Instrumentation Documents

Posted by Debyendu Chakraborty on Tuesday, April 9, 2013 Under: TECHNICAL

Every technical discipline has its own standardized way(s) of making descriptive diagrams, and instrumentation is no exception. The scope of instrumentation is so broad, however, that no one form of diagram is sufficient to capture all we might need to represent. This article will discuss different types of instrumentation diagrams and symbology. Click the links below to read the details:

• Process Flow Diagrams (PFDs)

• Process and Instrument diagrams (P&IDs)

• Loop diagrams (“loop sheets”)

• SAMA diagrams

• Instrument and Process Equipment Symbols

• Instrumentation Identification Tags

At the highest level, the instrument technician is interested in the interconnections of process vessels, pipes, and flow paths of process fluids. The proper form of diagram to represent the “big picture” of a process is called a process flow diagram. Individual instruments are sparsely represented in a PFD, because the focus of the diagram is the process itself.

At the lowest level, the instrument technician is interested in the interconnections of individual instruments, including all the wire numbers, terminal numbers, cable types, instrument calibration ranges, etc. The proper form of diagram for this level of fine detail is called a loop diagram. Here, the process vessels and piping are sparsely represented, because the focus of the diagram is the instruments themselves.

Process and instrument diagrams (P&IDs) lie somewhere in the middle between process flow diagrams and loop diagrams. A P&ID shows the layout of all relevant process vessels, pipes, and machinery, but with instruments superimposed on the diagram showing what gets measured and what gets controlled. Here, one can view the flow of the process as well as the “flow” of information between instruments measuring and controlling the process.

SAMA diagrams are used for an entirely different purpose: to document the strategy of a control system. In a SAMA diagram, emphasis is placed on the algorithms used to control a process, as opposed to piping, wiring, or instrument connections. These diagrams are commonly found within the power generation industry, but are sometimes used in other industries as well.

An instrument technician must often switch between different diagrams when troubleshooting a complex control system. There is simply too much detail for any one diagram to show everything. Even if the page were large enough, a “show everything” diagram would be so chock-full of details that it would be difficult to follow any one line of details you happened to be interested in at any particular time. The narrowing of scope with the progression from PFD to loop diagram may be visualized as a process of “zooming in,” as though one were viewing a process through the lens of a microscope at different powers. First you begin with a PFD or P&ID to get an overview of the process, to see how the major components interact. Then, once you have identified which instrument “loop” you need to investigate, you go to the appropriate loop diagram to see the interconnection details of that instrument system so you know where to connect your test equipment and what signals you expect to find when you do.

Another analogy for this progression of documents is a map, or more precisely, a globe, an atlas, and a city street map. The globe gives you the “big picture” of the Earth, countries, and major cities. An atlas allows you to “zoom in” to see details of particular provinces, states, and principalities, and the routes of travel connecting them all. A city map shows you major and minor roads, canals, alleyways, and perhaps even some addresses in order for you to find your way to a particular destination. It would be impractical to have a globe large enough to show you all the details of every city! Furthermore, a globe comprehensive enough to show you all these details would have to be updated very frequently to keep up with all cities’ road changes. There is a certain economy inherent to the omission of fine details, both in ease of use and in ease of maintenance.

PROCESS FLOW DIAGRAM

To show a practical process example, let’s examine three diagrams for a compressor control system. In this fictitious process, water is being evaporated from a process solution under partial vacuum (provided by the compressor). The compressor then transports the vapors to a “knockout drum” where some of them condense into liquid form. As a typical PFD, this diagram shows the major interconnections of process vessels and equipment, but omits details such as instrument signal lines and auxiliary instruments:

One might guess the instrument interconnections based on the instruments’ labels. For instance, a good guess would be that the level transmitter (LT) on the bottom of the knockout drum might send the signal that eventually controls the level valve (LV) on the bottom of that same vessel. One might also guess that the temperature transmitter (TT) on the top of the evaporator might be part of the temperature control system that lets steam into the heating jacket of that vessel.

Based on this diagram alone, one would be hard-pressed to determine what control system, if any, controls the compressor itself. All the PFD shows relating directly to the compressor is a flow transmitter (FT) on the suction line. This level of uncertainty is perfectly acceptable for a PFD, because its purpose is merely to show the general flow of the process itself, and only a bare minimum of control instrumentation.

PROCESS & INSTRUMENTATION DIAGRAM

The next level of detail is the Process and Instrument Diagram1, or P&ID. Here, we see a “zooming in” of scope from the whole evaporator process to the compressor as a unit. The evaporator and knockout vessels almost fade into the background, with their associated instruments absent from view:

Now we see there is more instrumentation associated with the compressor than just a flow transmitter. There is also a differential pressure transmitter (PDT), a flow indicating controller (FIC), and a “recycle” control valve that allows some of the vapor coming out of the compressor’s discharge line to go back around into the compressor’s suction line. Additionally, we have a pair of temperature transmitters that report suction and discharge line temperatures to an indicating recorder.

Some other noteworthy details emerge in the P&ID as well. We see that the flow transmitter, flow controller, pressure transmitter, and flow valve all bear a common number: 42. This common “loop number” indicates these four instruments are all part of the same control system. An instrument with any other loop number is part of a different control system, measuring and/or controlling some other function in the process. Examples of this include the two temperature transmitters and their respective recorders, bearing the loop numbers 41 and 43.

1Sometimes P&ID stands for Piping and Instrument Diagram. Either way, it means the same thing.

Please note the differences in the instrument “bubbles” as shown on this P&ID. Some of the bubbles are just open circles, where others have lines going through the middle. Each of these symbols has meaning according to the ISA (Instrumentation, Systems, and Automation society) standard:

The type of “bubble” used for each instrument tells us something about its location. This, obviously, is quite important when working in a facility with many thousands of instruments scattered over acres of facility area, structures, and buildings.

The rectangular box enclosing both temperature recorders shows they are part of the same physical instrument. In other words, this indicates there is really only one temperature recorder instrument, and that it plots both suction and discharge temperatures (most likely on the same trend graph). This suggests that each bubble may not necessarily represent a discrete, physical instrument, but rather an instrument function that may reside in a multi-function device.

