It is not uncommon for the drillpipe to undergo tensile failure (twistoff) whilst drilling. When this happens, drilling has to stop and the drillstring must be pulled from the borehole. The part of the string below the point of failure will of course be left in the borehole when the upper part of the string is retrieved. The retrieval of the lower part of the string is a very difficult and time consuming operation.

The failure of a drillstring can be due to excessively high stresses and/or corrosion. Drillpipe is exposed to the following stresses:
1. Tension – the weight of the suspended drillstring exposes each joint of drillpipe to several thousand pounds of tensile load. Extra tension may be exerted due to overpull (drag caused by difficult hole conditions e.g. dog legs) when pulling out of hole.
2. Torque – during drilling, rotation is transmitted down the string. Again, poor hole conditions can increase the amount of torque or twisting force on each joint.
3. Cyclic Stress Fatigue – in deviated holes, the wall of the pipe is exposed to compressive and tensile forces at points of bending in the hole. As the string is rotated each joint sustains a cycle of compressive and tensile forces (Figure 3). This can result in fatigue in the wall of the pipe.

cyclic loading

Stresses are also induced by vibration, abrasive friction and bouncing the bit off bottom.

Corrosion of a drillstring in a water based mud is primarily due to dissolved gases, dissolved salts and acids in the wellbore, such as:
1. Oxygen – present in all drilling fluids. It causes rusting and pitting. This may lead to washouts (small eroded hole in the pipe) and twist offs (parting of the drillstring). Oxygen can be removed from drilling fluids using a scavenger, such as sodium sulphate. Even small concentrations of oxygen (< 1 ppm) can be very damaging.
2. Carbon dioxide – can be introduced into the wellbore with the drilling fluid (makeup water, organic drilling fluid additives or bacterial action on additives in the drilling fluid) or from the formation. It forms carbonic acid which corrodes steel.
3. Dissolved Salts – increase the rates of corrosion due to the increased conductivity due to the presence of dissolved salts. Dissolved salts in drilling fluids may come from the makeup water, formation fluid inflow, drilled formations, or drilling fluid additives.
4. Hydrogen sulphide – may be present in the formations being drilled. It causes “hydrogen embrittlement” or “sulphide stress cracking”. Hydrogen is absorbed on to the surface of a steel in the presence of sulphide. If the local concentration of hydrogen is sufficient, cracks can be formed, leading rapidly to a brittle failure.  Hydrogen embrittlement in itself does not cause a failure, but will accelerate failure of the pipe if it is already under stress or notched. Only small amounts of H2S need be present to induce fatigue (< 13 ppm). Special scavengers can be circulated in the mud to remove the H2S (e.g. filming amines).
5. Organic acids – These produce corrosion by lowering the pH, remove protective      films and provide hydrogen to increase hydrogen embrittlement.

Although added chemicals can build up a layer of protection against corrosion, the fatigue stresses easily break this layer down, allowing corrosion to re-occur. It is this interaction of fatigue and corrosion which is difficult to combat.

Institute of Petroleum Engineering, Heriot-Watt University

Drillpipe is the major component of the drillstring It generally constitutes 90-95% of the entire length of the drillstring. Drillpipe is a seamless pipe with threaded connections, known as tooljoints (Figure 2). At one end of the pipe there is the box, which has the female end of the connection. At the other end of each length of drillpipe is the male end of the connection known as the pin. The wall thickness and therefore the outer diameter of the tooljoint must be larger than the wall thickness of the main body of the drillpipe in order to accommodate the threads of the connection. Hence the tool joints are clearly visible in the drillstring.

tool joint

Each length of drillpipe is known as a joint or a single. The standard dimensions for drillpipe are specified by the American Petroleum Institute. Singles are available in three API length “ranges” (see Table 1) with range 2 being the most common. The exact length of each single must be measured on the rigsite since the process used to manufacture the drillpipe means that singles are not of uniform length. Since the only way in which the driller knows the depth of the drillbit is by knowing the length of the drillstring the length of each length of drillpipe (and all other drillstring components) made up into the drillstring must be measured and recorded on a rillpipe tally. The drillpipe is also manufactured in a variety of outside diameters, and weights (Table 2) which assuming a specific gravity for steel of 490 lb/cuft, is a reflection of the wall thickness of the drillpipe. The drillpipe is also manufactured in a variety of material grades (Table 3). The specification for a particular string of drillpipe could therefore appear as:

5” 19.5 lb/ft Grade S Range 2

All of these specifications will influence the burst, collapse, tensile and torsional strength of the drillpipe and this allows the drilling engineer to select the pipe which will meet the specific requirements of the particular drilling operation.


Care must be taken when using the specifications given in Table 2 since although these are these are the normally quoted specifications for drillpipe, the weights and dimensions are ‘nominal’ values and do not reflect the true weight of the drillpipe or the minimum internal diameter of the pipe.

