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.

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There are many signs that a driller will become aware of when a kick has taken place. The first sign that an kick has taken place could be a sudden increase in the level of mud in the pits. Another sign may be mud flowing out of the well even when the pumps are shut down (i.e. without circulating). Mechanical devices such as pit level indicators or mud flowmeters which trigger off alarms to alert the rig crew that an influx has taken place are placed on all rigs. Regular pit drills are carried out to ensure that the driller and the rig crew can react quickly in the event of a kick.

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)

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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.

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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.

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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.

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The rotary system is used to rotate the drillstring, and therefore the drillbit, on the bottom of the borehole. The rotary system includes all the equipment used to achieve bit rotation (Figure 9).

The swivel is positioned at the top of the drillstring. It has 3 functions:
1. Supports the weight of the drill string
2. Permits the string to rotate
3. Allows mud to be pumped while the string is rotating

The hook of the travelling block is latched into the bail of the swivel and the kelly hose is attached to the gooseneck of the swivel.

The kelly is the first section of pipe below the swivel. It is normally about 40′ long, and has an outer hexagonal cross-section. It must have this hexagonal (or sometimes square) shape to transmit rotation from the rotary table to the drillstring. The kelly has a right hand thread connection on its lower [pin] end, and a left hand thread connection on its upper [box] end. A short, inexpensive piece of pipe called a kelly saver sub is used between the kelly and the first joint of drillpipe. The kelly saver sub prevents excessive wear of the threads of the connection on the kelly, due to continuous make-up and breakout of the kelly whilst drilling. Kelly cocks are valves installed at either end of the kelly to isolate high pressures and prevent backflow from the well if an influx occurs at the bottom of the well. The rotary table is located on the drill floor and can be turned in both clockwise and anti-clockwise directions. It is controlled from the drillers console. This rotating table has a square recess and four post holes. A large cylindrical sleeve, called a master bushing, is used to protect the rotary table.

drilling rig rotary

The torque from the rotary table is transmitted to the kelly through the four pins on a device which runs along the length of the kelly, known as the kelly bushing. The kelly bushing has 4 pins, which fit into the post holes of the rotary table. When power is supplied to the rotary table torque is transmitted from the rotating table to the kelly via the kelly bushing.

Slips are used to suspend pipe in the rotary table when making or breaking a connection. Slips are made up of three tapered, hinged segments, which are wrapped around the top of the drillpipe so that it can be suspended from the rotary table when the top connection of the drillpipe is being screwed or unscrewed. The inside of the slips have a serrated surface, which grips the pipe (Figure 9).

To unscrew (or “break”) a connection, two large wrenches (or tongs) are used. A stand (3 lengths of drillpipe) of pipe is raised up into the derrick until the lowermost drillpipe appears above the rotary table. The roughnecks drop the slips into the gap between the drillpipe and master bushing in the rotary table to wedge and support the rest of the drillstring. The breakout tongs are latched onto the pipe above the connection and the make up tongs below the connection (Figure 10). With the make-up tong held in position, the driller operates the breakout tong and breaks out the connection.

tubing making and breakout

To make a connection the make-up tong is put above, and the breakout tong below the connection. This time the breakout tong is fixed, and the driller pulls on the make-up tong until the connection is tight. Although the tongs are used to break or tighten up a connection to the required torque, other means of screwing the connection together, prior to torquing up, are available:

1. For making up the kelly, the lower tool joint is fixed by a tong while the kelly is rotated by a kelly spinner. The kelly spinner is a machine which is operated by compressed air.
2. A drillpipe spinner (power tongs) may be used to make up or backoff a connection (powered by compressed air).
3. For making up some subs or special tools (e.g. MWD subs) a chain tong is often used.

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The mud pits are usually a series of large steel tanks, all interconnected and fitted with agitators to maintain the solids, used to maintain the density of the drilling fluid, in suspension. Some pits are used for circulating (e.g. suction pit) and others for mixing and storing fresh mud. Most modern rigs have equipment for storing and mixing bulk additives (e.g. barite) as well as chemicals (both granular and liquid). The mixing pumps are generally high volume, low pressure centrifugal pumps.

