Second Class
Part B1
Prime Movers
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Power Engineering
Second Class (B1):
Prime Movers
Table of Contents
Chapter
Page
1. Steam Turbine Theory and Construction
2. Steam Turbine Auxiliaries and Control
3. Steam Turbine Operation and Maintenance
4. Steam Condensers
5. Internal Combustion Engines - Components and Auxiliaries
6. Internal Combustion Engines - Operation and Maintenance
7. Gas Turbine Design and Auxiliaries
8. Gas Turbine Operation and Control
9. Lubrication
10. Piping
11. Mechanical Drawing
1
75
131
161
217
261
303
377
425
481
533
End of Chapter Questions and Solutions
567
Steam Turbine Theory and
Construction
Learning Outcome
When you complete this learning material, you will be able to:
Explain the design and components of a steam turbine and calculate nozzle and steam
velocities.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Explain selection criteria for a turbine application.
2. Describe the design and components of steam turbine casings and casing drains.
3. Describe the design and components of steam turbine rotors, blading, and
diaphragms.
4. Describe shaft seal designs, including stuffing boxes, carbon rings, labyrinth and
water seals.
5. Describe the design and components of steam turbine bearings.
6. Describe the ways in which steam turbines are designed to counteract thrust.
7. Describe the purpose and design of expansion and anchoring components.
8. Explain the principles of steam turbine nozzle design.
9. Explain a steam turbine steam velocity diagram.
10. Calculate the steam velocity and angle of entry for impulse and reaction turbine
blading.
11. Calculate the work done on steam turbine blades and the resulting power
developed.
12. Calculate steam turbine Rankine cycle thermal efficiency.
Page 1
Page 2
Objective 1
Explain selection criteria for a turbine application.
TURBINE TYPES AND APPLICATIONS
Steam turbines are used in various plants and cycles to convert the heat energy in the
steam generated in fired boilers and heat recovery steam generators into mechanical
work. The selection of a specific type of steam turbine depends upon factors including
the steam conditions provided by the steam generator, the unit rating, the desired
flexibility of the system, and compatibility with the heat balance of the plant. Turbines
are available in small sizes for driving pumps and fans to multi-casing units for power
generation. Power generation turbines are available in sizes from a few megawatts to
over 1000 megawatts.
An almost limitless series of arrangements are available in adapting the turbine to power
plant requirements. This is a distinct advantage when we consider the many varied heat
balance needs of modern industry. There are two general classes into which all turbines
fall. Turbines exhausting at pressures below atmospheric pressure are condensing
turbines and those exhausting at or above atmospheric pressure are noncondensing
turbines. Condensing turbines are used where there is no need for process steam. A
condenser, cooled by either air or water, is required to condense the exhaust steam.
Noncondensing turbines are used when the exhaust steam is utilized for process heating.
In some condensing turbines not all of the steam passes through to the exhaust. Part of
the steam is extracted, or bled off, at one or more points. After doing some work by
expansion, the extracted steam is used to heat the feedwater. This cycle, which uses bled
steam to heat feedwater, is called a regenerative cycle and the turbine is called a
bleeder turbine.
Similarly, steam may be drawn off at one or more points at different pressures for
process steam. This requires automatic control of the steam quantity supplied to the
lower pressure section of the turbine. This arrangement is termed automatic extraction
in contrast to bleeder turbines, where the pressure at the bleed points varies with the
steam flow through the turbine. Bleed points range in number from one to eight, but
extraction generally requires only one or two pressure levels.
Page 3
Steam Turbines for Power Generation
There are as many types of steam turbines as there are types of power plant. They are
used for small gas fired cogeneration plants, for subcritical and supercritical fossil fuel
fired plants, and for nuclear power plants. Industrial plants, such as chemical plants,
refineries, and pulp mills, often use steam turbines to generate power for the plant site.
Fig. 1 illustrates the casing arrangements offered by a Japanese turbine manufacturer.
The 2 and 3 casing designs are for fossil fuel fired plants up to 1000 megawatts (MW).
The 4 casing arrangement is often found in fossil fuel fired plants of 600 MW and
above. The 4 casing (cross compound) arrangement is common in nuclear power plants
from 800 MW to over 1300 MW.
Figure 1
Turbine Casings and MW Ratings
The 2-cylinder reheat turbine in Fig. 2 has the HP (high pressure) and IP (intermediate
pressure) rotors in the first case. The LP (low pressure) case contains a double-flow
rotor. In a double-flow rotor, the steam enters at the centre of the rotor with half of the
steam flowing toward the front of the machine and half towards the rear. It exhausts
downward into the surface condenser.
Page 4
Figure 2
2-Cylinder Reheat Turbine
Another 2 case machine is shown in Fig. 3 with the exhaust steam ducted axially into a
surface condenser. The surface condenser is on the same level, or floor, as the turbine.
This arrangement uses less plant space than designs with the turbine above the
condenser.
Figure 3
Two-Cylinder Reheat Steam Turbine
The steam flow through these units is too high to build in a tandem compound
arrangement, such as those in Fig. 2 and Fig. 3. A tandem compound machine has all of
the turbine rotors and load connected axially into a single shaft. Cross compounding
features two separate and unconnected shafts, with the steam flowing from one machine
to another. Nuclear steam generators operate at lower pressures and lower temperatures
than similar sized fossil-fired units.
The 4 casing cross compound design used for nuclear power plants is shown in Fig. 4.
The HP and IP sections drive one generator, and the LP cases drive the second
generator.
Page 5
Figure 4
Cross Compound Steam Turbine
Industrial Applications
Steam turbines for industrial applications range in size from fan or pump drivers to units
of 50 MW. They often drive large compressors. Fig. 5 shows a General Electric (GE)
mechanical drive turbine. These turbines are built in ratings from 7.5 to 900 kW,
running at speeds from 1000 to 6500 rev/min. They are used to drive pumps,
compressors, fans, blowers, and similar equipment. The turbine illustrated in Fig. 5 is a
single-stage, velocity compounded, impulse type. Two rows of moving blades are
arranged with a row of stationary blades between them.
Figure 5
Single-Stage Mechanical Drive Turbine
(Courtesy of General Electric)
Page 6
The turbine shown in Fig. 6 is an Allis-Chalmers with two extraction points. Two
impulse wheels are used, one before the HP reaction staging and one before the LP
reaction stages. This is a typical extraction type of turbine. This machine is rated at 4000
kW at 3600 rev/min.
Figure 6
Automatic Extraction or Mixed Pressure Type Turbine
Fig. 7 shows a GE industrial turbine with the top casing removed. These turbines come
in many sizes.
Figure 7
GE Industrial Turbine
Page 7
Table 1 shows the various sizes available from GE. The most common sizes are from 15
to 50 MW. Smaller units down to 1 MW are available, as are units up to 100 MW.
Table 1
GE Small Turbines
A packaged axial flow turbine generator set is shown in Fig. 8. This is a compact design
suitable for small power plants or cogeneration applications. It comes complete with a
generator and surface condenser.
Figure 8
Packaged Axial Exhaust Turbine
Page 8
Objective 2
Describe the design and components of steam turbine
casings and casing drains.
TURBINE CASINGS
Turbine casings are designed to handle high pressures and temperatures while:
• Resisting distortion.
• Maintaining constant clearances between the blading, casing, bearings, and
sealing glands.
• Maintaining correct alignment of the turbine rotating assembly.
Split Casings
Horizontal split casings or cylinders are used to facilitate assembly and inspection. This
is not ideal as the heavy flanges of the joints are slow to follow the temperature changes
of the cylinder walls. Casings are made of thick material in order to withstand the high
pressures and temperatures. In practice, the thickness of walls and flanges decreases
from the inlet to the exhaust end.
Large casings for low-pressure turbines are constructed of welded plates. Smaller lowpressure casings are cast iron, which may be used for temperatures up to 230°C. Casings
for intermediate pressures are made of cast carbon steel able to withstand temperatures
up to 425°C. High-pressure, high-temperature casings used for temperatures above
550°C are made of cast alloy steels like 3% chromium and 1% molybdenum. Higher
temperatures require higher alloy metals (higher chromium content). The alloys must
also have a high creep resistance to operate at these temperatures.
Casings are made steam tight without the use of gaskets by machining their flange
surfaces to a very exact and smooth surface and then joining those surfaces accurately
and securely together. Dowel pins are often used to secure exact alignment of the flange
joint. A boring mill machines the inside of the casing. Grooves are machined for the
diaphragms (for impulse turbines) or for stationary blades (reaction turbines). The
casing is also bored for shaft seals and bearings.
Page 9
For high-pressure casings, the flanges must be very thick. Consequently, they will heat
up much more slowly than the casing walls. Some type of auxiliary flange heating is
often used for quicker and more uniform heating of the flanges and casing. Steam flows
through machined channels between the flanges or through holes drilled axially through
the upper and lower flanges.
Fig. 9 shows the lower section of a horizontally split casing. The centreline support
allows the casing to expand and contract evenly while maintaining alignment.
Figure 9
Turbine Lower Casing and Support
Double Casings
Double casings are used for very high steam pressure applications. The highest pressure
is applied to the inner casing, which is open at the exhaust end. The turbine inner casing
exhausts to the outer casing. The pressure is divided between the casings, and more
importantly, so is the temperature. The thermal stresses on casings and flanges are
greatly reduced. Fig.10 illustrates a double-shell HP turbine casing.
Figure 10
Double-Shell HP Casing
Page 10
Cylinder Casing Drains
It is important that the steam moving through the turbine be as dry (absence of water) as
possible. Water in the steam causes a loss in turbine efficiency and corrodes the turbine
blading it comes in contact with. Turbines are designed to have slightly wet steam
exiting the low-pressure blading. It is generally accepted that the maximum percentage
of wetness of the steam leaving the exhaust end of a turbine should be 14%.
The shape of the cylinder casing allows this water to drain to the condenser. Special
draining grooves are arranged in the cylinder casing to help remove water more
effectively. An example of this type of draining arrangement is illustrated in Fig.11.
Figure 11
Cylinder Casing Drainage
Drains must be located, and be of sufficient number, to avoid buildup of condensate at
any point in the turbine. Liquid water is likely to be re-entrained into the steam flow
causing erosion of the turbine blades and diaphragms. Standing pools of condensate will
also cause severe corrosion of the turbine casing. Turbines are designed to avoid the
formation of condensate before the steam reaches the exhaust end. Condensate that
forms prematurely (called early condensate) may be corrosive (if it has a low pH) and
should be drained as quickly as it forms.
Page 11
Page 12
Objective 3
Describe the design and components of steam turbine
rotors, blading, and diaphragms.
TURBINE ROTORS
Turbine rotors (Fig. 12) are categorized in three ways according to construction:
• Solid Forged Rotor
• Disc Rotor
• Welded Rotor
Figure 12
Turbine Rotors
Solid Forged Rotors
Rotors of this type have wheels and shaft machined from one solid forging, the whole
rotor being one piece of metal. This is a rigid construction. Solid rotors eliminate the
possibility of loose wheels, which can occur with shrunk-on type rotors. Grooves are
machined in the wheel rims of solid rotors to attach the blading.
Solid forged rotors are used in the HP and IP cylinders for designs employing impulse
type blading and for IP cylinders when reaction type blading is used. Fig. 13 shows a
rotor of the solid forged type.
Page 13
The choice of a solid rotor is dependent upon the turbine startup procedure. Stresses in
the rotor material are caused by the temperature differences between the surface areas
and the centre parts of the rotor. The rotor temperature becomes more uniform as the
rotor is heated by the steam. The turbine is warmed up slowly, allowing for uniform
heating across all areas of the turbine. This ensures balanced thermal expansion between
the rotor assembly and the casing. The stress levels in a rotor are affected by the steam
temperature, the diameter of the rotor, and the time taken to reach full-load operating
conditions.
Figure 13
Solid Forged Rotor
Disc Rotors
The disc rotor is constructed of a number of separately forged discs or wheels. The hubs
of these wheels are shrunk or keyed onto the central shaft. The outer rims of the wheels
have grooves machined to allow for attaching the blades. Suitable clearances are left
between the hubs to allow for expansion axially along the line of the shaft. Disc rotors
are also referred to as built-up rotors.
Under operating conditions, the temperature of the wheels rises faster than that of the
shaft. This might tend to make the wheel hubs become loose. To avoid any such danger,
care is taken during construction of the rotor to ensure the wheels are shrunk on tight
and correctly stressed. Fig. 14 illustrates a disc type of rotor which is the type used in
the LP cylinder of most designs of large turbines.
Page 14
Figure 14
Disc Type Rotor
Welded Rotors
Welded rotors are built up from a number of discs and two shaft ends. They are joined
together by welding at the circumferences. Because there are no central holes in the
discs, the structure is very strong. Small holes are drilled in the discs to allow steam to
enter inside the rotor body and supply uniform heat to the rotor. Grooves are machined
in the discs to attach the blades.
A fairly light and rigid drum rotor may be manufactured from discs welded together to
form a drum, as shown in Fig. 15. Before welding, the rotor is heated by induction
heating. Welding is performed with automatic welding machines such as the argon arc
process, where the arc burns in an argon atmosphere.
Page 15
Figure 15
Welded Drum Turbine Rotor
BLADING
The design of turbine blading affects the reliability and efficiency of the turbine.
Depending upon the design of the turbine, there is either:
• An impulse force impulse type blading
• A combination of impulse and reaction forces reaction type blading acting on
the turbine blades due to the steam flow
The longer the blade the greater the bending force at the root, or fixing point, of the
blade. There is also a centrifugal force, due to the speed at which the blade is rotating,
trying to throw the blade outwards.
These two forces—the bending force and the throwing-out force—are at maximum in
the largest blade wheel at the LP exhaust end of the turbine. Thus, the stresses which
these forces impose limit the size of the blades and the diameter of the last wheel. This
limitation is one of the reasons why turbines are designed with double flow in the LP
cylinder. In the double flow design, steam enters at the centre of the rotor with half of
the steam flowing to the front of the machine and half flowing toward the rear of the
machine. This design can handle double the flow of steam compared to a single flow
with the same diameter of blading. The rotor in Fig. 2 is a double flow rotor.
The mechanical stresses just described are not a great problem in the short HP moving
blading. This blading is subject to higher temperatures, which is a greater problem from
the design aspect.
Reaction Blading
In reaction blading, pressure drops occur across both fixed and moving blades. In the HP
cylinder, a very effective seal between fixed and moving blading is essential to prevent
steam leakage. Steam that leaks or bypasses the blades produces no work and reduces
the efficiency of the turbine. Fixed blades fit in grooves in the cylinder casing and
moving blades fit in grooves machined in the rotor.
Page 16
Blading subject to high temperatures in HP cylinders are made with root section and
shrouding in one piece. The shrouds have a projecting portion thinning down to form a
single knife-edge on the moving blades. On the fixed blades, a second strip is tapered to
form a double knife-edge. The blade packets fit in the grooves to form a complete row
of fixed or moving blades. The blade packets are serrated along the roots and secured in
the grooves, which are also serrated, by means of a side-locking strip as shown in Fig.
16.
An illustration of reaction blading is shown in Fig. 16. The leakage of steam is
controlled by the axial clearance, that is, the clearance along the line of the shaft. This
type of sealing is known as end tightening. Additional sealing is provided by a radial fin
machined into the shroud and adjusted to a fine clearance between cylinder bore or rotor
body.
Figure 16
HP Reaction Type Blading showing End Tightening
Blade Shrouding
The shrouding supplies support strength to the blades in addition to preventing steam
leakage, as shown in Fig. 17. In lower pressure stages of the turbine where support is
more important than sealing, a lacing wire is used, as in Fig. 18. Turbine blades must be
made of materials which will withstand high temperatures in the inlet stages, and low
temperatures but high rotational stresses in the exhaust stages. The most common
material in use today is stainless steel having low carbon content, about 0.1%, and a
chromium content of about 12%. This material is strong, resistant to corrosion and
erosion, and can be forged, machined and welded.
Page 17
Figure 17
Shrouded Built-up Reaction Blading
Figure 18
Unshrouded Built-up Reaction Blading
Page 18
Impulse Blading
The HP moving blades for impulse turbines are machined from solid bar, and the roots
and spacers are formed with the blade. This is illustrated in Fig. 19. Tangs are left at the
tips of the blades, so that when fixed in position in the wheel, the shrouding can be
attached. The shrouding is made up from sections of metal strip punched with holes to
correspond with the tangs. The strip is passed over the tangs which secure the strip in
position. The shrouding fits in separate sections to allow for expansion.
There is no pressure drop across the moving blades of an impulse turbine, and therefore,
the sealing arrangements are not as important as in the reaction type. The shrouding on
the impulse blading helps to guide the steam through the moving blades, allowing larger
radial clearance and strengthening the assembly.
Due to the steam pressure difference on each side of the diaphragm, it is necessary to
provide seals at the hole, where the shaft passes through the diaphragm, to prevent steam
leakage along the shaft.
Figure 19
Stages in the manufacture of HP Impulse Type Moving Blades
3-D Blading
A significant improvement in steam turbine efficiency was brought about by the use of
computer modelling of steam flows through turbine blading. The shape of the blading
changed after 3-D (3-dimensional) modelling. The blading profile, or shape, is not
symmetrical; it changed from parallel sided to twisted or bowed. Fig. 20 compares
conventional turbine blading and 3-D modelled blading. The resulting steam flow is
more evenly distributed across the blading with 3-D modelled blading. Fewer vortices
with a less turbulent flow are other advantages of 3-D modelled blading. The twisted
shape of a low pressure case blade (3-D modelled) is shown in Fig. 21.
Page 19
Figure 20
Conventional and 3-D Blading
Figure 21
Low Pressure Turbine Blade
Diaphragms
Fixed blading of an impulse turbine consists of nozzles mounted in diaphragms. The
diaphragm is made in two halves; one half is attached to the upper half of the cylinder
casing, and the other half is attached to the lower half of the cylinder casing. The
diaphragms are positioned in the cylinder casings by means of keys that allow for some
expansion. Special carrier rings support the diaphragms in HP cylinders.
Page 20
At the HP end of the turbine, the diaphragms are the built-up type. Nozzles are
machined separately from a solid bar and attached by grooves and rivets to the
diaphragm plate. In some cases, the nozzles are welded together and to the plate. Fig. 22
illustrates attachment of nozzles to the diaphragm plates.
Figure 22
Built-up Diaphragm
Page 21
Page 22
Objective 4
Describe shaft seal designs, including stuffing boxes,
carbon rings, labyrinth and water seals.
SHAFT SEALING
Due to the design and operating characteristics of steam turbines, there are a number of
pressure differential points across stages and sections of the turbine. Leakage of steam
across these points is a waste of energy and reduces the efficiency of the turbine.
Leakage is kept to a minimum at all times. At the high-pressure end of the turbine,
correct shaft sealing keeps the steam from leaking past the shaft.
At the low-pressure end of noncondensing turbines, the potential for steam loss to the
atmosphere is greatly reduced due to the smaller pressure difference across the casing to
the atmosphere. In condensing units, the final stages of the turbine operate below
atmospheric pressure tending to draw air into these stages. Air infiltration must be
minimized and/or eliminated as the air increases the pressure in the condenser. The
increased backpressure decreases the efficiency of the turbine and increases the cooling
load on the condenser.
Four methods of sealing rotating parts are:
• Stuffing Box
• Carbon Rings
• Labyrinth Seals
• Water Seals
Stuffing Box
Stuffing boxes are often used in centrifugal pumps. They are used only rarely on the
smallest of turbines.
Carbon Rings
An effective seal is produced by a series of spring-backed carbon rings. Fig. 23 shows
four rings mounted in a packing box or container. The detail at the right side of the
figure indicates how each ring is divided into three sections. The spring encircles the
ring allowing some radial adjustment but preventing axial movement. Clearances are
held extremely close and the graphite (carbon) is self-lubricating.
Page 23
Figure 23
Carbon Ring Shaft Seal
Labyrinth Seals
In large machines, the greater shaft diameters increase the surface speed above the limits
of carbon rings. Labyrinth rings are effective for larger shafts (see Fig. 24). The seals
function by breaking down the leakage over a number of steps (depending on the
pressure drop involved). Each step causes eddy currents reducing the velocity of the
steam through the preceding clearance. The total pressure drop is broken down into
many small pressure drops. Sealing steam maybe added partway down the shaft. A
steam leakoff section is used to bleed off steam before it exits along the shaft to
atmosphere. The leakoff also removes any condensate that forms in the seal.
Figure 24
Low-Pressure Labyrinth Shaft Seal
Page 24
Water Seals
Labyrinth and carbon rings reduce but do not eliminate leakage of steam where the shaft
leaves the casing. A water sealing gland used in combination with labyrinths effectively
provides a positive seal. This gland, shown in Fig. 25, is quite simple in its application.
It consists of a centrifugal pump runner (impeller) fixed to the turbine shaft. Cooling
water (usually condensate) is fed to the runner and builds up a ring of water under
centrifugal pressure at its periphery. The ring of water forms a positive seal. A detailed
view of the seal is shown in Fig. 26. The main advantage of water seals is that there is
no leakage steam at the shaft.
Disadvantages of this arrangement are:
• The seal is not effective until the turbine approaches running speed
• Scale will form if the water is not free of all impurities
• The quenching effects of the comparatively cool water on the hot rotor shaft;
repetition of this quenching may lead to cracking of the shaft
• They require more adjusting than steam glands do
Figure 25
Water Sealed Gland Overview
Page 25
Figure 26
Water Sealed Gland Detail
Page 26
Objective 5
Describe the design and components of steam turbine
bearings.
STEAM TURBINE BEARINGS
The bearing on a turbine really “gets around.” A typical 200 mm diameter bearing
operating at 3600 rev/min has a surface speed of 130 km/h. Such a bearing must run
continuously for years. In five years it would travel over 5 600 000 km with only minor
wear. Bearings are precision assemblies that require attention and preventative
maintenance during operation and careful handling during installation.
Bearing housings are usually of sturdy box-construction. They are bolted to or form an
integral part of the main body casting. Rigidity and alignment are major considerations
in steam turbine bearings. Rotor sag causes misalignment of bearings in larger units.
Some misalignment is dealt with by self-aligning bearings.
Small turbines often use ball bearings. They are the deep-groove type, either single or
double row. They are used where end thrust is low. Double row and angular thrust types
are used for heavier end thrust. Normally, the bearing at one end of the turbine rotor is
fixed rigidly in the housing and takes end thrust. The other end allows movement (a
limited amount) in an axial direction to allow for differential expansion and contraction
between the rotor and the casing.
Ring-Oiled Bearings
A cut-away section of a small turbine equipped with ring-oiled bearings is shown in Fig.
27. The rings ride freely on the journals revolving with them, dipping into oil contained
in the bearing housing. They automatically carry oil to the top of the journal from the
reservoir. It is distributed over the length of the journal by the force created by shaft
rotation and by special grooves machined into the bearing surface.
When the turbine is operating with high temperature steam, or is in a warm location, the
oil in the bearing reservoirs may become quite hot. To maintain the oil at a steady
operating temperature, cooling water jackets or coils are often incorporated in the
bearing design.
Page 27
Figure 27
Cutaway Section of a Small Turbine and Gear Box
Most small mechanical-drive turbines are fitted with ring-oiled bearings as shown in
Fig. 28. The rings rest on the journal and dip into the oil reservoir in the bearing base.
Rotation of the journal rotates the rings that carry oil from the reservoir to the top of the
journal. It is distributed to the bearing surface. In this design, cooling water is used to
cool the oil.
Figure 28
Ring-Oiled Bearing
Page 28
Pressure-Fed Bearings
Sleeve bearings find application in all sizes of turbines. Small machines normally have
the babbitt-lined, horizontally-split type fitted with one or more oil rings. Cooling is
accomplished either by means of a large oil reservoir or by a water jacket forming part
of the bearing casting, provision being made for the circulation of cooling water.
All large turbines use babbitt-lined sleeve bearings. They have proven to be most
reliable and require a minimum amount of maintenance and attention. They have a very
low coefficient of friction. Friction values are about 0.005 at 1800 rev/min for normal
operating temperature and loading. Normal values refer to the operating temperature
ranges specified by the manufacturer of the turbine.
The rotor of a steam turbine is supported by two main bearings located outside the steam
cylinder. Because of the extremely small clearances between the shaft and the shaft seals
and between the blading and the stationary parts, the bearings must be accurately
aligned. Wear must be kept to a minimum for the same reason, or damage will result to
the shaft seals and blading.
The loads imposed upon the main bearings are chiefly due to the weight of the rotor
assembly. This may or may not be equally divided between the bearings depending upon
the relative position of the bearings and the centre of gravity of the rotor assembly. The
design is usually such that the bearings do take equal shares of the load. In turbines
where the admission steam is not uniformly distributed around the circumference, the
forces on the blades have an influence on the bearing loads and pressures. If unbalanced
forces become great enough, a vibrating load may be imposed upon the bearing in
addition to that imposed by the rotor weight.
Large turbine main bearings generally consist of shells split horizontally and lined with
an anti-friction bearing metal. The bearings are enclosed in a housing to which a
generous supply of oil is pumped by the circulating pump. This oil is delivered to the
bearing, and chamfers and oil grooves assist in its even distribution along the length of
the journal. When an oil of correct viscosity is used, a wedge is formed between the
journal and the bearing. The journal floats on the oil wedge. Metal to metal contact
between the journal and bearing cannot occur.
The passages and grooves in the bearings are sized to permit a considerably greater flow
of oil than is required solely for lubrication. This additional oil flow is required to
remove heat. The heat is from friction and heat conducted to the bearing by the shaft.
The shaft is heated by hot parts of the turbine such as hot blading. The oil flow is
sufficient to cool the bearing, prevent hot spots due to induced heat, and maintain the oil
and the bearing at operating temperature. The oil supplied to turbine main bearings
serves more as a cooling agent than as a lubricant.
Page 29
A thermometer is normally provided in each main bearing to allow the bearing
temperature to be viewed and logged at regular intervals. The temperatures are a good
indication of the condition of the bearings. A sudden rise in temperature indicates a
condition needing attention such as oil flows, oil cooling, or turbine loading.
In turbines where the inlet steam is not uniformly distributed around the entire
circumference of the rotating element, the forces on the blading can impact the bearing
loadings. This and other unbalanced conditions can generate vibrations across the unit,
adding to the stresses and reducing the life of the bearings. Fig. 29 shows a journal main
bearing used on a steam turbine.
Figure 29
Main Bearing
Page 30
Objective 6
Describe the ways in which steam turbines are
designed to counteract thrust.
TURBINE THRUST
Impulse Turbines
In an impulse turbine, the pressure of the steam drops in the stationary nozzles.
Theoretically, the steam pressures on both sides of the moving blades are equal. The
thrust the steam exerts axially on the shaft is small. There is always a small thrust
tending to move the shaft in an axial direction toward the discharge end of the turbine.
This thrust is counteracted by preventing contact between the moving and stationary
parts of the turbine. A thrust bearing is commonly used for impulse turbines to
counteract the steam-induced thrust. The thrust bearing maintains the axial position of
the spindle in relation to the cylinder and is a vital element in a steam turbine unit.
Reaction Turbines
The reaction turbine has a pressure drop across each row of moving blades resulting in
an end thrust imparted to the turbine shaft. This thrust is in addition to the thrust
developed by the rotation of the shaft. One method of reducing the end thrust is the
double-flow principle of turbine design. Steam is admitted to a point midway along the
turbine casing, dividing and flowing axially in both directions. Opposing rows of
blading are mounted on either side of the steam inlet. The nearly equal end thrusts
developed by the blades counteract each other since they are moving in opposing
directions. Various methods are employed to offset any remaining thrust. In turbines that
are not double flow, other methods of thrust control are needed including: the use of
thrust bearings and dummy pistons.
Thrust Bearings
The thrust bearing maintains the axial position of the shaft in relation to the cylinder.
The size of the thrust bearing is matched to the amount of thrust. All turbines have some
thrust and require a thrust bearing to fix the position of the rotating shaft and blades in
relation to the stationary blading.
In small turbines, ball bearings carry axial and radial loads. Since the blading is usually
impulse type, axial loading is low. The ball bearings for light loads are either single or
double row or deep-groove type. Double row, angular thrust ball bearings (Fig. 30) are
used for heavier end loading. Normally, the bearing at one end of the turbine rotor is
fixed rigidly in the housing and takes any end thrust. The other end has limited
Page 31
movement in an axial direction to allow for differential thermal expansion and
contraction of the rotor and the casing.
Figure 30
Ball Bearing - Double Row
For larger turbines, there are two general types of thrust bearings in common use:
• Tapered land
• Kingsbury
Tapered Land
In the tapered land, Fig. 31(a), a large diameter collar takes the thrust in both
directions. Fig. 31(b) shows the theory of operation. The tapered shape of the lands
builds up a wedge of oil forcing the collar away from actual metal-to-metal contact. The
bearing itself is comprised of a revolving ring and a stationary ring. The revolving ring
offers a smooth flat thrust surface, while the surface of the stationary ring is grooved
radially. Half of each sector is chamfered towards the groove as shown. Radial holes
admit oil from the external circumference of the bearing to the inner core. When the
bearing is operating, the oil in the grooved and chamfered portions of the stationary ring
is drawn into the pressure areas, thus forming complete surface-separating films.
Page 32
(a)
(b)
Figure 31
Tapered Land Bearing
Kingsbury
The Kingsbury thrust bearing, shown in Fig. 32, uses a number of segments or tilting
pads which are free to rock. Since the pivot point is slightly off centre, an oil wedge is
set up with each segment automatically taking up its share of the load.
Figure 32
Kingsbury Thrust Bearing
Page 33
Fig. 33 shows another tilting pad type of thrust bearing. These tilting pads have a button
pivot that causes the pad to pivot. Tilting pad thrust bearings require large amounts of
oil to carry away the generated heat.
Figure 33
Tilting Pad Thrust Bearing
Dummy Pistons
There is a pressure drop across each row of blades in a reaction turbine, and a
considerable force is set up, which acts on the rotor in the direction of the steam flow. In
order to counteract this force and reduce the load on the thrust bearings, dummy pistons
are designed as part of the rotor at the steam inlet end.
An example of a dummy piston with balance pipe is shown in Fig. 34. The dummy
piston diameter is calculated so that the force of the steam pressure acting upon it in the
opposite direction to the steam flow balances out the force on the rotor blades in the
direction of the steam flow. The size of the dummy piston is designed to keep a small
but definite thrust towards the exhaust end of the turbine. A balance pipe is connected
from the casing, on the outer side of the balance piston, to a tap-off point down the
cylinder. The differential pressure remains constant at varying steam flow conditions.
Page 34
Figure 34
Dummy Piston and Balance Pipe
Thrust Adjusting Gear
The efficiency of reaction turbines depends upon close clearances between the
stationary and moving blades. To protect the axial seals, an adjustable thrust bearing, or
block, as shown in Fig. 35, is used. The whole thrust block is cylindrical and fits like a
piston in the cylinder with the thrust block able to move axially. The axial position of
the rotor is controlled within strictly defined limits. During startup, the thrust block is
pushed against a stop in the direction of exhaust for maximum clearance between the
stationary and moving blades, avoiding any danger of rubbing due to uneven
temperatures. The clearances are set to normal after the turbine has been loaded and is
up to operating temperature. The turbine blade clearances are adjusted by moving the
thrust block for minimum blade clearance. Maintaining minimum blade clearances
during operation minimizes the loss of steam energy bypassing the blades and helps
maximize turbine efficiencies.
Page 35
Figure 35
Turbine Thrust Adjusting Gear
Minimizing Axial Thrust
Turbine manufacturers strive to minimize large axial thrusts on turbine rotors. Steam
flows can be designed in opposite directions on a single shaft. This balances the thrusts,
as shown for the LP turbine section of Fig. 36. Steam is admitted to the centre of the LP
section. Half of the flow goes toward the HP section, and the other half flows toward the
generator. The result is very little overall thrust in either direction.
Figure 36
GE Turbine – Double Flow Down Exhaust LP Casing
A more detailed view of this arrangement is shown in Fig. 37.
Page 36
Figure 37
Non-reheat, Double Flow Down Exhaust Unit
Fig. 38 illustrates how opposed steam flow in the HP and IP sections can also be used to
reduce axial thrusts. In this arrangement, the HP casing steam flow is toward the front of
the turbine. The IP flow is toward the rear of the turbine. The HP and IP use a single
shaft, making it possible to use one thrust bearing for the HP/IP casing.
Figure 38
Opposed Flow HP/IP Section
Page 37
Page 38
Objective 7
Describe the purpose and design of expansion and
anchoring components.
TURBINE EXPANSION
To ensure that correct alignment of the turbine is maintained under all operating
conditions, provision is made to allow controlled axial and radial expansion. Axial
means the expanding steam flow is parallel to the line of the shafts. Radial (or
transverse) means the expansion is at right angles to the line of the shafts. The LP
cylinder casing exhaust is usually anchored to the foundation (axially only) at one point.
Movement of both the LP and the HP cylinder casings is allowed to take place by means
of sliding supports or keyways. The casing supports and pedestals are designed
specifically for each turbine and their specific operating conditions.
An example of sliding supports for a HP cylinder is shown in Fig. 39. The cylinder
casing is rigidly connected to the bearing pedestal. It is free to move radially away from
the shaft in all directions while remaining in alignment. The bearing pedestal is allowed
to slide axially on keyways attached to the bedplate and the pedestal.
Figure 39
HP Pedestal and Casing Support
Page 39
An example of an arrangement for the expansion of a two-cylinder turbine is shown in
Fig. 40.
Figure 40
Provision for Expansion of Two-Cylinder Turbine
In some turbines, the pedestal bearings are fixed solid to the foundation, and the casings
are allowed to expand axially at one end by means of supporting feet and sliding
keyways.
TURBINE ANCHORING
A system of cylinder anchorage for a three-cylinder, tandem compound, reaction turbine
is shown in Fig. 41. Anchorage systems depend upon the following:
• Type and size of the machine
• Number of cylinders
• Amount of expansion expected
Page 40
Figure 41
Anchorage of Three-Cylinder Turbine
Referring to Fig. 41, the HP cylinder is prevented from moving axially at the steam
inlet end by transverse keys A that allow radial movement. A centre key B keeps the
cylinder central but does not restrict radial expansion.
The exhaust end of the HP cylinder has two sliding feet resting on brackets. They are an
integral part of the intermediate bearing C. Slipper guides D prevent the cylinder from
lifting due to torque reaction. A centre key E keeps the cylinder centred at this end
without restricting axial or radial movement.
The IP cylinder is anchored in a similar manner. F is the transverse key at the inlet end
and G is the centre key. At the exhaust end, the centre guide key is H. The sliding feet
brackets are J and the slipper guides are K.
The sliding feet brackets J are an integral part of the LP turbine exhaust. The transverse
keys of the LP cylinder are located at M on the cylinder pedestals. The side-guides L
prevent body lateral movement. The slipper guides N are at the alternator end of the LP
turbine.
Page 41
Page 42
Objective 8
Explain the principles of steam turbine nozzle design.
IMPULSE TURBINE OPERATING PRINCIPLES
When steam at high pressure expands through a stationary nozzle, the steam pressure
drops and velocity increases. The steam exits the nozzle in the form of a high-speed jet.
The high velocity steam contacts the turbine blading. The direction of the steam flow
changes due to the shape of the blade, as shown in Fig. 42. The change in direction of
the steam flow produces an impulse force on the blade (F in Fig. 42). The change in
angular moment of the fluid in a rotating passage causes torque on the rotor. As the
blade is attached to the rotor of a turbine, the force on the blades causes the rotor to
revolve.
Figure 42
Impulse Turbine Blade Section
In Fig. 42, a force applied to the blade is developed by causing the steam to change
direction of flow (Newton's second law—change of momentum). The change of
momentum produces the impulse force. In an impulse turbine, there are a number of
stationary nozzles and the moving blades are arranged completely around the rotor.
Impulse Turbine Nozzles and Buckets
Fig. 43 shows a cutaway of impulse turbine nozzles and buckets. The nozzles are
stationary blading attached to the stationary diaphragm. The buckets, or moving blades,
on the rotor are attached to the turbine wheels. The wheels are connected to the shaft.
The moving blades convert the velocity energy of the steam into mechanical energy
causing the shaft to rotate. This turbine type has the disadvantages of very high speed
and extremely high centrifugal force.
Page 43
Figure 43
Impulse Turbine Nozzles and Buckets
Steam Nozzles
Nozzles are often constructed of Monel metal formed over special dies. Monel metal is a
high tensile strength nickel-copper alloy. Each nozzle is individually designed for proper
expansion of steam at the pressure and temperature specified. The following two types
of nozzles are used for steam turbines:
• Convergent
• Convergent-divergent
Convergent Nozzle
The convergent nozzle, shown in Fig. 44, is used for small pressure drops. As the
pressure drop across the nozzle is increased, the steam velocity also increases, but only
up to a specific minimum exit pressure called the critical pressure. The ratio of exit
pressure to inlet pressure, below which no increase in velocity is possible, is called the
critical pressure ratio. A typical value of this ratio for wet or saturated steam is 0.577,
while a typical value for superheated steam is 0.55. With a decrease in the exit pressure
to a pressure below the critical pressure, any extra energy that is added goes into
turbulence and the formation of eddy currents at the nozzle exit, rather than increasing
steam velocity.
Page 44
Figure 44
Convergent Nozzle
Convergent-Divergent Nozzle
When large pressure drops are required, a convergent-divergent nozzle, Fig. 45, is used.
The pressure at the narrowest part of the nozzle, the throat of the nozzle, should be at the
critical pressure. The pressure continues to drop in the divergent part of the nozzle. The
divergent section is designed to have increasing volume to match the increase in steam
volume as the pressure decreases. A properly designed convergent-divergent nozzle can
handle any pressure drop, producing the calculated steam velocity, without eddy
currents.
Figure 45
Convergent-Divergent Nozzle
Page 45
Page 46
Objective 9
Explain a steam turbine steam velocity diagram.
TURBINE BLADE VELOCITY DIAGRAMS
Steam nozzles are used to direct steam onto turbine blades at the correct angle resulting
in the most efficient energy conversion. The blades utilize the energy in the steam to
produce mechanical energy at the turbine shaft.
The principle behind this energy transformation is given in Newton's second law of
motion, which states:
Force = Mass × Acceleration
A force can be produced if a mass of some substance can be made to accelerate (or
decelerate). The mass applied to a turbine blade is the steam flowing over it.
Acceleration is defined as a rate of change of velocity. Velocity is a vector quantity and
must be specified in direction as well as magnitude. A change in direction is therefore a
change in velocity, and the rate of change is the acceleration produced.
Force × Distance moved = Work done
The product of the force exerted on a turbine blade and the distance through which it
moves determine the work done. Work taken over a time interval enables the power
produced to be calculated.
Blade velocity diagrams allow an estimate of the power developed from certain turbine
nozzle and blade combinations. Fig. 46 shows an example of a single-stage axial-flow
turbine with one nozzle (note the steam and blade directions).
Figure 46
Single-Stage Axial Flow Turbine
Page 47
For the purposes of the following calculations, it is assumed that the row of turbine
buckets on the rim of the wheel is equivalent to a straight line of buckets moving in a
tangential direction. Fig. 47 shows a cross-section of the flow path looking radially
inward towards the axis of rotation.
Figure 47
Cross-Section of Steam Flow Path
If one of the buckets, or blades, is considered, and the angles and speeds of steam and
blade are drawn, they appear as in Fig. 48.
Figure 48
Turbine Blade Velocity-Vector Diagram
The letters used in the turbine blading diagrams are from the Greek alphabet:
α
β
δ
γ
Page 48
Alpha
Beta
Delta
Gamma
Explanation of Terms in Fig. 48
Vl represents (in magnitude and direction) the steam leaving the nozzle. This
becomes the steam inlet to the moving blade.
α
is the angle of the axis of the nozzle with the direction of blade movement.
Vb
is the blade velocity.
VRl
(Velocity, relative, inlet) is the resultant of V1 and Vb and represents the
velocity and direction of the incoming steam relative to the moving blade.
β
is the inlet angle of the blade. Note that this angle matches the incoming
steam direction exactly so the steam enters the blades without shock.
The above angles and sides form the inlet blade velocity diagram.
Another triangle is formed by the conditions obtained at the moving blade outlet as
follows:
VR2 represents the steam leaving the blade. VR2 is measured relative to the
moving blade. The only reduction in magnitude of this steam velocity will
be that due to friction as the steam passes over the blade. The direction of
steam leaving the blade (angle γ ) depends upon the shape of blade used.
γ
is the exit angle of the blade.
Vb
represents the blade speed (this is identical with Vb in the inlet triangle).
V2
is the resultant of VR2 and Vb and represents the absolute steam-exit speed
and direction. The term absolute is used when a measurement is made with
reference to a fixed object, in this case the fixed parts of the turbine. The
fixed parts are the casing or the fixed blades. The term relative is used
when a measurement is made with reference to a moving object, in this
case the moving blades.
δ
is the angle at which the steam leaves the moving blade, referred to a fixed
point. Hence, this is its angle of approach to the next row of fixed blades.
Page 49
Page 50
Objective 10
Calculate the steam velocity and angle of entry for
impulse and reaction turbine blading.
TURBINE BLADE CHARACTERISTICS
The two blading types—impulse and reaction—have basic characteristics which
distinguish them. Each blading type has a characteristic shape of velocity vector
diagram.
Impulse Blading
Simple impulse blading is usually made so that the moving blades have the
Inlet angle β = Outlet angle γ
Each blade is symmetrical about its centreline.
There is no pressure drop across a moving impulse blade and no velocity increase.
If friction is neglected, there is no velocity decrease.
VR1 = VR 2
The moving blade section of the diagram is shown in Fig. 49.
Where ∠β = ∠γ (these angles are usually equal in an impulse turbine)
And VR1 = VR 2
Page 51
Figure 49
Impulse Moving Blading
Impulse Blading Calculations
Example 1
Referring to the impulse blading vector diagram in Fig. 50, steam flows from the nozzle
of a simple impulse turbine at a velocity of 600 m/s and at an angle of 20° to the
direction of blade motion. Blade velocity is 225 m/s. Neglecting friction, and with equal
blade inlet and outlet angles, calculate:
(a) Blade inlet angle so that the steam will enter without shock (V2).
(b) Magnitude and direction of the absolute velocity of the steam leaving the
blades.
Solution
Figure 50
Impulse Blading Vector Diagram
Page 52
Given data:
V1 = 600 m/s
Vb = 225 m/s
α = 20°
VR 2 = VR1
γ =β
Values X 1 and X B are added to the diagram for ease of reference and to simplify the
trigonometric calculations.
(a) Blade inlet angle so that the steam will enter without shock ( V2 ).
Vw1 = V1 × cos α
Vw1 = 600 m/s × cos 20°
Vw1 = 600 m/s × 0.9397
Vw1 = 563.82 m/s
V f 1 = V1 × sin α
V f 1 = 600 m/s × sin 20°
V f 1 = 600 m/s × 0.3420
V f 1 = 205.21 m/s
X I = VW 1 − VB
X I = 563.82 m/s - 225 m/s
X I = 338.82 m/s
β = tan -1
V fl
XI
⎛ 205.21 m/s ⎞
⎟
⎝ 338.82 m/s ⎠
β = tan -1 (0.6057)
β = 31° 12' (Ans.)
β = tan -1 ⎜
(b) Magnitude and direction of the absolute velocity of the steam leaving the
blades.
Blade outlet angle γ = Blade inlet angle β
γ = β
Blade outlet angle γ = 31° 12' ( Ans.)
Page 53
Since VR 2 = VR1
X B = X1
But X 1 = 338.82 m/s
X B = 338.82 m/s
VW 0 = X E - VB
VW 0 = 338.82 m/s - 225 m/s
VW 0 = 113.82 m/s
VFB = VF 1
But VF 1 = 205.21 m/s
VFB = 205.21 m/s
From Pythagoras' theorem:
V2 = VFB 2 + VWO 2
V2 = (205.21 m/s) 2 + (113.82 m/s) 2
V2 = 42111.14 + 12954.99
V2 = 55066.13
Magnitude of steam velocity V2 = 234.66 m/s (Ans.)
Reaction Blading
Reaction blading is made so that the moving and fixed blades are identical. This
relationship produces a 50% reaction turbine in which 50% of the steam’s loss of
enthalpy occurs in the fixed blades and 50% occurs in the moving blades; 100% reaction
blading is not attainable in practice. The term reaction turbine usually refers to a 50%
reaction turbine.
Moving blade inlet angle β = Fixed blade inlet angle δ
Moving blade exit angle γ = Fixed blade exit angle α
The relative velocity of the steam does not remain constant over the moving blade, as in
an impulse turbine, because the steam is expanding as it flows over the blade. This
expansion causes a pressure drop and a consequent velocity increase; VR2 will therefore
be greater than VR1.
Page 54
Because angles β and δ are equal and angles γ and α are equal, the blade velocity vector
diagram for a 50% reaction turbine is symmetrical about a central vertical axis as shown
in Fig. 51.
Figure 51
Reaction Blading Diagram
Reaction Blading Calculations
Example 2
Referring to the reaction blading vector diagram in Fig. 52, at one stage in a reaction
turbine, the velocity of the steam leaving the fixed blades is 100 m/s and the fixed blade
exit angle is 20°. The linear velocity of the moving blade is 66 m/s. The steam
consumption is 1.4 kg/s. Assuming the fixed and moving blades have identical sections,
calculate the entrance angle of the blades.
Solution
Figure 52
Reaction Blading Vector Diagram
Page 55
Given data:
Vl = 100 m/s (because fixed blade outlet is moving blade inlet)
α = 20° (because fixed blade outlet is moving blade inlet)
Vb = 66 m/s
VW 1 = V1 × cos α
VW 1 = 100 m/s × cos 20°
VW 1 = 100 m/s × 0.9397
VW 1 = 93.97 m/s
VF 1 = V1 × sin α
VF 1 = 100 m/s × sin 20°
VF 1 = 100 m/s × 0.3420°
VF 1 = 34.20 m/s
X I = VW 1 − VB
X I = 93.97 m/s − 66 m/s
X I = 27.97 m/s
⎛ VF 1 ⎞
⎟
⎝ XI ⎠
β = tan -1 ⎜
⎛ 34.20 m/s ⎞
⎟
⎝ 27.97 m/s ⎠
β = tan -1 (1.2227 )
β = tan -1 ⎜
β = 50° 43' (Ans.)
Page 56
Objective 11
Calculate the work done on steam turbine blades and
the resulting power developed.
WORK DONE ON BLADES
The force exerted on a blade depends upon the change in the component of the steam
velocity in the direction of the blade movement. At the inlet to the blade this component
will be Vl cos α. This is an absolute velocity referred to as the velocity of whirl.
At the outlet from the blade, the velocity of whirl is V2 cos δ .
Fig. 53 shows that V1 cos α must be in a left to right direction, whereas V2 cos β is in a
right to left direction.
Thus, the total change in this component of velocity is the sum of V1 cos α and V2 cos β .
The force exerted on the blade is given by:
Force = mass × acceleration
F ( newtons ) = kg steam flowing/s × change in velocity ( m/s 2 )
F ( newtons ) = m (V1 cos α + V2 cos β )
The force F newtons exerted on the blade does work by moving the blade.
Work done/s = F (N) × Blade speed ( m/s )
F × Vb
kW
1000
where Vb = blade speed, m/s
Power developed =
Fig. 53 shows the inlet triangle.
Page 57
Figure 53
Inlet Triangle
The vector V1 is resolved into two components:
•
V f 1 (velocity, flow, inlet) in the direction of steam flow.
•
Vw1 (velocity, whirl, inlet) in the direction of blade movement or whirl.
Fig. 54 shows the vector diagram of the steam exit vectors.
Figure 54
Steam Exit Vectors
The vector V2 is resolved into two components:
V fo (velocity, flow, outlet) in the direction of steam flow.
Vwo (velocity, whirl, outlet) in the direction of whirl.
Fig. 55 shows the inlet and outlet triangles superimposed upon the common base Vb .
Page 58
Figure 56
Inlet and Outlet Triangles
This is a convenient arrangement for the solution of problems, particularly when the
total change in velocity of whirl is required for calculation of turbine stage power.
The turbine blade velocity-vector diagram in Fig. 56 shows some interesting aspects.
The vectors VI and V2 represent steam flows measured from fixed points (absolute
velocities). The two angles, α and δ, are respectively the exit and the entrance angles for
the rows of fixed blades.
The point B can therefore be said to represent the fixed blade conditions.
The vectors VRI and VR2 represent steam conditions measured from moving blades
(relative velocities). Further, the angles β and γ are the inlet and exit angles of the
moving blade. Thus, point A can be said to represent the moving blade conditions.
Example 3
Referring to the vector diagram in Fig. 56, steam at a velocity of 760 m/s from a nozzle
is directed onto the blades of a turbine at 20o to the direction of blade movement.
Calculate the inlet angle of the blades so that the steam will enter without shock when
the linear velocity of the blades is 275 m/s. If the exit angle of the blades is the same as
the inlet angle, find, neglecting blade friction, the magnitude and direction of the steam
velocity leaving the blades.
Solution
Given
V1 = 760 m/s
Vb = 275 m/s
Find V2 and Angle δ
Page 59
Figure 56
Vector Diagram
The turbine is a simple impulse type since the inlet and exit angles of the moving blade
are equal. Point A on the diagram represents conditions around the moving blade.
Given that no friction occurs as the steam flows over the blades, the incoming velocity
VR1 will be the same as the exit velocity VR2. The direction is such that
angle β = angle γ
If perpendiculars are dropped from C to D and from E to F, the following calculations
can be carried out.
In triangle BCD:
sin 20° =
CD
V1
CD = V1 × sin 20°
CD = 760 × 0.3420
CD = 259.94 m/s
cos 20° =
DB
V1
DB = V1 × cos 20°
DB = 760 m/s × 0.9397
DB = 714.17 m/s
DA = DB - AB
DA = 714.17 - 275 m/s
DA = 439.17 m/s
Page 60
In triangle ACD:
CD
DA
259.94
tan β =
439.17
tan β = 0.5919
tan β =
Angle β = 30° 37' ( Ans.)
This is the inlet angle of the blades.
sin β =
CD
VR1
VR1 sin β =CD
CD
sin β
259.94 m/s
VR1 =
sin 30° 37 '
259.94 m/s
VR1 =
0.5093
VR1 = 510.39 m/s
VR1 =
Since there is no friction of steam over the blades, VR 2 will also be 510.39 m/s and angle
γ will be 30o 37'.
Now consider triangle AEF:
EF = CD
EF = 259.94 m/s
cos 30°37 ' =
AF
VR 2
AF = VR 2 × cos 30°37 '
AF = 510.39 m/s × 0.8606
AF = 439.24 m/s
Page 61
In triangle BEF:
BF = AF - Vb
BF = 439.24 m/s - 275 m/s
BF = 164.24 m/s
EF
BF
259.94 m/s
tan δ =
164.24 m/s
tan δ = 1.5827
tan δ =
∠δ = 57° 43' ( Ans.)
This is the direction of the steam leaving the blades.
EF
sin 57°43' =
V2
EF
sin 57° 43'
259.94 m/s
V2 =
0.8434
V2 = 308.21 m/s (Ans.)
This is the steam velocity leaving the blades, measured from the turbine casing, i.e.
an absolute velocity.
V2 =
Example 4
Referring to Fig. 57, steam leaves the fixed blades of one stage of a reaction turbine at
120 m/s with an exit angle of 25°. The moving blades travel with a linear speed of 90
m/s and the steam consumption of the turbine is 1 kg/s.
Calculate the entrance angle of the blades and the horsepower developed in one turbine
stage (assume 50% reaction blading).
Page 62
Solution
Figure 57
Vector Diagram
Given:
V1 = 120 m/s
Vb = 90 m/s
∠α = 25°
Reaction (or 50% reaction) blading has identical moving and fixed blades. The angles
and vectors around point A are duplicated around point B . The angle required is β .
DB
cos 25° =
V1
DB =V1 cos 25°
DB = 120 m/s × 0.9063
DB = 108.76 m/s
DA = DB − AB
DA = 108.76 m/s − 90
DA = 18.76 m/s
sin 25° =
CD
Vl
CD = V1 sin 25°
CD = 120 m/s × 0.4226
CD = 50.71 m/s
Page 63
CD
DA
50.71 m/s
tan β =
18.76 m/s
tan β = 2.7031
tan β =
Entrance angle of the blades β = 69° 42' ( Ans.)
The total change in the velocity of whirl is required for calculations of work done on the
blading as detailed earlier. This is represented by the length CE on the diagram:
CE = DA + AB + BF (because CD and EF are perpendiculars)
If the diagram is symmetrical about its centre:
then DA = BF
and CE = 2 × DA + AB
But AB is blade speed 90 m/s and DA = 18.76 m/s
CE = 2 × DA + AB
CE = ( 2 × 18.76 m/s ) + 90 m/s
CE = 37.52 m/s + 90 m/s
CE = 127.52 N
Force exerted on blading = w × a (newtons )
Force exerted on blading = kg steam/s × change in velocity, m/s 2
Force exerted on blading = 1.0 kg/s × 127.52 m/s
Force exerted on blading = 127.52 N
Horsepower developed = force × bleed speed, Nm/s
127.52 N × 90 m/s
Horsepower developed =
1000
Horsepower developed = 11.48 kW ( Ans.)
Example 5
Referring to Fig. 58, a single-stage impulse turbine has a steam consumption of 20
kg/min. The nozzles are inclined at 20° to the plane of the wheel and steam leaves the
nozzles at 600 m/s. The mean diameter of the blade ring is 1 metre and the wheel rotates
at 5000 rev/min. Find the inlet angle of the moving blades and the power of the wheel,
neglecting all losses.
Page 64
Solution
Figure 58
Blade Velocity Vector Diagram
Blade wheel rotates at 5000 rev/min. Circumference is π × 1 m .
5000 rev/min
60 s/min
Linear blade speed = 3.1416 ×1 m/rev × 83.33
Linear blade speed = 261.80 m/s
Linear blade speed = π × 1 m/rev ×
To find the power of the wheel, it is necessary to find the change in velocity of whirl,
i.e. the distance CE on the diagram.
In the triangle BCD:
cos 20° =
DB
V1
DB = V1 × cos 20°
DB = 600 m/s × 0.9397
DB = 563.82 m/s
Page 65
DB = DA + AB
DA = DB − AB
DA = 563.82 m/s - 261.80 m/s
DA = 302.02 m/s
sin 20° =
CD
Vl
CD = Vl × sin 20°
CD = 600 m/s × 0.3420
CD = 205.21 m/s
CD
DA
205.21 m/s
tan β =
302.02 m/s
tan β = 0.6795
tan β =
Inlet angle of moving blades = 34° 12' ( Ans.)
This is the inlet angle of the moving blades. Angle β is assumed to be equal to angle γ
(for simple impulse blading). VR1 (inlet steam speed relative to moving blade) will be
equal to VR 2 (outlet steam speed relative to moving blade) if there is no friction loss in
passing over the blades.
In triangles CDA and EFA:
Angle β = Angle γ
and CA = EA
CD will be equal to EF because both are perpendiculars dropped to the same base.
The triangles are congruent and DA = AF .
The total change in velocity is given by the distance CE
CE = DA + AF
Page 66
Note: If the angles β and γ are large enough, the perpendicular EF will bring F to
the left of point B . This would represent steam leaving the moving blades with a
velocity component, in the direction of whirl, which is less than the blade speed AB ;
i.e., the leaving steam would be moving partly in the direction of the blades.
In this case:
AF = DA
but DA = 302.02 m/s
AF = 302.02 m/s (which is greater than the blade speed 261.80 m/s)
CE = DA + AF
CE = 302.02 m/s + 302.02 m/s
CE = 604.04 m/s
Force on blades ( newtons ) = w × α
20 kg/min
60 s/min
α = change of velocity
α = 604.04 m/s
w=
Force on blades ( newtons ) = w × α
20 kg/min
× 604.04 m/s
60 s/min
Force on blades ( newtons ) = 201.35 N
Force on blades ( newtons ) =
Power = force × blade speed (Nm/s or watts)
201.35 N × 261.80 m/s
Power =
1000
Power = 52.71 kW (Ans.)
Page 67
Page 68
Objective 12
Calculate steam turbine Rankine cycle thermal
efficiency.
STEAM TURBINE CYCLE
The Rankine cycle is the cycle used in steam plants. A temperature-entropy diagram of
the Rankine cycle is shown in Fig. 59. The heat supplied to the steam includes superheat
de after the steam leaves the boiler dry and saturated at d. This heat addition will follow
the constant pressure line from d to e. The expansion of steam through the turbine is
given by ef, which in the ideal case is a vertical line (at constant entropy). The thermal
efficiency of this cycle is:
Thermal efficiency =
work done
heat supplied
Figure 59
Temperature-Entropy Diagram for Rankine Cycle
Note: Rankine cycle efficiency is the efficiency of the cycle including boiler, turbine,
and condenser. It is not the efficiency of the steam turbine by itself. It is the ratio of the
shaded area (abcdef) of the diagram to the total area (habcdefg).
Page 69
Example 6
Steam is supplied to a turbine at a pressure of 6000 kPa and 500°C. It is expanded
adiabatically and without friction to a backpressure of 10 kPa. It is condensed at this
pressure and returned to the boiler through an extraction pump and feed pump.
Neglecting the pump work, calculate:
(a) Heat supplied per kg of steam
(b) Work done by turbine per kg steam
(c) Thermal efficiency
This could be done from first principles by calculating the total heat supplied to give the
whole diagram area, and then subtracting the product of the entropy change h to g and
the temperature h to a.
The calculations can also be done using the steam tables, as shown below.
Solution
(a) Heat supplied per kg of steam.
Total heat per kg steam at 6000 kPa and 500°C = 3422.2 kJ/kg
Enthalpy of water at 10 kPa = 191.83 kJ/kg
Heat supplied = 3422.2 kJ/kg -191.83 kJ/kg
Heat supplied = 3230.37 kJ/kg ( Ans.)
(b) Work done by turbine per kg steam (from Steam Tables).
Entropy of steam per kg at 6000 kPa and 500°C = 6.8803 kJ/kg
Entropy of 1 kg water at 10 kPa = 0.6493 kJ/kg
Difference = change in entropy
Difference = 6.8803 kJ/kg - 0.6493 kJ/kg
Difference = 6.2310 kJ/kg
Page 70
Ta = absolute temperature of steam at 10 kPa
Ta = 45.81°C+273
Ta = 318.81K
Heat rejected = area on the graph afgh
= Ta × Entropy change h to g
= 318.81 K × 6.231 kJ/kg
= 1986.51 kJ
Work done = 3230.37 kJ/kg - 1986.51 kJ/kg
Work done = 1243.86 kJ/kg (Ans.)
(c) Thermal efficiency.
work done
heat supplied
1243.86
Rankine Cycle Thermal Efficiency =
× 100
3230.37
Rankine Cycle Thermal Efficiency = 0.3851× 100
Rankine Cycle Thermal Efficiency = 38.51% (Ans.)
Rankine Cycle Thermal Efficiency =
Page 71
Page 72
Chapter Questions
1. Describe why some turbines are designed with steam entering through two separate
inlets in the LP cylinder.
2. Sketch and describe a dummy piston used to counteract thrust forces in a steam
turbine.
3. Sketch and describe a velocity-vector diagram for impulse moving blading.
4. a) What is the difference between an extraction turbine and a bleeder turbine?
b) What are typical applications for these types of turbines?
5. When would a turbine be constructed using a double casing? Explain.
6. a) Describe a disc type of turbine rotor.
b) What is a common application for this type of rotor?
7. What are three types of shaft seals used on steam turbines?
8. a) What are two methods of lubricating steam turbine bearings?
b) What applications would be suitable for each type?
9. Steam flows from a nozzle of a simple impulse turbine at a velocity of 550 m/s and
an angle of 21° to the direction of blade motion. Blade velocity is 220 m/s.
Neglecting friction, and with equal blade inlet and outlet angles, calculate:
a) The blade inlet angle so that the steam will enter without shock (V2).
b) The magnitude and direction of the absolute velocity of the steam leaving the
blades.
10. Steam leaves the fixed blades of one stage of a reaction turbine at 122 m/s with an
exit angle of 23°. The moving blades travel with a linear speed of 88 m/s and the
steam consumption of the turbine is 1.1 kg/s.
a) Calculate the entrance angle of the blades
b) Horsepower developed in one turbine stage (assume 50% reaction blading).
Page 73
11. Steam is supplied to a turbine at a pressure of 10 250 kPa and 500°C. It is then
expanded adiabatically and without friction to a backpressure of 15 kPa. It is
condensed at this pressure and returned to the boiler by a feedwater pump.
Neglecting the pump work, calculate:
a) Heat supplied per kg of steam
b) Work done by turbine per kg steam
c) Thermal efficiency
Page 74
Steam Turbine Auxiliaries and
Control
Learning Outcome
When you complete this learning material, you will be able to:
Explain the purpose and design of steam turbine auxiliaries, control, and monitoring
equipment.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Describe the purpose, design and components of a turning gear.
2. Describe the purpose, design and components of an adjusting gear.
3. Explain critical speed.
4. Describe the design and components of lubricating oil and jacking oil systems.
5. Describe the design of speed reducing gears.
6. Describe the design and components of flexible couplings.
7. Describe the purpose and design of steam turbine governors and governor
systems.
8. Describe the purpose and design of steam turbine stop valves and control valves.
9. Describe the purpose and design of steam turbine grid type extraction valves.
10. Describe the purpose and design of steam turbine casing pressure relief systems
including rupture diaphragms.
11. Describe the purpose and design of steam turbine overspeed trips.
12. Describe the purpose and design of steam turbine supervisory equipment.
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Page 76
Objective 1
Describe the purpose, design and components of a
turning gear.
TURNING GEARS
When a turbine is left cold and at a standstill, the mass of the rotor tends to cause the
rotor to sag slightly. This is called bowing. If left at a standstill while the turbine is still
hot, the lower half of the rotor cools faster than the upper half. The rotor bends upwards.
This is called hogging. In both cases, the turbine is difficult, if not impossible, to start
up due to rubbing within the bearings, glands and diaphragms. To overcome this
problem, the manufacturer supplies large turbines with a turning or barring gear. It
consists of an electric motor and sets of reducing gears that turn the turbine shaft at low
speed. The normal speed of a turbine rotor on barring gear is between 20 and 40 rpm,
although some designs turn as slowly as 3 rpm.
The distance between bearings of large turbines is considerable (3 to 10 meters). Rotors
operating at temperatures above 400°C need turning after shutdown to ensure uniform
cooling takes place. The fan action in the casing caused by the slow turning turbine
blades prevents temperature variations.
Before a cold turbine is started up, the barring gear turns it for approximately three
hours. When a turbine is shut down, the barring gear turns it for the next 24 hours. The
exact time required depends on the difference in temperature between the stationary and
rotating parts. If a hydrogen-cooled generator is involved, the turbine is kept on barring
gear to prevent loss of hydrogen through the shaft seals. The turning gear, illustrated in
Fig. 1, uses a belt drive with a worm and wheel to reduce the motor speed. A yoke
supports the disengaging gear wheel. An oil-operated piston rotates the yoke about the
worm shaft to engage or disengage the turning gear from the turbine shaft.
The location of an under-slung barring or turning gear is shown in Fig. 2. This view
shows a tandem double-flow turbine being assembled for testing. Positioning of the
barring gear at the side of the bearing enables the pinion to engage the shaft below the
turbine centre line. The top portion of the diagram illustrates a side-mounted barring
gear with a vertical driving motor and their location in relation to the turbine shaft.
With the turbine revolving at slow speeds (on barring gear), the main lubricating oil
pump does not provide sufficient oil to lubricate the bearings. An auxiliary oil pump is
used when the turning gear is in operation. A separate motor driven oil pump is provided
to supply oil to the bearings instead of using the turbine-driven oil pump.
Page 77
Figure 1
Turning Gear
Figure 2
Illustrations of Barring (Turning) Gear
Page 78
Objective 2
Describe the purpose, design and components of an
adjusting gear.
TURBINE BLADE CLEARANCES
Efficient operation of a turbine depends to a large extent on the maintenance of the
correct clearances between fixed and moving elements. Excessive clearances cause
increased steam consumption and reduced clearances may cause blade rubbing.
When a turbine is constructed, the clearances are carefully set and a record is kept at the
plant. When the top halves of the casing are removed, the clearances are checked against
the record. Care is taken to ensure that the rotors are in the running position when taking
measurements. Provision is made to move the rotor axially to a position for lifting it
from the casing. Particular care is necessary with clearances of velocity stages fitted to
the high-pressure end of impulse machines, as in Fig. 3. A thorough check of clearances
is essential if replacement blades, nozzles or packing rings have been installed.
Figure 3
Velocity Stage Clearances
Page 79
THRUST ADJUSTING GEAR
The efficiency of reaction turbines depends upon the close clearances between the
stationary and moving blades. To protect the axial seals, an adjustable thrust bearing is
used as shown in Fig. 4. The thrust block is cylindrical and fits like a piston in the
cylinder. The thrust block can be adjusted axially. The axial position of the rotor is
controlled within strictly defined limits. During startup, the thrust block is moved
against a stop in the direction of the turbine exhaust. This setting is for maximum
clearance between the stationary and moving blades so that uneven temperatures during
startup do not cause rubbing. When the turbine is heated up and loaded, the thrust block
is adjusted to reducing the clearances to minimum, thus producing maximum efficiency.
Figure 4
Turbine Thrust Adjusting Gear
Page 80
Objective 3
Explain critical speed.
CRITICAL SPEED
If a turbine rotor were constructed so that it was an absolutely symmetrical body, its
balance would be perfect. When rotating, the symmetrical rotor would have no
vibration caused by out-of-balance mass. Errors of balance do take place in actual
rotors. They are caused by:
• Differences in the density of the material
• Errors due to machining
• Differences in blade masses
These are kept to a minimum by careful workmanship. The completed rotor is balanced
both statically (balanced at rest) and dynamically (balanced in motion) before being put
into service.
Static balancing involves supporting the shaft journals on transverse “knife edges. The
tendency of the rotor to roll is measured. Then mass is added or removed to delete the
tendency to roll.
Dynamic balancing is done after the static process in a machine with flexible bearing
supports. The rotor is run up to speed by an electric motor, and vibrations are measured.
Mass is added or removed to the rotor before it is retested. The process is repeated until
the vibration readings are in an acceptable range. The balanced rotor must have very
low vibrations when running at designed speed. New rotors are balanced at the factory.
Overhauled or refurbished rotors must also be dynamically balanced.
Note: At speed, a balanced rotor shows no more than 0.025 or 0.05 mm eccentricity.
A turbine shaft, supported between its two bearings can be likened to a piano wire. If the
wire is “plucked,” it vibrates with a natural frequency. Similarly, shaft rotation has a
natural frequency depending upon its stiffness, as illustrated in Fig. 5. If the shaft is
rotated, any out-of-balance force rotates with it and tends to deflect the shaft. As the
speed increases, the deflection also increases. When a particular speed is approached
(corresponding to the natural frequency of the shaft) the deflection increases very
rapidly and may be sufficient to permanently bend the shaft.
Page 81
Figure 5
Exaggerated Bow of a Shaft
This speed is called the critical speed and is determined in the design stages of the
machine. It depends upon the length of shaft between supports, the shaft diameter and
the shaft stiffness. If the critical speed is approached rapidly, there is little time for the
deflection to grow. Once above this speed, the deflection begins to decrease until
smooth running is again achieved. Turbine manufacturers recommend passing through
the critical speeds quickly. A turbine shaft, running in the critical speed zone, can be
identified by very high vibrations throughout most of the turbine bearings.
A turbine rotor may have more than one critical speed. The others occur as the shaft
takes up the forms shown exaggerated in Fig. 6.
Figure 6
Forms of Whirling Shaft at Critical Speeds
These are the second, third and fourth critical speeds. After passing through the first
critical speed the shaft settles down until the second critical speed is approached when it
commences to bend in the curve shown with a nodal point at the centre of its length
L
shown in Fig. 6 as . Generally, the operating speed is arranged to be between the first
2
and second critical speeds, though some short rotors may be so “stiff” that the operating
speed is below the first critical speed.
Some turbine rotors tend to lose their straightness when heated. Many manufacturers
guard against “thermal instability” by heating the rotor while it is slowly revolved. The
eccentricity is measured during the process.
Page 82
Most rotors tend to “bow” on heating. The deflection increases with temperature up to a
point and then decreases again until the shaft is nearly straight. It remains in this
condition when cooling down and shows no tendency to bend when the heating process
is repeated. This process of heating and cooling of the rotor is carried out before blading
is installed. This is a precaution to prevent rotor vibrations when the turbine is put into
service.
Page 83
Page 84
Objective 4
Describe the design and components of lubricating oil
and jacking oil systems.
LUBRICATING OIL SYSTEMS
Turbines are the prime movers that many plants depend upon. They must be provided
with a reliable supply of lubrication oil. The size of the turbine determines whether to
use a simple or complex lubricating system. Turbines of less than 150 kW, used to drive
auxiliary equipment, are often provided with ring-oiled bearings.
Moderate-sized turbines, particularly if driving through a reduction gear, may have both
ring-oiled bearings and a circulating system. These pressurized oil systems not only
supply oil in the form of a spray to the gears but also supply oil to the bearings of the
gearbox and the turbine.
Large turbines have circulating systems supplying oil to the:
• Turbine bearings
• Governor mechanisms
• Hydraulically operated steam throttle valves
• Bearings of the driven generators
A typical circulating oil system for a turbine and generator set is shown in Fig. 7. The
oil pumps take suction from the oil tank through strainers and discharge the oil at high
pressure, 552 to 827 kPa. From the strainers, the oil flows in two different directions:
• To the power oil and governor relay oil systems
• To the oil coolers and then to the turbine generator bearings
Power oil, acting in servomotors, uses hydraulic pressure to open stop valves and
governing valves. Governor relay oil acts as a sensitive regulating medium. It transmits
oil pressure signals to various parts of the governor oil system. The power oil and the
governor relay oil have to be at high pressure.
Lubrication oil is at a lower pressure, typically in the 69 kPa to 138 kPa range. Before
the oil passes to the coolers, it flows through a pressure-reducing valve. If the turbine
has been operating for a length of time, and the oil is at operating temperature, the oil
from the oil tank will be quite warm. Therefore, the oil will need cooling in the oil
coolers, before it flows through the bearings. Typical outlet temperatures, from the
coolers, are in the 43° to 49°C range.
Page 85
Inside the bearings the oil acts as a lubricant between moving surfaces and as a coolant
for the bearings. From the bearings, the oil drains into a return header leading back to
the oil tank. A thermometer is placed in each return line from the bearings and indicates
bearing temperature.
Figure 7
Typical Lubricating Oil System
JACKING OIL SYSTEMS
Large turbines, with heavy rotors, are generally equipped with a jacking oil pump. It
supplies the lower part of the bearings with oil, at approximately 2 000 to 10 000 kPa,
lifting the shaft and supplying lubricating oil. Oil pressure lifts or jacks the shaft a few
millimetres, so there is no metal-to-metal contact during the initial movement of the
rotor. Jacking of the shaft reduces the load on the barring gear motor. Jacking oil is
applied before starting the barring gear and while operating the turbine at slow speed.
