Pumps in Steam Power Plants

8/12/2019 Pumps in Steam Power Plants

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Pumps in Steam Power Plants

Life Inducing Devices

P V SubbaraoProfessor

Mechanical Engineering Department

I I T Delhi


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Classification of Pumps


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Pumps in Steam Power Plants

Turbogenerator & Auxiliaries 3 sets.

Steam generator equipment 6 sets.

Chemical feed system 13 sets.

Fuel Oil systems

14 sets.

Lubricating oil systems 5 sets.

Fire Protection systems 6 sets.

Service water system 7 sets.

Miscellaneous around 4 sets.


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Pump services in Main Steam Cycle

Turbogenerator and auxiliaries Condenser circulating pumps

Screen wash-water pumps

Cooling tower make-up pumps

Steam generator equipment Condensate pumps

Condensate booster pumps

Boiler-feed pumps

Boiler-feed booster pumps

Deaerator make-up pumps

Heater drain pumps (low and high pressure)


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Boiler Feed Pumps

The boiler feed pump (BFP) is one of the most importantauxiliary equipments in coal-fired power plants.

With the increase in steam parameters of thermodynamic cycle

and the growth of unit capacity, the power capacity of boiler

feed pumps is also growing. The power consumption of BFP has been accounted for about

5% of power generation capacity in the large generating units.

The reasonable choice for boiler feed pump driving mode

plays an important role in the operation economy of the entirepower plant.

The type and number of BFP and the design of its water

supply system have a great impact on thermal efficiency and

operation cost


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Boiler-Feed Pump Capacity

The total boiler-feed pump capacity is established by adding tothe maximum boiler flow a margin to cover boiler swings and

the eventual reduction in effective capacity from wear.

This margin varies from as much as 20% in small plants to as

little as 5% in the larger central stations. The total required capacity must be either handled by a single

pump or subdivided between several duplicate pumps

operating in parallel.

Industrial power plants generally use several pumps. Central stations tend to use single full-capacity pumps to serve

turbo-generators up to a rating of 100 or even 200 MW and

two pumps in parallel for larger installations.


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Cross-section, single 65,000 hp boiler feed pump,

1300 MW fossil power plant


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Suction Conditions

The net positive suction head (NPSH) represents the net

suction head at the pump suction, referred to the pump

centerline, over and above the vapor pressure of the

feedwater.

If the pump takes its suction from a deaerating heater, the

feedwater in the storage space is under a pressure equivalent to

the vapor pressure corresponding to its temperature.

Therefore the NPSH is equal to the staticsubmergence

between the water level in the storage space and the pumpcenterline less the frictional losses in the intervening piping.


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Erection of Pump


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Theoretically, the requiredNPSH is independent of operating temperature.

Practically, this temperature must be taken into account when establishing the

recommended submergence from the deaerator to the boiler-feed pump.

A margin of safety must be added to the theoretical requiredNPSH to protect theboiler-feed pumps against the transient conditions that follow a sudden reduction

in load for the main turbogenerator.

The discharge pressure of the condensate pump or the booster pump must be

carefully established so the suction pressure of the boiler-feed pump cannot fall

below the sum of the vapor pressure at pumping temperature and the requiredNPSH.

Careful attention must be given to any strainer that might be installed in the

pump suction piping.

The pressure drop increase across the strainer is indicative of foreign material

and it reduces the net positive suction head available (NPSHA) to the pump.

Strainersin the pump suction pipe are most often removed following plant start-

up qualification testing.


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Pump with lower NPSH


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Transient Conditions Following Load Reduction

Following a sudden load reduction, the turbine governor reduces

the steam flow in order to maintain the proper relation betweenturbine and generator power and to hold the unit at synchronous

speed.

The consequence of this reduction is a proportionate pressure

reduction at all successive turbine stages, including the bleed

stage that supplies steam to the deaerator.

The check valve in the extraction line closes and isolates the

heater from the turbine.

As hot feedwater continues to be withdrawn from the heater and

cold condensate to be admitted to the heater, the pressure in the

direct-contact heater starts to drop rapidly.

The check valve reopens when the heater pressure has been

reduced to the prevailing extraction pressure and stable

conditions are reestablished.


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Alternate Means for Low Load Conditions

In the event that circumstances do not permit the provision ofsufficientNPSH margin to provide adequate protection to the

boiler-feed pumps during a sudden turbine load reduction, two

alternate means are available to compensate for these

circumstances:

A small amount of steam from the boiler can be admitted to

the direct-contact heater through a pressure-reducing valve, to

reduce the rate of pressure decay in the heater.

A small amount of cold condensate from the discharge of the

condensate pumps can be made to bypass all or some of the

closed heaters and be injected at the boiler-feed pump suction

to subcool the feedwater, thus providing additionalNPSH

margin during load reduction.


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BOOSTER PUMPS

The increasing sizes of modern boiler-feed pumps coupled

with the practice of operating these pumps at speeds

considerably higher than 3600 rpm have led toNPSH

requirements as high as 46 to 76 m.

In most cases, it is not practical to install the direct-contact

heaters from which the feed pumps take their suction high

enough to meet such requirements.