Details we do not see on this P&ID include cable types, wire numbers, terminal blocks, junction boxes, instrument calibration ranges, failure modes, power sources, and the like. To examine this level of detail, we must go to the loop diagram we are interested .

LOOP DIAGRAMS

Finally, we arrive at the loop diagram (sometimes called a loop sheet) for the compressor surge control system (loop number 42):

Here we see that the P&ID didn’t show us all the instruments in this control “loop.” Not only do we have two transmitters, a controller, and a valve; we also have two signal transducers. Transducer 42a modifies the flow transmitter’s signal before it goes into the controller, and transducer 42b converts the electronic 4 to 20 mA signal into a pneumatic 3 to 15 PSI air pressure signal. Each instrument “bubble” in a loop diagram represents an individual device, with its own terminals for connecting wires.

Note that dashed lines now represent individual copper wires instead of whole cables. Terminal blocks where these wires connect to are represented by squares with numbers in them. Cable numbers, wire colors, junction block numbers, panel identification, and even grounding points are all shown in loop diagrams. The only type of diagram at a lower level of abstraction than a loop diagram would be an electronic schematic diagram for an individual instrument, which of course would only show details pertaining to that one instrument. Thus, the loop diagram is the most detailed form of diagram for a control system as a whole, and thus it must contain all details omitted by PFDs and P&IDs alike.

To the novice it may seem excessive to include such trivia as wire colors in a loop diagram. To the experienced instrument technician who has had to work on systems lacking such documented detail, this information is highly valued. The more detail you put into a loop diagram, the easier it makes the inevitable job of maintaining that system at some later date. When a loop diagram shows you exactly what wire color to expect at exactly what point in an instrumentation system, and exactly what terminal that wire should connect to, it becomes much easier to proceed with any troubleshooting, calibration, or upgrade task.

An interesting detail seen on this loop diagram is an entry specifying “input calibration” and “output calibration” for each and every instrument in the system. This is actually a very important concept to keep in mind when troubleshooting a complex instrumentation system: every instrument has at least one input and at least one output, with some sort of mathematical relationship between the two. Diagnosing where a problem lies within a measurement or control system often reduces to testing various instruments to see if their output responses appropriately match their input conditions.

For example, one way to test the flow transmitter in this system would be to subject it to a number of different pressures within its range (specified in the diagram as 0 to 100 inches of water column differential) and seeing whether or not the current signal output by the transmitter was consistently proportional to the applied pressure (e.g. 4 mA at 0 inches pressure, 20 mA at 100 inches pressure, 12 mA at 50 inches pressure, etc.).

Given the fact that a calibration error or malfunction in any one of these instruments can cause a problem for the control system as a whole, it is nice to know there is a way to determine which instrument is to blame and which instruments are not. This general principle holds true regardless of the instrument’s type or technology. You can use the same input-versus-output test procedure to verify the proper operation of a pneumatic (3 to 15 PSI) level transmitter or an analog electronic (4 to 20 mA) flow transmitter or a digital (fieldbus) temperature transmitter alike. Each and every instrument has an input and an output, and there is always a predictable (and testable) correlation from one to the other.

Another interesting detail seen on this loop diagram is the action of each instrument. You will notice a box and arrow (pointing either up or down) next to each instrument bubble. An “up” arrow (↑) represents a direct-acting instrument: one whose output signal increases as the input stimulus increases. A “down” arrow (↓) represents a reverse-acting instrument: one whose output signal decreases as the input stimulus increases. All the instruments in this loop are direct-acting with the exception of the pressure differential transmitter PDT-42:

Here, the “down” arrow tells us the transmitter will output a full-range signal (20 mA) when it senses zero differential pressure, and a 0% signal (4 mA) when sensing a full 200 PSI differential. While this calibration may seem confusing and unwarranted, it serves a definite purpose in this particular control system. Since the transmitter’s current signal decreases as pressure increases, and the controller must be correspondingly configured, a decreasing current signal will be interpreted by the controller as a high differential pressure. If any wire connection fails in the 4-20 mA current loop for that transmitter, the resulting 0 mA signal will be naturally “seen” by the controller as a pressure over-range condition. This is considered dangerous in a compressor system because it predicts a condition of surge. Thus, the controller will naturally take action to prevent surge by commanding the anti-surge control valve to open, because it “thinks” the compressor is about to surge. In other words, the transmitter is intentionally calibrated to be reverse-acting such that any break in the signal wiring will naturally bring the system to its safest condition.

SAMA DIAGRAMS

SAMA is an acronym standing for Scientific Apparatus Makers Association, referring to a unique form of diagram used primary in the power generation industry to document control strategies. These diagrams focus on the flow of information within a control system rather than on the process piping or instrument interconnections (wires, tubes, etc.). The general flow of a SAMA diagram is top-to-bottom, with the process sensing instrument (transmitter) located at the top and the final control element (valve or variable-speed motor) located at the bottom. No attempt is made to arrange symbols in a SAMA diagram to correlate with actual equipment layout: these diagrams are all about the algorithms used to make control decisions, and nothing more.

A sample SAMA diagram appears here, showing a flow transmitter (FT) sending a process variable signal to a PID controller, which then sends a manipulated variable signal to a flow control valve (FCV):

A cascaded control system, where the output of one controller acts as the setpoint for another controller to follow, appears in SAMA diagram form like this:

In this case, the primary controller senses the level in a vessel, commanding the secondary (flow) controller to maintain the necessary amount of flow either in or out of the vessel as needed to maintain level at some setpoint.

SAMA diagrams may show varying degrees of detail about the control strategies they document. For example, you may see the auto/manual controls represented as separate entities in a SAMA diagram, apart from the basic PID controller function. In the following example, we see a transfer block (T) and two manual adjustment blocks (A) providing a human operator the ability to separately adjust the controller’s setpoint and output (manipulated) variables, and to transfer between automatic and manual modes:

Rectangular blocks such as the _, P, I, and D shown in this diagram represent automatic functions. Diamond-shaped blocks such as the A and T blocks are manual functions which must be set by a human operator. Showing even more detail, the following SAMA diagram indicates the presence of setpoint tracking in the controller algorithm, a feature that forces the setpoint value to equal the process variable value any time the controller is in manual mode:

Here we see a new type of line: dashed instead of solid. This too has meaning in the world of SAMA diagrams. Solid lines represent analog (continuously variable) signals such as process variable, setpoint, and manipulated variable. Dashed lines represent discrete (on/off) signal paths, in this case the auto/manual state of the controller commanding the PID algorithm to get its setpoint either from the operator’s input (A) or from the process variable input (the flow transmitter: FT).

