the ratio of the section moduli of adjacent elements of the string should be no more than about 5.5 in ordinary conditions, and 3.5 in severe ones. Severe conditions are hard rock, strong vibration, and places where strings have already broken. A direct transition with a ratio of 8.57 is not acceptable in either case. HWDP brings it down to the norm for ordinary conditions. With an intermediate section of drill collars, the steps meet even the strict rule. The rule is empirical and does not replace a fatigue calculation, but it is simple and warns against failures at changes in stiffness. The pipe sizes are standard; the assembly is assumed for illustration.

Stabilisers, reamers, jars and subs

Stabilisers (also called calibrators in Russian-language practice) are short pipes with three or four straight or spiral blades. The outside diameter of the blades equals the bit diameter, or is slightly smaller. The blades are faced with a hard alloy or fitted with tungsten carbide inserts. Stabilisers keep the drill collars in the middle of the hole. They stop the collars bending and pressing against the wall, and they even out the weight on bit. Together with their spacing along the BHA, they decide how the angle will behave (build, hold, drop).

Integral blade: The blades are machined from one piece with the body. This is the strongest and most common type.
Welded blade: Cheaper, but a blade may come off. It is used in soft rock.
Sleeve-type: The blades are on a sleeve that can be changed on the rig when it wears or the hole diameter changes.
Non-rotating: A rubber sleeve with blades stays in place while the shaft rotates inside it. This means less wear and torque in hard abrasive rock. Temperature limits its use.
Near-bit and string stabilisers: A near-bit stabiliser is screwed straight onto the bit and has boxes at both ends. A string stabiliser is placed between the drill collars and has a pin and a box.

A stabiliser that has worn in diameter stops doing its job, and the assembly behaves differently from what was calculated. So after each trip the crew checks its diameter with a gauge ring. It changes the stabiliser when the wear exceeds the tolerance of the drilling programme.

Reamers. A roller reamer carries rollers with tungsten carbide inserts instead of blades. It holds the hole diameter in hard abrasive rock, where the bit quickly loses gauge (wears smaller). It also passes ledges, grooves and sharp bends of the hole with less torque than a blade stabiliser. Hole openers enlarge a pilot hole (a hole of smaller diameter) that has already been drilled. Underreamers open their cutters below a restriction, for example below a casing shoe, and drill a hole wider than the inside diameter of the restriction.

The jar (drilling jar) is an impact tool for freeing a stuck string. When the driller pulls on the string, the pipe above the jar stretches like a spring. The jar holds the pipe from contracting for a while. Then it releases its telescoping part, and the hammer strikes the anvil after a run-up. The energy of the stretch is turned into a blow at the stuck point. To deliver a downward blow, the driller sets the weight of the pipe above the jar down on it.

A hydraulic jar fires after a delay: oil slowly bleeds through a narrow passage. The harder the pull, the stronger the blow, so the driller controls the force of the blow.
A mechanical jar fires at a preset load and does not fire by accident during a trip. Hydromechanical jars combine both principles; most modern jars hit both up and down.
An accelerator is placed above the jar. It stores energy in compressed gas or a spring, strengthens the blow, and protects the pipe and the derrick from the shock wave.
Where to place it. Do not place it at the neutral point, because there the jar works under alternating loads and tires or fires by itself. Do not place it directly above a stabiliser, where the bending is stronger, or hard up against a crossover sub. There must be enough heavy pipe above the jar for the downward blow. If sticking to the wall is expected, the jar is moved higher in the BHA, so that the sticking does not come above the jar. Manufacturers calculate the place of the jar for each assembly.

A shock sub is placed above the bit when drilling hard rock. A steel spring or an elastic element in it damps the longitudinal vibrations and the impacts of the bit on the bottom. Subs are short parts of the BHA with various tasks:

A crossover sub connects elements with different threads or diameters.
A bit sub has boxes at both ends and often carries a float valve, which stops the mud from going up the pipe (shutting off the string from inside).
A saver sub is placed under the kelly or top drive. The thread wears on it at every connection, so the expensive part stays intact.
A lift sub is screwed onto a drill collar without a recess so that it can be lifted with the elevator.
A bent sub is a sub with a bent axis. It is the source of the offset in deflecting assemblies (assemblies that steer the well).
A circulating sub opens ports above the BHA, for example to pump lost circulation material (a filler that plugs a loss zone) past the motor and the bit.

