Boiler and Heater Operational Control

8/12/2019 Boiler and Heater Operational Control

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BOILER AND HEATER OPERATIONAL CONTROL

It is necessary to operate a boiler with more air than is theoretically needed to burn all the fuel. Burnercontrols are therefore always set to provide some amount of excess air in all operating scenarios,typically from two to five percent O2 in the flue gas. Excess air incurs a heat loss; it enters the combustionsystem at ambient temperature and leaves at stack temperature. Therefore, reducing the oxygen level in

the flue gas will reduce the heat loss.Tip: Typically, reducing oxygen in the flue gas by 1% increases boiler efficiency by about 2.5%.Controlling excess air is the most important tool for managing the energy efficiency andatmospheric emissions of a boiler system.It is important to keep in mind that the air-to-fuel ratio is based on mass, not volume. The mass of airsupplied to the mass of fuel being used (e.g. on a kilogram-to-kilogram basis) must be controlled. Thedensity of air and gaseous fuels changes with temperature and pressure, a fact that must be taken intoaccount in controlling the air-to-fuel ratio. For example, if pressure is fixed, the mass of air flowing in aduct will decrease when the temperature increases. The controls should therefore compensate forseasonal temperature variations and, optimally, for day and night variations too (especially during thespring and fall, when daily temperature variations are substantial).Similarly, the mass of natural gas flowing through a pipe will fall if the pressure in the supply pipe drops.(This may happen when the fuel flow to a second boiler increases.) Constant flow of liquid fuels, althoughless influenced by temperature, still depends on steady supply pressure to a valve maintaining a constantposition. If pressure increases (e.g. when a second pump is started), the oil flow for a given valve positionwill also increase.Variations in pressure and temperature can be corrected by sophisticated air and fuel controlsystems. Such systems can be expensive, so simpler systems are often used to avoid the expense. Theyare less precise and are set up with larger margins of excess air to avoid insufficient air conditions. Theycannot ensure optimum continuous operation. Due to the higher heat losses (i.e. lower energyefficiencies) associated with the cruder control systems, it pays to evaluate the economics of investing ina high-quality control system.For existing combustion equipment, measuring and minimizing excess air is the primary way tooptimize boiler and heater efficiency. Optimizing excess air (also referred to as O2 control) meansadjusting burner airflow to match fuel flow. Burner settings, initially calibrated during burnercommissioning, should be reviewed regularly. Carbon monoxide (CO) is a sensitive indicator ofincomplete combustion; its levels should range from zero to, perhaps, 50 parts per million (ppm) by

volume, rather than the usual environmental limit of 400 ppm. Each boiler house should have accuratelycalibrated analysers for measuring O2, CO and nitrogen oxides (NOx).Types of air and fuel controlsOn-off and high-low controlsThe use of on-off and high-low controls is limited to processes that can tolerate cycles of temperature andpressure, such as heating applications.Mechanical jackshaft controlsThe simplest type of modulating burner control is used in small burners, where the cost of morecomplex systems cannot be justified. These controls cannot measure airflow or fuel flow; the play in thejackshaft and linkages needs settings with higherthan-necessary excess air to ensure safe operationunder all conditions. The range of oxygen control (oxygen trim) is limited. The control response must bevery slow to ensure that the burner reaches a steady state before the oxygen trim acts.


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Parallel controlsSeparate drives in parallel controls adjust fuel flow and airflow, taking their signal from a master controller.The operator can adjust the flows individually and override the automatic control settings. These controlsare usually applied to older, medium-sized boilers equipped with pneumatic controls. Their performanceand operational safety can be improved by adding alarms that indicate if an actuator has slipped orcalibration has been lost. Also, an additional controller can be added to provide oxygen trim. Parallelcontrols have similar disadvantages to mechanical jackshaft controls.Cross-limiting controlUsually applied to larger boilers, cross-limiting control can sense and compensate for some of thefactors that affect optimum air-to-fuel ratio. This control measures the flow of air and fuel and adjustsairflow to maintain the optimum value determined during calibration tests. Flue gas composition can bemonitored and used in air control. Operations are safer when airflow cannot drop below the minimumneeded for the existing fuel. They are also safer when fuel flow cannot be increased more than theexisting airflow can burn. Oxygen trim is possible but, again, it has a limited range of adjustment. It mustalso respond slowly enough to allow the primary controls to reach equilibrium.Automatic control of excess air (oxygen trim)The high cost of purchasing and installing an oxygen analyser limits the use of oxygen trim controls to

large boilers. It increases energy efficiency by one to two percent. For very large boilers, where efficiency

gains of 0.1 percent mean significant annual savings, these controls usually measure CO as well.


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TOPIC: Boiler

The quality of a boiler is judged by its system

efficiency . But different norms of how to

calculate make comparison difficult and

confuse the issue

In this first installment of our tool kit, we will attempt

to learn the following:

Understanding different methods tocalculate system efficiencies.

Knowing the difference between the lowerand higher heating value of a fuel.

Appreciating the difference between thedirect and indirect method of measuringthe system efficiency.

Establishing a list of losses.