The jacking oil pump is shut down at turbine speeds of 50 to 60 rpm.
Page 86
The turbine/generator lube oil system, shown in Fig. 8, incorporates a jacking oil pump.
The jacking oil pump, # 4 on the drawing, takes suction from the lube oil header. The
jacking oil pump boosts the pressure and feeds oil to the bottom of the bearings. After
the jacking oil leaves the bearings, it then flows into the main return header along with
the lube oil being drained from the bearings. These combined oil flows drain by gravity
back to the lube oil tank.
Figure 8
Lube Oil with Jacking Oil System
Page 87
Page 88
Objective 5
Describe the design of speed reducing gears.
SPEED REDUCTION GEAR SETS
Steam turbines operate at speeds higher than the required operating speed of the driven
machine. Examples of this include turbine-driven:
• Direct-current generators
• Paper making machines
• Centrifugal pumps
• Blowers and fans
In these instances reduction gear sets are used to reduce the shaft speed of the turbine to
suit that of the machine being driven. Reduction gear sets used on medium and
large-sized steam turbines are housed in an oil-tight casing. They are connected to the
turbine and driven unit by flexible type couplings. Small turbines may be designed so
that the gear housing is integral with the turbine casing. The pinion may even be
connected directly to the rotor shaft. This type of arrangement is shown in Fig. 9.
Figure 9
Turbine Driver with Gear Reducer
Page 89
Fig. 10 shows a speed reduction gearbox with the top portion of the cover removed. The
driver is connected to the coupling of the small gear shaft. The driven machine is
connected to the opposite end of the large gear shaft. A pipe from the oil pump supplies
oil mist to the gears at their mesh point. Note that the gears are set at an angle to reduce
gear noise and vibration.
Figure 10
Gears in a Speed Reduction Gear Drive
Page 90
Objective 6
Describe the design and components of flexible
couplings.
FLEXIBLE COUPLINGS
Couplings are used to connect shafts of rotating equipment. Flexible couplings permit an
axial movement of the driven shaft, and they can also be designed to transmit or
eliminate end thrust from the driven unit to the turbine. Flexible couplings can
accommodate minor misalignments or bearing wear. They are not intended to overcome
shaft misalignment due to careless or faulty assembly.
Flexible couplings used on large direct-connected units are often enclosed in the same
housing as the turbine and driven unit bearings. They are lubricated in an oil-tight case.
Oil is supplied by the main lubricating oil system. Flexible couplings are often used to
connect the turbine rotor to its driven machine shaft or to connect the rotors of tandem
compounded turbines to each other. They are designed to absorb the differential
expansion of the shafts due to temperature changes and, to a certain extent, any
misalignment that occurs due to settlement of foundations or temperature changes.
Excessive wear on flexible couplings is often the result of faulty shaft alignment. A
flexible coupling is not designed to act as a universal joint. It can take care of very small
amounts of shaft misalignment, but its primary purpose is to allow for relative axial
movement between the shafts it connects.
Coupling components must be kept in good condition. They are taken apart, inspected
and cleaned when maintenance is performed on the driver. Couplings can lock up (fail to
move) transferring axial movement through the shaft. This can cause overloading of
thrust bearings and vibration problems.
Types of Flexible Couplings
There are many types of flexible couplings. They are selected based on the application
and the type of machines they connect. Normally, the couplings are lubricated, but more
types of dry couplings are being introduced. They are often made of hard rubber
compounds and require no maintenance and do not lock up.
Page 91
The coupling in Fig. 11, for turbines of small and medium output, has flanges keyed to
the shafts. The coupling bolts are screwed into one flange and rubber bushes with metal
cores are fitted over the plain ends of the bolts. The rubber bushes have a small
clearance in the holes of the other coupling flange. This type is called a “pin and
grommet coupling”
Figure 11
Turbine Coupling
Fig. 12 shows a coupling in which the drive between two shafts is taken by a forged
steel muff bolted to the two shaft hubs. The muff is rigid in torsion but gives a limited
amount of flexibility radially.
Figure 12
Semi-Flexible Coupling
Gear or tooth type couplings are shown in Figs. 13 and 14. The shaft hubs have a
number of teeth around the periphery. The sleeve has a matching set of teeth to transfer
torque to the drive while allowing small axial movements between the shafts.
Page 92
Figure 13
Gear Type Flexible Coupling
Figure 14
Gear Type Flexible Coupling
Fig. 15 shows a resilient grid (often called a Bibby or Flexsteel coupling). It has a
tempered steel spring as the driving medium between the two hubs. The hubs are keyed
to the shafts.
Figure 15
Resilient Grid (Flexsteel) Coupling
Page 93
Page 94
Objective 7
Describe the purpose and design of steam turbine
governors and governor systems.
STEAM TURBINE GOVERNORS
Turbine governing systems vary the steam flow to keep the speed of the turbine constant
with varying loads or to hold the pressure constant with varying demands for process
steam. The governor on a turbine driving an alternator controls the turbine inlet steam
flow to maintain constant speed with varying alternator load. In a backpressure turbine
supplying exhaust steam for process work, the steam supply to the turbine is controlled
to maintain a constant backpressure.
In an extraction turbine, the governor controls the steam flow so that both the turbine
speed and the pressure of steam, at the point of extraction, are maintained reasonably
constant. This involves regulation of the total amount of steam admitted to the inlet
stages of the turbine and of the steam supplied to the turbine stages following the
extraction point.
Governor Terminology
Speed Droop
Speed droop is the change in speed caused by an increase in load. An ideal governor
can maintain a constant speed at any load. But, mechanical losses within most
governors mean that they cannot achieve this speed control. If the load on a turbine
changes from zero (no-load) to maximum (full-load), the turbine slows down and the
governor may not be capable of restoring the turbine to set speed.
The difference between the no-load and full-load speed, expressed as a percentage of the
set speed, is called the “droop” of the governor. As the load increases, the speed will
“droop” below the set speed. For example, if the set speed of a turbine is 5000 rpm,
where it operates with no load, and the governor system can only achieve 4500 rpm,
when the turbine becomes fully loaded, the droop of the governor is (500/5000) x 100 =
10%. Governors with low droop are more sensitive to load changes and generally have
more accurate control than governors with high droop.
Page 95
Isochronous Governing
Isochronous governing gives perfect speed regulation with zero speed droop. An
isochronous governor regulates the turbine at constant speed at all loads, so the speed
regulation or droop is zero percent. Isochronous governing is used when prime movers
are operating alone.
If turbines are sharing load in a parallel operation, an action called hunting can occur.
Each turbine attempts to pick up the change in load and they begin “fighting” each other
for control. This creates an uncontrollable cycling of the load and turbine speeds. The
result may be that one machine ends up fully loaded while another machine may have no
load.
Governors fall into two main classes:
• Speed sensitive
• Pressure sensitive
Speed-Sensitive Governors
The speed-sensitive governor is a proportional-action controller because each change in
power causes a change in the turbine speed. The governor controls the opening of the
control valves as a function of this speed change. Due to the governor speed droop, the
frequency is not constant over the full range of load without an external adjustment.
The speed-sensitive governor may consist of the following types:
• Nozzle
• Throttle
• Bypass or overload
• Mechanical
• Mechanical – hydraulic
• Electronic – hydraulic
Nozzle Governing
Nozzle governing is only used in impulse turbines. Regulating the flow of steam to inlet
nozzles and the turbine blades maintains a set turbine speed. Common nozzle
arrangements are the bar-lift and the cam-lift systems.
Fig. 16 shows the bar-lift design with a row of inlet nozzles above the first stage turbine
blading and a set of nozzle valves, or plugs, held by a horizontal bar. Notice that the
lengths of the stems on these plugs vary. The flyweight action moves the bar up and
down to open and close the nozzles as required. The different lengths of the plug stems
determine the sequence in which they open and close.
Page 96
Figure 16
Bar-lift Nozzle Control Gear
Other designs use a cam-like device to control the sequence and opening of each nozzle.
Fig. 17 illustrates how oil under governor control acts on the underside of the springloaded operating piston. As the piston rises, a rack on the piston rod causes a layshaft to
rotate. On this layshaft are a number of cams, one for each admission poppet valve.
Each cam operating through a follower and a rocker arm actuates a steam valve which
supplies a group of nozzles. The cams on the layshaft are indexed so that the valves are
opened in a predetermined sequence and closed in the reverse order.
Figure 17
Cam-lift Steam Admission Valves
Page 97
Throttle Governing
An example of throttle governing is shown in Fig. 18. A single valve at the inlet to the
turbine adjusts the steam flow equally into the turbine casing and to the nozzles. The
inlet, or throttle valve, responds to the governor to increase or decrease the steam flow
for more or less speed. A hydraulic servomotor is often used to help move the throttle
valve. In larger turbines, there may be more throttle valves arranged in parallel in the
steam line.
Throttle governing is used with reaction turbines because the pressure drop in the
moving blading requires steam admission to the full circumference. The multi-valve
arrangement supplying steam to nozzle groups cannot be used. With throttle governing,
one or two control valves control the load from 0% to 100%.
Figure 18
Mechanical-Hydraulic Governor with Servo
Bypass or Overload Governing
Bypass or overload governing is used on both impulse and reaction turbines. It consists
of two throttling valves: one at the inlet of the first stage of the turbine, and the other at
an inlet downstream from the first few stages. The purpose of the second inlet point is to
allow the turbine to maintain speed while producing extra power, during high load or
overload conditions.
Page 98
Fig. 19 shows a steam chest with a stop and trip valve (on the left), followed by the main
steam throttle valve and the bypass throttle valve (on the right). This steam chest/valve
arrangement is mounted on the turbine so as to direct steam to the appropriate nozzles,
as shown in the turbine cross-section of Fig. 20.
Figure 19
Steam Chest with Stop, Trip and Throttle Valves
(Courtesy of C.A. Parsons)
Page 99
Figure 20
Bypass-Governed Turbine
Mechanical Governors
Fig. 21 shows the components and arrangements of a simple mechanical governor. A
set of weights, called flyweights, that pivot and move in and out are attached to the end
of the turbine shaft. The shaft ends of the flyweights contact the end of a governor,
which is free to move to the left or right, but is also acted upon by a counterspring. A
governor valve, or steam inlet valve, is mounted at the inlet of the turbine. It is
connected to the external steam supply line. The valve disc is double seated and has a
stem that extends out of the valve casing. A lever, connecting the valve stem to the
governor rod, is pinned and is free to pivot on a fixed fulcrum. This allows movement
in the governor rod to be transmitted to the valve stem.
Rotation of the turbine shaft causes the flyweights to pivot outwards due to centrifugal
force. The greater the speed of rotation the greater the centrifugal force and the further
outward the flyweights move. Movement of the flyweights causes movement of the
governor rod which causes movement of the governor valve.
Page 100
Figure 21
Mechanical Governor
The operation of a simple centrifugal mechanical governor is shown in Fig. 22. If the
load on the turbine increases, it slows down slightly. This causes the flyweights to
move inwards (due to less centrifugal force) and the governor rod moves to the left due
to the force of the counterspring. The lever pivots at the fulcrum and the lower end
moves to the right, thus opening the governor valve further. As more steam enters the
turbine, the speed begins to increase. The flyweights move outwards again until the
system becomes balanced at the set speed under the new load.
The disadvantage of simple mechanical governors is they have a high-speed droop,
usually around 10%. They are not suitable for large machines or where control must be
extremely accurate. Within limits, changing the pivot point at the fulcrum can reduce
the effects of droop, so the governor rod movement has more affect on the governor
valve movement.
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Figure 22
Simple Centrifugal Mechanical Governor
Mechanical-Hydraulic Governors
The mechanical-hydraulic governor has a pilot valve and a hydraulic amplifier. This
arrangement removes the direct linkage of the flyweights to the governor valve. The
flyweights position an oil pilot valve that admits high-pressure oil to a piston that moves
the governor valve. The advantage of the design is that the mechanical losses of the
governor are greatly reduced. The flyweights require less force to position the pilot
valve. The pilot provides the power to move the governor valve. The droop of this
governor is reduced to almost zero.
Fig. 23 is a diagram of a mechanical-hydraulic governor. Oil, at approximately 500 kPa,
is continuously supplied to the centre of the pilot valve. At normal speed, the pilot valve
covers the oil ports to the amplifier cylinder so that oil cannot enter or leave the
cylinder. If the load drops and the turbine speed increases, the flyweights move
outwards. This pulls the pilot valve upwards, admitting oil to the top of the cylinder
while allowing oil to drain from the bottom of the cylinder. The piston moves downward
forcing the steam valve to close.
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As the steam valve closes, the turbine speed decreases and the flyweights move inwards.
At normal speed, the pilot valve returns to the central, or neutral, position and the
turbine continues to operate at the set speed under the new load. Conversely, if the
turbine load increases and the turbine speed drops, the pilot valve admits more oil below
the piston causing the governor valve to open.
Figure 23
Mechanical-Hydraulic Governor
Mechanical-Hydraulic Governor Systems
A complete mechanical-hydraulic governor system is shown in Fig. 24. It demonstrates
how components relate to each other to provide a complete governor system. Referring
to the diagram, the turbine shaft drives a main, gear-type oil pump which supplies the
hydraulic oil pressure to the various governor components. An electric motor drives an
auxiliary oil pump which provides oil pressure during start-up of the turbine, until the
main oil pump can provide sufficient operating oil pressure.
Before start-up, the overspeed trip assembly is manually re-latched so that the oil trip
valve B is open, allowing oil pressure and flow to the other governor components. This
includes the turbine stop valve which is held open by the pressure under the operating
piston in cylinder C.
When the turbine is operating steadily, the spinning flyweights take a position balanced
by their counterspring. Flyweight movement controls the position of a plunger sliding
within sleeve G, which is part of the servo, or speed adjuster. The relative position of
the plunger and the sleeve determines the opening of the oil ports in the sleeve.
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High-pressure oil goes directly to the pilot valve K in the control oil cylinder. The pilot
valve regulates the oil pressure below the throttle valve cylinder J increasing pressure
when the speed is high. The position of the throttle valve responds accordingly.
The piston in the cylinder H determines the position of the moveable governor fulcrum
which affects the droop, proportionally, and speed control of the governor. Oil to this
cylinder is taken from the main oil supply, through valve F. The pressure in the line,
and therefore the pressure below piston H are determined by the position of the oil ports
at G in the servo. Adjusting the handwheel L changes the servo port openings causing
more or less oil to be drained, affecting the pressure to cylinder H and causing the speed
of the turbine to change. The movement of L may be done manually or it may be
activated by a small electric motor with remote control.
In an overspeed situation, the overspeed trip closes the oil supply cylinder B. This
causes all oil pressure to be lost beneath the trip valve and the throttle valve. The
turbine comes to a quick stop due to immediate loss of the steam supply.
Figure 24
Mechanical-Hydraulic Governor System
Electronic-Hydraulic Governors
Electronic-hydraulic governors use a combination of electronic and hydraulic controls.
The turbine control console contains all the controls necessary for starting, accelerating,
and loading the turbine and for controlling the extraction steam flows and pressures if
applicable.
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Referring to Fig. 25, the speed measuring device is a permanent magnet generator. It
produces an electrical output signal that is amplified and compared to a reference signal
by the computer in the control console. The difference is then amplified and applied to a
servo-valve, which hydraulically positions the servo-rams, moving the steam valves and
controlling the steam flow. The valve position is measured and fed back to the control
console, providing more exact control. Provisions are made for on-line servicing of the
computer circuit cards while the turbine is carrying load.
Electro-hydraulic governor systems use a separate fluid power unit to provide highpressure hydraulic oil to operate the servo-rams. The fluid power unit supplies hydraulic
oil at pressures in the range of 8 200 to 11 000 kPa.
Figure 25
Electro-Hydraulic Governor System
Fig. 26 shows an example of a basic electronic governor system for a turbine generator.
The actuator controls the pilot valve to readjust the position of the steam control valve
which maintains the desired speed as the generator load changes. The force to move the
throttle valve is usually hydraulic power acting through the actuator.
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Figure 26
Electronic-Hydraulic Governor System
PRESSURE SENSITIVE GOVERNORS
Pressure sensitive governors control a steady backpressure at the steam exhaust (outlet)
of the turbine. They may also control the extraction steam pressure part way through the
turbine. The extracted steam is discharged at a controlled pressure from that point.
There is a combination of speed and pressure control to assure relatively steady turbine
operation.
Backpressure Governing
Backpressure governing uses a pressure sensing element on the line from the turbine. A
set-point is entered into the controller which adjusts the position of the inlet steam
throttle valve. If the pressure is low, the throttle valve opens to admit more steam and
raise the exhaust pressure. If the pressure is high, the throttle valve closes to reduce the
pressure. It is used in processes where the exhaust steam from the turbine is used for
heating and where the pressure must be steady to ensure good heat control.
The efficiency of the backpressure turbine is very high because there are no exhaust
steam losses. The disadvantage of this system is that the load output of the turbine is
completely dependent on the demand for process steam.
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Extraction Governing
Process steam is supplied by extracting steam, at a controlled pressure, from
intermediate stages of a turbine. The control systems for extraction turbines are
complex and allow changes in the turbine load without affecting the steam extraction.
They also allow changes in the quantity of steam extracted without affecting the turbine
output.
A schematic of such a system is shown in Fig. 27. When the extraction steam demand
increases, the extraction pressure decreases forcing the pressure regulator piston
downwards. This moves point G down. Since point D is kept stationary by the speed
governor, the linkage makes point F move the extraction valve down. Point E moves the
steam inlet valve up. Less steam then passes through the extraction valve, increasing the
flow of extraction steam. The pressure remains constant.
As the load on the turbine increases, the speed decreases and the speed governor forces
point A downwards. Since point B is fixed and point G is held stationary by the
pressure regulator, points C and D move upwards. Points E and F move their respective
valves upwards. More high-pressure steam is admitted. The extra steam flows via the
more open extraction valve to the low-pressure stages of the turbine, resulting in
increased load with no change in the extraction flow and pressure.
Figure 27
Combined Speed and Pressure Governor
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Page 108
Objective 8
Describe the purpose and design of steam turbine stop
valves and control valves.
TRIP AND THROTTLE VALVES
Trip valves, used to provide a positive isolation of the turbine steam supply, are always
either fully open or closed. Throttle valves are adjusted as needed to control the turbine
speed or load. All turbines require trip and throttle valves to operate safely. They also
may have a combined trip and throttle valve. Trip and throttle (T/T) valves find
applications in the following types of turbine arrangements:
• Single-valve
• Multi-valve
Single-Valve Turbines
In a single-valve turbine, all the steam flows through a single governing or throttling
valve to the turbine nozzles. Changing the position of the throttling valve varies the
steam flow and the pressure of the steam flowing to the turbine nozzles.
Trip and throttle valves have two separate and distinct functions. When a safety device
such as an overspeed governor manually or automatically trips the trip and throttle
valve, it acts as a quick-closing valve. The emergency trip drains the oil causing the
servomotor to shut the steam valve. A manual throttling or block valve is used to bring
the machine up to minimum governor speed and to totally block the steam in after
shutting down. The throttling valve is not a 100% tight shut-off valve. The valve in Fig.
28 acts as a throttling and a trip valve.
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Figure 28
Double-Seated Steam Valve
The trip and throttling valve can also operate as a hand throttle valve for starting and
bringing the turbine up to speed. An example is shown in Fig. 29. It may be operated
by hand using the handwheel on top of the actuator or by a motor actuator which opens
or closes the valve. The trip hook or latch is used to trip the valve shut. When it is
tripped shut, the valve must then be completely closed to be able to re-latch the trip
mechanism.
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Figure 29
Trip/Throttle Valve
Multi-Valve Turbines
Fig. 30 shows a section through the steam chest of a large reaction turbine containing a
shut-off or trip valve and two throttle valves. The first throttle valve controls the
admission of steam to the turbine to about 80% of maximum load. The second controls
the admission of steam through the bypass for the remaining 20%.
The trip valve is sometimes called the emergency stop valve. It is opened wide at startup
and oil pressure keeps it in the open position. Spring pressure opposes the oil pressure
and tries to shut the valve. In an emergency condition such as machine overspeed, the
oil pressure is released and the spring closes the valve. The throttle valves are the
balanced or “double seat” type. Steam flows past both the upper and lower seats
eliminating forces tending to thrust the valve shut.
A steam strainer is fitted around the trip valve, and the valve spindles are sealed against
leakage with metallic labyrinth bushings. The steam chest is separate from the turbine
casing.
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Figure 30
Steam Chest with Stop and Throttling Valves
When a turbine has separate trip and throttle valves, the steam always goes through the
turbine stop valve before going through the throttling or governor valves. Fig. 31
illustrates the separate stop valve and control valve of a steam turbine in a fossil fired
generating plant. The assembly is separate from the turbine casing and is welded to the
steam piping on the inlet and the steam chest on the outlet. Both valves are operated
hydraulically and fit into the governor oil system of the steam turbine. The stop valve
must be open to allow oil pressure to the stop valve and control valve. The turbine
control valve is used to bring the turbine up to operating speed. The governor valves
then begin to close or take over speed control as the turbine speed increases. The speed
at which the governor takes control is called minimum governor speed. The governor
assembly controls the throttle valves and thus the steam flow to the turbine. The speed
adjustment on the governor controls the turbine speed when the turbine is on governor
control.
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Figure 31
Turbine Trip and Governor System
Page 113
Page 114
Objective 9
Describe the purpose and design of steam turbine grid
type extraction valves.
GRID TYPE EXTRACTION VALVES
Grid type extraction valves are placed inside the turbine casing after the stage that the
steam is extracted from. It controls the flow of steam to the remainder of the turbine. An
example of a grid extraction valve is shown in Fig. 32.
The valve consists of a ported stationary disc and a ported grid that rotates. When the
openings in the disc and the grid coincide, the valve is open and a full flow of steam
passes to the remainder of the turbine. When the grid is rotated from the fully open
position, the ports in the disc are partially covered by the grid. The steam flow is
restricted and the desired pressure maintained. A pilot valve, operated by a pressure
governor, controls the oil or steam supply pressure to either side of the operating piston.
The operating piston rotates the grid valve with a gear and teeth. The linkage from the
pressure governor is interlocked with the speed governor. Changes in the rate of steam
extraction do not interfere with the turbine speed.
Figure 32
Grid Type Extraction Valve
Page 115
A cutaway view of a grid type extraction valve is shown in Fig. 33.
Figure 33
Grid Type Extraction Valve Construction
Plant process or heating needs may require that steam is extracted at more than one
pressure. An example of a steam turbine with two extraction pressures is shown in Fig.
34. Steam passes through the admission valve and then through the first stages of the
turbine. Steam is bled off upstream of the first extraction grid valve. The steam that
passes through the first grid valve passes through more turbine blading. More steam is
bled off upstream of the second extraction grid valve. The remaining steam passes
through the second extraction grid valve and the remaining turbine blading. It exits the
turbine blading and enters the surface condenser.
Figure 34
Turbine with Two Grid Type Expansion Valves
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Objective 10
Describe the purpose and design of steam turbine
casing pressure relief systems including rupture
diaphragms.
TURBINE CASING PRESSURE RELIEF SYSTEMS
Some manufacturers fit rupturing diaphragms to the turbine exhaust branches. They are
designed to protect the condenser and LP turbine against overpressure. If over pressured
they rupture or blow out. Fig. 35 shows a condensing turbine with a relief diaphragm at
the top of the exhaust. Fig. 36 shows steam flowing out the rupture diaphragm on a lowpressure casing. The rupture diaphragms protect the casing as well as the condenser. The
pressure can reach rupture pressure if the condenser is not functioning properly. Causes
of condenser malfunction are air leaks or loss of cooling water.
Figure 35
Condensing Turbine with Relief Diaphragm
Page 117
Figure 36
Rupture Disc Test on LP Casing
Page 118
Objective 11
Describe the purpose and design of steam turbine
overspeed trips.
MECHANICAL OVERSPEED TRIP SYSTEMS
The mechanical overspeed trip on a steam turbine is an integral part of the governing
system. It prevents steam from entering the turbine if the speed becomes dangerously
high. The mechanical overspeed trip gear is generally located at the front end of the
high-pressure turbine shaft and is designed to shut off the steam supply to the turbine.
The trip speed is usually 10 to 12% above the standard operating speed.
A basic trip bolt in the normal operating position is shown in Fig. 37. It consists of a
weighted bolt that is held inside a specially made hole in the shaft. A spring is held in
compression to keep this trip bolt inside the shaft during standard operating conditions.
Figure 37
Trip Bolt
If the turbine shaft reaches the overspeed setting, the spring compression is overcome
and the bolt will be thrown out by centrifugal force, as shown in Fig. 38.
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Figure 38
Overspeed Trip Position
Fig. 39 shows a mechanical overspeed trip system using a mechanical linkage to control
the flow of steam to the turbine, during standard operating conditions.
Figure 39
Mechanical Overspeed Trip System (Turbine Normal Operation)
Fig. 40 illustrates an overspeed situation (movements are exaggerated for clarity).
Using the trip lever, the overspeed trip can be manually operated at any time.
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Figure 40
Mechanical Overspeed Trip System (Turbine Tripped)
The overspeed trip, shown in Fig. 41, shows clearly the operating principle of all
overspeed trips for turbines with hydraulic governor systems. The spring-loaded
tripping bolt, located in the turbine shaft, has the centre of gravity slightly off the centre
of the shaft in the direction of the bolt head. The nut, at the end of the bolt, provides a
stop for the bolt in the tripped position and for the tripping speed adjustment. During
standard operation, the main spring holds the trip rod against the tripping lever. Piston
A closes the oil drain and the high-pressure oil passes between pistons A and B, to the
stop valve. Note: The gear is shown in the set position.
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Figure 41
Emergency Overspeed Trip
When the turbine speed increases to the trip setting, usually 110% of operating speed,
the following occurs:
1. Centrifugal force overcomes the bolt spring tension
2. The bolt moves to the trip position and strikes the tripping lever
3. The trip rod is unlatched
4. The main spring moves the rod to the tripped position
5. Piston A opens the stop valve oil port to drain
6. Piston B closes off the high-pressure oil inlet port
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Fig. 42 shows a bolt type overspeed trip located in the high-pressure turbine shaft end.
The bolt is eccentric in the shaft, but the spring holds it in position at normal speeds.
The oil supply, maintaining the steam valves open, passes through ports P and U in the
standard position. At an overspeed condition, the pin (bolt) trips the latch R. When R is
tripped, the trip relay spring lifts the trip relay piston so that P is closed off and U is
open to drain.
Figure 42
Overspeed Trip Gear
ELECTRONIC OVERSPEED TRIP SYSTEMS
In Fig. 43, the turbine shaft contains a notched gear wheel. Inductive sensors, also
known as magnetic speed pickups, are mounted in or on the turbine casing. As the gear
teeth pass the sensors, the principle of magnetic induction generates an AC voltage that
can be read by the ECM (Electronic Control Module), which contains pulse-counting
sensors.
These units then convert the electronic pulse signals to revolutions per minute for
calculating the turbine shaft speed. Some steam turbines’ overspeed trip systems,
installed with three magnetic speed pickups, require that two out of the three sensors
agree the unit has reached the overspeed condition before a trip is initiated.
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Figure 43
Magnetic Speed Pickup Sensor
When the measured speed reaches the setpoint, an action is initiated to shut the
emergency stop valve. Referring to Fig. 44, electronic signals are sent from the
electronic control module to the trip block. If the electronic control module receives
input from 2 out of 3 speed pickups that there is an overspeed condition, it will then shut
off the supply of hydraulic oil that maintains the stop valve in an open position.
Another signal is sent from the electronic control system to close the control valve and
stop the flow of steam to the turbine.
Figure 44
Electro-Hydraulic Control System
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Objective 12
Describe the purpose and design of steam turbine
supervisory equipment.
STEAM TURBINE SUPERVISORY EQUIPMENT
Steam turbines come in many sizes from drivers of small pumps and fans to multi-case
power station generator drivers. They range in output from a few kW to over 1000 MW.
The smallest turbines may have a little instrumentation such as a few temperature and
pressure gauges. They may have vibration monitoring that is monitored in the control
room. Some turbines are started and stopped from remote locations.
The larger a turbine, the more likely it is to have extensive supervisory equipment to
monitor its operation. Fig. 45 illustrates the turbovisory equipment connected to a
turbine and generator set. This schematic represents a layout with separate panels or
cubicles, which can be located next to the machine in the field or in the control room.
The recorders and indicators can also be field or control room mounted. All of the data
from the machine may also be fed into a digital control system. Vibration monitoring
input is often sent into a vibration monitoring system to analyse readings and to predict
problems.
Figure 45
Turbovisory Equipment Schematic Diagram
Page 125
Fig. 46 illustrates the locations of instruments on the three cases of a large turbine. The
bearings for each rotor normally have vibration and temperature probes. Thrust bearings
have temperature (oil and/or pad) indications. High-thrust bearing temperatures indicate
high-thrust loads. There are eccentricity coils for the HP (high pressure) and IP
(intermediate pressure) rotors located next to the thrust bearings. The differential
expansion indicators for the HP and IP cases are located at the opposite end of the shaft
from the thrust bearings. Differential expansion refers to the relative difference in
expansion between the rotor and the turbine case. If excessive, it will lead to the rotor
blades rubbing the turbine diaphragm. The thrust bearing is a fixed location and the
shaft movement is measured as far as possible from the thrust bearing.
Figure 46
Layout of Supervisory Equipment
The expansion of the HP and IP rotors is shown in Fig. 47. The HP case has a thrust
bearing and a thrust collar at the front of the machine. The bearing pedestals have
sliding feet for expansion and indicators to monitor movement. The cylinders are
anchored at the exhaust end and expand towards the inlet. The flexible coupling between
the two rotors takes up the relative movement of the shafts. The arrows in Fig.50
indicate expansion of the cylinders and rotors.
When starting up the machine, careful monitoring of expansion is essential. Operators
soon know the positions of the machine when cold, when starting up, and when in
standard operation.
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Figure 47
Expansion of IP and HP Cylinders
Vibration Monitoring
Vibration monitoring systems are often separate from the remainder of the monitoring
equipment on large machines. The turbine in Fig. 48 has a computer based monitoring
system. Vibration sensors on the machine send signals to the transducer panel. Signals
from the transducer panel then go to the vibration monitoring input unit. Digital signals
are fed to the vibration monitoring computer.
The computer system is used to analyze the vibration data and maintain a history on the
equipment. The system in the graphic also has a remote service station which can be
used by engineers and or managers to view and analyze the vibration data.
Page 127
Figure 48
Vibration and Monitoring System
Page 128
Chapter Questions
1. What is an adjusting gear used for?
2. When is a turning gear used? When starting up a turbine, when is the turning gear
shut off?
3. Describe the difference between lubrication oil and jacking oil. What is governor oil
used for?
4. Explain static and dynamic balancing. When is each type used?
5. Describe the two distinct functions of a trip and throttle valve.
6. What are the three methods of speed-sensitive governing used for steam turbines?
7. What is coupling “lock up”? What types of problems does a locked coupling cause?
8. When are speed reduction gears used? List some applications using speed reduction
gears.
9. Describe a steam turbine grid type extraction valve.
10. List five variables that are monitored by supervisory equipment. What is differential
expansion?
11. Sketch and describe a magnetic speed sensor pickup used on an electronic turbine
overspeed trip system
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Page 130
Steam Turbine Operation and
Maintenance
Learning Outcome
When you complete this learning material, you will be able to:
Discuss procedures for operation and maintenance of a large steam turbine.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Describe the detailed hot and cold start-up procedures for a large steam turbine,
including safety precautions.
2. Describe the detailed shutdown procedure for a large steam turbine including
safety precautions.
3. Explain what checks are performed on a large steam turbine during normal
operation.
4. Sketch the flow of steam and condensate through a condensing steam turbine and
a non-condensing steam turbine.
5. Explain the preventive maintenance requirements for a large steam turbine.
Include shaft alignment, bearings, clearances for thrust, blades, shaft seals,
correction of blade fouling, erosion and cleaning.
6. Describe the purpose of and procedure for static and dynamic balancing.
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Page 132
Objective 1
Describe the detailed hot and cold startup procedures
for a large steam turbine, including safety precautions.
STEAM TURBINE START-UP PROCEDURES
Startup procedures for steam turbines vary according to the:
• Type of turbine
• Manufacturer’s recommendations
• Size of the turbine
• Length of time the turbine has been shutdown
The startup procedure described in this module is a generic procedure with steps that can
be applied to most steam turbines. As each turbine installation is different it is important
to follow the procedures for that turbine as set out by the manufacturer and the owner.
PRE-STARTUP INSPECTION
Before starting any turbine, a thorough inspection of the turbine and related equipment
is completed. The inspection commences by checking all applicable documentation of
the turbine and its auxiliaries. For example, all work that tradesmen have done is
completed and signed off. Locks and tags on auxiliary equipment must be removed. At
this stage the control operator checks all controls and valves to make sure they are
functioning properly. For example, control valves are stroked and checked in the field
to verify proper movement.
Any notes, logs, or readings that are available from other recent start-ups are reviewed.
This historical data helps to predict the timing of the startup sequence and the turbine’s
behaviour regarding vibration, expansion, and critical speeds.
During the field check of the equipment, the field operator verifies that all valves are in
the proper position for starting up. Other areas to check include:
• Pressure gauges and instruments are in the ‘ready to run position’ with sensing
valves open and drains shut.
• Main steam line traps and vents are open to warm up the steam piping.
• Equipment is clean and no scaffolding or debris from repairs left around the
equipment. Any debris or insulation is cleaned up before starting the equipment.
• Auxiliary equipment such as fans, pumps, and lube-oil systems are ready to run.
The quality and quantity of the lube oil is verified.
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INSTRUCTIONS FOR STARTING
Surface Condenser
Start the circulating cooling water pump and open the condenser circulating valves.
Ensure that all pipes and waterboxes are clear of air and full of water. Ensure the
surface condenser vacuum breaker is closed and then open the supply of sealing water.
The water valve need only be opened far enough to provide a positive water blanket
across the seal.
Start pulling vacuum with the air ejectors and the hogging ejector (quick start exhauster)
or vacuum pump. The cooling water for the ejectors can be cooling water or steam
condensate. If it is condensate, the ejectors require that the extraction pumps are
operating before the ejectors are started.
Apply steam or sealing water to all turbine shaft-glands to aid in raising vacuum. Build
up the condenser vacuum to about 500 to 650 mm. Excessive use of gland sealing steam
can produce local over-heating of the turbine shafts and lead to vibration problems. Care
is taken to regulate gland steam to the minimum necessary for complete sealing.
Excessive sealing water for water-sealed glands can have the opposite effect, quenching
the turbine shaft. The water-sealed glands will not seal properly until the turbine is
spinning at close to half its rated speed, and that this will limit the vacuum that is
attainable.
Lubricating Oil System
Check oil system valves and start the auxiliary oil pump. Check the oil system flows and
temperatures. If the oil is too cold, start the heater. Verify all bearings are supplied at the
correct pressure and that the control system oil supply is at normal pressure. Start the
jacking oil pump to ease the shafts on the bearings before starting the barring gear.
Turning Gear
Engage and start the turning or barring gear to run the rotors. The time the machine is
barred varies with the temperature of the turbine, from 5-30 minutes for a cold machine
to 1 hour plus for a hot machine.
Drains
Set all drains on the turbine and steam supply line. Then crack open the bypass around
the main steam inlet valve to warm through the steam lines to the turbine stop valves.
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Condensate Pump
Start the condensate or extraction pump and then open the condenser recirculating
valves so that the ejector condensers have a sufficient supply of condensate as cooling
water while the turbine is being loaded.
Emergency Trip
The emergency trip system should be tested before admitting steam to the turbine. The
turbine stop valves and their bypasses should be shut. Then the emergency stop valves
are opened fully to their normal operating position and closed automatically, using the
trip-gear. Finally, the emergency valves are set full-open before the turbine run-up
commences. Some turbines have a combined stop and emergency valve. In this case, if
there is pressure in the steam lines, the valve cannot be opened without spinning the
turbine. Therefore, the trip gear cannot be tested at this time.
TURBINE STARTUP
Slow-Roll the Turbine
Open the stop valve (or its bypass) sufficiently to start the turbine rolling, and then
restrict the steam flow keeping the turbine speed in check.
Stop the Barring Gear
The barring gear can be disengaged and shut down. The turbine should be accelerated
up to about 300 rev/min in two or three minutes to establish an oil film and held at this
speed for a time depending upon the manufacturer’s run-up program.
Hold Speed at First Warm-up Speed
Turbines, especially those with no barring gear, are slow-rolled at 300-500 rev/min.
Rotate at this speed for sufficient time to provide even warming and removal of any
distortion of the rotors that were developed after the last shutdown. This may take 15-30
minutes or longer.
Increasing Speed
Machines turned regularly during their cooling-out period after shutdown, can be run up
from rest to about two-thirds of normal full speed without pause, at 300 rev/min. The
speed is increased over 15-20 minutes.
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Running, at a critical speed, results in vibration of the shaft. Any object made of an
elastic material has a natural period of vibration. At the speed at which the centrifugal
force exceeds the elastic restoring force, the rotating element will vibrate as though it
were seriously unbalanced. If it runs at that speed (critical speed) without restraining
forces, the deflection will continue until the shaft fails.
Critical speeds should be passed through without delay. Operations personnel know
where critical speeds are from experience with the machine and by the manufacturer’s
specifications. The critical speeds are sometimes noted while test running rotors during
dynamic balancing.
During run up, the operator should check the following parameters:
• Vibrations
• Bearing metal temperatures
• Temperature differences between turbine casing top and bottom halves
• Oil temperatures downstream of the oil cooler
• The main shaft-driven oil pump should come into operation and the auxiliary
pump shut down
• Supervisory instruments are watched for signs of excessive shaft distortion or
displacement
• Differential expansion between the turbine rotor and casing due to thermal
expansion
Increasing Speed to Minimum Governor
The turbine speed is slowly increased to minimum governor. As the minimum governor
speed is reached, the turbine governor comes into operation by closing the main steam
control valve to control the speed. The governor is used to increase the speed to the
desired operating speed. With the machine at minimum governor, the stop valves are
opened fully. The machine is operated at minimum governor until operations and
maintenance personnel are satisfied the machine is ready to be loaded.
Note: During run-up a certain amount of vibration is expected at the critical speed or
speeds. If it does not smooth out after passing through a critical point, the machine
speed is reduced until the vibration disappears. If repeated attempts fail to smooth out
the vibration the machine may have to be returned to 300-500 rev/min for heat soaking.
The barring gear may also be used in a further attempt to secure even heating of the
rotors. Excessively low oil temperature may be a cause of high vibrations.
Page 136
TESTING OVERSPEED TRIPS
Overspeed Trips
When the machine has reached normal running speed and is under control of its
governor, the overspeed governor trip operation is tested. Testing is carried out so that
the steam supply to the turbine is controlled at all times. This is accomplished using a
hand-controlled bypass valve. The amount of steam available is kept at a level that does
not allow the machine to reach a dangerous speed if automatic equipment fails.
The overspeed trip should operate and limit the speed rise to a maximum of 110% of
operating speed. Periodic checks are made to prove that this equipment operates freely.
Overspeed trip checks are tested at two different points:
1. It can be tested when the machine is coming off load and about to be shut down.
At this time, the extra strains by over-speeding are imposed upon a thoroughly
warm machine. The stresses are minimized and if a failure occurs, maintenance
time is available to repair the mechanism.
2. The test is often carried out during startup. The safety of the machine is proved
before it is put online. Chances of incorrect settings of the equipment during the
shutdown are guarded against.
When the trip mechanisms have been taken apart or repaired during an outage, the trip
has to be tested before putting the turbine back on-line. This applies to all sizes of
turbines.
PREPARING FOR LOAD
Lubricating Oil Coolers
Coolers are put into service when required. The cooling water valves are adjusted or the
automatic controller is set to maintain the oil temperature within the manufacturer’s
specifications. This is usually about 45-50°C at the turbine bearings. Care should be
taken not to overcool the bearing lubricating oil at any time. Cold oil to the bearings
may cause turbine vibrations.
Bearing Oil Pressures and Temperatures
The lubricating oil must be up to operating temperature before the machine is loaded.
Bearing drain temperatures indicate bearing condition. High temperatures indicate high
loads. Thrust bearings run hotter than journal bearings.
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Condenser Vacuum
The vacuum should be at the normal operating levels. If this reading cannot be obtained,
the source of air leaks needs to be determined. This is done by taping flanges that have
been apart or by leak detecting equipment, such as ultrasonic listening devices. Steam
supply to glands should be adjusted. Water can be put on glands.
Steam Drains
Drains on the turbine and piping can be cut back and closed as the piping reaches
operating temperature. Steam traps are left in service.
Condenser (Condensate) Recirculation Valves
Condensate is recirculated as the machine is run up. The hot well level is placed on
automatic control. The steam condensate may have to be dumped or polished until the
quality is acceptable for the steam generator. High conductivity and iron levels are
common after a shutdown.
Turbine Spindle Thrust Adjustment
The turbine spindle thrust is adjusted when the machine is up to full operating
temperature.
LOADING THE TURBINE
While loading the turbine a careful watch must be kept on:
• Bearing temperatures
• Signs of vibration
• Rubbing
• Unusual noises
The operator’s experience and judgment is relied upon to evaluate signs of possible
trouble.
Many instruments and on-line analyzers are available and used to assist in monitoring
the turbine as it is loaded. Supervisory equipment indicates shaft vibrations, differential
expansion and eccentricity.
The turbine is loaded in steps or blocks as the steam is available. The water and steam
quality may limit the load and pressure of some units. A power generation unit is
brought up in load as the power is required to satisfy the load on the grid.
The graphs in Fig. 1 show turbine startup curves for different turbine downtimes. The
longer the downtime, the colder the turbine casings and rotors. They require more time
to be heated to operating temperatures. The curves are for a Siemens 360 MW reheat
turbine operating with a steam temperature of 540°C.
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The 8 hour start is a typical hot start, a warm start is the 48 hour curve, and the 150 hour
start is a cold startup. The steam pressure reaches full operating pressure before the
steam temperature is at full operating temperature for all starts. The steam pressure and
load curves are similar, because the machine is at 100% load when the steam pressure
reaches 100%.
Figure 1
Steam Turbine Start-up Curves for Various Shutdown Times
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Page 140
Objective 2
Describe the detailed shutdown procedure for a large
steam turbine including safety precautions.
STEAM TURBINE SHUTDOWN PROCEDURES
Shutdown procedures for steam turbines vary according to the:
• Type of turbine
• Manufacturer’s recommendations
• Size of the turbine
• Length of time the turbine has been operating
This shutdown procedure is a generic procedure with steps that can be applied to most
steam turbines. As each turbine installation is unique it is important to follow the
procedures the manufacturer and the owner have set out for that turbine.
Preparations for Shutdown
There are a variety of reasons why a turbine is shutdown. It may be for repairs of
equipment not directly related to the turbine, repairs to the turbine or its auxiliaries, or it
may even trip off-line. If the turbine is taken off-line to work on it or its auxiliary
equipment, the turbine is taken off-line slowly and the turbine and lube-oil cooled off.
When the turbine is to be restarted quickly, the turbine may be left in a hotter condition,
making for a faster startup. A quick check is made of auxiliary equipment and work to
be performed while the turbine is off-line.
Shutting Down the Turbine
The turbine load is slowly decreased, keeping an eye on vibrations and lube-oil
temperatures. Excessive vibration may require shutting down more quickly or tripping
the turbine. When decreasing load prior to shutting down the machine, the following
operations are carried out:
1. The thrust-adjusting gear is set for maximum clearance (where this gear is
fitted).
2. Open the condenser (condensate) recirculating valves to maintain sufficient flow
to cool the air ejector condensers.
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When all load is off the turbine, the main alternator breaker is opened. Operation of the
overspeed trips is checked, if required, and the turbine steam stop valves are then closed.
Shutting down the air ejectors or air pump allows the vacuum to fall. A flow of
gland-sealing steam is maintained until the vacuum is near zero. This prevents the
ingress of cold air to the shaft glands and minimizes shaft distortion. The steps taken
after the turbine is off-line are as follows:
1. Turbine casing steam piping drains are opened.
2. The auxiliary oil pump starts up as the turbine speed decreases.
3. When the turbine shaft stops, the barring gear is engaged and left running for the
recommended number of hours while the machine cools down.
4. In the absence of barring gear, usual with smaller machines, the shafts cool out
while standing still. It is particularly important that no steam leaks into the
cylinders at this time.
5. Cooling water valves to the oil coolers are closed as soon as possible to retain
heat in the oil for the next run-up.
6. Extraction pumps are shut down.
7. Circulating water to the main condenser is blocked in.
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Objective 3
Explain what checks are performed on a large steam
turbine during normal operation.
NORMAL TURBINE OPERATION
Once a turbine has been run up to speed and loaded, the steam temperatures and
pressures remain constant at each stage from inlet through to exhaust. The metal of the
rotors and cylinders is close to these temperatures and becomes stable. The expansion of
the cylinders and rotors ceases.
The stage pressures and temperatures are characteristic of the machine for each load.
The pressures and temperatures change with changes in load but are constant unless
some unusual condition develops. For example, if deposits from the steam begin to
gather on the blade surfaces, a gradual increase in frictional resistance to steam flow
occurs. The resistance to steam flow affects the stage pressure and temperature readings.
It is essential to keep records of pertinent temperatures and pressures to recognize a
diversion from normal values. A constant review of values is required because changes
often occur slowly and can easily be overlooked. Often computerized systems log daily
averages as well as maximum and minimum values. Checking back over previous
readings may indicate a long or short term trend.
One means of discovering trends is to set up a basis for comparison of the day-to-day
operating figures. At certain fixed loads, say 50%, 75% and 100% of full load with inlet
and exhaust conditions carefully set, readings are taken of the steam pressure and
temperature at various points on the turbine. Examples of temperature and pressure
points are the turbine stop valve, all stage pressures, and the exhaust back pressure.
Readings of spindle locations, vibrations from the turbovisory equipment, and
lubricating oil temperature and pressures are noted as well. The readings are taken
when the machine is in a known state of cleanliness and are repeated and checked
periodically. They are then used as standards of comparison and, if necessary, printed on
the daily log sheets.
Routine turbine operation on steady load consists of watching mechanical conditions
and temperatures, such as bearing oil pressures and temperatures. Monitoring for
unusual noises or vibrations is a constant process.
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Given steady inlet steam pressure and temperature, the steam conditions through the
machine do not vary noticeably. The exhaust vacuum changes often. It depends upon
the operation of the condenser air extraction equipment, the rate of air leakage into the
system, and the quantity and temperature of the condenser cooling water.
Operations personnel are prepared for any emergency situation in an operating plant.
Emergencies occur infrequently, but when they happen, they tend to be unexpected.
The effects of the emergency often camouflage its primary cause. The knowledge and
experience of the operating personnel are called upon to make speedy decisions. Errors
can be extremely costly.
The greater part of turbine operation will consist of normal day-to-day running. The
most important items at this time are the keeping of a daily log and maintaining the
general cleanliness of the machine. Both items are likely to be uninteresting and in
danger of being neglected but their value become immediately apparent in the event of
some fault developing in the turbine. Familiarity with normal log readings makes a
change very obvious, and a machine kept clean and free of oil drips, rags, etc. will have
a minimum fire hazard.
Daily Log
The items listed on the daily log will vary with the plant, but a typical set of readings
would give:
• Machine load
• Steam pressures and temperatures
• Lubricating oil pressures and temperatures
• Turbine expansion
• Vibration readings
• Condenser vacuum
• Condenser hotwell level and position of level control valve
• Circulating water pressure and temperatures
• Feed heater pressures and temperatures
• Ammeter readings for extraction pumps and feed pumps
• Notes on the oil coolers and air ejectors in service
• Normal positions of condenser circulating water valves
• Records of the steam flow to the machine and the make-up water passing to the
condenser.
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Objective 4
Sketch the flow of steam and condensate through a
condensing steam turbine and a non-condensing steam
turbine.
CONDENSING STEAM TURBINE
A steam turbine is classified as a condensing turbine if its exhaust steam is condensed in
a condenser. The condenser may be water cooled or air cooled. Often steam is extracted
or bled off the turbine at pressures required for feedwater heating or process heating.
Most steam turbine generator sets used in power stations are condensing types with up
to nine stages of feedwater heating. An example is shown in Fig. 2. It has high-pressure
(HP), intermediate-pressure (IP), and low-pressure (LP) turbine cases. The HP steam
pressure is 24.12 MPa and the main steam and reheat temperatures are 535°C. The
reheat pressure is 3.72 MPa.
Steam Flow
Referring to Fig. 2, steam flow begins in the boiler section of the steam generator. The
steam is superheated in the superheater section of the steam generator, before heading to
the HP casing of the steam turbine. There are bleed steam takeoffs on the HP casing for
feedwater heaters number 6 and 7. Some bleed steam is used for the turbine driven
boiler feedwater pump. The exhaust steam from the boiler feedwater pump is used to
heat the water entering the deaerating heater.
The steam leaves the HP casing and goes to the reheater section of the steam generator.
After reheating, the steam goes to the (IP) or reheat turbine. The reheat turbine exhausts
to the LP turbine. Some steam is taken off the reheat turbine exhaust for feedwater
heating – heater number 4. The LP turbine exhausts to the surface condenser.
Steam is bled off the LP turbine for the first three feedwater heaters. Steam from the LP
case is condensed in the surface condenser. The latent heat of the condensing steam is
passed to the cooling water.
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Condensate Flow
The condensate flow from the surface condenser (Fig. 2) is pumped by extraction pumps
through feedwater heater 1, 2, 3 and to the deaerating heater (deaerator). The steam
condensate from the condensing steam in the heaters flows back to the surface
condenser. The boiler feedwater pumps return the condensate from the deaerator
through the HP feedwater heaters and into the steam generator. Condensate from the
shell side of the HP heaters is routed to the deaerator.
Figure 2
Condensing Turbine with 7 Stages of Feed Water Heating
NONCONDENSING STEAM TURBINE
Noncondensing steam turbines are not connected directly to a surface condenser. They
exhaust at a higher pressure, such as 350 kPa. This LP steam is used for heating or
process applications. Steam at higher pressures is often bled off or extracted from the
turbine. A noncondensing steam turbine cogeneration cycle is shown in Fig. 3. It has a
single case steam turbine connected to the generator, which has a rated output of 66.9
megawatts.
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Steam Flow
Steam from the steam generator steam drum (Fig. 3) flows through the superheater
section and exits at 14.03 MPa and 538°C. This steam powers the steam turbine which
exhausts at 760 kPa and 177◦C. Steam for process use is extracted at 4.48 MPa and 930
kPa. Bleed steam is also taken from the turbine casing at 3.1 MPa, 1.95 MPa, and 930
kPa. The bleed steam is used for the 3 stages of feedwater heating.
Condensate Flow
Referring to Fig. 3, the condensate flow to the deaerator consists of makeup (replacing
process losses and boiler blowdown). The boiler feedwater pump is used to deliver
condensate through the feedwater heaters and into the steam generator. The condensate
from the shell sides of the heaters is routed to the deaerator.
Figure 3
Non-Condensing Steam Turbine Cogeneration Cycle
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Page 148
Objective 5
Explain the preventive maintenance requirements for a
large steam turbine. Include shaft alignment, bearings,
clearances for thrust, blades, shaft seals, correction of
blade fouling, erosion and cleaning.
PREVENTIVE MAINTENANCE REQUIREMENTS
Large steam turbines can operate for long periods, even years, without being shutdown
for repairs. The scheduling of outages usually depends upon the service. For example,
many power generation companies shut down their turbine/generator units during the
seasons when load on the power grid is low. They want their machines in top shape for
peak generation periods, when an outage is very bad for business.
Turbines in chemical plants and refineries are down when the processing equipment is
down for its annual turnaround. Often turnarounds have been extended to periods of
two or more years. Preventive maintenance (PM) can be performed on an as available
basis.
Preventive Maintenance Timing
A new turbine is usually operated for one year or less before completing a PM on it.
This PM checks such things as:
• Bearing clearances
• Thrust bearings
• Coupling conditions and alignments
• Blade fouling
• Overall conditions
Any problems arising from vibration or temperature readings are also checked out. If no
serious problems are noted, an additional run of one year or more is acceptable. The
length between PM’s can be increased based on the condition of equipment.
The turbine manufacturer will recommend a maximum timeframe between PM’s. The
manufacturer will also recommend that the rotor or rotors be removed and checked out
or replaced after a certain length of time. This is usually a period such as 10 years or
even longer. The main steam stop and control valves are overhauled when the turbine
rotors are changed. Insurance companies also recommend maximum times for rotors to
be in service.
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Shaft Alignment
Because of the speed of the rotating masses and the large out-of-balance forces which
can appear as vibration, the alignment of a large modern turbine is done carefully during
construction. When a PM is done on the machine, the alignment of the rotors and
couplings is also carried out.
The general principle of alignment is that, assuming the coupling faces to be true with
the shafts, the shafts are aligned so that a continuous curve is formed, with their natural
deflections, from governor to exciter. This point is illustrated exaggerated in Fig. 4. The
shafts retain their natural deflection at any speed other than the critical speeds. The
adjustment of bearing positions to match this static deflection of the shaft provides
correct alignment.
Figure 4
Alignment Curve for Turbo-generator
It is not necessary to know the shaft deflection curve. Accurate measurements between
coupling faces and over the coupling periphery provide correct alignment. When equal
measurements are obtained using a clock gauge or feelers at four points 90° apart round
the coupling periphery at locations x and y, Fig. 5, then correct alignment can be
assumed provided that the coupling faces and periphery are “true” with the shaft.
Figure 5
Alignment Measurements at Coupling
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Two general causes of misalignment occur when:
• The axes of the two shafts may meet but may not be in a straight line, as shown
in Fig. 6
• The axes may be parallel but may not be in line, see Fig. 7
Figure 6
Axes Meeting but Out-of-line
Figure 7
Shafts Parallel but Out-of-line
Most manufacturers supply an alignment gauge for a particular machine which has a
plate with a gap to cross the coupling and two true edges accurately aligned, as
illustrated in Fig. 8. When applied across a coupling, if both edges are wholly in contact
with the shafts on each side, the correct alignment is established. Misalignment of the
type indicated in (1) and (2) above is revealed as in Fig. 8. The gauge can also be laid on
the horizontal joint to check horizontal alignment.
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Figure 8
Use of Alignment Gauge
Clearances
The efficient operation of a turbine depends to a large extent on the maintenance of the
correct clearances between fixed and moving elements. Excessive clearances cause
increased steam consumption, while reduced clearances may result in blade rubbing.
When a turbine is erected, the clearances are carefully set and a record is kept at the
plant. When the top halves of the casing are removed, the clearances should be checked
against the record. Care is taken to ensure that the rotors are in the running position
when taking measurements. Provision is usually made to move the rotor axially to a
position for lifting from and returning to the casing.
Particular care is necessary with the clearances at the velocity stages which are
frequently fitted to the HP end of impulse machines, as shown in Fig. 9. A thorough
check of clearances is essential if any replacement blades, nozzles or packing rings have
been fitted.
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Figure 9
Velocity Stage Clearances
Bearings
A thorough examination is made of bearings for:
• Wear
• Grooving of the bearing metal and shaft
• Loose bearing metal
• Correct contact surface
• Possible evidence of electrolysis
Modern bearings are of the spherically-seated type and their fit in the housing should be
checked for tightness and alignment. Adjustments are made if necessary.
The condition of oil orifices, including the area of HP jacking oil, oil throwers, baffles
and the cleanliness of all oil and water passages is checked. Bearing clearances are
measured and recorded. For clearances, a bridge gauge (Fig. 10) is used and the
measurement at X is compared with previous records.
Variations indicate bearing wear or settlement. A typical permissible clearance is 0.025
to 0.05 mm per 25 mm diameter of the journal bearing.
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Figure 10
Use of Bridge Gauge
Blade Fouling
Turbine blading must be clean if it is to produce the full designed output of the turbine.
Deposits that adhere to the blades decrease the turbine efficiency and output. They may
cause an outage or even mechanical damage if not removed.
These deposits develop from carryover in the steam from the boilers and are principally
sodium hydroxide (caustic soda) and silica. Caustic soda melts at 315°C and is soluble
in water. Therefore, it will deposit in areas in the turbine where the temperature is below
315°C and where the steam moisture content is insufficient to give a blade-washing
effect.
Silica vaporizes at pressures above 4150 kPa and is insoluble in water. Deposits of silica
may be spread through the turbine blading and also combines with the soluble deposits.
Deposits on turbine blades gradually reduce the steam passage area and consequently
increase the pressure drop through each of the affected stages. Comparison of stage
pressure drops with standard figures is used as an indication of blade fouling.
Removal of these deposits can only be achieved either with washing or mechanical
means. Washing can be carried out without dismantling the machine. Mechanical
cleaning requires the turbine covers to be lifted and the spindles removed. In either case,
prevention of carry-over is desirable.
Blade washing is usually done on a cold machine and at speeds of rotation not more than
25% of full speed. Moisture-laden steam is introduced through the stop valve with all
cylinder drains open and the condensate run to waste. Samples are taken of the
condensate and the procedure continued until these samples show a high degree of
purity.
Insoluble deposits are not removed directly by washing, though rapid changes in
temperature may crack and loosen them. Mechanical cleaning methods such as blasting
with a mildly abrasive substance are used for these deposits.
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Blading
The blading may have been washed while in service following steam consumption
checks or stage pressure changes which indicates fouling. Preparations are made for
complete cleaning during an overhaul. The cylinder covers are taken off and inverted,
the turbine spindles are lifted out and, where necessary, the top and bottom half of
diaphragms are removed from the cylinders.
Blading is inspected for evidence of corrosion, erosion and mechanical rubbing. Blades
are “dressed” as necessary and badly damaged sections are replaced.
In the LP stages, lacing wires must be rebrazed or replaced as necessary. Shroud bands
in high-pressure and intermediate-pressure stages should be inspected for signs of
rubbing and dressed up or replaced.
All blades are inspected for cracks in the blade or at the root, particularly in the LP
stages, using one of the proven crack-detection methods.
Packing Glands
During operation, an increase in the amount of steam required for sealing indicates
deterioration of the shaft glands. During overhaul, packing glands are cleaned,
straightened where necessary, and adjustments made to restore correct clearances.
Spring-loaded sections are usually set up and dressed to fit correctly. Gland steam
supply pipes, vent pipes and drainage holes are examined for cleanliness.
Diaphragms
Diaphragms are inspected for cracks and checked for distortion, erosion or rubbing. The
casing groove landings are checked to ensure that the diaphragms fit properly. The
nozzles are cleared of any deposits and the edges dressed.
Cleaning after Construction
On completion of erection of a new turbine-generator set, elaborate precautions are
taken to ensure the cleanliness of the system. Cleaning is just as important as
maintenance work on the turbine. Dirt, debris, scale and silica carried into blading,
glands and bearings from the boiler and piping systems cause considerable operational
troubles in steam turbines.
All accessible parts are well cleaned and all loose material removed. The lubricating
and control oil systems are thoroughly cleaned and then closed. If the feed heating and
condensing system have been opened, they are thoroughly hosed and flushed to waste
and the system is closed.
When welding has been completed on the main steam line, a steam blow is carried out.
This removes slag from the steam piping. The steam blow is completed by
disconnecting the steam piping from the turbine, directing the piping outside of the
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building and allowing steam to blow through. The strainers in the steam chest and the oil
supply lines are replaced with fine mesh for the first few weeks after steam blowing.
All auxiliaries are tested as soon as electrical and steam supplies are available. A trial of
the vacuum raising equipment is carried out. The turbine glands are sealed and vacuum
is pulled using the ejectors or vacuum pumps. The turbine and condenser system are
checked for air leaks.
The turbine is never started without adequate insulation and lagging on HP steam pipes
and cylinders which reduces the chances of distortion taking place. All temperature
indicators and pressure gauges are connected and operational.
Turbine operating methods vary slightly according to the particular machines involved.
Manufacturers issue precise instructions for their individual product. The steps given in
this text serve as a general guide.
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Objective 6
Describe the purpose of and procedure for static and
dynamic balancing.
TURBINE ROTOR BALANCING
Turbine rotors are large masses of metal that rotate at high speeds. For the rotor to run
with minimal vibrations, the mass of the rotor is as homogeneous as possible. That is,
the rotor is as uniform as possible. The blade on one side of a rotor has the same mass as
the blade on the opposite side. This applies to all parts of a rotor, including blades,
shrouding, discs, and the rotor shaft. When the rotor is machined or built-up, there is
always some unbalanced mass. Balancing is the operation or process of reducing the
amount of unbalanced mass of the rotor. There are two basic methods of balancing
turbine rotors:
• Static balancing
• Dynamic balancing
Static Balancing
Static balancing of a rotor (Fig. 11) is accomplished when the rotor is at rest. This is
done when the manufacturer has completed construction of a new rotor. It is also
completed after a repair or reconditioning of a rotor that has been in service.
Figure 11
Static Rotor Balancing
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Dynamic Balancing
Dynamic balancing consists of rotating the rotor at operating speeds and adjusting the
balance for low levels of vibration. The balancing apparatus is a machine that spins the
rotor on a set of spring-mounted bearings. The soft bearings cause the rotor to move
about with any imbalance. The balancing machine computes the magnitude of the
imbalance that is causing the rotor motion. Corrections are then made to correct the
imbalance. The rotor is rotated on the machine again. The vibrations are analyzed
again. This procedure is repeated until the vibrations are within limits for the operational
speed of the rotor.
Balancing can also be done in situ, using steam to rotate the rotor in its own bearings.
The advantage of this is not having to remove the rotor. The disadvantage is that
corrections are very time consuming because the turbine must be opened for access and
will be hot.
Balancing Built-up Rotors
Methods for balancing built-up and solid rotors differ because of their construction.
With the built up rotors, each wheel or disc is added separately to the shaft. Each wheel
is temporarily fitted to a small shaft where they are statically balanced. Metal is usually
removed from the wheel or disc to balance it. The balanced wheels are then attached to
the permanent rotor. When all the wheels have been attached, the rotor is then
dynamically balanced. Any remaining parts are added to the rotor. These parts include
the thrust bearing disc and the overspeed trip assemblies. Then a final dynamic balance
is done. The rotor is then ready for installation.
Balancing Solid Rotors
A solid rotor requires a different approach from a built-up rotor. The wheels are part of
the shaft and cannot be balanced individually. The shaft and wheels are balanced
dynamically after machining but before the blading or buckets are installed. Since the
shaft and rotors are symmetrical, static balancing is not necessary. Static balancing is
carried out after each row of blading is installed. This allows each wheel with blading to
be in balance. A final dynamic balance is carried out after all the smaller parts are
installed on the rotor.
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Chapter Questions
1. Explain why different balancing procedures are used for solid and built-up rotors.
2. Using a simple sketch, explain what is meant by turbine blade clearances. Why is it
important to keep the clearances as close to original specifications as possible?
3. What are two types of turbine blade deposits? How do they affect turbine
performance?
4. Why would a steam turbine be slow-rolled before the speed is increased to minimum
governor speed?
5. What important safety device is checked before putting a turbine on load?
6. Explain the difference between a hot start and a cold start in relation to a steam
turbine start-up.
7. When starting a steam turbine, when would the barring gear be disengaged? Why is
this important?
8. Sketch a condensing steam turbine with feed water heaters. For simplicity show only
one HP feedwater heater and one LP feedwater heater as well as the deaerator.
9.
What are the things monitored on a steam turbine during normal operation
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Page 160
Steam Condensers
Learning Outcome
When you complete this learning material, you will be able to:
Discuss condenser principles, performance, operation and auxiliaries.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Describe the principles and design of jet, air cooled, and surface condensers.
2. Describe the purpose, principle and design of surface condenser support and
expansion systems.
3. Explain the significant parameters in condenser performance.
4. Calculate condenser thermal efficiency from the test data.
5. Explain the procedures used to troubleshoot condenser performance.
6. Explain the procedures used to backwash and clean a condenser.
7. Describe the purpose, principle and design of air ejectors and vacuum pumps.
8. Describe the purpose and flow of cooling water systems.
9. Describe the purpose, principle and design of cooling water intake screens,
circulating pumps, cooling towers, and cooling ponds.
10. Describe the purpose, principle and design of condenser atmospheric exhaust
(relief) valves.
11. Describe the purpose, principle and design of condensate pumps.
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Page 162
Objective 1
Describe the principles and design of jet, air cooled,
and surface condensers.
PRINCIPLES OF CONDENSER OPERATIONS
The cycle of operations through which the working fluid passes in a steam power plant
is compared for performance against the ideal Rankine Cycle. This cycle consists of four
main operations: heat supply (at constant pressure), expansion through the prime mover,
heat rejection (at constant pressure), and recompression.
Fig. 1 shows a Temperature-Entropy diagram for steam. The four operations are:
1. Heat supply, A - B - C - D
2. Expansion, D - E
3. Heat rejection, E -A
4. Recompression, (this takes place at point A and is not shown in Fig. 1).
Heat rejection is the operation which will be discussed in this lecture. The Rankine
Cycle demands only that this operation is carried out at constant pressure. This can be
fulfilled with the prime mover exhausting to atmosphere and the boiler water drawn
from some outside source.
There are two major disadvantages to this scheme. One is that all of the feedwater in the
system is blown out to atmosphere, necessitating 100% makeup. The other is that
backpressure on the prime mover limits the expansion of the steam and consequently the
work which could be realized from the engine. Expansion of the steam to a lower
pressure (below atmospheric) coupled with recovery of the condensate are essential to
the economy of a steam plant.
The condenser and its auxiliary equipment are used for efficient heat rejection. The
steam leaving the exhaust of the prime mover, turbine or engine, is condensed and the
condensate collected. The working fluid goes through this change of phase (from vapour
to liquid) so that it can be pumped back to boiler pressure. Latent heat in the steam is
lost in the process. This is the largest single loss in the complete cycle of a steam power
plant.
Fig. 1 shows this loss as the area on the diagram beneath the heat-rejection line E − A .
This area represents the heat taken from the steam as it passes through the condenser
and is rejected to the cooling water.
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Figure 1
Temperature-Entropy Diagram showing
Steam Cycle without Feed Heating
Fig. 2 shows these heat losses in a block diagram. The left-hand block, representing the
total heat input to the plant, is the heat released by the fuel burned. The right-hand
blocks show the disposition of this heat in the power plant, the effective portion being
30%. This is a measure of the plant overall thermal efficiency. The heat loss in the
condenser is the greatest single loss in the operation. A plant which puts this rejected
heat to use, in a process operation for example, can achieve an overall thermal efficiency
in excess of 30%.
Page 164
Figure 2
Heat Balance Diagram
Condensation of the steam in a steam plant cycle takes place at the lowest practicable
absolute pressure to enable the prime mover to extract the maximum amount of work
from each kg of steam before it is condensed.
Therefore, the condenser must be capable of maintaining a vacuum in the region of 710
mm mercury or 6.9 kPa abs while handling a full load of exhaust steam flow from the
prime mover. It does this most efficiently if the latent heat only is removed and none of
the sensible heat, i.e. the condensate temperature should be as near as possible to the
entering steam temperature.
Page 165
The following comparison shows how much work the expansion of steam at low
pressures does. When steam expands from 1000 kPa to atmospheric pressure, the
amount of work done is 102.6 kJ/kg. When the steam is expanded from atmospheric
pressure to 7.5 kPa vacuum, the amount of work done is 100.7 kJ/kg.
Other purposes of the condenser are:
• Condensing the steam and returning the water to the system to conserve pure
feedwater
• Using the deaerator to assist in keeping the oxygen content of the feedwater to a
minimum
CONDENSER DESIGNS
There are two main types of condensers:
• Contact condensers
• Surface condensers
Contact Condensers
Contact condensers can be divided into two main groups:
• Jet
• Air cooled
Jet Condensers
Jet condensers bring the exhaust steam and the cooling water together which condenses
the steam. Condensers operating with direct contact between steam and water may use
either a pump to remove the water from the condenser body, called low-level jet
condensers, or the body may be set at sufficient height above the hotwell that the water
flows out by gravity, called barometric condensers.
The necessary length of tailpipe for a barometric condenser depends upon atmospheric
conditions and the vacuum carried in the condenser. The average length of the tailpipe is
about 10.5 m. Fig. 3 shows a basic barometric condenser. Cooling water flows through
jets from the cooling water inlet and falls at right angles to the steam inlet.
Contact between cooling water and steam causes the steam to condense and the
condensate, together with any air or noncondensable gases, falls with the cooling water
through the tailpipe to the hotwell. Boiler feedwater and cooling water are withdrawn
from the hotwell. This type of jet condenser is called a parallel flow condenser because
the air and other gases pass through in the same direction as the condensate.
When starting up the plant, the cooling water pump lifts the water from the hotwell up to
the condenser inlet. As the vacuum is built up, it assists in drawing the water into the
condensing space.
Page 166
The maximum useful injection water lift that can be expected depends upon the vacuum
in the condenser and the barometric pressure of the surrounding atmosphere. It is about
10.5 m for an installation at sea level. The tailpipe dimensions are chosen so that the
water quantity flowing keeps the tailpipe sufficiently filled to maintain a seal on the
condensing space at all times.
Figure 3
Ejector-Jet Barometric Condenser
Fig. 4 illustrates the flow diagram of a disk –flow condenser and a two-stage condensing
ejector the barometric condenser. The tailpipe carries the cooling water and the
condensate as before but steam ejectors draw the air and noncondensable gases from the
top of the condensing space. Because of the opposition in flow directions, this type of jet
condenser is called a counterflow condenser. This condenser is strictly a contact
condenser and not a jet, because the cooling water flow in this case is carried over a
series of discs in its fall toward the tailpipe.
Page 167
Note that the two-stage ejector handling the air and gases includes an auxiliary
condenser of the same type as the main condenser. The purpose of the auxiliary
condenser is to remove entrained water vapour. As with the barometric condenser shown
in Fig. 3, no pump is required to move the water from the condensing space to the
hotwell.
Figure 4
Disk -Flow Condenser and Two-Stage Condensing Ejector
.
Fig. 5 shows a low-level jet condenser. The main difference between these and the
barometric type is that here the water is removed from the condenser body by a pump.
This type of condenser, used in a geothermal power plant, is suitable because the
cooling water can be mixed with the steam condensate, before it is pumped back into the
geothermal rock formation for reheating.
Page 168
Low-level jet condensers are fitted with an automatic vacuum breaker to protect the
turbine against flooding in the event of stoppage or failure of the water pump. The air
and other noncondensable gases are removed from the top of the condenser space, using
the counterflow principle with a two-stage steam ejector and an interstage condenser.