INSTRUMENTS & PROCESS EQUIPMENT SYMBOLS

INSTRUMENTS IDENTIFICATION TAGS

Up until this point, we have explored various types of instrumentation diagram, each one making reference to different instruments by lettered identifiers such as TT (Temperature Transmitter), PDT (Pressure Differential Transmitter), or FV (Flow Valve), without formally defining all the letters used to identify instruments. Part of the ISA 5.1 standard does exactly this, which is what we will now investigate.

Each instrument within an instrumented facility should have its own unique identifying tag consisting of a series of letters describing that instrument’s function, as well as a number identifying the particular loop it belongs to. An optional numerical prefix typically designates the larger area of the facility in which the loop resides, and an optional alphabetical suffix designates multiple instances of instruments within one loop.

For example, if we were to see an instrument bearing the tag FC-135, we would know it was a flow controller (FC) for loop number 135. In a large manufacturing facility with multiple processing “unit” areas, a tag such as this might be preceded by another number designating the unit area. For example, our hypothetical flow controller might be labeled 12-FC-135 (flow controller for loop #135, located in unit 12). If this loop happened to contain multiple controllers, we would need to distinguish them from each other by the use of suffix letters appended to the loop number (e.g. 12-FC-135A, 12-FC-135B, 12-FC-135C).

Each and every instrument within a particular loop is first defined by the variable that loop seeks to sense or control, regardless of the physical construction of the instrument itself. Our hypothetical flow controller FC-135, for example, may be physically identical to the level controller in loop #72 (LC-72), or to the temperature controller in loop #288 (TC-288). What makes FC-135 a flow controller is the fact that the transmitter sensing the main process variable measures flow. Likewise, the identifying tag for every other instrument within that loop2 must begin with the letter “F” as well. This includes the final control element as well: in a level control loop, the transmitter is identified as an “LT” even if the actual sensing element works on pressure (because the variable that the loop strives to sense or control is actually level, even if indirectly sensed by pressure), the controller is identified as an “LC”, and the control valve throttling fluid flow is identified as an “LV”: every instrument in that level-controlling loop serves to help control level, and so its primary function is to be a “level” instrument.

2Exceptions do exist to this rule. For example, in a cascade or feedforward loop where multiple transmitters feed into one or more controllers, each transmitter is identified by the type of process variable it senses, and each controller’s identifying tag follows suit.

Valid letters recognized by the ISA for defining the primary process variable of an instrument within a loop are shown in the following table. Please note that the use of a modifier defines a unique variable: for example, a “PT” is a transmitter measuring pressure at a single point in a process, whereas a “PDT” is a transmitter measuring a pressure difference between two points in a process. Likewise, a “TC” is a controller controlling temperature, whereas a “TKC” is a controller controlling the rate-of-change of temperature:

Letter	Variable	Modifier
A	Analytical (composition)
B	Burner or Combustion
C	User-defined
D	User-defined	Differential
E	Voltage
F	Flow	Ratio or Fraction
G	User-defined
H	Hand (manual)
I	Current
J	Power	Scan
K	Time or Schedule	Time rate-of-change
L	Level
M	User-defined	Momentary
N	User-defined
O	User-defined
P	Pressure or Vacuum
Q	Quantity	Time-Integral or Total
R	Radiation
S	Speed or Frequency	Safety
T	Temperature
U	Multi-function
V	Vibration
W	Weight or Force
X	Unclassified	X-axis
Y	Event, State, or Presence	Y-axis
Z	Position or Dimension	Z-axis

A “user-defined” letter represents a non-standard variable used multiple times in an instrumentation system. For example, an engineer designing an instrument system for measuring and controlling the refractive index of a liquid might choose to use the letter “C” for this variable. Thus, a refractive-index transmitter would be designated “CT” and a control valve for the refractive index loop would be designated “CV”. The meaning of a user-defined variable need only be defined in one location (e.g. in a legend for the diagram).

An “unclassified” letter represents one or more non-standard variables, each used only once (or a very limited number of times) in an instrumentation system. The meaning of an unclassified variable is best described immediately near the instrument’s symbol rather than in a legend. Succeeding letters in an instrument tag describe the function that instrument performs relative to the process variable. For example, a “PT” is an instrument transmitting a signal representing pressure, while a “PI” is an indicator for pressure and a “PC” is a controller for pressure. Many instruments have multiple functions designated by multiple letters, such as a TRC (Temperature Recording Controller ). In such cases, the first function letter represents the “passive” function (usually provided to a human operator) while the second letter represents the “active” (automated) control function.

Letter	Passive function	Active function	Modifier
A	Alarm
B	User-defined	User-defined	User-defined
C		Control
E	Element (sensing)
G	Glass or Viewport
H			High
I	Indicate
K		Control station
L	Light		Low
M			Middle or Intermediate
N	User-defined	User-defined	User-defined
O	Orifice
P	Test point
R	Record
S		Switch
T		Transmit
U	Multi-function	Multi-function	Multi-function
V		Valve, Damper, Louver
W	Well
X	Unclassified	Unclassified	Unclassified
Y		Relay, Compute, Convert
Z		Driver, Actuator, or unclassified final control element

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KEY POINTS TO FOCUS - HOW TO COMMISSION A THERMAL POWER PLANT

A. Electrical Engineer
- HT panel Inspection, testing and commissioning
- LT panel inspection . testing and commissioning
Both the above takes quite a bit of time depending on how well the erection had been made, predominately this is done
- Testing of power cables (if not charged yet)
- Testing of Control system interlocks in the switchgear
- HT Breaker/LTbreaker / MCC module healthiness checking
- Testing of proper feed back in the electrical SCADA system (open/close, power, current, voltage values etc ...)
- Panel Relay setting, inspection and testing
- Testing of CT's PT's and HT gear transducers
- generator and auxiliaries inspection, testing
- Turbine axillary drives testing
- Boiler/HRSG axillary drives testing
- generator control panel testing and commissioning
- ECP or electrical control panel for plant HT and LT switchgear testing and commissioning
- Generator relay panel testing, setting revision and commissioning
- Plant DC system testing and commissioning
- Plant UPS system testing and commissioning
- Generator AVR testing, tuning and commissioning