The top of the string: the kelly or the top drive

When the rig drills with a rotary table, a pipe of square or hexagonal cross-section, the kelly, turns the string. The kelly passes through the bushings of the rotary table and can slide down while it keeps rotating. Standard kellies are 12.2 or 16.5 m (40 or 54 ft) long. After the bit has drilled down the whole working length of the kelly, the crew lengthens the string by one joint. The upper thread of the kelly, which connects to the swivel (the rotating joint that carries the weight of the string and lets mud in), is left-handed. This means the right-hand rotation of the string tightens it instead of unscrewing it. There are ball valves above and below the kelly, and a saver sub under the lower valve.

The top drive is a motor hung from the travelling block. It turns the string directly through its own shaft. It has three main advantages. First, the crew can drill with a stand of two or three joints, which means fewer connections. Second, it can rotate and circulate while pulling the string out (backreaming, which is working the bit back up through the hole to clean it). Third, it can connect to the string quickly at any moment and at any height, for example with stuck pipe or with a kick (an unwanted inflow of fluid into the well) during a trip. Two ball valves are built into the top drive: an upper one with remote control and a lower manual one. It also has a power wrench for making up and breaking out connections, and a saver sub.

The torque limit on the top drive links it with the strength of the string. It is set below the make-up torque of the weakest connection and below the allowable torque of the pipe body. The lesson Rig circulating and rotary systems covers the design of the rotary table, swivel and top drive. The lesson on blowout prevention equipment covers the role of the valves during a kick.

Tensile and torsional strength of the pipe body

Catalogues give each pipe's rated properties. These are the tensile load and the torque at which the pipe body reaches the yield strength, the internal yield pressure and the collapse pressure. The pressures are calculated by the same formulas as for casing (rated properties of pipe). For a drill string, collapse (crushing by outside pressure) matters when the string is run empty, for example with a formation tester. All the rated values are calculated for the minimum yield strength, for each load separately and without design factors.

Tensile strength of the pipe body

F_y = Y_p\,A = Y_p\,\frac{\pi}{4}\left(D^2 - d^2\right)

where:

$F_y$ tensile load at which the stress in the pipe body reaches the minimum yield strength (tensile yield), N
$Y_p$ minimum yield strength of the strength grade, MPa
$A$ cross-sectional area of the wall of the pipe body, mm²
$D,\ d$ outside and inside diameters of the pipe body, mm

Units: MPa × mm² = N

Holds when

The load is axial and uniform over the section; there is no bending, torsion or pressure.
Nominal dimensions of a new pipe; for a worn one a reduced outside diameter is used.
This is the yield strength, not failure: above it the pipe stretches permanently. The working load is taken with a margin.

The strength grows in proportion to the yield strength and the wall area. The tool joint and the upset are designed to be stronger than the body, so in tension the string is usually limited by the pipe body.

Torsional strength of the pipe body

M_y = \frac{Y_p}{\sqrt3}\cdot\frac{J}{D/2}, \qquad J = \frac{\pi}{32}\left(D^4 - d^4\right)

where:

$M_y$ torque at which the shear stress at the outer surface reaches the shear yield strength (torsional yield), N·mm
$Y_p/\sqrt3$ yield strength in pure shear by the von Mises criterion — about 0.577 of the yield strength in tension, MPa
$J$ polar moment of inertia of the section of the pipe body, mm⁴
$D,\ d$ outside and inside diameters, mm

Units: MPa, mm; the torque in N·mm (divided by $10^6$ , in kN·m)

Holds when

The torsion is pure. The shear stress grows linearly from the axis to the outer surface, and yielding begins at the surface.
Tension is not taken into account. Under tension the allowable torque is smaller (see the advanced section).
This is a property of the pipe body. The tool joint is checked separately for its own torque.