Figure 5
Low-Level Jet Condenser
Advantages of the jet condenser are:
• Simple construction
• Low initial cost
• Occupies less space
• Can be usefully employed where the quantity of steam to be condensed is
moderate
Disadvantages of jet condensers are:
• Cooling water has to be the same quality as the boiler feedwater
• Vacuum achieved is limited to 660 to 685 mm which is not sufficient for a
turbine, therefore, they find limited use
Page 169
Air-Cooled Steam Condensers
Air-cooled steam condensers can be used to replace both a steam condenser and a
cooling tower in the power plant cycle. Air-cooled condensers accomplish the following
functions:
• Provide low back pressure for the turbine
• Recover the steam condensate
• Deaerate the condensate
No evaporation is used to cool the coils of an air cooled condenser. The heat is
transferred in the form of sensible heat to the ambient air. The air flow may be natural
draft but most are mechanical draft. Air cooled steam condensers are air cooled heat
exchangers. The heat transfer surface area is increased by using finned tubes. The tubes
and headers are usually arranged in an A-frame design, as shown in Fig. 6. In this design
steam enters the top header and flows downward through the finned tubes. Condensate
flows down the tubes by gravity and collects in the bottom header and drain pot.
The vacuum system is used to remove noncondensable gases. The A-frame design is the
most often used arrangement of air cooled steam condensers. The other types include
coolers with horizontal and vertical bundles.
Figure 6
Air-cooled Steam Condenser
Page 170
Air-cooled surface condensers have been installed in power plants over 350 megawatts
in North America and even larger plants internationally. They are often used when an
adequate supply of cooling water is not available. The major advantages of air-cooled
condensers are:
• No makeup water for cooling is required. The plant may be located where there
are not large supplies of cooling water
• Problems resulting from cooling water plumes are eliminated. Such problems
include fogging and icing and carryover of chemicals with the tower drift
• No chemicals are needed and there is no blowdown of water and chemicals
• Maintenance is less expensive
The main disadvantage is the higher exhaust pressure for the turbine. The minimum
temperature is higher with air-cooled condensers resulting in higher vacuum readings.
The higher vacuum reduces the turbine efficiency. In cold climates, special provisions
must be made in the design of air-cooled condenser to avoid freezing of the condensate
in the tubes and headers. These provisions include dampers, variable speed fans and
added instrumentation.
Surface Condensers
A surface condenser consists of a nest of tubes supported between tube plates contained
in a shell with waterboxes attached at each end. The steam to be condensed flows over
the surface of the tubes and the cooling water, through the tubes.
Surface condensers use air as the cooling medium in areas where supplies of cooling
water are very limited. These condensers may be straight dry air-cooled or may use air
blown over the outside of the condensing tubes together with a trickle of water. This is
evaporative cooling. In the latter case, the evaporation of the water causes the cooling
air to approach its wet bulb temperature instead of its dry bulb temperature as in the dry
air-cooled type.
Evaporative cooling condensers are rarely used because the air-to-metal heat transfer
rate is much lower than the steam-to-metal or water-to-metal rate. A cooling tower used
in conjunction with a normal water-cooled surface condenser gives better performance
and uses a minimum of water.
Turbines, used to generate electricity, have water-cooled surface condensers positioned
beneath the turbine exhaust branch. Fig. 7 shows the operating floor of a power plant.
The condenser is located on the level below the machine, directly below the low
pressure casings.
Page 171
Figure 7
Turbine Generator Installation
The cooling water flow may be single pass (once through) or two pass. The steam flow
may be from top to bottom (down flow) or radially towards the centre (central flow).
Fig. 8 shows an Elliot Company condenser operating on the down flow principle.
Figure 8
Down Flow Condenser
Page 172
Fig. 9 shows a two-pass central flow A.E.I. condenser.
Figure 9
Central Flow A.E.I. Condenser
Page 173
The earlier designs of surface condensers used the maximum number of tubes pitched
evenly over the whole of the available tube plate surface and often had a condensate
temperature of 5 to 8°C below that of the incoming exhaust steam. This is called
condensate sub-cooling (or undercooling).
A regenerative condenser uses wide tube spacing and leaves open spaces or steam lanes
to allow the entering steam to penetrate through the tube nest and come into contact with
the condensate falling from the upper tubes. The condensate and exhaust steam are
maintained at an equal temperature. In some cases the condensate temperature is ½ to 1°
above the vacuum temperature. This is caused by the recovery of exhaust steam velocity
energy as heat in the condensate.
The air extraction equipment may be arranged to draw from beneath baffles near the
bottom of the condenser in the down flow type which is the most common.
Alternatively, the air extraction may be from the centre of the tube nest in a central flow
type.
Air extraction takes place from the coolest area in the condenser, i.e. in the region of the
inlet cooling water. The advantage is that the air is at its minimum specific volume and
is most efficiently handled by ejectors. The purpose of the baffles is to prevent the steam
from coming into contact with the air, thus keeping the air as cool as possible.
Fig. 10 shows a Wheeler Company condenser tube plate design illustrating the trend
toward regenerative design. View (a) shows the earlier design with evenly spaced tubing
over the whole of the tube plate.
View (b), (c) and (d) show the provision of open steam lanes, steam space between shell
and tube banks, and graduated tube spacing. Also take note of the open tube spacing at
the steam inlet where the steam volume is greatest, and that the tubes taper to closer
spacing as they approach the air extraction. This design minimizes the pressure drop
from top to bottom of the condenser and maintains the condensate temperature as high
as possible.
Page 174
Figure 10
Condenser Tube Plate Designs
Page 175
SURFACE CONDENSER CONSTRUCTION
Tubes
Condenser tubes are straight and generally have 19 mm, 22 mm or 25 mm outside
diameter though occasionally 16 mm tubes have been used. The smaller diameter tube
gives slightly more surface area, but is subject to increased flow restrictions and requires
more circulating water pump power. The thickness is fairly standard at 18 B.W.G.
(Birmingham Wire Gauge). The dimensions generally work out so as to make the tube
length roughly 1.5 to 2.5 times the diameter of the tube plate.
The material used for the tubes must be a good conductor of heat and resistant to
corrosion. The material used depends mainly upon the corrosive properties of the
cooling water. Admiralty metal which is 70/30 brass with some addition of tin and
aluminium brass are generally suitable for fresh or sea water. Where the water is
particularly corrosive, cupro-nickel alloys are used though these materials have a
somewhat lower thermal conductivity and consequently their use necessitates a greater
condenser surface for a given heat transfer. Stainless steel is another material commonly
used for condenser tubes because of its corrosion resistance. Titanium is also used for
seawater applications.
The method of attachment of the tubes to the tube plate is very important. The joint
between the two prevents the cooling water from being drawn into the steam space and
thus contaminating the condensate. Because the tubes are brass, they expand more than
the steel shell when the condenser warms up under working conditions, so allowance for
this movement is made at the tube plate. The method used allows the tube to slide
through the tube plate as it expands. Various methods, used to attach the tubes to the
tube plate, are shown in Fig. 11.
View (a) shows the earliest method. It was made up of a packing of corset lace (or
condenser cord) soaked in oil (boiled linseed), with ferrules at each end, the tube
being butted up to the inlet ferrule shoulder and expansion allowance given at the
outlet end.
View (b) shows the “Crane” type of packing, again ferruled at each end. The packing
consists of fibre rings and flexible metallic rings fitted alternately, the ferrule screwed
hard in against the rings.
View (c) shows a tube ferruled at the inlet end only, with a full box of Crane type
packing at the outlet end. In this case the tube is held in place by the cone-shaped
rings in the inlet end packing; the outlet packing is caulked into place.
View (d) shows the inlet end is expanded and belled; the outlet end can be ferruled as
shown or fitted with caulked-in packing as in (c).
Page 176
View (e) shows both ends expanded into place. In this case special condenser
construction is necessary to permit the displacement of one tube plate to
accommodate differences in expansion.
Figure 11
Methods of Securing Condensers Tubes
Page 177
Tube Plates
Condenser tube plates are usually admiralty metal or a similar non-ferrous alloy
although mild steel is also common. Collar bolts secure the tube plates to the shell, Fig.
12, so that the waterboxes may be removed without disturbing the joint between the tube
plate and shell. The holes for the tube ends are drilled and reamed or drilled and tapped
depending upon the method of tube fixing. The pitching of the holes is chosen so that
steam has access to all portions of the tube nest with a minimum pressure difference
across the nest.
Steady plates, drilled to the same pattern as the tube plates, are placed in the steam space
to support the tubes when the distance between tube plates is considerable. They are
designed to support the tubes to avoid excessive sagging and also to dampen out any
vibration in the tubes. They are usually made of mild steel. As a further protection, the
top row of tubes is often replaced by a row of steel or iron rods. Their purpose is to
prevent tube damage from pieces of turbine blading or any foreign material carried
through the turbine exhaust.
Figure 12
Attachment of Tube Plates and Waterboxes
Condenser Shells
Shells are welded steel construction, generally stiffened by external ribs or internal
braces. The larger sizes are divided by circumferential joints for ease of transportation.
The shells are fitted with feet to carry the mass of the condenser. In the case of smaller
machines, these feet are secured to the engine foundation. In the larger machines, the
condenser is bolted to the exhaust branch and supported on springs.
The shell may also be fitted with an expansion joint to allow longitudinal movement.
This is done when the design calls for the tubes to be expanded into their tube sheets at
both ends and relative movement between shell and tubes must be accommodated.
Shells are made to accommodate the turbine exhausts and may be made in two separate
sections where the turbine has two exhausts, as with a double flow LP cylinder. In many
cases, the shell is divided to allow the circulating water to be shut off from one-half of
the shell for cleaning purposes while the machine is still running on a reduced load.
Page 178
Objective 2
Describe the purpose, principle and design of surface
condenser support and expansion systems.
CONDENSER SUPPORT AND EXPANSION SYSTEMS
The purpose of expansion joints and support springs is to allow relative movement
between the turbine exhaust flange and the condenser. In the smaller designs, the
condenser feet are bolted rigidly to the foundations and an expansion joint such as a
corrugated bellows piece is fitted between the engine exhaust flange and the condenser
inlet flange.
Fig. 13 shows C.H. Wheeler joints used for this purpose. For larger designs, the
condenser is bolted to the turbine exhaust flange and supported on springs, which are
proportioned to just support the mass of the condenser when operating full of cooling
water. This relieves the turbine exhaust of any thrust.
Figure 13
C. H. Wheeler Corrugated Expansion Joint
Fig. 14 illustrates condenser spring supports fitted to a condenser. The bolts F are
secured to the machine foundation and the condenser feet rest on the keeps E. The
condenser inlet flange is bolted directly to the turbine exhaust flange, and consequently
the joining of these flanges becomes an essential part of lining up the machine during
the assembly stages.
The spring settings are done with the condenser in working condition. If the steam space
has to be filled with water at any time, say for the purpose of testing the tubes and tube
plate for leakage, the jacking screws C are run up to the condenser feet to provide a solid
support for the extra mass.
Page 179
Figure 14
Condenser Spring Supports
Fig. 15 shows details of a tube plate stay rod fitted to a condenser for the purpose of
supporting the tube plate against water pressure and vacuum. This bronze stay is fitted
between the tube plate and the water-box cover. The number fitted is proportional to the
circulating water pressure involved. An alternative design is a steel rod passing through
the steam space and connected to both tube plates.
Figure 15
Tube Plate Stay Rod
Page 180
In Objective 1, the method used to allow for the expansion of the condenser tubes was
discussed. For Fig. 11 diagram (e) both ends of the tubes are expanded into place. When
this design is used, a shell expansion joint, Fig. 16, allows for the differential expansion
between the tubes and the shell.
Figure 16
Shell Expansion Joint
Page 181
Page 182
Objective 3
Explain the significant parameters in condenser
performance.
CONDENSER PERFORMANCE
When discussing condenser performance, the power engineer should be familiar with
the following definitions:
• Steam Load - Kilograms of steam per hour entering the condenser
• Vacuum Temperature - this is the saturation temperature corresponding to the
pressure of the steam entering the condenser. It is the temperature at which
condensation takes place and which the condensate remains at. It is also the
temperature of the exhaust steam because this steam is partially wet at entry to
the condenser
• Range - the difference between vacuum temperature and cooling water inlet
temperature in °C
• Rise - the difference between outlet and inlet cooling water temperatures in °C
• Mean Temperature Difference (MTD) - the difference in °C between the average
steam side temperature and the average waterside temperature for all of the
condenser tubes in °C
• Terminal Difference - the difference between vacuum temperature and the
cooling water outlet temperature in °C
• Condenser Surface - the total external surface of the condenser tubes between the
tube plates, expressed in m2
• Cooling Water Velocity - the average speed of flow of the cooling water through
the tubes, expressed in m/s
• Condenser Friction - Pressure loss occurring in circulating (cooling) water from
inlet to outlet, expressed in m head of water
• Air Flow - Some installations are fitted with an air flow meter for measurement
of the quantity of air discharged by the air evacuation equipment. Comparison of
readings gives warning of any increase in the air infiltration to the pressure
stages of the machine
• Condenser Vacuum - the difference between atmospheric pressure and the static
pressure within the condenser, expressed in mm Hg (mercury)
• Absolute Pressure or Back Pressure - the difference between atmospheric
pressure and condenser vacuum in mm Hg (or kPa)
An example may clarify the definitions of condenser vacuum and absolute pressure.
Page 183
A barometer measuring ambient pressure reads 762 mm Hg. This is the absolute
pressure of the atmosphere expressed in mm Hg. If a condenser maintains a pressure of
700 mm Hg less than atmospheric, it is said to be operating at 700 mm vacuum.
The difference between this 700 mm and the absolute atmospheric pressure of 762 mm
is 62 mm Hg. This is the absolute pressure or back pressure remaining within the
condenser.
Millimeters Hg and kPa can be converted as follows:
10 mm Hg = 1.333 kPa (calculated from the density of mercury) so that the absolute
pressure of 62 mm Hg. can be quoted as:
62 mm Hg ×
1.333 kPa
= 82.65 kPa
mm Hg
Backpressure is a better measure than vacuum for condenser performance because
backpressure measures its approach to a perfect vacuum and is unaffected by changes in
atmospheric conditions.
An operation aims at maintaining the original condenser test figures. However, a fall-off
in performance may be attributed to:
• Increase in cooling water inlet temperature
• Reduction in water quantity
• Change in load
• Increase in air leakage
• Fouling of the tube surfaces
The loading conditions, which were held steady during the test, might not occur
regularly enough to give reliable check figures during standard operation. Changes in
load, in cooling water quantity, or temperature should not be charged against the
condenser. Air leakage and fouling are isolated and measured. A record of these,
particularly fouling, is essential so that the operating engineer can decide upon the most
economical time for condenser cleaning.
Temperature Relations
The temperatures measured in the steam and water spaces are observed for their
deviation from the specified or test figures. The measurements are used as a guide to the
internal condition of the condenser.
Ideally, the three temperatures: exhaust steam, condensate, and cooling water outlet, are
the same. If tube fouling occurs, the cooling water is not able to absorb heat as well as it
should. The cooling water outlet temperature goes down, and the exhaust steam
temperature rises due to a diminishing vacuum.
Page 184
This widening gap between the exhaust steam and cooling water outlet temperatures
(terminal temperature difference) is a good indication of tube fouling.
Air leakage into the condenser widens the gap between the exhaust steam and
condensate temperatures. Air in the condenser space has several undesirable effects:
• It increases the condenser pressure and hence the turbine back pressure
• It tends to cling to the outsides of the condenser tubes and impedes the heat flow
from steam to cooling water
• It lowers the condensate temperature
This effect follows from Dalton’s Law of Partial Pressures. The effect of the air is felt
most at the bottom of the condenser where it makes up a larger part of the total pressure.
The condensate temperature depends only upon the partial pressure due to steam and is
reduced when this pressure is reduced.
Loss of Vacuum
Satisfactory indication of condenser performance is obtained from a record of the “loss
of vacuum” or vacuum depression from optimum to actual. To find the difference
between actual and optimum conditions, a set of curves are constructed. Curves, such as
the ones shown in Fig. 17, are drawn using test data or specification figures together
with actual observed vacuums when the condenser was known to be clean. Sufficient
figures to establish a trend for estimation of the rest of the curves with reasonable
accuracy. With the aid of such a curve, the operating engineer is able to plan condenser
cleaning dates.
Figure 17
Condenser “Loss of Vacuum” Record
Page 185
Page 186
Objective 4
Calculate condenser thermal efficiency from the test
data.
CONDENSER CALCULATIONS
A condenser is a heat exchanger. Heat is taken from the entering steam, transferred to
the circulating, or cooling water, and then rejected to an outside heat sink. A heat
balance is used to show the condenser operation as follows:
heat in = heat out
The “heat in” is the heat given up by the condensing steam. The “heat out” is the heat
carried away by the cooling water (c.w.), neglecting losses.
Using a time basis of 1 hour, the heat balance can be written as:
Heat release/kg of steam × kg of steam flow/hr = Heat gained/kg of CW × kg of CW flow/hr
Q, kJ/hr = 4.186 × ∆T × CW , kJ/hr
where Q = Heat input, kJ/hr
∆T = Temperature rise of CW ,°C
CW = Rate of flow of cooling water, kg/hr
4.186 = Specific heat capacity of water, kJ/kgK
This heat input, Q, kJ/hr , passes through the condenser tubes and is dependent upon
the:
• Surface area of the tubes
• Temperature gradient from steam to water across the tube metal
• Condition of the tube surfaces
Certain average figures arise from past practical experience in condenser operation. For
example, the heat rejected (released) per kg of steam to the condenser by a turbine is
2200 kJ/kg, and by a reciprocating engine is 2320 kJ/kg. An average steam loading on a
condenser is about 3.5 kg steam/h/m2 of tube surface area. The temperature rise of the
cooling water from inlet to outlet is about 8 to 11°C.
Page 187
The efficiency of any operation is given by the relationship of:
Output
Input
In the case of a heat engine, output is the work done by the engine, and input is the heat
supplied during the cycle, thus:
Work Done
Thermal Efficiency =
Heat Supplied
Studies on heat engines show that the maximum amount of work that can be done by
any heat engine is the difference between the heat supplied and the heat rejected
(enthalpy of steam after expansion) in the cycle:
Heat Supplied − Heat Rejected
Thermal Efficiency =
Heat Supplied
In a condenser, the heat supplied is the amount of heat in the steam entering the
condenser. The heat rejected is the amount of heat energy left in the steam condensate
leaving the condenser.
The actual work done in a condenser is the amount of heat removed from each kg of
steam entering the condenser, as it is condensed back to a liquid. Thus the work done is
found by subtracting the heat content of the condensate from the heat content of the
steam entering the condenser. This is the heat that the cooling water absorbs.
Note that the heat removed from each kg of steam is removed at constant pressure which
is based on the Rankine Cycle which states that heat must be removed at constant
pressure.
Therefore, for a condenser:
Heat in steam exhaust - Heat in condensate
Heat in steam exhaust
Enthalpy of steam exhaust - Enthalpy of condensate
=
Enthalpy of steam exhaust
= Enthalpy of steam exhaust
Thermal Efficiency =
Where H g
H f = Enthalpy of condensate
Thermal Efficiency =
Page 188
Hg − H f
Hg
Example 1
A new condenser is designed to receive 21 000 kg/h of dry exhaust steam from a
turbine. The condenser pressure is designed to be 5 kPa absolute. Calculate the design
thermal efficiency of the new condenser.
Solution
In this example, any efficiency losses due to air leakage or sub-cooling of the
condensate will not be a factor.
H -Hf
Condenser Thermal Efficiency = g
Hg
H g = 2561.5 kJ/kg
H f = 137.82 kJ/kg
2561.5 kJ/kg -137.8 kJ/kg
2561.5 kJ/kg
= 94.60% (Ans.)
Condenser Thermal Efficiency =
Note: This is under ideal conditions and with new and clean condenser tubes.
Example 2
After a year in operation the condenser in Example 1 is receiving 21 000 kg/h of steam
at 7.5 kPa (40.29°C), and the temperature of the condensate leaving the condenser is
35°C. Calculate the new thermal efficiency of the condenser.
Solution
Condenser Thermal Efficiency =
Hg - H f
Hg
H g = 2574.80 kJ/kg
H f = 146.68 kJ/kg
2574.80 -146.68
2574.80
2428.12
Condenser Thermal Efficiency =
2574.80
Condenser Thermal Efficiency = 0.9430
Condenser Thermal Efficiency = 94.30% (Ans.)
Condenser Thermal Efficiency =
As seen in the examples, a change of only a few degrees can make a difference to the
thermal efficiency on the condenser. If this decline in thermal efficiency is allowed to
continue, it will have a significant effect on the operation of the turbine.
Page 189
Page 190
Objective 5
Explain the procedures used to troubleshoot condenser
performance.
TROUBLESHOOTING PROCEDURES
To properly observe the performance of a condenser, the operating parameters must be
monitored. The required readings or parameters used to determine condenser
performance are the:
• Condenser vacuum
• Temperature of the steam entering the condenser
• Temperature of the condensate leaving the condenser
• Cooling water inlet and outlet temperatures
These readings are compared with the original readings taken when the condenser was
first put into service. When the condenser is new, the temperature of the steam exhaust,
the condensate, and the cooling water outlet are relatively close. A graph (like the one in
Fig. 17 – Objective 3) is developed to show the reduction of the condenser vacuum.
Comparisons of these various readings indicate whether the performance of the
condenser is deteriorating. In order to troubleshoot condenser performance issues, the
following four items are examined:
• Terminal difference
• Loss of vacuum
• Air leaks
• Insufficient circulating water
Terminal Difference
A comparison of the temperature differential or difference between the exhaust steam
temperature and the cooling water outlet is called the condenser terminal difference and
this figure is sometimes used as a guide to condenser fouling.
Loss of Vacuum
The most frequent cause of low vacuum is slime and mud on the waterside of the tubes.
This acts as an insulator and slows down the rate of heat transfer from steam to
circulating water. Increased partial pressure due to uncondensed steam adversely affects
the vacuum and the temperature at turbine exhaust rises. The temperature of the
condensate also rises because the vacuum has dropped. There is no sub-cooling of the
condensate because the heat cannot be transmitted through the condenser tubes.
Page 191
In this case, both the steam exhaust and condensate temperatures rise above normal
operating conditions and the cooling water outlet temperature is low.
Air Leaks
Increased air leakage into the condenser vacuum creates a widening difference between
the temperature of the exhaust steam and the temperature of the condensate. Another
way to determine if there is an increase in air infiltrating the condenser is to compare the
readings taken from the air flow meter. Faulty air extraction also compounds the
problem of air leakage.
Insufficient Circulating Water
A lack of sufficient cooling water reduces the vacuum. If the cooling water system has a
flow meter and accumulator, the amount of cooling water flow can be determined for a
given period of time. If the amount of cooling water flow is lower than usual, the reason
for the reduced flow must be resolved. If the normal pump motor amperes are known, a
drop in load on the pump monitor may indicate the reduced flow. An increase in the
temperature differential between the cooling water in and out temperatures also
indicates reduced flow. If the tubes are clean, the heat transfer rate is normal, and then
the reduced quantity of cooling water is raised to a higher temperature.
Page 192
Objective 6
Explain the procedures used to backwash and clean a
condenser.
CONDENSER CLEANING PROCEDURES
Provisions are sometimes made for on-line cleaning of large condensers which are
subject to fouling with algae and other residual matter. The waterboxes are divided into
two halves. Inlet and outlet circulating water valves are provided for each section so that
one-half of the condenser can be cleaned at one time. In some locations, sudden severe
surges of waste material might occur in the water used for cooling. This material may
lodge in the tube ends and block the flow of circulating water. In these cases, a reverse
flow or backwash system is advantageous.
Fig. 18 shows an example of a reverse flow type of design. The inlet and outlet valve
chambers A and D are provided with changeover valves. Referring to the left side of the
condenser in Fig. 18, water enters the divided water box at valve chamber A with the
left port open. The water flows through pass B to end of the condenser, back through
pass C, and out through upper port of D.
To backwash the condenser, flow is then reversed on the right side. Valves at inlet A
and discharge D are changed to permit water to flow through C and then back through B
in the opposite direction. It then exits the condenser through the lower port of D. With
this type of arrangement, one-half of the condenser can be backwashed while the other
half is in service.
Figure 18
C.H. Wheeler Reverse Flow Dual Bank” Condenser
Page 193
Fig. 19(a) shows the condenser in normal operation. Fig. 19(b) shows the first half being
backwashed while Fig. 19(c) shows backwashing of the second half. This design has
dual inlet and outlet valves, and there are butterfly type valves in the water-box division
plates which are used to backwash the condenser. With this design, the entire condenser
has to be shutdown in order to be backwashed.
Figure 19
Backwashing Allis-Chalmers Condenser
Page 194
Objective 7
Describe the purpose, principle and design of air
ejectors and vacuum pumps.
PURPOSE OF AIR EJECTORS
The pressure within a condenser shell is well below that of the surrounding atmosphere
and this induces atmospheric leakage through glands, valves, flanges and joints. Other
noncondensable gases like oxygen and carbon dioxide may be carried with the steam
from the boilers although modern feedwater treatment has reduced these to a minimum.
All these gases are poor heat conductors and, if allowed to accumulate, soon blanket the
condenser tube surfaces. Steam-jet air ejectors and vacuum pumps are used to remove
the air and other gases that accumulate in the condenser.
PRINCIPLE AND DESIGN OF AIR EJECTORS
Fig. 20 shows sectional of a single-stage ejector. High-pressure steam delivered to the
steam nozzle passes into the air chamber with high velocity and produces an area of low
pressure in its wake. Air and other gaseous vapours, drawn from the condenser into this
low-pressure area, become entrained in the jet of steam and are carried through the
diffuser to the discharge.
Figure 20
Sectional View of Ejector
Page 195
Fig. 21 shows the piping layout for a single-element two-stage steam-jet air ejector with
jet inter-condensers attached to a surface condenser. Note that the air extraction is taken
from beneath a baffle plate in the condenser steam space. This allows air to collect in a
shielded area where condensing steam does not heat the incoming cooling water. The air
is reduced in volume as much as possible to improve the effectiveness of the ejection
equipment. The ejector uses condensate from the main condenser in the intercooler. The
condensate from the intercooler is led back through a water leg to the main condenser.
Figure 21
Single-Element Two-Stage Steam-Jet Air Ejector
Fig. 22 shows a sectional view of a two-stage steam-jet air ejector with separate surface
intercondensers and aftercondensers. The air is vented off to atmosphere from the
aftercooler where the pressure is slightly above atmospheric.
Page 196
Figure 22
Two-Stage Steam-Jet Air Ejector
The number of stages used depends upon the pressure required. Generally, single-stage
air-ejectors are used to about 10 kPa, two-stage to 4 kPa, and three-stage below 4kPa.
Two-stage air-ejectors are the most commonly used. In order to give standby protection,
two sets of ejectors are often fitted. Each set has 100% capacity and has isolating valves
to allow cleaning of jets or nozzles while the other set is in operation.
The quantity of steam an air ejector uses depends upon the quantity of air that it is
required to remove and this depends on the size of condenser used. Air, in passing
through the condenser, becomes saturated with water vapour in the ratio of
approximately 30% air to 70% vapour. The ejector capacity must be sufficient to handle
this air-vapour mixture.
VACUUM PUMPS
Noncondensible gases can also be removed from surface condensers by vacuum pumps
(Fig. 23). A vacuum pump consists of an impeller mounted eccentrically in a round
casing. The casing is partly filled with the seal liquid, which is usually water. The
impeller rotates and the liquid is thrown by centrifugal force to form a liquid ring which
is concentric with the pump casing. The cells formed by the impeller vary in size as the
impeller rotates. The cells are large near the inlet port and small near the outlet. This
difference in size causes the vapours to be compressed as they pass though the pump.
The liquid ring also serves to carry away the heat from compression and from friction.
This is another reason for the constant supply of seal water to the pump. The seal water
is often cooled in a heat exchanger before entering the pump.
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Figure 23
Liquid Ring Vacuum Pump
These pumps can be used instead of ejectors or in addition to ejectors. A liquid ring
vacuum pump system is shown in Fig. 24. Sealing water is supplied to the vacuum pump
via a seal water cooler. Gases are pumped out to a vent separator which knocks out any
entrained seal water for reuse. Some of the seal water vaporizes and is carried out the
discharge. The amount of water vaporizing increases as the vacuum increases. This is
one of the limitations of vacuum pumps.
Figure 24
Liquid Ring Pump Vacuum System
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Objective 8
Describe the purpose and flow of cooling water
systems.
PURPOSE OF COOLING WATER SYSTEMS
The purpose of the cooling water system is to condense the exhaust steam entering the
condenser from the steam turbine or steam engine and to remove this exhaust heat from
the condenser and deposit it in a heat sink. The heat sink may be a river, lake, cooling
pond, or a cooling tower.
COOLING WATER FLOW PATHS
The cooling water, circulated through the condenser, may come from a river, lake, or an
estuary. In these cases, the cooling water makes one pass through the cooling water
system and then it is discharged back into the lake or river. The fresh supply of cooling
water is taken from another part of the lake or river. This type of cooling water system is
the most economical to build and operate provided the water supply is adequate to
supply the cooling water requirements of the operation.
If the supply of cooling water is limited, it is circulated through a closed system which
provides some means of cooling the water after leaving the condenser. The methods
used to cool the water are cooling ponds or cooling towers. With this type of system, the
only water required from a nearby river or lake, is makeup water, to make up for losses
due to evaporation, leaks in the cooling water system and blowdown losses.
If a cooling pond is used, then the water is pumped from the cooling pond through the
condenser and back out to the pond. If the pond is not large enough to adequately cool
the water, water sprays are installed in the pond or in the canal leading to the pond. The
design of the cooling ponds will be discussed later in this module.
If a cooling tower is used, the water is pumped from the basin of the cooling tower
through the condenser and back to the cooling tower.
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Page 200
Objective 9
Describe the purpose, principle and design of cooling
water intake screens, circulating pumps, cooling
towers, and cooling ponds.
COOLING WATER INTAKE SCREENS PURPOSE
The purpose of the cooling water intake screens is to prevent foreign material such as
rocks, pieces of wood, weeds, or anything else that can damage the cooling water pumps
from getting into the pumps. Another reason for intake screens is to prevent foreign
material from which can plug up or damage the condenser tubes.
PRINCIPLE AND DESIGN OF COOLING WATER INTAKE
SCREENS
The cooling water intake screen is designed to provide adequate screening of the cooling
water with a minimum pressure drop across the screen when the cooling water flow is at
maximum rates. The screen also prevents turbulent flow to the suction of the pump,
even if the intake screen becomes partially plugged with foreign material. The mesh size
is usually 3 mm to 12 mm. There are various types of cooling water intake screens in
use. The following two types will be discussed in this lecture:
• Travelling Screen -Through-flow
• Travelling Screen – Dual-Flow
Travelling Screen – Through-Flow
A belt type of travelling screen is shown in Fig. 25. The screen has a number of panels
joined together in the form of a belt. This belt screen is attached to a sprocket at each
end, and the top sprocket is the driver. The debris is collected on the ascending screen
panels. These panels move through an area above the operating floor where water jets
remove the debris collected from the cooling water and deposit it into collection troughs.
The clean panels then move downwards through the screened effluent going to the
pumps and back up through the incoming water.
The disadvantage of this screen is carry-over of debris to the pump side of the screen. As
the filtered water flows backward through the descending panels on the pump side of the
screen, it may dislodge any debris the water jets have not removed from the filtering
panels. The debris then flows downstream to the pumps and condensers which can cause
damage to this equipment.
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Figure 25
Travelling Screen (US Filter)
Travelling Screen – Dual-Flow
A picture of the dual-flow filter is shown in Fig. 26.
Figure 26
Travelling Screen Dual-Flow (US Filter)
Page 202
This is also a belt type of screen. The influent water flow goes through both the
ascending and descending panels, and the screened effluent exits from the centre of the
screen. Therefore, only clean screened water is allowed to flow downstream to the
pump. The water jets used to clean the debris from the panels are above the operating
floor which is similar to the through-flow design.
The advantages of dual-flow screen over the through-flow screen are:
• Water passes through the screen panels in one direction only. Therefore, there is
no chance of debris getting into the pumps and the cooling water system.
• The only way debris can be carried over with this screen is if one of the panels
breaks.
• Debris the water jets do not clean from the screens returns to the influent water
flow, and the next cleaning cycle removes it.
• The ascending and descending panels remove debris, so the screen size for a
given screening area can be reduced. This results in a lower initial cost and lower
total screen weight.
The government regulates the design and construction of cooling water intake structures
to minimize any adverse environmental impact. A major goal of these regulations is to
minimize the impingement and entrainment of fish and other aquatic organisms as they
are drawn into a facility’s cooling water intake.
Impingement occurs when fish and other aquatic life are trapped against cooling water
intake screens.
Entrainment occurs when aquatic organisms, eggs, and larvae are drawn into a cooling
water system, through the heat exchanger, and pumped back out.
Impingement and entrainment are minimized in the following ways:
• Fish diversion or avoidance systems designed to divert fish away from the intake
screens
• Use of mechanical screen systems that prevent organisms from entering the
intake system
• Fish return systems that transport live organisms away from the intake screens
CIRCULATING WATER PUMPS
The purpose of the circulating water pumps is to circulate the cooling water through the
cooling water system and the condenser. After passing through the heat exchangers, the
water is returned to the river, cooling pond or a cooling tower.
Types of Circulating Pumps
The type of pump commonly used for circulating water service is the vertical mixed
flow pump, which is illustrated in Fig. 27. It is called a mixed flow pump because it
obtains its pumping action from a mixture of centrifugal force and the lifting effect of
the impeller vanes. The vertical design removes the need for pump priming as the
impeller is submerged. These pumps operate at a low speed, usually 320 to 450 rev/min.
Page 203
In some applications, horizontal rather than vertical pumps are used. They are also
centrifugal pumps usually of the single-stage volute type.
Figure 27
Vertical Mixed Flow Circulating Water Pump
(Allis –Chalmers)
COOLING TOWERS
Purpose
When the availability of cooling water is restricted, the water is circulated through the
system, using some form of cooling after it leaves the condenser. A cooling pond or
cooling tower is the two most common means of cooling the circulating water. The
cooling tower is the more compact way of cooling the circulating water, and it can cool
large quantities of water.
Principle Of Cooling Tower Operation
The principle of cooling remains the same whether rivers or cooling towers are
employed, that is, the heat is given up to the atmosphere. In rivers, cooling takes place
from the flat surface of the water which may extend for many miles. In a tower, the
water surface exposed to the atmosphere has to be artificially increased to accomplish
the heat transfer. Two methods used in a cooling tower are:
•
•
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Splash cooling
Film cooling
Splash Cooling
Splash cooling breaks the water into small drops in the cooling tower. To illustrate this
principle, consider a section of water in a river 10 m long by 10 m wide by 1 m deep. Its
volume then is 100 m3. The heat contained in such a body of water is proportional to its
mass and hence its volume. Heat exchange takes place from the surface area of 100 m2.
If this 100 m3 of water is divided into spheres of 250 mm diameter so that the air could
make contact over the whole area of each sphere, the total volume and heat quantity
remain the same, but the surface area available for heat transfer is increased to 2700 m2,
that is, 27 times as much. If the water is divided into 60 mm diameter spheres, the
surface area is 10 800 m2, 108 times that of the flat surface.
Film Cooling
Film cooling also increases the water surface area. Water is induced to flow in a film or
sheet down the sides of a series of boards set with their long axis horizontal and
arranged in layers or banks. Each bank of boards is set at right angles to the one
vertically below it. This method reduces the “drift” loss, that is, that quantity of water
that the velocity of the air stream carries out of the tower. The splash cooling systems
employ “drift eliminators” to minimize this problem. These are baffles arrangements
built across the fill outlet. They serve to trap and return the escaping water droplets.
The great majority of the heat transfer takes place at the water surface, regardless of
whether this has been produced by a splash or a film method. It takes place through
evaporation of a part of the water into the surrounding air. This is the principle used in
evaporative cooling. A small amount of cooling also takes place by heat transfer to the
air.
The ability of air to evaporate water in contact with it depends upon its relative
humidity. Relative humidity is the ratio of the quantity of water vapour actually present
in m3 of air to the maximum amount of vapour the air can hold at that temperature.
When the relative humidity is 100% the air cannot hold any more water and is said to be
saturated. But when the relative humidity is less than 100%, water evaporates and heat is
carried away in the water vapour. This heat is the latent heat of vaporization.
When 1 kg of water is evaporated, it takes away approximately 2300 kJ of latent heat.
The air removing the latent heat causes the cooling effect which making possible the
cooling of the water in the tower to a temperature just a few degrees above the wet bulb
ambient temperature.
Using the 2300 kJ/kg latent heat and referring to 1 kg of water, it can be seen that
evaporating 1% (by mass) of the water reduces its temperature by 5.5°C or
1
kg × 2300 kJ/kg = 1 kg × 4.183kJ/kg DC × 5.5DC
100
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COOLING TOWER DESIGNS
In all cooling towers, the water supply is introduced at or near the top, and it falls by
gravity over the fill into the water reservoir at the bottom. The fill consists of some
arrangement of splash bars, generally constructed of redwood, pressure treated Douglas
fir, or PVC. The fill is designed to cause the falling water to break into droplets or to run
across the fill in a film to achieve the maximum water surface area to the air.
Cooling towers are classified according to the method of passing the air over the water
to be cooled. There are two main classifications of cooling towers:
• Natural Draft
• Mechanical Draft
Natural Draft
This open or atmospheric type has walls constructed of wooden louvers or slats laid
horizontally along the length of the walls and angled so that the air enters the tower in a
downward direction. This reduces the tendency to lift the fine water spray out of the top
of the tower and gives a better distribution of cooling air across the tower. The
movement of air is dependent upon natural convection currents.
One type of natural draft tower is the hyperbolic tower, as shown in Fig. 28. This model
of cooling tower is made of reinforced concrete and is built in sizes up to 25 000 m3/h. It
stands 90 meters high and has a 60 m base diameter. The air inlet, water distribution,
and fill are similar to a mechanical draft tower and fit in the bottom section of the tower.
The majority of the height of the hyperbolic tower is the stack or chimney.
Figure 28
Hyperbolic Cooling Tower System
Page 206
Natural draft towers are efficient and their maintenance and operating costs are minimal
as they require no fans. However, they are dependent upon local atmospheric conditions
and consequently mechanical draft towers are chosen for many plants.
Mechanical Draft
Advantages of mechanical draft towers over the natural draft type are:
• Smaller for equivalent duty, therefore, need less ground area and use less
pumping power
• Not dependent upon weather conditions to aid convection, therefore, give a more
constant performance over all seasons of the year
Disadvantages of mechanical draft towers over the natural draft type are:
Extra complication of the fans
Power and maintenance associated with the fans
Mechanical draft towers are constructed using either:
• Forced
• Induced.
Forced Draft
A forced draft cooling tower (Fig. 29) includes a fan placed at the bottom of the tower to
draw air from the surrounding atmosphere and force it upwards across the fill conterflow
to the falling water.
Figure 29
Forced Draft Cooling Tower
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Induced Draft
The induced draft method is the most widely used. Its main advantages over the forced
draft system are:
• The fan is placed at the top of the tower and discharges upward. The air is
directed away at high velocity and has little chance of recirculating (returning to
the intake at the bottom of the tower)
• There is less chance of the fan being subject to icing because it is in the path of
the warm discharge air. Noise from the fan is at a minimum because of its
location. Air enters the tower through a very large louver section, thus
decreasing frost tendency in winter. The fans can be reversed in winter to
remove ice build-up
• Air flow and consequently the cooling effect are more evenly distributed across
all sections of the tower
Disadvantages of the induced system are:
• Increased fan power required to handle the hot air instead of the cold air
• Slightly larger physically
• Higher initial cost
Fig. 30 shows a counterflow mechanical induced draft tower. The fan at the top
produces induced draft. The cooling air enters at the side and flows across and up the
tower and out the stack in cross-flow design. The hot water enters at the top and falls
down through the fill to collect in the tower basin.
Figure 30
Mechanical Draft Tower
Page 208
Dry Tower
Another type of cooling tower which finds application in areas where cooling supplies
are very restricted is the dry tower. They enclose the cooling water in tubing instead of
spraying it into the air space as in the normal or evaporative type of tower. The tubes
used are finned aluminium to give maximum surface area. They are placed in the tower
in banks and mechanical or natural air currents cool them. Water lost through
evaporation and drift is eliminated and the system only has to make up losses due to
leakage in the system. An example is shown in Fig. 31.
Figure 31
Marley Dry Cooling Tower
Materials Of Construction
The materials used in cooling tower construction are chosen mainly for strength and
resistance to corrosion. Douglas fir and Redwood are generally chosen though other
woods such as cypress and pine can be used. Commonly used materials are fibreglass
composites for the walls and supports and fibre glass boarding for wall covering.
Fill and mist eliminators are constructed of treated slats of Douglas fir or PVC. Where
structural steel is used, galvanizing protects it. Hardware such as bolts and nails are
made of stainless steel. The fan blades are made of stainless steel, aluminium, or fibre
glass.
Chemical attack and rotting (a biological attack) causes deterioration of wood used in
cooling towers with high operating temperatures accelerating the process. For
protection, the wood is pressure treated with creosote or chromated copper arsenate and
the circulating water is chemically treated.
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COOLING PONDS
Purpose
The purpose of a cooling pond is the same as that of the cooling tower – to provide a
means of cooling the circulating water.
Principle And Design Of Cooling Ponds
The primary heat transfer mechanism in a cooling pond is evaporation. As with a
cooling tower, the ability of the air to remove the latent heat of vaporization depends on
the relative humidity of the air. However, because the cooling water cannot be broken
up into small droplets or into a film or sheet, the vaporization takes place on the surface
of the water. To achieve maximum evaporative cooling, the warm and cold layers of
water in the pond are mixed vertically. If this is not done, layers of cold and warm
water (thermoclines) form. This causes horizontal layered flow which restricts the
movement of the warmer water to the surface for evaporation and cooling (shortcircuiting). The end result of this is that only a portion of the pond’s cooling capacity is
used.
During warm weather (ambient temperatures higher than water temperatures) a properly
functioning cooling pond will utilize the soil surrounding the pond as a cooling source.
For this to occur, water must be circulated past the pond bottom. Mixing the cooler
“bottom” water throughout the water column will reduce the overall pond water
temperature. Bernoulli's law dictates that heat transfer will occur with the expansion of
air bubbles as they move from an area of high pressure at the bottom of the pond to
lower pressure at the top and ultimately atmospheric pressure above the water. The
homogenizing of the water is achieved by means of an aerator placed on the bottom of
the pond. There are several different types of aerators available. When the pond is
constructed, a liner is placed inside the pond, to prevent erosion of the floor and sides of
the pond. Fig. 32 shows a picture of a cooling pond at an industrial site.
Figure 32
Cooling Pond
Page 210
Objective 10
Describe the purpose, principle and design of
condenser atmospheric exhaust (relief) valves.
CONDENSER EXHAUST VALVES
Since the condenser is a closed vessel, it is possible for the back pressure to rise until it
is above atmospheric pressure. This happens, for example, if the cooling water flow is
stopped. The shell is not designed to withstand a pressure from the inside and would
soon burst. The atmospheric relief valve is designed to open when the pressure in the
condenser rises above atmospheric.
Referring to Fig. 33, under standard conditions, a vacuum holds the atmospheric valve
shut. A water seal, supplied with condensate, prevents air from leaking through. When
the pressure reaches 7 kPa, the force on the disc area is greater than the water head on
the reverse side, thus, the disc lifts relieving the pressure to atmosphere. The valve is
usually fitted with a pivoted lever and a chain brought to operating level. Its operation
can be checked when the machine is off load and a manual assist can be supplied in the
case of failing to open under emergency conditions.
Alternatively, some manufacturers fit rupturing diaphragms to the turbine exhaust
piping. These are designed to protect the condenser and low-pressure turbine against
overpressure by blowing out and relieving the pressure.
High output turbines are not fitted with atmospheric relief valves which are big enough
to release a full load steam volume. Instead, the turbine is equipped with a pressure trip.
Page 211
Figure 33
Atmospheric Relief Valve
Condenser Pressure Trip
A condenser pressure trip has a plunger, acted upon by a bellows balanced against a
spring. The bellows piece has condenser vacuum inside and atmospheric pressure
outside exactly as in the load suppression gear.
Under normal vacuum conditions, the plunger is held retracted against the spring. In the
event of loss of vacuum, followed by positive condenser pressure, the plunger extends
until it depresses a switch connected to the turbine overall tripping circuit. This is
usually arranged to disconnect the load and close the steam valves.
Page 212
Objective 11
Describe the purpose, principle and design of
condensate pumps.
CONDENSATE PUMPS
These pumps are used to remove the steam condensate from the condenser and pump it
through feedwater heaters and back to the deaerator. Some of the condensate from the
discharge of these pumps is also used as a cooling medium for the steam condensers
which are part of the air ejector system. Condensate pumps are centrifugal, single, two
or three-stage pumps, and may be set with their spindles vertical or horizontal.
These constant speed pumps run with their suction and discharge valves fully open, so
that they operate continually at cavitation point. This results in automatic regulation of
the flow of the pump to match the steam flow into the condenser. Great care is taken
with the sealing of the joints and glands of these pumps to prevent air infiltration and
thereby excessive oxygen content in the boiler feed.
Fig. 34 shows an example of a single-stage vertical pump. The gland is sealed with a
water supply from the discharge side of the pump. A connection between the suction and
the main condenser removes any vapour from the suction chamber which assists in
starting, and gives stability under changing load conditions.
Figure 34
Parsons Single-Stage Vertical Pump
Page 213
The condensate extraction pump shown in Fig. 35 is a multistage design used to develop
higher discharge pressures. This type pumps the condensate through the low pressure
heaters to the deaerator.
Figure 35
Vertical Multistage Condensate Extraction Pump
Page 214
Chapter Questions
1. Define the following terms:
a) Low-level jet condenser
b) Barometric condenser
c) Parallel flow
d) Counter flow
2. Describe the term regenerative as it applies to a surface condenser.
3. What are the advantages and disadvantages of a jet condenser compared to a surface
condenser?
4. What are the two methods used to deal with the expansion between the turbine
exhaust flange and the condenser?
5. a) Explain the impact that tube fouling has on the performance of a condenser.
a) Explain the impact that air leakage has on the performance of a condenser.
6. A condenser receives 20 000 kg/hr of dry saturated steam at 36.2°C. The condensate
outlet temperature is 34.6°C. Calculate the thermal efficiency for this condenser.
7. Explain the procedures required to troubleshoot condenser performance.
8. Describe the operation of an air ejector.
9. a) Describe the operation of a dual-flow cooling water intake screen.
a) What are the advantages of this filter as compared to the through-flow filter?
10. a) Give a brief description of how a cooling tower works.
a) What are the two classifications of cooling towers? Give a brief description of
each classification.
11. With the aid of a simple sketch, describe the operation of an atmospheric relief
valve.
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Page 216
Internal Combustion Engines:
Components and Auxiliaries
Learning Outcome
When you complete this learning material, you will be able to:
Explain the design, selection, and components of reciprocating internal combustion
engine installations including auxiliaries.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Explain design, applications, and selection criteria for the different types of
reciprocating internal combustion engines.
2. Explain fuels and combustion processes and fuels used by internal combustion
engines.
3. Describe the design of internal combustion engine scavenging and supercharging
arrangements.
4. Describe the design and components of internal combustion engine fuel
conditioning systems, injection systems, and ignition systems.
5. Describe the design and components of internal combustion engine cooling
systems and cooling water conditioning systems.
6. Describe the purpose, design and components of internal combustion engine
lubricating oil systems.
7. State the purpose and describe the control of a typical internal combustion
engine including the operation of safety devices.
Page 217
Page 218
Objective 1
Explain design, application, and selection criteria for
the different types of reciprocating internal combustion
engines
DESIGN
Reciprocating internal combustion engines are divided into either spark-ignition (SI) or
compression-ignition (CI) types. They can operate in either a two-stroke or four-stroke
mode. This results in four possible combinations. The two-stroke compression-ignition
engine and the four-stroke spark-ignition engine are the most common in industrial
applications.
THE FOUR-STROKE CYCLE
The four-stroke cycle occurs over two rotations of the engine, as illustrated in Fig. 1. It
consists of the following steps:
• Induction
• Compression
• Power
• Exhaust
Induction
As the piston moves down, air is drawn into the cylinder through the intake port. The
exhaust valve then closes. In spark-ignition engines, a mixture of air and fuel is drawn
into the cylinder — unless direct fuel injection is used.
Compression
The intake and exhaust valves are closed and the air (or air-fuel mixture) is compressed.
In spark-ignition engines, an electric spark ignites the air-fuel mixture just before top
dead centre (TDC) and starts the combustion process. In compression-ignition engines,
or fuel injected spark-ignition engines, fuel is injected prior to top dead centre after
which combustion occurs.
Page 219
Expansion
In spark-ignition engines, combustion is largely finished at the beginning of the power
stroke. The hot gases expand and force the piston down from top dead centre. The
exhaust valve opens just before the end of the stroke. In compression-ignition engines,
combustion continues for most of the power stroke.
Exhaust
The exhaust valve remains open and the products of combustion are exhausted to the
atmosphere. At the end of this stroke, the exhaust valve closes and the intake valve
opens. The process then repeats itself.
Figure 1
Four-Stroke Cycle
THE TWO-STROKE CYCLE
As shown in Fig. 2, the two-stroke cycle takes place over one revolution of the engine
with each stroke combining two of the strokes of a four-stroke cycle. To accommodate
this, the piston stroke must be longer. One advantage is that no intake or exhaust valves
are needed since the piston covers and uncovers the intake (a) and exhaust ports (b).
At the beginning of the first stroke, the intake ports are uncovered. Fresh air then enters
the cylinder while the exhaust ports are still open to exhaust the burnt gases from the
previous combustion. Once the piston moves up and covers the ports, compression
begins. Fuel injection and self-ignition occur before top dead centre. Meanwhile, fresh
air is drawn into the crankcase through the non-return inlet valve.
Combustion continues for much of the power stroke at close to constant pressure. The
fresh air in the crankcase is partially pressurized during this part of the stroke to assist
with induction. Toward the end of the stroke, the exhaust ports, and then the intake
ports, are uncovered.
Page 220
Figure 2
Two-Stroke Cycle
SPARK-IGNITION ENGINES
In spark-ignition engines, a spark ignites the air-fuel mixture. Fuel can be pre-mixed in a
carburetor or injected directly into the cylinder. Compression ratios, limited by the need
to prevent pre-ignition, or knock, range from 7:1 to 10:1. Supercharging, or precompression of intake air, is used to increase power output.
The thermodynamic cycle for spark-ignited engines is also known as the Otto cycle. The
ideal description of a thermodynamic cycle is shown in Fig. 3(a) along with the more
realistic version in Fig. 3(b). The numbers 1 to 4 correspond to the four strokes of the
four-stroke cycle.
Since most combustion takes place while the piston is approaching top dead centre,
spark-ignition is said to be a constant volume process. This is not strictly true as can be
seen in Fig. 3(b). Once combustion is finished, power is produced by expansion of the
hot gases. The combusted mixture is close to atmospheric pressure at the end of the
stroke.
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(a) Ideal Cycle
(b) Actual cycle
Figure 3
The Spark Ignited Four-Stroke Cycle
The swept volume is the volume traveled by the piston as it moves from bottom to top
dead centre and is equal to the area of the piston times the length of the stroke.
The clearance volume is the volume trapped above the piston at top dead centre. Both of
these are illustrated in Fig. 3. The compression ratio can be calculated from the
clearance and swept volumes using the following equation:
Compression Ratio =
Clearance Volume + Swept Volume
Clearance Volume
Note: Since other factors, such as the timing of the opening and closing of inlet and
exhaust valves, are also important, this is only an approximate compression ratio.
COMPRESSION-IGNITION ENGINES
In compression-ignition engines, spontaneous ignition occurs due to the rise in
temperature caused by high compression ratios. This results in a more efficient engine.
Compression ratios need to be higher than 12:1 to allow spontaneous combustion. Ratios
of 15:1 to 20:1 are typical, but can be as high as 25:1.
The ideal description of a compression-ignition cycle is shown in Fig. 4(a) along with a
more realistic version in Fig. 4(b). The numbers 1 to 4 correspond to the four strokes of
the four-stroke cycle. In a two-stroke engine, induction and compression (steps 1 and 2)
are combined into the first stroke, and power and exhaust (steps 3 and 4) are combined
into the second stroke.
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The rate of combustion in a compression ignition engine is controlled by injection of the
fuel in order to limit the peak pressure. Combustion continues as the flame front
advances. The process continues at essentially constant pressure although this is an
approximation, as can be seen in Fig. 4(b).
(a) Ideal Cycle
(b) Actual cycle
Figure 4
The Compression Ignited Four-Stroke Cycle
Comparison of Different Types of Engines
Although a complete discussion of the merits of two-stroke and four-stroke engines is
not required here, it is worthwhile pointing out some key differences.
•
•
•
•
•
Two-stroke engines do not require intake and exhaust valves and are thus
simpler, easier to maintain, and less expensive to build
Two-stroke engines produce power every stroke instead of every other stroke,
and therefore produce more power for a given engine size and weight. This
makes them noisier than four-stroke engines of the same size
Two-stroke engines are less efficient than four-stroke engines because the
induction and exhaust processes are less complete. However, superchargers can
be used to increase efficiency
Compression-ignition engines are more efficient than spark-ignition engines
because they operate at higher compression ratios
Compression-ignition engines that burn diesel fuel produce excessive emissions
and exhaust smoke that requires treatment
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APPLICATIONS
Reciprocating internal combustion engines provide a cost-effective power source for:
• Many types of vehicles
• Standby and base load electrical power generators
• Compressors
• Pumps
• Marine applications
• Industrial equipment applications
Power output ranges from very small (less than 5 kW) to very large (up to 50 000 kW),
but the most important range for oil and gas power generation applications is 500kW5000 kW. The focus of this module is stationary applications for power generation and
mechanical drive equipment using natural gas as a fuel.
Fig. 5 shows a typical 12-cylinder natural gas lean burn engine used to drive a
compressor. It has a special fuel system that minimizes exhaust emissions.
Figure 5
Typical 12-Cylinder Natural Gas Lean Burn Engine
(Courtesy of Tom Van Hardeveld)
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SELECTION
The successful application of any engine depends upon satisfying requirements related
to performance, operating costs, and expected engine life. This requires a thorough
understanding of available designs, engine rating systems, and knowledge of tradeoffs
that might be necessary.
Selecting an internal combustion engine for a specific application depends on factors
such as:
• Type of fuel available
• Expected performance ratings and load cycles
• Configuration options
• Installation requirements and constraints such as weight and size
• Maintenance resources available
• Life-cycle costs - capital, operating, and maintenance
• Noise and exhaust emission requirements
The type of fuel used is a major consideration. The cleanest and most readily available
fuel should be used. Pipeline quality natural gas is desirable because it delivers the most
efficient, cost effective and environmentally acceptable solution. Lower quality gaseous
fuels, such as landfill or sewage gas, require special considerations and could provide
less desirable operation because of poor efficiency and lower power output. Diesel fuels,
such as kerosene, provide reliable operation. However, they may be unsuitable where
emissions are an issue, or where fuel sources are not easily accessible. Lower grade
liquid fuels may be cost-effective for lower speed engines, but require fuel treatment and
could result in higher maintenance costs.
Configuration options include whether the engine is naturally aspirated (intake air is not
compressed) or turbocharged. A naturally aspirated engine is simpler because it has less
additional equipment, but performance is affected by altitude and ambient temperatures.
A turbocharged engine is more complex because it has a turbocharger and an
aftercooler, but it is less affected by external factors and produces more power.
Expected load cycles should be carefully analyzed for feasibility, impact on operation,
and maintenance requirements. Many engines can operate for extended periods at peak
load, but this increases maintenance effort and costs. Similarly, operation at light loads
is possible, but not desirable for longer periods, as operation may become erratic and
cylinders might be over lubricated. Estimating load patterns for power generation can be
quite complicated because of daily and seasonal load variations (weather and
temperature).
Most gas engines are available with low or high compression. High compression is
restricted to high quality fuels. Low compression is used for lower quality fuels, and
where less stringent emission requirements are in effect.
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When selecting an internal combustion engine, it is important to consult with the
manufacturer on recommendations for proper application, fuel rating, and approved
equipment configuration. Most manufacturers have a method for calculating fuel rating
that prevents detonation (engine knocking).
Page 226
Objective 2
Explain fuels and combustion processes used by
internal combustion engines.
FUELS
Most fuels used in internal combustion engines are based on hydrocarbons (hydrogen
and carbon). The main source is petroleum, either in the form of natural gas (methane),
or a grade of liquid petroleum — ranging from light condensates (e.g. propane) to
medium hydrocarbons (e.g. gasoline and kerosene) to heavier oils (e.g. heavy distillates,
residuals, and crude oil). Another source is low energy gas fuel obtained from landfills,
bio-gas digesters, or coal.
Gaseous fuels are a combination of a hydrocarbon, inert gases such as nitrogen, and
possibly contaminants such as sulphur. The overall composition must be carefully
considered since it affects combustion processes and emissions.
Liquid fuels may also contain contaminants or other products that can adversely affect
engine performance and increase emissions.
Heating value is an important fuel characteristic. This is the amount of energy obtained
from a standard amount of fuel when it is fully combusted. It is normally expressed as
lower heating value (LHV). When fuel is burned, water is one of the products of
combustion. It is converted to steam during combustion and remains in vapour form in
the exhaust. This extra energy cannot be used, and the amount of heat left over for
conversion to work is referred to as the lower heating value.
Various approaches are used to determine the suitability of a fuel for combustion and its
resistance to detonation, or knock. One common method is the octane rating system
developed for liquid fuels. This was adapted for gaseous fuels, but the results have not
proven satisfactory for the wide range of fuels in use. Therefore, manufacturers have
developed specific methods to evaluate fuels and relate them to engine rating, design
configuration, and control limits.
Gaseous Fuels
Many internal combustion engines use natural gas as a fuel source. However, there are
many types of natural gas. The specific composition needs to be considered before the
gas can be used.
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The use of contaminated fuel leads to increased maintenance. The presence of liquids or
condensates in natural gas causes pre-ignition, detonation, and other combustion
problems. Compounds such as hydrogen sulphide or chlorinated hydrocarbons
accelerate corrosion through the formation of acids. Natural gas with high levels of these
compounds needs to be treated.
In its original state, natural gas may be referred to as field gas, wet gas (due to the
presence of hydrocarbon liquids), or wellhead gas. It is generally unsuitable for use in
internal combustion engines. If it contains large amounts of hydrogen sulphide (H2S), it
is referred to as sour gas, and is highly corrosive and damaging to an engine.
Clean natural gas, sometimes called dry pipeline gas or sweet gas, consists of 85%-95%
methane. The remainder is usually a mixture of ethane, propane, butane, and other
heavier hydrocarbons, mostly in vapour form. It provides the best results for internal
combustion engines with respect to efficiency, engine life, performance, and emissions.
Natural gas with a low heating value can be produced from biomass (digester gas),
sanitary landfills, or a manufacturing process such as methane recovery from coal.
These gases often contain harmful by-products which require special treatment and
filtering. In addition, fuel systems may need to be changed to accommodate the higher
volume of these fuels before they can be used.
Table 1 shows typical heating values for different gaseous fuels, each of which requires
a different carburetion and fuel system configuration.
Table 1
Typical Heating Values for Gas Fuels
(Courtesy of Finning-Caterpillar)
High Energy Gas
Natural Gas
Low Energy Natural Gas
Biogas
Landfill Gas
55.0 – 94.3 MJ/Nm3
31.4 – 55.0 MJ/Nm3
23.6 – 31.4 MJ/Nm3
17.7 – 25.5 MJ/Nm3
15.7 – 23.6 MJ/Nm3
Liquid Fuels
Diesel fuel is the most common fuel used in compression-ignition engines. The most
important characteristics of good diesel fuel are cleanliness, self-ignition capability,
viscosity, volatility, and temperature.
Diesel fuels are generally sufficiently clean when produced at the refinery, but there is
substantial opportunity for contamination by dirt, water, or other substances during
transportation and storage.
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The self-ignition capability of a diesel fuel is indicated by its cetane number. This is the
measure of the ignition quality of the fuel, and is more important for higher speed
engines than for lower speed ones. If a low cetane number fuel is used in a high speed
engine, a considerable quantity of liquid will accumulate before ignition takes place,
resulting in engine knock.
Viscosity is important for heavier fuels or at lower temperatures. Heating may be
required in these cases.
At low temperatures, fuels can form waxy deposits which plug filters and cause gummy
deposits to build up in the cylinder. Fuels with a higher volatility prevent the build up of
deposits on cylinder walls.
Higher speed diesel engines are only suited to run on No. 1 and No. 2 distillate
(kerosene) but lower speed engines can use heavier fuels such as low grade residual oils
and Bunker C.
Additives may be used to:
• Improve cetane number
• Inhibit the formation of combustion deposits
• Absorb water
• Reduce foaming
COMBUSTION
Every fuel requires a precise amount of air to produce combustion. The stoichiometric
ratio is the chemically perfect air/fuel ratio (AFR) that results in complete combustion.
The equivalence ratio is the ratio of the stoichiometric ratio to the actual air/fuel ratio.
If the equivalence ratio is less than 1, the mixture is lean. If it is greater than 1, it is rich.
Maximum power is generated by a mixture that is about 10% rich (equivalence ratio of
1.1). The best fuel consumption is produced by a lean mixture (equivalence ratio of 0.9,
or 10% lean).
The inverse of the equivalence ratio (1/R), called the Excess Air Ratio or Lambda ( λ ),
is also used. In this case, values greater than 1 are lean and values less than 1 are rich.
Spark Ignition
One of the main differences between spark-ignition and compression-ignition engines is
the type of combustion. In spark-ignition engines, the fuel is pre-mixed with air in a
carburetor using an air/fuel ratio that is close to stoichiometric. If the mixture is too lean
or too rich, ignition and combustion may not occur, might be delayed, or could be
erratic. Compression-ignition engines use fuel injection instead.
When the spark occurs, the initial onset of combustion is quite slow, and there is a short
delay before rapid combustion spreads through the cylinder. Thus, the point of ignition
is always in advance of top dead centre as shown in Fig. 6.
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Figure 6
Cylinder Pressure for a Spark-ignition Engine
As combustion occurs, the expanding burned gas compresses and heats the remaining
unburned gas. This can cause detonation, or knock, if the unburned gas spontaneously
self-ignites ahead of the flame front. The severe pressure wave caused by detonation can
be very destructive to mechanical components.
Knock should not be confused with pre-ignition, which happens when a hot surface,
such as the tip of a spark plug, ignites the unburned gas prior to spark-ignition.
Increasing inlet air temperature decreases the knock margin; therefore, detonation may
occur more frequently in the summer.
Compression Ignition
In compression-ignition engines fuel is not pre-mixed with air; it is injected into the
cylinder. Combustion occurs spontaneously along a flame front where stoichiometric
conditions exist. Since combustion is caused by compression, not by a spark, preignition cannot take place.
Page 230
Objective 3
Describe the design of internal combustion engine
scavenging and supercharging arrangements.
SCAVENGING
Scavenging is the removal of combusted gases and the replacement with intake of fresh
air (or air-fuel mixture).
The intake and exhaust processes and the geometry of the cylinder, create turbulence.
Turbulence is important in speeding up combustion.
In four-stroke engines, because complete strokes are dedicated to intake and to exhaust,
scavenging can take place almost completely. Fig. 7(a) shows loop scavenging. Fig. 7(b)
shows cross scavenging while Fig. 7(c) is the uniform method of scavenging with
exhaust valve.
Figure 7
Two-Stroke Mixing Approaches
SUPERCHARGING
Several methods, including supercharging, are used to increase mixing and swirling, and
thus improve the intake, exhaust, and combustion processes. Supercharging precompresses the intake air to increase mass flow through the engine. Increasing mass
flow directly increases power output. Supercharging can increase the power output for a
given engine size by 20%-40%. However, it has almost no effect on efficiency. In twostroke engines, supercharging also improves scavenging.
Page 231
Supercharging can be accomplished in two ways:
• Turbochargers
• Superchargers
Turbochargers
Turbochargers use a compressor which is attached to a turbine driven by exhaust gases.
Turbochargers are common on many engines even though they increase the mechanical
complexity of the engine and its control. Fig. 8 shows a turbocharger layout with a
centrifugal compressor and an axial turbine.
Figure 8
Turbocharger Layout
(Courtesy of Waukesha Engine)
On V-type engines, twin turbochargers are often used as shown in Fig. 9.
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Figure 9
Typical Turbocharger for a Natural Gas Engine
(Courtesy of Tom Van Hardeveld)
An intercooler, shown in Fig. 9, is often inserted before the intake manifold because
compression increases air temperature and reduces the effect of increased density.
The amount of boost provided by the compressor is controlled by a wastegate in the
exhaust which dumps or bypasses unneeded exhaust air before it reaches the turbine.
The wastegate can be installed before the exhaust turbine.
Superchargers
Superchargers make use of a blower or compressor that is directly coupled to the engine.
Superchargers are not common in industrial applications because they are less efficient
than turbochargers. However, they respond faster to load changes (this is more
important in auto racing than in power generation). Superchargers usually consist of a
positive displacement compressor, such as the ROOTS™ blower shown in Fig. 10.
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Figure 10
ROOTS™ Blower
Page 234
Objective 4
Describe the design and components of internal
combustion engine fuel conditioning systems, injection
systems, and ignition systems.
FUEL CONDITIONING SYSTEMS
Spark-ignition engines pre-mix air and fuel using carburetors. Compression-ignition
engines use fuel injection systems. Mechanical engine control has largely been replaced
by flexible and adaptable electronic control systems that optimize engine operation and
efficiency. These systems adjust ignition timing to minimize fuel consumption without
causing knock, and may use an oxygen sensor in the exhaust to optimize efficiency (see
Fig. 14). They provide protection against abnormal conditions, such as overspeed, and
ensure that engine operation does not exceed various limits.
FUEL INJECTION SYSTEMS
Fuel injection systems are used on the following types of internal combustion engines:
• Spark-ignition
• Compression ignition
Spark-Ignition Engines
Many fuel systems burn a lean mixture to reduce emissions such as nitrogen oxides
(NOx). Since lean fuels can cause combustion problems, a prechamber, which burns a
rich mixture, is added to provide a torch that ignites and combusts the lean mixture. An
example of a prechamber design, also called stratified combustion, is shown in Fig. 11.
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Figure 11
Pre-Chamber Design with Stratified Combustion
(Courtesy of Waukesha Engine)
The design of a lean-burn fuel system is shown in Fig. 12. The main air/gas mixer
(carburetor), which has a governor controlled throttle, mixes the fuel and air. A pressure
balance line between the carburetor and main gas pressure regulator maintains a
constant gas-over-air pressure differential. The main gas pressure regulator ensures that
natural gas is provided to the main air/gas mixer, and to the prechamber air/gas mixer, at
the correct pressure. The prechamber air-fuel mixture is admitted into the cylinder
through a separate manifold and special admission valves.
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Figure 12
Lean Burn Fuel System
(Courtesy of Waukesha Engine)
Fig. 13 shows a close-up of the carburetor on the engine shown in Fig. 5. An air filter
ensures a clean supply of air. The fuel supply has a fuel filter. It may also have a heater
to keep the temperature of the natural gas above the dew point, and thus ensure that
liquids are not introduced into the engine.
Page 237
Figure 13
Example of a Carburetor for a Natural Gas Engine
(Courtesy of Tom Van Hardeveld)
Some engines have a separate air-fuel ratio control. This control, shown in Fig. 14,
measures the amount of free oxygen in the exhaust and adjusts the air and fuel flows
accordingly.
Figure 14
Example of an Air-Fuel Ratio Control
(Courtesy of Finning-Caterpillar)
Page 238
Air-fuel controlled engines have several advantages:
• They control emissions at constant levels despite variations in ambient
temperature, fuel quality, speed, and load
• They operate efficiently using a lean mixture that is close to misfire (failure to
ignite properly)
• High compression lean burn engines operate with a narrow margin between
misfire and detonation
• Air-fuel control ensures that engine operation stays within this band
Compressions-Ignition
Toward the end of the compression stroke, most compression-ignition engines inject
fuel directly, or indirectly, into the cylinder using a solid (airless) injection system.
Indirect injection systems use a prechamber to speed up combustion and allow engines
to run faster. Many different prechamber designs are used. Initial combustion occurs in
the prechamber, and then the burning fuel-air mixture is injected into the main cylinder.
This action produces swirling and turbulence that speeds up the rate of combustion.
Indirect injection is not as effective in two-stroke engines since the increased turbulence
interferes with the exhaust portion of the stroke and starting the engine is more difficult.
For slower engines, direct injection is more effective because rapid combustion is less
important at lower speeds.
A typical direct fuel injection system for a small engine is shown in Fig. 15.
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Figure 15
Fuel Injection System
Fuel pumps control the load and speed of diesel engines by metering the amount of fuel
supplied to the fuel injectors. An example of a mechanically controlled fuel pump is
shown in Fig. 16. Fuel injectors are an important component of the ignition system since
they provide an accurate high-pressure spray that is easily combustible.
Page 240
Figure 16
Fuel Pump
IGNITION SYSTEMS
Battery operated ignition systems are adequate for low compression engines. In Fig. 17,
a primary coil, or transformer, boosts the voltage, and a distributor provides high voltage
pulses to the spark plugs.
Figure 17
High Tension Battery Distribution Circuit
In Fig. 18, individual coils are used for each cylinder to minimize the length of the high
voltage lines.
Page 241
Figure 18
Low Tension Battery Distribution Circuit
High compression (1700 – 4300 kPa) spark-ignition engines require high voltage (25
000 to 30 000 volts) to produce an adequate spark. Special spark plugs are used that
operate at low enough temperatures to prevent pre-ignition, yet high enough to promote
rapid combustion and prevent carbon build up on the electrode.
High compression engines commonly use a magneto. This is a rotating magnet, driven
from the engine that does not require a battery because it uses a changing magnetic field
to produce its own current. The alternating current generated by the magneto is rectified
to direct current and stored in a capacitor. Silicon controlled rectifiers release this
electrical energy to high voltage coils located close to each cylinder. A pickup sensor,
which reads magnetic reference marks on a timing disc, records the exact position of the
crankshaft and tells each coil when to fire. The coils can be seen on top of each cylinder
in Fig.5.
Fig. 19 shows a typical spark plug with a coil (high energy ignition transformer)
mounted on each cylinder.
Figure 19
Spark Plug and Ignition Coil
Page 242
A magneto is shown is Fig. 20.
Figure 20
Solid State Magneto
(Courtesy of Finning-Caterpillar)
Modern ignition timing systems are electronically controlled by variable ignition to
enhance engine performance and prevent detonation. An example of an ignition timing
system is shown in Fig. 21.
Figure 21
Ignition Timing System
(Courtesy of Finning-Caterpillar)
Page 243
Page 244
Objective 5
Describe the design and components of internal
combustion engine cooling systems and cooling water
conditioning systems.