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B. Instrumentation Engineer
- Turbine control system testing, tweaking and commissioning
- Plant DCS system (Boiler and BOP) testing, tweaking and commissioning
- Plant SCADA system (electrical switchgear control) testing and commissioning
All the above work involves more or less the same type of work
- Testing (occasional calibration and replacement) of Plant field instrumentation
- Testing and commissioning of plant control valves (loop checking and ensuring proper feedback)
- Testing commissioning of plant solenoid valves (proper operation and feedback
- Testing and commissioning of plant MOV (with electrical engineer, this by far in my opinion is the most back breaking work and in the quest of complete automation there are literally 50-100 MOV's in each co generation plant, i don't know MOV's and me do not go well )
- Testing and commissioning of plant servo's (a very subtle art :) )
- Testing and calibration of plant measurement circuits, pressure, temperature, flow, speed, position and vibration probes. They also take a lot of time mainly because they form a major quantity of the plant instrumentation.
- Testing and commissioning of plant analyzers, In boilers, it will be PH, silica, conductivity, phosphate, SOx, NOx, CO, unburnt fuel and oxygen analysers. This work as far as i have seen is exclusively done by the vendors. all you have to do is to verify the operation and sign :).
- Testing and tweaking of graphics, minor modifications in consultation with plant operating personnel.
- testing and tweaking of control constants and minor (to sometimes major) logic modifications in application code to the controllers.
- hanging around a lot of time in marshaling units, RTU's, in the field and in front of the controller, thinking, scratching your head and desperately wising to god that atleast this should work.
- Testing and commissioning of other plant systems, which do not form the part of the typical turbine and DCS control. They include
- Turbine and generator CO2 release system
- Plant and Trubine heat sensors and fire detectors panel
- MCP (manual call points) system and associated auxiliaries
- Plant communication system (another exclusive vendor area)

Thermal power station over view

A thermal power station is a power plant in which the prime mover is steam driven. Water is heated, turns into steam and spins a steam turbine which drives an electrical generator. After it passes through the turbine, the steam is condensed in a condenser and recycled to where it was heated; this is known as a Rankine cycle. The greatest variation in the design of thermal power stations is due to the different fuel sources. Some prefer to use the term energy center because such facilities convert forms of heat energy into electricity.^[1] Some thermal power plants also deliver heat energy for industrial purposes, for district heating, or for desalination of water as well as delivering electrical power. A large part of human CO₂emissions comes from fossil fueled thermal power plants; efforts to reduce these outputs are various and widespread.

Introductory overview

Almost all coal, nuclear, geothermal, solar thermal electric, and waste incineration plants, as well as many natural gas power plants are thermal.Natural gas is frequently combusted in gas turbines as well as boilers. The waste heat from a gas turbine can be used to raise steam, in acombined cycle plant that improves overall efficiency. Power plants burning coal, fuel oil, or natural gas are often called fossil-fuel power plants. Some biomass-fueled thermal power plants have appeared also. Non-nuclear thermal power plants, particularly fossil-fueled plants, which do not use co-generation are sometimes referred to as conventional power plants.

Commercial electric utility power stations are usually constructed on a large scale and designed for continuous operation. Electric power plants typically use three-phase electrical generators to produce alternating current (AC) electric power at a frequency of 50 Hz or 60 Hz. Large companies or institutions may have their own power plants to supply heating or electricity to their facilities, especially if steam is created anyway for other purposes. Steam-driven power plants have been used in various large ships, but are now usually used in large naval ships. Shipboard power plants usually directly couple the turbine to the ship's propellers through gearboxes. Power plants in such ships also provide steam to smaller turbines driving electric generators to supply electricity. Shipboard steam power plants can be either fossil fuel or nuclear. Nuclear marine propulsion is, with few exceptions, used only in naval vessels. There have been perhaps about a dozen turbo-electric ships in which a steam-driven turbine drives an electric generator which powers an electric motor for propulsion.

combined heat and power (CH&P) plants, often called co-generation plants, produce both electric power and heat for process heat or space heating. Steam and hot water lose energy when piped over substantial distance, so carrying heat energy by steam or hot water is often only worthwhile within a local area, such as a ship, industrial plant, or district heating of nearby buildings.

History

Reciprocating steam engines have been used for mechanical power sources since the 18th Century, with notable improvements being made by James Watt. The very first commercial central electrical generating stations in the Pearl Street Station, New York and the Holborn Viaduct power station, London, in 1882, also used reciprocating steam engines. The development of the steam turbine allowed larger and more efficient central generating stations to be built. By 1892 it was considered as an alternative to reciprocating engines ^[2] Turbines offered higher speeds, more compact machinery, and stable speed regulation allowing for parallel synchronous operation of generators on a common bus. Turbines entirely replaced reciprocating engines in large central stations after about 1905. The largest reciprocating engine-generator sets ever built were completed in 1901 for the Manhattan Elevated Railway. Each of seventeen units weighed about 500 tons and was rated 6000 kilowatts; a contemporary turbine-set of similar rating would have weighed about 20% as much.^[3]

Efficiency

The energy efficiency of a conventional thermal power station, considered as salable energy as a percent of the heating value of the fuel consumed, is typically 33% to 48%. This efficiency is limited as all heat engines are governed by the laws ofthermodynamics. The rest of the energy must leave the plant in the form of heat. This waste heat can go through a condenserand be disposed of with cooling water or in cooling towers. If the waste heat is instead utilized for district heating, it is called co-generation. An important class of thermal power station are associated with desalination facilities; these are typically found in desert countries with large supplies of natural gas and in these plants, freshwater production and electricity are equally important co-products.