Understanding the basic mathematicsbehind efficiency calculations.

Converting between norm efficiencies.

Definition of System Efficiency

A boiler is an equipment that is sold with a guaranteed system efficiency. Some people call it design efficiency to

distinguish it from the operational efficiency.

For instance saying a boiler has a guaranteed efficiency of 83% means 17% of the energy input in the boiler (mostly

fuel energy) is lost and is not used to generate steam. The trouble with this practice is that there are several norms how

to determine and calculate efficiencies. Based on the norm efficiency the same boiler may have at least two design

efficiencies.

Any consultant involved in boiler testing should therefore have at least some understanding how thermal efficiencies

based on measured data, are calculated. The most basic equation everybody agrees is

Where

Adsorbed heat = Eout = The energy the feed water has picked up.

Energy Input = Ein = The energy going into the boiler.


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There is no disagreement of what "adsorbed heat" means. It is the energy needed to convert feed water entering the

boiler at a specific pressure and temperature to steam leaving the boiler at a specific pressure and temperature. This

includes the energy picked up by the blow down and not converted into steam.

Disagreement among national norms exist of what is considered an "energy input".Unfortunately any fuel has two

widely published energy contents. They are:

The Higher Heating Value (HHV), also called Gross Calorific Value (GCV)

The Lower Heating Value (LHV), also called the Net Calorific Value (NCV)

The functional relation between HHV and LHV is

where is the mass of water (in kg) generated by one kg of fuel during the combustion process, and

with

H = weight percent of Hydrogen in the fuel

xH2O= weight percent of physically bound water in the fuel.

It is assumed that all water is evaporated at 25C (the temperature of the systemboundary). A fuel contains physically

and

chemically bound water. Drying the fuel can drive off the physically bound water, while the chemically bound water is

formed through the reaction of Oxygen with the atomic Hydrogen of the fuel. Contrary to common believe and the

notation in the American norm, there is no molecular Hydrogen (H2) or Oxygen (O2) in the fuel.

The LHV is always smaller than the HHV.Table 1 gives an overview of how much LHV and HHV differ. See Table 1.

Table 1.

FUEL TYPE HHV LHV % CHANGE MJ/kg MJ/kg

Light fuel oil 44.003 41.255 6.24

Coal A 21.693 20.236 6.72

Wood, very dry (10% H2O) 17.739 16.308 8.07

Wood, freshly cut (70% H2O) 5.913 3.808 35.61

LPG (90% Propane) 50.250 46.256 7.95

Carbon, C 34.095 34.095 0

Bagasse (50% H2O) 9.855 7.974 19.08


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It should be noted that the adsorbed heat is a measured value and does not depend on the fuel energy input (LHV or

HHV). How much heat the feed water can adsorb is a matter of boiler design and operation.

For example, assume 1 ton of light fuel oil is fired in a boiler and the adsorbed heat has been measured as 36,500 MJ.

Using either the HHV or LHV as energy input we have

This boiler if tested by the German norm will be advertised with a design efficiency of about = 88% because this

norm uses the LHV for calculation, while the same boiler sold by an American company would have an = 83%

because the American norm uses the HHV as a basis for the energy input.

Due to the large difference, internationally known boiler manufacturers report both efficiencies in sales brochures.

Another

method to avoid any misunderstanding is to report the rated capacity in MW and the associated fuel consumption

based on a given HHV or LHV of the fuel.

NOTE 1: Calculating the thermal efficiency directly as suggested in equation (1) and (2) would require to

simultaneously measure the fuel flow, the steam flow, and the feed water flow. The procedure does not only involve

measuring flows (kg/h or m3/h) but also to record the fuel temperature and pressure of the steam and feed water.

With solid fuel fired boilers it is impossible to measure the fuel flow correctly. The direct method is therefore used very

seldom to determine the efficiency of a boiler in the field. It is used as confirmation of the measured losses if fuel, feed

water and steam meters are installed.

NOTE 2: Most performance testing and commissioning of smaller and medium sized boilers is done by the indirect

method measuring the losses and calculating the efficiency as

This is the preferred choice, because the method is based on the measurement of losses and shows opportunities to

reduce them.The HHV of the fuel is used as the relevant energy input.

NOTE 3: In case of a performance contract, verification of fuel cost reduction should be done by the direct method. This

implies that performance contracting of solid fuel fired boilers is complicated due to difficulties in measuring fuel flow.

NOTE 4: The correct derivation of the efficiency equation for the indirect method is


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In hot water boilers that may have stack gas temperatures below 90 oC, we observe system efficiencies of larger 100%

if the LHV is used as energy input in the direct method calculation. It is therefore recommended to avoid the LHV as

energy input, because it would violate the Second Law of Thermodynamics which says the energy output of a system

(boiler) cannot be larger than the energy input. In other words it is not possible to create energy in a boiler.