PURPOSE OF COOLING
The purpose of engine cooling is three-fold:
• To promote efficiency
• To enhance combustion
• To ensure mechanical reliability
Engine efficiency is improved when more air is inducted into the cylinder. When the
cylinder walls are cooled, more air can be drawn into the cylinder. In spark-ignition
engines, combustion is enhanced by having cooler cylinder walls which will also inhibit
knock and detonation.
Mechanical reliability is adversely affected by high metal temperatures and thermal
strain. In addition, if the temperature of the top rings on the cylinder exceeds 200°C,
lubricants will degrade and fail to provide adequate protection. Thus, it is very important
that the cooling system function properly since it has to remove about 20%-40% of the
energy input into the engine.
COOLING WATER SYSTEMS
Most internal combustion engines use a mixture of water and industrial grade antifreeze
(such as ethylene glycol) which contains various inhibitors and corrosion protectors. A
50/50 water to antifreeze mixture provides the best overall protection against freezing
and boiling, but this can reduce the cooling efficiency by as much as 15%. A minimum
of 30% antifreeze is usually recommended, but local conditions and manufacturer
recommendations should be carefully checked. Cooling water samples should be taken
periodically and checked for contaminants and antifreeze strength.
COOLING SYSTEM DESIGN AND COMPONENTS
Cooling systems normally use forced circulation. The coolant pump is powered by the
engine, either by a gear or by belts. As shown in Fig. 22, the coolant circulates through
the cylinder walls, the cylinder head, and the exhaust manifold. A thermostat (or
multiple thermostats) divides the coolant between a direct return line and a cooling
circuit that passes through the heat exchanger. The heat exchanger may use air or oil. A
top-up reserve tank is often included. Fig. 22 also shows an auxiliary water pump that is
used to feed the oil cooler.
Page 245
Figure 22
Cooling System
(Courtesy of Waukesha Engine)
There are many cooling system configurations. Fig. 23 shows an example of an air to air
aftercooler engine. The type used depends on the application, and on whether or not
there are other cooling requirements, such as gas compression. For cogeneration
applications, the cooling system may be used to heat water sources for domestic or hot
water heating.
Page 246
Figure 23
Cooling System for Compressor Application
(Courtesy of Finning-Caterpillar)
Page 247
Page 248
Objective 6
Describe the purpose, design and components of
internal combustion engine lubricating oil systems.
PURPOSE OF LUBRICATION SYSTEMS
Lubrication is critical to engine operation for the following reasons:
• Minimizes friction losses of sliding and rotating surfaces
• Reduces friction wear on moving components
• Cools engine parts such as pistons that cannot be cooled directly by cooling
water
• Cleans the engine by flushing away wear particles
• Helps seal piston rings in the cylinders
OIL PROPERTIES
Oil has several properties that are important for successful engine operation including:
• Viscosity
• Additives
• Acidity
• Contaminants
Viscosity
Viscosity measures the resistance of a fluid to deformation under pressure. Oil, with a
higher viscosity, is better able to withstand the friction forces from two adjacent
components. However, friction losses are higher with a higher viscosity, so the proper
level of viscosity has to be determined for each application. Since viscosity decreases
with temperature, operating temperatures have to be taken into consideration.
Page 249
Additives
Additives are present in lube oils to improve performance, to prevent deterioration, and
to combat contaminants. Common additives are:
• Detergents to clean engine surfaces by reacting with oxidation products
• Oxidation inhibitors to prevent increases in viscosity, organic acids or other
compounds
• Dispersants to prevent the formation of sludge by keeping contaminants in
suspension
• Alkalinity agents to neutralize acids
• Anti-wear agents to reduce friction
• Pour-point dispersants to counteract the formation of waxes at low temperatures
• Viscosity improvers to increase viscosity at higher temperatures
Acidity
Acidity must be closely controlled because acids can corrode wetted oil system surfaces.
Contaminants
Oil quality can deteriorate over time due to heat and use. It can become contaminated by
particles caused by the internal wear of engine components, or by external contaminants
such as dirt or glycol.
Oil can also be affected by fuel contaminants such as hydrogen sulphide (H2S). If
sulphur compounds cannot be totally removed from the fuel, additional precautions,
such as enhanced oil sampling and reduced oil replacement intervals, need to be taken.
The engine manufacturer should be consulted on recommended lube oil type.
OIL SYSTEM DESIGN AND COMPONENTS
The internal oil flow system is quite extensive, as shown in Fig. 24. A header distributes
pressurized oil to the main bearings. The oil then flows through drilled passages in the
connecting rods to the connecting rod bearing and the piston rod. From the piston rod, it
is sprayed onto the underside of the piston crown for cooling, and then drains into the
sump. The cylinder head has a separate oil supply that lubricates the camshaft assembly
and rocker arms. Oil is supplied to the turbocharger and the gear train.
Page 250
Figure 24
Internal Oil Flow System
(Courtesy of Waukesha Engine)
A typical external oil system schematic is shown in Fig. 25. The engine crankcase, or
sump, serves as the oil reservoir. Oil is drawn from the lowest part of the sump through
a screen that prevents foreign material from entering the lube oil circuit. A positive
displacement pump, gear-driven from the engine, is usually used as a main oil pump.
Excess oil is dumped back into the sump by the oil pump relief valve. Then, the oil
flows to the cooler where a temperature control valve allows the correct amount of oil to
be cooled. The final oil pressure is adjusted to compensate for installation differences.
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Figure 25
External Oil System Schematic
(Courtesy of Waukesha Engine)
The main oil filter is usually a full-flow type, and typically filters up to 10-20 microns.
With a clean filter, the differential pressure is about 15-20 kPa. Maximum allowable
differential pressure is normally about 100 kPa. An example of a cooler and filter
assembly is shown in Fig. 26.
Page 252
Figure 26
Oil Cooler and Filter Assembly
(Courtesy of Tom Van Hardeveld)
Since the main oil pump cannot supply sufficient pressure until the engine is rotating, a
separate electric prelube pump activates on startup to provide initial lubrication prior to
and during startup.
Some engines (those used for backup power generation) have quick-start capability
aided by a low pressure pump that operates when the engine is not running to minimize
startup time.
Page 253
Page 254
Objective 7
State the purpose and describe the control of a typical
internal combustion engine including the operation of
safety devices.
ENGINE CONTROL
The control of a reciprocating internal combustion engine consists of a number of
different systems including:
• Speed governing
• Ignition control
• Fuel system control
• Cooling system control
• Lubrication system control
• Safety and engine protection
• Startup and shutdown sequencing
Most systems incorporate extensive electronic and computerized control and monitoring
devices. Various aspects of control, such as oil cooling, are controlled by independent
devices such as thermostats. If the equipment is unattended, additional supervisory
control and monitoring systems may need to be installed at a remote location.
SAFETY AND PROTECTION SYSTEMS
Protection can be provided by:
• A local alarm that activates an indicator or audible horn but causes no additional
actions
• A remote alarm that is transmitted to a control centre, pager, or other remote
device
• A normal shutdown with local or remote indication
• An emergency shutdown with local or remote indication
• A manual emergency shutdown of the engine via a local panel
Most protection systems use both an alarm and a shutdown, but every situation has to be
considered separately. Factors such as the criticality of the equipment, local regulations
and conditions, and company practices need to be considered when planning a
protection system.
A typical electronic engine protection system is shown in Fig. 27.
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Figure 27
Engine Protection System
(Courtesy of Finning-Caterpillar)
General Engine Operation Protection
Protection for general engine operation may include:
• Intake air restriction caused by plugging of the intake air filter or blockage of the
intake
• High intake air temperature caused by high ambient temperature or inadequate
cooling by the intercooler (for turbocharged engines)
• Engine overspeed caused by loss of load
• High vibration caused by a number of different factors such as mechanical
failure, unbalance, or misalignment
• High crankcase pressure due to wear or failure of the piston ring or cylinder
• High main bearing temperature caused by long term wear or high oil temperature
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Fuel System Protection
Fuel system protection may include:
• Low fuel temperature resulting from failure of the fuel heater
• High fuel pressure due to failure of the fuel regulator
• High fuel filter differential pressure due to clogging of the filter
Cooling System Protection
Cooling system protection may include:
• Low coolant level in the coolant reservoir
• High jacket water temperature due to failure of cooling or inadequate coolant
flow
• Cooler vibration due to unbalance, or misalignment of the cooler fan
Oil System Protection
Oil system protection may include:
• Low oil pressure due to failure of the oil pump or a restriction
• Low oil temperature resulting from failure of the oil heater
• Low oil level in the sump
• High oil pressure caused by failure of the oil pump relief valve
• High oil temperature caused by failure of the oil cooling system
• High oil filter differential pressure due to clogging of the filter
Combustion System Protection
Protection for combustion systems may include:
• High exhaust gas temperature (measured by a pyrometer -usually one per
cylinder)
• High exhaust gas temperature spread (difference between the highest and lowest
temperature)
• Activation of a detonation sensor (usually one per cylinder)
Safety Parameters
During startup, relevant safety parameters include:
• Low starting gas pressure (for an air or gas starter)
• Excessive cranking time due to a bad starter or insufficient start pressure
• Low oil pressure caused by cold oil or failure of the prelube pump
Additional protective shutdowns may be added for fire and gas leak detection if the
engine is located in a hazardous location.
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Chapter Questions
1. Describe the steps of a four-stroke cycle for a spark-ignition engine.
2. What are the differences between a spark-ignition and a compression- ignition
engine?
3. List the two types of supercharging and describe how they function.
4. With the aid of a simple sketch, describe the design of a lean burn fuel system used
in a spark ignition engine system.
5. Describe three major purposes for engine cooling.
6. What are three aspects of oil quality that need to be monitored?
7. Discuss four operating conditions for which engine protection is required?
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Internal Combustion Engines:
Operation and Maintenance
Learning Outcome
When you complete this learning material, you will be able to:
Describe general routine and major maintenance requirements, and detailed operating
and troubleshooting procedures for internal combustion engines.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Describe the detailed startup procedures for an internal combustion engine.
2. Describe the detailed shutdown procedures for an internal combustion engine.
3. Explain the routine maintenance and monitoring requirements for an internal
combustion engine.
4. Explain the major maintenance and overhaul requirements for an internal
combustion engine.
5. Explain the troubleshooting of combustion and engine problems.
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Objective 1
Describe the detailed startup procedures for an internal
combustion engine.
INTRODUCTION
The startup of an internal combustion engine is usually not complicated, but it is
important to follow procedures rigorously to ensure both the safety and the integrity of
the equipment.
The following description is for a reciprocating internal combustion engine, but the
description will vary according to the make and type of engine, its application and use
and specific installation and environmental conditions.
Internal combustion engine operators should be fully aware of and understand written
procedures and manuals provided by manufacturers, equipment packagers, and the
operating company. Procedures and guidelines provided by the manufacturer and/or
equipment packager must be strictly followed. The equipment operator will have his
own practices and procedures that should also be understood and followed.
Different startup procedures are used for:
• Standard startup for frequently used equipment
• Standard startup for intermittently used or backup equipment
• Startup after routine or minor maintenance
• Startup after major maintenance or overhaul
BASIC STEPS IN STARTUP
Most start-ups are handled automatically by the engine control system with little or no
intervention from an operator. Some engines are located in a remote location and can be
started and stopped from a remote control room without on-site attendance. Other
engines can be started automatically, such as a backup generator that starts
automatically when there is a loss of main power.
The basic steps in a startup are:
1. Pre-start inspection
2. Engine barring
3. Initiation of startup either manually or automatically
4. Startup sequence including engine cranking, ignition, idling and loading
5. Post-startup checks
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Pre-Start Inspection
Steps required for the pre-start inspection vary with the type of startup. For automatic
starting and when the engine is in a remote location, these steps cannot be carried out
but protective devices minimize the risks in the control system.
If the equipment is used frequently and no maintenance work has been done, only a few
checks need to be carried out. These may include a walk-around and visual inspection of
the engine to check for:
• Leaks from the coolant system, especially from the pump seals, fittings, and
hoses
• Leaks from the oil system including pumps, fittings, piping, and tubing
• Coolant level
• Oil tank and sump level
• Air intake obstructions
• All guards and covers are in place and securely fastened
• General hazards
• Diesel fuel day tank levels
If routine, minor, or major maintenance has been done, the work area should be cleaned
up and all tools, parts, and supplies removed prior to startup. Shutoff valves need to be
opened or unlocked. Other maintenance steps and a more thorough pre-start inspection
may be required.
Engine Barring
Large engines require barring during shutdown. The pre-lube pump is started and then
the engine is reverse barred for at least two full revolutions. Check for coolant in the
cylinders. The barring motor is then manually or automatically started and the engine is
barred over for not more than one hour before the scheduled start.
Initiation of Startup
The startup is initiated by one of the following:
• An automatic start signal to the engine from a control system or device, for
example, based on a loss of power (for an electric generator)
• A start signal initiated from a control system, either on-site or from a remote
location, by a control system operator such as the example in Fig. 1
• A manual start using a pushbutton on a local operator panel such as the one
shown in Fig. 2
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Figure 1
Computerized Control Panel
(Courtesy of Finning-Caterpillar)
Figure 2
Manual Start Panel
(Courtesy of Tom Van Hardeveld)
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Most engines have controls that check the status of permissives or signals that have to
be in the correct state for the start to commence. Some of these signals clear
automatically when the abnormal condition goes away but others have to be reset
manually. Some examples of permissives are:
• Lube oil temperature
• Jacket water temperature
• Fuel gas pressure
Startup Sequence
The startup sequence following depends on the type of engine and starting system.
1. To lubricate the engine, operate the prelube pump for a determined time period
after sufficient pressure is obtained.
2. If so equipped, the barring device, used to rotate the engine, should be engaged.
3. Engage the starter, the engine cranks over, and ignition commences.
4. Once the engine operates on its own, the starter is turned off.
5. The engine operates at idle speed until it warms up.
6. Load the engine by closing the breaker to the generator.
7. If the engine cranks for a determined time period, it will shutdown on overcrank.
Starting systems may be electric, using an electric motor run from a battery or AC
power. Either of these systems is common with smaller engines. Larger engines usually
need higher starting torque which requires a starter operated by air (2000 kPa) or by
high pressure gas.
A start system, using an air starter and an air-operated prelube pump, is shown in Fig. 3.
An air compressor supplies compressed air to a storage tank. Pressure regulators ensure
the correct pressure for the starter and the prelube pump. The air to the starter is tied into
the barring device to make sure that the engine cannot be started until the barring device
is disengaged. Upon initiation from the control panel, a solenoid valve is activated and
allows control air to be fed to the prelube relay valve which then provides compressed
air to the prelube pump. Once prelube is completed, another signal is sent to the starter
solenoid valve which activates the starter relay valve and allows the main air supply to
reach the starter.
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Figure 3
Air Start System
(Courtesy of Finning-Caterpillar)
Post-Startup Checks
Once the engine is operating, check for any coolant and oil leaks. Record the operating
conditions, speed, pressures, and temperatures, on a log sheet to ensure they are within
acceptable limits and to use for future comparison to see if the engine is operating at its
normal conditions. Individual pressures are recorded if the engine contains multiple
turbochargers. Large diesel engines have individual cylinder pyrometers. Once the
engine is loaded, the cylinders should be checked to see that the temperatures are
balanced. The date and time of the startup and the running hours on the hour meter
should be recorded in the log book along with any relevant observations or problems
encountered.
Cold Starting
In low ambient temperature conditions, it may be necessary to heat the lube oil and
possibly the jacket water or coolant to keep the engine block warm. If the oil is too cold,
the starting torque may be too high and prevent the engine reaching the required
cranking speed.
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The oil may be heated with a heater in the oil tank or by circulating the oil or coolant
through a heat exchanger. The oil or coolant temperature must be within acceptable
limits before a start is initiated. Table 1 shows a typical approach where the ambient
temperature is too low, so a slow warm-up is required. If a slow warm-up isn’t possible,
the lube oil and jacket water (JW) must be heated.
Table 1
Cold Starting Limits and Options
(Courtesy of Finning-Caterpillar)
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Objective 2
Describe the detailed shutdown procedures for an
internal combustion engine.
SHUTDOWN PROCEDURES
There are two types of shutdowns:
• Normal
• Emergency
Normal Shutdown
A normal shutdown may be initiated by one of the following methods:
• Automatically by the control system if the engine is not required, for example,
when commercial power is restored and the backup generator is no longer
required
• Remotely by an operator at another location with a stop signal sent to the site
• Manually by an operator on-site using a stop button at a local or remote panel
Upon activation of a normal shutdown, the load is reduced and the engine operates at
idle speed for 15-30 minutes. Closing the fuel valve first and shortly afterwards
(typically 10 seconds) stopping the ignition, stops the engine so that the fuel
downstream of the fuel valve is exhausted and not allowed to collect in the engine. The
prelube pump is operated for a predetermined time as a post-lube to assist with
lubrication on run-down and for cooling.
Emergency Shutdown
An emergency shutdown may occur as a result of:
• Automatic shutdown by the control system if the protective device is activated or
if the parameters such as speed, pressure, or temperature are exceeded
• Manual shutdown using a pushbutton
In an emergency shutdown, there is no cool down period and the fuel valve closes
immediately. If the emergency does not endanger the operator or the condition of the
engine, the ignition remains on for a short period so that all of the fuel is burned and not
left in the engine and the exhaust system. For safety-related emergencies, the ignition is
stopped at the same time as the fuel valve is closed. In these cases, when restarted, the
engine should go through a purge cycle and crank for approximately 10 seconds with the
fuel valve closed and the ignition system off. The post-lube cycle is activated as with a
standard shutdown.
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Objective 3
Explain the routine maintenance and monitoring
requirements for an internal combustion engine.
INTRODUCTION
Good maintenance is important to ensure power output, efficiency, and long term engine
condition. The results of good or bad maintenance are often not immediately evident,
but there is a definite impact over the long term on performance and cost.
The engine manufacturer generally specifies the details of routine maintenance and
monitoring of the internal combustion engine. However, these specifications apply to
average conditions and every user has to consider whether the amount, frequency and
type of maintenance have to be adjusted to account for the severity of the operating
conditions. There are two major factors that affect maintenance:
• Environmental conditions
• Load
Environmental Conditions
Environmental conditions include:
• High or low ambient temperatures
• High altitude operation
• External contaminants such as salt, dust and sand in the air
• The presence of contaminants in the fuel
Load
If operated consistently at close to rated load, the reciprocating internal combustion
engine operates most efficiently and requires the least maintenance. In some cases,
higher than the rated load is allowed for peaking loads but these will always impact
maintenance requirements. Operating at part load is detrimental to engine condition
because the engine becomes over-lubricated. High cylinder pressures position the piston
rings with the right clearance for sufficient lubrication. The problem is less severe for
turbocharged engines. Typical time limits for part load operation are shown in Table 2.
Referring to Table 2, a “NA” engine is one that is naturally aspirated while “TA” engine
is turbo aspirated.
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Table 2
Time Limits for Part Load Operation
(Courtesy of Finning-Caterpillar)
Look at vendor testing, use relevant experience, and do an in-depth analysis to develop a
maintenance program that is applicable to a specific situation. The results can be
documented in a computerized maintenance management system and include the
following:
• A detailed task description
• How often the task is done
• Time and skills required
• Special procedures
• Spare parts needed
Work orders can then be issued automatically to ensure that all tasks are carried out on
time and results are documented.
ROUTINE MAINTENANCE
Routine maintenance consists of minor tasks such as the following:
• Visual monitoring and inspection
• Recording engine parameters on a log sheet
• Checking fluid levels
• Sampling fluids (oil and coolant)
• Replacing filters
• Greasing bearings
• Testing relief valves
• General cleanup
• Calibrating control devices and instrumentation
• Replacing sparks plugs
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The frequency with which these tasks are performed depends on the location of the
equipment, remote or central, attended or unattended, and the type of engine. It is
standard for visual monitoring and logging to be done once per shift or once per day.
Other checks, such as oil and coolant testing, may be done once per week or even once
per month. Other tasks are done typically at 6 and 12 month intervals. Some, such as oil
changes, are based on operating hours or lubricant analysis.
Cooling System
Routine maintenance of the cooling system may include:
• Inspecting cooling system components, piping, and hoses for leaks
• Monitoring coolant level
• Checking belt tension on pumps
• Greasing water pumps
• External cleaning of radiator or air cooler
• Sampling coolant (optional)
• Cleaning and flushing cooling system
Because coolant contains corrosion inhibitors and usually antifreeze, the quality of the
coolant is important. Even where regular sampling and testing is done, regular cleaning
and flushing is still required.
Lubrication System
Routine maintenance of the lubrication system may include:
• Inspecting lubrication system components, piping, and hoses for leaks
• Monitoring oil levels
• Monitoring oil filter differential pressure
• Checking belt tension for pumps
• Oil sampling
• Testing relief valves
• Lube oil pressure adjustment
• Oil change
There may be various oil levels to monitor. The most important oil level is in the
crankcase because it supplies oil to the engine. The crankcase may be refilled
automatically from a makeup tank that is topped up from barrels or a tanker truck. The
makeup tank also has a level indicator. The oil level indicators in the crankcase and the
makeup tank may be tied into the control system with an alarm and possibly an
automatic shutdown for the crankcase oil level.
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Different approaches may be used for ensuring oil quality. Oil quality may be affected
by:
• External contaminants such as dirt, sand or water
• Contamination by combustion products
• Coolant leaking from the oil cooler
• Increase in viscosity
• Increase in acid number
• Depletion of oil additives
• Particle wear from moving and sliding surfaces
For smaller engines, it is usually sufficient to replace the oil on a regular basis as
determined by operating hours. If engine usage is low as with backup generators ( less
than 50%), base it on calendar time. A yearly oil change is standard.
For larger engines, it is common practice to take oil samples every 1-3 months and to
have them analysed for contaminants. The timing of the oil change can then be based on
the condition of the oil. Table 3 presents typical condemning limits for lube oil used on
a turbocharged natural gas fuelled engine.
Table 3
Lube Oil Condemning Limits
(Courtesy of Waukesha Engine)
An online centrifuge spinner, such as the one shown in Fig. 4, is used to clean the oil.
The photo also shows a pair of regular bypass filters. It is a bypass system, so only a part
of the oil is circulated through the centrifuge and cleaned.
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Contaminant particles are collected on a paper filter that is replaced at regular intervals
established by checking the amount of deposit collected. Bypass filters keep the oil
clean and serve to increase the time between oil changes by approximately 25%.
Figure 4
Online Oil Cleaning Using a Centrifuge Spinner and Bypass Filters
(Courtesy of Tom Van Hardeveld)
Fuel and Ignition Systems
Routine maintenance of the fuel and ignition systems may include:
• Inspecting and greasing (if needed) governor and carburetor linkages
• Inspecting governor oil level
• Monitoring fuel filter differential pressure
• Inspecting ignition wiring
• Adjusting the carburetor and governor
• Checking ignition timing
• Checking pressure regulators
• Cleaning and re-gapping or replacing spark plugs
• Checking fuel injectors on diesel engines for unobstructed motion (shellac often
causes them to stick wide open)
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Engine Components
Routine maintenance for engine components may include:
• Inspecting air intake filter for obstruction
• Monitoring air filter differential pressure
• Checking exhaust back pressure
• Checking crankcase pressure and breather cap
• Checking turbocharger
• Cleaning intercooler (for turbocharged engines)
Instrumentation and Controls
Routine maintenance for instrumentation and controls may include:
• Visual inspection of the instrumentation and controls wiring and connectors to
ensure they are secure
• Calibrating temperature and pressure switches
• Calibrating temperature and pressure sensors
• Testing the overspeed switch and protection system
MONITORING
To ensure the continuous operation of an internal combustion engine, it is important to
monitor the engine parameters. Readings are recorded on a log sheet. Computerized
monitoring programs may be used with log data gathered either with a hand-held data
collector or by continuous monitoring through the control system.
Table 4 shows an example of a paper engine log sheet. The date and time of the log is
recorded along with the name of the operator who completed it and the hours on the run
meter. Each parameter is clearly described including its unit of measure. Alert values are
also noted for each parameter where they are relevant. Where an alert value has been
exceeded, the reading is circled.
The sequencing of the parameters is always an issue. For recording purposes, sequence
the parameters in the order that the readings are taken. When viewing the results,
organize the readings logically according to systems and types of readings. The log
sheet in Table 4 is organized this way but has a separate column which indicates the
normal input sequence for reference.
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Sometimes a calculated value is required to recognize an abnormal condition. If the
calculation is simple, it can be added to the log sheet, as in Table 4, with the exhaust
temperature spread and several pressure and temperature differences. The spread is the
difference between the lowest and highest exhaust temperatures. If the spread is caused
by an exhaust temperature that is too high, the carburetor could be receiving too much
fuel. If the temperature is too low, there could be too little fuel or incorrect timing.
Another calculation shown in Table 4 is the manifold pressure and temperature
differences that apply to an engine that has a right bank and a left bank, each with its
own turbocharger.
Everyone who logs equipment needs to be trained not only how to take readings but also
what the readings are used for and what to do if an alert is exceeded. Someone who is
familiar with the engine and its operation should document the abnormal information
separately from the log sheet.
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Table 4
Example of a Log Sheet
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Objective 4
Explain the major maintenance and overhaul
requirements for an internal combustion engine.
INTRODUCTION
Major maintenance requirements for an internal combustion engine vary considerably.
Manufacturers provide detailed instructions and recommendations on major
maintenance that must be carefully followed. However, each engine is considered
separately and the frequency of maintenance is dependent on individual load, type of
fuel, and environmental factors.
MAJOR MAINTENANCE
The following description is an example of the types of major maintenance that might be
carried out, but it should never be used as the basis for an actual maintenance program.
Some maintenance activities relate to repair and replacement of major components in
auxiliary systems. These can usually be done as needed without major impact on the
availability of the engine.
Other maintenance actions deal with major mechanical components including pistons,
cylinders, heads, crankshaft, valves, rocker assemblies and camshafts. If maintenance of
these parts is required, it is often more effective to perform a complete overhaul of all or
most of these components because of the time required. Typically, this occurs every
30,000 to 50,000 hours or 5 years for a high usage engine. If the engine is small enough
(up to approximately 1000 kW), it may be possible to remove the entire engine, replace
it with a spare or rental, and then overhaul it in a repair facility. Otherwise, the overhaul
is done on-site and takes 4 - 6 weeks to complete.
Cylinder Heads
Cylinder heads incorporate the valves and the rocker mechanism that activate the valves
as controlled by the camshaft (see Fig. 5). The valves close against a valve seat that
wears over time, a process that is called valve recession. There are screws in the rocker
mechanism (see Fig. 5 and Fig. 6) that allow the valve clearance (or valve lash) to be
adjusted on a regular basis (every 3 - 6 months). On large engines, each cylinder has an
individual head.
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Figure 5
Rocker Arm Assembly
(Courtesy of Waukesha Engine)
Figure 6
Valve Adjusting Components
(Courtesy of Waukesha Engine)
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The valve seat is replaced when the valve recession reaches a specified limit. The valve
guide in which the valve stem is contained also wears over time and is replaced. As
illustrated in Fig. 7, a manufacturer has specified limits for the critical lettered
dimensions. It is common for the entire cylinder head to be refurbished at once with all
valves, valve seats and guides, and other worn components replaced.
Figure 7
Valve Train Dimensions
(Courtesy of Waukesha Engine)
Cylinders and Pistons
Cylinders have sleeves (also called liners) that can be replaced when they exceed
prescribed tolerances or become damaged. Excessively worn liners cause blow-by into
the crankcase which reduces cylinder pressure and contaminates lube oil. Worn cylinder
liners may cause increased crankcase pressure. Diesel engine liners should be checked
for cavitation erosion on the leeward side of the coolant flow direction.
An example of a cylinder sleeve is shown in Fig. 8 and Fig. 9. There are external
grooves for rubber or Teflon rings toward the bottom of the sleeve that seal against the
crankcase. At the top of the sleeve is a flange that ensures that the sleeve stays at the top
of the crankcase. Diesel engine sleeves should be checked for cavitation erosion of the
lee side of the coolant flow direction.
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Figure 8
Cylinder Sleeves
(Courtesy of Waukesha Engine)
Figure 9
Crankcase and Cylinder Sleeve
(Courtesy of Waukesha Engine)
The main area of wear with pistons is the piston rings which can be replaced. Important
piston and piston ring dimensions are shown with letters in Fig. 10. The piston may have
to be replaced if there is wear where the piston pin connects to the connecting rod, Fig.
10(C).
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Figure 10
Pistons
(Courtesy of Waukesha Engine)
Rods, Crankshaft, Camshaft, and Bearings
Bearings on the crankshaft include main support and connecting rod bearings. Required
clearances are crucial to proper operation, as shown in Fig. 11 and Fig. 12.
Figure 11
Connecting Rod Dimensions
(Courtesy of Waukesha Engine)
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The crankshaft deflection, shown as “D” in Fig. 12, is measured with a crankshaft
micrometer. When the load is direct coupled to the engine flywheel, outboard bearing
misalignment can cause the crankshaft to flex as it rotates. Engine specifications will
indicate the maximum allowable deflection. The outboard bearing must be aligned to
keep the deflection within limits. Engine with flexible couplings or universal drive
shafts do not experience this problem.
Figure 12
Crankshaft Dimensions
(Courtesy of Waukesha Engine)
Fig. 13 illustrates a typical main bearing shell. The lobes on the camshaft will wear and
may have to be repaired or replaced.
Figure 13
Lower Main Bearing Shell
(Courtesy of Waukesha Engine)
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Another part of the rotating components is the timing gears for the camshaft and
possibly a gear train for auxiliary pumps, as illustrated in Fig. 14. Condition of the gear
teeth can be measured from the backlash which should not exceed specified limits.
Figure 14
Timing Gears
(Courtesy of Waukesha Engine)
Cooling System
In the cooling system, major maintenance involves the water pump and the cooler. The
most common problem with the water pump is deterioration of the seals. When the seals
deteriorate, the pump is overhauled and the seals are replaced. Leaks are detected
through a weep hole.
The cooler requires cleaning and flushing on a regular basis, but the cooler may have to
be replaced if there is long term corrosion.
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Lubrication System
Major maintenance of the lubrication system is related to the oil pumps and the oil
cooler. Once seals begin to leak or pump pressure is not adequate, the oil pump should
be replaced and sent out for repair.
If increases in lube oil temperature cannot be traced to a malfunctioning water pump, an
incorrect thermostat setting, or increased engine load, the cooler must be inspected
internally for deposits, especially on the coolant side of the cooler.
Intake and Exhaust System
Due to the vibration from operation, the intake and exhaust ducting develop cracks and
fasteners may become loose. Corrosion occurs especially in the exhaust system because
combustion produces water, and fuel contaminants may produce harmful acids.
The integrity of the intake ducting is very important, particularly downstream of the
filters, so that unfiltered air is not drawn into the intake. If exhaust gas leaks into a room,
it poses a safety hazard. Because high exhaust back pressure is detrimental to engine
operation, it must be monitored. The muffler corrodes over time and causes increased
sound emissions. Inspect the external and internal intake ducting and measure the
exhaust back pressure on a yearly basis.
Fuel and Ignition System
Most of the maintenance on the fuel and ignition systems consists of routine adjustments
and minor replacements such as spark plugs. There are other parts that may require
replacement or refurbishment.
On lean burn engines, admission valves that admit fuel directly into the cylinder ( Fig.
15) are critical and must be cleaned on a regular basis, usually every 4 000 hours of
operation. On the ignition system, the wiring and the coils may need replacement based
on its condition during visual inspection. The magneto drive disc is typically replaced
every 4000 running hours.
Figure 15
Fuel Admission Valve
(Courtesy of Waukesha Engine)
Many engines, especially lean burn engines, are tuned using an oxygen analyser (Fig.
16). Most oxygen analysers are designed around the fuel cell principle. The oxygen in
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the exhaust is combined with hydrogen to produce water and conductivity which is
measured. Since ambient air contains 21% oxygen, the range is usually 0 - 25% and the
sensor is easy to calibrate. Normal exhaust emission levels should be about 10%
oxygen. The flow rate should be minimal or the readings are affected. The analyser has a
flow sampling system that protects it against:
• Water which is present in all exhaust
• Over-pressuring on turbocharged engines
• Temperatures which are too hot or too cold
Figure 16
Exhaust Gas Oxygen Analyser Schematic
(Courtesy of Waukesha Engine)
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Turbocharger System
The compressor and the turbine determine the efficiency of the turbocharger. If the inlet
air is not clean, the compressor side may become fouled and the boost pressure will be
reduced. The high temperature of the exhaust gases and fuel contaminants such as
sulphur cause deterioration on the turbine side and a lack of boost pressure. The other
area of wear is the bearings, which is verified by measuring the clearance in the axial
and radial directions (Fig. 17). If the limits are exceeded, the turbocharger should be
removed and sent in to a shop for repair.
Figure 17
Turbocharger Bearing Checks
(Courtesy of Waukesha Engine)
The wastegate assembly that bypasses exhaust not required by the turbocharger may
also have to be checked and calibrated, as illustrated in Fig. 18.
Figure 18
Turbocharger Wastegate Calibration
(Courtesy of Waukesha Engine)
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Starting System
Another component likely to require major maintenance is the starter. Its effectiveness is
determined by its ability to crank the engine to the required speed. Once this becomes a
problem, the starter should be removed, inspected, and overhauled. The quality of the
start gas may also affect the starter if wellhead gas is used.
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Objective 5
Explain the troubleshooting of combustion and engine
problems.
INTRODUCTION
Good troubleshooting methods minimize the effects of problems with equipment
availability and reliability. In addition to sound knowledge of internal combustion
engines and their effective operation, it is necessary to take the correct approach to
problems.
A potential problem may become evident through human observation, routine
monitoring and logging, inadequate performance (dependent on the type of load), or a
control system alarm or shutdown. The stages in troubleshooting may consist of some or
all of these steps:
1. Detection of a problem.
2. Preliminary investigation using available information from the control system
(e.g. alarm indication), log sheets, performance readings, and troubleshooting
guides.
3. Attempts to rectify the problem.
4. Consultation with maintenance experts.
5. Consultation with technical specialists and possibly the manufacturer.
General principles for effective troubleshooting are as follows:
• Do not jump to conclusions quickly; keep an open mind and stick to the facts
• Take time to gather relevant data and information
• Consult others who may have important information
• Try easy, low cost, and low risk fixes or solutions first
• Consult experts if the problem is difficult or beyond your expertise
• Do not stop until you are sure that the problem has been resolved
• Document the problem and steps taken to resolve it on a work order or other
standard form
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ENGINE TROUBLESHOOTING
Troubleshooting information is often presented in a standard chart provided by most
manufacturers. Table 5 is an example of a standard troubleshooting chart.
There are three aspects to internal combustion engine troubleshooting. The symptom
describes what an operator might notice or detect during the operation of the engine.
The probable cause lists the likely reasons for the symptom. The remedy makes
recommendations on how the problem may be resolved.
Table 5
Example Troubleshooting Chart
(Courtesy of Waukesha Engine)
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Chapter Questions
1. a) Explain what inspections are carried out before starting an internal combustion
engine.
b) Explain the steps that occur during starting the engine.
2. Describe the two types of shutdowns and the differences between them.
3. List three examples of routine maintenance for the lubrication system.
4. What parts of the cylinder head wear with use?
5. What causes blow-by of exhaust gases into the crankcase?
6. What three aspects of troubleshooting are described in a typical troubleshooting
chart?
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Gas Turbine Design and
Auxiliaries
Learning Outcome
When you complete this learning material, you will be able to:
Explain the design and components of a gas turbine and related auxiliaries.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Explain applications and selection criteria for the different types of gas turbine
engines.
2. Describe the principles and design of open and closed cycle gas turbine systems.
3. Describe the principles and design of combined cycle and cogeneration systems
using gas turbines.
4. Describe the principles and design of gas turbine regeneration, intercooling, and
reheating.
5. Describe the principles and design of gas turbine shaft arrangements.
6. Describe the design and components of gas turbine compressors, combustors
(combustion chambers) and turbines.
7. Describe the design and operation of gas turbine air intake and exhaust systems.
8. Describe the design and operation of a gas turbine lubricating oil system.
9. Describe the design and operation of a gas turbine fuel system.
10. Describe the design and operation of a gas turbine steam or water injection
system and a dry low NOx system.
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Objective 1
Explain applications and selection criteria for the
different types of gas turbine engines.
INTRODUCTION
Gas turbine engines are becoming a major source of power for many industrial
applications. There are a wide range of designs and configurations available to meet the
varied needs of industry. The simple cycle gas turbine provides a very efficient and
capable solution which can be further improved when combined with exhaust heat
recovery and other methods.
APPLICATIONS
Industrial gas turbines are used for a very wide range of applications, including:
• Base load power generation (ranging from small 30kW microturbines to large
(250MW – 650MW) turbines used in combined cycle power plants)
• Backup power generation and peak loading
• Natural gas compression (from the wellhead to gas transmission and distribution)
• Combined cycle applications (produce power from the prime load and from
steam recovered from the exhaust gas by means of a heat exchanger)
• Cogeneration (of power and heat for use in steam, heating, and other
applications)
• Various process plant applications (such as a mechanical drive, usually used for
compression)
• Offshore power generation and compression
• Ship propulsion
• Vehicle propulsion (particularly heavy-duty trucks)
• Fast trains
TYPES OF GAS TURBINES
There are two basic types of gas turbines used in industrial applications:
• Aero-derivative gas turbines (derived from aircraft engines)
• Heavy-duty gas turbines (designed for industrial applications)
Aero-Derivative Gas Turbines
Aero-derivative gas turbines are aircraft engines adapted for industrial use, either by:
• Adding a power turbine to drive the load
• Converting a turboprop engine which already has a power turbine
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An example of the first type, a Rolls Royce RB211-24C, is shown in Fig. 1. It was
introduced in 1974 and is still in production, although many changes have been made.
Like most aero-derivatives, the design is simple, compact, and lightweight.
Figure 1
Rolls Royce RB211 Gas Turbine (26.1 MW)
(Courtesy of Tom Van Hardeveld)
In general, aero-derivative gas turbines are:
• Suitable for locations such as offshore platforms, ships, trains, and vehicles
where high power to weight ratio is critical
• Easily maintained and can be removed and replaced quite quickly which
maximizes on-line time and availability
• Fast startup and loading capability, which is critical for backup power generation
and certain process applications
• Less durable than heavy-duty industrial type gas turbines and, under the same
conditions, will usually have a shorter life span
• High efficiency and power output
• Able to use a variety of gaseous and liquid fuels and can be designed to operate
on mixed fuels if required
Heavy Duty Gas Turbines
Heavy duty gas turbines have many of the same basic design features as steam turbines,
compressors and axial and radial air and gas compressors. Since the overall equipment
size and weight is not as much of an issue with industrial type gas turbines, the layout is
more flexible and they will be designed using heavier and more rugged materials than
aero-derivatives. An example of an industrial type gas turbine is the General Electric
6FA (107 MW) shown in Fig. 2.
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Figure 2
GE Frame 6FA Heavy-Duty Gas Turbine
(Courtesy of GE Power Systems)
Heavy-duty or industrial type gas turbines have the following general characteristics:
• Physically larger, more rugged and heavier than aero-derivatives
• More durable than aero-derivatives which allows long intervals between
overhauls and gives a longer life cycle with increased on-line time
• Very efficient with quick start-up and loading capabilities
• Able to use a wide variety of gas and liquid fuels
• Design and layout of compressor, combustors, turbine and load is more flexible
than aero-derivatives
• Potential for inter-cooling, regeneration, reheat and other custom options that
increase cycle efficiency and allow for combined cycle and cogeneration
operation
However, heavy-duty designs do vary, and some, such as those manufactured by Solar
Turbines (4.57MW), are a hybrid of aero-derivative and heavy-duty gas turbines, as
shown in Fig. 3.
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Figure 3
Solar Centaur 50 Gas Turbine
(Courtesy of Solar Turbines)
SELECTION
The successful application of any engine depends on satisfying requirements related to
desired performance, cost-effective operation, and expected engine life. This requires a
thorough understanding of the designs available and engine rating systems, as well as
knowledge of tradeoffs that might need to be made. A trade off may be, for example, a
more robust turbine (higher cost) but with a longer engine life.
The selection of a gas turbine engine for a specific application depends on factors such
as:
• Performance ratings
• Weight and size restrictions
• Type of fuel available
• Maintenance support resources
• Life cycle costs
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Performance Ratings
The performance rating and required range of power output are important factors to
consider when choosing a specific gas turbine. Gas turbines operate most efficiently
when running full loaded. Although they can operate down to 50% of full load rating,
the lower operating ranges will cause the turbine output efficiency to drop substantially,
down into the 30% to 40% range.
This makes it important to choose a gas turbine that operates at, or near, its maximum
power capabilities. Smaller gas turbines are less efficient, although waste heat recovery
or combined cycle applications can be very efficient. For short-term peak power
applications, a gas turbine can sometimes be run at higher than rated power output, but
this practice will reduce the life cycle of the turbine and cause an increase in
maintenance and repair costs.
Weight and Size Restrictions
Weight and size restrictions usually favour gas turbines over other types of engines,
such as reciprocating internal combustion engines, especially for higher power
applications. Aero-derivative engines normally provide the lowest-weight solution.
Type of Fuel Available
The type of fuel available needs to be considered. The cleanest and most accessible fuel
should be used. Pipeline quality natural gas is desirable because it delivers the most
efficient, cost-effective, and environmentally acceptable solution. Lower quality gaseous
fuels such as landfill or sewage gas require special handling and delivery systems and,
due to their lower kJ values, will result in lower power output and turbine efficiencies.
Liquid fuel, such as kerosene, provides reliable operation but may be unsuitable where
emissions are an issue, or where fuel sources are not easily accessible. Lower grade
liquid fuels may be cost-effective, but require fuel treatment and could result in higher
maintenance costs.
Maintenance Support Resources
Maintenance has to be taken into consideration before a final selection is made. This
includes the availability of skilled personnel, spare parts, and other support
requirements.
Life Cycle Costs
Life cycle costs include not only the initial capital investment, but also fuel, operating,
and maintenance costs. Simple cycle gas turbines are now efficient enough to compete
with other types of engines on a cost basis. The use of gas turbines in combined cycle
applications provides an efficient solution over the life cycle of the engine.
When selecting a gas turbine engine, it is important to consult with manufacturers on
recommendations for proper application, engine rating, and equipment configuration.
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Objective 2
Describe the principle and design of open and closed
cycle gas turbine systems.
THE GAS TURBINE CYCLE
A knowledge of thermodynamic principles helps to understand the operation of gas
turbines. Gas turbines can use one of two basic cycles — the open cycle or the closed
cycle. This objective presents the simple versions of the open and closed cycle. A
detailed description of the simple gas turbine cycle will be given here to allow the reader
to grasp the key concepts and operating principles involved. Combined and cogeneration
cycles will be covered further in the module.
The gas turbine thermodynamic cycle, called the Brayton cycle, is shown in Fig. 4. It
consists of four steps:
1. The air is compressed, which increases the pressure and temperature and
decreases the volume (from stage 1 to stage 2).
2. Heat is added, which results in a major increase in temperature and a small
increase in volume, but almost no change in pressure (from stage 2 to stage 3).
3. Then, the air is expanded through the turbine and produces mechanical work.
Pressure decreases to near atmospheric level. The temperature also decreases,
although the air is still quite hot when it exits (from stage 3 to stage 4).
4. The air is cooled to ambient conditions and returns to its original volume and
density (from stage 4 to stage 1).
Note: a significant part of the work of the turbine (W33΄) is used to run the compressor.
The remaining energy extracted (W3΄4) is available to drive the load.
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Figure 4
The Brayton Cycle
Open Cycle
Gas turbines almost always use the open cycle. Air is drawn from the atmosphere into
the turbine, and then exhausted back to the atmosphere at the end of the cycle. Fuel is
added to the air in the combustor section and combustion occurs inside the gas turbine.
An open cycle model of the Brayton cycle is shown in Fig. 5 and consists of four steps:
1. The air is compressed in a compressor (stage 1 to stage 2)
2. Fuel is added and combusted in a combustor (from stage 2 to stage 3).
3. The air expands, first through a turbine that runs the compressor, and then
through a separate turbine that drives the load (from stage 3 to stage 4).
4. The air is exhausted to the atmosphere where it cools to ambient conditions and
returns to its original volume and density (stage 4).
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Figure 5
The Open Cycle Gas Turbine
Closed Cycle
The closed cycle is similar to the open cycle except that the working fluid (air) remains
in the cycle instead of being exhausted to the atmosphere. This offers a number of
thermodynamic advantages but at the expense of a more complicated configuration. This
means that:
• The fluid has to be heated by a heat exchanger that will have the combustion
process separate from the cycle fluid
• The fluid needs to be cooled after expanding through the turbine
Closed cycle systems are used less often than open cycle systems. Open cycle gas
turbines are more efficient and combined cycle applications offer a better solution than
closed cycle systems.
The simple closed cycle (Fig. 6) consists of the following steps:
1. The fluid is compressed in a compressor.
2. The fluid is heated in a heat exchanger. Since it passes through tubes which are
surrounded by combustion gases, the fluid and the burning fuel do not come in
direct contact with each other.
3. The fluid expands, first through a turbine that runs the compressor, and then
through a separate turbine that drives the load.
4. The fluid is cooled in a heat exchanger before being compressed again.
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Figure 6
The Closed Cycle Gas Turbine
Advantages of the closed cycle are:
• The working fluid pressure can be much higher than open cycle system pressure.
Higher pressure means that the working fluid has a higher density. Therefore, a
greater mass of the fluid expands through the turbine producing more power.
• Combustion products do not mix with the working fluid. Thus, there is no
fouling of turbine blades or heat exchanger surfaces, and therefore a wider
variety of fuels can be used.
• A working fluid with a greater heat transfer coefficient than air can be used, such
as helium which has approximately twice the heat transfer coefficient of air. This
reduces the amount of heating surface required in the heat exchangers.
Disadvantages of the closed cycle are:
• The initial cost is higher than that of an open cycle system because of the heat
exchangers (air cooler and air heater).
• More space is required because the unit is larger due to the extra components.
• A steady supply of cooling water is required.
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Objective 3
Describe the principles and design of combined cycle
and cogeneration systems using gas turbines.
INTRODUCTION
The exhaust gases from gas turbines contain a large amount of heat energy that is
available for use to generate steam or to heat process fluids throughout the facility.
Utilizing this waste energy can greatly increase the overall efficiency of the system and
make the selection of a gas turbine much more advantageous to the engineer.
Exhaust temperatures can range from 400°C to 600°C. This heat can be partially
recovered by a waste heat recovery system. Thermal efficiency can be increased from a
simple cycle efficiency of 30%-40% to a total plant efficiency of 60%-70%. To avoid
corrosion, the final temperature should not be reduced below the dew point.
A combined cycle uses the waste heat energy in the exhaust gases to provide additional
steam generating capability for the facility. The combined cycle approach is ideal for
use in large base load power generation applications that can exceed 1000 MW of total
power. If the waste heat produces steam or hot water that is used for heating, cooling, or
general steam applications, it is called a cogeneration or combined heat and power
(CHP) system.
Combined Cycle Design
In a combined cycle design, the exhaust gases are routed to a Heat Recovery Steam
Generator (HRSG) that supplies steam to a steam turbine. The steam turbine can be used
to drive a separate generator (Fig. 7) or, in some cases, it can be attached directly to the
same generator as the gas turbine (Fig. 8).
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Figure 7
Separate Generators with Common Steam Turbine
Figure 8
Single Generator with Steam Turbine on Common Shaft
The HRSG may be unfired (no extra heat is added), or it may be fired. In the fired type,
an additional burner, or multiples of burners, will be installed in the ducting just
upstream of the HRSG to increase the temperature of the exhaust gases.
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The advantages of the fired system are that it:
• Compensates for changes in gas turbine output to give constant steam production
• Can be used when the turbine is at low loads or not on at all to generate steam
for the facility
Early combined cycle installations used a single-pressure HRSG. Now HRSGs often use
a double-pressure or triple-pressure configuration, such as the one shown in Fig. 9. This
extracts the greatest amount of heat and results in a more efficient operation. The choice
of HRSG depends on the temperature of the exhaust. A triple-pressure HRSG is the best
option for gas turbines with a high firing temperature (above 550°C).
Figure 9
Triple-pressure HRSG
(Courtesy of GE Power Systems)
Cogeneration Design
Cogeneration designs are used in distributed power applications. An example is shown
in Fig. 10. The two gas turbines (GT) each produce 1 550kW of electrical power. Their
exhaust is fed to a common HRSG, which has supplementary firing, so that the amount
of steam can be varied. Each engine has a diverter valve in case steam is not required.
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Figure 10
Cogeneration Exhaust and Steam System
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Objective 4
Describe the principles and design of gas turbine
regeneration, intercooling, and reheating.
CYCLE IMPROVEMENTS
Three approaches — regeneration, intercooling, reheat — can be used to improve the
efficiency of the basic gas turbine cycle. For various compatibility reasons, these are
normally used independently and, at the moment, no gas turbine exists that uses all three
methods. Aero-derivative engines are designed to be as light as possible to allow them
to function efficiently as airplane engines. Therefore, they will not have the extra
equipment included with them to allow for cycle improvements like industrial type
turbines do. As simple cycle gas turbines are becoming more efficient, these cycle
improvements are becoming less necessary. Furthermore, combined cycle designs,
which use waste heat for other purposes, are becoming more prevalent.
Regeneration
The most common cycle improvement was the regenerative cycle, or regeneration. A
heat exchanger installed in the exhaust preheats the air between the compressor and the
combustors, as shown in Fig. 11. Thus, exhaust heat is used to increase the temperature
of the compressed air prior to combustion. This approach was quite common since it
improved the efficiency of the gas turbine by 15% to 20%.
Figure 11
Regeneration
Disadvantages of regeneration include increased capital costs and pressure losses due to
the high pressure ratio compressors. Instead of regeneration, many installations use the
exhaust heat for combined cycle or cogeneration applications.
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Intercooling
In some gas turbines, inlet air is compressed in two stages using a dual shaft
arrangement. The air is cooled between the stages in a heat exchanger, or intercooler
(Fig. 12). Since isothermal compression (compression without an increase in air
temperature) takes less work than adiabatic compression (compression without
removing heat which increases the air temperature), more turbine power is available for
the output load. Another advantage of intercooling is that the total mass of air that needs
to be circulated through the cycle per kW of energy produced is reduced.
Figure 12
Intercooling
However, the beneficial effects of intercooling decrease as the pressure ratio increases.
A high pressure ratio means that losses through the intercooler become significant.
Using an intercooler makes more sense when combined with regeneration because more
exhaust heat can be recovered. This improves the overall cycle efficiency.
Intercoolers are shell and tube heat exchangers similar in construction to regenerators.
Cooling water passes through the tubes while air passes on the shell side. In some cases,
air passes through tubes surrounded by water. The General Electric LM6000 has an
innovative intercooling option, shown in Fig. 13, which introduces an atomized water
spray between the low pressure and high pressure compressors. This provides a 9%
power boost at 15˚C and 20% at 32˚C, without requiring a separate heat exchanger. A
second water spray is injected into the air intake to reduce the temperature, and thus
increase the power output.
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Figure 13
Intercooling Using Water Spray
(Courtesy of GE Power Systems)
Reheat
Reheat cycles are fairly rare, but some gas turbines still use them. The hot gas is
expanded in two stages and reheated between stages. After leaving the first set of
combustion chambers, the gas is expanded through a high pressure turbine. Then, it
passes through a second set of combustion chambers before entering a low pressure
turbine where it is expanded a second time (see Fig. 14). The second set of combustion
chambers uses the excess oxygen content of the gas exiting the high pressure turbine for
combustion.
Reheating increases the energy content of the gas and improves the thermal efficiency of
the cycle. As a result, less air has to be compressed in order to do the same amount of
work.
Figure 14
Reheat
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Objective 5
Describe the principles and design of gas turbine shaft
arrangements.
SHAFT ARRANGEMENTS
Gas turbines are designed with a number of different shaft arrangements including:
• Single shaft
• Dual shaft
• Multi-shaft arrangements
Single Shaft
In the single shaft arrangement, the compressor, turbine, and load are connected and
rotate at the same speed (see Fig. 15). This arrangement is used for power generation
where a constant speed is required, but is rarely used for other applications because the
power output is not flexible. Mechanically, it is simpler than a two-shaft arrangement,
but requires a larger starting motor because it must also rotate the generator (load) up to
ignition speed. The hot end drive arrangement, Fig. 15(a), is more common than the cold
end drive that is shown in Fig. 15(b).
(a) Hot End Drive
(b) Cold End Drive
Figure 15
Shaft Layouts – Single Shaft
The General Electric 6001, shown in Fig. 16, is an example of a hot end drive (the load
is connected to the turbine).
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Figure 16
General Electric 6001 –Single Shaft Gas Turbine with Hot End Drive
(Courtesy of GE Power Systems)
The Alstom Typhoon, shown in Fig. 17, is an example of a cold end drive arrangement.
Figure 17
Alstom Typhoon – Single Shaft Gas Turbine with Cold End Drive
(Courtesy of Alstom)
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Dual Shaft
The dual shaft (twin-shaft) arrangement, shown in Fig. 18, is the most common design.
The compressor and turbine are connected by a shaft, but the power turbine (also called
the free turbine) is coupled on a second shaft with the load. This layout provides more
operational flexibility with respect to speed and load, especially for compressors.
Many gas turbines use dual shaft designs with the load coupled to the gas turbine (hot
end) such those shown in Fig. 18 (a) and Fig. 19.
A cold end drive (the load is coupled to the compressor) positions the power turbine and
load shaft inside the compressor turbine shaft as shown in Fig. 18 (b). This arrangement
is much less common, although it does exist.
(a) Hot End Drive
(b) Cold End Drive
Figure 18
Shaft Layouts – Dual Shaft
Figure 19
General Electric LM2500 – Dual Shaft Gas Turbine with Hot End Drive
(Courtesy of GE Power Systems)
Multi-Shaft
Fig. 20 (a) shows a fairly common aero-derivative design that uses a two-shaft
arrangement for the engine, and a third shaft for the power turbine. The low-pressure
compressor and turbine are connected by a shaft fitted inside the hollow shaft
connecting the high-pressure compressor and turbine. Mechanically, this design is more
complicated (especially for the bearings), but offers greater efficiency and operational
flexibility.
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An even more complicated layout positions the load at the cold end, which requires
three shafts on the same centerline, as shown in Fig. 20 (b).
(a) Hot End Drive
(b) Cold End Drive
Figure 20
Shaft Layouts – Triple Shaft
An example of this design, the Rolls Royce RB211 shown in Fig. 21; is widely used for
both power generation and mechanical drive applications, such as compressors.
Figure 21
Rolls Royce RB211 – Triple Shaft Gas Turbine with Hot End Drive
(Courtesy of Rolls Royce)
The General Electric LM6000, shown in Fig. 22, uses a unique design. It is similar to
the triple shaft arrangement shown above, but the load is directly connected to either the
low-pressure compressor, or the low-pressure turbine.
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Figure 22
Shaft Layouts – Direct Dual Shaft
This engine, with optional cold end or hot end drive, is used exclusively for power
generation and is shown in Fig. 23.
Figure 23
General Electric LM6000 –Dual Shaft Gas Turbine
(Courtesy of GE Power Systems)
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Objective 6
Describe the design and components of gas turbine
compressors, combustors (combustion chambers) and
turbines.
COMPRESSOR DESIGN
Highly efficient and effective compressors are essential for efficient gas turbine
operation. Two types of compressors are used: axial and centrifugal (or radial). Small
gas turbines often use centrifugal compressors, sometimes in combination with several
axial stages. Large gas turbines almost always use multi-stage axial compressors.
To increase compressor efficiency, especially at lower speeds, multi-shaft arrangements
may be used so that the initial stages can operate at lower speeds than the later stages.
Compressor designs often use a combination of inlet guide vanes (IGV’s), variable
stator vanes (VSV’s), and bleed valves to counteract the effects of surge, which happens
at lower speeds. This is described later in this module.
Axial Compressors
Axial compressors are similar to propellers; the air moves parallel to the axis of rotation.
Since the mass flow through the compressor is constant, the area must decrease from the
inlet to the outlet of the compressor. This means that the blades are largest in the first
stage, and then get progressively smaller.
An axial compressor has multiple stages. An initial row of stationary blades, called the
inlet guide vanes, is used to direct the air (at the correct angle) into the first stage of
rotor blades. In each stage, a row of moving blades (rotors) is followed by a row of
stationary blades (stators). Each stage has a small compression ratio, usually between
1.1:1 and 1.4:1. A compression ratio of between 10:1 and 40:1 can be achieved by all
stages in combination.
Due to the diverging shape of the rotating and stationary blades in an axial compressor,
the pressure of the fluid is increased across both sections of blades. Each row of rotor
blades increases the velocity and the pressure of the air. The subsequent row of stator
blades act as a diffuser which further increases pressure and decreases velocity.
The axial compressor rotor blade, shown in Fig. 24, shows the slender shape compressor
blades need to maximize efficiency. Notice the twist in the blade which produces the
optimum aerodynamic angle when the air enters into each compressor stage. The angle
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increases with the radius because velocity is higher at the tip of the blade than at the
root.
Figure 24
Rolls Royce RB211 Gas Turbine
(Courtesy of Tom Van Hardeveld)
A cross-section of the axial compressor from a General Electric LM2500 is shown in
Fig. 25. Note that the cooling flow from the 9th stage of the compressor is fed back
through the intake strut to cool and pressurize the inside of the shaft, and the front,
centre, and rear bearings. A bleed valve, coming off the 13th stage, cools the high
pressure turbine nozzles.
Figure 25
General Electric LM2500 Gas Turbine
(Courtesy of GE Power Systems)
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Centrifugal Compressors
Centrifugal compressors were initially widely used in gas turbines because they were
more efficient and rugged than axial compressors. They are similar in basic design to the
centrifugal compressors used throughout the various processes to compress fluids like
air and natural gas vapours. Centrifugal compressors can achieve a higher per stage
compression ratio, up to 9:1, than axial compressors.
A centrifugal compressor uses an impeller to accelerate the air and partially increase the
pressure. A diffuser, which follows the impeller, further increases the pressure. Multiple
impellers may be used (sometimes designed back-to-back), or they may be combined
with several axial stages.
The Kawasaki M1A-13A gas turbine, shown in Fig. 26, has two centrifugal compressors
mounted on a single shaft with the turbine and a gearbox connected to a generator.
Figure 26
Kawasaki M1A-13A Gas Turbine
Compressor Surge
At lower speeds, since the blades are not at the optimum angle, air flow separation can
occur. This is similar to an aircraft wing stalling or losing lift. When starting a gas
turbine, the pressure rise is very low, and the compressor is trying to push the air into a
much smaller area, designed for a larger compression ratio, at the back of the
compressor. This can cause the air to choke. The result is called surge or rotating stall. It
is a very complicated aerodynamic phenomenon that is not fully understood.
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However, the methods required to counteract it are well developed. Two basic options
used for countering surge are bleed valves and variable compressor geometry, but
surge can still occur if the blades become dirty or fouled.
Bleed Valves
A bleed valve reduces the likelihood of surge by dumping air to increase air flow
through the compressor during startup. When the blades reach a predetermined speed,
the valve closes. The Rolls Royce RB211 Gas Turbine, shown in Fig. 1, has one bleed
valve at the exit of the first compressor rotor, and one at exit of the second compressor
rotor, which activate at different speeds.
The Solar Centaur 50 Gas Turbine, shown in Fig.3, has one bleed valve at the end of the
compressor which feeds into the exhaust. Sometimes, multiple bleed valves are used.
Variable Compressor Geometry
Variable compressor geometry is used on many gas turbines to improve efficiency at
part load and reduce the likelihood of surge during startup. One or more stages of stator
vanes, either inlet guide vanes (IGVs) or variable stator vanes (VSVs), are rotated to
optimize the airflow through the compressor according to the operating conditions —
speed and temperature.
Most gas turbines have variable IGVs, such as the ones shown in Fig. 27. They are held
in place by a ring around the outside of the compressor stage and actuated by hydraulics
(see Fig. 28). During startup, the blades rotate to a closed position and restrict the flow
of air. At a specified speed, they begin to open until they reach a predetermined angle.
Figure 27
Rolls Royce RB211 Gas Turbine Inlet Guide Vanes
(Courtesy of Tom Van Hardeveld)
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Figure 28
Rolls Royce RB211 Gas Turbine Inlet Guide Vane Linkage
(Courtesy of Tom Van Hardeveld)
Some engines use multiple stages of VSVs downstream of the IGV. The Solar Centaur
50 Gas Turbine, in Fig. 3, has three additional VSVs in addition to the IGV. They
actuate from closed to the open position between 80% and 92.5% speed.
The General Electric LM2500, shown in Fig. 29, uses an IGV plus a very extensive set
of VSVs on seven stages. Hence, it does not require bleed valves.
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Figure 29
General Electric LM2500 Gas Turbine IGV/VSV Linkage
(Courtesy of Tom Van Hardeveld)
Compressor Blade Materials
Compressor blades operate at low or moderately high temperatures but are subject to
high rotational stresses. Stator vanes and blades are often made from stainless or high
alloy steel, or sometimes from titanium. They need to resist corrosion and erosion from
external contaminants. Coatings are applied to increase compressor efficiency and
reduce corrosion.
COMBUSTOR DESIGN
Combustors are designed to burn a wide variety of fuels — from natural gas to liquids,
or even low energy gases. Some engines can use both natural gas and liquid fuel and
switch from one to the other during operation. These systems require special fuel
nozzles and more complicated fuel gas and control systems.
The combustion section must be able to burn a variety of fuels efficiently with low
emissions, high reliability, and long life. Each fuel has an optimum set of combustion
characteristics that must be met to give complete and efficient chemical reactions
between the reactive elements in the fuel and oxygen in the air. The atmosphere in the
combustor is very aggressive with combustion temperatures ranging from 900ºC to
1850ºC. The presence of oxides of sulphur and nitrogen creates a high potential for
corrosion and erosion of the internal components. This requires the use of exotic alloys,
ceramic coatings and sleeve cooling mechanisms to handle these conditions.
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The temperature of combustion can reach 1850ºC, but the temperature limit of most
metals is closer to 1200˚C. As a result, only about 20% of the air that flows through the
combustion section is directly involved in combustion. The remaining 80%, called
secondary air, is used to cool the combustion liner and dilute the air leaving the
combustor to reduce its temperature before it reaches the turbine section.
Since combustion can only be sustained at fairly low velocities, combustion air is
diffused at the inlet of the combustion section. This also helps increase air pressure. A
vortex is maintained downstream from the fuel nozzles to provide the required velocity
for sustained combustion. Then, the two air streams (combustion and secondary air) are
mixed before leaving the combustor. This process is shown in Fig. 30. This is an
example of a straight-through combustor design commonly used on aero-derivative
engines because it minimizes the frontal area to reduce drag.
Figure 30
Air Flow in a Straight-Through Combustor
(Courtesy of Rolls Royce)
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Many heavy-duty gas turbines use a reverse flow combustor, as shown in Fig. 31, to
make the combustors more accessible. On startup, an igniter provides an electric spark
to start the combustion process. Once started, combustion is self-sustaining. If the gas
turbine has several combustors, more than one igniter may be installed. A crossfire tube,
shown in Fig. 31, is used to ignite the other combustors and distribute the pressure
evenly between combustors.
Figure 31
Air Flow through a Reverse-Flow Combustor
(Courtesy of GE Power Systems)
Types of Combustors
There are three basic combustor designs:
• Single-can (external)
• Annular
• Can-annular (turbo-annular)
Single-Can (External)
The single-can (Fig. 32) or external design combustor, often used on heavy-duty gas
turbines, is usually reverse-flow combustors. Fig. 16 and Fig. 17 show gas turbines with
external combustors.
Some gas turbines have only one, or sometimes two, main combustors (usually the
reverse-flow type) mounted vertically above the turbine. This design can be seen in
small gas turbines, such as the Kawasaki M1A-13A shown in Fig. 26.
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Figure 32
Single Can (External) Gas Turbine Combustor
Annular
The annular combustor (Fig. 33), a more modern concept, consists of a singular flame
tube in an annular shape. It is smaller in size than the can burner and does not have the
problem of combustion propagation between chambers. Combustion takes place in a
single combustion liner, with an inner and outer casing, that encircles the centerline of
the gas turbine. Fuel nozzles are evenly spaced around the ring. This is a very simple
design that minimizes the complexity of the combustion and dilution air flows.
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Figure 33
Annular Combustor
Fig. 34 shows the combustion and turbine sections of the General Electric LM2500. This
engine uses an annular combustor design. Compressor air flows around the combustor to
cool the liner and then the turbine discs downstream.
At the top is an optional design for dry low NOx emission (discussed in Objective 10).
This requires a different and larger combustor design with more fuel nozzles to reduce
emissions.
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Figure 34
General Electric LM2500 Engine
(Courtesy of GE Power Systems)
Can-Annular (Turbo-annular)
In the can-annular or turbo-annular design combustor (Fig. 35), combustion takes place
in multiple combustors (also called combustion cans) placed around the centerline of the
gas turbine. Some aero-derivative gas turbines use this straight-through combustor
design since it minimizes the front area of the turbine.
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Figure 35
Can-Annular Combustor
Combustor Liner Materials
Combustor liners are made from high-temperature nickel or cobalt-bases alloys such as
Hastelloy® X and Mastelloy® X. These will usually be coated with ceramic coatings or
tiles to improve their heat handling capacities. Some engines have combustors that are
entirely ceramic, or ceramic mixed with high-temperature alloys. Special laser drilling
techniques are used to precisely position the correct number and size of holes
throughout the liner to allow for cooling air to flow in and give film cooling to the liner.
As well, slots will be machined in the liner to allow the secondary air to enter the
primary and dilution zones at just the right positions to:
• Stabilize the flame
• Assist in complete combustion
• Cool the combustion by-products
TURBINE DESIGN
After leaving the combustor, the hot gases are sent to the turbine section. Turbines
operate at very high temperatures, high blade loading, and large rotational stresses. Like
compressors, turbines can use either an axial-flow or a radial-inflow design, although
axial-flow turbines are much more common.
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In the reaction turbine, power is extracted from the hot gases exhausting from the
combustors by experiencing an enthalpy reduction (pressure and temperature) through
both the stationary and rotating blades which increases the velocity of the rotor. This
power is first used to drive the internal compressor to make the gas turbine “self
sustaining”. The remaining energy is then used to drive process loads such as
compressors, pumps or electrical power generators. As discussed in Objective 5, the hot
gases may be passed through one or more turbine cylinders to extract all the available
power. The turbine may use a number of different shaft arrangements to drive the
various process loads.
Axial-flow Turbines
Because energy can be extracted more efficiently than it can be added, fewer stages are
needed in the turbine than in the compressor. In axial flow turbines, a stage consists of a
row of stationary blades (also called nozzle guide vanes or nozzles) followed by one or
more rows of rotating blades depending on the type and design of the turbine. Nozzles
increase the velocity of the hot gases with a partial pressure drop. Then, the moving
blades extract power with a further drop in pressure and temperature.
The turbine section of the General Electric LM2500 is shown in Fig. 34. Note that a
separate turbine drives the compressor, and a power turbine drives the generator, or
other process loads. Cooling for the 2nd stage turbine nozzles is supplied from the 13th
stage bleed valve. Cooling for the power turbine discs is supplied from the 9th stage
bleed valve.
Blade Cooling
The current trend in gas turbine technology is to increase the inlet temperature of the
gases, up to about 1370ºC. This will increase the turbine power output as well as the
turbine cycle efficiency. This increase has been achieved through advanced metallurgy
and the use of special cooling systems for the turbine blades. Many gas turbines use aircooled (or sometimes water-cooled) blades to reduce metal temperature and increase
blade life. Air is supplied from the compressor discharge, circulated through the blade,
and then extracted through holes in the leading edge, trailing edge, and surface of each
blade. The designs that are used for gas turbine cooling are:
• Film
• Transpiration
• Convection
• Impingement
• Water
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Film
Cooling air is introduced through ports at the base of the blades where it then circulates
through a series of vertical channels. The air passes out through a series of small holes
bored in the blades leading edge. Slots are provided in the trailing edge to allow the
escaping air to cool this part of the blade by convection. Film cooling is also used to
protect the liners of the combustors from hot gases.
Transpiration
This type of cooling is achieved by passing air through the porous wall of the blades. At
very high operating temperatures, this method is effective since the entire blade is
covered with coolant flow. During normal operation, some of the pores are closed by
oxidation. Consequently, this can cause uneven cooling and high thermal stresses. There
can be a higher probability of blade failure when using this design.
Convection
Coolant air makes multiple passes through a serpentine channel from the hub to the tip,
inside the turbine blade, to remove heat across the wall. This flow of air is in a radial
direction. This is the most common type of cooling used in gas turbines.
Impingement
Jets of high velocity cooling air are blasted on the inner surface of the airfoil of the
turbine blades. Heat transfer from the blade metal surface to the cooling air is increased.
Since the leading edge of the blade requires more cooling than the midchord or trailing
edge, the flow of cooling air is impinged at the leading edge.
Water
Preheated cooling water flows through a series of tubes that are embedded in the blade.
The water absorbs heat and lowers the blade temperature below 540ºC. It then
discharges from the blade tip as steam into the gas stream.
An example of blade cooling is shown in Fig. 36. Air from the compressor section flows
through the inside of the shaft into the nozzles and 1st stage rotor blades, which are
hollow, and then escapes through the many cooling holes in the blades.
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Figure 36
Rolls Royce Avon Turbine Nozzle and Blade Cooling
(Courtesy of Rolls Royce)
Turbine Materials
One of the greatest challenges in gas turbine construction is selecting the materials to
use in the turbine nozzles and blades, particularly for the first stage. Conventional
nozzles and blades are cast from special nickel-based super alloys such as INCONEL®,
UDIMET®, WASPALLOY™, and HASTELLOY® X. Special casting techniques are
used to manufacture blades with superior strength and temperature resistance. Ceramic
components will allow a significant increase in firing temperatures.
At very high temperatures and stresses, materials suffer from a phenomenon called
creep. The material stretches over time which causes voids to open up. This can
ultimately lead to catastrophic rupture and failure of the turbine blades.
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Turbine blade life depends on the following items:
• Type of fuel burned
• Blade materials
• Operating conditions (number of stops and starts, loading percentages and
temperature control)
• Ambient and environmental conditions
The first stage blade materials are the most important as they will experience the highest
temperatures and the most corrosive conditions. These blades will last from 20 000
hours when burning residual oils to 100 000 hours when burning natural gas. Metallurgy
used for the first stage blading is usually INCONEL (IN) 738 and their expected “life
cycle” can be extended by coating the bladed with composite plasma or RT22. The
second stage blades are made from precipitation-hardened nickel based alloys like U500
or nimonic. Nimonic is a nickel-chromium-cobalt alloy being precipitation hardenable,
having high stress-rupture strength and creep resistance at high temperatures (up to
about 950°C). It is a widely used and well proven alloy in high temperature conditions.
The turbine wheels are made from Cr-Mo-V, 12 Cr alloys or M152.
