power-plant-details

Industrial Instrumentation Research Journal

Wed, 27 Aug 2014 15:53:44 +0100

LETS TRY TO READ THE LOGIC BLOCK DIAGRAM OF SOME BOP OF POWER PLANT

Sat, 25 Jan 2014 16:45:25 +0100

Instrumentation Documents

Tue, 09 Apr 2013 10:54:38 +0100

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

POWER PLANT VARIOUS CONTROLS

Mon, 25 Feb 2013 15:43:55 +0100

Various Controls in Power Plant

Various controls of Power Plant

1. Flow Control

2. Pressure Control

3. Level Control

4. Temperature Control

Flow Control

The flow control is a fast control. It consists of PI control. The flow control includes

1. Feed water Flow

2. Condensate Flow

3. Combustion Air (PA and SA) Flow

4. Fuel Flow Controls.

5. CEP Recirculation Flow

The flow is basically a PI control. Low P and high I will make the control smooth, but the control will be slower. On the contrary High P values make the control fast, but very high P and I values tends to create high over and undershoots creating oscillation in the process value.

Process to Tune:

First keep the P and I value 0.5 and 1 and see the behaviour of the system. If the action seems to be very slow then increase P value as well as I value in range 0.8 and 1.4. Below are some basic values you can try with.

Start 0.5 and 1

Increase 0.8 and 1.4

Increase 1.2 and 1.8

Increase 1.2 and 2.3

Increase 1.6 and 3.2

Increase 2 and 3.5

For very Fast systems

Increase to 2.5 and 5 but in this case you should vary the P and I with respect to the deviation or the error signal.

If the system is slow then the PI values goes as follows

Start 0.5 and 1

Decrease 0.3 and 0.8

Decrease 0.2 and 0.5

Decrease 0.2 and 0.3

Do not decrease the values below that will cause no effect on the system.

Pressure Control

Pressure Control Loops in boilers

1. Furnace Pressure (ID and FD Control)

2. Main Steam Pressure Control

3. Feed water Pressure control (Scoop Control of BFP)

4. Auxiliary Steam Pressure Control

5. HP Bypass Steam Pressure Control

Pressure control is same as flow control, but most of the time it is a very fast control, unlikely flow can be slow control also.

Level Control

1. De-Aerator Level Control

2. Hot well Level Control

3. Drum Level Control

4. LPH Level

The above mentioned are some of the typical level controls of power plant. Most of the level control includes PI only but I personally think introduction of D variable makes it a much better control.

The level control is very critical in Power Plants and needs to be taken very seriously.

Drum Level Control:

This control is divided into 2 types.

1. Single Element Control

2. Three Element Control

1. Single Element Control

PV = Drum Level (%)

Setpoint = Drum Level (%)

Error = PV - SP

Error is fed to the PID / PI controller which controls the drum level.

2. Three Element Control

Here there are 2 PID Controller

1st PID/ PI controller

PV = Drum Level

SP = Drum Level

Error = PV – SP

The error is fed to the 1st controller which generates a set point for the next controller 2nd Controller.

PV = FW Flow (Compensated)

SP = Signal from 1st Controller + MS Flow

Error = PV – SP

Tuning of these controllers are very critical and time taking .It is to be noted that the PV i.e. the drum level should be damped signal.

De-aerator Level Control

PV = DEA LVL

SP = DEA LVL

ERR = PV – SP

ERR is fed to PI controller and the output is modified with the rate of change of Condensate and FW Flow. The rate of change of Condensate and Feed water flow is used to have a feed forward effect in the controller. By adding this parameters we can take care of the level before hand.

Condenser Level Control

PV = Hot well LVL

SP = Hot well LVL

ERR = PV – SP

ERR is fed to PI controller and the output is modified with the rate of change of Condensate Flow. By adding this parameters we can take care of the level before hand.

Temperature Control

This control is the critical control in Power Plant. Major loops under this control are as follows

1. RH temperature Control

2. SH Temperature Control

3. Main Steam Temperature Control

4. Auxiliary Steam Temperature Control

5. HP Bypass Steam Temperature Control

The temperature control is a very typical control and here we have to use PID loops. There are many new controllers where we can feed process dead time and process lag time. I f we can use such controllers then it will be very helpful to tune this controllers.

Temperature controllers tuning process is different as per different plant parameters.