The Carnot efficiency dictates that higher efficiencies can be attained by increasing the temperature of the steam. Sub-critical fossil fuel power plants can achieve 36–40% efficiency. Super critical designs have efficiencies in the low to mid 40% range, with new "ultra critical" designs using pressures of 4400 psi (30.3 MPa) and multiple stage reheat reaching about 48% efficiency. Above the critical point for water of 705 °F (374 °C) and 3212 psi (22.06 MPa), there is no phase transition from water to steam, but only a gradual decrease in density.

Current nuclear power plants must operate below the temperatures and pressures that coal-fired plants do, since the pressurized vessel is very large and contains the entire bundle of nuclear fuel rods. The size of the reactor limits the pressure that can be reached. This, in turn, limits their thermodynamic efficiency to 30–32%. Some advanced reactor designs being studied, such as the Very high temperature reactor, Advanced gas-cooled reactor and Super critical water reactor, would operate at temperatures and pressures similar to current coal plants, producing comparable thermodynamic efficiency.

Electricity cost

The direct cost of electric energy produced by a thermal power station is the result of cost of fuel, capital cost for the plant, operator labour, maintenance, and such factors as ash handling and disposal. Indirect, social or environmental costs such as the economic value of environmental impacts, or environmental and health effects of the complete fuel cycle and plant decommissioning, are not usually assigned to generation costs for thermal stations in utility practice, but may form part of an environmental impact assessment.

Diagram of a typical coal-fired thermal power station

Typical diagram of a coal-fired thermal power station

1. Cooling tower	10. Steam Control valve	19. Superheater
2. Cooling water pump	11. High pressure steam turbine	20. Forced draught (draft) fan
3. transmission line (3-phase)	12. Deaerator	21. Reheater
4. Step-up transformer (3-phase)	13. Feedwater heater	22. Combustion air intake
5. Electrical generator (3-phase)	14. Coal conveyor	23. Economiser
6. Low pressure steam turbine	15. Coal hopper	24. Air preheater
7. Condensate pump	16. Coal pulverizer	25. Precipitator
8. Surface condenser	17. Boiler steam drum	26. Induced draught (draft) fan
9. Intermediate pressure steam turbine	18. Bottom ash hopper	27. Flue gas stack

For units over about 200 MW capacity, redundancy of key components is provided by installing duplicates of the forced and induced draft fans, air preheaters, and fly ash collectors. On some units of about 60 MW, two boilers per unit may instead be provided.

Boiler and steam cycle

In fossil-fueled power plants, steam generator refers to a furnace that burns the fossil fuel to boil water to generate steam.

In the nuclear plant field, steam generator refers to a specific type of large heat exchanger used in a pressurized water reactor (PWR) to thermally connect the primary (reactor plant) and secondary (steam plant) systems, which generates steam. In a nuclear reactor called a boiling water reactor (BWR), water is boiled to generate steam directly in the reactor itself and there are no units called steam generators.

In some industrial settings, there can also be steam-producing heat exchangers called heat recovery steam generators (HRSG) which utilize heat from some industrial process. The steam generating boiler has to produce steam at the high purity, pressure and temperature required for the steam turbine that drives the electrical generator.

Geothermal plants need no boiler since they use naturally occurring steam sources. Heat exchangers may be used where the geothermal steam is very corrosive or contains excessive suspended solids.

A fossil fuel steam generator includes an economizer, a steam drum, and the furnace with its steam generating tubes and superheater coils. Necessary safety valves are located at suitable points to avoid excessive boiler pressure. The air and flue gas path equipment include: forced draft (FD) fan, Air Preheater (AP), boiler furnace, induced draft (ID) fan, fly ash collectors (electrostatic precipitator or baghouse) and the flue gas stack.

Feed water heating and deaeration

The feed water used in the steam boiler is a means of transferring heat energy from the burning fuel to the mechanical energy of the spinning steam turbine. The total feed water consists of recirculated condensate water and purified makeup water. Because the metallic materials it contacts are subject to corrosion at high temperatures and pressures, the makeup water is highly purified before use. A system of water softeners and ion exchange demineralizers produces water so pure that it coincidentally becomes an electrical insulator, with conductivity in the range of 0.3–1.0 microsiemens per centimeter. The makeup water in a 500 MWe plant amounts to perhaps 20 US gallons per minute (1.25 L/s) to offset the small losses from steam leaks in the system.

The feed water cycle begins with condensate water being pumped out of the condenser after traveling through the steam turbines. The condensate flow rate at full load in a 500 MW plant is about 6,000 US gallons per minute (400 L/s).

The water flows through a series of six or seven intermediate feed water heaters, heated up at each point with steam extracted from an appropriate duct on the turbines and gaining temperature at each stage. Typically, the condensate plus the makeup water then flows through a deaerator that removes dissolved air from the water, further purifying and reducing its corrosiveness. The water may be dosed following this point with hydrazine, a chemical that removes the remaining oxygen in the water to below 5 parts per billion (ppb). It is also dosed with pH control agents such as ammonia or morpholine to keep the residual acidity low and thus non-corrosive.

Boiler operation

The boiler is a rectangular furnace about 50 feet (15 m) on a side and 130 feet (40 m) tall. Its walls are made of a web of high pressure steel tubes about 2.3 inches (58 mm) in diameter.

Pulverized coal is air-blown into the furnace from fuel nozzles at the four corners and it rapidly burns, forming a large fireball at the center. The thermal radiation of the fireball heats the water that circulates through the boiler tubes near the boiler perimeter. The water circulation rate in the boiler is three to four times the throughput and is typically driven by pumps. As the water in the boiler circulates it absorbs heat and changes into steam at 700 °F (370 °C) and 3,200 psi (22,000 kPa). It is separated from the water inside a drum at the top of the furnace. The saturated steam is introduced into superheat pendant tubes that hang in the hottest part of the combustion gases as they exit the furnace. Here the steam is superheated to 1,000 °F (540 °C) to prepare it for the turbine.

Plants designed for lignite (brown coal) are increasingly used in locations as varied as Germany, Victoria, Australia and North Dakota. Lignite is a much younger form of coal than black coal. It has a lower energy density than black coal and requires a much larger furnace for equivalent heat output. Such coals may contain up to 70% water and ash, yielding lower furnace temperatures and requiring larger induced-draft fans. The firing systems also differ from black coal and typically draw hot gas from the furnace-exit level and mix it with the incoming coal in fan-type mills that inject the pulverized coal and hot gas mixture into the boiler.