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Objective 7
Describe the design and operation of gas turbine air
intake and exhaust systems.
AIR INTAKE SYSTEMS
The air intake system provides clean air to the gas turbine. To achieve this, air filters are
installed in the intake. The type of air intake system used depends on the environmental
conditions where the gas turbine is installed. Some environmental conditions that can
greatly impact the type of air intake filtering systems installation are:
• Off-shore platform and ocean area installations
• Desert or high dust installations
• Cold climate and arctic installations
• High rain and wind conditions
• Industrial installations where their a number of sulphur compounds and corrosive
materials in the local atmosphere
The intake system becomes more complicated if intake cooling (to increase power at
high ambient temperatures) is required, or if icing conditions may occur.
An intake system is shown in Fig. 37. Note that the air intake is positioned above the
enclosure to save space and to place the intake in a higher position where the air may be
cleaner. The intake is designed to allow the installation of intake cooling or anti-icing.
The first stage of filtration is a stainless steel screen which prevents entry of major
debris. The second stage is a series of cylindrical filters mounted inside the air intake
which remove the bulk of the debris.
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Figure 37
Air Intake System (GE LM6000)
(Courtesy of GE Power Systems)
Some filter systems use inertial filtering which consists of a series of vanes that deflect
the air and separate the contaminants using centrifugal force. A more effective approach
is to use many small cylindrical filters, such as the ones shown in Fig. 38. Compressed
air is used to backflow individual filters and to dislodge dust that has been collected and
deposited into a hopper or other type of removal system.
These pulse cleaning systems are commonly called huff and puff and operate
automatically based on pressure differential. They work well in both dusty and cold
weather conditions.
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Figure 38
Pulse Cleaning Filter
(Courtesy of Donaldson)
Inlet Cooling
Inlet cooling systems decrease intake air temperature, and thereby increase power
output, as shown in Fig. 39. A 0.5% decrease in power can result from a 1ºC
temperature increase. In hot climates, this variation in power output can be significant
and costly. They are based on the principle of evaporative cooling. When moisture
evaporates, it requires a large amount of heat to overcome the latent heat of
vaporization. The result is a drop in air temperature.
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Figure 39
Typical Gas Turbine Performance
Various inlet cooling methods are used:
• Evaporative cooling
• Fog cooling
• Chillers
Evaporative Cooling
This system (Fig. 40) consists of a wetted media which is located downstream of the
inlet air filter. This arrangement protects the wetted media from any airborne particles in
the ambient air. Evaporative cooling enhances engine efficiency by increasing the
density of the air. Increased air density raises the specific mass flow through the engine
which improves the fuel efficiency and power output. This system operates as an air
washer, thereby cleaning the air. Another advantage to this system is a reduction in the
emissions of oxides of nitrogen.
Figure 40
Evaporative Cooling
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Fog Cooling
Atomized demineralized water under high pressure (7 000 to 20 000 kPa), is sprayed
into an air steam (Fig. 41). Small fog droplets of approximately 10 microns (µm)
diameter are desired as they have a faster evaporation rate. Fogging systems offer a very
small pressure drop to the flow of inlet air to the gas turbine.
Figure 41
Fog Inlet Air Cooling System
Chillers
Inlet air to the gas turbine is cooled by passing it through a finned coil of tubes (Fig. 42)
which uses either NH3 (Ammonia) or HFC-134a refrigerant as the cooling medium. The
air temperature must not be less than 5ºC to prevent the formation of ice on the coils.
Refrigeration will always provide the design inlet temperature regardless of the ambient
conditions, unlike the evaporative systems which lose effectiveness in high humidity
conditions.
Figure 42
Refrigeration Air Cooling System
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Anti-Icing Systems
Ice can form in the air intake, or on the first few stages of the compressor, when low
temperatures combine with humidity. If chunks of ice are drawn into the compressor,
they can cause major damage, such as catastrophic destruction of the compressor section
blading.
Various anti-icing systems are used:
• Air is bled from the hot end of the compressor and injected into the front of the
compressor through the nose cone and the first few stator vanes (see Fig. 43)
• Heating coils are installed in the air intake
• Heated air is fed from the exhaust (or another source) into the air intake
These systems are activated only when icing conditions are present because they reduce
the efficiency and power output of the gas turbine.
Figure 43
Rolls Royce Avon Anti-Icing System
(Courtesy of Rolls Royce)
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EXHAUST SYSTEMS
The exhaust system directs the hot turbine exhaust, with as low a pressure loss as
possible, to a location that is safe for employees and equipment. It has to be structurally
sound and designed for high exhaust temperatures. Care should be taken to ensure that
exhaust air does not re-circulate into the air intake since this will result in a loss of
maximum power, unless this is part of an anti-icing system.
Noise attenuators and silencers are often added to the exhaust in accordance with local
requirements.
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Page 352
Objective 8
Describe the design and operation of a gas turbine
lubricating oil system.
INTRODUCTION
Most gas turbines have lube oil systems that lubricate the bearings supporting the rotor
or rotors. Aero-derivative gas turbines use antifriction bearings which require small lube
oil systems. Heavy-duty gas turbines use journal bearings which require larger lube oil
systems. Microturbines are the exception; because of their small size, they are able to
operate with air cooled bearings that do not require a lube oil system.
All lube oil systems perform the following basic functions:
• Lubricate and/or separate the rotating surfaces from the stationary surfaces
• Cool the bearings and other critical components
• Assist in controlling radial and axial thrust
All lube oil systems include these basic components:
• An oil reservoir to ensure an adequate supply of oil
• Oil heaters in the reservoirs to maintain a certain start-up temperature and reduce
the potential for moisture to collect to collect in and contaminate the oil
• Filters to ensure the oil is clean
• Pumps to provide pressure
• Coolers to ensure oil temperatures are kept within operating limits
• Start-up permissives for oil pressure, oil temperature and oil flow rates
• Protective, monitoring, and control devices (e.g. gauges and safety valves)
Gas turbine installations may have one or more lube oil system. These are the major
configurations:
• One integrated lube oil system that serves the gas turbine, power turbine,
gearbox and driven equipment (compressor or generator), incorporated in heavyduty gas turbines such as those manufactured by Solar Turbines.
• Two lube oil systems: one for the gas turbine and power turbine, one for the load
device. This design is also used in heavy-duty gas turbines.
• Three separate lube oil systems: one for the engine, one for the power turbine,
and one for the load. Used in some aero-derivative gas turbines.
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Bearings
Gas turbines use two different types of bearings:
• Antifriction (roller and/or ball) bearings - common in aero-derivative gas
turbines that have lighter rotors
• Radial (journal or tilt-pad) bearings - common in heavy-duty gas turbines that
have heavier rotors
Fig. 44 shows an antifriction (roller) bearing for a Rolls Royce RB211. It features a
separate oil squeeze film to dampen the bearing and increase its life. This engine also
uses ball bearings (not shown) to counter and control thrust.
Figure 44
Rolls Royce RB211 Antifriction Bearing
(Courtesy of Rolls Royce)
The bearing configuration for the Rolls Royce RB211 is shown in Fig. 45. The two
rotors shown require a more complicated arrangement using five bearings: two thrust
(ball) bearings, and three roller bearings for the radial loads.
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Figure 45
Rolls Royce RB211 Bearing Configuration
(Courtesy of Rolls Royce)
Heavy-duty gas turbines require radial bearings which can take higher loads. Although
standard journal bearings are used, tilt-pad bearings are more common. Fig. 46 shows a
Solar bearing with five tilting pads on individual pivot pins.
Figure 46
Radial Tilt-Pad Bearing
(Courtesy of Solar Turbines)
Fig. 47 shows a tilt-pad thrust bearing.
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Figure 47
Tilt-Pad Thrust Bearing
(Courtesy of Solar Turbines)
On a dual-shaft heavy-duty gas turbine, thrust bearings are located on the front end of
the compressor, at the back end of the compressor, before the gas turbine, and after the
power turbine. Thrust bearings are positioned at the front end of the compressor and
next to the power turbine bearings (one for each shaft).
AERO-DERIVATIVE GAS TURBINE LUBE OIL SYSTEM
Fig. 48 shows the lube oil system for an aero-derivative gas turbine — the General
Electric LM6000 (used for power generation). It lubricates the gas turbine and power
turbine bearings. The driven equipment is handled by a separate system.
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Figure 48
General Electric LM6000 Lube Oil System
(Courtesy of GE Power Systems)
This lube oil system is divided into two sections: a supply system and a scavenge
system. To prevent corrosion, all piping, fittings, and the reservoir are Type 304
stainless steel. The lube oil used is synthetic type oil suitable for high temperatures.
The oil reservoir contains approximately 500L in a 568L tank. It is fitted with protective
devices to guard against low oil level and low oil temperature. A thermostatically
controlled heater in the lube oil tank reservoir ensures that a minimum oil temperature is
maintained to reduce the stresses on the turbine on startup and to keep moisture from
condensing in the reservoir and contaminating the oil.
An electric motor driven auxiliary lube oil pump is used to initially pressurize the
system and satisfy the permissives to allow the turbine to start.
A positive displacement pump, driven by an auxiliary gearbox on the engine, provides
the required pressure to the bearings. After it leaves the pump, the oil is filtered through
a duplex full-flow filter.
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The oil supply is protected by switches for:
• High oil temperature
• Low oil pressure
• High filter differential pressure
Then, the oil flows through the bearings and accumulates in the bearing sumps. The oil
temperature is measured at each scavenge line in case of bearing problems.
Chip detectors are often located in the sumps to detect metal particles. If a bearing
becomes damaged, metal particles break away and become entrained in the oil. Chip
detectors are basically magnets that attract metal particles and detect when they
accumulate. When the chip detector alarms, the detector will be removed and the
particles that have been captured by the detector will be analyzed. The quantity and type
of material collected will indicate:
• Where the problem is
• How severe the problem has become
Scavenge pumps (also driven by the auxiliary gearbox) provide pressure to flow the oil
from the bearing sumps through another set of filters, and then through duplex
thermostatically controlled water-cooled coolers. Then, the oil flows back into the
reservoir.
HEAVY-DUTY GAS TURBINE LUBE OIL SYSTEM
Fig. 49 shows the lube oil system for a heavy-duty gas turbine with a single integrated
oil system serving the gas turbine, gearbox, and driven equipment.
The oil reservoir is much larger than aero-derivative gas turbine lube oil reservoirs. It
normally contains mineral oil, which does not have as high a temperature range as
synthetic oil, but is more cost-effective. Oil temperatures are not as high in heavy-duty
gas turbines since the oil flow is greater. If necessary, equipment may be installed to
heat the oil supply.
During normal operation, oil pressure is supplied by a main lube oil pump which is
driven from an accessory drive mounted on the front of the compressor shaft. Prior to
startup and on shutdown, oil pressure is supplied by an AC-driven pre/post lube oil
pump. This pump runs for a period of time after shutdown to cool and lubricate the
bearings and prevent damage. In case of power loss or pre/post lube oil pump failure, a
third pump — using another source of energy, for example, a DC pump driven from
batteries — is available as backup.
The cooled oil is cleaned by duplex filters that can be replaced during operation. Duplex
filter systems consist of two filters in parallel to allow one to be serviced while the other
is on line. It is monitored by a differential pressure alarm and pressure gauge. At the
lube oil header, protection systems guard against high oil temperature and low oil
pressure.
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After leaving the bearings, the oil drains back into the oil reservoir using gravity. Oil
temperature is usually measured in the drains to monitor bearing condition.
A hydraulic pump is sometimes installed after the main lube oil pump to supply high
pressure oil to control the variable inlet and stator vanes, the fuel control valve, and
bleed valves.
Figure 49
Lube Oil System for a Solar Gas Turbine
(Courtesy of Solar Turbines)
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Page 360
Objective 9
Describe the design and operation of a gas turbine fuel
system.
NATURAL GAS FUEL
Natural gas is the best fuel for gas turbines since it:
• Promotes the most efficient combustion
• Produces the lowest environmental emissions
• Delivers the longest engine life
It has to operate within a specified range of heating values and be free of liquid
contaminants and sulphur compounds. The pressure of the turbine fuel gas system is
usually much lower than the supply pipeline operating pressure. When the pressure is
reduced across a throttling valve, the gas temperature will drop due to the natural
refrigerating effect. This will tend to allow the heavier constituents in the gas to
condense. For this reason, line heaters are usually installed just downstream of the
pressure reducing valves to increase the gas temperature above the dew point of the
heavier constituents in the gas.
If low energy fuel is used, special fuel nozzles and combustors must be installed. As
well, the fuel gas system has to be adapted to accommodate the higher flow rates
required to deliver the same fuel energy.
FUEL GAS SYSTEM
The General Electric LM6000 fuel gas system, shown in Fig.50, is representative of
most gas turbines.
A fuel gas compressor is installed in case extra compression is required to boost a low
pressure fuel source. The pressure of the fuel gas has to be higher than the pressure of
the compressed air delivered to the combustion section. A pressure regulator and relief
valve is installed to ensure that the fuel gas supply is maintained at the correct pressure.
Low and high pressure switches protect against over or under pressure conditions.
A fuel filter ensures that contaminants do not enter the fuel system. Some systems use
heat exchangers to raise the fuel gas to its optimum temperature to ensure that:
• Complete combustion occurs in the combustor
• The gas always remains above the dew point temperatures of the heaviest
constituents in the fuel gas
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A fuel gas flow meter monitors fuel consumption, but is not used for fuel control. Fuel is
metered and controlled by the fuel metering valve, one of the most important
components of the fuel gas system. It is also an essential component of the startup and
shutdown sequence. Fuel valves are normally electrically controlled with hydraulic
actuation, but electrically actuated valves are becoming more common. The fuel
metering valve ensures that the correct amount of fuel is provided according to the
operating conditions. It precisely controls the flow of fuel to ensure that maximum
turbine temperature is not exceeded. The rate at which the fuel valve is opened and
closed is limited to prevent temperature increases that might damage the turbine.
Additional shutoff valves are provided for emergency purposes.
Figure 50
General Electric LM6000 Fuel Gas System
(Courtesy of GE Power Systems)
LIQUID FUELS
Gas turbines can burn a wide range of liquid fuels including:
• Distillates, such as kerosene, which do not require fuel treatment
• Blended heavy distillates and low ash crudes which require some treatment
• Residuals and heavy ash crudes which require considerable cleaning and
treatment
Fuel quality affects gas turbine availability. As fuel quality decreases, maintenance
actions and overhauls are needed more frequently and maintenance costs increase.
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FUEL OIL SYSTEM
An example of a fuel oil system is shown in Fig. 51. The system starts with a fuel
storage tank and fuel treatment.
Treatment varies with the type of fuel and may include centrifuges, filters, de-watering,
and chemical treatment. Chemicals that are especially harmful to the turbine section are
sodium, potassium, and vanadium since they cause rapid corrosion. Gas turbines burn
mainly natural gas and light oil. Crude oil, residual, and some distillates contain
corrosive components and as such require fuel treatment equipment. In addition, ash
deposits from these fuels result in gas turbine deratings of up to 15 percent. However,
they may still be economically attractive fuels, particularly in combined-cycle plants.
Sodium and potassium are removed from residual, crude and heavy distillates by a water
washing procedure. A simpler and less expensive purification system will do the same
job for light crude and light distillates. A magnesium additive system may also be
needed to reduce the corrosive effects if vanadium is present. Fuels requiring such
treatment must have a separate fuel-treatment plant and a system of accurate fuel
monitoring to assure reliable, low-maintenance operation of gas turbines.
Then, the cleaned and treated oil is filtered and pumped to the gas turbine where it is
filtered once more. Similar to fuel gas systems, there is a main metering valve with a
primary and secondary shutoff valve. The liquid fuel must be supplied to the nozzles at a
specific pressure to ensure proper and efficient atomization and combustion. To handle
load changes the pressure controlled bypass valve directs the excess flow back to the
storage tank to maintain a set operating pressure on the system. Drains are provided on
the fuel manifolds.
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Figure 51
Liquid Fuel System (General Electric LM6000)
(Courtesy of GE Power Systems)
Protective instrumentation is installed on the fuel gas system to monitor, control, alarm
and/or completely shutdown the unit for specific conditions of pressure, temperature and
flow rates.
Dual Fuel Systems
Some gas turbines have dual fuel capability so that the operator can switch to a less
expensive fuel, or use the alternative fuel as a backup. An example of a dual fuel system
(gas and liquid), shown in Fig. 52, requires a special fuel nozzle. The control system
design is more complex to manage the two types of fuels and to accommodate the
switchover between them. Some systems can burn a mixture of gaseous and liquid fuels
simultaneously.
Page 364
Figure 52
Dual Fuel System (Rolls Royce Avon)
(Courtesy of Rolls Royce)
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Page 366
Objective 10
Describe the design and operation of a gas turbine
steam or water injection system and a dry low NOx
system.
INTRODUCTION
Gas turbines are required to produce low levels of emissions since the levels and types
of emission are legislated and enforced in many areas. These increasingly stringent
requirements have resulted in major changes to gas turbine design, particularly the
combustion section.
Gas turbine emissions are summarized in Table 1. They are divided into two groups,
major species, and minor species. Major species are measured in percent (%), while
minor species are measured in parts per million (ppm). The specific pollutants produced
depend on the operating conditions of the gas turbine, especially the combustion
characteristics, and the type of fuel used.
Table 1
Gas Turbine Emissions
(Courtesy of GE Power Systems)
The focus of emission control efforts has been sulphur dioxides (SOx) and. nitrogen
oxides (NOx). Sulphur dioxides are formed from the burning of fossil fuels.
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Nitrogen oxides are formed from the:
• Oxidation of free nitrogen already in the air by the high temperature of
combustion
• Partial combustion of fossil fuels
In general, the formation of NOx can be managed by reducing flame temperature. The
four methods of NOx control are:
• Water injection
• Dry low NOx emission combustor design
• Catalytic reduction
• Lean pre-mixed combustion
WATER INJECTION SYSTEMS
The earliest methods to reduce NOx emissions involved the injection of water or steam
into the combustor. This approach has been applied mainly to heavy-duty gas turbines
and less frequently to aero-derivative gas turbines. Water or steam injection can reduce
NOx levels to 25 ppmv (parts per million per volume) for natural gas fuels from normal
levels of 150 - 200 ppmv without emission control.
Water is also used to reduce NOx emissions from oil-fired combustion systems. It is
mixed with the oil before being sprayed into the burner. Water decreases the combustion
temperature and can reduce NOx emissions from burning light weight oils by as much as
15%. A significant added advantage in using these emulsions is that they reduce the
emission of particulate matter. When water is mixed in the oil, each oil droplet sprayed
into the firebox has several tiny water droplets inside. The heat existing in the firebox
makes these water droplets flash into steam and explode the oil droplet. Increasing the
surface area of the oil enables it to burn faster and more completely. A reduction in
particulate emissions can be achieved regardless of whether light or heavy oils are being
burned.
Emissions are reduced by introducing a heat sink to limit flame temperature. An
additional benefit is that power output is increased due to an increase in the mass flow.
Water is more effective than steam, not only because it is at a lower temperature, but
also due to the latent heat of vaporization. In fact, about 1.6 times the amount of steam is
required to produce the same effect.
The major limitation is that the quality of the water must be very high, similar to boiler
feed water, to reduce deposits and corrosion in the downstream hot gas path
components. Since a substantial amount of water is required, this method is not suitable
for many situations.
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Water is injected directly into the combustor by one of two methods:
• Water injection fuel nozzle
• Breech-load fuel nozzle
Water Injection Fuel Nozzle
Water is injected using water spray nozzles (Fig. 53) installed close to each fuel injector.
Water injection systems require a water pump and filters, flow meters, water stop, and
flow control valves, in addition to a more complicated control system. Steam injection
systems require a steam flow meter, steam control valve, steam stop valve, and steam
blowdown valves.
Figure 53
Water Injection Fuel Nozzle
(Courtesy of GE Power Systems)
Breech-Load Fuel Nozzle
Fig. 54 shows a breech-load fuel nozzle where the water is injected in one spot upstream
of the combustors to allow for premixing with the fuel before combustion.
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Figure 54
Breech-load Fuel Nozzle
(Courtesy of GE Power Systems)
DRY LOW NOX EMISSION COMBUSTOR DESIGN
Development started in the 1970’s to produce an emission control system that did not
use water or steam and could also achieve lower emission levels. This method is usually
known as either dry low NOx (DLN) or dry low emission (DLE) depending on the
manufacturer. Levels, as low as 7ppmv, are now being achieved in large industrial gas
turbines.
Dry emission systems are based on the fact that emission of NOx is drastically reduced if
the air-fuel mixture is lean or less than stoichiometric (the correct proportion of air to
fuel required to achieve total combustion). The disadvantage with lean mixtures is that
combustion becomes unstable, especially at part load.
Various designs have been developed to provide stable operation, some of which use a
series of staged fuel nozzles. An example of this design, used in heavy-duty gas
turbines, is shown in Fig. 55. It features two sets of fuel nozzles:
• Primary fuel nozzle for startup and part load operation
• Secondary nozzle for lean operation and lowest emissions at full load
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Figure 55
Dry Low NOx Combustor
(Courtesy of GE Power Systems)
The staging of these nozzles is shown in Fig. 56.
Figure 56
Fuel-Staged Dry Low NOx Operating Modes
(Courtesy of GE Power Systems)
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CATALYTIC REDUCTION
NOx emissions are removed from the burner exhaust gases through the use of a catalyst.
In one process, ammonia is added to the flue gas prior to the gas passing over a catalyst.
The catalyst enables the ammonia to react chemically with the NOx converting it to
molecular nitrogen and water. The catalyst used is a combination of titanium and
vanadium oxides. This system promotes the removal of up to 90% of nitrogen oxides
from the flue gases.
The ammonia reacts with both the nitrogen monoxide (NO) and nitrogen dioxide (NO2)
Reaction with NO:
4NO + 4NH 3 + O 2 = 4N 2 + 6H 2O
Reaction with NO2:
2NO 2 + 4NH 3 + O 2 = 3N 2 + 6H 2 O
The NO and NO2 react with the ammonia to form nitrogen and water. The nitrogen is
harmless and can be released back into the atmosphere.
In a second process, both NOx and SOx are removed. The combustion gases are passed
across a bed of copper oxide, which reacts with the sulphur oxide to form copper
sulphate. The copper sulphate acts as a catalyst for reducing NOx to ammonia.
Approximately 90% of the NOx and SOx can be removed from the flue gases through
this process.
LEAN PRE-MIXED COMBUSTION
Another method of reducing the formation of NOx is to reduce the flame temperature by
thoroughly premixing the fuel with large quantities of air prior to combustion. Referring
to Fig. 57, in a conventional gas turbine combustor, 30% of the total air flow is mixed
with the fuel supply to the burner. The remaining 70% of the required air flow is added
at later stages to the burner. This results in a burner temperature of approximately
2260ºC.
With the Solar Turbine SoLoNOx® type of burner, 60% of the total air flow is mixed
with the fuel supply to the burner. The remaining 40% is added at later stages. This
results in a burner temperature of 1590ºC. This lean-premixed combustion technology
ensures a uniform air/fuel mixture and prevention of the formation of NOx.
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Figure 57
Lean Pre-Mixed Combustion Design
(Courtesy of Solar Turbines)
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Chapter Questions
1. What factors influence the selection of the type of gas turbine engine for a specific
application?
2. With the aid of a simple sketch, describe the gas turbine thermodynamic cycle.
3. Explain the advantages of a fired HRSG system over an unfired unit
4. Explain the advantages for using intercooling to improve the efficiency of the basic
gas turbine cycle.
5. Using simple sketches, describe the hot end and cold end drives that are used in
multi-shaft arrangements for gas turbines.
6. Give a brief explanation of the following types of combustors that are used for gas
turbines:
a) Annular
b) Can-annular
7. With the aid of s simple sketch, describe how a refrigeration chiller is used to
increase the power output of a gas turbine.
8. a) Using a simple sketch, describe an aero-derivative gas turbine lube oil system.
b) Discuss the use of chip detectors to detect metal particles in the oil.
9. Explain, with the aid of a simple sketch, a type of fuel gas system for a gas turbine.
10. With the use of simple equations, describe how ammonia is used in the catalytic
reduction of NOx emissions from the exhaust gases of a gas turbine.
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Gas Turbine Operation and
Control
Learning Outcome
When you complete this learning material, you will be able to:
Describe general routine and major maintenance requirements, and detailed operating
and troubleshooting procedures for gas turbine engines.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Describe the components and operation of gas turbine supervisory and control
systems.
2. Describe the principles and design of gas turbine protection devices.
3. Describe the detailed hot and cold startup procedures for a gas turbine, including
safety precautions.
4. Describe the detailed shutdown procedure for a gas turbine, including safety
precautions.
5. Explain the routine maintenance and monitoring requirements for a gas turbine.
6. Describe the major maintenance and overhaul requirements for a gas turbine.
7. Explain the troubleshooting of gas turbine problems.
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Objective 1
Describe the components and operation of gas turbine
supervisory and control systems.
INTRODUCTION
Plant supervisory and gas turbine control systems have undergone major changes.
Advances in computerization and information technology continue to impact gas turbine
control. However, the fundamentals of gas turbine control remain fairly constant.
Control of a gas turbine exists at three levels:
• Plant
• Gas turbine
• Closed loop
PLANT LEVEL CONTROLS
The control system of a gas turbine is usually integrated with a higher-level process
control system, often referred to as the supervisory control system. This manages the
overall control of the facility itself and provides the master control setpoint (or setpoint
range) for the driven load. The supervisory control system also has the ability to stop
and start the gas turbine and monitor and track its critical operating parameters. The
supervisory control system may be located at the gas turbine itself or located in a
centralized control room with the other plant control systems (like a facility wide DCS
system).
The control of a gas turbine is linked to the load device. If the gas turbine is connected
to a generator, the objective is to operate the generator at a constant frequency or
generator speed. For a mechanical load such as a compressor, the required power output
and speed of the power turbine depends on a setpoint (such as suction pressure,
discharge pressure, or flow) and will vary with demand.
One common control system uses a computer network referred to as a DCS (Distributed
Control System). Separate computers are used for the station (overall) control and for
individual unit (or gas turbine) control. They are interconnected by a high speed
computer network. Unit control is performed by a PLC (Programmable Logic
Controller).
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Some vendors supply specific control system packages with their equipment that are
considered “proprietary.” Therefore, the specific control logic, software and functional
strategies cannot be analysed or modified by the purchaser. These systems are
sometimes called “black boxes” because their “brains” cannot be read or changed by the
purchaser. This unit control is interfaced to instrumentation and sequencing inputs and
outputs.
The control system is accessed through an operator interface called an HMI (Human
Machine Interface) which has largely replaced most of the analog systems with their
associated strip charts, single instrument displays and individual control instruments. An
example of a control system network is shown in Fig. 1.
Figure 1
Gas Turbine Control System Network
(Courtesy of Rolls Royce)
GAS TURBINE LEVEL CONTROLS
In most control systems, the control functions are performed by a specialized computer
(PLC). This computer is programmed with specialized control logic, called ladder logic,
which describes the instructions needed to perform all the necessary control,
sequencing, logic, and other functions. It has largely replaced pneumatics, relays, and
specialized analog controls.
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The PLC interfaces with instrumentation and devices through I/O (input/output) cards
that receive:
• Analog inputs (e.g. pressures and temperatures)
• Analog outputs (e.g. fuel gas valve position)
• Digital inputs (e.g. whether the oil pump is running)
• Digital outputs (e.g. a signal to turn on a pump)
• Frequency inputs (e.g. rotor speed)
Some control systems use multiple processors for double and even triple redundancy.
Other systems use two out of three voting logic for critical input signals, such as speed,
to ensure high reliability and equipment protection (e.g. overspeed protection).
Every control system has a control panel with an operator interface (HMI). It allows an
operator to:
• Startup or shutdown the gas turbine
• Control the turbines speed
• Modify the control system logic (with special access rights)
• Monitor measured parameters.
An example of the gas turbine level control is shown in Fig. 2.
Figure 2
Gas Turbine Control Panel and HMI
(Courtesy of Rolls Royce)
Control System Functions
The major function of a control system is to ensure correct sequencing during startup
and shutdown. The details of this function are fully covered in Objectives 3 and 4.
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The control system must safely control the flow of fuel to the combustors to ensure that
the gas turbine efficiently drives the process load under all conditions. It positions the
fuel metering valve based upon load or demand (e.g. generator frequency or compressor
discharge pressure).
Changes in demand loading requires a very controlled “ramp up” or “ramp down”
response from the gas turbine control system as a rapid increase or decrease in
acceleration can cause surge, flame out or other combustion problems..
Depending on ambient temperature, there are maximum limits to operation. At higher
ambient temperatures, a gas turbine is limited by exhaust gas temperature to ensure that
temperature limits for combustion and turbine section components are not exceeded. At
lower ambient temperatures, a gas turbine is limited by rotor speed to regulate the
stresses placed on rotor blades. For dual shaft gas turbines, there are minimum and
maximum limits on power turbine speed.
Additional controls are required for bleed valves and variable guide vanes. Sometimes,
these controls are independent, but it is becoming common to include them in the main
gas turbine control system. Both bleed valve and variable guide vane operations are
controlled by the main gas turbine controller using a calculation embedded into the logic
sequencing that matches their positions to a specific startup time line and engine speed.
Another function of the control system is to indicate when abnormal levels are reached
by generating an alarm, or by shutting down the gas turbine under certain conditions.
Protective systems are described in Objective 2.
Instrumentation
The control and monitoring system of a gas turbine normally incorporates
instrumentation to monitor the following conditions:
• Rotor speed for each shaft (r/min)
• Inlet temperature to the compressor, combustors and turbine (˚C)
• Differential pressure across the intake filters (Pa)
• Compressor discharge pressure (kPa), measured at the exit of the compressor and
before combustion begins.
• Exhaust gas temperatures (˚C), usually measured at multiple circumferential
points and as an average, after the first or second turbine stage, or in between the
engine turbine and power turbine
• Vibration, measured using accelerometers mounted on the engine case if antifriction bearings are used (applies to most aeroderivatives)
• Vibration, measured using eddy-current displacement probes if journal or tilt-pad
bearings are used (applies to most heavy-duty gas turbines)
• Bearing temperatures (˚C), measured if journal or tilt-pad bearings are used
(applies to most heavy-duty gas turbines)
• Inlet guide vane and variable stator vane position (angle in degrees)
• Fuel gas flow, pressure, and temperature
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•
•
Oil system pressures and temperatures
Generator output, or compressor shaft power (kW)
CLOSED LOOP CONTROLS
Some controls are independent devices directly controlled by the main gas turbine
control system.
Examples of these type of controls include:
• Engine bleed valves that are positioned by a speed signal and ambient
temperature
• Oil cooler that is controlled by a thermostatic valve that controls the amount of
oil going to or bypassing the cooler
• Pressure regulators that limit oil pressure after the main lube oil pump.
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Objective 2
Describe the principles and design of gas turbine
protection devices.
INTRODUCTION
Protective devices prevent abnormal operating conditions, both for safety purposes and
to protect equipment. In some cases, the control system first produces an alarm which
can take one or more of the following forms:
• A flashing light on the control system computer or panel
• An audible horn
• An alarm sent to a remote supervisory system
• A message sent to a pager
In some instances, if a higher level is reached, or if the alarm is not acknowledged in a
certain time period, the control system may initiate a shutdown.
For critical shutdowns, the fuel valve is immediately closed. In less critical situations, a
normal stop with a normal cooldown is used.
Fig. 3 shows an example of a protective shutdown system. It features not only triple
redundant control processors, but also a separate triple redundant protection module
which is hardwired independently and has its own hydraulic trip system. This protects
against overspeed and loss of flame and checks generator synchronization. There will be
links to other equipment or parts of the system within the facility, such as a steam
turbine or HRSG in a combined cycle operation, to ensure that all connected or impacted
equipment will be protected.
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Figure 3
Gas Turbine Protection System
(Courtesy of GE Power Systems)
TYPES OF PROTECTION
Protection may require one of the following actions:
• Alarm only
• Alarm at one level and shutdown at a higher (or lower) level
• Shutdown with normal cooldown
• Fast shutdown with no cooldown
• Activation of auxiliary or support systems
Combustion Protection
Combustion protection includes:
• High exhaust gas temperature (fast shutdown)
• High exhaust gas temperature spread (alarm only)
• Loss of flame (fast shutdown)
• Ignition failure on startup (fast shutdown)
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Overspeed Protection
Overspeed protection includes:
• High gas turbine rotor speed for single shaft units (fast shutdown)
• High power turbine rotor speed for dual or multiple shaft units (fast shutdown)
• Mechanical and electronic overspeed devices for turbine protection
Vibration Protection
Vibration protection includes:
• High vibration for any transducer (alarm and fast shutdown)
Fuel Gas Supply System Protection
Fuel gas supply system protection includes:
• High fuel gas supply pressure (alarm and fast shutdown)
• Low fuel gas supply pressure (alarm only)
Fuel Oil/Liquid Fuel System Protection
Fuel oil/liquid fuel system protection includes:
• Low fuel pump suction pressure
• High and low differential pressure across the fuel manifold
• Fuel supply header low or high pressure
• Fuel transfer failure
Oil System Protection
Oil system protection includes:
• Low oil pressure (fast shutdown)
• Low lube oil tank temperature (alarm only)
• High lube oil header temperature (alarm and fast shutdown)
• High bearing temperature (alarm and fast shutdown)
• Low oil level (alarm and shutdown)
• High oil filter differential pressure (alarm only)
Intake System Protection
Air intake system protection includes:
• High air filter differential pressure (alarm only)
• High and low compressor inlet temperature (alarm)
Fire and Gas Protection
Fire and gas system protection includes:
• Fire detection (fast shutdown)
• Presence of gas detected in the gas turbine enclosure (alarm and fast shutdown)
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Objective 3
Describe the detailed hot and cold startup procedures
for a gas turbine, including safety precautions.
INTRODUCTION
The startup of a gas turbine requires a specific sequencing. It is extremely important that
the operator be completely competent in all the relevant procedures and the various
steps that must be executed to ensure the safety of personnel and protect the equipment
from potential damage. In general, the control system handles all the steps required for a
startup. Manual intervention is not necessary unless there is an unscheduled trip or
shutdown.
The following description applies to most gas turbines, but will vary according to the
type of engine, its application and use, and specific installation and environmental
conditions.
Gas turbine operators should understand and be fully aware of written procedures and
manuals provided by manufacturers, equipment packagers, and the operating company.
Procedures and guidelines provided by the manufacturer and/or equipment packager
need to be strictly followed. Equipment operators may also have their own practices and
procedures that need to be understood and followed.
The startup and shutdown of a gas turbine may be triggered automatically if
predetermined conditions occur. For example, a backup power generation unit may start
automatically in response to an increase in demand, or a compressor may start if the
pressure drops in a given process. Often, operators monitoring the overall process will
initiate a start manually. Once a startup or shutdown is initiated, the sequencing is
almost always automatic.
STEPS TO START A GAS TURBINE
The basic steps in starting a gas turbine are:
1. Preparing for startup
2. Start initiation
3. Crank and lightoff
4. Acceleration phase
5. Synchronization phase
6. Operational phase
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These steps must happen in a specific sequence and at certain time intervals. They are
usually managed by the control system. The operator often has no role except to watch
the process. If certain conditions occur, or if specific requirements are not met at some
point in the startup sequence, the startup will be aborted and the unit stopped.
Preparing for Startup
Different startup preparation activities are needed for:
• Normal startup for frequently used equipment
• Normal startup for intermittently used or backup equipment
• Startup after routine or minor maintenance
• Startup after major maintenance or overhaul
If the equipment is used frequently and maintenance work has not been done recently,
only a few checks are required. These may include a walk-around and visual inspection
of the engine to check for:
• Leaks in the oil system (including pumps, fittings, piping and tubing)
• Oil tank and sump level
• Air intake obstructions
• Correct placement and secure fastening of all guards and covers
• General hazards
If the equipment has been shut down for an extended period of time, the operator should
check that all the following auxiliary equipment and support systems are activated and
energized:
• Electrical
• Pneumatic
• Fuel
• Instrumentation
• Lubrication
• System controllers
These systems may have been shutdown and need to be activated before the startup is
initiated. If routine, minor, or major maintenance has been done recently, the work area
has to be cleaned and all tools, parts and supplies removed prior to startup. Shutoff
valves may need to be opened or unlocked. Other maintenance-specific steps may need
to be taken, and a more thorough pre-start inspection may be required.
For remote applications, startup normally occurs automatically without human
participation or intervention, unless an abnormal situation requires response. If a
previous malfunction or abnormal condition has occurred, the system may need to be
reset. This is done by pressing a reset switch on a control panel or on a computer screen.
There are also a number of permissives that need to be satisfied before the control
system can initiate a start sequence. Some of these pertain to gas turbines (such as
minimum oil reservoir temperature), and others are required by generators or
compressors.
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Start Initiation
A gas turbine operates in one of two modes: remote or local. The mode of operation is
set either by a switch on the control panel or by a selection box on a computer screen.
When in remote mode, a high-level process control system initiates a startup. When in
local mode, the startup can only be initiated from the control panel. During the startup
sequence, a number of conditions have to be met as determined by various pressure,
temperature, and status switches. Timers are used to ensure that these conditions occur
within an expected time period, if not, the startup is aborted.
When the start button is pressed (locally or remotely), the following happens:
• Ventilation fans start up to vent the building or enclosure.
• Pre-lubrication begins. The backup pump starts to test the system; if adequate
pressure is achieved within a certain time period, the prelube pump starts and the
prelube timer resets to ensure adequate pressure.
• The fuel gas system is checked to ensure that fuel valves are operating properly
and adequate pressure is available.
Cranking and Lightoff
An example of a startup sequence for a heavy-duty gas turbine driving a generator is
shown in Fig. 4.
Figure 4
Single Shaft Heavy-Duty Gas Turbine Startup Sequence
(Courtesy of GE Power Systems)
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The equivalent startup sequence for a dual shaft aeroderivative gas turbine is shown in
Fig. 5. It should be noted that there are three speeds:
• N1 for the low pressure rotor
• N2 for the high pressure rotor
• Power turbine speed for the rotor attached to the load.
The starter rotates the N2 rotor, and then the N1 and power turbine rotors break away
(self-power) when the aerodynamic forces are sufficient to rotate them.
Total startup time for a large heavy-duty gas turbine is normally 12 to 20 minutes (start
times for aeroderivatives are shorter, about 5 to10 minutes). This allows for a slow
warm-up that minimizes the effects of thermal shock on hot section components. For
single shaft heavy-duty gas turbines, the startup time may also include several minutes
to start the diesel engine (often used as a starter due to the high torque required to turn
not only the gas turbine rotor but also the generator). It is possible to decrease start time
by as much as 50% for fast load or emergency situations.
After the warm-up period, the starter begins to rotate (crank) the gas turbine rotor. The
first portion of the crank is to purge the gas turbine for several minutes in case explosive
vapours are still present. This is especially important for combined cycle or
cogeneration applications where exhaust is passed through a heat exchanger. The rotor
then coasts down to a speed appropriate for lightoff.
Fuel is admitted to the combustion chambers, the igniters are energized, and lightoff
occurs. Once positive light off is determined by the flame scanners, the startup sequence
will continue. Combustion is established in all combustors by means of crossfire tubes.
This results in a rapid increase in speed. The starter disengages due to the operation of
the overrunning clutch and shuts off. The igniters are de-energized.
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Figure 5
Dual Shaft Aeroderivative Gas Turbine Startup Sequence
Courtesy of Strategic Maintenance Solutions Inc.
Acceleration Phase
For the single shaft heavy-duty gas turbine shown in Fig. 4, warm-up occurs relatively
slowly (over several minutes) as the speed increases. For the aeroderivative gas turbine
shown in Fig. 5, the engine warms up at a constant idle speed.
On startup initiation, the bleed valve(s) are open, and the inlet and variable guide vanes
are closed. The bleed valves close at a certain speed or over a specified range of speeds.
The guide vanes open to their optimum position over a range of speeds as designated by
a specified schedule (relationship between guide vane position and speed), as shown in
Fig. 4.
Synchronization Phase
After the warm-up is finished, fuel flow is increased and the load is applied. For a
generator, this involves synchronizing the speed, phase, and voltage and then closing the
breaker.
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For a compressor the following steps are taken:
• Pressurize the compressor by opening the suction valve
• Purge the compressor by opening the vent valves
• Open the recycle valves and crank the compressor
• Increase speed and open discharge valve.
• Increase pressure by closing recycle valves
The actual operating point is determined by the control system. The acceleration and
deceleration of gas turbines are limited to certain rates. Sudden increases in speed causes
rapid increases in turbine temperature that can easily exceed the limits. Rapid decreases
in speed can interrupt combustion; re-lighting would be catastrophic.
Operational Phase
Once the engine is running, it may be advantageous to do another walk-around to check
for oil leaks and listen to the engine. Readings of the operating conditions (e.g. speed,
pressures, and temperatures) should be entered on a log sheet to ensure they are within
acceptable limits and for future comparison. The date and time of the startup and the
running hours on the hour meter should be recorded in a log book along with any
relevant observations or problems encountered.
COLD STARTING
At low ambient temperatures, it may be necessary to heat the lube oil to facilitate
starting. If the oil is too cold, starting torque may be too high and the turbine rotor may
fail to reach the required cranking speed. Oil temperature needs to fall within acceptable
limits before a startup can be initiated. The oil can be heated by a heater in the oil tank,
or by circulating the oil through a heat exchanger.
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Objective 4
Describe the detailed shutdown procedure for a gas
turbine, including safety precautions.
NORMAL SHUTDOWN
Shutdown of a gas turbine is most often initiated by an operator although some systems
shutdown automatically when the gas turbine is no longer required. To a large extent, a
shutdown is the reverse of a startup.
The first step in a controlled shutdown is to reduce the speed, over a specified period of
time, down to “zero load speed.” As the speed is being reduced, the load on the turbine
(electric generator or gas compressor) will be reduced and the entire unit will be allowed
to cool down under even and stable conditions. Once at idle speed, the power turbine wil
be unloaded completely by disconnecting from the main electrical grid or fully opening
the recycle valves if the load is a gas compressor. During this cool down period, the
turbine can be quickly loaded back up if the need arises.
When the cooldown timer timeframe has been completed or the specific minimum set
temperatures across the machine have been reached, the fuel valve is closed and
combustion is eliminated. The rotor speed will decrease and the machine will stop.
As the speed drops, the main lube oil pump (if driven off the rotor) loses pressure. At a
specified point, usually based on oil pressure, the prelube pump starts and continues to
lubricate and cool the bearings for a specified time period. The enclosure or building
fans shut off.
On most heavy-duty gas turbines, the turning gear activates at either 15% of operating
speed or immediately after the rotor stops turning. The turning gear rotates the rotor at a
slow speed for a certain time period — ranging from 5 hours for a small gas turbine to
as many as 60 hours for a very large gas turbine. Restart at any time during this time
period is allowed. This cooldown period prevents bowing of the rotor, which would
cause high vibration on the next startup and could lock-up the rotor and prevent starter
rotation.
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FAST SHUTDOWN
This type of shutdown is reserved for emergency conditions. It increases wear on a gas
turbine because of the rapid cooldown it entails. A fast shutdown is initiated when a
protective device detects an abnormal condition, such as high vibration, or when an
operator initiates an emergency stop. The cooldown period is eliminated, and the fuel
valve is closed immediately. The rest of the shutdown sequence is the same.
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Objective 5
Explain the routine maintenance and monitoring
requirements for a gas turbine.
INTRODUCTION
Predictive and preventative maintenance programs are very important to ensure:
• Maximum power output
• High cycle efficiency
• Long term engine integrity
• Minimum offline time
If the gas turbine is not correctly maintained it will result in:
• Increased offline time
• Increased operating costs
• Decreased life cycle of the unite
Generally, routine maintenance and monitoring of gas turbines is specified in detail by
the manufacturer of the engine. However, these routines apply to average conditions.
Every user has to consider whether the amount, frequency, and type of maintenance
need to be adjusted according to more or less severe operating conditions.
The following three major factors affect the type and level of maintenance that will be
required on the gas turbine system:
• Environmental conditions
• Load conditions
• Fuel types used
ENVIRONMENTAL CONDITIONS
Environmental conditions include:
• High or low ambient temperatures
• High altitude or sea level operation
• External contaminants such as abrasive contaminants, corrosive gases or high
moisture content in the air
• Amount of water or steam injected
• Fuel contaminants
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LOAD CONDITIONS
Load conditions include:
• Stop/start times
• Above rated load operations
• Normal load operations
• Reduced load operations
Gas turbines operate best and require the least maintenance if run consistently at close to
rated load. In some cases, operation at higher than rated load is allowed for peaking
loads, but this always increases maintenance requirements. Running at part load may be
detrimental to engine condition if bleed valves are open, but the main impact will be
reduced fuel efficiency.
A maintenance program tailored to a specific gas turbine or individual components of
the turbine system can be developed using a number of important information sources.
Key sources would include the following:
• Vendor/manufacture manual and recommendations
• Existing trend data from the DCS and PPMS systems
• Good engineering practices from relevant codes and standards materials
• Previous experience
The results should be thoroughly documented, probably in a computerized maintenance
management system, and should include detailed task descriptions, task frequency, time
and skills required, special procedures, and spare parts needed. Then, work orders can
be generated to ensure that all tasks are carried out on time. All findings will be tracked
and trended to ensure the desired results are being achieved.
It is important to emphasize that the following tasks are typical, but are not applicable in
all cases. They should not be used as the sole basis for a routine maintenance program.
ROUTINE MAINTENANCE
Routine maintenance consists of various minor tasks that can be broken down into these
categories:
• Visual monitoring and inspection
• Recording engine parameters on a log sheet
• Checking fluid levels
• Sampling fluids (oil and possibly glycol if it is used for oil cooling)
• Replacing filters
• Engine compressor waterwashing
• Testing relief valves
• General cleanup
• Calibrating instrumentation
• Testing control and protective devices
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The frequency of these tasks depends on the location of the equipment
(remote/unattended/attended), its criticality, and the type of engine. Visual monitoring
and logging are usually done once per shift or once per day, other routine checks may be
done once per week or even once per month. Some tasks are done at 6 month or 12
month intervals. Some tasks are also based on “equipment running hours”. These
schedules will be developed by tracking and trending the system over time to determine
the most efficient and cost effective times for each task. Lube oil changes can be based
on running hours but are more often based on detailed lube oil analysis.
Routine Lubrication System Maintenance
Oil systems are relatively maintenance free. Automatic protection is usually provided
against common problems. Maintenance tasks include:
• Checking for oil leaks (daily)
• Monitoring oil pressures and temperatures (daily)
• Checking chip detectors when they sound an alarm
• Topping up the oil reservoir
• Changing oil filters when the differential pressure alarm sounds
• Cleaning the oil coolers (shell and tube sides)
• Taking oil samples regularly for analysis and cleaning the oil during operation or
replacing it when required
• Calibrating instrumentation and testing protective devices
Different approaches are used for ensuring oil quality. Oil quality may be affected by:
• External contaminants (such as dirt, sand or water)
• Contamination by combustion products
• Coolant leaking from the oil cooler
• Increase in viscosity
• Increase in acid number
• Depletion of oil additives
• Wear particles from moving and sliding surfaces
For smaller engines, it is usually sufficient to replace the oil on a regular basis as
determined by running hours. If engine usage is low (less than 50%), as with backup
generators, oil replacement should be based on a calendar schedule (often annually).
For larger engines, it is common practice to take oil samples every 1 to 3 months and
have them analyzed for contaminants. The timing of the oil change is based on the
condition of the oil.
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Routine Fuel System Maintenance
Fuel systems are relatively maintenance free. Automatic protection is usually provided
against common problems. Maintenance tasks include:
• Checking for fuel leaks (daily)
• Monitoring pressures and temperatures (daily)
• Changing the fuel filters when the differential pressure exceeds the allowable
setpoint pressure
• Cleaning centrifuges and other treatment components and replenishing chemicals
(for liquid fuels)
• Calibrating instrumentation and testing protective devices
WATERWASHING
The major cause of deterioration in gas turbine performance is fouling of the compressor
blading. Fouling results in decreased compressor efficiency which will reduce the
overall thermal cycle efficiency as well as reduce the maximum power output. It also
results in compressor surge and acceleration problems.
The source of contamination is usually dust, salt, hydrocarbon products and corrosive
gases like SO2 other airborne particles that are not trapped by intake filters.
Contamination can also come from machinery close to the gas turbine, or even gas
turbine exhaust that is re-ingested under certain wind conditions. Sometimes, a
compressor front bearing that is leaking oil will make the problem worse.
Compressor cleaning can be accomplished by using either a liquid or an abrasive
material. In the past, it was quite common for walnut shells or rice (or other abrasive
materials sometimes called carbo-blast) to be injected into the intake to abrasively clean
the compressor blading. This is done while the unit is running and the materials are
burnt up in the combustion section and then pass through the engine. Since it is not as
effective as the waterwash method, it is not utilized as often any more. It also has the
disadvantage of plugging up cooling passages in the compressor and cooling holes in the
turbine blades.
The most effective method of compressor cleaning is the offline waterwash. This
consists of stopping the unit, injecting waterwash fluids into the intake of the
compressor while running on the starter, and then restarting the unit. It is also referred to
as the crank-soak method. Online water washing is not as effective as off-line although
it is still a viable alternative if downtime is not acceptable.
Waterwash Fluids
The high-purity water that is used must conform to quality standards specified by the
gas turbine vendor. Using hard water, or water contaminated with sodium, potassium,
magnesium, vanadium or other chemicals, can cause further fouling and increased
corrosion.
Page 400
To remove oily substances, additional cleaning agents and solvents are mixed with the
water. Acceptable cleaners are often specified by gas turbine vendors. However, the
most effective cleaning agents are also the most toxic and require special handling.
If the temperature is less than 4˚C, a 1:1 mixture of water and ethylene glycol is
recommended to prevent icing. The gas turbine vendor should be consulted since
commercial and automotive anti-freeze products are usually not acceptable.
MONITORING
Monitoring engine parameters is important to ensure successful operation of a gas
turbine. This is usually accomplished by recording various readings on a log sheet.
Computerized monitoring programs, which gather data using hand-held data collectors
or by monitoring control systems, are also used.
An example of a paper log sheet is given in Fig. 6. The date and time of the entry and
the hours on the run meter are recorded along with the name of the person who
completed it. Each parameter is clearly described with its unit of measurement. Alert
values are noted for each parameter where relevant. Where an alert value has been
exceeded, the reading is circled.
The sequence of parameters on the log sheet is always an issue. For recording purposes,
it is best to put them in the order that the readings are taken although this often differs
between operators. When viewing the results, it is better to organize the readings
logically according to systems and types of readings. The log sheet in Fig. 6 is organized
this way, but includes a separate column to indicate the normal input sequence (for
reference purposes only).
Sometimes, a calculated value is required to recognize an abnormal condition. If the
calculation is simple, such as the exhaust temperature spread shown in Fig. 6, it can be
added to the log sheet. This is the difference between the lowest and highest exhaust
temperatures. If the spread is caused by an exhaust temperature that is too high, the
engine may be receiving too much fuel through an eroded fuel nozzle. If the spread is
caused by an exhaust temperature that is too low, there may be problems with a plugged
fuel nozzle.
DCS trends on vibration, temperatures across the entire cycle, power to fuel ratios,
maximum load capabilities, emissions and a number of other critical items can be
electronically monitored to give the operator detailed information on the current
condition of the equipment as compared to design or rated data.
Page 401
Input
seq.
Parameter
Unit of
Measuremen
t
1
Name
2
Date
yy.mm.dd
3
4
5
6
13
16
15
Time
Run Hours
Ambient temperature
Gas producer speed
Power turbine speed
Generator power
Air filter diff pressure
Compressor discharge
pressure
Exhaust gas temp #1
Exhaust gas temp #2
Exhaust gas temp #3
Exhaust gas temp #4
Exhaust gas temp #5
Exhaust gas temp #6
Exhaust gas temp #7
Exhaust gas temp #8
Temp spread
Fuel pressure
Oil pressure
Oil temperature
Oil filter diff pressure
Oil level
Vibration - front
Vibration - centre
Vibration - rear
hh.mm
hrs
°C
RPM
RPM
kW
mm H2O
14
17
18
19
20
21
22
23
24
Calc.
8
10
9
11
12
Low
alert
High
alert
P.
Jones
03.06.0 03.06.0 03.06.0
1
2
3
0830
0900
0845
12,345 12,369 12,393
21
16
18
12,000
9200
9100
11000
7500
6100
6050
7000
16,300 16,000 15,900
400
210
215
220
A. Smith A. Smith
8500
2000
kPa
°C
°C
°C
°C
°C
°C
°C
°C
°C
kPa
kPa
°C
kPa
%
mm/sec
mm/sec
mm/sec
200
275
75
550
550
550
550
550
550
550
550
80
350
380
90
100
50
COMMENTS:
Figure 6
Example of a Log Sheet
Page 402
Readings
20
20
20
254
243
298
502
503
500
498
506
508
507
506
10
320
290
82
60
80
10
12
8
500
585
503
507
509
501
502
504
85
330
295
83
62
85
11
14
7
490
571
498
502
503
510
506
503
81
360
293
82
63
85
9
13
9
Objective 6
Describe the major maintenance and overhaul
requirements for a gas turbine.
INTRODUCTION
Major maintenance requirements for gas turbines vary considerably. Manufacturers
provide detailed instructions and recommendations on major maintenance that should be
carefully followed. However, each engine should be considered separately. The
frequency of maintenance is highly dependent on the following:
• Individual load
• Fuel type and quality
• Stop/start cycles
• Environmental factors
• Water or steam injection
• Rate of start-up
The following description is an example of the types of major maintenance that might be
carried out. It should not be used as the sole basis for an actual maintenance program.
Intervals reflect suggested values only.
Maintenance activities are broken down into three types:
• Routine inspections (every year or every 8,000 running hours)
• Intermediate level maintenance (every 3 to 5 years, every 24,000 to 30,000
running hours or every 1200 starts)
• Major maintenance or overhaul (every 6 to 8 years, every 48,000 to 60,000
running hours or every 2400 starts)
For intermediate or major maintenance of aeroderivative gas turbines and small to
medium heavy-duty gas turbines, it is possible to remove the entire engine, replace it
with a spare or rental, then overhaul it in a repair facility. Otherwise, the overhaul has to
be done on-site which can easily take several weeks to complete.
ROUTINE INSPECTION
It is common for routine inspections to take place once per year or every 8,000 running
hours. The core of this inspection is usually borescoping the engine. A borescope is a
long, flexible, articulated hose that contains a fibre optic cable. Radially aligned holes
are supplied in the compressor casing, turbine shell and internal stationary turbine
shrouds to allow the borescope to check all these areas.
Page 403
The borescope is used to inspect the internal gas path without dismantling the engine. It
has a light at one end and is connected to a viewer through which internal components,
such as blades and combustion section, can be closely inspected. It is also used to check
guide vane linkages for bushing wear and proper calibration.
Combustion Inspection
Combustion inspection, carried out during a shutdown, consists of the inspection of the
flame detectors, fuel nozzles, liners, cross-fire tubes, spark plug assemblies, combustor
flow sleeves and transition pieces. The requirements for this type of inspection include
the following:
• Inspection of the fuel nozzles for erosion of tip holes and plugging
• Inspection of the cross-fire tubes and liners for erosion, oxidation, cracking and
corrosion
• Inspection of the spark plug assemblies for condition of the electrodes and
insulators
• Visual inspection of the compressor inlet and turbine exhaust areas and the inlet
guide vanes
• Inspection of the gas, air and fluid passages in the nozzle assembly for signs of
erosion, cracking and corrosion
• Inspection of the transition piece for cracks and wear
• Inspection of the flow sleeve welds for signs of cracking
• Inspect the interior of the combustion chamber for foreign objects and debris
• Visual inspection of the first stage turbine nozzles and buckets
Hot Gas Path Inspection
This type of inspection includes all components that have been in contact with the hot
gases. Signs of any abnormal wear, corrosion, erosion and cracking are identified after
removal of the top of the turbine. Hot gas path inspection includes the following:
• Visual inspection of the turbine exhaust area for any signs of deterioration or
cracking
• Inspection the condition of the later stage nozzle diaphragm packings
• Check the later stage diaphragm seals for rubbing and reduction in clearances
• Use of a borescope to check the condition of the blading in the end of the axialflow compressor
• Visual inspection of the coating on the first-stage buckets
• Inspection and record the condition of the first three-stage nozzles
• Measure and record the clearances of the bucket tips.
• Inspect the bucket seals for deterioration, clearances and any signs of rubbing
Page 404
Major Inspection
Major inspection of a gas turbine includes the examination, from the inlet to the exhaust,
of all the internal stationary and rotating parts. The frequency of this inspection is
dependent on the recommendations in the manufacturer’s maintenance manual and the
findings from the borescope and hot gas inspection. The first stage buckets may need to
be replaced depending on the visual inspection of the coating. This type of inspection
includes the following:
• Check the alignment of the complete unit
• Check the clearances and signs of wear in the bearing liners and seals
• Inspection of the seals and proper fit of the turbine nozzles
• Inspection of the diaphragms for any signs of thermal deterioration, erosion, and
rubbing
• Inspect the frame. Shells and casings for any signs of erosion and cracking
• Inspection of the exhaust systems for visible cracks and broken silencer and
insulation panels
• Visual inspection of the turbine stationary shroud for signs of cracking, rubbing,
erosion, clearances and the buildup of deposits
• Inspection of the stator and rotor compressor blades for visible signs of cracking,
bowing, corrosion pitting, rubbing and impact damage
• Check the axial and radial clearances against their original manufacturer’s values
• Removal of the turbine buckets for NDE (Non Destructive Examination)
• Inspection of the coating on the first stage buckets
• Visual inspection of the inlet and flow path of the compressor for signs of
leakage, corrosion, erosion and fouling
INTERMEDIATE LEVEL MAINTENANCE
After 24,000 to 30,000 running hours, it is usually necessary to carry out maintenance
on hot gas path components, such as turbine nozzles and blades and combustors. This
may entail repair or replacement of these components. For aeroderivative gas turbines,
this usually means a trip to the repair shop where the engine can be dismantled and
inspected. For heavy-duty gas turbines, maintenance is usually done on site after
removing covers from the compressor and turbine and opening the combustors. The
amount of maintenance required depends on the type of deterioration and damage found.
MAJOR MAINTENANCE OR OVERHAUL
Major maintenance or overhaul occurs every 48,000 to 60,000 running hours and is a
costly activity. It is often referred to a zero hour overhaul since the final result is an
engine that is in almost new condition.
The following example outlines the major steps in an overhaul of an aeroderivative
engine that has been sent to a repair shop (a replacement engine was installed in its
place). This process can take from 45 to 60 days.
Page 405
Step One
The engine is placed in a vertical hydraulic pit (Fig. 7) so it can be easily dismantled.
The engine can be raised or lowered to make it easier to access all parts of the engine.
Figure 7
Engine in Hydraulic Pit
Courtesy of Strategic Maintenance Solutions Inc.
Page 406
Step Two
All parts, especially blades, are carefully organized in trays (Fig. 8).
Figure 8
Parts in Trays
(Courtesy of Strategic Maintenance Solutions Inc.)
Page 407
Step Three
Parts are cleaned using sandblasting, chemical cleaning tanks (Fig. 9), and ceramic
media cleaning tanks.
Figure 9
Chemical Cleaning Tanks
(Courtesy of Strategic Maintenance Solutions Inc.)
Page 408
Step Four
Blades are checked for cracks (Fig. 10) by spraying dye penetrant on the blade and then
cleaning it off. The dye remains in the cracks and can be detected under ultraviolet light.
Figure 10
Ultraviolet Inspection Booth
(Courtesy of Strategic Maintenance Solutions Inc.)
Page 409
Step Five
A process called dispositioning (Fig. 11) is used to decide whether components should
be kept, repaired, or rejected. This is based on specific criteria such as the dimensions,
type, and size of cracks, loss of coatings, and sometimes the number of operating hours.
Figure 11
Dispositioning
(Courtesy of Strategic Maintenance Solutions Inc.)
Page 410
Step Six
Repairs (Fig. 12) are carried out and engine parts are stored waiting for new parts.
Figure 12
Repair of Parts
(Courtesy of Strategic Maintenance Solutions Inc.)
Page 411
Step Seven
The rotor and blading are reassembled (Fig. 13). This usually involves carefully
restacking the stages of the rotor to prevent unbalance.
Figure 13
Reassembly of Rotor and Blading
(Courtesy of Strategic Maintenance Solutions Inc.)
Page 412
Step Eight
The rotor is balanced in a balancing machine (Fig. 14) to ensure that vibration levels are
within acceptable limits.
Figure 14
Balancing Machine
(Courtesy of Strategic Maintenance Solutions Inc.)
Page 413
Step Nine
The final reassembly (Fig. 15) takes place by assembling rotors, casings, combustion
components, and all auxiliaries mounted on the engine.
Figure 15
Final Reassembly
(Courtesy of Strategic Maintenance Solutions Inc.)
Page 414
Step Ten
The engine is tested in a test cell (Fig. 16) to verify performance and check vibration
levels.
Figure 16
Engine Installed in Test Cell
(Courtesy of Strategic Maintenance Solutions Inc.)
Page 415
Page 416
Objective 7
Explain the troubleshooting of gas turbine problems.
INTRODUCTION
Good troubleshooting methods are important to minimize the effects of problems on
equipment availability and reliability. Predictive and preventative maintenance,
operating skills and techniques are of a great benefit to the operator. Current technology
provides the operator and maintenance engineer with a wide variety of excellent tools
with which they can track and trend all critical components of their equipment. These
tools can be used to predict potential problems before they occur and thus allow the
operator to respond to the issue before it impacts production of damages the equipment.
Should an incident occur, the standardized “failure analysis” procedures and programs
should be used to identify the “root cause” of the problem and help develop a formalized
response to eliminate the chance for the incident to re-occur.
A potential problem may become evident through human observation, routine
monitoring and logging, inadequate performance (dependent on the type of load), or a
control system alarm or shutdown.
The stages in troubleshooting may include some or all of these steps:
1. Initial problem indication
2. Preliminary investigation using available information (from the control system
(e.g. alarm indication), log sheets, performance readings and troubleshooting
guides)
3. Initial attempts (hopefully successful) to rectify the problem
4. Consultation with maintenance experts
5. Consultation with technical specialists or possibly the manufacturer.
General principles for effective troubleshooting are as follows:
• Do not jump to conclusions quickly; keep an open mind and stick to the facts
• Take time to gather relevant data and information
• Consult others who may have important information
• Try easy, low cost and low risk fixes or solutions first
• Seek expert help if the problem appears to be difficult or beyond your expertise
• Do not stop until you are sure that the problem has been solved
• Document the problem and the steps taken to solve it on a work order or other
standard form.
Page 417
TROUBLESHOOTING CHARTS
For illustrative purposes only, the following troubleshooting information is presented in
the form of a standard troubleshooting chart. Always consult the troubleshooting charts
provided by the equipment manufacturers.
The following tables show the three aspects of troubleshooting: symptom, probable
cause, and remedy. The symptom column describes what an operator might notice or
detect during the operation of an engine. The probable cause column lists likely reasons
for the symptom. The remedy column lists potential solutions.
Page 418
Table 1 identifies the problems that might occur during the starting of the turbine.
Table 1
Troubleshooting (Starting)
Symptom
Probable Cause
Remedy
Rotor fails to rotate
Permissives not cleared
Address and clear
permissives
Correct gas or hydraulic
pressure not present
Check to ensure sufficient gas
or hydraulic pressure
Starter motor inoperative
Repair or replace starter
motor
Starter clutch not engaging
Repair starter clutch
Rotor is seized
If previous shutdown was
recent and from full power,
wait for several hours
Major internal problem
Contact manufacturer
Igniters not functioning
Check ignition system as per
maintenance manual
Gas or liquid manifold
pressure is not correct
Check fuel system as per
maintenance manual
Rotor speed is not sufficient
Check starter system
Air intake is obstructed
Clear intake obstructions
Fuel pressure is not adequate
Check fuel system as per
maintenance manual
Control system setting is not
correct
Check control system as per
maintenance manual
Main oil pump pressure is not
high enough
Check main oil pump
regulator and pump
performance
Control system setting is not
correct
Check control system as per
maintenance manual
Check valve between oil lines
not operating properly
Verify proper operation
Bleed valves not operating
properly
Check bleed valves as per
maintenance manual
Inlet guide vane not operating
properly
Check IGV system as per
maintenance manual
Engine compressor is fouled
Clean engine compressor
using offline waterwash
Rotor rotates but fails to light
off
Engine lights off but fails to
reach idle speed
Lube oil pump fails to switch
over from prelube to main
pump
Loud bang is heard on startup
Page 419
Table 2 highlights the conditions that may occur during the running phase.
Table 2
Troubleshooting (Running)
Symptom
Probable Cause
Remedy
Speed is unstable
Fuel pressure is not correct
Check to ensure sufficient gas
or hydraulic pressure
Control system setting is not
correct
Check control system as per
maintenance manual
Speed probe or indicator is
faulty
Repair or replace speed
probe or indicator
Control system setting is not
correct
Check control system as per
maintenance manual
Engine compressor is fouled
Clean engine compressor
using offline waterwash
Long term engine
deterioration
Perform borescope. If
necessary schedule major
overhaul
Fuel nozzle is eroded
Check fuel nozzles
Fuel nozzle is plugged
Check fuel nozzles
Instrumentation problem
Check thermocouples,
harness, and connections
Sudden decrease in vibration
Problem with vibration
transducer or wiring
Check vibration transducer or
wiring
Sudden increase in vibration
If only one reading affected —
problem with vibration
transducer or wiring
Check vibration transducer or
wiring
If more than one reading
affected — engine mountings
are tight or seized
Check engine mountings
If more than one reading
affected — major engine
problem or internal failure
Check vibration as per
maintenance manual
Long term engine
deterioration
Perform borescope. If
necessary schedule major
overhaul
Maximum power is not
obtained
Exhaust gas temperature
spread is too high
Slow increase in vibration
Page 420
Table 3 outlines the troubleshooting of alarms and shutdowns associated with the
turbine.
Table 3
Troubleshooting (Alarms and Shutdowns)
Symptom
Probable Cause
Remedy
Fuel pressure low
Fuel system leaks
Check for fuel system leaks
Fuel filter blocked
Check fuel filter
Problem with vibration
transducer or wiring
Check vibration transducer or
wiring
Alarm and shutdown levels
not correct
Reset alarm and shutdown
levels
Engine mountings too tight or
seized
Check engine mountings
Major engine problem or
internal failure
Perform borescope. If
necessary schedule major
overhaul
Speed probe has failed
Check and replace speed
probe
Problem with wiring and
instrumentation
Check wiring and
instrumentation
Tank level too low
Refill oil tank
Lube oil pump not supplying
correct pressure
Check and replace lube oil
pump
Regulator not set correctly
Check setting for regulator
Tank level too low
Refill oil tank
Oil cooler thermostatic valve
not operating properly
Check and reset thermostatic
valve
Oil cooler is plugged
Repair oil cooler
Vibration high
Loss of speed signal
Lube oil supply pressure low
Oil tank temperature too high
Page 421
Page 422
Chapter Questions
1. Describe the functions of a gas turbine control system.
2. List the monitoring points that are associated with the following gas turbine systems
protection:
a) Oil
b) Combustion
3. What steps are followed to prepare a gas turbine for startup?
4. Describe the steps to be followed in the normal shutdown of a gas turbine.
5. Discuss the methods used to waterwash gas turbine blades, including the type of
cleaners used.
6. Discuss the steps involved in the overhaul of an aeroderivative gas turbine.
7. Briefly outline the symptom, probable cause and remedy for a high vibration alarm
to annunciate.
Page 423
Page 424
Lubrication
Learning Outcome
When you complete this learning material, you will be able to:
Explain the components of a lubrication application and maintenance program.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Describe the methods of manufacture and the different classifications of lubricants.
2. Describe the significance and measurement of lubricating oil characteristics,
including viscosity, relative density, API gravity, pour point, and dielectric strength.
3. Explain the typical causes of lubricating oil deterioration.
4. Describe the types of lubrication additives.
5. Describe a typical power plant lubrication program, including a lubrication survey.
6. Explain the different types of lubricating/governing/seal oil systems.
7. Describe the components and operation of a typical lubricating oil purification
system.
8. Describe the various applications of ball-and-roller bearings and their lubrication,
including bearing seals.
Page 425
Page 426
Objective 1
Describe the methods of manufacture and the different
classifications of lubricants.
METHODS OF MANUFACTURE
Lubricants are manufactured to meet the requirements of the service for which they are
intended. The particular properties desired depend upon the nature of the surfaces which
are to be lubricated, the load carried, the speed of rubbing and the operating
temperature.
The following are methods of manufactring lubricants:
• Fractionating
• Cracking
• Refining
Fractionating
Fig. 1 shows a diagrammatic cross-section of a fractionating tower. Crude oil is
preheated and continuously pumped into the tower at the approximate level shown. Heat
within the tower is applied with steam jets streaming directly into the charge of crude
oil. The crude oil boils and the vapours produced rise into the tower. These vapors must
pass through the bubble caps in each tray in their progress up the tower and as their
temperature falls, condensation of the various constituents takes place.
Page 427
Figure 1
Fractionating Tower
Fig. 2 shows the liquid levels on the trays and the upward path of the vapours through
the bubble caps.The temperatures at the top and bottom of the tower are carefully
controlled and this in turn keeps the various level temperatures constant so that
continuous streams of liquid can be taken from various levels in the tower as the vapors
continue to condense. Oils produced in this manner are called “straight-run.”
Page 428
Figure 2
Trays and Bubble Caps inside Fractionating Towers.
Cracking
All refined petroleum products such as gasoline, kerosene, gas oil and lubricating oil are
composed of two elements, carbon and hydrogen. The other constituents present in
minor quantities, such as sulphur, are considered to be impurities. Further, the majority
of these petroleum products are composed of approximately 85% carbon and 15%
hydrogen by weight.
The arrangement and number of the individual carbon and hydrogen atoms that make up
the particular molecules in the product govern the difference between products. The
chemical combinations of atoms (molecules) can be changed to form new molecules.
The possible number of carbon compounds which can be produced is so great that it
occupies a special classification in the field of chemistry called organic chemistry.
One method of changing molecules is called“thermal cracking.” Here, the application of
heat and pressure combine to produce violent agitation of the atoms forming the
molecules until they force a division into smaller molecules and transform, for example,
heavy fuel oil into gasoline.
The cracking process, in some cases, proceeds faster and more readily in the presence of
a catalyst. Catalyst cracking is employed extensively to produce gasoline with superior
anti-knock and stability qualities.
Page 429
Refining
Lubricating oils obtained from crude petroleum by distillation (fractionating) contain
impurities such as sulphur and other compounds. Washing with a solvent (solvent
refining) removes these unwanted materials.