CAPACITANCE TYPE LEVEL SWITCH

Wed, 16 Jan 2013 16:03:51 +0100

CAPACITANCE TYPE LEVEL SWITCH – MODEL – CLS 100

APPLICATION – OIL

BASIC CONCEPT -The RF type level switch is basically designed to measure the material kept inside the tank or vessel such as oil, water etc.

The capacitance is formed between the active electrode and the tank wall, this increased capacitance is sensed by a digital circuit to operate a relay

PRINCIPLE OF OPERATION – Capacitance formed between probe rod and wall tank which act as reference or ground.

WORKING – For proper working of the probe it is absolutely necessary that there is continuity between probe adopter and the tank wall. it should be kept it mind that flow should be static and the dielectric build inside is enough to make a positive capacitance, so as to operate the relay.

FAIL SAFE MODE – maximum fail safe means that the relay de-energizes when the level drops below the desired level or when the main supply fails.

CALIBRATION - For calibrating after installation raise / lower the oil level inside the tank where alarm is reqd.switch ON the power supply to the unit & wait for 10 min.

Adjust pot P1 slowly till RELAY/LED changes state. If the potentiometer reaches end position and no change in relay / led status is observed then turn the potentiometer in opposite direction.

During calibration notice that the probe does not touches the tank wall, this will increase the capacitance, and give inaccurate result. NOTE- allow a warm up time of 12min before starting calibration

3E DRUM LEVEL CONTROL & COMPENSATION

Tue, 04 Dec 2012 07:51:11 +0100

3E DRUM LEVEL CONTROL & COMPENSATION

The aim of drum level control is to maintain the drum level at the centre line of the boiler drum.

The 3 element in this loop are the drum level, the steam flow & the feed water flow. The level is measured by two independents DPT.The stream drum pressure is measured using pressure transmitter PT. The two level signals are corrected for density using the drum pressure signal before the same is used for indication, control & high, low alarm generation.

The density compensation is done by the formula-

Actual Steam Flow = Indicated steam flow * √ {(P1+1.029)*(T2+273)} / {(P2 +1.029) *(T1+273)} …………….1

Where P1 is measured pressure signal & T1 is measured temp signal, P2 = 89kg/cm2, T2 = 515 Deg C (Designed constant).

For very low trip generation first the constants are generated from individual transmitter & then two out of two is performed on the three density compensated level signal and the output is used as PV from the drum level controller.

In case 3E the controller LIC output goes to feed forward summation block where the steam flow is added to it & generates the remote set point flow controller FIC.

Steam flow measured using steam flow transmitter FT-1 & FT-2 , two out of two is performed, whish acts as a feed-forward signals & takes care of shrink & swell effects. the steam flow transmitter are connected across flow nozzle which is square rooted and then pressure & temperature compensation done.

This compensation takes care of error arising due to density variation of stream when boiler is operating at conditions different from design conditions.

For drum level compensation by modifying eqn 1

Hm + DP + h (ra - rs) / (rw - rs)

Hm = corrected drum level, DP = diff pressure measured by level transmitters, ra= wet led density (0.992), rs = saturated steam density(refer steam table) , rw = saturated water density , H = wet leg height (h=H)

PRESSURE IN KG/CM2	rw	rs
45.040	0.7910	0.0217
48.9	0.784	0.0237
……..	………	……..
88.644	0.7145	0.04623
94.990	0.07019	0.05225
101.68	0.6984	0.05461

Note - Hope I shall able to share more on PPIC,next to come – steam temp control , furnace draft , combustion control , CBD tank level control , deareator level , flue gas outlet temp control etc…….keep on visiting.

DBR (INST & CONT) - POWER PLANT

Tue, 20 May 2014 17:33:12 +0100

The design basis report for control & instrumentation seeks to establish the philosophy , salient features, and the proper design criteria for cont & inst.
The purpose of cont & inst system is to provide versatile automation for aiding the operating persons to carry complex jobs, to ensure safe & efficient operation and in the process relieving the operator to great extent.