The weight per foot of the pipe is a function of the connection type and grade of the drillpipe and the weight per foot that should be used when calculating the true weight of a string of pipe is given in Table 13.

The weight of the pipe calculated in the manner described above will reflect the weight of the drillpipe when suspended in air (“Weight in air”). When the pipe is suspended in the borehole it will be immersed in drilling fluid of a particular density and will therefore be subjected to a buoyant force. This buoyant force will be directly proportional to the density of the drilling fluid. The weight of drillpipe when suspended in a fluid (“Wet Weight”) can be calculated from the following:

Buoyant Weight (“Wet Weight”) of Drillpipe = Weight of pipe in Air x Buoyancy Factor

The buoyancy factor for a particular density of drilling fluid can be found from Table 15.

Institute of Petroleum Engineering, Heriot-Watt University

Safety requires constant monitoring of the drilling process. If drilling problems are detected early remedial action can be taken quickly, thereby avoiding major problems. The driller must be aware of how drilling parameters are changing (e.g. WOB, RPM, pump rate, pump pressure, gas content of mud etc.). For this reason there are various gauges installed on the driller’s console where he can read them easily.

Another useful aid in monitoring the well is mudlogging. The mudlogger carefully inspects rock cuttings taken from the shale shaker at regular intervals. By calculating lag times the cuttings descriptions can be matched with the depth and hence a log of the formations being drilled can be drawn up . This log is useful to the geologist in correlating this well with others in the vicinity. Mudloggers also monitor the gas present in the mud by using gas chromatography.

To remove the formation fluids now trapped in the annulus a high pressure circulating system is used. A choke manifold with an adjustable choke is used to control flow rates during the circulation. Basically heavier mud must be pumped down the drillpipe to control the formation pressure, and the fluids in the annulus circulated to surface. As the kick starts moving up the hole the choke opening is restricted to hold enough back pressure on the formation to prevent any further influx. The fluids are circulated out via the choke line, through the choke manifold out to a gas/mud separator and a flare stack (Figure 16). Once the heavier mud has reached surface the well should be dead.

bop stack up

Blow out preventors (BOPs) must be installed to cope with any kicks that may occur. BOPs are basically high pressure valves which seal off the top of the well. On land rigs or fixed platforms the BOP stack is located directly beneath the rig floor. On floating rigs the BOP stack is installed on the sea bed. In either case the valves are hydraulically operated from the rig floor.

There are two basic types of BOP.

Annular preventor – designed to seal off the annulus between the drillstring and the side of hole (may also seal off open hole if kick occurs while the pipe is out of the hole). These are made of synthetic rubber which, when expanded, will seal off the cavity (Figure 14).

hydril annular bop

Ram type preventor – designed to seal off the annulus by ramming large rubber-faced blocks of steel together. Different types are available:

blind rams – seal off in open hole
pipe rams – seal off around drillpipe (Figure 15)
shear rams – sever drillpipe (used as last resort)

RAM type bop

Normally the BOP stack will contain both annular and ram type preventors ( Figure 16).

bop stack up

To stop the flow of fluids from the drillpipe, the kelly cock valves can be closed, or an internal BOP (basically a non-return check valve preventing upward flow) can be fitted into the drillstring.

Institute of Petroleum Engineering, Heriot-Watt University

The function of the well control system is to prevent the uncontrolled flow of formation fluids from the wellbore. When the drillbit enters a permeable formation the pressure in the pore space of the formation may be greater than the hydrostatic pressure exerted by the mud colom. If this is so, formation fluids will enter the wellbore and start displacing mud from the hole. Any influx of formation fluids (oil, gas or water) in the borehole is known as a kick.

The well control system is designed to:
1. Detect a kick
2. Close-in the well at surface
3. Remove the formation fluid which has flowed into the well
4. Make the well safe

Failure to do this results in the uncontrolled flow of fluids – known as a blow-out
– which may cause loss of lives and equipment, damage to the environment and the
loss of oil or gas reserves. Primary well control is achieved by ensuring that the
hydrostatic mud pressure is sufficient to overcome formation pressure. Hydrostatic
pressure is calculated from:
P = 0.052 x MW x TVD
P        =     hydrostatic pressure (psi)
MW   =     mud weight (ppg)
TVD =      vertical height of mud column (ft)

Institute of Petroleum Engineering, Heriot-Watt University

Most offshore drilling rigs now have top drive systems installed in the derrick. A top drive system consists of a power swivel, driven by a 1000 hp dc electric motor. This power swivel is connected to the travelling block and both components run along a vertical guide track which extends from below the crown block to within 3 metres of the rig floor. The electric motor delivers over 25000 ft-lbs torque and can operate at 300 rpm. The power swivel is remotely controlled from the driller’s console, and can be set back if necessary to allow conventional operations to be carried out.