Wax, contained in lubricating oils, has a direct influence on the temperature at which the
oil ceases to pour. If a wax-bearing oil is used at low temperatures, the wax content is
reduced to lower the pour point. This is done by chilling the oil to a temperature lower
than the desired pour point. Cloth filters remove the solidified wax formed at this
temperature. Wax is not affected by distillation and, during this process, passes over
with the various fractions of the oil. Wax has a flash point and fire point equal to the
heaviest oils and appears to have little effect when oils are used at high temperatures.
CLASSIFICATIONS OF LUBRICANTS
The majority of lubricants are composed of:
• Mineral oils
• Refined oils
• Synthetic oils
• Fatty oils
• Solids
• Greases
MINERAL OILS
Mineral oils are manufactured from crude petroleum oil. The process of commercially
boiling and then condensing the vapours sorts the crude oil into various products called
“cuts” or “fractions. This distillation process is called “fractionating” and is carried out
in a fractionating tower.
Unlike water, which boils uniformly at 100°C (at sea level), crude oil contains a variety
of components that each have a different boiling point.This property is made use of in
the fractionating process.
REFINED OILS
Paraffinic and naphthenic oils are refined from crude oil. Literature on lubrication
frequently makes references to long chain molecules and ring structures in connection
with paraffinic and naphthenic oils, respectively. These terms refer to the arrangement
of hydrogen and carbon atoms that make up the molecular structure of the oils.
Page 430
Paraffinic Oils
Paraffinic oils are distinguished by a molecular structure composed of long chains of
hydrocarbons. The hydrogen and carbon atoms are linked in a long linear series similar
to a chain. Paraffinic oils contain paraffin wax and are the most widely used base stock
for lubricating oils. Paraffinic oils have:
• Excellent stability (higher resistance to oxidation)
• Higher pour point
• Higher viscosity index
• Low volatility and, consequently, high flash points
• Low specific gravities
Naphthenic Oils
In contrast to paraffinic oils, naphthenic oils are distinguished by a molecular structure
composed of “rings” of hydrocarbons. The hydrogen and carbon atoms are linked in a
circular pattern. These oils do not contain wax and behave differently from paraffinic
oils. Naphthenic oils have:
• Good stability
• Lower pour point due to absence of wax
• Lower viscosity indexes
• Higher volatility (lower flash point)
• Higher specific gravities
Naphthenic oils are reserved for applications with narrow temperature ranges and where
a low pour point is required.
SYNTHETIC OILS
Synthetic lubricants are produced through chemical synthesis rather than from the
refinement of existing petroleum or vegetable oils. These oils are generally superior to
petroleum (mineral) lubricant. Synthetic oils perform better than mineral oils in the
following respects:
• Better oxidation stability or resistance
• Better viscosity index
• Much lower pour point, as low as -46ºC
• Lower coefficient of friction
The advantages that synthetic oils offer are most notable at either very low or very high
temperatures. Good oxidation stability and a lower coefficient of friction permit
operation at higher temperatures. The better viscosity index and lower pour points
permit operation at lower temperatures.
The major disadvantage to synthetic oils is the initial cost which is approximately three
times higher than mineral-based oils. However, the initial premium is usually recovered
over the life of the product which is about three times longer than conventional
lubricants. The higher cost makes it inadvisable to use synthetics in oil systems
experiencing leakage and high oil consumptions.
Page 431
Factors to be considered when selecting synthetic oils include:
• Pour and flash points
• Demulsibility
• Lubricity
• Rust and corrosion protection
• Thermal and oxidation stability
• Antiwear properties
• Compatibility with seals, paints, and other oils
Synthetic oils are as different from each other as they are from mineral oils. Their
performance and applicability to any specific situation depends on the quality of the
synthetic base oil and additive package.
Several major categories of synthetic lubricants are available including:
• Synthesized hydrocarbons
• Organic esters
• Polyglycols
• Silicones
Synthesized Hydrocarbons
Polyalphaolefins and dialkylated benzenes are the most common. These lubricants
provide performance characteristics closest to mineral oils and are compatible with
them. Applications include engine and turbine oils, hydraulic fluids, gear and bearing
oils, and compressor oils.
Organic Esters
Diabasic acid and polyol esters are the most common. The properties of these oils are
easily enhanced through additives. Applications include crankcase oils and compressor
lubricants.
Polyglycols
Polyglycols properties are based on their molecular weight and monomers used, and
offer a wide range of formulating possibilities. When used as functional fluids, they
offer superior lubricity and solvency. Applications include gears, bearings, and
compressors for hydrocarbon gases.
Silicones
These oils are chemically inert, non-toxic, fire-resistant, and water repellent. They also
have low pour points and volatility, good low temperature fluidity, and good oxidation
and thermal stability at high temperatures.
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FATTY OILS
Fatty oils are obtained from the seeds of vegetables. They are sometimes used alone but
more frequently are compounded with mineral oils. They are known also as “fixed oils”
because they cannot be distilled without decomposition.
The addition of a fatty oil to a mineral oil increases the adsorbed film on the surface to
be lubricated which raises the load-carrying ability of oil films.
In the presence of heat, mineral oils act differently from fatty oils. A simple experiment
shows that fatty oils move towards the hottest part of a flate iron plate, while mineral
oils tend to “shy” away from heat. This feature is due to a more rapid lowering of
surface tension within the fatty oil which improves the penetrating and spreading
property.
Mineral oils on a metal surface heated to about 230°C tend to form small spheres, like
water on a hot frying pan, when the holding force within the molecules becomes greater
than the affinity of the surface molecules for the metal. The ability to wet a metal
surface in an unbroken film is a necessary function of lubrication.
Mineral oils may be compounded with various materials in many ways. The basic
principle of compounding is to add oily materials that improve the load-carrying ability
of the finished oil under certain conditions, or impart particular qualities which straight
mineral oils do not possess.
The following are the origins and properties of two common fatty oils:
• Canola oil
• Castor oil
Rapeseed Oil
This oil is obtained from plant seeds and has a pale, clear yellow color. Before this oil is
compounded with mineral oil, it is subjected to blowing with air which oxidizes,
stabilizes, and reduces the drying tendencies of the oil.
Rapeseed is used for compounding with mineral oil where there is a possibility of water
entering the bearings. It emulsifies with the water and prevents the displacement of the
oil film from the bearing metal.
Castor Oil
Castor oil comes from the beans of the castor shrub and has the highest specific gravity
and viscosity of any fatty oil. It does not readily mix with mineral oils unless some other
fatty oil such as lard or rape is present. It is occasionally compounded with heavy
mineral oil and used for lubricating heavy-duty gearing.
As a lubricant for internal combustion engines, it has a viscosity rating of an SAE 50
(Society of Automotive Engineers) motor oil and a high viscosity index rating. Castor
oil is used in engines with extremely high bearing pressures such as racing car engines.
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It produces tough stringy deposits after a short period of use and is cleaned out
frequently.
Adhesive Compounds
When hand-oiling methods are used to lubricate machine bearings, materials that reduce
dripping are added to the oils. Latex and several synthetic products are added to oil to
impart this clinging property to oils and greases.
Extreme Pressure Agents
Chlorinated compounds are frequently added to mineral oils. Under these circumstances,
a thin film of metal chloride is produced when the oil film breaks, and this action
prevents scoring or welding.
The amount of extreme pressure agents required to produce this effect is comparatively
small and gear oils generally contain no more than 1 percent while metal-cutting oils
may contain about 0.5 per cent. The oil may contain both sulphur and chlorine as
prepared compounds.
SOLID LUBRICANTS
Solid lubricants are useful in reducing friction where oil films cannot be maintained
because of pressures or temperatures. Because solid lubricants are dry they are useful for
some applications where oils tend to gather dirt and become gummy.
Solid lubricants may be divided into two general classifications. The first group is
mechanical and has no particular affinity for a metal surface. The second classification
has a chemical affinity for most metals although no chemical reaction. All solid
lubricants range from mild polishing agents to mild lapping agents. Neither class
provides adequate protection from rusting, which indicates that the solid film is not
impervious to moisture.
All solid lubricants interpose a layer of material between the moving surfaces. Solid
lubricants should be softer than the materials being lubricated. As an example, emery
and ferric oxide will reduce friction but rapidly score and abrade the metal surfaces.
Solid lubricants are fixed and therefore cannot transmit heat or contaminants from the
bearing as circulating oil can.
Graphite
Graphite is manufactured from coke or anthracite coal. A great deal of graphite for nonlubricating purposes is mined, but mined graphite contains many impurities which are
difficult, if not impossible, to remove completely.
Graphite is normally obtained in flake form. The particles are milled to a very small
size, called colloidal graphite. Colloidal graphite is used in the dry form and mixed with
various oils, greases and solvents which act as vehicles to carry the graphite to the
moving surfaces.
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Talc
Talc is powdered soapstone. Air flotation refines it and permits the larger particles and
impurities to sink out of the air stream. Like most natural products it contains a small
percentage of impurities. A common use is as a mild lapping compound for breaking in
machine parts.
Mica
Mica is a mineral found in nature. The mining and refining processes are much the same
as for talc. Sheet mica is widely used as a dielectric in electrical equipment. In the finely
powdered state it is used for running-in bearings, where it laps out the high spots to
increase the bearing area.
Zinc Oxide
This material is a white metallic oxide of zinc. The very small particle size makes it of
some interest as a solid lubricant. Because of its (light) colour, it has applications where
darker lubricants are not suitable as in textile, food, and chemical processes.
Molybdenum Disulfide
Molybdenum disulfide is a solid chemical lubricant. The molecular structure of an atom
of molybdenum coupled to two atoms of sulphur provides a strong bond to metals that
are active with sulphur. Some of these are iron, silver, and copper. Some researchers
believe that the sulphur-to-sulphur bond that shears easily causes the low coefficient of
friction between molecules. Others believe that the low shear is the result of adsorbed
moisture or other films on the surface of the fine particles of molybdenum sulfide.
To obtain the maximum performance, the metal surfaces are cleaned well before
applying a chemically active solid lubricant. It may be used with a solvent to carry the
solid lubricant to the moving surfaces. Some applications are in instrument lubrication
where lubricants tend to gather dirt and in springs and electrical switch gear. Equipment
that is heavily loaded and used intermittently uses solid lubricants.
Extreme Pressure Lubricants
Full extreme pressure lubricants are sometimes called“hypoid” lubricants. They contain
compounds of sulphur, chlorine or phosphorus. Under high load conditons the high
points of the bearing surfaces break through the polar films of the lubricant and
temperatures are produced which can cause galling. At these temperatures the chemicals
in the full extreme pressure lubricants become active and form coatings of sulphides,
chlorides, or phosphides. These coatings act as a dirt film and prevent any solder from
sticking. At normal operating temperatures, these chemical compounds are inactive and
have little, if any, action on the metal surfaces.
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Oleic Acid
This is an organic acid found in almost all fatty oils. It is used as a mild “extreme
pressure agent” by adding up to 1 percent to a mineral oil. Extreme pressure agents are
used in applications where the conventional lubricants fail to protect the metal surfaces,
for example under the high shear conditions existing in the sliding action of hypoid gear
teeth. These substances are polar.They do not change the surface of the metal chemically
but orient themselves to the metal surface and are extremely difficult to remove.
GREASES
Grease is a semi-solid lubricant produced by the addition of a thickening agent to a
lubricating oil. Greases are divided into four types:
• Water resistant
• Water soluble
• Multi-purpose
• Synthetic
Water Resistant Greases
These greases use a calcium or aluminum base and are for low temperature use. Cooking
tallow or fatty acids with lime and water to form the base or soap makes a calcium (or
lime base) grease.(Rewrote. The soap is then emulsified in oil until a grease of the
required consistency is produced. The proportions of oil and soap in the grease vary
from approximately 95% oil and 5% soap to 75% oil and 25% soap.
Lime-soap greases are not used where the temperature is likely to rise above 70°C
because the essential water content then evaporates and separation of the soap and oil
follows with consequent breakdown of the grease. Similarly, this grease separates into
oil and soap under heavy pressure so that it is not suitable for high-temperature,
heavy-load or high-speed bearings. Its advantages are its insolubility in water and its
soft texture.
Aluminum-soap grease is similar in texture and lubricating qualities to calcium soap
grease, but it is more stable and resists separation. It is limited to use below its melting
point of 93°C because its physical characteristics change drastically above this
temperature and the grease becomes like rubber.
Water Soluble Greases
Sodium-soap (soda-base) greases are made by a process similar to that of the lime-base
greases, however they differ in their characteristics. They have a sponge or fibre-like
texture and possess a high degree of cohesion which makes them suitable for
ball-and-roller bearings. Soda-base greases have a high melting point, about 150° 175°C so they can be used in high temperature locations.
These greases readily form emulsions with water and therefore are not used in situations
where they are in contact with water or steam.
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Multi-Purpose Greases
Lithium and barium soaps, when used as bases, produce greases which have a wide
range of operating temperature limits.
Barium-base grease has a high resistance to water and works well at temperatures up to
200°C. Lithium-base greases have good metal wetting properties and are water
resistant.They can be used with low pour-point oils to produce low temperature greases
which can be used down to -50°C.
Synthetic Greases
These are composed of synthetic fluid lubricants and the same soaps and thickeners that
are used with the conventional mineral greases. They are generally suited to use at
temperature extremes and can be produced in either water soluble or water resistant
types. The synthetic fluids most used are polyalkylene glycols and silicones.
Some silicone grease is manufactured and used (entirely synthetic). This does not melt,
is highly resistant to water and oxidation, and suited to use in the presence of chemical
fumes or other corrosive influences.
Qualities of Lubricants
Lubricants provide the following services with emphasis placed upon one or more of
these according to the needs of the particular application:
• Minimum coefficient of friction
• Maximum adhesion to the surfaces to be lubricated
• Physical stability under variations of temperature and pressure
• Resistance to oxidation and emulsion
• Fluidity at low temperatures
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Page 438
Objective 2
Describe the significance and measurement of
lubricating oil characteristics including viscosity,
relative density, API (American Petroleum Institute)
gravity, pour point, and dielectric strength.
LUBRICATING OIL CHARACTERISTICS
The following are characteristics of lubricating oils:
• Viscosity
• Viscosity index
• Flash and fire points
• Specific gravity (relative density)
• Pour point
• Cloud point
• Neutralization (acid) number
• Dielectric strength
Viscosity
The viscosity of an oil is a measure of the oil’s resistance to shear. Viscosity is
commonly known as resistance to flow. If a lubricating oil is considered as a series of
fluid layers superimposed on each other, the viscosity of the oil is a measure of the
resistance to flow between the individual layers. A high viscosity implies a high
resistance to flow while a low viscosity indicates a low resistance to flow. Viscosity
varies inversely with temperature. Pressure also affects viscosity. Higher pressure causes
the viscosity to increase, and subsequently the load-carrying capacity of the oil also
increases. This property enables the use of thin oils to lubricate heavy machinery. The
load-carrying capacity also increases as the operating speed of the lubricated machinery
is increased.
The Saybolt Universal Viscosimeter is used to determine viscosity. It is a simple
apparatus and gives reliable results for comparative purposes. The principal sections of
the apparatus are outlined in Fig. 3.
The top receptacle is filled with the oil to be tested until it overflows the rim. This is
slightly over 60 cc. The apparatus is in a heat bath held at either 37.8 or 99°C, for
whichever temperature it is desired to obtain the viscosity. Light oils are run at 37.8°C,
and heavy oils at 99°C.
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When the oil has reached the temperature of the bath, the plug is pulled out and the time
in seconds for 60 cc to run into the flask (Fig. 4) is recorded as the viscosity. For
example, if the temperature of the oil was 37.8°C and the time taken to fill the flask was
500 seconds, the oil has a viscosity of 500 at 37.8°C . This measurement is written as
follows:
Viscosity 500 at 37.8°C (S.S.U.) (Saybolt Seconds Universal)
The S.S.U. indicates that the viscosity was run with a Saybolt universal tube for
securing the viscosimeter.
Figure 3
Saybolt Tube
Viscosity readings are taken at 37.8°C for time limits between 40 and 1000 seconds.
Readings below 40 seconds are not sufficiently accurate with this method, and very few
types of lubricating oils have a viscosity of 40 seconds at 37.8°C. This reading is
approximately the viscosity of light fuel oil.
Readings for more viscous oils are taken at 99°C on the S.S.U. For example, if the time
taken to fill the lower receptacle with 60 cc was 150 seconds at a temperature of 99°C, it
is written:
Viscosity 150 at 99°C (S.S.U.)
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Figure 4
Saybolt Flask
Viscosity readings may be taken at any temperature. However, a complete test for the
majority of lubricating oils supplies two readings, one at 37.8°C and the other at 99°C
With two readings, a line on a viscosity-temperature chart joins and extends the two
points and intermediate viscosities are read off for any desired temperature between.
This method of determining viscosity is relatively accurate for most readings between -1
and 150°C.
Viscosity Index
The viscosity index of a lubricating oil indicates its change in viscosity with
temperature. All oils flow more readily with increasing temperature, but the amount of
viscosity change varies with different types of oil.
Oils that change least in viscosity during temperature changes have a high viscosity
index. The maximum figure of 100 is given to a paraffin base oil with viscosity 50
S.S.U. at 99°C and 260 S.S.U. at 37.8°C.
The minimum figure of zero is given to a napthalene based oil with a viscosity of 50
S.S.U. at 99°C and 430 S.S.U. at 37.8°C.
Test figures taken on other oils are checked against these and given a viscosity index
rating by comparison.
In some applications where the operating temperature varies over a wide range, it is
advantageous to add a viscosity index improver to the oil. These are long chain, high
molecular mass polymers derived from petroleum. At low temperatures the viscosity is
that of the oil itself. As the temperature rises, an increasing number of the polymers
come out of solution and prevent the oil from becoming too thin.
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Flash and Fire Points
The flash point of an oil is the temperature to which it must be heated to give off
sufficient vapor to form an inflammable mixture with air. In this test, the vapours flash
upon the application of a lighted burner and then go out for want of more vapour. The
flash point of lubricating oils varies in the range 200° to 260°C.
The fire point is the temperature to which an oil must be heated to burn continuously
when the test burner is applied to the vapour. This is usually about 10 to 25°C above the
flash points.
Specific Gravity (or Relative Density)
The specific gravity of a mineral oil is a numerical value, an index of the mass of the oil
compared with the mass of an equal volume of water. The specific gravity of water is
taken as unity (1.0). Liquids with a reading below 1 are less dense than water, liquids
with a reading above 1 are more dense than water.
The specific gravity of oils is important in the control of refinery operations or where
large volumes of oil are being handled. It is also helpful in identifying oils because the
specific gravity of an oil varies with the type of crude oil from which it was
manufactured.
Gravity A.P.I.
Specific gravity readings are given to several places of decimals, e.g. 0.9765. The
American Petroleum Institute (A.P.I.) devised a scale which is a mathematical function
of the specific gravity. The advantage is that it is easier to visualize the relationships
betwen whole numbers than between the decimal points on the original scale.
The relationship between the two scales is derived as follows:
Gravity A.P.I. =
141.5
− 131.5
Specific Gravity at 15.6D
Pour Point
The pour point of an oil is the lowest temperature at which an oil will flow. The test is
important for lubricating oils that are used in cold surroundings, particularly where they
must flow to the suction side of an oil pump. A commonly used rule of thumb when
selecting oils is to ensure that the pour point is at least 10oC lower than the lowest
anticipated ambient temperature.
The test procedure is simple. The sample is cooled in a test tube until the oil ceases to
pour and then 3°C is added to the temperature. For example if a particular oil ceases to
pour at -12°C the pour point is stated as -9°C. When selecting an oil for use under low
temperature conditions, the viscosity and the pour point are taken into consideration.
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Cloud Point
The cloud point is the temperature at which dissolved solids in the oil, such as paraffin
wax, begin to form and separate from the oil. As the temperature drops, wax crystallizes
and become visible. Certain oils are maintained at temperatures above the cloud point to
prevent clogging of filters.
Neutralization (Acid) Number
The neutralization or acid number is a measure of the amount of potassium hydroxide
required to neutralize the acid in a lubricant. Acids are formed as oils oxidize with age
and service. The acid number for an oil sample is indicative of the age of the oil and can
be used to determine when the oil is changed.
Dielectric Strength
Highly refined mineral oils possess excellent electrical insulating properties. They are
used as cooling media in transformers, oil circuit breakers, and similar apparatus.
Passing an electrical current through the oil until the voltage is sufficient to cross a gap
between two submerged electrodes which are placed about 2.5 mm apart measures the
resistance to break down from electrical discharge. These electrodes are circular and
have a diameter of 25 mm.
The apparatus and temperature conditions are standardized, and the breakdown point of
the oil is recorded in volts. An average grade of transformer oil resists 30 kV under this
test. When mineral oils are used in electrical equipment, they are refined to eliminate all
impurities, and special precautions are taken to remove all trace of moisture. An almost
infinitesimal trace of moisture lowers the dielectric strength. Fig. 5 shows the effect of
moisture in transformer oil.
Figure 5
Effects of Moisture on Dielectric Strength of Oil
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Page 444
Objective 3
Explain the typical causes of lubricating oil
deterioration.
LUBRICATING OIL DETERIORATION
The lubrication system on a modern steam turbine contains thousands of litres of high
grade oil and in itself represents a considerable financial investment. It is essential that
oils are maintained in top condition to protect this investment and of course, to ensure
that the oils can perform their lubricating and cooling duties in the complex machinery
of the turbine and its controls.
Both operators and designers demand the utmost in reliability, continuity of operation,
and economy from steam turbines. In meeting these demands the turbine depends to a
large extent upon the quality of the oil in its lubricating system. Unless this oil
satisfactorily performs its functions, efficient turbine operation cannot be maintained. In
addition to performing certain specific functions, the oil must also be suitable for long,
continuous service. This period is measured in years or, in fact, the lifetime of the
turbine, because complete replacement of the oil charge of a large turbine is an
expensive and lengthy process.
The following are the main causes of deterioration in turbine lubricating oils:
• Oxidation
• Foaming
• Emulsions
• Sludge
Oxidation
When lubricating oils react with oxygen, materials form that impair the qualities of the
oil. Eventually the impurities become insoluble in the oil, form sludge, especially with
water and foreign suspended matter, and promote the formation of deposits. On
continued oxidation, the oil develops organic acids and in severe cases the viscosity
increases significantly.
The reaction between oil and oxygen is accelerated by:
• Increasing the temperature
• Metallic catalysts
• Water
• Foreign suspended matter
• The oxidation products themselves
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An increase of 10°C in the temperature of the oil doubles the rate of oxidation. Thus an
oil which gives satisfactory service life when the bearing outlet temperature is 65°C
might show quite unsatisfactory service life if the temperature to rises to 80°C.
Therefore, operating temperatures are held within the limits the turbine manufacturer
specifies, 55° to 70°C.
Metals that act as catalysts promote oxidation. Copper, brass, bronze and zinc are
particularly effective catalysts and their use is avoided as much as possible. Galvanized
(zinc coated) iron piping or tanks are not recommended. Tinning the surfaces that come
in contact with the oil overcomes the adverse effects of copper.
Moisture may enter the lubricating system through leaks at the sealing glands of steam
turbines or at the oil coolers and through condensation from the atmosphere in the
storage tank. The lubricating oil is inspected periodically for the presence of water and,
if detected, the source is determined and the problem eliminated as soon as possible.
Oxidation inhibitors that the refiner incorporate in turbine oils combat the adverse
effects of oil oxidation. Even under severe operating conditions, very small amounts of
oxygen inhibitors greatly prolong the useful life of the oil.
Foaming
The formation of foam on the surface of the oil in the storage tank indicates the presence
of air in the oil. It is essential that most of the air entrained in the oil as if flows through
the lubrication system is eliminated before the oil is recirculated. Entrapped air reduces
the flow of oil to the bearings and causes erratic operation of the governors. Turbine oils
are manufactured so they free themselves of air very rapidly. In general, low viscosity
oils dissipate entrained air more rapidly than higher viscosity oils.
The following mechanical and operational conditions promote air entrainment:
• Air leakage into the pump suction line
• Low oil level, permitting the pump suction inlet to become exposed to air
• Insufficient venting of the lubricating system
• Excessive splashing from oil return lines to the storage tank
• Oil return lines of insufficient size or capacity
• Discharge velocity from the pressure regulating valve too high causing
unnecessary splashing and spray above the oil level
• Operating the circulating oil pump at excessive capacity
• Wide difference in temperature between fresh oil added and the oil in the system
• Vacuum conditions inside bearings
Mechanical changes and adjustments easily correct all of the above conditions.
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When hydrogen-cooled generators are employed, the ability of the oil to free itself from
entrained gas takes on added importance. The system oil is used to provide an oil film
between the babbitt seal face and the shaft flange to prevent the escape of the hydrogen.
Since the oil is supplied under a pressure greater than the hydrogen pressure, provisions
must be made for the oil flowing through the seal to be returned to a hydrogen
detrainment tank where the oil and hydrogen are separated.
Emulsions
Water is the most prevalent of all the impurities that contaminate turbine lubricating
systems. Steam from leaking shaft seals and condensation of humid air in oil reservoirs
and return pipes are the most frequent sources of water. When water is churned up with
an unoxidized turbine oil, an emulsion is formed that quickly separates out, back into oil
and water.
Although limited oxidation is not in itself detrimental to the service value of a turbine
oil, the products formed as oxidation continues reduce the ability of the oil to separate
from the water in an emulsion and permanent emulsions may be formed. The presence
of dirt and metallic particles tends to accelerate the formation of permanent emulsions
and eventually causes deposits and sludge.
Emulsions impair the lubricating qualities of an oil and in extreme cases rupture of the
oil film causes scoring of bearings or gear teeth.
Sludge
All deposits in turbine oil circulating systems are called sludge. This sludge is a slimy
mass containing emulsions, oxidized hydrocarbons and other impurities. Unlike an
emulsion, sludge does not form suddenly but is only present after the oil has been in use
for some time. Oxidation is the primary cause of oil sludge together with solid
contaminants and emulsions. The useful life of a turbine oil therefore depends upon its
resistance to oxidation.
Sludge is sometimes deposited when too much new oil is added to a system at one time
because the chemical balance of the oil is temporarily disturbed. For this reason it is
considered good practice never to add at one time new oil that is more than ten per cent
of the turbine oil system capacity unless all of the oil is being replaced at one time.
Tests
Taking representative samples of the oil at regular intervals is good practice for
maintaining a systematic check on the oil. Observation of these samples at site gives
indications of major changes in the oil condition, and routine testing carried out in the
oil suppliers’ laboratories ensure an exact record.
The tests usually carried out on turbine oil samples include the viscosity, the colour, the
neutralization value, the water content and tests for any extraneous impurities. No single
test determinea the serviceability of the oil entirely nor, in fact, does one set of results.
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Regular testing and recording however, will show whatever trends are developing and
will give indications of conditions within the turbine and the future serviceability of the
oil.
Generally speaking, the two most important indications of the oil condition are its
appearance and its neutralization value.
Visual inspection of the oil sample will disclose whether water is getting into the oiling
system or whether contamination by solid impurities is occurring. The sample should be
allowed to stand for 24 hours in order to precipitate out any solid impurities. It should
then present a clear, bright appearance to show freedom from water content, sludge and
metallic impurities.
The neutralization value is the result of a test designed to ascertain the degree of acidity
of the oil due to soluble (and therefore invisible) products of oxidation.
The sample of oil is treated with potassium hydroxide (KOH); the number of milligrams
required to produce a neutral mixture per gram is known as the neutralization value of
that oil.
As long as the oxidation inhibitors in a turbine oil are effective the neutralization value
will not normally increase. It may be possible to have foreign acidic contaminants enter
the oil and raise the neutralization value even though the oxidation inhibitor is still
effective.
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Objective 4
Describe the types of lubrication additives.
LUBRICANT ADDITIVES
Lubricant (oil or grease) additives are chemical compounds which either enhance some
of the properties the product has or impart new characteristics.
They are divided into two classes:
• Those which affect the physical characteristics of the oil such as viscosity index,
pour point and foaming
• Those which affect the performance characteristics, which include oxidation and
corrosion inhibitors, detergents and dispersants
Oxidation-Corrosion Inhibitors
Since both oxidation and corrosion inhibitors are closely associated with oil oxidation,
and some additives are effective for both purposes, they are grouped under the same
heading. The oxidation inhibitor is used to prevent varnish and sludge formation on
metal parts. The corrosion inhibitor is used to prevent corrosive attack on metal surfaces.
The inhibitors are composed of organic compounds containing sulphur, phosphorus or
nitrogen. They decrease the amount of oxygen the oil takes up and reduce the formation
of acidic bodies. In some cases, the additive itself may be oxidized in preference to the
oil. Inhibitorsenable a protective film to form on the bearings and other metal parts.
Detergent-Dispersant Additives
Detergent-dipersant additives are used in crankcase oils is to keep the engine clean. The
detergent keeps oxidation products soluble in the oil to keep metal surfaces clean and
prevent deposit formation of all types. The dispersant breaks down insolubles into a
finely divided state so that they remain suspended in colloidal form in the oil. These
additives are metallo-organic compounds such as phosphates and sulphonates, or high
molecular weight soaps.
Rust Preventatives
Rust preventatives prevent rusting of metal parts during shutdown periods or protect
equipment during storage or shipment.
Rust preventatives consist of sulphonates, amines, or the derivatives of some fatty acids.
They absorb certain active materials on a metal surface, neutralize corrosive acids and
form a protective film that repels water.
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Pour- Point Depressants
Pour-point depressants lower the pour point of the lubricating oil. If oil is cooled, it
finally reaches a temperature at which it no longer flows. The wax content crystallizes
and forms a semi-solid sponge structure which holds the oil. The additive forms a film
on the wax crystals and prevents them from adhering to each other and allows the oil to
flow at much lower temperatures.
Viscosity Index Improvers
Viscosity index improvers are effective over a wide temperature range. They lower
lower the rate of change of the viscosity of the oil with change of temperature. They are
called long chain, high molecular weight, polymers of alkyl and methacrylate
compounds. They are generally considerably more viscous than the lubricating oils in
which they are used and are held in colloidal suspension in the oil. At low temperatures,
the viscosity is that of the oil itself. At high temperatures, it is thought that more and
more of the suspended additive polymers go into solution and keep the oil viscosity up.
Foam Inhibitors
Entrainment of air bubbles forms foam in a lubricating oil. This occurs when an oil is
violently agitated in the presence of air. High viscosity oils have a stronger tendency to
do this than the lighter oils. The additives used are silicone polymers and they reduce the
surface tension between air bubbles so that the bubbles combine to form larger bubbles
which can rise to the surface of the oil and escape.
Anti-Wear Agents
At times of extreme high pressure or high temperature, chemical action causes anti-wear
agents to form a film on metal surfaces to reduce the surface friction and prevent scoring
or seizure. They also reduce or minimize wear.
Anti-wear agents are organic compounds containing chlorine, phosphorus and sulphur.
As long as good film lubrication conditions exist in a bearing, there is no metal-to-metal
contact. If the oil film is destroyed due to excess pressure or high temperature, the
condition becomes one of boundary lubrication. At these times, the anti-wear additives
reduce the resulting friction.
Emulsion Breakers
A third agent, which may be oxidized oil, iron rust, metallic soaps, or contamination
with grease or other foreign substances causes an emulsion of oil and water to form.
Heating to 75° to 100°C and then allowing it to settle in a tank or employing a
centrifuge breaks down the average emulsion. Some emulsions cannot be broken using
this method and chemical compounds have to be used to free the water from the oil.
Each solution requires a specific emulsion breaker. The chemical compounds employed
to break emulsions are soluble in water. Therefore very little remains in the oil after it is
separated from the water. The amount added is usually not more than 0.1 percent of the
total volume. In fact, if too much emulsion breaker is added, the result can be a still
more stubborn emulsion.
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Objective 5
Describe a typical power plant lubrication program,
including a lubrication survey.
POWER PLANT LUBRICATION PROGRAM
One of the most important factors upon which the availability of the machinery in an
industrial plant depends is good lubrication. Considerable damage can occur if the
correct care and attention is not paid to lubrication systems and the lubricants used.
The conditions under which the lubricant operates are severe. It must perform over a
wide temperature range and handle heavy loads and fast speeds. The types of metals and
alloys used in the construction of parts also affect the lubrication.
A lubricant is expected to act as a heat transfer medium, protect against rust and
corrosion, and act as a sealing medium. To meet these demands, lubricant suppliers offer
a wide range of products are tailor-made for specific applications or conditions.
Most lubricant suppliers provide their customers with a lubrication engineering service.
They will:
• Give advice on the lubricant to use for each situation in a plant, thus reducing the
total number of lubricants used
• Advise on maintenance problems
• Carry out periodic tests on special installations such as turbine oils, in their own
laboratories
It is advantageous to plan the entire plant lubrication as one combined operation.
Savings will be effected through the:
• Reduction in the number and variety of lubricants used
• Reduction in maintenance costs and plant-outage time
• Increased life of equipment due to proper lubrication
Lubrication Survey
To begin the process, machines requiring lubrication must be listed in an organized
fashion. This is called a “Lubrication Survey.” A typical lubrication survey include:
• Machine Information
• Lubricant Information
• Lubricant Evaluation and Acceptance
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Machine Information
The first task is to develop documentation of the type of machine(s) to be lubricated.
This includes make, model, identification (name/number) and a form of designation
outlining the severity of service, such as, is it continuously operated at temperatures
above “X” or in a wet or dusty environment. Once this is done, the lubricant type and
grade that is used in the machine is compared with information to the manufacturer’s
recommended lubricant for the machine/service combination.
Any differences in the lubricant used compared to the recommended lubricant are
justified. In practice, never assume that the equipment manual is always correct. When
justifying any differences, discussing them with the engineering group at the Original
Equipment Manufacturer (OEM) may help.
Often recommendations found in manuals or sales literature for machine lubricant
combinations are outdated and/or the recommended lubricant has changed without the
change being noted. The volume of lubricant used in the machine and the frequency of
relubrication are addressed during this phase. This information is helpful later when
purchasing and schedules are set and used oil analysis results need to be interpreted.
Lubricant Information
Each manufacturer has a recommended lubricant for their equipment and is stated in
their operating manuals. A competent lubrication specialist can crossmatch a given
lubricant with another manufacturers lubricant of equal quality. Therefore, it is usual to
have a variety of oils and greases that cover the general needs of the plant. There may be
isolated equipment requirements for speciality lubricants that do not have a cross
reference.
Lubricant Evaluation and Acceptance
Potential problems with the lubricants used and the impact that off-specification
lubricants have on operations both need to be defined. Evaluation methods and
acceptance criteria vary depending on the potential problems and the risk associated
with off-specification lubricants. The type of lubricant, age, packaging and methods of
distribution all have an impact on what yan operator might expect to see if there is a
problem.
When selecting analysis, the first determination to be considered is what level of
accuracy is required in the analysis. There are two different types of analysis available:
• American Society of Testing and Materials (ASTM) test methods
• Tests developed in-house
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Objective 6
Explain the different types of lubricating/governing/seal
oil systems.
AIR COMPRESSORS LUBRICATING SYSTEMS
The multi-stage, twin compressor (Fig. 6) with intercoolers in position shows a pressure
system of lubrication. The oil reservoir is located in the sump. A gear pump (not shown)
draws oil from the reservoir and delivers it under pressure to the crankshaft bearings.
This oil is also supplied to “drilled” connecting rods where the oil channel is inside the
rods and the oil is fed directly from the crankpin supply to the crosshead bearings. Oil
weeping out of the bearings lubricates all other parts within the crankcase oil under
pressure does not lubricate. Surplus oil returns to the reservoir for recirculation. Positive
feed oilers separately lubricate air cylinders.
Figure 6
Multi-Stage Compressor
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Gas Turbines
Fig. 7 shows a typical lube oil system for an aeroderivative gas turbine used for power
generation. It lubricates the bearings of both turbine sections – the compressor turbine
and the power turbine. A separate system handles the lubrication of the load (driven)
equipment. This oil system is divided into two sections: a supply system and a scavenge
system. The scavenge system returns the oil from the bearings to the supply and treating
equipment. All piping, fittings and reservoir are Type 304 Stainless Steel to prevent
corrosion. The system uses synthetic oil suitable for high temperatures.
The oil reservoir contains approximately 500 litres in a 568 litre tank. Protection devices
are fitted against low oil level and low oil temperature. A thermostatically controlled
heater is included and, to facilitate starting, ensures a minimum temperature is
maintained while the unit is not operating.
An auxiliary gearbox on the engine drives a positive displacement pump that provides
the required pressure to the bearings. After the pump, a duplex, full flow filter that
allows filter changeout while operating filters the oil. High oil temperature, low oil
pressure and high filter differential pressure switches protect the oil supply.
The oil flows through the bearings and accumulates in the bearing sumps. The oil
temperature is measured at each scavenge line in case of bearing problems.
Chip detectors are often located in the sumps to detect metal particles from the bearings.
If a bearing is damaged, metal particles are entrained in the oil. The chip detector is a
magnet that attracts these metallic particles and detects when they accumulate on the
magnet. Upon alarm, the detector is removed and inspected to diagnose the type and
extent of bearing damage.
The auxiliary gearbox of the turbine drives the scavenge pump that provides the
pressure for the oil to flow through another set of filters and then through duplex, watercooled coolers that are thermostatically controlled. The oil then flows back to the
reservoir.
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Figure 7
Typical Lube Oil System
(General Electric)
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Steam Turbines
Fig. 8 is a schematic diagram of a typical lubricating oil system for a turbine generator.
The oil tank has a capacity of 4542 to 9084 litres or more depending on the size of the
unit. The oil pumps take suction from the oil tank through strainers and discharge the
oil at high pressure, 552 to 827 kPa. From here, the oil flows in two different directions:
• To the power oil and governor relay oil systems
• To the oil coolers and then to the turbine generator bearings
Using hydraulic pressure, the power oil, acting in servomotors, opens the emergency
stop valves and governing valve. Governor relay oil acts as a speed and load sensitive
regulating medium. The power oil and the governor relay oil have to be at high
pressure.
Oil, used for lubrication, is at a lower pressure, in the 69 kPa to 138 kPa range.
Therefore, before the oil passes to the coolers, it flows through a pressure-reducing
valve. If the turbine has been operating for a length of time, the oil from the oil tank is
quite warm. Therefore, the oil needs cooling, in the oil coolers, before it flows through
the bearings. Typical outlet temperatures from the coolers are in the 43° – 49°C range.
Inside the bearings, the oil acts as a lubricant between moving surfaces and also acts as a
coolant for the bearings. From the bearings, the oil drains into a return header which
leads back into the oil tank. A thermometer is placed in each return line from the
bearings to indicate bearing oil temperature.
Figure 8
Turbine Lubricating Oil System
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Fig. 9 shows details of the high and low pressure sides of the oiling system for a steam
turbine and generator with hydrogen seals.
Figure 9
Lubrication and Seal Oil System
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Objective 7
Describe the components and operation of a typical
lubricating oil purification system.
OIL PURIFICATION EQUIPMENT
The various methods of lubricating oil purification in commercial use are as follows:
• Settling tanks
• Centrifuges
• Strainers
• Absorbent filters
• Adsorbent filters
• Distillation
• Coagulation
Settling Tanks
Settling is the simplest of all purifying methods but only is used where the oil can be
withdrawn from service.
Fig. 10 shows a pair of settling tanks. The warm oil drained from the machine should be
run into a clean empty tank having a conical sloping bottom and allowed to stand for a
period of about 10 days. Efficient separation of the impurities occurs at an oil
temperature of about 50° to 60°C and steam coils or other heating elements are provided
to attain this oil temperature.
The heated oil is allowed to stand without agitation to permit water and other impurities
to settle out. Some impurities which are soluble at operating temperatures become
insoluble at room temperatures, and they are precipitated as the oil cools.
The withdrawal of the clarified oil following the settling is handled with great care to
avoid agitation of the impurities which have settled on the sloping sides of the tank.
Centrifuging can reclaim the good oil remaining in the sludge after the clarified oil has
been drawn off. The tanks, shown in Fig. 10, have a float suction for the clean oil outlet
to help avoid forming a vortex which agitates the solid impurities.
Gravity separation is used in systems with large volumes of oil and where water
contamination is extensive.
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Figure 10
Settling Tanks
CENTRIFUGES
In the centrifuge, the liquid is rotated at high speeds up to 15 000 rev/min. The
development of centrifugal force facilitates the separation of the contaminants that are
heavier than oil. Sedimentation and separation are continuous and very fast. When
liquid and solid particles in a liquid mixture are subjected to the centrifugal force in a
separator bowl, it takes only a few seconds to achieve what takes many hours in a tank
under the influence of gravity.
The centrifugal bowl (Fig. 11) is equipped with a series of conical discs which divide
the feed material into layers less than 1.3 mm in thickness. The oil, water and solids are
fed into the top inlet A. The mixed feed material travels down the inlet tube (B) into the
centrifuge bowl.
The feed material is forced upward through the holes in the intermediate discs (C) and
into the spaces between them. This is where the centrifugal action immediately
separates the feed material into the heavy and light phases (oil, water, and solids). The
solids are thrown directly to the bowl wall (D). The oil, with its lighter density, is
displaced inward and travels upward through the space around the inlet tube to the light
phase discharge (E). The incoming feed material displaces the water phase, which
centrifugal force has thrown outward, and travels upward along the outer edge of the
bowl to the heavy phase discharge (F). Solids may be retained in the bowl or discharged
immediately depending on bowl design and operating requirements.
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Figure 11
Centrifugal Separation
Strainers
Strainers may be wire mesh, metal discs, cloth towels, or blotting paper. Strainers do not
remove water or other liquid impurities. They remove only the larger solid particles in
used oil. Strainers are often used in conjunction with other methods of oil purification.
The oil filter, illustrated in Fig. 12, is a combination of settling and straining. The oil
first passes through a wire mesh strainer and then to precipitation trays, where water is
allowed to settle. After leaving the precipitation compartment the oil passes through
cloth bags held on wire frames where solid impurities are strained out.
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Figure 12
Combined Settling Tank and Strainer
Absorbent Filters
In-line absorbent filters consist of sponge, wood fiber, cotton waste, or similar materials.
When these filters become saturated with impurities, the filter cartridge is cleaned or
replaced with a new one. This type of filter should be as large as possible.
Strainers and absorbent filters are always equipped with a relief valve or overflow which
permits the oil to be bypassed when the filter becomes clogged.
Adsorbent Filters
Adsorbent filters employ materials which do not absorb impurities as a sponge absorbs
water. In this type of purifier, clays, such as fuller’s earth and diatomaceous earth, are
used as the filtering medium.
Adsorbent filters are highly effective in removing the very finest impurities. A small
quantity of fuller’s earth presents a vast area of contact surfaces to which impurities can
adhere. With this type of filter, the smallest impurities may be removed from used oil.
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Clay filtration cannot be employed effectively on oils that contain compounds or
additives as the surface of the clay particles will become plugged and inoperative in a
comparatively short period of time.
Distillation
Distillation is employed in combination with purifiers to remove the fuel dilution from
used crankcase oils. The oil, heated to about 150ºC, does not remove all the dilution,
particularly the heavy ends of No. 2 fuel oil, but an appreciable percentage is driven off.
Adding a small percentage of new oil that is one grade heavier may overcome some of
the effect of the undistilled poriton. As a general rule this procedure is necessary only
when dilution is excessive.
Coagulation
Coagulation of impurities and acidic compounds using chemicals is an effective method
for treating used oils from internal combustion engine crankcases. With the addition of
chemicals such as soda ash, trisodium phosphate, or sodium silicate in solution with
water, the impurities are coagulated. Settling, filtering, or centrifuging subsequently
remove them.
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Objective 8
Describe the various applications of ball-and-roller
bearings and their lubrication, including bearing seals.
LUBRICATION PRINCIPLES
Friction between two surfaces is the resistance to motion (or attempted motion). For
example, two flat pieces of metal rest upon each other as in Fig. 13. It appears that the
smoothly-ground surfaces offer little or no resistance to the movement of one over the
other. However, when these surfaces are viewed under a microscope, they are found to
have innumerable irregularities similar to the hills and valleys shown in Fig. 14 (a). The
interlocking of these irregularities produces a definite resistance to motion.
Figure 13
Smooth Metallic Surfaces
The force necessary to start movement is large compared with that required for
continued motion because inertia prevents the moving surface from dropping down
again into an interlocking position. Momentum carries the hills of the moving plate over
the corresponding hills on the stationary plate. This is the condition that exists in a
non-lubricated bearing. The result is the destruction of the rubbing surfaces.
The primary purpose of a lubricant in all types of bearings is to separate the metallic
surfaces, Fig. 14 (b), and reduce friction, power losses and wear. The media used to
separate bearing surfaces may be liquid, plastic solid or solid, depending upon operating
conditions and economic suitability for the purpose. The balls or rollers of
ball-and-roller bearings are considered as solid lubricants because they separate moving
and stationary surfaces. Pure rolling in this type of bearing is only theoretical because a
certain amount of slippage and friction occurs in practice.
Highly-finished ground metallic surfaces appear to be perfectly smooth and incapable of
offering resistance to motion if one is pushed over the other.
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Figure 14
(a) Magnification of Smooth Surfaces
(b) Application of a Suitable Lubricant
FULL FLUID FILM OR FLOOD LUBRICATION
Liquid and plastic solid lubricants are used to separate the moving and stationary parts
of bearings with a lubricating film that prevents metallic contact. When this film is thick
enough to completely separate the moving surfaces, the condition is called full fluid
film or flood lubrication. Complete separation of the surfaces in a bearing with
lubricating oil film implies a film of lubricant so thick that the high spots on these
surfaces do not touch. This condition only occurs when the clearance space is flooded
with oil and there is motion.
Without motion, the oil film breaks down and is squeezed out of the bearing-pressure
area leaving the surfaces only oil wet. This does occur as a bearing comes to rest. When
operating from rest, the oil wet surfaces facilitate the initial movement, and the moving
part carries with it sufficient oil from the adjacent supply to rebuild the film on which it
may ride.
BALL AND ROLLER BEARINGS
The word bearing is used to describe any form of supporting or constraining apparatus
defining relative motion between the supporting or constraining agent and the supported
or constrained member. Bearings are subdivided into three groups:
• Radial Bearings
• Guide Bearings
• Thrust Bearings
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Radial Bearings
Radial bearing is the term given to all applications where a circular member is
constrained so that it can only rotate about its own axis. The formation of a full fluid
film in a radial bearing is shown diagrammatically in Figs. 15 to 19.
In Fig. 15, clearance between a shaft and its bearing is depicted in exaggerated form.
The shaft is shown at rest and a small quantity of oil remains in the pressure area from
previous operation. Downward force of the idle shaft has squeezed the fluid film out of
the pressure area leaving the surfaces in an oil wet condition. This is the condition
before the shaft revolves.
The idle shaft is resting upon the microscopic high spots in the bearing. In other words
the load on the bearing is not uniformly distributed over the entire projected pressure
area but is concentrated on both the shaft and the bearing. The effect is to intensify the
loading on the reduced area carrying the shaft.
Figure 15
Shaft at Rest
In Fig. 16, the shaft has started to rotate and oil is being fed into the bearing at the top
where the clearance between the shaft and the bearing is greatest. If the oil supply is
adequate and the oil itself sufficiently fluid, this clearance space is immediately filled.
Leakage of oil from the ends of the bearing depends upon the pressure exerted on the oil
in the clearance space, the length of the bearing and the resistance which the oil itself
offers to easy flow.
Due to the interlocking of the surface irregularities, the frictional resistance upon
starting is very high and the shaft momentarily climbs up the side of the bearing. During
this climb, the mass of the shaft is transferred from the lowest point in the bearing to a
new area wet with oil. The area of the shaft now resting on the bearing is also
thoroughly oil wetted.
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Continued rotation of the shaft produces a condition where the shaft no longer
sufficiently grips the bearing. Instantly, the shaft ceases to climb and begins to slide over
the bearing surface with reduced friction and torque. As the speed increases, the oil
adhering to the shaft surface is continually drawn into the clearance space and develops
a hydraulic pressure in the wedge of oil.
The intensity of this pressure depends upon the speed of the shaft, the adhesiveness of
the oil, and the surface finish of the shaft. The finish of the shaft is important because
the pumping action which gives rise to the hydraulic pressure is dependent upon the
adhesion of the oil in the microscopic irregularities in the shaft surface. The point of
greatest pressure is at the tip or thinnest portion of the wedge.
Figure 16
Shaft Beginning to Rotate
As the pressure in the wedge increases, the oil seeks every possible avenue of escape.
The ends of the bearing afford an opportunity for leakage. However, if the oil used has
adequate resistance to flow, end leakage is minimized and the hydraulic pressure in the
wedge increases. Eventually the shaft is lifted from the bearing and provides a ready
escape route for the oil under the revolving shaft. Under these conditions the shaft slips
back to its original central position, Fig. 17, and rides upon an oil film of measurable
thickness. The interlocking microscopic hills and valleys of the contacting surfaces
restrict its movement and the torque required to turn the shaft is substantially reduced.
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Figure 17
Shaft Increasing Speed
At full speed, the hydraulic pressure in the oil wedge is sufficient to move the shaft over
to the other side of bearing as shown in Fig. 18.
Figure 18
Shaft at Full Speed
During operation, the film of oil continues to separate the metallic surfaces and floats
the rapidly revolving shaft. The only friction encountered is the fluid friction the rapid
shear of the many thin layers of oil cause as they slide over one another. The outer
layers adhere to the microscopic projections on the bearing and the inner layers adhere
to the microscopic projections on the shaft.
As the shaft rotates and these hypothetical layers of oil move over one another, the
intensity of shear is greatest in the middle layers. Therefore, the heat the shearing
generates is also greatest in the middle layers. The oil layers immediately adjacent to the
metal parts, being cooler than the internal layers, are more viscous and therefore cling to
the metal parts forming a protective coating.
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Fig. 19 shows the pressure distribution in an oil film in a radial bearing. The length of
each line (measured radially) is proportional to the pressure at that point. Maximum
pressure is reached at a point after bottom dead centre and as soon as the maximum oil
pressure area is passed, there is a sharp decrease in pressure. At point A, there is actually
a suction effect instead of a pressure.
Figure 19
Oil Pressure Distribution in a Radial Bearing
These hydraulic pressures are taken into account when constructing bearings, and
particularly when positioning oil feeds, and cutting oil grooves in a radial bearing.
To achieve full fluid-film lubrication the following conditions are fulfilled:
• The lubricant is capable of “wetting” the journal and bearing so that the oil
adheres to the revolving journal and be drawn into the pressure area.
• The bearing and journal are free to assume a slight angle to permit the formation
of a converging oil film. It is not possible to obtain fluid-film lubrication
between two parallel flat surfaces because an oil wedge cannot be built up.
• The clearance space between the bearing and the journal is kept full of oil.
• The lubricant is applied in the low-pressure area of the bearing.
• The viscosity of the oil is sufficiently high to permit the formation of a
load-supporting oil film under the prevailing conditions of load and speed.
• There is a minimum rubbing speed (Any other word we can use?) below which a
full fluid oil film cannot be provided. This condition accounts for most of the
wear in the bearings that stop and start frequently.
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Guide Bearings
Guide bearings guide moving members along a predetermined path. A cylinder is a
guide bearing for the piston reciprocating within it.
Thrust Bearings
A thrust bearing prevents unwanted axial movement and keeps the shaft in its correct
location. The load which a thrust bearing carries to achieve this varies from a few
kilograms in the case of a small electric motor to several tonnes for a reaction turbine
rotor.
Various types of thrust bearings are used:
• Ball
• Collar
• Tilting Pad
Ball Thrust Bearing
Fig. 20 shows a typical ball thrust bearing. The ball raceways are ground into the face of
the rings and the bearing is intended for thrust loads only. A separate radial bearing
absorbs any radial load.
Figure 20
Ball Thrust Bearing
Collar Thrust Bearing
Fig. 21 shows a simple collar thrust bearing. The shaft has three collars and each of
these bears against the surface of a bearing block. Boundary lubrication is also present
in simple collar type thrust bearings. The oil is introduced, as shown in Fig. 21(a),
between the collars so that centrifugal force throws it outward across the thrust surfaces.
Fig. 21(b) shows an incorrect method of introducing lubrication to the collar thrust. The
lubricant is not introduced at the circumference of the rotating collars. Centrifugal force
prevents the oil from reaching those areas which take the thrust.
The faces of the collars and their bearings are flat and parallel. Therefore, this type of
thrust bearing is limited in the load it can carry because there is no oil wedge action
produced.
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(a)
(b)
Figure 21
Simple Collar Thrust Bearing
Tilting Pad
A more suitable design of thrust bearing has the bearing surfaces in the form of pads.
These pads are free to tilt and allow the formation of an oil wedge to separate the
bearing pad from the shaft collar.
The Michell thrust bearing, Fig. 22(a), and the similar Kingsbury thrust Fig. 22(b), are
single collar bearings that have specially designed thrust pads that are pivoted to allow
the formation of an oil wedge between the faces of thrust pad and shaft collar.
Figure 22
Tilting Pad Thrust Bearings
Bearing Seals
Bearing seals are installed on the shaft where it enters the bearing housing. This is to:
• Prevent foreign matter, such as dust, grit and water, from entering the bearing
housing and contaminating the lubricant
• Prevent the lubricant from leaving the housing
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These seals (Fig. 23) are felt, synthetic rubber, or leather rings, enclosed in their own
steel casing. They are sometimes fitted with a light spring to force the seal against the
shaft.
Figure 23
Shaft Seals
Fig. 24 shows a seal mounted in the housing of a ball bearing, which can be either oil or
grease lubricated.
Figure 24
Ball Bearing with Seal
Hydrodynamic Theory
The previous description and diagrams follow the hydrodynamic theory of lubrication
involving a fluid film completely separating the opposing surface. The following
diagrams give a graphic analysis of this action.
Fig. 25(a) and (b) show a surface X moving at constant velocity across a stationary
surface Y with an oil film between the two. In Fig. 25 (a), the X and Y surfaces are
parallel, in Fig. 25(b) the X surface is at a slight angle. In each case, the triangle abc
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represents the quantity of oil entering between the surfaces and the triangle a’b’c’ the
quantity of oil leaving.
In Fig. 25 (a) bc = b’c’, the triangles are equal, and the quantity of oil entering the
bearing equals the quantity leaving. There is no upward force acting to separate the
surfaces X and Y. In Fig. 25 (b), bc is greater than b’c’ and ac is greater than a’c’.
Therefore triangle abc is greater than a’b’c’. More oil can enter than is able to leave and
a vertical force results which tends to separate X from Y.
In both Fig. 25 (a) and 25 (b), there is a horizontal force shearing the oil but only in (b)
is there a resultant vertical force. This principle explains why moving surfaces are
designed to provide a wedge if full fluid-film lubrication is to be achieved and
machinery is to carry high loads without wear.
Figure 25
Hydrodynamic Theory
BOUNDARY LUBRICATION
Under some conditions, it is impossible to maintain a complete fluid film over the
rubbing surfaces and a film of only microscopic thickness is present. The surfaces are
only wetted, and consequently the hills of each surface may make contact and set up
friction and wear. When conditions of bearing design, speed, load, and method of
application of the lubricant are not favourable to the formation of an oil film, the state of
lubrication is called the boundary lubrication. In this case, there may be intermittent
contact between the bearing and journal, and the laws of fluid-film lubrication are not
applicable. The lubricant merely serves to make the opposing surfaces more slippery and
to fill in surface imperfections.
For slow speeds and heavy loads, “oiliness” or film strength of the lubricant, is an
important factor. These conditions of operation indicate that a grease or a solid lubricant
should be used. Because the greases are polar compounds, they provide greater wetting
ability than conventional oils. Solid lubricants are used only under special conditions.
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Oil Grooves in Bearings
Grooves are frequently used in the top half of the bearing or non-pressure area for
distributing the lubricant evenly ahead of the pressure area. Grooves in the actual
pressure area are considered harmful because they tend to disrupt the oil film and reduce
the size of this area.
The ability of an oil film to lift and support a heavy load is dependent upon hydraulic
pressure. The pumping action of the rotating journal brings this pressure about, and any
grooves in the pressure area that permit oil to escape tend to encourage metallic contact.
When bearings are composed of two or more parts fitted together, any sharp corners at
the joints tend to scrape the oil from the journal. Consequently, all corners and edges are
chamfered or rounded to prevent this scraping action.
Figs. 26 and 27 show the type of groove necessary for a typical bearing. A single groove
in the upper part of a one-piece bearing (Fig. 26) is normally sufficient to secure
adequate oil distribution over the entire bearing area.
Figure 26
Groove in One-piece Bearing
Simple chamfers in a two piece bearing (Fig. 27) serve a two fold purpose. They prevent
the sharp edges of the bearing base and cap scraping lubricant from the shaft. Chamfers
also act as reservoirs which afford distribution along the bearing length. When
chamfering a bearing, it is important to cut away any shims which might be present to
prevent them from scraping the shaft.
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Figure 27
Oil Distribution in a Two Piece Bearing
In heavy-duty slow-speed bearings it may be desirable to cut an auxiliary oil groove
(Fig. 28) in the lower half of the bearing. This is just ahead of the maximum pressure
area to ensure an adequate supply of oil along the entire bearing length in that area.
Figure 28
Auxiliary Oil Groove
Fig. 29 illustrates the type of grooving that is detrimental in the pressure area of a
bearing. This type of grooving serves to cut down the actual bearing area and allows the
oil under pressure to escape.
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Figure 29
Example of Incorrect Grooving
Another detrimental effect of grooves in the pressure area is that, as the bearing wears,
the chamfer is reduced to a sharp edge, which acts as a scraper and increases the rate of
wear. Fig. 30 shows the effect of such grooves on the distribution of oil pressure.
Figure 30
Effect of Incorrect Grooving
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Page 478
Chapter Questions
1. With the aid of a simple sketch, describe how the various cuts of oils are separated in
a fractionating tower.
2. Briefly describe the following:
a) Viscosity
b) Pour point
c) Cloud point
d) Flash point
3. a) Explain what occurs when lubricating oils react with oxygen.
b) Briefly describe various causes for this reaction to be accelerated.
4. Give a brief explanation of the following lubrication additives.
a) Detergent-dispersent
b) Anti-wear agents
c) Foam inhibitors
d) Rust prevention
5. What are the advantages to planning the entire plant lubrication program as one
combined operation?
6. With the aid of a simple sketch, explain the operation of a lube oil centrifuge.
7. With the aid of a sketch, explain the hydrodynamic theory of lubrication.
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Page 480
Piping
Learning Outcome
When you complete this learning material, you will be able to:
Explain piping system design, inspection, and maintenance.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Explain selection criteria for piping materials.
2. Calculate the required thickness and maximum allowable working pressure of
piping.
3. Describe typical inspection procedures for piping installations and repairs.
4. Describe a typical routine inspection procedure and schedule for high-energy
piping.
5. Explain the effects of high temperature on piping strength.
6. Describe the design and installation criteria for a piping system layout.
7. Explain the theory and effects of water hammer.
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Page 482
Objective 1
Explain selection criteria for piping materials.
PIPING MATERIALS SELECTION
The selection of materials for piping applications is a process that requires consideration
of material characteristics appropriate for the required service. Materials are suitable for
the flow medium and the given operating conditions of temperature and pressure safety
during the intended design life of the product. Mechanical strength must be factored in
for long term service and the resistance to operational variables such as thermal or
mechanical cycling.
Extremes in the process temperatures influence the material capabilities ranging from:
• Brittle fracture toughness at low temperatures
• Creep strength at the higher operating temperatures
The operating environment surrounding the pipe or piping components must be factored
into the design. Corrosion and erosion can cause degradation of the properties of the
material. The products that are contained in the piping are also an important factor.
The following properties contribute to the attractiveness and economy of a given pipe
material:
• Ability to be bent or formed
• Suitability for welding or other methods of joining
• Ease of heat treatment
• Uniformity and stability of the resultant microstructure
The piping used must be of the correct size in order to provide the required flow and
must have sufficient strength to withstand the pressure and temperature of the fluid
being transferred. In addition to this, the piping system must include provision for
expansion and contraction, proper support, insulation and drainage.
The design, manufacture, testing and installation of power piping systems for steam
plants is covered in the ASME Code B 31.1 “Power Piping” and in the ASME Code
Section I “Power Boilers.”
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PIPING MATERIALS
Steels are the most frequently used materials for power piping systems. The general
classifications or steels are:
• Low carbon steels
• Alloy steels
• Austenitic stainless steels
Table 1A in the ASME Code Section II, Part D, lists the allowable stress values for
these materials for various temperatures up to 815°C.
Low Carbon Steel
Low carbon steel is the lowest priced steel and it is used extensively for steam, water,
fuel oil and compressed air piping for temperatures below 400°C. Above 400°C, it is not
recommended as graphitization may occur within the pipe material at these elevated
temperatures. Graphitization is the breaking down of steel into iron and carbon graphite.
Failure of the material occurs along lines where there is a concentration of graphite.
Pipe made from low carbon steel is seamless electric resistance welded or butt welded.
Specification numbers of some examples of low carbon steel pipe, as listed in Table 1A,
are: SA-53B, SA-106B and SA-135A.
Alloy Steels
Alloy steels, such as the chrome-molybdenum types, are used for temperatures above
400°C. An application would be for use in the central boiler station steam piping at
540°C or more. Superheaters are normally made from chrome molybdenum tubes and
headers. The uses of some types, such as 1 chromium ½ molybdenum or 1¼ chromium
½ molybdenum where graphitization can be a problem, are limited to 525°C. 2¼
chromium 1 molybdenum (or higher % chrome alloys up to 9Cr-1Mo) is usually used
above 460°C.
Alloy steel pipe may be seamless or welded and some examples, as listed in Table 1A,
are: SA-213T12, SA-335P11 and SA-423-2.
Austenitic Stainless Steels
Austenitic stainless steels are a special class of high alloy steels which range from 18%
chrome - 8 % nickel to 25% chrome - 12% nickel. They are also alloyed with chromium,
molybdenum and sometimes with copper, titanium, niobium and nitrogen. Alloying with
nitrogen raises the yield strength of the steels.
They are highly resistant to corrosion and maintain high strength at high temperatures.
This piping is available as seamless or welded pipe and tubing. Applications are high
temperature loop tubes in once-through boilers.
Page 484
Some specification numbers as listed in Table 1A of ASME Section II Material
Specifications (also Table PG-23.1 of the ASME Section I Code Extract) are:
• SA-268TP405 – seamless tube,
• SA-268TP430 – welded pipe,
• SA-430FP304 – seamless pipe
Other Materials
Materials other than steel which may be used in power plant piping are cast iron and
nonferrous materials such as copper and brass. However, these materials are limited by
the code in regard to pressure and temperature.
According to the ASME Code Section I, cast iron can be used for steam pressures up to
1725 kPa providing the steam temperature does not exceed 230°C, but in no case, can be
used for boiler blowoff connections. Cast iron is not used where shock loading may
occur.
The ASME Code Section I also specifies that nonferrous pipe or tubes shall not be used
for blow-off piping or for any other service where the temperature exceeds 210°C. In
cases where the use of nonferrous materials (any metal other than iron and its alloys
such as aluminium, copper or copper nickel) is allowed, there is a possibility of galvanic
corrosion occurring when these materials are used in conjunction with steel or other
metals. The galvanic corrosion occurs where the dissimilar metals come in contact.
Page 485
Page 486
Objective 2
Calculate the required thickness and maximum
allowable working pressure of piping.
COMMERCIAL PIPE SIZES
Commercial pipe is made in standard sizes with different wall thicknesses or weights.
Up to and including 300 mm pipe, the size is expressed as nominal (approximate) inside
diameter. Above 300 mm, the size is given as the actual outside diameter.
For example, if a pipe was designated as 152 mm size this would mean that it has a
nominal or approximate inside diameter of 152 mm. The outside diameter is 168 mm
and this is a constant value no matter what the wall thickness is. The actual inside
diameter of the pipe will depend upon its wall thickness. For a standard wall thickness,
the actual inside diameter of 152 mm pipe is 154 mm. For an extra strong wall
thickness, the actual inside diameter is 146 mm.
There are two systems used to designate the various wall thicknesses of different sizes
of pipe. The older method lists pipe as standard (S), extra strong (XS) and double extra
strong (XXS). The newer method, which is superseding the older method, uses schedule
numbers to designate wall thicknesses. These numbers are: 10, 20, 30, 40, 60, 80, 100,
120, 140 and 160. In most sizes of pipe;
• Schedule 40 corresponds to standard
• Schedule 80 corresponds to extra strong
Table 1 lists the dimensions and the mass per metre of different sizes of steel pipe with
varying wall thicknesses.
Page 487
Table 1
Dimensions and Masses of Steel Pipe
Note: Upper figures in each square denote wall thickness in mm
Lower figures denote mass per metre in kilograms
Page 488
STRENGTH OF PIPING
The strength of a pipe depends upon:
• Wall thickness
• Material from which it is made
• Temperature to which it is subjected
• Method of its manufacture (whether seamless or welded)
REQUIRED THICKNESS
To determine the maximum wall thickness necessary for a pipe to withstand a certain
pressure and temperature, the following formula from the B-31.1 Power Piping Code,
Paragraph 104.1.2 (Straight Pipe under Internal Pressure) is used. This is essentially the
same formula as given in the ASME Code Section I PG-27.2.2.
P Do
tm =
+ A where
2SE + 2YP
tm = Minimum required wall thickness in millimetres. (As pipe manufacturing
processes do not produce absolutely uniform wall thicknesses, the value of tm as
determined by the formula is usually increased by 12.5% to provide a
manufacturing tolerance).
P = Maximum Allowable Working Pressure (MPa)
Do = Outside diameter of pipe in millimetres
SE = Maximum allowable stress value in MPa at the operating temperature as listed in
Tables A-1 and A-2 in the Power Piping Code or in Table 1A in the ASME Code
Section II, Part D. The stress values in these tables take into account the
efficiency of the longitudinal seam of welded pipe. (See Notes 7, 8 and 9 at the
end of Table PG-23.1)
A = Allowance for threading and structural stability, millimetres
Threaded steel or nonferrous pipe
19 mm nominal and smaller, A = 0. 065
25 mm nominal and larger, A = depth of thread
Plain end steel or nonferrous pipe
89 mm size and smaller, A = 0. 065
102 mm size and larger, A = 0.000
(Plain end pipe is that which does not have its wall thickness reduced when
joining to another pipe. For example, pipe lengths welded together rather than
joined by threading)
y
= Temperature coefficient having values as given in Table 2
Page 489
Table 2
Values of y
Temperature
ºC
Ferritic
Steels
Austenitic
Steels
482
and
below
0.4
510
0.5
538
0.7
566
0.7
593
0.7
621
and
above
0.7
0.4
0.4
0.4
0.4
0.5
0.7
For y values between the temperatures listed in Table 2, interpolation may be used.
Example 1
Calculate the required thickness for 304.8 mm nominal size plain end steam pipe to
operate at 10 250 kPa and 510°C. The material is seamless alloy steel SA-335P12.
Solution
tm
=
P
Do
SE
y
A
=
=
=
=
=
P Do
+A
2(SE + Py )
10.25 MPa (given)
323.85 mm (Table 1)
73.8 MPa (Table 1A in the ASME Code Section II, Part D)
0.508
(Table 2 – Ferritic steel by interpolation)
0.000
(See previous page for 102 mm and larger pipe size)
10.25 × 323.85
+A
2(73.8 + 10.25 × 0.508)
3319.46
tm =
+0
2(79.01)
3319.46
tm =
+0
158.02
tm = 21.01 + 0
tm =
tm = 21.01 mm
Using a manufacturer’s tolerance allowance of 12.5%, the required wall thickness is:
= 21.01×1.125
= 26.26 mm ( Ans.)
Page 490
MAXIMUM ALLOWABLE WORKING PRESSURE
To calculate the value of P for a given value of tm, the formula is transposed to solve for
P as follows:
P=
2 SE (tm − A)
Do − 2 y (tm − A)
Example 2
Calculate the maximum allowable working pressure, in MPa, for a 203.2 mm nominal
size plain end steam pipe with a minimum thickness of 18.24 mm. The average
operating temperature is 510°C. The pipe material is a Ferritic steel SA-213-T11.
Solution
Where:
tm
Do
SE
y
A
P=
=
=
=
=
=
18.24 mm
219.08 mm (Table 1)
78.60 MPa (Table 1A in the ASME Code Section II, Part D)
0.508 (Table 2 by interpolation for 510ºC)
0.000 (See previous page)
2 SE (tm − A)
Do − 2 y (tm − A)
2 × 78.6(18.24 - 0)
219.08 - 2 × 0.508(18.24 - 0)
2 × 78.6(18.24)
=
219.08 − 2 × 0.508(18.24)
2 × 1346.11
=
219.08 − 2 × 9.27
2692.22
=
219.08 − 18.54
2692.22
=
200.84
= 13.42 MPa (Ans.)
=
Page 491
Page 492
Objective 3
Describe typical inspection procedures for piping
installations and repairs.
INSPECTION PROCEDURES
Whenever new piping is installed or repairs are made to existing piping, the piping is
tested to ensure it will withstand its maximum allowable operating pressure. The
majority of piping is joined together with welding. The welding process may cause a
number of defects which include the following:
• Incomplete fusion
• Undercutting
• Porosity
• Slag inclusion
• Cracking.
Various methods of non-destructive examination (NDE) are used to discover these
defects. NDE is the testing of materials without destroying the integrity of the material
or lowering its ability to perform its primary function. These tests include:
• Visual
• Magnetic particle
• Liquid penetrant
• Radiographic
• Ultrasonic
• Leak
• Time-of-Flight Diffraction (TOFD)
Visual
Visual inspection is the most cost-effective method, but it must take place prior to,
during and after welding. The ANSI/AWS D1.1, (American National Standards
Institute/American Welding Society) Structural Welding Code-Steel, states, "Welds
subject to non-destructive examination shall have been found acceptable by visual
inspection." Before the first welding arc is struck, materials are examined to see if they
meet specifications for quality, type, size, cleanliness and freedom from defects. Grease,
paint, oil, oxide film or heavy scales are removed.
Page 493
The pieces to be joined are examined for:
• Flatness
• Straightness
• Dimensional accuracy
• Alignment
• Fit-up
• Joint preparation
Process and procedure variables are verified, including electrode size and type,
equipment settings and provisions for preheat or postheat. All of these precautions apply
regardless of the inspection method used. During fabrication, visual examination of a
weld bead and the end crater may reveal problems such as cracks, inadequate
penetration, and gas or slag inclusions.
On simple welds, inspecting at the beginning of each operation and periodically as work
progresses is adequate. However, where more than one layer of filler metal is deposited,
each layer is inspected before depositing the next. The root pass of a multipass weld is
the most critical for weld soundness. It is especially susceptible to cracking, and because
it solidifies quickly, it may trap gas and slag. On subsequent passes, conditions the
shape of the weld bead causes or changes in the joint configuration can cause further
cracking as well as undercut and slag trapping.
After welding, visual inspection detects a variety of surface flaws, including cracks,
porosity and unfilled craters regardless of subsequent inspection procedures.