The torque grows with the yield strength and especially fast with the outside diameter: $J/(D/2)$ increases almost as the cube of the diameter. So wear on the outside takes away torsional strength slightly faster than tensile strength (in the example below, 78% against 79% of the new pipe).

In other unit systems (1)

Oilfield units

Q\,[\text{ft·lbf}] = 0.096167\,\frac{J\,[\text{in}^4]\;Y_p\,[\text{psi}]}{D\,[\text{in}]}

$J$ is in inches to the fourth power, $Y_p$ in psi, $D$ in inches, $Q$ in foot-pounds force.

$0.096167 = 2\cdot 0.577/12$ : $0.577 \approx 1/\sqrt3$ , the factor 2 comes from the radius $D/2$ , and 12 converts inch-pounds to foot-pounds. The rated torques in catalogues are calculated by this form.

Wear reduces both properties. For a worn pipe we calculate the rated values as if the wall were worn uniformly on the outside down to the allowable remainder $\beta t$ , with the bore unchanged. The outside diameter then becomes $D_{\text{worn}} = d + 2\beta t$ . At the limit of the premium class $\beta = 0.8$ . Real wear is usually one-sided, and for the same smallest wall thickness more metal remains in the section. So the assumption of uniform wear is on the safe side.

Worked exampleStrength of a 127 × 9.19 mm S-135 pipe: new and worn

Given (assumed data)

Pipe body: 127 × 9.19 mm (5″, 19.50 lb/ft)
Strength grade: S-135: $Y_p$ = 931 MPa (135,000 psi)
Wear: uniform on the outside, 80% of the wall remaining (the limit of the premium class)

Solution

Bore: $d = 127 - 2\cdot 9.19 = 108.62$ mm. Wall area: $A = \frac{\pi}{4}(127^2 - 108.62^2) = 3401$ mm².
Tension: $F_y = 931\cdot 3401 = 3.17$ MN, about 323 tf.
Torsion: $J = \frac{\pi}{32}(127^4 - 108.62^4) = 11.874\cdot 10^6$ mm⁴. Then $M_y = \dfrac{931}{\sqrt3}\cdot\dfrac{11.874\cdot10^6}{63.5} = 100.5$ kN·m.
Check in oilfield units: with $D$ = 5″, $d$ = 4.276″ and $Y_p$ = 135,000 psi, the catalogue formula gives 74,100 ft·lbf and 712 thousand lbf in tension. These are the same values as in the tables of the standard for this pipe.
Worn pipe: $D_{\text{worn}} = 108.62 + 2\cdot 0.8\cdot 9.19 = 123.324$ mm. Then $A = 2679$ mm², $F_y = 2.49$ MN and $M_y = 78.8$ kN·m. These are 79% and 78% of the values for the new pipe.
For comparison, a new pipe of the same size of grade G-105 ( $Y_p$ = 724 MPa): $F_y = 2.46$ MN, $M_y = 78.2$ kN·m.

Answer: A new S-135 pipe starts to yield in tension at 3.17 MN or in torsion at 100.5 kN·m. A pipe worn to the limit of the premium class does so at 2.49 MN or 78.8 kN·m.

What it means. Wearing away a fifth of the wall takes away about a fifth of the strength, in both tension and torsion. A worn S-135 pipe turns out almost equal to a new G-105 pipe. These are the yield limits of the pipe body alone, without design factors and without the combined action of loads. Working loads are taken with a margin (Drill string design). The tool joint, with its make-up torque, often limits the allowable torque of the string. The sizes and strength grades are standard; the wear is assumed for illustration.

A tool joint has its own torsional strength, calculated from the sections of the pin and the box in the thread, and its own recommended make-up torque. When the tool joint wears on its outside diameter, the box weakens. So at inspection tool joints are classified separately, by the smallest outside diameter and the width of the shoulder.

Wear, inspection and pipe classes

A drill pipe serves on many wells, and its condition changes from trip to trip. The tool joints and the pipe body wear. Slip marks appear. Corrosion pits form on the inner surface. Fatigue cracks develop near the upsets. Threads and shoulders are damaged, the box swells and the pin stretches. So pipes are checked from time to time by non-destructive methods (methods that do not damage the pipe). This is called inspection. On its results a pipe is assigned to a class, or rejected.