The Losses

Using the direct method one does not have to list losses because they dont enter into the calculation. With the indirect

method an agreement of what we consider a loss must be reached. The most logical way to do this is to draw a system

boundary around the boiler and declare all energy flows (except steam) that leave the boundary a loss. A sample list of

losses is

1. The chemical energy of unburned carbon monoxide (CO) in the stack gas.2. The sensible and latent heat of the dry stack gas and the water in the stack gas.3. The radiation and convection losses from the boiler surface.4. The blow down losses (Optional. Some norms dont consider it).

5. The sensible heat losses of the residue (ash).6. The unburned carbon losses (LOI) in the residue.7. All other combustible gases and solids in the stack gas such as Higher Hydrocarbons (CnHm), H2, and solid

carbon (C).

Only losses 1, 2, 4, 5, and 6 are measurable without too much effort and complications. One mainly tries to reduce

losses 2 and 6. Loss 6 is important in solid fuel fired boilers. There are a few other losses, such as steam used for oil

preheating and atomization in larger installations fired with "Bunker C" oil.

Percentage fuel savings

All our efforts to reduce energy consumption should be expressed in terms "percentage fuel saved". In case the

efficiency of a boiler is determent and measures are recommended to increase efficiency from an "as is" situation to an

new improved efficiency the percent savings of fuel consumption are given as

In the literature you may find all permutations of this equation such as

A definitely wrong but often used approximation is S = new - oldNote that S1= -S4and S2= -S3

Let us assume that the as is situation is given as


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Reducing losses means for the same level of energy output Eout less energy input Ein is needed. Consequently

where Ein is the amount of energy saved. A positive number. Applying equation S1will lead to

Consequently S1is the only correct equation. A positive number means fuel savings while a negative number means

additional fuel consumption. In another issue it will be explained that the above equation cannot be used to calculate

fuel savings from reduction of blow down or condensate return, since both are not considered losses.

Reference:

Boilers Operation Philosophy

The primary function of the boiler is to produce the steam in sufficient quantities to meetthe needs of the plant. In order to do this, the boiler requires fuel, air and water at all the

times during operation. The heat released during the combustion of the fuel produces

steam from the water. In most cases, the steam is heated further before leaving the boiler.This process is continuous for the entire period that the boiler is in operation.

The amount of steam varying according to the load changes. In order to change the steam

output, the boiler must change the rate of the air and fuel combustion and rate of water

flow proportionately. In order to respond to these changes accurately and efficiently,various control systems are used on the boiler.

Steam Boiler

Main Parts:FD Fan :

It sucks the air from the atmosphere and give for combustion chamber.

Air Fuel Ratio is 1Kg of Gas needs 10kg of air & 2.5kg of the access air.Steam Heater:

Steam heater will be used only during oil firing to increase the inlet air temperature to the

boiler.

Air Pre-Heater:It uses to make a heat exchange between hot flue gas going out and inlet cold

combustion air to the boiler.

Burners:
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The burner is the device that permits controlled burning of fuel inside the furnace. The

burner mixes the fuel with the required amount of air and directs the flame into the

combustion area. Each boiler has six burners. The burner comprises of gas burner and oilburner with atomizing steam connection.

Burner consists of:

Air Register:used to give an enough quantity of air to the burner for goodcombustion.

Ignition Gun: used to give ignition spark to the burner for firing.

Flame Detector:used to monitor the flame.

Cooling Air Fans:There are two cooling air fans are used to cool the burners and surrounding equipments

like flame detector, oil firing gun, gas burners.

Gas Supply Line:

Fuel gas comes from fuel gas reducing station, which maintains constant fuel gaspressure. In case of failure or low header pressure line 2 takes over and keeps the header

pressure to the required pressure.

Fuel Oil Supply Line:Fuel oil comes from fuel oil tank, through F.O transfer pumps it comes to oil system. Fuel

oil is maintained at 5-bar pressure by PLC control and F.O is supplied to fuel oil supplypumps which boosts to 22 bar pressure.

De-aerator:It used to remove the oxygen and any other gases which contents in the water.

Deaerator is used to store the water, which is feed pump inlet for each boiler.Feed Water System:

Treat the water by removing dissolved solids and dissolved gases.

Steam Drum:The primary purpose of the steam drum is to separate the steam from the boiler water.

Super Heater:

They are used to increase the steam temperature before it leaves the boiler.

Economizer:The economizer is used to heat the boiler feed water before it enters the steam drum.

Soot blowers:The unburned carbon is called the soot. In order to remove the soot and ash deposits

during operation, soot blowers are installed in the various locations in the furnace.

Waste Heat Recovery Boiler (WHRB):
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The function of the waste heat recovery boiler is typical to the normal boiler 1 and 2, but

there are some differences in operation modes, burners and fuel.

Operation modes:- Exhaust mode:this mode is used in normal operation by using flue gas, which is

coming from Gas Turbine Generator ( as well as supplementary firing by burners. In

this case the bypass stack damper and combustion air FD fan are closed and boiler inletdamper (BID) is opened.

- Island mode:this mode is typical to independent operation mode because burners

only operate the boiler. The boiler is separated from flue gas from GTG by close boilerinlet damper (BID) and open bypass stack damper and combustion air FD fan.

Burner group:There are seven burners are grouped in three groups as the following:1. Group I: burner elements 3 and 5.