At least 2 slush pumps are installed on the rig. At shallow depths they are usually connected in parallel to deliver high flow rates. As the well goes deeper the pumps may act in series to provide high pressure and lower flowrates.

duplex and triplex pump

Positive displacement type pumps are used (reciprocating pistons) to deliver the high volumes and high pressures required to circulate mud through the drillstring and up the annulus. There are two types of positive displacement pumps in common use:
(i)     Duplex (2 cylinders) – double acting
(ii)    Triplex (3 cylinders) – single acting

Triplex pumps are generally used in offshore rigs and duplex pumps on land rigs. Duplex pumps (Figure 7) have two cylinders and are double-acting (i.e. pump on the up-stroke and the down-stroke). Triplex pumps (Figure 8) have three cylinders and are single-acting (i.e. pump on the up-stroke only). Triplex pumps have the advantages of being lighter, give smoother discharge and have lower maintenance costs.

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The circulating system is used to circulate drilling fluid down through the drill string and up the annulus, carrying the drilled cuttings from the face of the bit to surface. The main components of the circulating system are shown in Figure 6. The main functions of the drilling fluid will be discussed in a subsequent chapter – Drilling Fluids. However, the two main functions of the drilling fluid are:

1. To clean the hole of cuttings made by the bit
2. To exert a hydrostatic pressure sufficient to prevent formation fluids entering the borehole

Drilling fluid (mud) is usually a mixture of water, clay, weighting material (Barite) and chemicals. The mud is mixed and conditioned in the mud pits and then circulated downhole by large pumps (slush pumps). The mud is pumped through the standpipe, kelly hose, swivel, kelly and down the drillstring. At the bottom of the hole the mud passes through the bit and then up the annulus, carrying cuttings up to surface. On surface the mud is directed from the annulus, through the flowline (or mud return line) and before it re-enters the mudpits the drilled cuttings are removed from the drilling mud by the solids removal equipment. Once the drilled cuttings have been removed from the mud it is re-circulated down the hole. The mud is therefore in a continuous circulating system. The properties of the mud are checked continuously to ensure that the desired properties of the mud are maintained. If the properties of the mud change then chemicals will be added to the mud to bring the properties back to those that are required to fulfil the functions of the fluid. These chemicals will be added whilst circulating through the mud pits or mud with the required properties will be mixed in separate mud pits and slowly mixed in with the circulating mud.

circulating system

When the mud pumps are switched off, the mud will stop flowing through the system and the level of the mud inside the drillstring will equal the level in the annulus. The level in the annulus will be equal to the height of the mud return flowline. If the mud continues to flow from the annulus when the mud pumps are switched off then an influx from the formation is occurring and the well should be closed in with the Blowout preventer stack. If the level of fluid in the well falls below the flowline when the mud pumps are shut down losses are occurring (the mud is flowing into the formations downhole).

The discharge line from the mud pumps is connected to the standpipe – a steel pipe mounted vertically on one leg of the derrick. A flexible rubber hose (kelly hose) connects the top of the standpipe to the swivel via the gooseneck. The swivel will be discussed in the section on rotary system below.

Once the mud has been circulated round the system it will contain suspended drilled cuttings, perhaps some gas and other contaminants. These must be removed before the mud is recycled. The mud passes over a shale shaker, which is basically a vibrating screen. This will remove the larger particles, while allowing the residue (underflow) to pass into settling tanks. The finer material can be removed using other solids removal equipment. If the mud contains gas from the formation it will be passed through a degasser which separates the gas from the liquid mud. Having passed through all the mud processing equipment the mud is returned to the mud tanks for recycling.

There will be at least two pumps on the rig and these will be connected by a mud manifold. When drilling large diameter hole near surface both pumps are connected in parallel to produce high flow rates. When drilling smaller size hole only one pump is usually necessary and the other is used as a back-up. The advantages of using reciprocating positive displacement pumps are that they can be used to:
1. Pump fluids containing high solids content
2. Operate over a wide range of pressures and flow rates
and that they are:
1. Reliable
2. Simple to operate, and easy to maintain

The flowrate and pressure delivered by the pump depends on the size of sleeve (liner) that is placed in the cylinders of the pumps. A liner is basically a replaceable tube which is placed inside the cylinder to decrease the bore.