Magnetic Particle
Magnetic particle testing (MT) is used to detect surface or subsurface flaws. An electric
current produces a magnetic flux that attracts magnetic particles to the cracks in the
metal. In the presence of discontinuities, the magnetic flux in a material is distorted.
This distortion is a function of the orientation of the discontinuity to the magnetic field
(flux lines). The distortion is greatest when the discontinuity is perpendicular to the
magnetic field. When distortion of the magnetic field is great enough, a pair of magnetic
poles that act as small magnets, are established at the discontinuity.
Fig. 1(a) shows how magnetic particle testing is used to locate cracks in ferromagnetic
materials. Magnetic particles are attracted to the poles and gather at the crack, Fig. 1(b),
indicating a surface or subsurface flaw. This technique can only be applied on
ferromagnetic materials. Magnetic particle testing is often used for finding cracks in
piping, vessels, and the storage tanks of deaerators.
Page 494
(a)
(b)
Figure 1
Magnetic Particle Testing
Magnetic particles, applied wet or dry, are available in various colors:
• Silver-grey
• Black
• Red
• Yellow
• Green
• Fluorescent
Various colours are necessary to obtain the maximum contrast between the surface of
the component and the discontinuity. Fluorescent particles are extremely visible when
viewed under ultraviolet light and have a high contrast with the surface being examined.
Liquid Penetrant
Surface cracks and pinholes that are not visible to the naked eye can be located using
liquid penetrant inspection. This method is widely used to locate leaks in welds and can
be applied with austenitic steels and nonferrous materials where magnetic particle
inspection is not effective.
Two types of penetrating liquids are used:
• Fluorescent
• Visible dye
Page 495
Fluorescent
With fluorescent penetrant inspection, a highly fluorescent liquid with good penetrating
qualities is applied to the surface of the part to be examined. Capillary action draws the
liquid into the surface openings, and the excess is removed. A developer is then used to
draw the penetrant to the surface, and the resulting indication is viewed under ultraviolet
(black) light. The high contrast between the fluorescent material and the object makes it
possible to detect minute traces of penetrant that indicate surface defects.
Visible Dye
Dye penetrant inspection is similar, except that vividly coloured dyes visible under
ordinary light are used (Fig. 2). A white developer is used with the dye penetrants that
create a sharply contrasting background to the vivid dye color. This allows greater
portability because it eliminates the need for ultraviolet light.
Figure 2
Dye Penetrant
The part to be inspected is clean and dry because any foreign matter could close the
cracks or pinholes and exclude the penetrant. Penetrants can be applied by dipping,
spraying or brushing with sufficient time allowed for the liquid to be fully absorbed into
the discontinuities. This may take an hour or more of very exacting work.
Liquid penetrant inspection is widely used for leak detection. A common procedure is
to:
1. Apply fluorescent material to one side of a joint
2. Wait an adequate time for capillary action to take place
3. View the other side of the joint with ultraviolet light
Radiographic
Radiography (X-ray) is one of the most important, versatile and widely accepted of all
the non-destructive examination methods. X-ray is used to determine the internal
soundness of welds.
Page 496
Radiography is based on the ability of X-rays and gamma rays to pass through metal and
other materials opaque to ordinary light and produce photographic records of the
transmitted radiant energy. All materials absorb known amounts of this radiant energy.
Therefore, X-rays and gamma rays can be used to show discontinuities and inclusions
within the opaque material. The permanent film record of the internal conditions shows
the basic information that determines weld soundness.
High-voltage generators produce x-rays. As the high voltage applied to an x-ray tube is
increased, the wavelength of the emitted X-ray becomes shorter and provides more
penetrating power.
The atomic disintegration of radioisotopes produces gamma rays. The radioactive
isotopes most widely used in industrial radiography are Cobalt 60 and Iridium 192.
Gamma rays emitted from these isotopes are similar to x-rays except that their
wavelengths are usually shorter. This allows them to penetrate to greater depths than Xrays of the same power. However, exposure times are considerably longer due to the
lower intensity.
When X-rays or gamma rays are directed at a section of weldment, not all of the
radiation passes through the metal. Various materials, depending on their density,
thickness and atomic number absorb different wavelengths of radiant energy. The
degree to which these materials absorb the rays determines the intensity of the rays
penetrating through the material. When variations of these rays are recorded, there is a
means of seeing inside the material available. The image on a developed photosensitized
film is known as a radiograph (Fig. 3).
The opaque material absorbs a certain amount of radiation, but where there is a thin
section or a void (slag inclusion or porosity), less absorption takes place. These areas
appear darker on the radiograph. Thicker areas of the specimen or higher density
material (tungsten inclusion), absorb more radiation and their corresponding areas on the
radiograph are lighter.
Page 497
Figure 3
Radiograph
The reliability and interpretive value of radiographic images are a function of their
sharpness and contrast. The sharpness of an image and its contrast with the background
enables the observer to detect a flaw. To be sure that the radiographic exposure produces
acceptable results, a gauge called an Image Quality Indicator (IQI) is placed on the part
so that its image is produced on the radiograph.
Image quality indicators, used to determine radiographic quality, are also called
penetrameters. A standard hole-type penetrameter is a rectangular piece of metal with
three drilled holes of set diameters. The thickness of the piece of metal is a percentage of
the thickness of the specimen being radiographed. The diameter of each hole is different
and is a given multiple of the penetrameter thickness. A penetrameter is not an indicator
or gauge to measure the size of a discontinuity or the minimum detectable flaw size. It is
an indicator of the quality of the radiographic technique.
Surface defects show up on the film and must be recognized. Because the angle of
exposure also influences the radiograph, it is difficult or impossible to evaluate fillet
welds using this method. Because a radiograph compresses all the defects that occur
throughout the thickness of the weld into one plane, it tends to give an exaggerated
impression of scattered-type defects such as porosity or inclusions.
An x-ray image of the interior of a weld can be viewed on a fluorescent screen as well as
on developed film. The screen makes it possible to inspect parts faster and at lower cost
than with film. Linking the fluorescent screen with a video camera overcomes many of
the shortcomings of radiographic imaging. Instead of waiting for film to be developed,
the images are viewed in real time. This improves quality and reduces costs on
production applications, such as pipe welding, where a problem can be identified and
corrected quickly.
Page 498
Radiographic equipment produces radiation that is harmful to body tissue in excessive
amounts, so safety precautions are followed closely. All instructions are followed
carefully to achieve satisfactory results. Only personnel who are trained in radiation
safety and qualified as industrial radiographers are permitted to do radiographic testing.
Ultrasonic
Ultrasonic inspection (Fig. 4) is a method of detecting discontinuities. A high-frequency
sound beam, at an angle of about 70°, is directed through the base plate and weld on a
predictable path. These sound waves pass through the material bouncing off the inner
and outer walls. A defect reflects part of the sound back to the source (a quartz crystal
transducer). The sound pulses are shown on an oscilloscope together with the reflected
signal from the defect.
When the sound beam's path strikes an interruption in the material continuity, some of
the sound is reflected back. The instrument collects the sound which is then amplified
and displayed as a vertical trace on a video screen.
Figure 4
Ultrasonic Inspection
Both surface and subsurface defects in metals are detected, located and measured using
ultrasonic inspection, including flaws too small to be detected with other methods. The
ultrasonic unit contains a crystal of quartz or other piezoelectric material encapsulated in
a transducer or probe. When a voltage is applied, the crystal vibrates rapidly. As an
ultrasonic transducer is held against the metal to be inspected, it imparts mechanical
vibrations of the same frequency as the crystal through a couplant material into the base
metal and weld. The couplant transfers the ultrasonic waves better than air does. For
relatively flat, smooth surfaces, a mixture of glycerin and water may be used as a
couplant. For rough surfaces, light motor oil with a wetting agent may be used.
Waves are propagated through the material until they reach a discontinuity or change in
density.
At these points (discontinuities) some of the vibration energy is reflected back. As the
current that causes the vibration is shut off and on at 60-1000 times per second, the
quartz crystal intermittently acts as a receiver to pick up the reflected vibrations. This
causes pressure on the crystal and generates an electrical current. Fed to a video screen,
this current produces vertical deflections on the horizontal base line. The resulting
pattern on the face of the tube represents the reflected signal and the discontinuity.
Page 499
Compact, portable ultrasonic equipment is available for field inspection and is
commonly used on bridge and structural work as well as for checking the thickness of
piping.
Ultrasonic testing is not as suitable as other NDE methods for determining porosity in
welds because round gas pores respond to ultrasonic tests as a series of single-point
reflectors. This results in low amplitude responses that are easily confused with "base
line noise" inherent with testing parameters. However, it is the preferred test method for
detecting common types of discontinuities and laminations.
Portable ultrasonic equipment is available with digital operation and microprocessor
controls. These instruments may have built-in memory and provide hard copy printouts
or video monitoring and recording. They are interfaced with computers which allow
further analysis, documentation and archiving, much as with radiographic data.
Ultrasonic examination requires expert interpretation from highly skilled and
extensively trained personnel
Leak
Leak testing, to verify the integrity of a piping system, is performed in accordance with
ASME B31.1 Power Piping Code. The testing methods, most widely used, are:
• Hydrostatic
• Pneumatic
Hydrostatic
It is mandatory that the design, fabrication, and erection of power piping, constructed
under this ASME Code demonstrate leak tightness. A hydrostatic leak test prior to initial
operation meets this requirement. A non-compressible liquid, such as water, is usually
the test medium used. Water is inexpensive and readily available. A glycol/water
mixture or methanol is used if the testing is performed when the ambient temperature is
near or below freezing.
The hydrostatic test pressure of a piping system is not less than 1.5 times the design
pressure, but does not exceed the maximum test pressure of any vessels or components
in the piping system. The test pressure is maintained for sufficient time to inspect all
joints, with a minimum time of ten minutes.
Hydrostatic testing is the preferred method because it is very safe. Liquids are not
compressible. When a leak occurs, the pressure is gone. Compressible fluids continue to
expand, creating a safety hazard.
Pneumatic
Pneumatic testing of piping systems involves the pressurization with a compressible gas,
such as air or nitrogen. Air is an inexpensive and readily available test medium.
Nitrogen is selected if there is the possibility of combustible gases being present. This
Page 500
type of test is only used when the design of piping systems does not allow the complete
removal of water.
The primary hazard with compressed gases is the amount of stored energy contained.
The results are catastrophic if a failure occurs. Pneumatic testing is done with all
nonessential personnel removed from the immediate area.
Time-of-Flight Diffraction (TOFD)
TOFD is a type of ultrasonic inspection that uses diffraction signals instead of reflection
signals. The TOFD technique is an effective, fully computerized inspection method for
the detection and sizing of flaws with a high rate of accuracy. The location, geometry or
orientation of the anomalies is irrelevant for detection and sizing. In the TOFD
technique, a transmitter and a receiver are placed equal distances from the weld. The
scanner with the probes is moved parallel to the weld.
TOFD is utilized over the entire length of the weld to classify inherent flaws and creep
damage. The small, high intensity beam spot used in this inspection is effective in
detecting creep damage due to an early form of cavitation.
Fig. 5 shows the typical TOFD arrangement for the detection of deep-seated damage,
with the probes set broadly. The intersection point of the beam centres lies at a depth of
approximately 2/3 wall thickness. This inspection is done in a single scan pass with
transducers straddling the weld.
Figure 5
TOFD Transducer Configuration for Deep Coverage
Page 501
Page 502
Objective 4
Describe a typical routine inspection procedure and
schedule for high-energy piping.
HIGH-ENERGY PIPING
High-energy piping includes main steam and hot reheat piping systems designed to
operate at high temperatures and pressures. Main steam piping has design temperatures
between 510ºC and 565ºC and operating pressures between 8.6 MPa up to supercritical.
Hot reheat piping systems operate between 510ºC and 565ºC but at lower pressures than
the main steam piping. For example, a Combustion Engineering steam generator with a
main steam pressure of 17.4 MPa has a reheat pressure of 4.05 MPa.
The ASME B31.1 Power Piping Code prescribes recommended practices for the
inspection of high-energy piping systems. High-energy piping systems, part of the
feedwater and steam circuit of a steam generating power plant, include runs of piping
and supports, restraints and all valves. This also includes all systems under two-phase
flow conditions. A record keeping program is developed to analyze piping system
distortions and potential failures.
The following procedures are established and implemented:
• Operating and maintenance programs
• Piping and pipe support inspection program
OPERATING AND MAINTENANCE PROGRAMS
Written procedures include the qualifications of personnel and material history and
records.
Each plant files and maintains the following documentation:
• Flow diagrams
• Valve data
• Welding procedures and records
• Support drawings
• Pipe drawings
• Operating records that document cases of exceeding piping design criteria
• Piping drawings (isometric piping drawings)
• Construction drawings that identify weld locations
• Pipe specifications that outline the material, outside diameter and wall thickness
• Material certification records
Page 503
PIPING AND PIPE SUPPORT INSPECTION PROGRAM
The piping and pipe support inspection program identifies the initial hanger positions at
the time of installation and unit startup. Routine visual surveys are scheduled to identify
any changes in position of piping and setting of pipe hangers, slide supports and shock
suppressors.
Attaching markings or pointers to the piping components allows for periodic position
determinations and permanent identification. These observations include:
• Any interference from other piping or equipment
• Piping vibrations
• General condition of the supports, guides, anchors, supplementary steel and
attachments
Procedures are developed for corrosion control and evaluation of the piping components
for corrosion damage. These procedures include the periodic visual inspection of the
following:
• Condition of the paint on the piping to resist external ambient corrosion
• Condition of the insulation and/or wrappings for winter freeze protection
• Thickness testing for pipe elbows and welded joints
Check superheater and reheat piping for signs of creep. This is done after a period of
operation such as 10, 15 or 20 years. Samples of metal are taken for metallurgical
inspection or lengths of pipe are measured to detect increase in length.
Page 504
Objective 5
Explain the effects of high temperature on piping
strength.
HIGH TEMPERATURE EFFECTS ON PIPING
Piping in power plants and process plants is often subjected to high operating
temperatures. The operating temperature has an effect on the tensile strength of the
metal and may also cause creep.
Tensile Strength
As the temperature is increased, the properties of the pipe material change. The tensile
strength of the material rapidly decreases above a certain temperature. This is indicated
in Table 1A of the ASME Code, Section II, Part D. For materials listed in this table, the
working stress allowed decreases as the temperature increases. For example, steel pipe
of material SA-53B is allowed a working stress of 103 425 kPa at 343°C. But, at a
temperature of 427°C, the working stress allowed is only 74 466 kPa.
The ultimate strength of carbon steel and a number of alloy steels as determined by short
time tensile strength tests over a temperature range of 38°C to 816°C is shown in Fig. 6.
The results of these tests indicate that the strength decreases with an increase in
temperature. There is a temperature region for the austenitic alloy steels between 204
and 482°Cwhere the strength is fairly constant. The strength of carbon and many low
alloy steels increases between the ranges of 38 to 316°C.
Page 505
Figure 6
Tensile Strength of Various Steels
CREEP
In addition to immediately reducing the tensile strength of a material, high temperatures
cause the pipe material to creep. This is a condition where the pipe material gradually
stretches or undergoes plastic deformation. This occurs if the material is subjected to
stress under high temperature and can become a long term gradual decrease in tensile
strength. Eventually the material will fail if the stress at the elevated temperature is
maintained for a sufficient length of time. For power plant piping, an elongation or
stretching rate of 1 percent in 100 000 hours is considered acceptable.
To determine the rate of creep of a material, a creep test is conducted. A specimen of
the material is held at constant temperature in a furnace and, using a system of levers, a
deadweight is applied. The deformation of the specimen is measured periodically
throughout the test and a curve is plotted showing the percent creep throughout the time
of the test.
Page 506
Fig. 7 shows the creep curves for a material tested at low stress and at high stress. The
rate of creep is divided into three stages. During the first stage, the creep rate decreases
(the slope of the curve decreases). During the second stage, the rate is constant (the
slope of the curve does not change). During the third stage, the rate increases (the curve
slope becomes steeper) until the specimen ruptures.
Another adverse effect of high temperature on pipe material is that it promotes oxidation
and corrosion. A low carbon steel heated in air for a certain period experienced over 50
times as much oxidation at 816°C as it did when heated for the same period at 538°C.
In addition to the above problems, if the operating temperature of the pipe is high, then
the pipe expands when coming up to that temperature. Movement of the pipe due to
expansion is allowed for when installing the pipe.
Figure 7
Typical Creep Curves
Page 507
Page 508
Objective 6
Describe the design and installation criteria for a piping
system layout.
PIPING SYSTEM LAYOUT
Piping systems, used to transfer fluids such as water, steam, oil, gas and air from one
location to another, must include:
• Proper support
• Provisions for expansion and contraction
• Cold springing
• Anchors
• Drainage
• Insulation
Piping Supports
Piping is supported so that the equipment to which it is attached does not carry the
weight of the piping. The supports used prevent excessive sagging of the pipe and, at
the same time, allow free movement of the pipe due to expansion and contraction.
However, unlike a pipe guide, the pipe support does not control the direction of the pipe
line movement.
The supporting arrangement is designed to carry the weight of the pipe, valves, fittings
and insulation plus the weight of the fluid contained within the pipe.
Fig. 8 illustrates two types of adjustable pipe hangers which are suspended from
overhead beams. Fig. 8 (a) shows an adjustable strap hanger while Fig. 8 (b) illustrates
an adjustable roller hanger.
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Figure 8
Pipe Hangers
The roller stands in Fig. 9 may be bolted to brackets, structural supports and floors. Four
adjustment screws which raise or lower the roller the pipe rests on control the vertical
adjustment of the pipe position in the adjustable stand..
Figure 9
Pipe Roller Stands
In the case of a horizontal pipe where the action of other parts of the piping system
causes vertical movement, the rigid type hangers or supports in Figs. 8 and 9 are not
suitable. In this situation, variable spring hangers are used permitting the pipe to move
up or down without disturbing the load distribution. Fig. 10 shows a type of a variable
spring hanger.
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Figure 10
Variable Spring Hanger
If the amount of vertical movement of the supported pipe is large, then a constant
support hanger (Fig. 11) is used. This type features a coiled helical spring which is
arranged to move as the pipe moves and maintains a constant supporting force on the
spring. Roller bearings with sealed lubrication are used to reduce friction between the
moving parts of the hanger.
The constant support hanger is factory adjusted and tested to support the specified load
throughout a definite range of travel. The spring compression can be adjusted in the
field to give a plus or minus 10% variation in the load setting.
Page 511
Figure 11
Constant Support Hanger
Expansion of Piping
Expansion control in pipelines that carry hot or cold fluids or are exposed to large
variations in ambient temperature can be a major problem. As the metal temperature of
the pipe increases or decreases, its length also varies due to thermal expansion or
contraction. Therefore, unless provision is made for these changes in length, excessive
stresses are induced in the piping and large forces are transmitted through the system to
anchors and connected equipment.
Several different methods are available for controlling pipeline expansion. Two of the
most common are:
• Expansion bends
• Expansion joints
Expansion Bends
With this method, the pipe is fabricated with special bends or loops. Flexing or
springing of the bends or loops takes up the increase due to expansion in the length of
pipe. Fig. 12 shows some typical shapes of expansion bends. Length and height
dimensions are used to install the bend that will withstand the required amount of
expansion.
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Figure 12
Expansion Bends
Advantages of expansion bends are:
• Easily added to piping systems and fit on pipe racks and high lines
• Most trouble-free method as there is no maintenance involved
• Leakage is unlikely
• Any temperature, pressure or fluid can be handled with proper selection of
material and thickness
Disadvantages of expansion bends are:
• Require a larger amount of space
• Produce a higher pressure drop and heat loss
• Produce higher end thrusts which can present problems when connecting to
equipment such as turbines and pumps
Expansion Joints
Two types in use are:
• Slip expansion joint
• Corrugated expansion joint
Slip Expansion Joint
This type, illustrated in Fig.13, features a slip pipe which is welded to an adjoining pipe.
The slip pipe fits into the main body of the joint which is fastened to the end of the other
adjoining pipe. When the pipe line expands, the slip pipe moves within the joint body.
To prevent leakage between the slip pipe and the joint body, packing is used around the
outside of the slip pipe and the slip pipe moves within the packing.
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In the joint illustrated, the packing consists of two sections of packing separated by a
section of plastic packing. Additional plastic packing may be added using a packing
plunger while the joint is in service. Grease fittings are used to provide lubrication.
Figure 13
Slip Expansion Joint
Advantages of slip expansion joints are:
• Simple and rugged
• Capable of handling a large amount of expansion
• Require minimum space
• Produce little pressure drop and heat loss
Disadvantages of slip expansion joints are:
• More moving parts and possibilities for leaks
• Must be located where the packing can be given attention
• Problems may arise if the joint is poorly aligned or if it becomes corroded
• Joint are installed and maintained according to manufacturer’s instructions
• Proper packing is used
• Require lubrication two or three times a year unless self-lubricating packing is
used.
Corrugated Expansion Joint
A simple design suitable for only low pressures is illustrated in Fig.14 and is available
with either flanges or welding ends. This type of expansion joint has a flexible
corrugated section which can absorb a certain amount of endwise movement of the pipe.
They are often seen at the exhaust end of a steam turbine.
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Figure 14
Low Pressure Corrugated Expansion Joint
For higher pressures, the corrugated joint uses control or reinforcing rings which
surround the corrugations as illustrated in Fig. 15.
Figure 15
Reinforced Corrugated Expansion Joint
The bellows type corrugated expansion joint, shown in Fig. 16, is suitable for pressures
up to 2070 kPa. It is equipped with an internal safety sleeve with a limit stop to prevent
undue extension or compression. Because this sleeve is closely fitted, it prevents
excessive leakage if failure of the bellows section occurs. This type may be supplied
with or without anchor bases.
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Figure 16
Bellows Type Corrugated Expansion Joint
Advantages of corrugated expansion joints are:
• Require less space
• Produce less pressure drop and heat loss than the expansion bends or loops
• Do not require maintenance as in the case of the slip type
Disadvantages of corrugated expansion joints are:
• Amount of movement the bellows or corrugations provide is less than the slip
expansion joint provides
• Vulnerable to condensate corrosion during shutdown periods as the condensate
does not drain effectively
Fig. 17 illustrates the various different designs of bellows or corrugations.
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Figure 17
Types of Bellows
Cold Springing
Cold springing or pre-stressing of a piping system is applied to reduce the effect of
thermal expansion in the piping system. Leaving a gap at an appropriate location in the
piping system and "pulling up cold" during the erection/installation of the piping
achieves this. Cold pull, usually 50% of the expansion of the pipe run under
consideration, has no effect on the code stress but can be used to reduce the nozzle loads
on machinery or vessels.
Effect Of Cold Springing
Cold springing introduces a predetermined stress in the pipe and reduces the maximum
thermal loads and stresses in a system when the pipe is cold. Its main purpose is to
reduce the peak loading on connecting equipment. However, it does not affect the
overall stress range, and therefore cannot be used in the stress range equations. In piping
systems well below the creep range, any cold spring should stay for life. Pipes in the
creep range eventually fully relax out, so they become 100% cold sprung regardless of
how much is applied at original build stage. Some codes make use of cold spring to
reduce the maximum hot stress (deadweight + pressure +thermal expansion).
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Cold spring is used to:
1. Minimize the offset of a piping system from the neutral position (installed
position without cold spring) to the operating condition. For example, if a pipe
moves 50 mm from the neutral to the hot position and it is cold sprung 25 mm,
the offset from the neutral position when cold will be -25 mm and in the hot
position +25 mm.
2. Minimize the forces on an end point which may be at a piece of equipment.
Because a negative force is put on the equipment in the cold position, the pipe
passes through a neutral force condition during heat up and has a reduced force
in the hot or operating position.
3. Reduce the stress in the hot position. Because a negative stress is placed on the
pipe when installed with cold spring and during heat up, the pipe relieves this
initial stress and passes through a neutral stress condition. The final stress in the
hot position is reduced.
4) Minimize hanger movement. For example, if a hanger is on a pipe that moves 50
mm horizontally, the hanger is dislocated from its neutral position 50 mm
without cold spring. The hanger offset and rod lengths are such that the hanger
rod is not offset more than 4 degrees.
If 25 mm of cold spring is installed and the hanger is moved -25 mm from its
neutral position and in the hot position it is +25 mm from the neutral position,
then the rod can half the length and still be within the 4 degree limit.
If the hanger offsets more than 4 degrees, the uplift becomes a factor and induces
more load and stress at the hanger point and possibly at equipment connections.
Good judgment is necessary when applying cold spring. The cold spring becomes a vital
part of the design. Extra precautions and field verifications are used when actually
installing the pipe to ensure that the cold spring is installed as designed.
Piping Anchors
Anchors are important in any piping system but there are some special considerations
necessary when expansion joints are used. No expansion joint operates properly unless
the pipeline is securely anchored. In addition, the pipeline has enough guides or supports
to prevent buckling or bowing of the pipe.
When guides are installed near an expansion joint they hold the pipe in the proper
position for best operation of the joint. With the slip type joint, this prevents
misalignment of the sleeve in the joint. With the bellows type joint, the guides prevent
excessive stress on the bellows which results from misalignment of the pipe.
A pipe alignment guide is a form of sleeve or framework, fastened to a rigid part of the
installation, which permits the pipe to move freely in one direction only, along the axis
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of the pipe. It allows sufficient clearance between the fixed and moving parts to give
proper guidance without excessive friction.
Anchors are installed to:
• Stabilize the piping at certain points, such as valves or other equipment
• Support junctions of two or more pipes
• Terminal points
With expansion joints, anchors serve to divide the system into sections, so that each
expansion joint absorbs only the expansion of its own section.
If only one expansion joint is used, it is placed in the middle of the pipeline. If it is not
fitted with an anchor, the line is anchored at each end. If the single joint is fitted with an
anchor then it is placed at the end of the line.
When several expansion joints are used in a pipe line, the pipe may be anchored midway
between the joints or at the joints themselves if they are fitted with anchor bases.
Drainage
All piping systems that have a possibility of forming liquids need to have provisions for
the liquid to drain to low spots. From the low spots, the liquid is removed using traps
and low point drains.
STEAM TRAPS
Steam traps are automatic valves that discharge condensate from a steam line without
discharging steam. Steam traps are an essential part of a steam system. Without them the
steam pipes and heat exchangers quickly fill with condensate that prevents the flow of
steam and transfer of heat. Steam traps are placed along distribution piping and after all
heat exchangers.
There are four types of steam traps:
• Inverted bucket
• Float and thermostatic
• Thermostatic
• Thermodynamic
Inverted Bucket Traps
In inverted bucket traps (Fig. 18), steam is contained within an inverted bucket floating
in condensate. As the level of condensate rises, it is discharged. Inverted bucket traps
require water, called the prime, within the bucket to operate. This trap is most
appropriate for steady loads such as on distribution systems. Condensate is discharged
intermittently.
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Figure 18
Inverted Bucket Trap
Courtesy of Spirax Sarco
Float and Thermostatic Traps
In float and thermostatic traps (Fig. 19), condensate is discharged when the rising level
of condensate lifts a float attached to a level valve. A thermostatically operated vent
discharges air from the top of the trap. Float and thermostatic traps have superior air
removal characteristics. However, the internal valves and seats are matched to steam
pressure or the trap can fail in closed position. Condensate is discharged continuously
as it collects in the trap body.
Figure 19
Float and Thermostatic Trap
Courtesy of Spirax Sarco
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Thermostatic Traps
Thermostatic traps (Fig. 20) operate on the difference in temperature between steam and
condensate. When condensate reaches the trap, the filled thermal element opens a pilot
valve to allow limited flow. The main valve stays closed until the condensate load
exceeds the capacity of the pilot valve. Then the pilot valve opens the main valve, and
both discharge at full capacity. At startup, both the pilot valve and the main valve are
open for high-capacity discharge of air and condensate. In standard operation, the pilot
valve may drain condensate continuously, closing only in the absence of condensate.
Although condensate is discharged continuously, thermostatic traps always cause some
condensate to remain in the system so steam is not blown through the trap.
Figure 20
Thermostatic Trap
Thermodynamic Traps
Thermodynamic traps (Fig. 21) have a disk situated on a central orifice. As condensate
pressure builds, it lifts the disk, passes through the orifice at the centre of the disk and
exits through smaller orifices surrounding the disk. Flash steam builds up pressure on
top of the disk and closes the orifice. Condensate is discharged intermittently.
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Figure 21
Thermodynamic Trap
Courtesy of Spirax Sarco
Piping Insulation
Insulation is materials or combinations of materials that retard the flow of heat energy.
Substances with a large number of microscopic air pockets dispersed throughout the
material make the most efficient insulators. These extremely small air spaces restrict the
formation of convection currents and the air is a poor conductor of heat.
Piping is covered with insulation to:
• Reduce heat loss and condensation
• Prevent uncomfortably high ambient temperatures within the power plant
• Prevent injury to personnel from contact with hot surfaces
• Prevent sweating of cool pipe surfaces
A material suitable for use as an insulation has the following characteristics:
• High insulating value
• Long life
• Vermin proof
• Non corrosive
• Ability to retain its shape and insulating value when wet
• Ease of application and installation
Thermal conductivity or K value of a material is a way of measuring the quantity of heat
that passes through a metre thickness per square metre per time unit with one degree
difference in temperature between the faces. The units of measure are watts per square
metre per temperature difference (W/m²K).
Energy
K value (W / m² K ) =
Area × ∆T ( ° K ) × Time
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Thermal conductivity (k value) is important in determining a material’s ability to resist
the flow of heat. The lower the k factor, the higher the materials insulating power and
thus lower overall heat transfer and operating costs. The value of thermal conductivity is
used:
• As a benchmark of a material’s performance during operation
• To determine a utility’s savings in the consumption of steam or fuel
• To measure the return on investment
Pipe Insulation Materials
The following are types of pipe insulation materials used in commercial and industrial
installations:
• Diatomaceous silica
• Calcium silicate
• Fibreglass
• Cellular
• Mineral fibre (rock and slag wool)
• Expanded silica, or perlite
• Elastomeric
• Foamed plastic
• Refractory fibre
• Insulating cement
• Reflective metal insulation
Diatomaceous Silica
Diatomaceous silica is combined with a hydraulic binder to form asbestos free block
insulation. These items are versatile products available in a range of sizes and
thicknesses up to 18 cm. Because of its low thermal conductivity (0.09 – 0.15 W/m²K),
this type of insulation is an economical, energy saving insulation. It exhibits minimal
shrinkage at its 1040°C temperature limit, and does not readily decompose even when
exposed directly to flame.
Calcium Silicate
Calcium silicate is a granular insulation made of lime and silica reinforced with organic
and inorganic fibres and molded into rigid forms. Service temperature range covered is
37.8ºC to 648.9ºC.
Calcium silicate insulation has the following features:
• Light weight
• Low thermal conductivity of 0.049 – 0.095 W/m²K
• High temperature and chemical resistance
• Water absorbent
• Non-combustible
• Easily cut and installed
• Ideal materials for insulation applications in power and chemical plants.
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Fibreglass
Fibreglass insulation is available as flexible blanket, rigid board, pipe insulation and
other pre-molded shapes. Service temperature range is -40.0ºC to 250ºC. Thermal
conductivity of fibreglass is 0.039 – 0.045 W/m²K. Fibreglass is neutral. However, the
binder may have a pH factor. It is non-combustible and has good sound absorption
qualities.
Cellular
This is available in board form and can be fabricated into pipe insulation and various
shapes. Service temperature range is -267.8ºC to 482.2ºC. Thermal conductivity of
cellular glass is 0.043 – 0.045 W/m²K.
This product has the following features:
• Good structural strength
• Poor impact resistance
• Non-combustible
• Non-absorptive
• Resistant to many chemicals
Mineral Fibre (Rock And Slag Wool)
Rock and/or slag wool fibres are bonded together with a heat resistant binder to produce
mineral fibres. Upper temperature limit can reach 1037.8ºC. The thermal conductivity of
mineral fibre is 0.05 to 0.17 W/m2K. The material has a practically neutral pH, is noncombustible, and has good sound control qualities.
Expanded Silica (Perlite)
Perlite is made from an inert siliceous volcanic rock combined with water. The thermal
conductivity of perlite is 0.04 to 0.06 W/m2K at 24°C. The material has low shrinkage
and high resistance to substrate corrosion. Perlite is non-combustible and operates in the
intermediate and high temperature ranges. The product is available in rigid preformed
shapes and blocks.
Elastomeric
Foamed resins combined with elastomers produce a flexible cellular material. Available
in preformed shapes and sheets, elastomeric insulations possess good cutting
characteristics and low water and vapour permeability. The upper temperature limit is
104.4ºC. The thermal conductivity of elastomeric insulations is 0.036 W/m2K.
Elastomeric insulation is cost efficient for low temperature applications with no
jacketing necessary.
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Foamed Plastic
Insulation produced from foaming plastic resins creates predominantly closed cellular
rigid materials. "K" values decline after initial use as the gas trapped within the cellular
structure is eventually replaced by air. Foamed plastics are light weight with excellent
moisture resistance and cutting characteristics. The chemical content varies with each
manufacturer. Available in preformed shapes and boards, foamed plastics are generally
used in the low and lower intermediate service temperature range -182.8ºC to 148.9ºC.
The thermal conductivity of elastomeric insulations is 0.03 - 0.04 W/m2K.
Refractory Fibre
Refractory fibre insulations are mineral or ceramic fibres, including alumina and silica,
bound with extremely high temperature binders. The material is manufactured in blanket
or rigid form. Temperature limits reach 1648.9ºC. The thermal conductivity of refractory
fibre insulations is 0.019 - 0.038 W/m2K. The material is non-combustible.
Insulating Cement
Cements may be applied to high temperature surfaces. Finishing cements or one-coat
cements are used in the lower intermediate range and as a finish to other insulation
applications. The thermal conductivity of refractory fibre insulations is 0.011 - 0.022
W/m2K. Operating temperature limits reach 982.0ºC.
Reflective Metal Insulation
This is a new type of insulation constructed of metal reflective sheets of stainless steel,
spaced and baffled to form isolated air chambers around the piping. The highly polished
reflective sheets reflect the heat and prevent loss due to radiation but absorb little heat
through conduction. The k factor varies from 0.53 to 0.66 W/m2K.
Applications
The following indicates the general application of various piping insulations for
different temperature ranges:
• Above 1040oC - refractory fibres are generally used or in some cases reflective
metal insulation
• 650oC - 1040oC - double layer construction is used with the inner layer
diatomaceous silica and the outer layer calcium silicate
• 150oC - 650oC - calcium silicate is generally used with double layer construction
for pipe temperatures over 316oC
• 0 - 260oC - glass fibre is most commonly used as it is generally the most
economical and has good resistance to normal abuse
The effectiveness of a particular insulation is expressed as an efficiency E where:
E=
Heat loss from bare pipe − heat loss from insulated pipe
heat loss from bare pipe
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The heat losses are expressed in kJ/h/linear metre. Piping insulation is usually fabricated
in half-cylindrical sections for fitting over the pipe. The sections are held together with
metal wire or bands and then a surface finish, usually a canvas type, is applied. Special
shapes and arrangements of insulation are used for fittings such as elbows, flanges, and
valves such as shown in Fig. 22.
Figure 22
Insulation of Fittings
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Objective 7
Explain the theory and effects of water hammer.
WATER HAMMER
Water hammer is a series of hammer blow-like shocks produced by a sudden change of
velocity of water or other liquid flowing within a pipeline. These shocks may have
sufficient magnitude to rupture the pipe or pipe fittings or to damage connected
equipment.
The sudden change of velocity necessary to produce water hammer may be caused by
the following:
• Rapid operation of a valve
• Sudden stoppage in flow due to a pump trip
• Rapid condensing of a pocket of steam within the pipe
Valve Operation
In the case of a valve being quickly closed in a pipeline through which water is flowing,
the first effect is the sudden decrease in the velocity of the water and a corresponding
increase in pressure at the valve. This causes a pressure wave to travel back upstream to
the inlet end of the pipe where it reverses and surges back and forth through the pipe,
getting weaker with each successive reversal. This pressure wave due to water hammer
is in addition to the normal water pressure within the pipe and depends upon the
magnitude and rate of change in velocity. Complete stoppage of flow is not necessary to
produce water hammer as any sudden change in velocity may bring it about to some
degree depending upon the above conditions.
Where too rapid closing of a valve is the cause of the water hammer, the remedy is to
ensure that the valve is closed slowly. The period of effective closing of a gate valve
takes place in the last 20% of the valve travel and this portion is undertaken as slowly as
possible. If the valve is equipped with a bypass, the bypass is opened to equalize the
pressure on both sides of the valve. The bypass valve is closed after the main valve has
been closed.
When opening a gate valve, the first 20% of the valve travel is the most critical portion.
If so equipped, the bypass should be opened to allow for pressure equalization. Then the
main valve is opened as slowly as possible. As a general rule, all valves are opened and
closed slowly and cautiously.
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Sudden Stoppage in Flow
When water hammer is due to the sudden stopping of a motor-driven pump due to a
power failure, the pressure drops at the pump discharge. The water in the discharge line
stops and then reverses direction. Subsequent rapid closing of the check valve at the
pump causes severe shock when the energy of the reverse flow is violently expended
against the check valve disc.
A pump trip may also cause water hammer in the pump suction line in cases where the
water flows to the pump through a long line by gravity or under pressure from another
pump.
The maximum intensity of the wave can be calculated using Joukowsky’s Law:
H wh =
cv
g
Where:
Hwh
c
v
g
=
=
=
=
head of water hammer, m
velocity of sound in the liquid, m/s
instantaneous velocity change in liquid (m/s)
acceleration due to gravity, 9.81 m/s2
Example 3
A pump delivers water to a tank 75 m above the pump. During a power failure, the
pump discharge check valve gets stuck in the open position for a few moments and then
slams shut. Before the check valve closes, water begins to flow backwards through the
pump with a velocity of 15 m/s. If the speed of sound in water is 1469 m/s at 15.6°C,
what is the water hammer head produced?
Solution
cv
g
1469 m/s × 15 m/s
=
9.81 m/s 2
= 2246.18 m
H wh =
H wh
H wh
A water hammer surge of 2246.18 m, added to the normal running head of 75 m, would
create a total head of:
2246.18 + 75 = 2321.18 m
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Converting this head to pressure:
Pressure = ρ gh
Pressure = 1000 kg/m3 × 9.81 m/s 2 × 2321.18 m
Pressure = 22 770 776 N/m 2
Pressure = 22 770 776 Pa
Pressure = 22 771 kPa (Ans.)
This may be sufficient to destroy any weak point in the system. The above example is
for instantaneous closing. If the valve closing time is increased, the shock wave is
greatly decreased. Devices which can be used to reduce the shock in a pump discharge
line are air chambers, relief valves or check valves with a built-in dashpot to prevent
rapid closing of the disc.
Steam Condensing
In the case of a steam line, water hammer may occur if condensate is present in the line.
As the steam passes through the line above the surface of the condensate it may raise up
behind it a mass of the condensate (water). Thus an isolated pocket of steam is formed.
Because it is in contact with the cooler water, the steam suddenly condenses and a low
pressure is formed in the pocket. Water rushing into this low pressure pocket causes
severe shock to the pipe and piping fittings.
Water hammer can also occur in a steam line that is horizontal or pitched upward from
the source of steam. It is most violent when a blank or a closed valve dead ends the
steam flow in the pipe.
To avoid water hammer in steam lines they are properly pitched and drainage points
installed between valves and at pockets in the line where water can accumulate. The
drainage points are equipped with drip legs, free-blow drain valves, and traps. In
addition, gate valves in the line are not installed with their stems below the horizontal
because the valve bonnets act as pockets.
When warming up a steam line all drain valves are opened wide before steam is
admitted. The steam admission valve should only be cracked open. If equipped with a
bypass, it is slowly opened to pressurize the line on both sides of the main isolation
valve. The main valve is slowly and carefully opened fully after the line has been
sufficiently warmed up. The drain valves are left open until all of the warm-up
condensate has been discharged and drains are blowing dry steam. The trap is then able
to handle the condensate that forms under standard operating conditions.
Page 529
Page 530
Chapter Questions
1. List the properties that contribute to the suitability and economy of a given pipe
material.
2. (a) Calculate the required thickness for 406.4 mm nominal size plain end steam pipe
to operate at 17 250 kPa and 540°C. The material used is seamless alloy steel
SA-335P12.
(b) Calculate the maximum allowable working pressure, in MPa, for the nominal
size plain end steam pipe in the above example.
3. With the aid of a simple sketch, show how the probes are located in relation to the
weld in time-of-flight diffraction.
4. Explain how high temperatures affect the tensile strength of piping.
5. Give the advantages and disadvantages of the following:
(a) Expansion bends
(b) Slip expansion joints
(c) Corrugated expansion joints
6. Explain how the sudden closing of a valve can cause water hammer in a pipe.
Page 531
Page 532
Mechanical Drawing
Learning Outcome
When you complete this learning material, you will be able to:
Interpret construction and process drawings.
Learning Objectives
You will specifically be able to complete the following tasks:
1. Interpret the information provided in orthographic, isometric, and oblique
projections.
2. Interpret the information provided in construction drawings with sectioning and
dimensioning.
3. Interpret the information provided in process flow drawings.
4. Interpret the information provided in process and instrumentation drawings
(P&IDs.)
5. Explain the use of isometric piping system and spool drawings in piping systems.
Page 533
Page 534
Objective 1
Interpret the information provided in orthographic,
isometric, and oblique projections.
MECHANICAL DRAWINGS
A pictorial representation is much more clear and concise than using words to describe
parts and systems. Engineers use mechanical drawings before the construction of
mechanical parts and systems including piping systems.
Mechanical drawings are used to communicate technical data about piping, equipment,
and processes. The drawings use standardized concepts, symbols and terminology.
Plant operators need to read standard power plant and process drawings such as process
flow diagrams, Process and Instrumentation Drawings (P&IDs) and pressure vessel
drawings. When creating procedures for starting up processes or purging piping or
vessels, a thorough knowledge of process and instrument drawings is mandatory.
Operators often make drawings or sketches of machinery parts or piping systems for
upgrades or modification. The drawings need to contain enough detail for the intended
readers, such as other operators, engineers or trades people.
The objective of mechanical drawing is to describe accurately the shape of an
engineering object such as an engine part. Other information may be indicated on the
drawing such as welding, material of construction, and types of machining. Additional
information is brief and often covered more extensively in other documents that
accompanying the drawings. Additional documents may include: mechanical
specification sheets, installation instructions, startup procedures, general operating
instructions and other OEM (original equipment manufacturer) data sheets.
Orthographic Drawings
An important type of engineering drawing is the Orthographic drawing. Orthographic
is a Greek word and its English equivalent is “Description at Right Angles.” If readers
remember the English equivalent, they will experience less difficulty understanding
orthographic rules.
Orthographic drawing is used most often and has three views. An orthographic
projection (isometric) view is shown on the left side of Fig. 1. The orthographic views
on the right side are the front, side, and top. The number of views selected for an object
must be sufficient to provide all the information required to construct the object. The
draftsperson usually selects a front view of the object which best describes the general
shape of the part. The front view the draftsperson uses may not be the front view of the
part as it fits into a mechanism. The front view is sometimes called a front elevation.
Page 535
Figure 1
Isometric with Orthographic Views
Other views of an object, other than the three standard views, can also be drawn. The
isometric view of the object on the right hand side of Fig. 2 may be projected in the
orthographic projections shown in the left hand side. They are:
F.V.
Front View
Bot.V.
Bottom View
R.V.
Right Side View
L. V.
Left Side View
B.V.
Back or Rear View
Aux. V.
Auxiliary View
T. V.
Top View
Figure 2
Systematic Arrangement of Views
Page 536
Pictorial Drawings
The objective of pictorial drawings is to approximate a camera snapshot. They give the
reader a three dimensional view of the object being shown. This makes it easier to
visualize the object as it appears when constructed. With computer aided drafting, a
pictorial view can be generated from the orthographic views. Pictorial drawings enhance
the ability of the reader to visualize objects in the drawing. They are extensively used in
architecture where they show how future buildings will appear before they are erected.
In mechanical and power engineering, they are used for piping isometric drawings and
piping spool drawings.
Although a draftsperson creates the pictorial drawings, the power engineer should be
familiar with them. When an isometric or oblique view of a part is known, the
orthographic views can be sketched from it.
Pictorial drawings (isometric or oblique) approximate camera snapshots and can be used
to convey information to power plant trainees, labourers, visitors and generally people
who are not familiar with more technical orthographic drawings. This information may
refer to safety, orientation and other important uses.
Isometric Drawings And Their Relation To Orthographic Views
Fig. 3 is an example of an isometric drawing and its equivalent orthographic drawings.
The pictorial isometric view on the right shows the origins of views Front A, Top B, and
Right Side D.
Figure 3
Orthographic and Isometric Views
Page 537
The isometric view of a more detailed object is shown in Fig. 4. It is accompanied by
standard orthographic views. The isometric view shows parts of the three views shown
in orthographic versions. The isometric view is three-dimensional and each view of the
orthographic drawing is only two-dimensional. Observe how the projection tracing lines
follow the main outline of the part from one view to the other in the orthographic views.
The drilled hole is traced from the front view to the top view and to the right side view.
The hole is drawn with a bold line in the front view but with a hidden feature line in the
other views. From the isometric view, the hole on the top view or the right side view
cannot be seen. The hole is there but cannot be shown with the visible outline line. This
is where the hidden feature line (dotted line) is used. There are two more hidden feature
lines, one in the front view and one in the right side view.
Figure 4
Types of Projections
A projection line can be drawn from the end of a hidden feature line to the neighbouring
view and see which visible outline line it corresponds to. The projection line is drawn
parallel to the existing projection lines. To assist the reader to visualize the construction
of the orthographic views from the isometric view, the corresponding views are
numbered.
Centre lines are used on orthographic drawings. The centre line is not part of the object
itself, but like projection lines they are part of the orthographic drawing. Centre lines are
mandatory where holes are drilled and where bores are turned on a lathe. They are used
as axes of symmetry wherever a symmetrical axis is located on an object. For holes and
bores centre lines are drawn at the centre of the circle and locate where the machinist
centres his drilling bit to make the hole, or where the lathe operator centres his lathe to
machine a bore.
Page 538
Construction Of Isometric Drawings
Because the isometric drawings are three dimensional in a single view, their backbone
consists of three axes intersecting at a common point on the paper. The point is called
the origin O.
The axes are drawn as shown in Fig. 5. Axes OC, OB, make a 30° angle with the
horizontal. Axis OA is vertical and perpendicular (or at 90º to the horizontal base line).
All the horizontal lines of the front view are parallel to OC. All the horizontal lines of
the right side view are drawn parallel to OB. The vertical lines of both front and right
side views are parallel to OA. The sizes in this example are drawn twice the
orthographic sizes.
The vertical lines of the top view are parallel to OB while the horizontal lines of the top
view are parallel to OC. The slanted line EF on the right side view presents some
difficulty because it must be placed parallel to none of the isometric axes. The person
drawing the view visualizes the object to be drawn. The auxiliary thin lines used in
drawing this isometric drawing, are left as a guide to how the isometric was drawn.
Figure 5
Isometric Construction
Detailed piping drawings are often shown in the isometric view. An example of an
isometric piping drawing is shown in Fig. 6. As with all isometric views, the piping is
drawn as vertical or at a 30° angle to the horizontal.
Page 539
Figure 6
Isometric View Applied to Piping
Oblique Drawings
Although the oblique pictorial drawing is not used as often as isometric pictorial
drawings, it does have some features that make it useful for specific applications. In the
oblique pictorial drawing (Fig. 7), the axis COC is horizontal, axis OA is vertical and
axis OB is the receding axis drawn at a convenient angle, usually 30°.
The object drawn in isometric view in Fig. 5 is drawn as an oblique pictorial drawing in
Fig. 7. Except for the slanted lines EF, the front view is identical to the orthographic
method.
The horizontal lines of the right side view are drawn parallel to axis OB. The vertical
lines of the right side view are parallel to OA. The horizontal lines of the top view are
parallel to COC. The vertical lines of the top view are parallel to OB. The auxiliary lines
are left in the drawing to visualize how this oblique drawing was made.
Page 540
Figure 7
Oblique Construction
An example of an oblique drawing applied to a piping system is shown in Fig. 8. The
same method is used, with all lines being vertical, horizontal, or at a 30° angle to the
horizontal.
Figure 8
Oblique Piping Drawing
Page 541
Partial Views
Using the orthographic method of drawing it is not always necessary to present a part in
the standard three views if all the key information is conveyed using one or two views.
An example is shown in Fig. 9. The side view is not included as the front view and the
top view have conveyed all information clearly.
Figure 9
Top and Front Views Only
Page 542
Objective 2
Interpret the information provided in construction
drawings with sectioning and dimensioning.
SECTIONING
Orthographic Drawings (description at right angles) can sufficiently describe the shape
and dimensions of objects whose details are visible externally. For example, a piping
network may require a very complicated drawing yet all its bends, curves and angles are
visible on the outside. A more complicated part like a bearing, seal, or pump has a
number of internal shapes and components that are not clearly illustrated using only
hidden lines. To show all such interior details with hidden feature lines is not only
difficult but almost impossible. For internal details another concept is added to the
orthographic method called “Sectioning.”
The part in Fig. 10 is in its isometric view. For a clearer view of the internal details of
the object, an imaginary saw is used to cut through the object. The cut is made along a
chosen line that reveals a new front view that is drawn to illustrate key internal features.
The cut is imaginary but it can be visualized. After the cut is completed, the rear half is
used as the front view. The holes appear with solid visible lines, not hidden feature
lines. Because they are now solid lines dimensions can be added to them. The 45°
inclined hatching or section lines cover the surface where the imaginary saw cut the
metal.
Figure 10
Section Drawing
Page 543
When the top view is drawn it indicates where the cutting took place. The cut was along
the horizontal axis of symmetry shown by line AA (extra heavy and bold) with the two
arrows. It shows which part is seen in the front sectional view. A basic rule for sections
is that a visible outline line cannot go over a sectioned area. Once the object has been
sectioned, the use of most hidden lines can be eliminated. Solid lines are used across
areas only to outline the object. Other examples are illustrated in Fig. 11 and Fig. 12.
Compare the drawing without sectioning (Fig. 11) and the one with sectioning (Fig. 12).
The drawing with sectioning is much easier to visualize and is easier to use for a
tradesman producing this object in a machine shop. The interior of the part is clearer and
more visible in the sectional drawing.
Figure 11
Side View Not Sectioned
Figure 12
Side View in Full Section
Page 544
Another drawing of the part is shown in Fig. 13, using half the sectioning. This method
also produces a clear and visible view of the internals of the part. The section line AA
indicates how the section was cut.
Figure 13
Side View in Half Section
DIMENSIONING
Valuable information contained on drawings includes the size of the object and the
location of its components. Dimensions are used to indicate the size of the object and its
components. Standard drafting practices are used to keep the dimensions of drawings
consistent. Computerized drafting has increased the consistency of application of
dimensions.
Dimensions are placed on drawings using extension lines, dimension lines, leader lines
and arrowheads.
Unidirectional System of Dimensioning
In the unidirectional system, all the dimensions are oriented and read from left to right.
The dimensions are placed in a horizontal position. It is the preferred system because it
is the easiest to read. An example of unidirectional dimensioning is shown in Fig. 14.
Page 545
Figure 14
Unidirectional System of Dimensioning
Aligned System of Dimensioning
In the aligned system of dimensioning, the dimensions are placed on the drawing from
the bottom or right side of the print. The dimensions are written in the direction the
dimension lines are running. The dimensions are either horizontal, vertical, or at an
angle. The dimensions can be slightly more difficult to read than the unidirectional
system. An example of aligned dimensioning is shown in Fig. 15. Notice the difference
in the 1.20 and 0.40 orientations between Fig. 14 and Fig. 15.
Figure 15
Aligned System of Dimensioning
Page 546
Fig. 16 shows a pressure vessel elevation view (front view is sometimes called the
elevation) and end view. Some dimensions are included on this drawing showing the
relative locations of the nozzles. Notice the reference lines do not touch the vessel. N1
and N2 are nozzles used to connect piping to the vessel, and C1 is a coupling for
attaching the drain connections to the vessel.
Figure 16
Pressure Vessel Drawing with Dimensions
Fig. 17 is a drawing of a boiler and economizer with ducting and supports. Dimensions
are provided for the major components. For example some of the dimensions on the
drawing are:
Steam drum diameter
Steam drum wall thickness
Mud drum diameter
Mud drum wall thickness
Floor to centre of mud drum
Floor to centre of boiler outlet duct
1.52 m
12.38 cm
1.07 m
8.57 cm
1.83 m
4.11 m
Page 547
Figure 17
Side Elevation of Boiler and Economizer
Page 548
Objective 3
Interpret the information provided in process flow
drawings.
PROCESS FLOW DRAWINGS (PFD)
The process flow diagram is a simplified schematic of a plant, or portion of a plant,
which shows only the major equipment items and the major process flow
streams. A process flow diagram lists the prime function of the major equipment
and the reference numbers of the material balance table. The material balance
table provides the pressure, temperature, composition, and flow rates of the
streams shown. Process flow diagrams are not to scale, and only show the
equipment sequence in the process flow, not the equipment’s relative locations.
Purpose of Process Flow Drawings
Process Flow Drawings are a valuable reference for plant operating and engineering
staff. They assist in understanding the details of the process and its instrumentation
control system, and they provide a valuable source of information for training of plant
personnel. The PFD shows the general layout of the process lines, equipment, and
major control points. It includes flow rates, pressures, and temperatures. This provides
an overview of the processes and design parameters.
Layout of the Flow Diagram
A separate flow diagram is prepared for each plant process. If a single sheet is too
crowded, more sheets may be used. For simple processes, more than one process may be
shown on a sheet. Process lines have the rate and direction of flow and other required
data such as pressures and temperatures noted. Main process flows preferably go from
the left of the sheet to the right. Line sizes are not shown on a flow diagram.
The name and specific identifying tag number of each piece of equipment is located at
the top or bottom of the page directly above or below the equipment on the
drawing (e.g. V-101 Debutanizer Tower). With flow diagrams, simplicity in
presentation is important.
Page 549
A PFD is not drawn to scale and does not show the exact orientation of equipment,
except for “order of occurrence.” Typical details shown on process flow diagrams
include:
• Major equipment with process line orientation
• Main piping and direction of flow
• Process Equipment proper name and numbering. (Optional items are dimensions,
and normal capacity)
• Operating pressure, temperature, and level values (at the major vessels or control
points)
• Heat exchanger duties, number of passes, process orientation (shell or tube side),
and general configuration
• Pump and or compressor flows and rates (often at major control points)
• Major instrumentation such as major control valve locations, and basic
instrumentation orientation
• Main pressure control valves and pressure relief valves (PRV).
A process flow diagram is shown in Fig. 18. It shows the main process flows for a
section of a process plant. The temperatures of the feed and main control points are
shown. The names of the major pieces of equipment are shown at the top of the drawing.
The pumps are identified at the bottom of the drawing.
Figure 18
Process Flow Diagram
Page 550
The PFD in Fig. 19 shows the main flows in a steam plant. The flow, condensate flow,
and major pieces of equipment are also shown. The legend in the lower left corner of
this drawing displays the symbols used on the drawing. Often the symbols are shown on
separate pages at the front of a series of drawings. More detailed information is shown
in the mechanical flow diagrams also known as P&IDs.
Figure 19
Steam System Process Flow Diagram
Page 551
Page 552
Objective 4
Interpret the information provided in process and
instrumentation drawings (P&IDs.)
THE MECHANICAL FLOW DIAGRAM
In most plants the mechanical flow diagram is called a Process and Instrument Diagram
or for short P&ID. The P&ID differs from the PFD in that the P&ID includes
equipment specific details related to their design, construction, operation and control
strategies. The P&ID visually summarizes all the system and process calculations that
are based on flow rates, pressures, temperatures, and general layout of the process flow
diagram. The P&ID is not drawn to scale and does not show the exact orientation of
equipment, except for “order of occurrence.” The detail shown on mechanical flow
diagrams includes:
• Vessel size, design pressure and temperature rating, insulation requirements, and
all connections
• Heat exchanger duties, number of passes, nozzle types and sizes, insulation
requirements, and general configuration
• Pump and compressor details, including power, and external mechanical details,
controls, instrumentation, and utilities
• Flow lines complete with line identification and specifications including: size,
insulation requirements, valve sizes and types, and connections (threaded,
flanged, and so on)
• Instrumentation including meter runs, flow recorders, temperature indicators and
recorders, pressure and level controllers, control valves, pressure indicators and
recorders, level gauges, safety relief valves, thermometer wells and shutdown
devices. The location and types of controllers, alarm and shutdown systems, and
control strategies may also be shown.
Purpose Of The Mechanical Flow Diagram
Mechanical flow diagrams are used for the following purposes:
1. During the design and pre-construction phase, P&IDs enable the engineering
contractor to make a complete mechanical equipment, instrument, valve, and
controller takeoff (detailed list), on which to base a cost estimate for bid and
contract purposes. The P&IDs show graphically the results of the mechanical
design engineer’s work. They include all that is incorporated in the completed
construction project. The mechanical flow diagram and the process flow diagram
are usually sufficient to define the scope of a project. These lists may also be
generated by computer as the drawings are produced.
Page 553
2. During construction, P&IDs provide the field construction and inspection
personnel with a reference to ensure that all equipment, instrumentation, piping,
valves, insulation, are properly located and interrelated.
3. After construction, P&IDs are an invaluable operational and training reference
for plant operating and engineering staff. They assist in understanding the
details of the process, its instrumentation control system, and the relationship
between process, utility, and electrical systems. They provide an index to
detailed piping, isometric drawings, and equipment or instrument data sheets.
P&ID Details
The pressure and temperature values listed on the Process Flow Diagram are not shown
on the mechanical P&ID. An example of a P&ID drawing is shown in Fig. 20
indicating the same section of a process plant shown on the drawing in Fig. 18.
The P&ID shows:
• Piping identification numbers
• Piping Sizes
• All instrumentation
• Piping details (including vent and drain valves)
Often a P&ID details only several major pieces of equipment. The P&ID in Fig. 21 has
only one major piece of equipment, the pressure vessel V-2 (Sales Gas Scrubber) and its
piping and instrumentation details. The following information is found on this P&ID:
• The three-phase (natural gas, hydrocarbon liquid, and glycol-water phase) inlet
enters the vessel through an 8-inch (203.2 mm) line and flanged connection. The
inlet line carries 2½ inches (63.5 mm) of cold insulation (note the symbol) versus
the vessel insulation of 4 inches (101.6 mm), shown with a different symbol.
• The vapour stream passes through a demister pad and leaves the top of the
vessel, through an 8-inch (203.2 mm) flanged connection, into an 8-inch (203.2
mm) line. Hydrocarbon liquid leaves the bottom of the vessel through a 2-inch
(50.8 mm) flanged connection into a 2-inch (50.8 mm) line, BA-G-10.
• The glycol-water mixture leaves through a 1½-inch (38.1 mm) flanged
connection into 1 ½-inch (38.1 mm) BA-Q-9 Also provided is a 1-inch (25.4
mm) flanged drain connection having a 1-inch socket weld gate valve in series
with a 1-inch (25.4 mm) screwed globe valve.
Page 554
Figure 20
P&ID Drawing
Page 555
Figure 21
Mechanical Flow Diagram
Page 556
Instrumentation details on the vessel and shown on the P&ID in Fig. 21 include:
•
One level gauge (LG-2) isolated from the vessel by angle valves and capable of
being drained through ½-inch (12.7 mm) gate valves
•
Two level controllers (LC-2 and LC-3): LC-2 controls the hydrocarbon liquid
level through 1 inch (25.4 mm) LCV-2 (level control valve) and is isolated from
the vessel by two 1½-inch (38.1 mm) screwed plug valves; LC-3 is isolated from
the vessel by two 1½-inch (38.1 mm) socket weld gate valves
•
One high level shutdown controller, LSH-2 (level switch high), which is capable
of shutting down the whole plant by stopping the refrigerant compressors
through a magneto ground, and shutting off flow to the plant by closing the inlet
emergency shutoff valve
•
One pressure indicator, PI-3, isolated by a ½-inch (12.7 mm) gate valve and one
temperature indicator, TI-4
•
One safety relief valve, 2 inch x 3 inch (50.8 mm x 76.2 mm) PSV-2, with a
flanged inlet and outlet
Mechanical flow diagrams show details such as the level control valve stations with
isolating block valves, bypass valve, and ½-inch pressure bleed valve. All piping details
are included on a P&ID drawing, including vents, drains, and gauges.
P&ID Symbols
Mechanical drawings come in sets for a particular plant or section of a larger plant. The
set of drawings includes a legend showing all the symbols used in the drawing. Fig. 22
shows a sample of a list of piping symbols. It includes:
• Valve Symbols - these symbols identify different types of valves such as globe
valves, plug valves, control valves, and ball valves; each type of valve has its
own symbol
• Line Symbols - these symbols identify different types of piping, such as normal
piping, instrument air lines, and instrument and electrical lines
• Flow Diagram Abbreviations - these abbreviations stand for standard terms that
are used on P&ID drawings; some examples are NO for normally open for
valves, SO for steam out, and CSO for car seal open
• Miscellaneous Symbols - they are used for specific items that are not common on
all P&ID drawings; examples are spectacle blinds and specialty piping items
Page 557
Figure 22
P&ID Symbols
Because P&IDs contain instrumentation data, a list of instrumentation symbols is also
included with the piping symbols. Fig. 23 shows a list of P&ID instrumentation
symbols. It includes symbols for flow, temperature, level and pressure instruments.
There are also symbols for miscellaneous items such as transmitters and hand control
valves. Symbols for board-mounted and locally-mounted instruments are also shown.
The board-mounted (control room) instruments appear as circles with horizontal lines
through them. The locally or field mounted instruments are circles with no line.
Page 558
Figure 23
P&ID Drawing Instrumentation Symbols
Page 559
Page 560
Objective 5
Explain the use of isometric piping system and spool
drawings in piping systems.
ISOMETRIC PIPING DRAWINGS
When more construction detail is needed than is found on P&ID drawings, isometric
piping drawings are used. They have more detail on things like piping lengths, joints,
valves and pipe fittings. The pipe line numbers from the P&ID are used to reference the
isometric drawings. The isometric view shows three sides of the piping in one practical
and easy to read view. A typical isometric piping drawing is shown in Fig. 24. The
horizontal lines are drawn at angles 30° from the horizontal, but vertical lines remain
vertical.
Figure 24
Isometric Piping Drawing
Tradesmen use isometric drawings for constructing and repairing the piping systems.
All piping components such as flanges, valves, piping, and pipe fittings are shown.
More detailed information than is provided on the isometric drawing can be found on
the spool drawings and the bill of materials that accompanies the spool drawing.
Page 561
Piping spool drawings, also called shop fabrication drawings, are separate drawings
incorporating all the dimensions, material specifications, and information needed to
fabricate the piping spool.
Piping Spool Drawings and Bills of Materials
Sections of the piping on the isometric drawings are labelled, such as KD30\83 – 004 on
Fig. 24. The label refers to the piping spool drawing KD30/83 – 004.
An isometric spool drawing is shown in Fig. 25.
Figure 25
Isometric Piping Spool Drawing
Isometric piping spool drawings reference flanges, piping and fitting details. The
materials are itemized on a bill of materials for each spool drawing. An example of a
bill of materials for spool drawings is shown in Fig. 26. The bill of materials is used for
construction of the piping on the spool drawing and for repairs to existing piping.
Included on the bill of materials are such details as the quantity and type of fittings,
flanges, bolts and gaskets. The bill of materials may be on the spool drawing or on a
separate sheet.
Page 562
Figure 26
Bill of Materials
The piping spool drawing may also appear as a single line orthographic spool drawing
as shown in Fig. 27. Another form for the spool drawing is the double line orthographic
spool drawing shown in Fig. 28. These views are of the same piping spool that is shown
in Fig. 25. The reference letters refer to the same bill of materials. The double line
drawing is more graphic than the single line drawing, showing two dimensions.
Page 563
Figure 27
Single Line Orthographic Spool Drawing
Figure 28
Double Line Orthographic Spool Drawing
Page 564
Chapter Questions
1.
When is sectioning used in orthographic projections?
2.
With reference to the pressure vessel drawing in Figure 16, what is the
distance from the centre of nozzle N1 to the outside of the flange on N2?
3.
What is the thickness of the steam drum and the mud drum in Figure 12?
4.
Explain the difference between a process flow diagram and a process and
instrument diagram.
5.
What lists of symbols accompanies process and instrument diagrams?
6.
Why do process and instrument drawings refer to isometric piping drawings?
7.
Name the three forms used to draw piping spool drawings.
8.
What is a bill of materials and when is it used?
9.
What is the difference between an isometric and an oblique drawing?
10.
Sketch the top front and side views of the four blocks shown below.
Page 565
Page 566
End of Chapter Questions
and Solutions
Chapter 1 Solutions
Steam Turbine Theory and Construction
1. Describe why some turbines are designed with steam entering through two
separate inlets in the LP cylinder.
The design of turbine blading affects the reliability and efficiency of the turbine. The
longer the blade the greater the bending force at the root, or fixing point, of the blade.
There is also a centrifugal force, due to the speed at which the blade is rotating, trying
to throw the blade outwards. These two forces—the bending force and the
throwing-out force—are at maximum in the largest blade wheel at the LP exhaust end
of the turbine. Thus, the stresses which these forces impose limit the size of the
blades and the diameter of the last wheel. This limitation is one of the reasons why
turbines are designed with double flow in the LP cylinder.
In the double flow design, steam enters at the centre of the rotor with half of the
steam flowing to the front of the machine and half flowing toward the rear of the
machine. This design can handle double the flow of steam compared to a single flow
with the same diameter of blading.
2. Sketch and describe a dummy piston used to counteract thrust forces in a steam
turbine.
There is a pressure drop across each row of blades in a reaction turbine, and a
considerable force is set up, which acts on the rotor in the direction of the steam flow.
In order to counteract this force and reduce the load on the thrust bearings, dummy
pistons are designed as part of the rotor at the steam inlet end. The dummy piston
diameter is calculated so that the force of the steam pressure acting upon it in the
opposite direction to the steam flow balances out the force on the rotor blades in the
direction of the steam flow. The size of the dummy piston is designed to keep a small
but definite thrust towards the exhaust end of the turbine. A balance pipe is connected
from the casing, on the outer side of the balance piston, to a tap-off point down the
cylinder. The differential pressure remains constant at varying steam flow conditions.
Page 567
Dummy Piston and Balance Pipe
3. Sketch and describe a velocity-vector diagram for impulse moving blading.
Turbine Blade Velocity-Vector Diagram
The letters used in the turbine blading diagrams are from the Greek alphabet:
α
Alpha
β
Beta
δ
Delta
γ
Gamma
Explanation of Terms in the Above Diagram
Vl represents (in magnitude and direction) the steam leaving the nozzle.
This becomes the steam inlet to the moving blade.
Page 568
α
is the angle of the axis of the nozzle with the direction of blade
movement.
Vb
is the blade velocity.
VRl
(Velocity, relative, inlet) is the resultant of V1 and Vb and represents
the velocity and direction of the incoming steam relative to the moving
blade.
β
is the inlet angle of the blade. Note that this angle matches the
incoming steam direction exactly so the steam enters the blades
without shock.
The above angles and sides form the inlet blade velocity diagram.
Another triangle is formed by the conditions obtained at the moving blade outlet as
follows:
VR2 represents the steam leaving the blade. VR2 is measured relative to the
moving blade. The only reduction in magnitude of this steam velocity
will be that due to friction as the steam passes over the blade. The
direction of steam leaving the blade (angle γ ) depends upon the shape
of blade used.
γ
is the exit angle of the blade.
Vb
represents the blade speed (this is identical with Vb in the inlet
triangle).
V2
is the resultant of VR2 and Vb and represents the absolute steam-exit
speed and direction. The term absolute is used when a measurement is
made with reference to a fixed object, in this case the fixed parts of the
turbine. The fixed parts are the casing or the fixed blades. The term
relative is used when a measurement is made with reference to a
moving object, in this case the moving blades.
δ
is the angle at which the steam leaves the moving blade, referred to a
fixed point. Hence, this is its angle of approach to the next row of
fixed blades.
Page 569
4. a) What is the difference between an extraction turbine and a bleeder turbine?
b) What are typical applications for these types of turbines?
a) In some condensing turbines not all of the steam passes through to the exhaust.
Part of the steam is extracted, or bled off, at one or more points. After doing some
work by expansion, the extracted steam is used to heat the feedwater. This cycle,
which uses bled steam to heat feedwater, is called a regenerative cycle and the
turbine is called a bleeder turbine.
Similarly, steam may be drawn off at one or more points at different pressures for
process steam. This requires automatic control of the steam quantity supplied to the
lower pressure section of the turbine. This arrangement is termed automatic
extraction in contrast to bleeder turbines, where the pressure at the bleed points varies
with the steam flow through the turbine. Bleed points range in number from one to
eight, but extraction generally requires only one or two pressure levels.
b) The steam from a bleeder turbine is used to heat feedwater in a boiler feedwater
heater. Steam from an extraction turbine supplies at a lower pressure for process
use.
5. When would a turbine be constructed using a double casing? Explain.
Double casings are used for very high steam pressure applications. The highest
pressure is applied to the inner casing, which is open at the exhaust end. The turbine
inner casing exhausts to the outer casing. The pressure is divided between the
casings, and more importantly, so is the temperature. The thermal stresses on casings
and flanges are greatly reduced.
6. a) Describe a disc type of turbine rotor.
b) What is a common application for this type of rotor?
a) The disc rotor is constructed of a number of separately forged discs or wheels.
The hubs of these wheels are shrunk or keyed onto the central shaft. The outer
rims of the wheels have grooves machined to allow for attaching the blades.
Suitable clearances are left between the hubs to allow for expansion axially along
the line of the shaft. Disc rotors are also referred to as built-up rotors.
Under operating conditions, the temperature of the wheels rises faster than that of the
shaft. This might tend to make the wheel hubs become loose. To avoid any such
danger, care is taken during construction of the rotor to ensure the wheels are shrunk
on tight and correctly stressed. Fig. 14 illustrates a disc type of rotor which is the type
used in the LP cylinder of most designs of large turbines.
b) Disc type rotors are used in the LP cylinder of most designs of large turbines.
7. What are three types of shaft seals used on steam turbines?
Page 570
The following types of shaft seals are used on steam turbines:
• Carbon Rings
• Labyrinth Seals
• Water Seals
8. a) What are two methods of lubricating steam turbine bearings?
b) What applications would be suitable for each type?
a) Two methods of lubricating steam turbine bearings are:
• Ring oiled
• Pressure fed
b)
Most small mechanical-drive turbines are fitted with ring-oiled bearings.
Large turbine main bearings generally consist of shells split horizontally and
lined with an anti-friction bearing metal. The bearings are enclosed in a
housing to which a generous supply of oil is pumped by the circulating pump.
This oil is delivered to the bearing, and chamfers and oil grooves assist in its
even distribution along the length of the journal.