Methods of drill pipe inspection

Method: Visual inspection and measurement
What it finds: damage to threads and shoulders, wear of tool joints, width of the shoulder, swelling of the box
Limitations: only what is visible from outside; the inside after cleaning

Method: Electromagnetic inspection of the pipe body (EMI)
What it finds: transverse and longitudinal cracks, pits, thinning of the wall along the whole length
Limitations: does not cover upsets and tool joints; findings are refined by other methods

Method: Ultrasonic inspection (UT)
What it finds: wall thickness; cracks in the upsets and in the slip area
Limitations: needs surface preparation, inspects selected zones

Method: Magnetic particle inspection (MPI)
What it finds: surface cracks in threads, near shoulders, in upsets; usually fluorescent powder under ultraviolet light
Limitations: does not see internal defects; on non-magnetic drill collars it is replaced by dye penetrant inspection

Method	What it finds	Limitations
Visual inspection and measurement	damage to threads and shoulders, wear of tool joints, width of the shoulder, swelling of the box	only what is visible from outside; the inside after cleaning
Electromagnetic inspection of the pipe body (EMI)	transverse and longitudinal cracks, pits, thinning of the wall along the whole length	does not cover upsets and tool joints; findings are refined by other methods
Ultrasonic inspection (UT)	wall thickness; cracks in the upsets and in the slip area	needs surface preparation, inspects selected zones
Magnetic particle inspection (MPI)	surface cracks in threads, near shoulders, in upsets; usually fluorescent powder under ultraviolet light	does not see internal defects; on non-magnetic drill collars it is replaced by dye penetrant inspection

Pipes are classified by the smallest remaining wall thickness of the body and by other signs of wear. Coloured bands on the pipe mark the classes. International practice relies on the recommendations of API RP 7G-2:

Classes of used drill pipe

Class: Premium
Marking: two white bands
Remaining wall of the body: at least 80% of nominal

Class: Class 2
Marking: one yellow band
Remaining wall of the body: at least 70%

Class: Class 3
Marking: one orange band
Remaining wall of the body: wear greater than allowed for class 2

Class: Scrap
Marking: one red band
Remaining wall of the body: cracks, washouts and other unacceptable defects — whatever the wall

Class	Marking	Remaining wall of the body
Premium	two white bands	at least 80% of nominal
Class 2	one yellow band	at least 70%
Class 3	one orange band	wear greater than allowed for class 2
Scrap	one red band	cracks, washouts and other unacceptable defects — whatever the wall

Tool joints are classified separately, by the smallest outside diameter and the width of the shoulder. Many operators also apply the industry standard DS-1. In it a category from 1 to 5 sets the scope of inspection: the more severe the conditions of the well and the more expensive a failure, the more methods and zones are inspected.

The rated properties of premium-class pipes are calculated for uniform wear down to 80% of the wall, as in the example above. The customer usually states in the contract with the drilling contractor which class of pipe is allowed and when pipes are inspected. The times can be before the start of work, after a certain footage drilled or running time, after sticking and jarring, or before critical wells.

Terms and symbols

Drill string: The string from the top drive or kelly to the bit: drill pipe, HWDP, BHA.
Tool joint: The pin and box welded to the ends of a drill pipe. The shoulder seals the connection.
Nominal weight: A conventional indication of the wall thickness of a drill pipe, in lb/ft. The actual weight with tool joints is greater.
Strength grade (E-75, X-95, G-105, S-135): The class of steel of the pipe body. The number is the minimum yield strength in ksi.
Make-up torque: The torque to which a connection is tightened to press the shoulders together.
Drill collars: Heavy-wall drill pipes. They give the weight on bit and the stiffness of the bottom of the string.
HWDP: Heavy-weight drill pipe with long tool joints and a central upset. It gives a transition in stiffness, and weight in deviated holes.
Stabiliser: An element of the BHA with blades reaching almost the full diameter of the hole (in Russian-language practice also called a calibrator).
Jar: An impact tool for freeing a stuck string.
Sub: A short part for connecting different threads and for other auxiliary tasks.
Top drive, kelly: Devices that rotate the string from above and feed mud into it.
Pipe class: The category of a used pipe by the remaining wall and defects: premium, class 2, class 3, scrap.