2. Group II: burner elements 1, 4 and 7.3. Group III: burner elements 2 and 6.

Each burner is consist of:1. Pilot burner.

2. Flame detector.

3. Cooling air.4. Spark.

Sealing air fan:The function of sealing air fan is to seal and protect FD fan from heating up by flue gas in

exhaust operation mode. Also it seal bypass damper from flue gas leakage to the stake at

exhaust mode. The WHRB protection system will trip the boiler when the seal air pressure

less than 20 mBar.

BURNER MANAGEMENT SYSTEM (BMS):The B.M.S. is the system, which decides and takes appropriate action according to the

safety and protection of the boiler. Example: Fuel Gas pressure coming Low or Low /Lowaccording to set point, Boiler will trip by the protection logic through BMS when there is

low/low alarm.

TRICONEX PLC:Receives three different inputs for each of the measured variable. Any one differs from the

other two readings, PLC generates a discrepancy alarm and as soon as second measuredvariable differs from the set point defined in the PLC, a trip alarm is generated and theboiler shuts down for safety and protection of the equipment. This is called two out of three

voting system.
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INTERLOCK SYSTEM:

Interlocks are devices that sense off-limit operating conditions related to the start-up or

shutdown of the boiler. These devices act to permit a sequence of control actions whenstarting or shutting down the boiler. In this application, they are called permissive

interlocks. Other interlocks cause a shutdown sequence of control actions. In thisapplication, they are called tripping interlocks. All permissive to start and tripping signals

will mention in the protection system title of this report.

PROTECTION SYSTEM:To prevent or to save the plant from any damage, we use Protection Logic to perform the

following:

Warn the boiler operator of hazardous operating conditions. Protect the equipment from damage.

Ensure that the equipment functions in the proper manner.

Shut the equipment down when unsafe conditions occur or when operating limits areexceeded.

Boiler Protection & Sequence

Boiler Start Up Start burner 1 Release start up burner 1 Sequence burner 1 sequence fail reset

Boiler purged

Protection stop Burner 1 oil presale Burner 1 gas presale

Condition to step 02 Condition to step 03 Condition to step 04

Condition to step 05 Fuel gas. Quick shutoff valve step 07 Condition to step 08 Condition to step 09

Ignitor on Burner 1 oil on Burner 1 gas on

Condition to step 13

Sequence burner 1 on (End Feedback) Release start up burner 1 Set air flow to ignition start position from burner 1

Reset Ignition set point from burner 1

Boiler Protection Active Fuel gas vent valve close

Fuel gas quick shutoff valve close Gas burner 1 select

Atomizing steam open

Fuel oil quick shutoff valve close Fuel oil quick shutoff valve close oil burner 1 select Oil scavenge valve opened

Air slide UV291A open


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Flame monitor off

Ignitor not on

Start up sequence fail Stop sequence fail

Gas burner select Sequence burner guide gas protection active

Oil burner select Sequence burner guide oil protection active

Burner 1 sequence reset Burner 1 start sequence running

Burner 1 stop sequence running

Burner 1 on

Shut Down Inputs:

Boiler drum level low Furnace pressure high Control air pressure low

Flue gas damper not open

Damper before air heater not open

Emergency Push button (console) Emergency Push Button (DCS)

Emergency Push Button ( Ground Level) Emergency Push Button (Boiler Top) Emergency Push Button (9m Level)

24VDC to Solenoid Operate Valve failure

Cooling air pressure low Fuel gas pressure high Fuel gas pressure low

Fuel oil pressure low Fuel oil temperature low Atomizing steam pressure low

Scavenger steam pressure low Combustion air flow low Low fuel gas flow Low fuel oil supply flow

FD Fan on Combustion air is excess of the set point

Boiler Start Permissive Signal1. At lease one oil/gas burner on.2. Fuel oil / gas control valve closed.

3. Remote selected.4. Fuel gas selected.

5. Boiler purged.6. Burner start/ stop sequence not running.

BOILER CONTROL SYSTEM

The basic objective of the boiler control system during normal operation is to maintain

constant steam pressure at the steam header going to the plant. In other words theprimary control command originates with the steam pressure in the lines downstream fromthe secondary superheater. All other control signals will follow from the measurement and

desired response to the steam pressure. At the same time all control loops are designed for


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safe operation and will shut the systems down in the event of operating problems. The

boiler control system must perform the following functions:

Provide feed water to the boiler. Maintain steam output pressure.

Provide combustion air to the furnace. Provide fuel to the burners.

Provide draft to the furnace, flue and stack. Provide blow down of the drums.

The flow of feed water entering the boiler must equal the flow of steam and blow down

water leaving the boiler. Also the feed water control system must maintain the feed water,

the steam flow rates and the steam drum level at the same time, which was called three-element control system.

The burner management system (BMS) and Programmable Logic Control (TRICONEX PLC)controlled the boiler control system.