Plants that use gas turbines to heat the water for conversion into steam use boilers known as heat recovery steam generators (HRSG). The exhaust heat from the gas turbines is used to make superheated steam that is then used in a conventional water-steam generation cycle, as described in gas turbine combined-cycle plants section below.

Boiler furnace and steam drum

Once water inside the boiler or steam generator, the process of adding the latent heat of vaporization or enthalpy is underway. The boiler transfers energy to the water by the chemical reaction of burning some type of fuel.

The water enters the boiler through a section in the convection pass called the economizer. From the economizer it passes to the steam drum. Once the water enters the steam drum it goes down to the lower inlet water wall headers. From the inlet headers the water rises through the water walls and is eventually turned into steam due to the heat being generated by the burners located on the front and rear water walls (typically). As the water is turned into steam/vapor in the water walls, the steam/vapor once again enters the steam drum. The steam/vapor is passed through a series of steam and water separators and then dryers inside the steam drum. The steam separators and dryers remove water droplets from the steam and the cycle through the water walls is repeated. This process is known as natural circulation.

The boiler furnace auxiliary equipment includes coal feed nozzles and igniter guns, soot blowers, water lancing and observation ports (in the furnace walls) for observation of the furnace interior. Furnace explosions due to any accumulation of combustible gases after a trip-out are avoided by flushing out such gases from the combustion zone before igniting the coal.

The steam drum (as well as the super heater coils and headers) have air vents and drains needed for initial start up. The steam drum has internal devices that removes moisture from the wet steam entering the drum from the steam generating tubes. The dry steam then flows into the super heater coils.

Superheater

Fossil fuel power plants can have a superheater and/or re-heater section in the steam generating furnace. In a fossil fuel plant, after the steam is conditioned by the drying equipment inside the steam drum, it is piped from the upper drum area into tubes inside an area of the furnace known as the superheater, which has an elaborate set up of tubing where the steam vapor picks up more energy from hot flue gases outside the tubing and its temperature is now superheated above the saturation temperature. The superheated steam is then piped through the main steam lines to the valves before the high pressure turbine.

Nuclear-powered steam plants do not have such sections but produce steam at essentially saturated conditions. Experimental nuclear plants were equipped with fossil-fired super heaters in an attempt to improve overall plant operating cost.

Steam condensing

The condenser condenses the steam from the exhaust of the turbine into liquid to allow it to be pumped. If the condenser can be made cooler, the pressure of the exhaust steam is reduced and efficiency of the cycle increases.

The surface condenser is a shell and tube heat exchanger in which cooling water is circulated through the tubes.^[5]^[9]^[10]^[11] The exhaust steam from the low pressure turbine enters the shell where it is cooled and converted to condensate (water) by flowing over the tubes as shown in the adjacent diagram. Such condensers use steam ejectors or rotary motor-driven exhausters for continuous removal of air and gases from the steam side to maintain vacuum.

For best efficiency, the temperature in the condenser must be kept as low as practical in order to achieve the lowest possible pressure in the condensing steam. Since the condenser temperature can almost always be kept significantly below 100 °C where the vapor pressure of water is much less than atmospheric pressure, the condenser generally works under vacuum. Thus leaks of non-condensible air into the closed loop must be prevented.

Typically the cooling water causes the steam to condense at a temperature of about 35 °C (95 °F) and that creates an absolute pressure in the condenser of about 2–7 kPa (0.59–2.1 inHg), i.e. a vacuum of about −95 kPa (−28.1 inHg) relative to atmospheric pressure. The large decrease in volume that occurs when water vapor condenses to liquid creates the low vacuum that helps pull steam through and increase the efficiency of the turbines.

The limiting factor is the temperature of the cooling water and that, in turn, is limited by the prevailing average climatic conditions at the power plant's location (it may be possible to lower the temperature beyond the turbine limits during winter, causing excessive condensation in the turbine). Plants operating in hot climates may have to reduce output if their source of condenser cooling water becomes warmer; unfortunately this usually coincides with periods of high electrical demand for air conditioning.

The condenser generally uses either circulating cooling water from a cooling tower to reject waste heat to the atmosphere, or once-through water from a river, lake or ocean.

A Marley mechanical induced draft cooling tower

The heat absorbed by the circulating cooling water in the condenser tubes must also be removed to maintain the ability of the water to cool as it circulates. This is done by pumping the warm water from the condenser through either natural draft, forced draft or induced draft cooling towers (as seen in the image to the right) that reduce the temperature of the water by evaporation, by about 11 to 17 °C (20 to 30 °F)—expelling waste heat to the atmosphere. The circulation flow rate of the cooling water in a 500 MW unit is about 14.2 m³/s (500 ft³/s or 225,000 US gal/min) at full load.^[12]

The condenser tubes are made of brass or stainless steel to resist corrosion from either side. Nevertheless they may become internally fouled during operation by bacteria or algae in the cooling water or by mineral scaling, all of which inhibit heat transfer and reduce thermodynamic efficiency. Many plants include an automatic cleaning system that circulates sponge rubber balls through the tubes to scrub them clean without the need to take the system off-line.

The cooling water used to condense the steam in the condenser returns to its source without having been changed other than having been warmed. If the water returns to a local water body (rather than a circulating cooling tower), it is tempered with cool 'raw' water to prevent thermal shock when discharged into that body of water.

Another form of condensing system is the air-cooled condenser. The process is similar to that of a radiator and fan. Exhaust heat from the low pressure section of a steam turbine runs through the condensing tubes, the tubes are usually finned and ambient air is pushed through the fins with the help of a large fan. The steam condenses to water to be reused in the water-steam cycle. Air-cooled condensers typically operate at a higher temperature than water-cooled versions. While saving water, the efficiency of the cycle is reduced (resulting in more carbon dioxide per megawatt of electricity).

From the bottom of the condenser, powerful condensate pumps recycle the condensed steam (water) back to the water/steam cycle.

Reheater

Power plant furnaces may have a reheater section containing tubes heated by hot flue gases outside the tubes. Exhaust steam from the high pressure turbine is passed through these heated tubes to collect more energy before driving the intermediate and then low pressure turbines.