Common mistakes and misconceptions

Wrong

“The tool joint thread holds the pressure, as on a casing pipe.”

In fact

The coarse tool joint thread is not leak-tight. The seal is the shoulder, pressed together by the make-up torque. An under-tightened tool joint lets mud through when it is bent, and it washes out.

Wrong

“S-135 pipe is stronger, so it is always the better choice.”

In fact

When hydrogen sulfide is present, high-strength steel is prone to sulfide stress cracking. There the crew needs pipes of a special grade with limited hardness.

Wrong

“The weight on bit can be produced by the weight of the drill pipe.”

In fact

In a vertical hole compressed drill pipe buckles and quickly tires. The drill collars provide the weight, and the pipe above them stays in tension. In deviated holes HWDP, which the wall supports, can provide part of it.

Wrong

“A worn pipe is as strong as a new one as long as it has no cracks.”

In fact

The strength of the body is proportional to the wall area, and in torsion it depends even more strongly on the outside diameter. Wear down to 80% of the wall takes away about a fifth of the strength.

Wrong

“The more torque on the top drive, the better the string gets through trouble.”

In fact

A torque above the make-up torque tightens the tool joints further in the hole and can damage them. A torque above the allowable torque of the body can twist the pipe off. The weakest connection sets the torque limit on the drive.

In depth: advanced detail

Torsion under tension

In the upper part of the string a pipe is stretched by the weight of everything that hangs below it, and it is also twisted. Yielding begins when the combination of the normal stress $\sigma$ (the pull per unit area) and the shear stress $\tau$ (the twisting stress) reaches the limit. By the von Mises criterion, $\sigma^2 + 3\tau^2 = Y_p^2$ . So the allowable shear stress, $\tau = \sqrt{(Y_p^2 - \sigma^2)/3}$ , decreases as the tension grows, and so does the allowable torque.

Yield torque of the pipe body under tension

M_y(F) = M_y\,\sqrt{1 - \left(\frac{F}{F_y}\right)^2}

where:

$M_y(F)$ torque at which the outer surface of the pipe body reaches yield under a tensile load $F$ , kN·m
$M_y,\ F_y$ strength of the pipe body in pure torsion and in pure tension, kN·m, MN
$F$ tensile load in the given section, MN

Units: any consistent ones: $F$ and $F_y$ in the same units of force

Holds when

The tension is uniform over the section; there is no bending or pressure.
The von Mises criterion for the outer surface, where the shear stress is greatest.
The pipe body; the tool joint is checked separately.

The curve is a quarter of an ellipse: at small tension the torque hardly decreases, but near $F_y$ it falls to zero. A worn pipe loses torque faster because the same load is a larger fraction of its limit.

CalculatedCalculated yield limits of the body of a 127 × 9.19 mm S-135 pipe under combined tension and torsion, for a new pipe and for one worn to the limit of the premium class. The points mark the tension of 1.80 MN from the example below.

Worked exampleHow much torque a pipe can take at the wellhead of a deep well

Given (assumed data)

Pipe: 127 × 9.19 mm, S-135, new and worn to the premium class — from the example of the lesson
Tensile load at the wellhead: 1.80 MN (assumed; how it is calculated is covered in drill string design)

Solution

Fraction of the limit in tension: for the new pipe $1.80/3.167 = 0.5684$ , for the worn one $1.80/2.494 = 0.7217$ .
New: $M_y(F) = 100.51\cdot\sqrt{1 - 0.5684^2} = 82.7$ kN·m.
Worn: $M_y(F) = 78.83\cdot\sqrt{1 - 0.7217^2} = 54.6$ kN·m.

Answer: Under a tension of 1.80 MN, a new pipe withstands 82.7 kN·m before yielding (instead of 100.51). A worn pipe withstands only 54.6 kN·m (instead of 78.83).

What it means. The tension has taken 18% of the torsional strength from the new pipe and 31% from the worn one. So in deep wells the most stretched upper pipes of the string are chosen with particular care: they are new, or of a stronger grade. The allowable torque is estimated with the tension and the wear taken into account. This is the yield limit without a margin. The data in this example are assumed for illustration.