DRUM LEVEL CONTROL SYSTEM:The steam flow transmitter that is compensated for pressure, temperature and the feed

water flow transmitter, gives signals to the steam and water flow computing relay. The twosignals are balanced each other in the computing relay. Any change in the flow rates will be

transmitted to steam flow, water flow and drum level computing relay. The leveltransmitter, compensated for pressure and temperature, at the steam drum also sends asignal to this relay. At this point, the signal from the level transmitter is balanced with the

signal from the signal from the steam flow/water flow relay. Any difference between the

two signals is transmitted through the manual/automatic selector switch to the feed watercontrol valve. This signal positions the valve to provide the rate of feed water flow equal tothe steam flow rate, while maintaining the steam drum level at the same time.

Blow down control normally uses the conductivity of the boiler water to establish the blowdown flow rate.

AIR AND FUEL COMBUSTION CONTROL SYSTEM:On the fireside of the boiler the primary control functions are to: Control combustion airflow to the burners Control fuel flow to the burners

Control furnace draft and flue gas flowThese functions are also closely related and must be kept in proper balance to maintain

the correct firing rate and combustion gas flow to the furnace which controls the steam

pressure at the steam header.

The airflow must be kept in proportion to the steam flow. This is because, there is a directrelationship between the energy input (fuel and air) and the energy output (steam). Bykeeping the steam flow/air flow ratio at the proper value, maximum combustion efficiency

can be maintained.


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13. Developed bootable floppies for PMS PPSV initialization

Background:In plant operation Bootable floppies, which are essential for PMS system, are rapidly becoming defective due to aging. Only two nos. of bootable floppies are available for six systems.

The PPSV (Pre-processing Station has provision to boot Process Management System) from 3-1/2 inchfloppy drive. (Make: TEAC- FD235HF). The floppy drive is bundled with SCSI controller (MAKE: OMIT3500). The drive and controller are unique and not available in the market. The bootable floppy containsthe critical boot program. We have contacted BHEL, Motorola (OEM) and various other vendor globallybut replacement is not available for the defective part. Nowadays these components are not beingmanufactured. Also no support is available from Motorola on VERSADos operating system, which hasbecome obsolete.

Impact:Non availability of Process Management System to the operator.Operator will not be able to do effective process control as well as o peration.Jeopardise the safety of plant equipment.

Root Cause:Aging of bootable floppies on account of continuous us for 10 years.

Operating system VERSADos residing in the has become obsolete.Corrective Action:Sufficient nos. of bootable floppies developed jointly with BHEL.Successful efforts made to find method of making

Effectiveness Of Corrective Action:Sufficient nos. of bootable floppies are available & availability of PMS is ensured.Measurable Benefits: 100% Availability of PMS, which is vital for O & M, is ensured. Deferred the expenditure in the order of Rs. 2.5 crore till reasonable solution is found.Page 17 of 18


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14. Operation of ACW / ACW Pumps through DDC Logic along with Auto pickupscheme.

Background:Operation Of ACW / ECW Pumps Is Possible Only From The Local Panel. Local Panel Is At 0 Mtr. While

Control Room Is Located At 13.5 Mtr.Impact:During Emergency Of Tripping Of Ecw Pump, It Is Not Possible For Control Room Operator To Start ThePump Immediately. This May Lead To Unit Tripping And Loss Of Generation.

Reasons for taking up the plan:

ACW / ECW Pumps are critical auxiliaries of plant. To save the units from tripping in case of failure of ACW /ECW pump. Parallel operation was provided in PCR-2 from local panel, which involved abundant cabling. These pump were operating through relay logic. These systems require regular maintenance.Auto pickup facility of standby pump was not available.

ROOT CAUSE ANALYSIS:

1.Operation Of ECW / ACW Pumps Is Not Available From Control Room.2.Vendor Does Not Supply The Scheme Of Remote Operation Since Commissioning.

Corrective Action:Scheme Has To Be Prepared And Approved. Implementation Shall Be Done During Opportunity.Signals Like MCC Disturbance , Pump Auto Selection, Command On To Pumps Are Configured InSOE or Each Pump.

Purpose / envisaged benefits:Auto pickup facility of standby pump is provided through DDC.

All cabling is done directly from individual breaker of each pump to control panel in PCR-2. This has

reduced the cabling, which in turn shall reduce maintenance and increase reliability of system. Protections and permissive like MCC disturbance are provided through DDC which will ensure safeoperation of pumps. Critical events like MCC Disturb / Command ON of each pump is hooked to SOE for monitoring and

event analysis.Existing spare cable from local panel to PCR-2 can be utilized for same modification in U-1.Avoidance to one unit trip can lead to direct savings of Rs. 20 Lakhs. and preventing to inconvenience tocustomer

Measurable Benefits:1. Operator Shall Have The Operational Control Of The Pumps From Remote.2. In Case Of Emergency Operator Can Take Appropriate Action. Immediately.