In such cases, it has become the practice to use boiler-feed

booster pumps operating at lower speeds, such as 1750 rpm, to

provide a greater availableNPSH to the boiler-feed pumpsthan can be made available from strictly static elevation

differences.

Such booster pumps are generally of the single-stage, double-

suction design.


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Axially split case multistage boiler feed pump, up

to 241 bar


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Radially split, segmental ring boiler feed pump

upto 240 bar


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Radially split, double-case, barrel boiler feed pump

above 250 bar


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High-Speed, High-Pressure Boiler Feed Pumps

As steam pressures rose to 200 to 310 barthe total head thatwas required to be developed by the pump rose to as high as

2140 and 3660 m.

The only means available of achieving these higher heads at

3000 rpm was to increase impeller diameter and the number ofstages.

The pumps had to have longer and longer shafts to

accommodate the larger number of stages.

This threatened to interfere with the long uninterrupted lifebetween overhauls to which steam power plant operators were

beginning to become accustomed.

The logical solution was to reduce the shaft span by reducing

the number of stages.


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Drives for Boiler Feed Pumps

There are many factors which affect the driving modes of

BFP, such as thermal economy and operational reliability,

amount of equipment investment and complexity of the system

structure, etc.

Among the factors above, thermal economy is one of the most

important factors when choosing the driving mode of BFP.

As is well known, there are two driving types that are motor-

driven and steam-driven for boiler feed pumps.


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International View : Motor Driven BFPs

The designers and owners of coal-fired power plants in

Western European countries tend to adopt motor-driven pumps

system to feed water for boiler.

The reasons for the choice are that internal efficiency of small

steam turbines which drive feed water pumps in their countries

is almost equivalent to the product of the efficiency of power

transmission and internal efficiency of low-pressure cylinder

of main steam turbine.

On this premise, an integrated investment of motor-driven feedwater pump system is lower than that of steam-driven feed

water pump.


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International View : Steam Driven BFPs

Other people such as American, Russian and Japaneseconsider that steam-driven mode is superior to motor-driven

mode.

The cause of this choice is that the internal efficiency of the

small steam turbine produced by companies in their countrieshas much higher than the product of the efficiency of power

transmission and internal efficiency of low-pressure cylinder

of main steam turbine.

In other word, the net output of generating unit which hassteam-driven feed water pumps is more than that of the same

generating unit which feed water system is driven by

electromotor.


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New Methods for Comparison

A new method called equivalent work efficiency rate to

evaluation thermal economy of the two main feed water pump

driving modes.

Thermal economy evaluation of the two main feed water pump

driving modes.

The heat consumption rate and comprehensive cost-based coal

consumption based on the principle of energy value analysis.


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COMPARISON OF THEIR HEAT CONSUMPTION

RATE

Description of heat consumption rate

Analysis and discuss of an example


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Description of heat consumption rate

Generally speaking, heat consumption rate (HR) is the key

indicator to determine thermal economy of thermodynamiccycle and operation of the turbine generator unit.

From different point of view, it has two expression forms, one

known as the gross heat rate, and the other called the net heat

rate. Heat consumption rate is defined as the amount heat which

generated 1kWh electricity by generating unit.

For different thermodynamic cycle, the formula of heat rate

has different expression forms. To the intermediate reheating unit whose boiler water is fed by

motor-driven pump, the gross heat consumption rate can be

expressed as


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Gen

crhhrhrhsteamfwmainsteam

P

hhmhhmHR

sup

The net heat consumption rate can be expressed as Formula

bfpGen


PP

hhmhhmHR

sup

To the intermediate reheating unit whose boiler water is fed by

steam-driven pump, the gross and net heat consumption rate are

formulated as

bfpGen


PPhhmhhmHR

sup

Gen


P

hhmhhmHR

sup


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Analysis of A Case Study

As the actual operation of generating unit and the configuration

parameters of motor-driven pumps were not exactly the same indifferent generating unit, the net heat rate of motor-driven pump was

calculated based on an average power consumption of a variety of

motor-driven pumps.

These thermal calculations were preformed for a plan of condensingturbine-driven pump, and then net heat consumption rates in

different operation conditions were obtained.

According to the average power of electromotor units and the

original design gross heat rates of the generator units, the net heat

consumption rates of motor-driven constant speed pumps and

motor-driven variable speed pumps in the sliding pressure modes

were calculated respectively after taken into account enthalpy rise in

feed water pump.


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NET HEAT CONSUMPTION RATES OF FEED

WATER PUMP DRIVEN BY STEAM AND ELECTRICITY OF

300MW UNIT IN SLIDING PRESSURE MODEKJ/KW


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Comparison : Steam & Constant Speed Motor

Thermal economy of steam- driven pumps is better than that of

motor-driven pumps in different operation loads.

In particular, thermal economy of constant speed electric pump

declines quickly in low loads.

As their operating speed is not adjusted, constant speed

electric pumps work in the variable load by reducing the pump

outlet pressure by the way of regulating flow which can be

performed by altering the pump speed through a throttle valve,

so that thermal efficiency of generating units in low-loaddeclines much.