Why pipes tire in a curved hole

A pipe lying in a curved section of the hole is bent. On the outside of the bend its fibres are stretched, and on the inside they are compressed. As the pipe rotates, each point of the wall passes through both sides in one revolution, and the stress in it changes from $+\sigma_b$ to $-\sigma_b$ . At 120 rpm that is 172,800 cycles a day. This is how the fatigue builds up that ends in a crack and a washout.

Bending stress in a pipe rotating in a curved hole

\sigma_b = \frac{E\,\kappa\,D}{2}\cdot\frac{KL}{\tanh(KL)}, \qquad K = \sqrt{\frac{T}{EI}}

where:

$\sigma_b$ largest bending stress in the pipe body — at the tool joints, Pa
$E$ Young's modulus of steel, $2.07\cdot10^{11}$ , Pa
$\kappa$ curvature of the hole: the dogleg severity (how fast the hole bends along its length) converted to radians per metre, rad/m
$D$ outside diameter of the pipe body, m
$T$ tensile load in the pipe at this depth, N
$I$ second moment of area of the section of the pipe body, $J/2$ , m⁴
$L$ half the distance between tool joints (for length range 2 pipe, about 4.6 m), m

Units: SI

Holds when

The pipe body between the tool joints does not touch the wall of the hole; the tool joints lie on the wall.
The curvature of the hole is constant over the length of the pipe.
Without tension the factor $KL/\tanh(KL)$ equals one, and the pipe simply follows the curvature of the hole.

Tension straightens the pipe between the tool joints, and the bending concentrates near the joints. The stress there grows almost in proportion to $\sqrt T$ . So the same dogleg is much less dangerous deep down, where the pipes are little stretched, than in the upper part of the well, where the tension is high.

Worked exampleA 3° dogleg over 30 m: at the bottom and at the top of the string

Given (assumed data)

Pipe: 127 × 9.19 mm; $I = J/2$ ; $E = 2.07\cdot10^{11}$ Pa; $L$ = 4.6 m
Dogleg severity: 3° per 30 m
Tension of the pipe in the dogleg: 0.5 MN (dogleg deep in the well) and 1.5 MN (dogleg in the upper part)

Solution

Curvature $\kappa = 3\cdot\pi/180/30 = 0.001745$ rad/m; without tension $\sigma_b = E\kappa D/2 = 22.9$ MPa.
Section stiffness $EI = 1.229$ MN·m². At 0.5 MN: $K = \sqrt{0.5/1.229} = 0.638$ m⁻¹, $KL = 2.93$ , the factor $KL/\tanh(KL) = 2.95$ , $\sigma_b = 68$ MPa.
At 1.5 MN: $K = 1.105$ m⁻¹, $KL = 5.08$ , the factor 5.08, $\sigma_b = 116$ MPa.

Answer: The same dogleg gives an alternating stress of about 68 MPa deep in the string and about 116 MPa in its upper part, instead of the 22.9 MPa that it gives without tension.

What it means. The stresses are far below the yield strength, but they repeat hundreds of thousands of times a day. In mud that contains oxygen, carbon dioxide or hydrogen sulfide, steel essentially has no safe level of alternating stress. A crack grows even at small stresses, only more slowly. This gives practical rules. Sharp doglegs are especially dangerous in the upper part of the hole. Pipes that have gone through them are inspected more often. The allowable dogleg severity is assessed with the tension taken into account. The data in this example are assumed for illustration.

Connections to other topics

How a well is drilled: the process and the people involved — the drilling rig, stands, connections and trips.
Deflection tools and downhole motors — BHAs for building, holding and dropping angle, downhole motors, RSS and MWD.
Casing: purpose, types, properties and standards — strength grades, sulfide stress cracking and the rated pressures of pipe.
Blowout prevention equipment — the top drive valves, the ball valve on the rig floor and the check valves in the string.
Circulating pressure losses — how the diameters of the pipe, collars and tool joints determine the pressure losses during circulation.
Drill string design — weight on bit, the neutral point, the margin of overpull and the length of the drill collars.
Drill bits: types and design — bits and the subs for them.
Rig circulating and rotary systems — the rotary table, swivel and top drive as parts of the drilling rig.