3. Possible Unit Trip On ECW / ACW System Failure Shall Be averted.Page 18 of 18


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(Trend Setter Project 1)Reduction in Boiler Tube Failures

1.0 Introduction:The power sector demand and supply balance in the country is always tilted towardsdemand. The demand outstrips supply by a substantial margin. And the peak demand

supply gap is substantially higher than base demand supply position. In such a conditionthe availability of a generating capacity is very vital. A generating station in healthy conditionnot only supplies electricity to end-users but also provides stability to regional grid systemfor its proper functioning.In Indian power sector, coal based thermal power generating stations operate as base loadstations and they provide major chunk of the demand. Hence their availability is highlydesirable. These power plants have to undergo certain regulatory outages as well asoutages for necessary maintenance. These outages are termed as planned outages. Andall the other outages, which cause unit outage, are forced or unplanned outage. A typicalclassification of forced outage is shown below (Refer Fig: 1). As it is clear that the majorreason for forced outage is tube leaka

ge in boilerpressure parts.


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A coal based thermal power plant of the size of DTPS would loss its availability by about1.65 %, if it experiences one tube leakage every 6 months in each of its unit. This would beequivalent to a direct generation loss of 72 MUs and a direct revenue loss of Rs.215 Millionfor DTPS.Each start up of boiler / turbine after attending the problem would result in consumption oflarge quantity of oil, coal and DM water. The start / stop due to the frequent tube leakageswould affect the long-term life and performance of boiler and turbine. And in case offrequent leakages boiler parameters may also be need to be restricted to lower valuecompared to design parameters and this would result in continuous loss in heat rate.

2.0 Root Cause of Tube Failures:The boiler pressure parts are subjected to very high steam pressures and flow internallyand high temperatures and abrasive environment externally. Hence they are likely to failand cause a forced outage.India has huge reserves of coal that can be used for power generation. But the quality ofcoal is poor due to very high proportion of highly abrasive ash content. The ash content isas high as 45 % in Indian coals. The inherent nature of power generation process is suchthat the boiler pressure parts get a continuous exposure towards high temperature flue

gases containing abrasive ash. This erosion leads to tube thinning process, which ultimatelyresults in boiler tube rupture causing a forced outage.

3.0 Classification of Tube Failure Causes:A typical classification of boiler tube failure causes is shown below (Refer Fig: 2). Thispicture shows clear majority of tube failure cases due to erosion and welding failures.Page 2 of 24

A coal based thermal power plant of the size of DTPS would loss its availability by about1.65 %, if it experiences one tube leakage every 6 months in each of its unit. This would beequivalent to a direct generation loss of 72 MUs and a direct revenue loss of Rs.215 Millionfor DTPS.Each start up of boiler / turbine after attending the problem would result in consumption oflarge quantity of oil, coal and DM water. The start / stop due to the frequent tube leakageswould affect the long-term life and performance of boiler and turbine. And in case offrequent leakages boiler parameters may also be need to be restricted to lower valuecompared to design parameters and this would result in continuous loss in heat rate.

2.0 Root Cause of Tube Failures:The boiler pressure parts are subjected to very high steam pressures and flow internallyand high temperatures and abrasive environment externally. Hence they are likely to failand cause a forced outage.India has huge reserves of coal that can be used for power generation. But the quality ofcoal is poor due to very high proportion of highly abrasive ash content. The ash content isas high as 45 % in Indian coals. The inherent nature of power generation process is such

that the boiler pressure parts get a continuous exposure towards high temperature fluegases containing abrasive ash. This erosion leads to tube thinning process, which ultimatelyresults in boiler tube rupture causing a forced outage.

3.0 Classification of Tube Failure Causes:A typical classification of boiler tube failure causes is shown below (Refer Fig: 2). Thispicture shows clear majority of tube failure cases due to erosion and welding failures.Page 2 of 24


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But the welding failures for the jobs done during erection work in past is not preventableduring the O & M phase. So we have taken preventive measures for welding joints beingmade at our end. We ensure 100 % radiography and use of highly skilled high-pressurewelders. This has resulted in no welding joint failure of the joint made at our site since 1997.

Hence the focus gets shifted towards prevention and control of erosion related failures.4.0 Initial Innovative Strategy for Erosion Reduction:The cause of erosion is known and we undertook some preventive measures right at thebeginning of the operations of DTPS. We pioneered the concept of blending the low quality-high ash Indian coal with high quality imported coal having very low ash proportion.Thereafter we also improved the quality of available Indian coal by establishing a coalwashery near pithead and washing the low quality Indian coal and reducing its ashproportion by about 10 %. And again blended this better quality Indian coal with high GCVLow ash imported coal.Page 3 of 24

These efforts gave us good results and this is evident from the statistics of tube failure cases for

DTPS vis--vis that of NTPC

a leader in Indian power generation sector. NTPC mainly uses

indigenous coal having high ash content. And even after rigorous preventive measures the rate of

tube failures is high (refer fig: 3). This clearly shows advantage of use of blended coal over the use

of Indian coal. And now the practice of coal blending is being adopted by progressive utilities all


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over the country. The innovative practice of coal blending was started way back in 1996 and it has

given very good results for DTPS.

