Rig Types(Part-II)
11.Prime Movers (Engines )
The majority of the rig power is consumed by two operations :
A. Circulation of the drilling fluid.
B. Hoisting and/or Rotating.
These two operations couls occur at the same time. The power where in consumption of the circulation system is essentially constant, the hoisting the prime movers must be capable of handling highly variable loads at rapid acceleration over a wide range of speed and torque.
TYPES OF PRIME MOVERS :
A) Steam Engines:
These were the first engines used but have mainly been replaced by the
following two types.
B) Electric Motors
Both AC and DC motors are in use. DC type is most widely used today because it has a wide torque and speed range and is easily controlled. DC-powered rigs fall into two categories: one uses DC generators and the other, which is gaining popularity, uses AC generators along with Silicon Controlled Rectification (SCR) to produce the required DC power.
C) Internal Combustion Engine
This is the most commonly used engine type due, in part, to the availability of diesel fuel. These engines are in fact inferior to both steam and electric motors. Their torque speed characteristics may be improved by the use of torque converters, but with a loss in efficiency.
12. Transmission
On a multi-engine rig the series of chains and clutches that connect the engines to the drilling equipment is called the transmission.
13. Draw Works
It is the control centre from which the driller operates the rig. It contains the clutches, chains, sprockets, engine throttles and other controls that enable the rig power to be diverted to the part of the operations at hand. It also houses the drum that spools the drilling line during hoisting operations and allows feed-off during drilling. A brake is used by the driller to control the speed of the drum while operations. Draw Works are commonly designated by horse power and depth rating. (Figures 12&13)
Draw works
Figure 12
Brake
Figure 13
Drilling Line 14.
This line affords a means of handling the loads suspended from the hook during all drilling operations. The wire line most commonly used is the 6 ´ 19, Seal construction, fibre core, plow steel cable. Where dictated by high load requirements, premium grade lines with an independent wire rope centre are used. The drilling line runs from the main drum up to the crown blocks and down to the travelling blocks. The line is slung several times around the blocks. From the crown blocks the line goes down to the drill floor where it is attached to the anchor. This section of the line is known as the “dead line” since it is stationary. (Figure 09)
Rotary Table 15.
This performs two functions:
1. It transmits the rotation to the drill string by turning the kelly joint.
2. It suspends the drill string weight during connections and trips.
Rotary table is usually driven by a chain from the drawworks on mechanical rigs and by its own motor on electrically driven rigs. Some are capable of speed of up to 400 RPM. A rotary table is defined by the size of its central opening; the largest being 37½ inches. This opening is fitted with a master bushing which is split into two parts. (Figure 14)
16. Kelly
This is the topmost joint in the drill string and is 40-45 feet in length. It is commonly square or hexagonal. The kelly passes through the rotary table and transmits the table rotation to the drill string via the kelly bushing. (Figure 15)
17. Kelly Bushing
This engages with master bushing either by having a square lower section or by four pins fitted into holes around the central opening. This transmits the rotations to the kelly. (Figure 15)
18. Master Bushings
Through the master bushings, the rotary table transmits rotary motion to the kelly drive bushings and the kelly. They are also the connecting link between the rotary table and the slips which support the pipe during trips.
Figure 15
18. Swivel
The swivel supports the drill string and allows rotation at the same time. It also allows the passage of drilling fluid from the rotary hose into the drill string. The swivel performs a very tough job supporting a load that can be measured in hundreds of tons. This string could also be rotating at 200 or more revolutions per minute. Abrasive drilling fluids are often pumped through it at the rate of perhaps a thousand gallons a minute at a pressures that can exceed 3,000 psi. The swivel is hung from the hook by the swivel bail and is connected to the rotary hose by the goose neck. Inside the housing just below the goose neck is the wash pipe. This is made of the strongest material known to the industry. The wash pipe is stationary and is joined to the rotating swivel stem. Special packing to seal this rotating joint is contained in the stuffing box. The bearings run in an oil bath. (Figure 16)
19. Top drive
This is a specially designed electric or hydraulic motor installed on the drill lines that replaced Kelly and kelly bushing and it rotates the string as well. Using the top drive enables drilling to be carried out stand by stand instead of joint by joint. This reduces the number of connections to be made while drilling. (Figure 17)
Unlike the kelly, Top drive is not removed
during trips.
Figure 17
20. Heave (Motion) Compensation
Heave Compansators are used on semisbus and float ships rigs. The two basic types of motion compensators are:
1st.Drill string compensator
2nd.Riser and guideline tensioner.