9. Steam flows from a nozzle of a simple impulse turbine at a velocity of 550 m/s
and an angle of 21° to the direction of blade motion. Blade velocity is 220 m/s.
Neglecting blade friction, and with equal blade inlet and outlet angles, calculate:
a) The blade inlet angle so that the steam will enter without shock (V2).
b) The magnitude and direction of the absolute velocity of the steam leaving the
blades.
Solution
The combined velocity-vector diagram representing the conditions must first be
drawn.
Impulse Blading Vector Diagram
Page 571
Given data:
V1 = 550 m/s
Vb = 220 m/s
α = 21°
VR 2 = VR1
γ =β
Values X 1 and X B are added to the diagram for ease of reference and to simplify the
trigonometric calculations.
(a) Blade inlet angle so that the steam will enter without shock ( V2 ).
Vw1 = V1 × cos α
Vw1 = 550 m/s × cos 21°
Vw1 = 550 m/s × 0.9336
Vw1 = 513.47 m/s
V f 1 = V1 × sin α
V f 1 = 550 m/s × sin 21°
V f 1 = 550 m/s × 0.3584
V f 1 = 197.10 m/s
X I = VW 1 − VB
X I = 513.47 m/s - 220 m/s
X I = 293.47 m/s
β = tan -1
V fl
XI
⎛ 197.10 m/s ⎞
⎟
⎝ 293.47 m/s ⎠
β = tan -1 (0.6716)
β = 33° 53' (Ans.)
β = tan -1 ⎜
(b) Magnitude and direction of the absolute velocity of the steam leaving the blades.
Blade outlet angle γ = Blade inlet angle β
γ = β
Blade outlet angle γ = 33° 53' ( Ans.)
Page 572
Since VR 2 = VR1
X B = X1
Then But X 1 = 293.47 m/s
X B = 293.47 m/s
VW 0 = X E - VB
VW 0 = 293.47 m/s - 220 m/s
VW 0 = 73.47 m/s
VFB = VF 1
But VF 1 = 197.10 m/s
VFB = 197.10 m/s
From Pythagoras's theorem:
V2 = VFB 2 + VWO 2
V2 = (197.10 m/s) 2 + (73.47 m/s) 2
V2 = 38848.41 + 5397.84
V2 = 44246.25
Magnitude of steam velocity V2 = 210.35 m/s (Ans.)
10. Steam leaves the fixed blades of one stage of a reaction turbine at 122 m/s with
an exit angle of 23°. The moving blades travel with a linear speed of 88 m/s and
the steam consumption of the turbine is 1.1 kg/s.
a) Calculate the entrance angle of the blades
b) Horsepower developed in one turbine stage (assume 50% reaction blading).
Page 573
Solution
Vector Diagram
a) Given:
V1 = 122 m/s
Vb = 88 m/s
∠α = 23°
Reaction (or 50% reaction) blading has identical moving and fixed blades. The angles
and vectors around point A are duplicated around point B . The angle required is β.
DB
cos 23° =
V1
Chapter 2
DB =V1 cos 23°
DB = 122 m/s × 0.9205
DB = 112.30 m/s
DA = DB - AB
DA = 112.30 m/s − 88
DA = 24.30 m/s
sin 23° =
CD
Vl
CD = V1 sin 23°
CD = 122 m/s × 0.3907
CD = 47.67 m/s
Page 574
CD
DA
47.67 m/s
tan β =
24.30 m/s
tan β = 1.9617
tan β =
Entrance angle of the blades β = 62° 59' ( Ans.)
The total change in the velocity of whirl is required for calculations of work done on
the blading as detailed earlier. This is represented by the length CE on the diagram:
CE = DA + AB + BF (because CD and EF are perpendiculars)
b) If the diagram is symmetrical about its centre:
then DA = BF
and CE = 2 × DA + AB
But AB is blade speed 88 m/s and DA = 24.30 m/s
CE = 2 × DA + AB
CE = ( 2 × 24.30 m/s ) + 88 m/s
CE = 48.60 m/s + 88 m/s
CE = 136.60 N
Force exerted on blading = w × a (newtons )
Force exerted on blading = kg steam/s × change in velocity, m/s 2
Force exerted on blading = 1.1 kg/s × 136.60 m/s
Force exerted on blading = 150.26 N
Horsepower developed = force × bleed speed, Nm/s
150.26 × 88m/s
Horsepower developed =
1000
Horsepower developed = 13.22 kW ( Ans.)
11. Steam is supplied to a turbine at a pressure of 10 250 kPa and 500°C. It is then
expanded adiabatically and without friction to a backpressure of 15 kPa. It is
condensed at this pressure and returned to the boiler by a feedwater pump.
Neglecting the pump work, calculate:
a) Heat supplied per kg of steam
b) Work done by turbine per kg steam
Page 575
c) Thermal efficiency
Solution
(a) Enthalpy per kg of steam:
10 250 kPa, 500°C = 10 000 kPa, 500°C +
250
(11 000 kPa, 500°C -10 000 kPa at 500°C )
1000
250
( 3361.0 kJ/kg - 3373.7 kJ/kg )
1000
250
10 250 kPa, 500°C = 3373.7 kJ/kg +
( -12.70 kJ/kg )
1000
10 250 kPa, 500°C = 3373.7 kJ/kg − 3.175 kJ/kg
10 250 kPa, 500°C = 3370.53 kJ/kg
10 250 kPa, 500°C = 3373.7 kJ/kg +
Enthalpy Water at 15 kPa = 225.94 kJ/kg
Heat supplied = 3370.53 kJ/kg - 225.94 kJ/kg
Heat supplied = 3144.59 kJ/kg ( Ans.)
(b) Work done by turbine per kg steam:
Page 576
Entropy:
250
(11 000 kPa, 500°C − 10 000 kPa, 500°C )
1000
250
10 250 kPa, 500°C = 6.5966 kJ/kg +
( 6.5400 kJ/kg - 6.5966 kJ/kg )
1000
250
10 250 kPa, 500°C = 6.5966 kJ/kg +
( -0.0566 kJ/kg )
1000
10 250 kPa, 500°C = 6.5966 kJ/kg - 0.0142
10 250 kPa, 500°C = 6.5824 kJ/kg
10 250 kPa, 500°C = 10 000 kPa, 500°C +
1 kg water at 15 kPa = 0.7549 kJ/kg
Difference = change in entropy
Difference = 6.5824 kJ/kg - 0.7549 kJ/kg
Difference = 5.8275 kJ/kg
Ta = absolute temperature of steam at 15 kPa
Ta =53.97°C+273
Ta = 326.97 K
Heat rejected = Ta × Change in entropy
Heat rejected = 326.97 K × 5.8275 kJ/kg
Heat rejected = 1905.42 kJ
Work done = 3144.59 kJ/kg - 1905.42 kJ/kg
Work done = 1239.17 kJ/kg (Ans.)
(c) Thermal efficiency:
work done
heat supplied
1239.17
Rankine Cycle Thermal Efficiency =
× 100
3144.59
Rankine Cycle Thermal Efficiency = 0.3941×100
Rankine Cycle Thermal Efficiency = 39.41% (Ans.)
Rankine Cycle Thermal Efficiency =
Page 577
Chapter 2 Solutions
Steam Turbine Auxiliaries and Control
1. What is a thrust adjusting gear used for?
The efficiency of reaction turbines depends upon the close clearances between the
stationary and moving blades. To protect the axial seals, an adjustable thrust bearing
is used. The thrust block is cylindrical and fits like a piston in the cylinder. The thrust
block can be adjusted axially. The axial position of the rotor is controlled within
strictly defined limits. During startup, the thrust block is moved against a stop in the
direction of the turbine exhaust. This setting is for maximum clearance between the
stationary and moving blades so that uneven temperatures during startup do not cause
rubbing. When the turbine is heated up and loaded, the thrust block is adjusted to
reducing the clearances to minimum clearance producing maximum efficiency.
2. When is a turning gear used? When starting up a turbine, at what point is the
turning gear shut off?
When a turbine is left cold and at a standstill, the mass of the rotor tends to cause
the rotor to sag slightly. This is called bowing. If left at a standstill while the
turbine is still hot, the lower half of the rotor cools faster than the upper half. The
rotor bends upwards. This is called hogging. In both cases, the turbine is
difficult, if not impossible, to start up due to rubbing within the bearings, glands
and diaphragms. To overcome this problem, the manufacturer supplies large
turbines with a turning or barring gear. It consists of an electric motor and sets of
reducing gears that turn the turbine shaft at low speed. Once the turbine rotor is
above 40 rpm, the barring gear is shutoff.
3. Describe the difference between lubrication oil and jacking oil. What is governor
oil used for?
Lubrication Oil
Turbines are the prime movers that many plants depend upon. They must be
provided with a reliable supply of lubrication oil. The size of the turbine
determines whether to use a simple or complex lubricating system. Turbines of
less than 150 kW, used to drive auxiliary equipment, are often provided with ringoiled bearings.
Page 578
Moderate-sized turbines, particularly if driving through a reduction gear, may have
both ring-oiled bearings and a circulating system. These pressurized oil systems not
only supply oil in the form of a spray to the gears but also supply oil to the bearings
of the gearbox and the turbine.
Large turbines have circulating systems supplying oil to the:
• Turbine bearings
• Governor mechanisms
• Hydraulically operated steam throttle valves
• Bearings of the driven generators
Jacking Oil
Large turbines, with heavy rotors, are generally equipped with a jacking oil pump. It
supplies the lower part of the bearings with oil, at approximately 2 000 to 10 000 kPa,
lifting the shaft and supplying lubricating oil. Oil pressure lifts or jacks the shaft a
few millimeters, so there is no metal-to-metal contact during the initial movement of
the rotor. Jacking of the shaft reduces the load on the barring gear motor. Jacking oil
is applied before starting the barring gear and while operating the turbine at slow
speed.
Governor Oil
Governor relay oil acts as a sensitive regulating medium. It transmits oil pressure
signals to various parts of the governor oil system.
4. Explain static and dynamic balancing. When is each type used?
Static balancing involves supporting the shaft journals on transverse “knife edges.
Rotors are statically balanced at rest. The tendency of the rotor to roll is measured.
Then mass is added or removed to delete the tendency to roll.
Dynamic balancing is done after the static process in a machine with flexible bearing
supports. The rotor is run up to speed by an electric motor, and vibrations are
measured. Mass is added or removed to the rotor before it is retested. The process is
repeated until the vibration readings are in an acceptable range. The balanced rotor
must have very low vibrations when running at designed speed. New rotors are
balanced at the factory. Overhauled or refurbished rotors must also be dynamically
balanced.
Page 579
5. Describe the two distinct functions of a trip and throttle valve.
Trip and throttle valves have the following two separate and distinct functions:
• When a safety device such as an overspeed governor manually or
automatically trips the trip and throttle valve, it acts as a quick-closing
valve
• It also operates as a hand throttle valve for starting and bringing the
turbine up to speed.
6. What are the three methods of speed-sensitive governing used for steam
turbines?
Three methods of speed-sensitive governor are:
• Nozzle
• Throttle
• Bypass or overload
7. What is coupling “lock up”? What types of problems does a locked coupling
cause?
Couplings can lock up (fail to move) transferring axial movement through the shaft.
This can cause overloading of thrust bearings and vibration problems.
8. When are speed reduction gears used? List some applications using speed
reduction gears.
Steam turbines operate at speeds higher than the required operating speed of the
driven machine. Reduction gear sets are used to reduce the shaft speed of the turbine
to suit that of the machine being driven.
Applications using speed reduction gears include turbine-driven:
• Direct-current generators
• Paper making machines
• Centrifugal pumps
• Blowers and fans
Page 580
9. Describe a steam turbine grid type extraction valve.
Grid type extraction valves are placed inside the turbine casing after the stage that the
steam is extracted from. It controls the flow of steam to the remainder of the turbine.
The valve consists of a ported stationary disc and a ported grid that rotates. When the
openings in the disc and the grid coincide, the valve is open and a full flow of steam
passes to the remainder of the turbine. When the grid is rotated from the fully open
position, the ports in the disc are partially covered by the grid. The steam flow is
restricted and the desired pressure maintained. A pilot valve, operated by a pressure
governor, controls the oil or steam supply pressure to either side of the operating
piston. The operating piston rotates the grid valve with a gear and teeth. The linkage
from the pressure governor is interlocked with the speed governor. Changes in the
rate of steam extraction do not interfere with the turbine speed.
10. List five variables that are monitored by supervisory equipment. What is
differential expansion?
Five variables that are monitored by supervisory equipment are:
• Machine speed
• Bearing temperatures
• Vibration detection
• Differential axial expansion
• Generator output
Differential Expansion
Differential expansion refers to the relative difference in expansion between the rotor
and the turbine case. If excessive, it will lead to the rotor blades rubbing the turbine
diaphragm.
11. Sketch and describe a magnetic speed sensor pickup used on an electronic
turbine overspeed trip system.
In the following figure, the turbine shaft contains a notched gear wheel. Inductive
sensors, also known as magnetic speed pickups, are mounted in or on the turbine
casing. As the gear teeth pass the sensors, the principle of magnetic induction
generates an AC voltage that can be read by the ECM (Electronic Control Module),
which contains pulse-counting sensors.
These units then convert the electronic pulse signals to revolutions per minute for
calculating the turbine shaft speed. Some steam turbines’ overspeed trip systems,
installed with three magnetic speed pickups, require that two out of the three sensors
agree the unit has reached the overspeed condition before a trip is initiated.
Page 581
Magnetic Speed Pickup Sensor
Page 582
Chapter 3 Solutions
Steam Turbine Operation and Maintenance
1. Explain why different balancing procedures are used for solid and builtup
rotors.
Methods for balancing built-up and solid rotors differ because of their construction.
With the built up rotors, each wheel or disc is added separately to the shaft. Each
wheel is temporarily fitted to a small shaft where they are statically balanced. Metal
is usually removed from the wheel or disc to balance it. The balanced wheels are then
attached to the permanent rotor.
When all the wheels have been attached, the rotor is then dynamically balanced. Any
remaining parts are added to the rotor. These parts include the thrust bearing disc and
the overspeed trip assemblies. Then a final dynamic balance is done. The rotor is then
ready for installation.
2. Using a simple sketch, explain what is meant by turbine blade clearances. Why
is it important to keep the clearances as close to original specifications as
possible?
The efficient operation of a turbine depends to a large extent on the maintenance of
the correct clearances between fixed and moving elements. Excessive clearances
result in increased steam consumption while reduced clearances may result in blade
rubbing.
When a turbine is erected the clearances are carefully set and a record is kept at the
plant. When the top halves of the casing are removed the clearances should be
checked against the record. Care must be taken to ensure that the rotors are in the
running position when taking measurements. Provision is usually made to move the
rotor axially to a position for lifting from and returning to the casing.
Particular care is necessary with the clearances at the velocity stages which are
frequently fitted to the high-pressure end of impulse machines, as shown in the
following figure. A thorough check of clearances is essential if any replacement
blades, nozzles or packing rings have been fitted.
Page 583
Velocity Stage Clearances
3. What are two types of turbine blade deposits? How do they affect turbine
performance?
Deposits develop from carryover in the steam from the boilers and are principally
sodium hydroxide (caustic soda) and silica.
Caustic soda melts at 315°C and is soluble in water, hence it will deposit in areas in
the turbine where the temperature is below 315°C and where the steam moisture
content is insufficient to give a blade-washing effect.
Silica vaporizes at pressures above 4150 kPa and is insoluble in water. Deposits of
silica may be spread through the turbine blading and will also combine with the
soluble deposits.
Turbine blading must be maintained in a clean condition if it is to produce the full
designed output of the turbine. Deposits which adhere to the blades decrease the
turbine efficiency and output. They may cause an outage or even mechanical damage
if not removed. Deposits on turbine blades will gradually reduce the steam passage
area and consequently increase the pressure drop through each of the affected stages.
Page 584
4. Why would a steam turbine be slow-rolled before the speed is increased to
minimum governor speed?
Turbines, especially those with no barring gear, are slow-rolled at 300-500 rev/min.
Rotate at this speed for sufficient time to provide even warming and removal of any
distortion of the rotors that were developed after the last shutdown. This may take 1530 minutes or longer.
5. What important safety device is checked before putting a turbine on load?
When the machine has reached normal running speed and is under control of its
governor, the overspeed governor trip operation is tested.
6. Explain the difference between a hot start and a cold start in relation to a steam
turbine start-up.
The longer the downtime the colder the turbine casings and rotors become. They
require more time to be heated to operating temperatures. An 8 hour start would be a
typical hot start; a warm start takes approximately 48 hours while a cold startup takes
150 hours.
7. When starting a steam turbine, when would the barring gear be disengaged?
Why is this important?
The barring gear is disengaged and shutdown when the turbine speed reaches 200300 rev/min, depending upon the manufacturer’s run-up program. The barring gear is
not designed to run at the normal operating speed of the turbine. It is only used to
rotate the turbine rotor at a slow speed to allow uniform cooling.
Page 585
8. Sketch a condensing steam turbine with feed water heaters. For simplicity show
only one HP feedwater heater and one LP feedwater heater as well as the
deaerator.
Condensing Turbine with 7 Stages of Feed Water Heating
9. What are the things monitored on a steam turbine during normal operation?
The items listed on the daily log will vary with the plant, but a typical set of readings
would give:
• Machine load
• Steam pressures and temperatures
• Lubricating oil pressures and temperatures
• Turbine expansion
• Vibration readings
• Condenser vacuum
• Condenser hotwell level and position of level control valve
• Circulating water pressure and temperatures
• Feed heater pressures and temperatures
• Ammeter readings for extraction pumps and feed pumps
• Notes on the oil coolers and air ejectors in service
• Normal positions of condenser circulating water valves
• Records of the steam flow to the machine and the make-up water passing to
the condenser.
Page 586
Chapter 4 Solutions
Steam Condensers
1. Define the following terms:
a)
b)
c)
d)
Low-level jet condenser
Barometric condenser
Parallel flow
Counter flow
a) Low-level jet condenser is a jet condenser that has to use a pump to remove
the condensate from the condenser body.
b) Barometric condenser is a jet condenser which has the condenser body set at
sufficient height above the hotwell that the water will flow out by gravity.
c) Parallel flow is a jet condenser where the air and other gases flow together
with the condensate into the hotwell.
d) Counter flow is a jet condenser where the air and other gases are removed
from the top condenser body, while the condensate flows down to the hotwell.
2. Describe the term Regenerative, as it applies to a surface condenser.
Regenerative is the term used to describe a condenser design that uses wide tube
spacing and has open spaces or steam lanes to allow the entering steam to penetrate
through the tube nest and come into contact with the condensate falling from the
upper tubes. By this means the condensate temperature is maintained equal with the
exhaust steam.
3. What are the advantages and disadvantages of a jet condenser as compared to a
surface condenser?
Advantages of the jet condenser are:
• Simple construction
• Low initial cost
• Occupies less space
• Can be usefully employed where the quantity of steam to be condensed is
moderate
Page 587
Disadvantages of jet condensers are:
• Cooling water has to be the same quality as the boiler feedwater
• Vacuum achieved is limited to 660 to 685 mm which is not sufficient for a
turbine, therefore, they find limited use
4. What are the two methods used to deal with the expansion between the turbine
exhaust flange and the condenser?
In small installations this is done by bolting the condenser feet rigidly to the
foundations and fitting an expansion joint such as a corrugated bellows piece between
the turbine exhaust flange and the condenser inlet flange.
For large installations the condenser is bolted to the turbine exhaust flange and
supported on springs, which are so proportioned as to just support the mass of the
condenser when operating full of cooling water and so relieve the turbine exhaust of
any thrust.
5. a) Explain the impact that tube fouling has on the performance of a condenser.
b) Explain the impact that air leakage has on the performance of a condenser.
a) If tube fouling occurs, the cooling water will not be able to absorb heat as well as
it should. The cooling water outlet temperature will go down and the exhaust
steam temperature will rise due to a diminishing vacuum. Thus a widening gap
between the exhaust steam and cooling water outlet temperatures.
b) It increases the condenser pressure and hence the turbine back pressure. It tends to
cling to the outsides of the condenser tubes and impede the heat flow from steam
to cooling water, and it lowers the condensate temperature.
Page 588
6. A condenser receives 20,000 kg/hr of dry saturated steam at 36.2ºC. The
condensate outlet temperature is 34.6ºC. Calculate the thermal efficiency for this
condenser.
1.2
( H g at 40°C - H g at 35°C )
5
1.2
H g at 36.2°C = 2565.3 kJ/kgK +
( 2574.3 kJ/kgK - 2565.3 kJ/kgK )
5
H g at 36.2°C = 2565.3 kJ/kgK + 0.24 ( 9 kJ/kgK )
H g at 36.2°C = H g at 35°C +
H g at 36.2°C = 2565.3 kJ/kgK + 2.16 kJ/kgK
H g at 36.2°C = 2567.46 kJ/kgK
1.2
( H f at 40°C - H f at 35°C )
5
1.2
H f at 36.2°C = 146.68 kJ/kgK +
(167.57 kJ/kgK - 146.68 kJ/kgK )
5
H f at 36.2°C = 146.68 kJ/kgK + 0.24 ( 20.89 kJ/kgK )
H f at 36.2°C = H f at 35°C +
H f at 36.2°C = 146.68 kJ/kgK + 5.02 kJ/kgK
H f at 36.2°C = 151.69 kJ/kgK
2567.46 kJ/kgK -151.69 kJ/kgK
2567.46 kJ/kgK
2415.77 kJ/kgK
Condenser Thermal Efficiency =
2567.46 kJ/kgK
Condenser Thermal Efficiency = 0.9409
Condenser Thermal Efficiency =
Condenser Thermal Efficiency = 94.09% ( Ans.)
7. Explain the procedures used to troubleshoot condenser performance.
To properly observe the performance of a condenser, the operating parameters must
be monitored. The required readings or parameters used to determine condenser
performance are the:
• Condenser vacuum
• Temperature of the steam entering the condenser
• Temperature of the condensate leaving the condenser
• Cooling water inlet and outlet temperatures
Page 589
These readings are compared with the original readings taken when the condenser
was first put into service. When the condenser is new, the temperature of the steam
exhaust, the condensate, and the cooling water outlet are relatively close. A graph
(like the one in Fig. 17 – Objective 3) is developed to show the reduction of the
condenser vacuum. Comparisons of these various readings indicate whether the
performance of the condenser is deteriorating. In order to troubleshoot condenser
performance issues, the following four items are examined:
• Terminal difference
• Loss of vacuum
• Air leaks
• Insufficient circulating water
Terminal Difference
A comparison of the temperature differential or difference between the exhaust steam
temperature and the cooling water outlet is called the condenser terminal difference
and this figure is sometimes used as a guide to condenser fouling.
Loss of Vacuum
The most frequent cause of low vacuum is slime and mud on the waterside of the
tubes. This acts as an insulator and slows down the rate of heat transfer from steam to
circulating water. Increased partial pressure due to uncondensed steam adversely
affects the vacuum and the temperature at turbine exhaust rises. The temperature of
the condensate also rises because the vacuum has dropped. There is no sub-cooling of
the condensate because the heat cannot be transmitted through the condenser tubes.
In this case, both the steam exhaust and condensate temperatures rise above normal
operating conditions and the cooling water outlet temperature is low.
Air Leaks
Increased air leakage into the condenser vacuum creates a widening difference
between the temperature of the exhaust steam and the temperature of the condensate.
Another way to determine if there is an increase in air infiltrating the condenser is to
compare the readings taken from the air flow meter. Faulty air extraction also
compounds the problem of air leakage.
Page 590
Insufficient Circulating Water
A lack of sufficient cooling water reduces the vacuum. If the cooling water system
has a flow meter and accumulator, the amount of cooling water flow can be
determined for a given period of time. If the amount of cooling water flow is lower
than usual, the reason for the reduced flow must be resolved. If the normal pump
motor amperes are known, a drop in load on the pump monitor may indicate the
reduced flow. An increase in the temperature differential between the cooling water
in and out temperatures also indicates reduced flow. If the tubes are clean, the heat
transfer rate is normal, and then the reduced quantity of cooling water is raised to a
higher temperature.
8. Describe the operation of an air ejector.
Referring to the figures, HP steam delivered to the steam nozzle passes into the air
chamber with high velocity and produces an area of low pressure in its wake. Air and
other gaseous vapours drawn from the condenser into this low-pressure area, become
entrained in the jet of steam, and are carried through the diffuser to the discharge.
Page 591
9. a) Describe the operation of a dual-flow cooling water intake screen.
b) What are the advantages of this filter as compared to the through-flow filter?
a) This filter is a belt type of filter. The influent water flow goes through both
the ascending and descending filter panels, with the filtered effluent exiting
from the center of the filter. Therefore, only clean filtered water is allowed to
flow downstream to the pump. The water jets used to clean the debris from
the filter panels are above the operating floor.
b) The advantages of this filter over the through –flow filter are:
• Water passes through the filter panels only in one direction. Therefore no
chance of debris not removed by the water jets, from being dislodged by
the filtered effluent, and getting into the pumps and condenser.
• The only way debris can be carried over with this filter is if one of the
filter panels breaks.
• Debris not cleaned from the panels by the water jets simply returns to the
influent water flow, to be removed by the next cleaning cycle.
• The filter size for a given screening area can be reduced due to the debris
being removed by the ascending and descending panels. This will result in
a lower initial cost and lower total screen weight.
10. a) Give a brief description of how a cooling tower works.
b) What are the two classifications of cooling towers? Give a brief description of
each classification.
a) In all cooling towers, the water supply is introduced at or near the top and it
falls by gravity over the fill into the water reservoir at the bottom. The fill
consists of some arrangement of splash bars, generally constructed of
redwood or cypress, or cement asbestos and designed to cause the falling
water to be broken into droplets or to run across the boards in a film, the
object being to present the maximum water surface area to the cooling air.
b) The two classifications of cooling towers are:
• Natural draft
• Mechanical draft.
Page 592
Natural Draft
The natural draft has two types of designs. The first one is the open or atmospheric
type. It has walls constructed of wooden louvers or slats laid horizontally along the
length of the walls and angled so that the air enters the tower in a downward
direction. This reduces the tendency to lift the fine water spray out of the top of the
tower and gives a better distribution of cooling air across the whole cross section. The
movement of air is dependent upon natural convection currents.
The natural draft type of tower is often built with closed sides, which are carried
above the level of the water entry. This type is known as the closed or chimney type.
Mechanical Draft
The Mechanical draft also has two different types of designs. They are the:
• Forced draft
• Induced draft
Forced Draft
The forced draft method includes in its arrangement a fan placed at the bottom of the
tower to draw air from the surrounding atmosphere and force it upwards across the
fill in contra-flow to the falling water.
Induced Draft
The induced draft method is the most widely used at the present time. Advantages
over the forced draft system are:
• The fan is placed at the top of the tower and discharges upward. The air is
thereby directed away at high velocity and has little chance of
recirculating by returning to the intake at the bottom of the tower
• There is less chance of the fan being subject to icing because it is in the
path of the warm discharge air and noise from the fan is at a minimum
because of its location. Air enters the tower through a very large louver
section too, thus decreasing frost tendency in winter
• Finally, air flow and consequently the cooling effect is more evenly
distributed across all sections of the tower
Disadvantage of the induced system is the:
• Increased fan power required to handle the hot air instead of the cold air
Page 593
11. With the aid of a simple sketch, describe the operation of an atmospheric relief
valve.
Since the condenser is a closed vessel, it is possible for the back pressure to rise until
it is above atmospheric pressure. This happens, for example, if the cooling water flow
is stopped. The shell is not designed to withstand a pressure from the inside and
would soon burst. The atmospheric relief valve is designed to open when the pressure
in the condenser rises above atmospheric.
Referring to the following figure, under standard conditions, a vacuum holds the
atmospheric valve shut. A water seal, supplied with condensate, prevents air from
leaking through. When the pressure reaches 7 kPa, the force on the disc area is
greater than the water head on the reverse side, thus, the disc lifts relieving the
pressure to atmosphere. The valve is usually fitted with a pivoted lever and a chain
brought to operating level. Its operation can be checked when the machine is off load
and a manual assist can be supplied in the case of failing to open under emergency
conditions.
Atmospheric Relief Valve
Page 594
Chapter 5 Solutions
Internal Combustion Engines Components and Auxiliaries
1. Describe the steps of a four-stroke cycle for a spark ignition engine.
The four-stroke cycle occurs over two rotations of the engine. It consists of the
following steps:
Induction
As the piston moves down, air is drawn into the cylinder through the intake port. The
exhaust valve is closed. In spark-ignition engines, a mixture of air and fuel is drawn
into the cylinder — unless direct fuel injection is used.
Compression
The intake and exhaust valves are closed and the air (or air-fuel mixture) is
compressed. In spark-ignition engines, an electric spark ignites the air-fuel mixture
just before top dead centre (TDC) and starts the combustion process. In compressionignition engines, or fuel injected spark-ignition engines, fuel is injected prior to top
dead centre after which combustion occurs.
Expansion
In spark-ignition engines, combustion is largely finished at the beginning of the
power stroke. The hot gases expand and force the piston down from top dead centre.
The exhaust valve opens just before the end of the stroke. In compression-ignition
engines, combustion continues for most of the power stroke.
Exhaust
The exhaust valve remains open and the products of combustion are exhausted to the
atmosphere. At the end of this stroke, the exhaust valve closes and the intake valve
opens. The process then repeats itself.
Page 595
2. What are the differences between a spark-ignition and a compression-ignition
engine?
Spark Ignition
In spark-ignition engines, a spark ignites the air-fuel mixture. Fuel can be pre-mixed
in a carburetor or injected directly into the cylinder.
Compression Ignition
In compression-ignition engines, spontaneous ignition occurs due to the rise in
temperature caused by high compression ratios. This results in a more efficient
engine.
3. List the two types of supercharging and describe how they function.
Turbochargers
Turbochargers use a compressor which is attached to a turbine driven by exhaust
gases. Turbochargers are common on many engines even though they increase the
mechanical complexity of the engine and its control.
Superchargers
Superchargers make use of a blower or compressor that is directly coupled to the
engine. Superchargers are not common in industrial applications because they are less
efficient than turbochargers. However, they respond faster to load changes.
Superchargers usually consist of a positive displacement compressor.
4. With the aid of a simple sketch, describe the design of a lean burn fuel system
used in a spark-ignition engine system.
In a lean-burn fuel system, the main air/gas mixer (carburetor), which has a governor
controlled throttle, mixes the fuel and air. A pressure balance line between the
carburetor and main gas pressure regulator maintains a constant gas-over-air pressure
differential. The main gas pressure regulator ensures that natural gas is provided to
the main air/gas mixer, and to the prechamber air/gas mixer, at the correct pressure.
The prechamber air-fuel mixture is admitted into the cylinder through a separate
manifold and special admission valves.
Page 596
Lean Burn Fuel System
(Courtesy of Waukesha Engine)
5. Describe the three major purposes for engine cooling.
The purposes of engine cooling are to:
• Promote efficiency
• Enhance combustion
• Ensure mechanical reliability
Engine efficiency is improved when more air is inducted into the cylinder. When the
cylinder walls are cooled, more air can be drawn into the cylinder.
In spark-ignition engines, combustion is enhanced by having cooler cylinder walls
which will also inhibit knock and detonation.
Page 597
Mechanical reliability is adversely affected by high metal temperatures and thermal
strain. In addition, if the temperature of the top rings on the cylinder exceeds 200°C,
lubricants will degrade and fail to provide adequate protection. Thus, it is very
important that the cooling system function properly since it has to remove about
20%-40% of the energy input into the engine.
6. What are three aspects of oil quality that need to be monitored? (any three of)
Viscosity
Viscosity measures the resistance of a fluid to deformation under pressure. Oil with a
higher viscosity is better able to withstand the friction forces from two adjacent
components. However, friction losses are higher with a higher viscosity, so the proper
level of viscosity has to be determined for each application. Since viscosity decreases
with temperature, operating temperatures have to be taken into consideration.
Additives
Additives are present in lube oils to improve performance, to prevent deterioration,
and to combat contaminants. Common additives are:
• Detergents to clean engine surfaces by reacting with oxidation products
• Oxidation inhibitors to prevent increases in viscosity, organic acids or
other compounds
• Dispersants to prevent the formation of sludge by keeping contaminants in
suspension
• Alkalinity agents to neutralize acids
• Anti-wear agents to reduce friction
• Pour-point dispersants to counteract the formation of waxes at low
temperatures
• Viscosity improvers to increase viscosity at higher temperatures.
Acidity
Acidity must be closely controlled because acids can corrode wetted oil system
surfaces.
Contaminants
Oil quality can deteriorate over time due to heat and use. It can be contaminated
by particles caused by the internal wear of engine components, or by external
contaminants such as dirt or glycol.
Oil can also be affected by fuel contaminants such as hydrogen sulphide (H2S). If
sulphur compounds cannot be totally removed from the fuel, additional precautions,
such as enhanced oil sampling and reduced oil replacement intervals, need to be
taken. The engine manufacturer should be consulted on recommended lube oil type.
Page 598
7. Discuss four operating conditions for which engine protection is required (any
four).
General Engine Operation Protection
Protection for general engine operation may include:
• Intake air restriction caused by plugging of the intake air filter or blockage
of the intake
• High intake air temperature caused by high ambient temperature or
inadequate cooling by the intercooler (for turbocharged engines)
• Engine overspeed caused by loss of load
• High vibration caused by a number of different factors such as mechanical
failure, unbalance, or misalignment
• High crankcase pressure due to wear or failure of the piston ring or
cylinder
• High main bearing temperature caused by long term wear or high oil
temperature
Fuel System Protection
Fuel system protection may include:
• Low fuel temperature resulting from failure of the fuel heater
• High fuel pressure due to failure of the fuel regulator
• High fuel filter differential pressure due to clogging of the filter
Cooling System Protection
Cooling system protection may include:
• Low coolant level in the coolant reservoir
• High jacket water temperature due to failure of cooling or inadequate
coolant flow
• Cooler vibration due to unbalance, or misalignment of the cooler fan
Oil System Protection
Oil system protection may include:
• Low oil pressure due to failure of the oil pump or a restriction
• Low oil temperature resulting from failure of the oil heater
• Low oil level in the sump
• High oil pressure caused by failure of the oil pump relief valve
• High oil temperature caused by failure of the oil cooling system
• High oil filter differential pressure due to clogging of the filter
Combustion System Protection
Protection for combustion systems may include:
• High exhaust gas temperature (measured by a pyrometer -usually one per
cylinder)
Page 599
•
•
High exhaust gas temperature spread (difference between the highest and
lowest temperature)
Activation of a detonation sensor (usually one per cylinder)
Safety Parameters
During startup, relevant safety parameters include:
• Low starting gas pressure (for an air or gas starter)
• Excessive cranking time due to a bad starter or insufficient start pressure
• Low oil pressure caused by cold oil or failure of the prelube pump
Page 600
Chapter 6 Solutions
Internal Combustion Engines - Operation and Maintenance
1. a) Explain what inspections are carried out before starting an internal
combustion engine.
b) Explain the steps that occur during starting the engine.
a) Pre-Start Inspection
Steps required for the pre-start inspection vary with the type of startup. For automatic
starting and when the engine is in a remote location, these steps cannot be carried out
but protective devices minimize the risks in the control system.
If the equipment is used frequently and no maintenance work has been done, only a
few checks need to be carried out. These may include a walk-around and visual
inspection of the engine to check for:
• Leaks from the coolant system, especially from the pump seals, fittings, and
hoses
• Leaks from the oil system including pumps, fittings, piping, and tubing
• Coolant level
• Oil tank and sump level
• Air intake obstructions
• All guards and covers are in place and securely fastened
• General hazards
• Diesel fuel day tank levels
b) Startup Sequence
The startup sequence following depends on the type of engine and starting system.
1. To lubricate the engine, operate the prelube pump for a determined time
period after sufficient pressure is obtained.
2. If so equipped, the barring device, used to rotate the engine, should be
engaged.
3. Engage the starter, the engine cranks over, and ignition commences.
4. Once the engine operates on its own, the starter is turned off.
5. The engine operates at idle speed until it warms up.
6. Load the engine by closing the breaker to the generator.
7. If the engine cranks for a determined time period, it will shutdown on
overcrank.
Page 601
2. Describe the two types of shutdowns and the differences between them.
A shutdown is either normal or emergency.
Normal Shutdown
Upon activation of a normal shutdown, the load is reduced and the engine operates at
idle speed for 15-30 minutes. Closing the fuel valve first and shortly afterwards
(typically 10 seconds) stopping the ignition, stops the engine so that the fuel
downstream of the fuel valve is exhausted and not allowed to collect in the engine.
The prelube pump is operated for a predetermined time as a post-lube to assist with
lubrication on run-down and for cooling.
Emergency Shutdown
In an emergency shutdown, there is no cooldown period and the fuel valve closes
immediately. If the emergency does not endanger the operator or the condition of the
engine, the ignition remains on for a short period so that all of the fuel is burned and
not left in the engine and the exhaust system. For safety-related emergencies, the
ignition is stopped at the same time as the fuel valve is closed. In these cases, when
restarted, the engine should go through a purge cycle and crank for approximately 10
seconds with the fuel valve closed and the ignition system off.
3. List three examples of routine maintenance for the lubrication system.
Use any of the following tasks.
Routine maintenance of the lubrication system may include:
• Inspecting lubrication system components, piping, and hoses for leaks
• Monitoring oil levels
• Monitoring oil filter differential pressure
• Checking belt tension for pumps
• Oil sampling
• Testing relief valves
• Lube oil pressure adjustment
• Oil change
Page 602
4. What parts of the cylinder head wear with use?
Typical wear will occur with valve seats and valve guides.
5. What causes blow-by of exhaust gases into the crankcase?
Blow-by is caused either by worn piston rings, worn cylinder sleeves (or liners) or a
combination of both of these factors.
6. What are the three aspects of troubleshooting described in a typical
troubleshooting chart?
There are three aspects to troubleshooting:
a) The symptom describes what an operator might notice or detect during the
operation of the engine.
b) The probable cause lists the likely reasons for the symptom.
c) The remedy makes recommendations on how the problem may be resolved.
Page 603
Chapter 7 Solutions
Gas Turbine Design and Auxiliaries
1. What factors influence the selection of the type of gas turbine engine for a
specific application?
The selection of a gas turbine engine for a specific application depends on factors
such as:
• Performance ratings
• Weight and size restrictions
• Type of fuel available
• Maintenance support resources
• Life cycle costs
Performance Ratings
The performance rating and required range of power output are important factors to
consider when choosing a specific gas turbine. Gas turbines operate most efficiently
when running full loaded. Although they can operate down to 50% of full load rating,
the lower operating ranges will cause the turbine output efficiency to drop
substantially, down into the 30% to 40% range.
This makes it important to choose a gas turbine that operates at, or near, its maximum
power capabilities. Smaller gas turbines are less efficient, although waste heat
recovery or combined cycle applications can be very efficient. For short-term peak
power applications, a gas turbine can sometimes be run at higher than rated power
output, but this practice will reduce the life cycle of the turbine and cause an increase
in maintenance and repair costs.
Weight and Size Restrictions
Weight and size restrictions usually favour gas turbines over other types of engines,
such as reciprocating internal combustion engines, especially for higher power
applications. Aero-derivative engines normally provide the lowest-weight solution.
Type of Fuel Available
The type of fuel available needs to be considered. The cleanest and most accessible
fuel should be used. Pipeline quality natural gas is desirable because it delivers the
most efficient, cost-effective, and environmentally acceptable solution. Lower quality
gaseous fuels such as landfill or sewage gas require special handling and delivery
systems and, due to their lower kJ values, will result in lower power output and
turbine efficiencies.
Page 604
Liquid fuel, such as kerosene, provides reliable operation but may be unsuitable
where emissions are an issue, or where fuel sources are not easily accessible. Lower
grade liquid fuels may be cost-effective, but require fuel treatment and could result in
higher maintenance costs.
Maintenance Support Resources
Maintenance has to be taken into consideration before a final selection is made. This
includes the availability of skilled personnel, spare parts, and other support
requirements.
Life Cycle Costs
Life cycle costs include not only the initial capital investment, but also fuel,
operating, and maintenance costs. Simple cycle gas turbines are now efficient enough
to compete with other types of engines on a cost basis. The use of gas turbines in
combined cycle applications provides an efficient solution over the life cycle of the
engine.
When selecting a gas turbine engine, it is important to consult with manufacturers on
recommendations for proper application, engine rating, and equipment configuration.
2. With the aid of a simple sketch, describe the gas turbine thermodynamic cycle.
The gas turbine thermodynamic cycle, called the Brayton cycle, is shown in the
following figure.. It consists of four steps:
1. The air is compressed, which increases the pressure and temperature and
decreases the volume (from stage 1 to stage 2).
2. Heat is added, which results in a major increase in temperature and a small
increase in volume, but almost no change in pressure (from stage 2 to
stage 3).
3. Then, the air is expanded through the turbine and produces mechanical
work. Pressure decreases to near atmospheric level. The temperature also
decreases, although the air is still quite hot when it exits (from stage 3 to
stage 4).
4. The air is cooled to ambient conditions and returns to its original volume
and density (from stage 4 to stage 1).
Note: a significant part of the work of the turbine (W33΄) is used to run the
compressor. The remaining energy extracted (W3΄4) is available to drive the load.
Page 605
The Brayton Cycle
3. Explain the advantages of a fired HRSG system over an unfired unit.
The advantages of the fired system are that it:
• Compensates for changes in gas turbine output to give constant steam
production
• Can be used when the turbine is at low loads or not on at all to generate
steam for the facility
4. Explain the advantages for using intercooling to improve the efficiency of the
basic gas turbine cycle.
In some gas turbines, inlet air is compressed in two stages using a dual shaft
arrangement. The air is cooled between the stages in a heat exchanger, or intercooler.
Since isothermal compression (compression without an increase in air temperature)
takes less work than adiabatic compression (compression without removing heat
which increases the air temperature), more turbine power is available for the output
load. Another advantage of intercooling is that the total mass of air that needs to be
circulated through the cycle per kW of energy produced is reduced.
Page 606
5. Using simple sketches, describe the hot end and cold end drives that are used in
multi-shaft arrangements for gas turbines.
The following figure shows a fairly common aero-derivative design that uses a twoshaft arrangement for the engine, and a third shaft for the power turbine. The lowpressure compressor and turbine are connected by a shaft fitted inside the hollow
shaft connecting the high-pressure compressor and turbine. Mechanically, this design
is more complicated (especially for the bearings), but offers greater efficiency and
operational flexibility.
An even more complicated layout positions the load at the cold end, which requires
three shafts on the same centerline.
(a) Hot End Drive
(b) Cold End Drive
Shaft Layouts – Triple Shaft
6. Give a brief explanation of the following types of combustors that are used for
gas turbines:
a) Annular
b) Can-annular
a) Annular
The annular combustor consists of a singular flame tube in an annular
shape. It is smaller in size than the can burner and does not have the
problem of combustion propagation between chambers. Combustion takes
place in a single combustion liner, with an inner and outer casing, that
encircles the centerline of the gas turbine. Fuel nozzles are evenly spaced
around the ring. This is a very simple design that minimizes the
complexity of the combustion and dilution air flows.
b) Can-Annular
In the can-annular design combustor, combustion takes place in multiple
combustors (also called combustion cans) placed around the centerline of
the gas turbine. Some aero-derivative gas turbines use this straightthrough combustor design since it minimizes the front area of the turbine.
Page 607
7. With the aid of s simple sketch, describe how a refrigeration chiller is used to
increase the power output of a gas turbine.
Inlet air to the gas turbine is cooled by passing it through a finned coil of tubes which
uses either NH3 (Ammonia) or HFC-134a refrigerant as the cooling medium. The air
temperature must not be less than 5ºC to prevent the formation of ice on the coils.
Refrigeration will always provide the design inlet temperature regardless of the
ambient conditions, unlike the evaporative systems which lose effectiveness in high
humidity conditions.
Refrigeration Air Cooling System
8. a) Using a simple sketch, describe an aero-derivative gas turbine lube oil
system.
b) Discuss the use of chip detectors to detect metal particles in the oil.
a) Aero-Derivative Gas Turbine Lube Oil System
The following figure shows the lube oil system for an aero-derivative gas turbine
— the General Electric LM6000 (used for power generation). It lubricates the gas
turbine and power turbine bearings. The driven equipment is handled by a
separate system.
Page 608
General Electric LM6000 Lube Oil System
(Courtesy of GE Power Systems)
This lube oil system is divided into two sections: a supply system and a scavenge
system. To prevent corrosion, all piping, fittings, and the reservoir are Type 304
stainless steel. The lube oil used is synthetic type oil suitable for high
temperatures.
The oil reservoir contains approximately 500L in a 568L tank. It is fitted with
protective devices to guard against low oil level and low oil temperature. A
thermostatically controlled heater in the lube oil tank reservoir ensures that a
minimum oil temperature is maintained to reduce the stresses on the turbine on
startup and to keep moisture from condensing in the reservoir and contaminating
the oil.
An electric motor driven auxiliary lube oil pump is used to initially pressurize the
system and satisfy the permissives to allow the turbine to start.
A positive displacement pump, driven by an auxiliary gearbox on the engine,
provides the required pressure to the bearings. After it leaves the pump, the oil is
filtered through a duplex full-flow filter.
Page 609
The oil supply is protected by switches for:
• High oil temperature
• Low oil pressure
• High filter differential pressure
Then, the oil flows through the bearings and accumulates in the bearing sumps.
The oil temperature is measured at each scavenge line in case of bearing
problems.
Scavenge pumps (also driven by the auxiliary gearbox) provide pressure to flow
the oil from the bearing sumps through another set of filters, and then through
duplex thermostatically controlled water-cooled coolers. Then, the oil flows back
into the reservoir.
b) Chip Detectors
Chip detectors are often located in the sumps to detect metal particles. If a bearing
becomes damaged, metal particles break away and become entrained in the oil.
Chip detectors are basically magnets that attract metal particles and detect when
they accumulate. When the chip detector alarms, the detector will be removed and
the particles that have been captured by the detector will be analyzed. The
quantity and type of material collected will indicate:
• Where the problem is
• How severe the problem has become
9. Explain, with the aid of a simple sketch, a type of fuel gas system for a gas
turbine.
Fuel Gas System
The General Electric LM6000 fuel gas system is representative of most gas turbines.
A fuel gas compressor is installed in case extra compression is required to boost a
low pressure fuel source. The pressure of the fuel gas has to be higher than the
pressure of the compressed air delivered to the combustion section. A pressure
regulator and relief valve is installed to ensure that the fuel gas supply is maintained
at the correct pressure. Low and high pressure switches protect against over or under
pressure conditions.
A fuel filter ensures that contaminants do not enter the fuel system. Some systems use
heat exchangers to raise the fuel gas to its optimum temperature to ensure that:
• Complete combustion occurs in the combustor
• The gas always remains above the dew point temperatures of the heaviest
constituents in the fuel gas
Page 610
A fuel gas flow meter monitors fuel consumption, but is not used for fuel control.
Fuel is metered and controlled by the fuel metering valve, one of the most important
components of the fuel gas system. It is also an essential component of the startup
and shutdown sequence. Fuel valves are normally electrically controlled with
hydraulic actuation, but electrically actuated valves are becoming more common. The
fuel metering valve ensures that the correct amount of fuel is provided according to
the operating conditions. It precisely controls the flow of fuel to ensure that
maximum turbine temperature is not exceeded. The rate at which the fuel valve is
opened and closed is limited to prevent temperature increases that might damage the
turbine. Additional shutoff valves are provided for emergency purposes.
General Electric LM6000 Fuel Gas System
(Courtesy of GE Power Systems)
Page 611
10. With the use of simple equations, describe how ammonia is used in the catalytic
reduction of NOx emissions from the exhaust gases of a gas turbine.
NOx emissions are removed from the burner exhaust gases through the use of a
catalyst. In one process, ammonia is added to the flue gas prior to the gas passing
over a catalyst. The catalyst enables the ammonia to react chemically with the NOx
converting it to molecular nitrogen and water. The catalyst used is a combination of
titanium and vanadium oxides. This system promotes the removal of up to 90% of
nitrogen oxides from the flue gases.
The ammonia reacts with both the nitrogen monoxide (NO) and nitrogen dioxide
(NO2)
Reaction with NO:
4 NO + 4 NH 3 + O2 = 4 N 2 + 6 H 2O
Reaction with NO2:
2 NO2 + 4 NH 3 + O2 = 3N 2 + 6 H 2 0
The NO and NO2 react with the ammonia to form nitrogen and water. The nitrogen is
harmless and can be released back into the atmosphere.
Page 612
Chapter 8 Solutions
Gas Turbine Operation and Control
1. Describe the functions of a gas turbine control system.
The major function of a control system is to ensure correct sequencing during startup
and shutdown. The control system must safely control the flow of fuel to the
combustors to ensure that the gas turbine efficiently drives the process load under all
conditions. It positions the fuel metering valve based upon load or demand (e.g.
generator frequency or compressor discharge pressure).
Changes in demand loading requires a very controlled “ramp up” or “ramp down”
response from the gas turbine control system as a rapid increase or decrease in
acceleration can cause surge, flame out or other combustion problems..
Depending on ambient temperature, there are maximum limits to operation. At higher
ambient temperatures, a gas turbine is limited by exhaust gas temperature to ensure
that temperature limits for combustion and turbine section components are not
exceeded. At lower ambient temperatures, a gas turbine is limited by rotor speed to
regulate the stresses placed on rotor blades. For dual shaft gas turbines, there are
minimum and maximum limits on power turbine speed.
Additional controls are required for bleed valves and variable guide vanes.
Sometimes, these controls are independent, but it is becoming common to include
them in the main gas turbine control system. Both bleed valve and variable guide
vane operations are controlled by the main gas turbine controller using a calculation
embedded into the logic sequencing that matches their positions to a specific startup
time line and engine speed.
Another function of the control system is to indicate when abnormal levels are
reached by generating an alarm, or by shutting down the gas turbine under certain
conditions.
Page 613
2. List the monitoring points that are associated with the following gas turbine
system protection.
a) Oil
b) Combustion
a) Oil
Oil system protection includes:
• Low oil pressure (fast shutdown)
• Low lube oil tank temperature (alarm only)
• High lube oil header temperature (alarm and fast shutdown)
• High bearing temperature (alarm and fast shutdown)
• Low oil level (alarm and shutdown)
• High oil filter differential pressure (alarm only)
b) Combustion
Combustion protection includes:
• High exhaust gas temperature (fast shutdown)
• High exhaust gas temperature spread (alarm only)
• Loss of flame (fast shutdown)
• Ignition failure on startup (fast shutdown)
3. What steps are followed to prepare a gas turbine for startup?
If the equipment is used frequently and maintenance work has not been done recently,
only a few checks are required. These may include a walk-around and visual
inspection of the engine to check for:
• Leaks in the oil system (including pumps, fittings, piping and tubing)
• Oil tank and sump level
• Air intake obstructions
• Correct placement and secure fastening of all guards and covers
• General hazards
If the equipment has been shut down for an extended period of time, the operator
should check that all the following auxiliary equipment and support systems are
activated and energized:
• Electrical
• Pneumatic
• Fuel
• Instrumentation
• Lubrication
• System controllers
Page 614
These systems may have been shutdown and need to be activated before the startup is
initiated.
If routine, minor, or major maintenance has been done recently, the work area has to
be cleaned and all tools, parts and supplies removed prior to startup. Shutoff valves
may need to be opened or unlocked. Other maintenance-specific steps may need to be
taken, and a more thorough pre-start inspection may be required.
4. Describe the steps to be followed in the normal shutdown of a gas turbine.
The first step in a controlled shutdown is to reduce the speed, over a specified period
of time, down to “zero load speed”. As the speed is being reduced, the load on the
turbine (electric generator or gas compressor) will be reduced and the entire unit will
be allowed to cool down under even and stable conditions. Once at idle speed, the
power turbine wil be unloaded completely by disconnecting from the main electrical
grid or fully opening the recycle valves if the load is a gas compressor. During this
cool down period, the turbine can be quickly loaded back up if the need arises.
When the cooldown timer timeframe has been completed or the specific minimum set
temperatures across the machine have been reached, the fuel valve is closed and
combustion is eliminated. The rotor speed will decrease and the machine will stop.
As the speed drops, the main lube oil pump (if driven off the rotor) loses pressure. At
a specified point, usually based on oil pressure, the prelube pump starts and continues
to lubricate and cool the bearings for a specified time period. The enclosure or
building fans shut off.
On most heavy-duty gas turbines, the turning gear activates at either 15% of
operating speed or immediately after the rotor stops turning. The turning gear rotates
the rotor at a slow speed for a certain time period — ranging from 5 hours for a small
gas turbine to as many as 60 hours for a very large gas turbine. Restart at any time
during this time period is allowed. This cooldown period prevents bowing of the
rotor, which would cause high vibration on the next startup and could lock-up the
rotor and prevent starter rotation.
Page 615
5. Discuss the methods used to waterwash gas turbine blades, including the type of
cleaner used.
The most effective method of compressor cleaning is the offline waterwash. This
consists of stopping the unit, injecting waterwash fluids into the intake of the
compressor while running on the starter, and then restarting the unit. It is also referred
to as the crank-soak method. Online water washing is not as effective as off-line
although it is still a viable alternative if downtime is not acceptable.
To remove oily substances, additional cleaning agents and solvents are mixed with
the water. Acceptable cleaners are often specified by gas turbine vendors. However,
the most effective cleaning agents are also the most toxic and require special
handling.
If the temperature is less than 4˚C, a 1:1 mixture of water and ethylene glycol is
recommended to prevent icing. The gas turbine vendor should be consulted since
commercial and automotive anti-freeze products are usually not acceptable.
6. Discuss the steps involved in the overhaul of an aeroderivative gas turbine.
a) The engine is placed in a vertical hydraulic pit so it can be easily dismantled.
b) All parts, especially blades, are carefully organized in trays.
c) Parts are cleaned using sandblasting, chemical cleaning tanks, and ceramic
media cleaning tanks.
d) Blades are checked for cracks by spraying dye penetrant on the blade and then
cleaning it off. The dye remains in the cracks and can be detected under
ultraviolet light.
e) A process called dispositioning is used to decide whether components should
be kept, repaired, or have to be rejected. This is based on specific criteria such
as the dimensions, type, and size of cracks, loss of coatings, and sometimes
the number of operating hours.
f) Repairs are then carried out and the engine parts are stored waiting for new
parts.
g) The rotor and blading are reassembled. This usually involves carefully
restacking the stages of the rotor to prevent unbalance.
h) The rotor is balanced in a balancing machine to ensure that vibration levels
are within acceptable limits.
i) The final re-assembly takes place by assembling rotors, casings, combustion
components and all auxiliaries mounted on the engine.
j) The engine is tested in a test cell to verify performance and check vibration
levels.
Page 616
7. Briefly outline the symptom, probable cause and remedy for a high vibration
alarm to annunciate.
Symptom
Probable Cause
Remedy
Vibration high
Problem with vibration
transducer or wiring
Check vibration
transducer or wiring
Alarm and shutdown levels not
correct
Reset alarm and
shutdown levels
Engine mountings too tight or
seized
Check engine mountings
Major engine problem or
internal failure
Perform borescope. If
necessary schedule
major overhaul
Page 617
Chapter 9 Solutions
Lubrication
1.
With the aid of a simple sketch, describe how the various cuts of oils are
separated in a fractionating tower.
Crude oil is preheated and continuously pumped into the tower at the approximate
level shown. Heat within the tower is applied by means of steam jets streaming
directly into the charge of crude oil. The crude oil boils and the vapors produced rise
into the tower. These vapors must pass through the bubble caps in each tray in their
progress up the tower and as their temperature falls, condensation of the various
constituents takes place.
Fractionating Tower
Page 618
2. Briefly describe the following:
a)
Viscosity
b)
Pour point
c)
Cloud point
d)
Flash point
a) Viscosity is a measure of the oil’s resistance to shear. Viscosity is more
commonly known as resistance to flow.
b) Pour point of an oil is the lowest temperatureat which an oil will flow.
c) Cloud point is the temperature at which dissolved solids in the oil, such as
paraffin wax, begin to form and separate from the oil
d) Flash point of an oil is the temperature to which it must be heated to give off
sufficient vapor to form an inflammable mixture with air.
3. a) Explain what occurs when lubricating oils react with oxygen.
b) Briefly describe various causes for this reaction to be accelerated.
a) When lubricating oils react with oxygen, materials are formed that impair the
qualities of the oil. Eventually they become insoluble in the oil, form sludge,
especially with water and foreign suspended matter, and promote the
formation of deposits. On continued oxidation, the oil will develop organic
acids and in severe cases the viscosity will increase significantly.
b) The reaction between oil and oxygen is accelerated by:
• Increasing the temperature
• Metallic catalysts
• Water
• Foreign suspended matter
• The oxidation products themselves
Page 619
4. Give a brief explanation of the following lubrication additives.
a) Detergent-dispersent
b) Anti-wear agents
c) Foam inhibitors
d) Rust prevention
a) Detergent-dispersent are used in crankcase oils is to keep the engine clean.
The detergent acts to maintain metal surfaces clean and prevent deposit
formation of all types, by keeping oxidation products soluble in the oil. The
dispersant acts to break down insolubles into a finely divided state so that they
will remain suspended in colloidal form in the oil. They are metallo-organic
compounds such as phosphates and sulphonates, or high molecular weight
soaps.
b)
Anti-wear agents form a film on metal surfaces by chemical action at times of
extreme high pressure, or high temperature so as to reduce the surface friction
and prevent scoring or seizure. They also will reduce or minimize wear. They
are organic compounds containing chlorine, phosphorus and sulphur. As long
as good film lubrication conditions exist in a bearing, there can be no metalto-metal contact but if the oil film is destroyed due to excess pressure or high
temperature the condition becomes one of boundary lubrication and at these
times the anti-wear additives act to reduce the resulting friction.
c)
Foam in a lubricating oil is formed by the entrainment of air bubbles. This can
occur when an oil is violently agitated in the presence of air; high viscosity
oils will have a stronger tendency to do this than the lighter oils. The additives
used are silicone polymers and they act so as to reduce the surface tension
between air bubbles so that they tend to combine into larger bubbles which
can rise to the surface of the oil and escape.
d)
Rust prevention These are used to prevent rusting of metal parts during shutdown periods or to protect equipment during storage or shipment. They
consist of sulphonates, amines, or the derivatives of some fatty acids. They act
to absorb certain active materials on a metal surface, neutralize corrosive
acids and form a protective film which repels water.
5. What are the advantages to planning the entire plant lubrication program as one
combined operation?
In almost any plant it will be advantageous to plan the entire plant lubrication as one
combined operation. Savings will be effected through the:
• Reduction in the number and variety of lubricants used
• Reduction in maintenance costs and plant-outage time
• Increased life of equipment due to proper lubrication
Page 620
6. With the aid of a simple sketch, explain the operation of a lube oil centrifuge.
In the centrifuge, centrifugal force is produced by rotating the liquid at high speeds,
up to 15 000 rev/min. This facilitates the separation of the contaminants that are
heavier than oil. Sedimentation and separation are continuous and very fast. When
liquid and solid particles in a liquid mixture are subjected to the centrifugal force in a
separator bowl, it takes only a few seconds to achieve what takes many hours in a
tank under the influence of gravity.
The centrifugal bowl is equipped with a series of conical shaped discs which divide
the feed material into layers less than .13 cm in thickness. The oil, water and solids
are fed into the top inlet A. The still mixed feed material travels down the inlet tube
(B) into the centrifuge bowl.
The feed material is forced upward through the holes in the intermediate discs (C)
and into the spaces between them. This is where the centrifugal action immediately
separates the feed material into the heavy and light phases (oil, water, and solids.)
The solids are thrown directly to the bowl wall (D). The oil, with its lighter density,
is displaced inward and travels upward through the space around the inlet tube to the
light phase discharge (E). The water phase, thrown outward by centrifugal force, is
displaced by the incoming feed material and travels upward along the outer edge of
the bowl to the heavy phase discharge (F). Solids may be retained in the bowl or
discharged immediately, depending on bowl design and operating requirements.
Page 621
Centrifugal Separation
7. With the aid of a sketch, explain the hydrodynamic theory of lubrication.
The hydro-dynamics theory of lubrication involves the complete separation of
opposing surfaces by a fluid film. The following diagrams give a graphic analysis of
this action.
Fig. (a) and (b) show a surface X moving at constant velocity across a stationary
surface Y with an oil film between the two. In Fig. (a), the X and Y surfaces are
parallel. In Fig. (b), the X surface is at a slight angle. In each case the triangle abc
represents the quantity of oil entering between the surfaces and the triangle a’b’c’ the
quantity of oil leaving.
Page 622
Hydro-Dynamic Theory
In Fig. (a), bc = b’c’, the triangles are equal, and the quantity of oil entering the
bearing equals the quantity leaving; there is therefore no upward force acting to
separate the surfaces X and Y.
In Fig. (b) bc is greater than b’c’ and ac than a’c’. Therefore triangle abc is greater
than a’b’c’. Thus more oil can enter than is able to leave and a vertical force results
which tends to separate X from Y.
In both Fig. (a) and 20 (b), there is a horizontal force shearing the oil but only in (b)
is there a resultant vertical force. This simple basic principle explains why moving
surfaces must be designed to provide a wedge if full fluid film lubrication is to be
achieved, and machinery is to carry high loads without wear.
Page 623
Chapter 10 Solutions
Piping
1. List the properties that contribute to the suitability and economy of a given pipe
material.
The following properties contribute to the attractiveness and economy of a given pipe
material:
• Ability to be bent or formed
• Suitability for welding or other methods of joining
• Ease of heat treatment
• Uniformity and stability of the resultant microstructure
2. a) Calculate the required thickness for 406.4 mm nominal size plain end
steam pipe to operate at 17 250 kPa and 540°C. The material is to be
seamless alloy steel SA-335P21.
Solution
P = 17.25 MPa (given)
Do = 406.40 mm (Table 1)
SE = 37.92 MPa (Table 1A)
y = 0.7 (Table 3)
A = 0.000
tm =
PDo
+A
2 ( SE + Py )
tm =
17.25 MPa × 406.40 mm
+0
2 ( 37.92 MPa + 17.25 × 0.7 )
tm =
7010.40
+0
2 ( 49.995 )
7010.40
+0
99.99
t m = 70.11+0
tm =
t m = 70.11 mm
Using a manufacturer’s tolerance allowance of 12.5%, then the required wall
thickness is:
70.11 x 1.125 = 78.87 mm (Ans.)
Page 624
a) Calculate the maximum allowable working pressure, in MPa, for the
nominal size plain end steam pipe in the above example.
P=
2 SE (t m − A)
Do − 2y (t m − A)
2 × 37.92(78.87 - 0)
406.40 - 2 × 0.7(78.87 - 0)
2 × 37.92(78.87)
=
406.40 − 2 × 0.7(78.87)
2 × 2990.75
=
406.40 − 2 × 55.21
5981.50
=
406.40 − 110.42
5981.50
=
295.98
= 20.21 MPa
=
3. With the aid of a simple sketch, show how the probes are located in relation to
the weld in time-of-flight diffraction.
Time-of-Flight Diffraction (TOFD)
The TOFD technique is an effective fully computerized inspection method for the
detection and sizing of flaws with a high rate of accuracy. With the TOFD technique,
which applies diffraction signals instead of reflection signals type, location, geometry
or orientation of the anomalies is irrelevant for detection and sizing. In the TOFD
technique, a transmitter and a receiver are placed on equal distances of the weld. The
scanner with the probes is moved in most cases swiftly parallel with the weld.
TOFD is utilized over the entirety of the weld seam lengths for expedient detection
and classification of inherent flaws and creep damage. The small, high intensity beam
spot achieved in this inspection has proven effective in detecting incipient creep
damage to a very early form of cavitation.
The following figure shows the typical TOFD arrangement for the detection of deepseated damage, with the probes set relatively broadly such that the intersection point
of the beam centers lies at a depth of approximately 2/3 wall. This inspection can be
implemented in a single scan pass, with the transducers straddling the weld.
Page 625
TOFD Transducer Configuration for Deep Coverage
4. Explain how high temperatures affect the tensile strength of piping.
Tensile Strength
As the temperature is increased, the properties of the pipe material will change. The
tensile strength of the material will rapidly decrease above a certain temperature. This
is indicated in Table 1A of the ASME Code, Section II, Part D. For any material
listed in this table, the working stress allowed will decrease as the temperature
increases. For example, steel pipe of material SA-53B is allowed a working stress of
103 425 kPa at 343°C. But, at a temperature of 427°C, the working stress allowed is
only 74 466 kPa.
5. Give the advantages and disadvantages of the following:
a) Expansion bends
b) Slip expansion joints
c) Corrugated expansion joints
a) Expansion Bends
Advantages of expansion bends are:
• Most trouble-free method as there is no maintenance involved
• Leakage is unlikely
• Any temperature, pressure or fluid can be handled by proper selection
of material and thickness
Disadvantages of expansion bends are:
• Require a larger amount of space
• Produce a higher pressure drop and heat loss
• More costly than expansion joints
• Produce higher end thrusts which can present problems when
connecting to equipment such as turbines and pumps.
Page 626
•
b) Slip Expansion Joints
Advantages of slip expansion joints are:
• Simple and rugged
• Capable of handling a large amount of expansion
• Minimum space required
• Produce little pressure drop and heat loss
Disadvantages of slip expansion joints are:
• Must be located where the packing can be given attention
• Problems may arise if the joint is poorly aligned or if it becomes
corroded
• Joint needs to be installed and maintained according to manufacturer’s
instructions
• Proper packing must be used
• Needs to be lubricated two or three times a year unless self lubricating packing is used.
c) Corrugated Expansion Joints
Advantages of corrugated expansion joints are:
• Require less space
• Produce less pressure drop and heat loss than the expansion bends or
loops
• Do not require maintenance as in the case of the slip type
Disadvantages of corrugated expansion joints are
• Amount of movement provided by the bellows or corrugations is less
than can be provided by the slip expansion joint
• Vulnerable to condensate corrosion during shutdown periods as the
condensate will not drain effectively
Page 627
6. Explain how the sudden closing of a valve can cause water hammer in a pipe.
Valve Operation
In the case of a valve being quickly closed in a pipeline through which water is
flowing, the first effect is the sudden decrease in the velocity of the water and a
correspondingly increase in pressure at the valve. This causes a pressure wave to
travel back upstream to the inlet end of the pipe where it reverses and surges back and
forth through the pipe, getting weaker with each successive reversal. This pressure
wave due to water hammer is in addition to the normal water pressure within the pipe
and depends upon the magnitude and rate of change in velocity as well as the
elasticity of the pipe and of the water. Complete stoppage of flow is not necessary to
produce water hammer as any sudden change in velocity will bring it about to a
greater or less degree depending upon the above conditions.
Where too rapid closing of a valve is the cause of the water hammer, the remedy is to
ensure that the valve is closed slowly. The period of effective closing of a gate valve
takes place in the last 20% of the valve travel and this portion should be undertaken
as slowly as possible. If the valve is equipped with a bypass, the bypass should be
opened to equalize the pressure on both sides of the valve. Then the bypass valve is
closed.
When opening a gate valve, the first 20% of the valve travel is the most critical
portion. If so equipped, the bypass should be opened to allow for pressure
equalization. Then the valve should be opened as slowly as possible. As a general
rule, all valves should be opened and closed slowly and cautiously.
Page 628
Chapter 11 Solutions
Mechanical Drawing
1. When is sectioning used in orthographic projections?
Showing interior details with hidden feature lines in orthographic drawings is very
difficult. For internal details in orthographic drawings, “Sectioning” is used. It is a
cutaway type of view showing internal details.
2. With reference to the following pressure vessel drawing, what is the distance
from the centre of nozzle N1 to the outside of the flange on N2?
Pressure Vessel Drawing with Dimensions
Distance from the centre of nozzle N1 to the outside of the flange on N2:
= Centre of N1 to reference line + reference line to outside of flange N2
= 1.82 m + 0.838 m
= 2.658m ( Ans.)
Page 629
3. What is the thickness of the steam drum and the mud drum in the following
drawing?
Side Elevation of Boiler and Economizer
The thickness of the steam drum is 12.38 cm.
The thickness of the mud drum is 8.57 cm.
Page 630
4. Explain the difference between a process flow diagram and a process and
instrument diagram.
Process flow diagrams are simplified schematics of a plant, or portion of a plant.
They show only the major equipment items and the major process flow streams. A
process flow diagram lists the prime function of the major equipment and the
reference numbers of the material balance table.
In most plants the mechanical flow diagram is called a Process and Instrument
Diagram or for short P&ID. Unlike the simplified process flow diagram, the
mechanical flow diagram (P&ID) includes details. The P&ID visually summarizes all
the system and process calculations that were based on flow rates, pressures,
temperatures, and general layout of the process flow diagram.
5. What lists of symbols accompanies process and instrument diagrams?
Mechanical drawings come in sets for a particular plant or section of a larger plant.
The set of drawings includes a legend showing all the following symbols used in the
drawing. This legend could include the following list of piping symbols:
• Valve Symbols - these symbols identify different types of valves such as
globe valves, plug valves, control valves, and ball valves; each type of
valve has its own symbol
• Line Symbols - these symbols identify different types of piping, such as
normal piping, instrument airlines, and instrument and electrical lines
• Flow Diagram Abbreviations - these abbreviations stand for standard
terms that are used on P&ID drawings; some examples are NO for
normally open for valves, SO for steam out, and CO for car seal open
• Miscellaneous Symbols - they are used for specific items that are not
common on all P&ID drawings; examples are spectacle blinds and
specialty piping items
Because P&ID drawings contain instrumentation data, a list of instrumentation
symbols is also included with the piping symbols.
Page 631
6. Why do process and instrument drawings refer to isometric piping drawings?
When more information than is found on P&ID drawings is needed, the isometric
piping drawings are used. The piping line numbers from the P&ID are used to
reference the isometric drawings. The isometric view shows three sides of the piping
in one practical and easy to read view.
7. Name the three forms used to draw piping spool drawings.
Piping spool drawings can be drawn the following formats.
• An isometric spool drawing.
• A single line orthographic spool drawing.
• A double line orthographic spool drawing.
8. What is a bill of material and when would it be used?
Isometric piping spool drawings reference flanges, piping and fitting details. These
materials are itemized on a bill of materials for each spool drawing. The Bill of
Materials is used for construction of the piping on the spool drawing and for repairs
to existing piping. Included on the Bill of Materials are such details as the quantity
and type of fittings, flanges, bolts and gaskets.
9. What is the difference between an isometric and an oblique drawing?
Pictorial drawings have the objective of approximating a camera snapshot. They give
the reader a three dimensional view of the object being shown. This makes it easier
to visualize the object as it would appear when constructed. Isometric and oblique
drawings are both types of pictorial drawings. In isometric drawings, the angles used
are: vertical and 30º angles to the vertical.
Oblique drawings are also pictorial three dimensional drawings. Lines are drawn
vertical, horizontal and at a 30º angle to the horizontal.
Page 632