A pipe handling unit, which consists of a 500 ton elevator system and a torque wrench, is suspended below the power swivel. These are used to break out connections. A hydraulically actuated valve below the power swivel is used as a kelly cock.

top drive system

A top drive system replaces the functions of the rotary table and allows the drillstring to be rotated from the top, using the power swivel instead of a kelly and rotary table (Figure 13). The power swivel replaces the conventional rotary system, although a conventional rotary table would generally, also be available as a back up.

The advantages of this system are:
•     It enables complete 90′ stands of pipe to be added to the string rather than the conventional 30′ singles. This saves rig time since 2 out of every 3 connections are eliminated. It also makes coring operations more efficient
•     When tripping out of the hole the power swivel can be easily stabbed into the string to allow circulation and string rotation when pulling out of hole, if necessary (e.g. to prevent stuck pipe)
•     When tripping into the hole the power swivel can be connected to allow any bridges to be drilled out without having to pick up the kelly

The procedures for adding a stand, when using a top drive system is as follows:
1.    Suspend the drillstring from slips, as in the conventional system, and stop
2.    Break out the connection at the bottom of the power sub
3.    Unlatch the elevators and raise the block to the top of the derrick
4.    Catch the next stand in the elevators, and stab the power sub into the top of the stand
5.    Make up the top and bottom connections of the stand
6.    Pick up the string, pull slips, start pumps and drill ahead

Top drive systems are now very widely used. The disadvantages of a top drive system are:
1. Increase in topside weight on the rig
2. Electric and hydraulic control lines must be run up inside the derrick

When drilling from a semi-submersible under heaving conditions the drillstring may bottom out during connections when the string is hung off in the slips. This could be overcome by drilling with doubles and a drilling sub which could be broken out like a kelly. This method however would reduce the time-saving advantages of the top drive system.

Institute of Petroleum Engineering, Heriot-Watt University

When drilling ahead the top of the kelly will eventually reach the rotary table (this is known as kelly down). At this point a new joint of pipe must be added to the string in order to drill deeper. The sequence of events when adding a joint of pipe is as follows (Figure 11):

adding drill pipe

1.    Stop the rotary table, pick up the kelly until the connection at the bottom of the kelly saver sub is above the rotary table, and stop pumping.
2.    Set the drill pipe slips in the rotary table to support the weight of the drill string, break the connection between the kelly saver sub and first joint of pipe, and unscrew the kelly.
3.    Swing the kelly over to the next joint of drill pipe which is stored in the mouse hole (an opening through the floor near the rotary table).
4.    Stab the kelly into the new joint, screw it together and use tongs to tighten the connection.
5.    Pick up the kelly and new joint out of the mouse hole and swing the assembly back to the rotary table.
6.    Stab the new joint into the connection above the rotary table and make-up the connection.
7.    Pick up the kelly, pull the slips and run in hole until the kelly bushing engages the rotary table.
8.    Start pumping, run the bit to bottom and rotate and drill ahead.

This procedure must be repeated every 30ft as drilling proceeds.

Institute of Petroleum Engineering, Heriot-Watt University

On some rigs a mechanical device known as an iron roughneck may be used to make-up and break-out connections. This machine runs on rails attached to the rig floor, and is easily set aside when not in use. Its mobility allows it to carry out mousehole connections when the tracks are correctly positioned. The device consists of a spinning wrench and torque wrench, which are both hydraulically operated. Advantages offered by this device include controlled torque, minimal damage to threads (thereby increasing the service life of the drillpipe) and reducing crew fatigue.

When the time comes to pull out of the hole the following procedure is used (Figure 12):

pulling pipe from the hole

1.    Stop the rotary, pick up the kelly until the connection at the bottom of the kelly saver sub is above the rotary table, and stop pumping
2.    Set the drillpipe slips, break out the kelly and set the kelly back in the rat-hole (another hole in the rig floor which stores the kelly and swivel when not in use)
3.    Remove the swivel from the hook (i.e. kelly, kelly bushing, swivel and kelly hose all stored in rathole)
4.    Latch the elevators onto the top connection of the drillpipe, pick up the drillpipe and remove the slips. Pull the top of the drillpipe until the top of the drillpipe is at the top of the derrick and the second connection below the top of the drillpipe is exposed at the rotary table. A stand (3 joints of pipe) is now exposed above the rotary table
5.    Roughnecks use tongs to break out the connection at the rotary table and carefully swings the bottom of the stand over to one side. Stands must be stacked in an orderly fashion.
6.    The Derrickman, on the monkey board, grabs the top of the stand, and sets it back in fingerboard.

When running pipe into the hole it is basically the same procedure in reverse.

Institute of Petroleum Engineering, Heriot-Watt University