1.CONTROL & OPERATION PHILOSOPHY
For easy operation of plant the entire plant is sub categorizes as -
a. Boilers & auxiliaries,vaccume & condensate system
b. Stream Generator ,Flue gas system , ESP ,Fuel Feeding & Ash extraction methodology
c. AHP with its auxiliaries
d. Compressed air system
e. Air cooling & ventilation
f. ACW, CWP system
g. CHP
h. DM Plant
i.Fire alarm system
j.Intake water & pump house
k.DE-DS system
l.HP/LP dosing system
m. SWAS & Silica Analysis system
n.Auxilary Electrical System - 132 Kv, 11 Kv , 6.6 Kv , 440v , 220V

2. CONTROL ROOM
Total plant operation will be executed from CCR at STG building operating floor. the control room will be air - conditioned & have false ceiling.
AVR,RMP,TSP,SP(Synchronising Panel), PA System, DCS Panel , SWRD Relay Panel etc will be in control room.
the approx size of control room depends upon panel sizeing & other sub panels.

3.STG
The STG control & other monitoring system shall be through DCS unit control desk LCD monitor (SCADA System).
Remember the following OLCS (OPEN LOOP CONTROL SYSTEM)

A. main & aux oil pump , B. emergency oil pumps , C. gland steam exhaust fans , D. condensate extraction pumps , E. QCNRV, F. ESV Logic , G. Lube oil centrifuge , H. turning gear motor , I. HP / LP inlet,outlet,bypass MOV , J. Vaccume breaker.
Remember the following CLCS (CLOSE LOOP CONTROL SYSTEM)

A. Hotwell level , B. CEP re-circulation C. Gland steam pressure control D. PRDS Control , E. Lube oil temp , F. LPH level control, G. HPH normal & emergency level control

4. GOVERNING CONTROL
Woodward 505 designed for high accuracy & sensitivity of response. The governer will have linear droop characteristics with a suitable range for stable operation & will have provision for adjusting the same with fine steps.(pls refer my previous post in this page below to see the governer calibration).
1. speed control 2. load control 3. frequency control
(detail shall be post on account of viewers demand and curosity to know woodward 505).

5. PROTECTIONS
The main function of the protection system is to shutdown the STG in case of occurance of dangerous operational faults.
(all the trips had been posts in my previous posts)

6. TURBO - SUPERVISORY INSTRUMENTATION

TSI monitoring system of Bently Nevada model 3500 will be provided to monitor steam turbine, gearbox , gen bearing vibrations & rotor axial shift & turbine speed.

7. BOILER CONTROLS

Control of boiler including BMS interlocks and its auxiliaries are given through DCS & MMI in CCR.
Remember the following automatic close loop control -
A. 3 or 1 element drum level control , B. Temp control for attemperator & De Superheater , C. Combustion Control , D. CBD Tank control, E. furnace draft control , F. LDO header pressure control , G. dearator pressure & level control , H. start up-vent control , I. air heater bypass control

8. BMS

The burner management system will be used for start up the boiler.
(pls refer my previous post for details)

9. POLLUTION MONITORING

1. NOx/SOx/CO 2. O2 Analyser 3. SPM
( follow prev posts on O2 Analyser)

There are many more auxillary systems in Power Plant only few i have depicted here,rest shall be post upon your interest. Any faulty post , suggestion or modification shall be heartily accepted.

HOW TO MAKE HOOP UP DRAWINGS FOR FILED INSTRUMENTS

Tue, 13 Nov 2012 07:37:58 +0100

Guide Line to prepare Hook- Up drawings for Field Instrument.
An Instrument Index is a super starting point for any design, it is really a database of all the necessary references which are required in an instrument design.

Tag number, Numbers of the loop drawing, Layout & routing drawing and isometric piping drawing containing the particular control loop component.
Elevations of both the primary control loop component and process connection.
Tagging of mechanical (piping or equipment) to instrumentation interface
Tagging of all elements/fittings & valves with item numbers.
Direction of slopes in hook-up lines.
Elevation of Instrument.
Maximum allowable lengths of hook-up lines.
Accessories often detailed include Monoflanges, Double Block and Bleed Valves and Fittings etc.
Material take off with part numbers, number of particular fittings, size, connection, material type, mounting type.
weather shield and tubing specification

MORE DETAILS SHALL BE UPDATED SOON.........keep visiting.

DCS- ARCHITECTURE

Wed, 07 Nov 2012 06:46:40 +0100

DCS-INTRODUCTION IN BRIEF

Tue, 06 Nov 2012 17:34:19 +0100