1st.Drill string Compensator:
The drill string motion Compensator system is designed to nullify the effects of rig heave on the drill string or other hook-supported equipment.(Figure 18)
Mounted between the hook and travelling block, the compensator is connected to deck mounted air pressure vessels via a hose loop and standpipe and is controlled and monitored from the driller’s control console. While drilling, the drill string compensator controls the weight on the bit. The driller lowers the travelling block to account for drill-off and to maintain the compensator cylinder within its stroke capacity while the drill string compensator automatically maintains the selected bit weight. As the rig heaves upward, the compensator cylinders are retracted and the hook moves downward to maintain the selected loads.
Actually, the hook remains fixed relative to the seabed; the rig and compensator move, producing relative motion between the hook and rig. The motion of both the kelly and drill string is relative to the rotary table.
2nd.Riser and Guideline Tensioners
The marine riser is essentially a conduit, but its a main purpose is to maintain contact with and give access to the borehole when drilling.(Figure 18)
Riser tensioners provide tension to the marine riser pipe below the telescopic joint by a system of wires joined via sheaves to a series of pneumatic cylinders.
Its purpose is to maintain the riser in tension at all times regardless of the heaving of the rig. It is common practice to install four or six tensioners, each with a load rating of around 60,000 lb. Compensation for vertical movement several times the length of the stroke of the pistons is possible, due to multiple cable turns around the pistons. Guideline tensioners operate on the same principle as the riser tensioners. Their purpose is to maintain the correct tension in the guidelines between the rig and the guide base (which sits on the seafloor), regardless of the heaving of the rig. The guideline tensioner is designed to deal with tensions of less than 10,000 lb; therefor, wires, cylinders and other components are smaller than those used in the riser tensioner system.
21. Drill String
This term includes all the components used to drill below the kelly or top drive; and it can include the following components:-
a) Drill Pipe & Tool Joints
The drill pipe furnishes the necessary length for the drill string and serves as a conduit for the drilling fluid. The drill pipe lengths (joints ) are hollow seamless tubes where the tool joints ( connections ) are separate components and are attached to the pipe at both ends to complete the manufacture of one joint. Tool joints are of thicker outer diameter to withstand the torque applied by tongs to tighten the connection. The drill pipe joints are normally made in approximately 30 ft/9.5m lengths.
b) Heavy weight drill pipe (HWDP)
This is the same as a drill pipe but with a smaller inner diameter and longer tool joints. Because of its wall thickness, its pound-per-foot weight is greater than an ordinary drill pipe. Heavy weight drill pipe is inserted as a section between the drill pipe section up and the lower drill collars section to serve as a transition section between the two of them, this gives the drill string the required elasticity.
c) Thread Protectors
These are either made of metal or plastic and fit on both ends of a threaded pipe (box and pin ends) to protect the threads from corrosion and mechanical damage during storage or transportation. Obviously, they must be removed before use.
d) Drill Collars
These are heavy walled, spiral and large outer diameter steel tubes. Their function is to supply the desired weight on bit and to allow the lighter drill pipe to remain in tension. The spiral grooves are to minimize the surface of contact between hole and pipe reducing the risk of getting stuck. This also helps the drilling fluid to flow up the annulus in case of tight hole.
e) Rotary Bits
These may be classified into three general types :
1. Drag Bits:- these have no moving parts but drill by the shovelling action of their blade on the formation.
2. Roller Bits:- first designed by Howard R. Hughes in 1909. These may have originated from one to numerous individual rotating cones.
Three cone bits (Tri-Cone) are the most widely used in the oil field. The length and spacing of the teeth depend on the type of formation that the bit is designed to drill. Hard formation bits may have tungsten carbide “inserts” instead of teeth.
Various types of bearings are in use. Specially designed jet nozzles are set on the bit to direct the drilling fluid to produce a high velocity fluid stress on the bottom of the hole. So called conventional bits were forerunners of roller bits but were open-ended; i.e. without jets.
3. Diamond Bits:- These are designed to drill by the scraping action of diamonds set in a steel matrix. This type of bits is normally used in hard formations where long bit life and the subsequent reduction in trip time are desirable. (Fig 19)
Figure 19
f) Stabilizers
These are run between the drill collars and are of a blade type construction. Drilling fluid can pass freely between the blades while the outer edge of the blades contacts the wall of the hole and holds the drill collars firmly centered in the hole. They do exactly as their name implies, they provide stability to the bit and collars. This is important as it improves bit life, in addition to keeping the direction of the hole under control.