Check yourself

1
What makes a made-up drill pipe tool joint leak-tight?
1. A.The thread compound
2. B.The shoulders of the pin and the box, pressed together by the make-up torque
3. C.The tapered thread
4. D.A rubber seal ring
Show the answer
Correct answer: B. The shoulders of the pin and the box, pressed together by the make-up torque
There are gaps between the turns of the coarse tool joint thread, and the compound cannot seal them. The shoulders seal the connection, and the thread only gives the preload when the joint is made up. If the torque is too low, the interface opens when the string is bent, and the connection washes out.
2
Find the tensile and torsional strength of the body of a new 114.3 × 8.56 mm (4½″, 16.60 lb/ft) G-105 pipe.
Show the answer
Bore: $d = 114.3 - 2\cdot8.56 = 97.18$ mm. Wall area: $A = \frac{\pi}{4}(114.3^2 - 97.18^2) \approx 2844$ mm². Tensile strength: $F_y = 724\cdot 2844 \approx 2.06$ MN (about 463 thousand lbf). Polar moment: $J = \frac{\pi}{32}(114.3^4 - 97.18^4) \approx 8.00\cdot10^6$ mm⁴. Torsional strength: $M_y = \dfrac{724}{\sqrt3}\cdot\dfrac{8.00\cdot10^6}{57.15} \approx 58.5$ kN·m, which is about 43,100 ft·lbf.
3
Why is heavy-weight drill pipe placed between the drill collars and the drill pipe?
1. A.So that the stiffness changes in steps rather than in a jump, and the drill pipe above the collars does not fail from fatigue
2. B.To increase the inside diameter of the string
3. C.So that a jar is not needed
4. D.To make the string lighter
Show the answer
Correct answer: A. So that the stiffness changes in steps rather than in a jump, and the drill pipe above the collars does not fail from fatigue
At an abrupt transition from stiff drill collars to flexible pipe, the bending concentrates in the first few pipes. HWDP is intermediate in stiffness and divides the jump into steps. In deviated holes it can also provide part of the weight on bit.
4
According to an inspection report, the smallest remaining wall of a 127 × 9.19 mm pipe is 7.6 mm, and there are no cracks. Which class should it be assigned to? How will its tensile strength change compared with the rating of a new pipe, if the wear is taken as uniform on the outside?
Show the answer
The remainder is $7.6/9.19 \approx 0.83$ , which is more than 80%, so the pipe is premium class. With uniform wear, $D_{\text{worn}} = 108.62 + 2\cdot7.6 = 123.82$ mm. The area is $\frac{\pi}{4}(123.82^2 - 108.62^2) \approx 2775$ mm², against 3401 mm² for the new pipe. That is about 82% of the tensile strength. The premium-class rating is calculated for 80% of the wall, so it is on the safe side.
5
Why is the torque limit on the top drive set below the make-up torque of the tool joints?
1. A.So that the bit wears less
2. B.So as not to overheat the drive motor
3. C.The drilling fluid requires it
4. D.So that the tool joints are not tightened further in the hole beyond the design torque and do not suffer permanent deformation
Show the answer
Correct answer: D. So that the tool joints are not tightened further in the hole beyond the design torque and do not suffer permanent deformation
If the working torque is greater than the make-up torque, the connections are tightened further in the hole: the boxes swell, the pins stretch and the shoulders are crushed. So the torque limit on the drive is chosen by the weakest connection of the string and by the allowable torque of the pipe body.
6
A jar was placed in the drill collars directly above the top stabiliser, and while drilling it ended up near the neutral point. What is wrong here?
Show the answer
At the neutral point the load on the jar constantly changes from tension to compression, so the jar wears, tires and can fire by itself. Directly above a stabiliser the bending of the pipe is stronger. The jar is placed higher, usually in the HWDP above the drill collars, outside the zone of the neutral point. There must be enough weight of pipe above it for the downward blow. The manufacturer calculates the place for the given assembly.

Updated: 26 October 2026