5.0 Continuous Improvement through further Innovation:But after year 2002 we thought of having further improvement in the boiler performance andwanted more reliability / availability. As the demand of Mumbai suburban region wasgrowing at a faster rate, high availability and reliability of boilers at a much higher loadingwas becoming a necessity.The blended coal has still an ash content of @ 25% and that again causes erosion but at alower rate. This erosion also ultimately leads to boiler tube leakage and unplanned forced

outage. The use of 100 % imported coals of 1-2 % ash content is techno economicallyunviable as the boilers are not designed accordingly and cost of generation also would behighly subjected to cost of imported coal.Page 4 of 24


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5.1 Prevention of ErosionConventional Techniques:There are prevalent industry wide practices of erosion prevention or reduction.

1. Thicker tubes2. Shielding

But these techniques have disadvantages. All the areas of boiler are not easilyapproachable. Hence in such areas it is difficult to provide shielding. Also provision ofshielding in some areas would disturb the established gas flow pattern. And more flow mayget directed towards newer zones making them more erosion prone. Provision of thickertubes need to be done right at the design stage for erosion prone zones. But these wouldresult in comparative inefficient heat transfer process.Hence discussions with industry experts, recommendations of OEM and our own pastexperiences led us to thinking about having some protective layer over the tubes exposedto highly abrasive, high temperature and high velocity ash laden flue gases.Our past experiences and those of NTPC showed some clear trends of vulnerable zones ofboiler. The boiler tubes in these zones were subjected to more erosion compared to rest ofthe internals. The areas may be different from one boiler to another due to different flow

patterns, gas distribution, misalignments in tube rows, vicinity of soot blowers, etc. Ashaving a protective layer over complete boiler internals would not be technically andeconomically feasible, the vulnerable zones of the boiler were identified and decided to givea protective anti erosion layer.

As an improved practice to monitor vulnerable areas of the boiler, we started doing aregular extensive tube thickness survey for the boiler. The results of these surveys andfailures of boiler tubes due to erosion were showing similar trends (refer Fig: 4 & 5).Page 5 of 24


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5.2 Technology of HVOF Process:Selection of the process:In market there are many technologies available for surface coating.1. Wire Flame spray2. Arc wire spray


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3. Powder Flame spray4. Plasma sprayBut, in the above-mentioned surface coating technologies, temperature used for thespraying as well as base metal temperature goes more than 600 C, which may lead tochange in microstructure of the metal.

5.3 High Velocity Oxy Fuel (HVOF) Process:The process is designed to give high level of coating density and adhesion to the substrateand can handle coating materials in powder form such as tungsten carbide / cobalt,chromium carbide / nickel chrome, triballoy and inconel. This process gives very dense andhigh adhesion deposits, and has application in space, defense, chemical, petrochemical,and power generation and aircraft industries.

As, in this HVOF process, temperature of base metal is not crossing more than 300 deg C,hence microstructure of the base metal is retained.

Also, advantage of this process is that porosity is very low & adhesion is very good. Andhence the technology of HVOF for anti erosion coating was selected.

5.4 Implementation:We have decided to replace the eroded tubes by surface coated tubes in phased manner.

The reason for carrying out the replacement job in phase manner was some selectivereplacement could be done due to limited time span of the O / H and it would also providean opportunity to evaluate the performance of the coated tubes.Page 7 of 24


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Phase I:In DTPS, water wall tubes near burner panel are the most erosion prone area. Of the totalnumber of tube leakages due to erosion, 60% occur in water wall tubes. Hence we replacedthese eroded tubes by surface coated tubes during overhaul of U # 1and 2 during theirrespective overhauls. Cost incurred during the implementation of Phase-I was Rs 2.3

Million.Phase II:The second most erosion prone area is economiser tube. Of the total number of tubeleakages due to erosion, 15% occur in economiser tubes. As above phase1 replacementis showing very good results, we are planning to replace eroded economiser tubes bysurface coated tubes during the next proposed overhaul.Page 8

Location of Erosion prone areas in DTPS Boiler


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6.0 Conclusion:From the trend shown (Fig-7) here it is very clear that there has not been a single tube leakage since

2003 in the areas where it was highly probable due to high erosion patterns observed in past. The

strategy of tube coatings has helped us with improving our availability(Fig-9) and also maintaining

the high loading factor(Fig-10).


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We have been able to operate DTPS units at a record availability and loading factor andmaintain yearly plant loading factor at more than 100 % with lowest heat rate(Fig-8) in Indiasince 2003-04.The resultant heat rate is lower by 2.54 % from the base value of 2320 Kcal/ KWH in 2001-02.The project of providing additional protection to boiler tubes in vulnerable areas can be veryeasily replicated across the industry. It can be applied to large utility boilers as well assmaller industrial boiler the benefits to the consumer would be immense as mentionedearlier.

Page 10 of 24


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Direct Benefits:(a) In case of a tube leakage DTPS looses revenues of Rs. 18 Million for this loss ofgeneration. This loss of generation needs to be bought from external sources at a muchhigher rate than the generation cost of DTPS. Hence prevention of one tube leakage helpsthe company to continue to provide subsidy or lower tariff to retail consumers.