(Figure 20)
Figure 20
g) Reamers
These usually have the same diameter as the bit and are run a little distance above it.. As the bit wears out it tends to decrease in diameter and consequently start drilling a smaller hole. The reamers’ function is to cut the hole out to full size behind the bit.
h) Under-reamers
Used for drilling or opening out a hole below a restriction such as imposed by the blow-out preventer assembly. They are run above a conventional roller bit having their cones on collapsible arms, enabling it to pass through a narrow opening. When required, the arms can be opened, usually by the drilling fluid pressure, and a larger hole is thus drilled.
(Figure21)
Figure 21
i) Hole Openers
These are run above a conventional roller bit and are used for drilling large diameter holes. They have replaceable cutters and serve the same function as an underreamer except they are not collapsible and can only be used when there is no restriction smaller than the hole size they drill. (Figure 22)
Figure 22
j) Jars
Jars are fitted into the drill string and are used in the event of the drill string becoming stuck. They provide upward or downward jarring blows that help freeing the string. Jars use different mechanisms including hydraulic and mechanical.
k) Monel
This is a non-magnetic drill collar used to contain the magnetic survey tools, the monel is made of special non magnetic alloy that does not affect the
reading of the survey tools that determine the hole deviation depending on the deflection from the magnetic deflection of the earth sphere.
l) Subs
A sub refers to any short Length of pipe, collar or casing that is made to perform a specific job. The most common types of subs you can find on rigsite are the following:
a. Crossover Sub:
A crossover sub is designed with different threaded ends for changes between different sizes and types of drill pipe or collars.
b. Bit Sub:
This sub is used to save the thread of the bit from excessive break out such as to change nozzles or BHA, So the break out of the bit is usually done at the connection between the sub and the upper collar pipe. The sub is ended with a box on both ends so that pipe and collars are always run pin down.
c. Shock sub:
This is run behind the bit with a steel spring or rubber packing to absorb the impact of the bit bouncing on hard formations and prevent damaging the rest of the drill string.
d. Bumper Sub:
This is a free telescopic sub with 6-8 ft closure. Its purpose is to absorb the effects of heave on a floating rig. and not transfer it to the bit, these are now largely replaced by the "motion compensator" which is a hydraulic device attached to the travelling block so that the entire drill string remains stationary as the rig heaves.
e. Bent sub:
This is a non-straight sub designated with different bending angles, it is fitted in the deviating bottom hole assembly above the mud motor to drill deviated holes. The angle of bending is selected according to the inclination building rate and the length of the interval to be drilled with this sub.
f. Float valve:
This is a small mechanical one way valve inserted inside the bit sub, the valve allows mud to flow in one direction from the string to the annulus, This valve is usually used while drilling the surface hole sections, the penetration rate is usually fast causing the annulus becomes loaded with cuttings, a differential pressure takes place between the annulus and the string, once pumps are shut-off, the valve is mechanically closed preventing any back flow to occur .
22. Casing head
Often called a casing hanger and is of multi purpose :-
· To provide a support point to suspend casing strings prior to being cemented into position.
· Used to provide a coupling between the various casing strings and the
BOP stack.
· Having locked the casing with cement, the hanger then provides a seal between other casing strings and the annulus. A standard casing head is fixed to the first casing string and thereafter provides for up to three subsequent casing strings.
23. MUD PUMPS (Slush Pumps)
Two or three pumps are usually found on rig site, their function is to circulate the drilling fluid at the required pressure and volume. The type of pump used is a reciprocating piston pump. Pump design varies but the basic features are common Pumps may be classified on four features :-
A. Number of Cylinders:
Normally pumps have either two or three cylinders and are known as Duplex and Triplex respectively.
B. Pumping Action:
1. Double-acting Pumps - This means that both sides of the piston are used for pumping i.e. the piston is filling one side of the cylinder while fluid is being discharged on the other side. Usually Duplex pumps are double-acting.
This type of pump can be easily recognized by valve systems at both ends of the cylinder.
2. Single-acting Pumps - On these only one side of the piston is used for pumping, that is, the cylinder is then filling or discharging. Triplex pumps are usually single-acting recognizable by having a valve system at one end only.
C. Piston Stroke:-
This obviously is related to the output of the pump. It is fixed and can not be changed. The longer the stroke of the piston, the greater the pump output.
D. Cylinder diameter (Liner size): -
Each cylinder is equipped with a removable sleeve or liner. A pump, although of fixed stroke length, has a whole range interchangeable liners of different diameter available, allowing for different pressure/volume ranges with changing hole conditions. aurally, the smaller the liner diameter, the smaller the volume pumped on each stroke but as the liner walls are thicker, more pressure is available. There are usually two to three pumps on a drilling rig. They are always
of the positive displacement type. In other words plunger pumps rather like a bicycle pump.