Air path

External fans re provided to give sufficient air for combustion. The Primary air fan takes air from the atmosphere and, first warming it in the air preheater for better combustion, injects it via the air nozzles on the furnace wall.

The induced draft fan assists the FD fan by drawing out combustible gases from the furnace, maintaining a slightly negative pressure in the furnace to avoid backfiring through any closing.

Steam turbine generator

Rotor of a modern steam turbine, used in a power station

The turbine generator consists of a series of steam turbines interconnected to each other and a generator on a common shaft. There is a high pressure turbine at one end, followed by an intermediate pressure turbine, two low pressure turbines, and the generator. As steam moves through the system and loses pressure and thermal energy it expands in volume, requiring increasing diameter and longer blades at each succeeding stage to extract the remaining energy. The entire rotating mass may be over 200 metric tons and 100 feet (30 m) long. It is so heavy that it must be kept turning slowly even when shut down (at 3 rpm) so that the shaft will not bow even slightly and become unbalanced. This is so important that it is one of only five functions of blackout emergency power batteries on site. Other functions are emergency lighting, communication, station alarms and turbogenerator lube oil.

Superheated steam from the boiler is delivered through 14–16-inch (360–410 mm) diameter piping to the high pressure turbine where it falls in pressure to 600 psi (4.1 MPa) and to 600 °F (320 °C) in temperature through the stage. It exits via 24–26-inch (610–660 mm) diameter cold reheat lines and passes back into the boiler where the steam is reheated in special reheat pendant tubes back to 1,000 °F (500 °C). The hot reheat steam is conducted to the intermediate pressure turbine where it falls in both temperature and pressure and exits directly to the long-bladed low pressure turbines and finally exits to the condenser.

The generator, 30 feet (9 m) long and 12 feet (3.7 m) in diameter, contains a stationary stator and a spinning rotor, each containing miles of heavycopper conductor—no permanent magnets here. In operation it generates up to 21,000 amperes at 24,000 volts AC (504 MWe) as it spins at either 3,000 or 3,600 rpm, synchronized to the power grid. The rotor spins in a sealed chamber cooled with hydrogen gas, selected because it has the highest known heat transfer coefficient of any gas and for its low viscosity which reduces windage losses. This system requires special handling during startup, with air in the chamber first displaced by carbon dioxide before filling with hydrogen. This ensures that the highly explosivehydrogen–oxygen environment is not created.

The power grid frequency is 60 Hz across North America and 50 Hz in Europe, Oceania, Asia (Korea and parts of Japan are notable exceptions) and parts of Africa.

The electricity flows to a distribution yard where transformers increase the voltage for transmission to its destination.

The steam turbine-driven generators have auxiliary systems enabling them to work satisfactorily and safely. The steam turbine generator being rotating equipment generally has a heavy, large diameter shaft. The shaft therefore requires not only supports but also has to be kept in position while running. To minimize the frictional resistance to the rotation, the shaft has a number ofbearings. The bearing shells, in which the shaft rotates, are lined with a low friction material like Babbitt metal. Oil lubrication is provided to further reduce the friction between shaft and bearing surface and to limit the heat generated.

Stack gas path and cleanup

As the combustion flue gas exits the boiler it is routed through a rotating flat basket of metal mesh which picks up heat and returns it to incoming fresh air as the basket rotates, This is called theair preheater. The gas exiting the boiler is laden with fly ash, which are tiny spherical ash particles. The flue gas contains nitrogen along with combustion products carbon dioxide, sulfur dioxide, and nitrogen oxides. The fly ash is removed by fabric bag filters or electrostatic precipitators. Once removed, the fly ash byproduct can sometimes be used in the manufacturing of concrete. This cleaning up of flue gases, however, only occurs in plants that are fitted with the appropriate technology. Still, the majority of coal-fired power plants in the world do not have these facilities.^{[citation needed]} Legislation in Europe has been efficient to reduce flue gas pollution. Japan has been using flue gas cleaning technology for over 30 years and the US has been doing the same for over 25 years. China is now beginning to grapple with the pollution caused by coal-fired power plants.

Where required by law, the sulfur and nitrogen oxide pollutants are removed by stack gas scrubbers which use a pulverized limestone or other alkaline wet slurry to remove those pollutants from the exit stack gas. Other devices use catalysts to remove Nitrous Oxide compounds from the flue gas stream. The gas travelling up the flue gas stack may by this time have dropped to about50 °C (120 °F). A typical flue gas stack may be 150–180 metres (490–590 ft) tall to disperse the remaining flue gas components in the atmosphere. The tallest flue gas stack in the world is 419.7 metres (1,377 ft) tall at the GRES-2 power plant in Ekibastuz, Kazakhstan.

In the United States and a number of other countries, atmospheric dispersion modeling ^[13] studies are required to determine the flue gas stack height needed to comply with the local air pollutionregulations. The United States also requires the height of a flue gas stack to comply with what is known as the "Good Engineering Practice (GEP)" stack height.^[14]^[15] In the case of existing flue gas stacks that exceed the GEP stack height, any air pollution dispersion modeling studies for such stacks must use the GEP stack height rather than the actual stack height.

Fly ash collection

Fly ash is captured and removed from the flue gas by electrostatic precipitators or fabric bag filters (or sometimes both) located at the outlet of the furnace and before the induced draft fan. The fly ash is periodically removed from the collection hoppers below the precipitators or bag filters. Generally, the fly ash is pneumatically transported to storage silos for subsequent transport by trucks or railroad cars .

Bottom ash collection and disposal

At the bottom of the furnace, there is a hopper for collection of bottom ash. This hopper is always filled with water to quench the ash and clinkers falling down from the furnace. Some arrangement is included to crush the clinkers and for conveying the crushed clinkers and bottom ash to a storage site . Ash extractor is used to discharge ash from Municipal solid waste fired boilers.