(b) Also start up after each tube leakage consumes on an average1. 75 Kilo Litters oil2. 50 Tonnes of coal

These resources are consumed without generating electricity. Hence it is a direct loss. Thisdirect loss costs are more than Rs 1 million for DTPS. Also these processes generateadditional green house gases.Hence prevention of one tube leakage provides benefit in terms of

1. Lower tariff to consumers2. Lesser pollution & resource conservation to society at large


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(Trend Setter Project 2)Reduction of Boiler Exit Flue Gas Temperature

The Indian power sector has always been operating in the deficit regime. The customer hasbeen facing the brunt of the impact. The power costs and availability of quality power arethe major issues for the customer. And the suppliers have been charging for availability and

reliability. In the regions where players other than state electricity boards are supplying thepower directly to the end user, they have been charging a premium for the consistentsupply. Hence the power availability, quality and ultimately the cost are the three issues,which the customer has been dealing with to control his own costs.In India, the coal based thermal power plants are the backbone of the power generationsector. Out of total generation more than 70 % is being met by the coal based thermalplants. The soaring cost, unreliability of supply, dependency on other countries has made oiland gas power plants not viable. Almost all of existing oil and gas-based power plants areeither idle or running with reduced capacity. Non-fossil / renewable energy based power isconsidered an alternate due to its environmentally clean power and non-exhaustive primaryenergy source. But commercially and economically it is not viable due to high capitalinvestment.

Hence efficiency of the coal-based power plant plays a major role in the costs of poweravailable for consumption. The basic coal based power generation plants operate on themodified Rankine cycle. Here there is a lot of scope for inefficiencies. Or inversely there is alot of scope for improvement in the operating efficiency.Page 13 of 24


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Analysis of Boiler Efficiency: -

The steam generator is the heart of any coal based thermal power station. The boiler operations

play a major role in maintaining and improving the efficiency of the power generation cycle and

they affect the power costs. Following graph shows a breakup of design efficiency of DTPS boiler.

And the 2nd

figure shows the typical breakup of actual boiler operation for DTPS.

As it can be seen from the figure that that dry & wet flue gas losses and the unburntcarbon losses are the major losses. The efforts of DTPS O & M team were focused on

these losses as the boiler efficiency can be greatly improved by reducing these losses.Page 14 of 24


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The wet flue gas losses are mainly dependent on the characteristic of the fuel and theycannot be controlled. While the dry flue gas losses are controllable as they mainly dependupon

Flue gas volume Flue gas temperature

The innovative strategy for boiler efficiency enhancement was implemented in two phases.

1st

phase involved control of excess air. All the boiler engineers know that every percentreduction in residual Oxygen (after air preheater) improves the heat rate by 0.3%. But thisthumb rule cannot be applied blindly.The combustion of coal in huge quantity is needs a highly controlled environment for safeand efficient result. DTPS operations concentrated in controlling oxygen by checking COin exit flue gas. The investment was done in CO measurement equipment. The COmeasurement also posed a great challenge not only in measurement but also in sustainingthe validity of these measurements. The original location of the sensing elements, assuggested by the OEM, was highly prone to problems. Hence it was shifted to 70-meterheight in the flue gas stack. This helped in establishing the reliability of the measurement

of flue gas CO content an eventually the reduction in excess air to an acceptable level.The next step was to improve the measurement of residual Oxygen in the flue gasses.The flue gas duct of a 250 MW boiler is huge equipment. And to control the combustion onthe basis of a single point measurement of Oxygen cannot give accurate results. So tostart with additional investments were made for procuring and commissioning additionalOxygen sensors. So the residual Oxygen measurement was done based on multiplesensors.DTPS boiler operators have been given a target to maintain the excess air level < 12%with CO levels at < 50PPM in hourly average as a part of their own functional levelobjectives. This strategy of involving desk engineers has given very good results. For thewhole of last financial year 2005-06 the average excess air was maintained at 12.3 %. The

trend of monthly average excess air as measured by online instrumentation is shownbelow.


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Page 15 of 24

The Problem: -

The other factor affecting the flue gas losses is the temperature of exit flue gases. Forevery 1 C rise in exit flue gas temperature the heat rate deteriorates by 1 Kcal / Kwh.

Almost all the coal based thermal power stations have a problem of high exit flue gastemperature. The APH exchanges heat between the flue gasses coming out of the boilerand gives it to primary/secondary out of the boiler and gives it to primary/secondary air.But this is not the only equipment, which affects the exit flue gas temperature.The flue gas temperature is affected by

Condition of air pre heater. Condition of furnace heat transfer surface cleanliness Condition of fuel firing equipment

The problems of these equipments are generally dealt with during overhauls and rectifiedto an extent. These losses can be controlled by way of use of good O & M practices like Regular soot blowing of Air preheater Soot blowing of furnace heat transfer surfaces by use of water wall & long

range soot blowers Replacement of air heater baskets Reconditioning / replacement of coal burners Regular cleaning of furnace


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Page 16 of 24


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But the problem still cannot be eliminated and it becomes a part of day-to-day O & Mactivity. DTPS also has been facing the problem of high exit flue gas temperature.Analysis of the Problem at DTPS: -The following schematic diagram shows the coal milling system of DTPS.

Figure 3:

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Boiler and Heater Operational Control