PUMP TYPES:
*duplex, double-acting or *triplex, single-acting
A duplex pump has two cylinders. Each cylinder has two suction and two discharge valves. As the piston moves through the cylinder it is discharging mud in front at the same time as mud is filling the cylinder behind.
A triplex pump has three cylinders with each cylinder having only one suction and one discharge valve. The cylinder is filled as the piston moves back and is discharged as the piston moves forward. For one complete cycle of each piston a triplex pump discharges one cylinder full of mud. In a duplex pump however, because it is double acting, two cylinder volumes are discharged for every cycle of each piston. (Figure 23) shows the pump action for each type. Pumps are commonly rated on the horse power they transit. Pistons are sometimes known as swabs. The discharge of the pump is fitted with a pulsation dampener and connected to the stand pipe and rotary hose (kelly hose), through the mud line via the mud line manifold or standpipe manifold.
Figure 23
24. Kelly Line-Rotary Hose (Mud Hose)
This connects the standpipe to the goose neck and is flexible but strong enough to hold high pressures. These hoses may be pressure rated up to 12,000 psi.
25. Shale Shaker
This is a vibrating screen used to separate the drilled solids from the drilling fluid. The screen is mounted on a spring or rubber supported chassis, which is vibrated by means of an eccentric rotating shaft. Screens of different mesh size are available. Mesh sizes being measured by the number of openings per square inch. The screens are sometimes mounted as a pair, using screens of different sizes. In double deck Shaker; mud returning from the well core comes down the flowline and into a surge tank; sometimes known as the possum belly or shaker header box; this allows a smooth flow of mud onto the screens. The shakers are usually situated over a sand trap, which is a narrow pit with sloping sides terminating in a valve, it is used to trap fine sand that may pass through the shaker screens, this pit must be dumped out periodically.
26. Desanders and Desilters
These devices remove particles from mud, which were not removed by the
shakers or the sand trap. This separation is accomplished by utilizing centrifugal force. The equipment is essentially a series of cones mounted on a manifold, mud is pumped into the manifold and enters the cone. The mud swirls round the inside of each cone, this rotating action causes the lighter fluids to come to one centre and rise out of a hole in the top, whereas the heavier soils go to the outside of the cone and sink down it and out of an opening in the bottom. These units are operated at low pressure (30-40 psi) but can handle high volumes, typically 250 gallons per minute per cone. The difference between desanders and desilters is mainly in the size of the cones.The smaller the cones the smaller the particles that it separates.
27. Degassers
These separate the gas that may be trapped in the drilling fluid. The principle of operation is essentially the same even though the design varies. The mud is either passed over a series of baffles or caused to swirl round in a bowl; both actions cause the mud to break up resulting in the greatest surface area possible for the gas to break out. In the swirling action the mud is spread very thinly over a surface. In addition to the increased surface area, some degassers apply a slight vacuum, this aids in the separation as the gas or air bubbles expand and break out of the fluid more easily.
28. Mud Pits
After drilling fluid has been processed by the solids control equipment; it passes into the return pit,that is connected sometimes by other pits to the suction pit. The suction pit is directly connected to the pumps allowing the mud to circulate through this system. Between the return and suction pits the mud is constantly agitated by electric paddle mixers and mud guns. Chemicals are added to the mud via special hoppers. The suction pit may also contain a small (typically 50 bbls) slug pit used to mix special heavy mud that may be needed when tripping or to mix other small specific volumes. The pits in use are referred to as “Active Pits”. All pits are equipped with valves so that their contents may be dumped or transferred easily in-between them.
29. BOP’s (Blow-Out Preventers)
The main function of the blow-out preventers is to furnish a means of closingoff the annular space between the drill pipe and casing. Most preventers are either hydraulically or pneumatically controled with manual operation available as a safety precaution. Blow-out preventers are rated according to their working pressure and their inner diameter. There are many design variations of BOP’s; however, they fall essentially into two categories :
A) Annular Preventers:- This type seal by closing a circular packing element around the drill pipe; this element is made of rubber one most types will also seal the annulus with virtually anything or nothing in the bore. (Figure 24)
Annular Type BOP
Figure 24
B) Ram Preventers:- These derive their name from the hydraulic cylinders and ram shafts that move the two sealing ram blocks. (Figure 25) Unlike annular preventers, this type will only seal around a specific pipe size; to accommodate different pipe sizes the ram elements are changeable. A set of rams and annual preventers, when assembled, is known as the Blow-Out Preventer Stack; commonly referred to as the stack or BOP’s
Ram Type BOP
Figure 25
Example of BOP Stack Arrangement
Figure 26
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