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Comparison : Steam & Variable Speed Motor

Compared to that of the motor-driven mode of variable speed,

thermal economy of units which use steam-driven pumps to feed

water in full load has increased but not significantly.

Better at low load interval from 50% to 90%.

The main reason is that the efficiency of hydraulic coupler is

much lower than that of small steam turbine (SST) driving feed

water pump particularly in low load, and there are electro-

mechanical loss and power transmission loss.

The internal efficiency of SST changes slightly in variable load

conditions, although it is lower than that of main turbine in full

load.

At the same time SST can drive directly feed water pumps,

resulting in better thermal economy, because intermediate link of

energy conversion and transmission is few.


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EQUIVALENT WORK EFFICIENCY

Relative equivalent work efficiency rate is defined that the

ratio of power consumption of motor-driven pumps and

electricity which can be generated in steam turbine by the

equivalent enthalpy drops of the steam flow from extraction

point entering into SST.

This definition can reflect thermal economy of energy owned

by steam and electricity.

The calculation method by equivalent work efficiency is easy

to understand and be performed, simultaneously avoiding thecomputational precision difficulty of small steam turbine

exhaust enthalpy.


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Comprehensive Cost-based Coal Consumption rate

On the basis of the principle of energy value analysis,the term of comprehensive cost-based coal consumption

rate (CCCR) was brought forward, and it is defined as

the following expression.

Comprehensive power generation costs are made of the unitgenerating cost and the cost of plant electric consumption.

Unit generating cost can be express as the product of standard

coal consumption rate for generating and unit price of standard

coal


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The cost of plant electrical power consumption is equal to the

product of power consumption rate and pool purchase price.

So formula of CCCR can be expressed as:


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The physical meaning of CCCR

The physical meaning of CCCR is that the power consumptionof standard coal when 1kWh electricity generated according to

comprehensive generating cost.

Comprehensive cost-based coal consumption rate is a

corrected expression of standard coal consumption rate of

power supply considering monetary values of electricity and

coal.

It reflects main comprehensive cost of generating electricity

essentially.


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Comparison of CCCR


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CONCLUSIONS

With the increase of unit capacity, capacity of feed water

pump correspondingly will increase.

The steam-driven mode of the variable-speed pumps by small

steam turbine will be more and more acceptable to much more

people.

A steam-driven mode is better than motor-driven mode in

thermal economy.

Compared with motor-driven pumps, steam-driven pumps are

good to net electrical output increases for large units, reducing

the net heat rate of generating and CCCR.


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The small steam turbine driving variable-speed pumps does

well in declining of power consumption rate and rising of

operation efficiency, thus it could replace motor-driven pumps

in future.

The driving mode of boiler feed pump is mainly affected by

thermal economy of system.

Besides thermal economy of system, the driving mode of

boiler feed pump also depends on comprehensive combination

of investment income, operating reliability, complexity of

system structure.


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Head Vs Flow Rate & Selection of Operating Point

2

21 QKKHf


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PUMPS R i P ll l


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PUMPS Running Parallel


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Operation of Pumps at Low Flows

There are a number of unfavorable conditions which may occur

separately or simultaneously when the pump is operated at reducedflows. Some include:

Cases of heavy leakages from the casing, seal, and stuffing box

Deflection and shearing of shafts

Seizure of pump internals

Close tolerances erosion Separation cavitation

Product quality degradation

Excessive hydraulic thrust

Premature bearing failures

Each condition may dictate a different minimum flow low requirement. The final decision on recommended minimum flow is taken after

careful techno-economicalanalysis by both the pump user and themanufacturer.


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Cavitation

As the liquid flows onto the impeller of the pump it is acceleratedand initially its pressure falls (Bernoulli).

The pressure subsequently increases as the fluid leaves theimpeller and as the kinetic energy is recovered in the volutechamber.

If the pressure of the liquid falls below the vapour pressure, Pv, theliquid boils, generating vapour bubbles or cavities-cavitation.

The bubbles are swept into higher pressure regions by the liquidflow, where they collapse creating pressure waves and causemechanical damage to solid surfaces.

Moreover, pump discharge head is reduced at flow rates above thecavitation point.

Operation under these conditions is not desirable and damages theequipment.


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NPSH (Net Pressure Suction Head).

Net Positive Suction Head Required, NPSHr

NPSH is one of the most widely used and least understood termsassociated with pumps. Understanding the significance of NPSH isvery much essential during installation as well as operation of thepumps.

Pumps can pump only liquids, not vapors Rise in temperature and fall in pressure induces vaporization

NPSH as a measure to prevent liquid vaporization

Net Positive Suction Head (NPSH) is the total head at the suctionflange of the pump less the vapor pressure converted to fluid column

height of the liquid.


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P f f A D d I ll


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Performance of A Damaged Impeller


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Performance with Reduced Throat Area

P ith Mi W


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Pump with Minor Wears

Pump with Excessive Wear


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Pump with Excessive Wear

Pump with rough impeller & casing


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Pump with rough impeller & casing

Documents

Pumps in Steam Power Plants