Auxiliary systems

Boiler make-up water treatment plant and storage

Since there is continuous withdrawal of steam and continuous return of condensate to the boiler, losses due to blowdown and leakages have to be made up to maintain a desired water level in the boiler steam drum. For this, continuous make-up water is added to the boiler water system. Impurities in the raw water input to the plant generally consist of calcium and magnesium salts which impart hardness to the water. Hardness in the make-up water to the boiler will form deposits on the tube water surfaces which will lead to overheating and failure of the tubes. Thus, the salts have to be removed from the water, and that is done by a water demineralising treatment plant (DM). A DM plant generally consists of cation, anion, and mixed bed exchangers. Any ions in the final water from this process consist essentially of hydrogen ions and hydroxide ions, which recombine to form pure water. Very pure DM water becomes highly corrosive once it absorbs oxygen from the atmosphere because of its very high affinity for oxygen.

The capacity of the DM plant is dictated by the type and quantity of salts in the raw water input. However, some storage is essential as the DM plant may be down for maintenance. For this purpose, a storage tank is installed from which DM water is continuously withdrawn for boiler make-up. The storage tank for DM water is made from materials not affected by corrosive water, such as PVC. The piping and valves are generally of stainless steel. Sometimes, a steam blanketing arrangement or stainless steel doughnut float is provided on top of the water in the tank to avoid contact with air. DM water make-up is generally added at the steam space of the surface condenser (i.e., the vacuum side). This arrangement not only sprays the water but also DM water gets deaerated, with the dissolved gases being removed by a de-aerator through an ejector attached to the condenser.

Fuel preparation system

In coal-fired power stations, the raw feed coal from the coal storage area is first crushed into small pieces and then conveyed to the coal feed hoppers at the boilers. The coal is next pulverizedinto a very fine powder. The pulverizers may be ball mills, rotating drum grinders, or other types of grinders.

Some power stations burn fuel oil rather than coal. The oil must kept warm (above its pour point) in the fuel oil storage tanks to prevent the oil from congealing and becoming unpumpable. The oil is usually heated to about 100 °C before being pumped through the furnace fuel oil spray nozzles.

Boilers in some power stations use processed natural gas as their main fuel. Other power stations may use processed natural gas as auxiliary fuel in the event that their main fuel supply (coal or oil) is interrupted. In such cases, separate gas burners are provided on the boiler furnaces.

Barring gear

Barring gear (or "turning gear") is the mechanism provided to rotate the turbine generator shaft at a very low speed after unit stoppages. Once the unit is "tripped" (i.e., the steam inlet valve is closed), the turbine coasts down towards standstill. When it stops completely, there is a tendency for the turbine shaft to deflect or bend if allowed to remain in one position too long. This is because the heat inside the turbine casing tends to concentrate in the top half of the casing, making the top half portion of the shaft hotter than the bottom half. The shaft therefore could warp or bend by millionths of inches.

This small shaft deflection, only detectable by eccentricity meters, would be enough to cause damaging vibrations to the entire steam turbine generator unit when it is restarted. The shaft is therefore automatically turned at low speed (about one percent rated speed) by the barring gear until it has cooled sufficiently to permit a complete stop.

Oil system

An auxiliary oil system pump is used to supply oil at the start-up of the steam turbine generator. It supplies the hydraulic oil system required for steam turbine's main inlet steam stop valve, the governing control valves, the bearing and seal oil systems, the relevant hydraulic relays and other mechanisms.

At a preset speed of the turbine during start-ups, a pump driven by the turbine main shaft takes over the functions of the auxiliary system.

Generator cooling

While small generators may be cooled by air drawn through filters at the inlet, larger units generally require special cooling arrangements. Hydrogen gas cooling, in an oil-sealed casing, is used because it has the highest known heat transfer coefficient of any gas and for its low viscosity which reduces windage losses. This system requires special handling during start-up, with air in the generator enclosure first displaced by carbon dioxide before filling with hydrogen. This ensures that the highly flammable hydrogen does not mix with oxygen in the air.

The hydrogen pressure inside the casing is maintained slightly higher than atmospheric pressure to avoid outside air ingress. The hydrogen must be sealed against outward leakage where the shaft emerges from the casing. Mechanical seals around the shaft are installed with a very small annular gap to avoid rubbing between the shaft and the seals. Seal oil is used to prevent the hydrogen gas leakage to atmosphere.

The generator also uses water cooling. Since the generator coils are at a potential of about 22 kV, an insulating barrier such as Teflon is used to interconnect the water line and the generator high voltage windings. Demineralized water of low conductivity is used.

Generator high voltage system

The generator voltage for modern utility-connected generators ranges from 11 kV in smaller units to 22 kV in larger units. The generator high voltage leads are normally large aluminium channels because of their high current as compared to the cables used in smaller machines. They are enclosed in well-grounded aluminium bus ducts and are supported on suitable insulators. The generator high voltage leads are connected to step-up transformers for connecting to a high voltage electrical substation (usually in the range of 115 kV to 765 kV) for further transmission by the local power grid.

The necessary protection and metering devices are included for the high voltage leads. Thus, the steam turbine generator and the transformer form one unit. Smaller units,may share a common generator step-up transformer with individual circuit breakers to connect the generators to a common bus.

Monitoring and alarm system

Most of the power plant operational controls are automatic. However, at times, manual intervention may be required. Thus, the plant is provided with monitors and alarm systems that alert the plant operators when certain operating parameters are seriously deviating from their normal range.

Battery supplied emergency lighting and communication

A central battery system consisting of lead acid cell units is provided to supply emergency electric power, when needed, to essential items such as the power plant's control systems, communication systems, turbine lube oil pumps, and emergency lighting. This is essential for a safe, damage-free shutdown of the units in an emergency situation.

Transport of coal fuel to site and to storage

Most thermal stations use coal as the main fuel. Raw coal is transported from coal mines to a power station site by trucks, barges, bulk cargo ships or railway cars. Generally, when shipped by railways, the coal cars are sent as a full train of cars. The coal received at site may be of different sizes. The railway cars are unloaded at site by rotary dumpers or side tilt dumpers to tip over onto conveyor belts below. The coal is generally conveyed to crushers which crush the coal to about ³⁄₄ inches (19 mm) size. The crushed coal is then sent by belt conveyors to a storage pile. Normally, the crushed coal is compacted by bulldozers, as compacting of highly volatile coal avoids spontaneous ignition.

The crushed coal is conveyed from the storage pile to silos or hoppers at the boilers by another belt conveyor system.

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