Boiler Feed Pump - Presentation handbook.pdf

Pumps in Steam Power Plants

P M V Subbarao Professor M h i lE Mechanical Engineering i i D Department t t I I T Delhi

Life Inducing Devices Devices……

Classification of Pumps

Pumps u ps in Stea Steam Power o e Plants a ts • • • • • • • •

Turbogenerator g & 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. sets

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 Co de sate booster booste pumps pu ps Boiler-feed pumps Boiler-feed booster pumps Deaerator make-up make p ppumps mps Heater drain pumps (low and high pressure)

Boiler o e Feed eed Pumps u ps • The boiler feed pump (BFP) is one of the most important auxiliary equipments in coal coal-fired fired power plants. 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 units. • The reasonable choice for boiler feed pump driving mode plays an important role in the operation economy of the entire power 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

Boiler-Feed o e eed Pump u p Capac Capacity ty • The total boiler-feed pump capacity is established by adding to the h maximum i boiler b il flow fl a margin i to cover boiler b il swings i andd 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. 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.

Cross-section, single 65,000 hp boiler feed pump, 1300 MW ffossilil power plant l t

Suction Suct o Conditions Co d t o s • The net ppositive suction head ((NPSH)) represents p the net suction head at the pump suction, referred to the pump centerline, over and above the vapor pressure of the feedwater. 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 static submergence between the water level in the storage space and the pump centerline less the frictional losses in the intervening piping.

Erection of Pump

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Theoretically, the required NPSH is independent of operating temperature. Practically this temperature must be taken into account when establishing the Practically, recommended submergence from the deaerator to the boiler-feed pump. A margin of safety must be added to the theoretical required NPSH to protect the boiler-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 required NPSH. 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 pump. Strainers in the pump suction pipe are most often removed following plant startup qualification testing.

Pump with lower NPSH

Transient Conditions Following Load Reduction • Following a sudden load reduction, the turbine governor reduces the steam flow in order to maintain the proper relation between turbine 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.

Alternate te ate Means ea s for o Low o Load oad Co Conditions dto s • In the event that circumstances do not permit the provision of sufficient NPSH 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: i t • A small amount of steam from the boiler can be admitted to the direct-contact heater through g a pressure-reducing p g valve,, to reduce the rate of pressure decay in the heater. • A small amount of cold condensate from the discharge of the condensate d t pumps can be b made d to t bypass b all ll or some off the th closed heaters and be injected at the boiler-feed pump suction to subcool the feedwater, thus providing additional NPSH margin during load reduction.

BOOSTER OOS PUMPS U S • The increasing sizes of modern boiler-feed pumps coupled with the ppractice of operating p g these pumps p p at speeds p considerably higher than 3600 rpm have led to NPSH requirements as high as 46 to 76 m. • In I mostt cases, it is i nott practical ti l to t install i t ll the th direct-contact di t t t 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 available NPSH to the boiler-feed boiler feed pumps than can be made available from strictly static elevation differences. • Such booster pumps are generally of the single-stage, doublesuction design.

Axially split case multistage boiler feed pump, up t 241 b to bar

Radially split, segmental ring boiler feed pump upto t 240 b bar

Radially split, double-case, barrel boiler feed pump above b 250 b bar

High-Speed, g Speed, High-Pressure g essu e Boiler o e Feed eed Pumps u ps • As steam pressures rose to 200 to 310 bar—the total head that was required to be developed by the pump rose to as high as 2140 and 3660 m. g heads at • The onlyy means available of achievingg these higher 3000 rpm was to increase impeller diameter and the number of stages. • The pumps had to have longer and longer shafts to accommodate the larger number of stages. • This threatened to interfere with the longg uninterrupted p life between overhauls to which steam power plant operators were beginning to become accustomed. • The Th logical l i l solution l ti was to t reduce d the th shaft h ft span by b reducing d i the number of stages.

Drives es for o Boiler o e Feed eed Pumps u ps • There are manyy factors which affect the drivingg modes of BFP, such as thermal economy and operational reliability, amount of equipment investment and complexity of the system structure etc. 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 motordriven and steam-driven for boiler feed pumps.

International te at o a View e : Motor oto Driven e BFPs s • The designers g and owners of coal-fired ppower plants p in Western European countries tend to adopt motor-driven pumps system to feed water for boiler. • The Th reasons for f the th choice h i are that th t internal i t l efficiency ffi i off small ll 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, premise an integrated investment of motor-driven motor driven feed water pump system is lower than that of steam-driven feed water pump.

International te at o a View e : Stea Steam Driven e BFPs s • Other people such as American, Russian and Japanese consider id that h steam-driven di mode d is i superior i to motor-driven di mode. • The cause of this choice is that the internal efficiency of the small steam turbine produced by companies in their countries has much higher than the product of the efficiency of power transmission and internal efficiency efficienc of low-pressure lo press re ccylinder linder of main steam turbine. • In other word,, the net output p of ggenerating g unit which has steam-driven feed water pumps is more than that of the same generating unit which feed water system is driven by electromotor. electromotor

New e Methods et ods for o Co Comparison pa so • A new method called equivalent q work efficiencyy rate to evaluation thermal economy of the two main feed water pump driving modes. • Thermal Th l economy evaluation l ti off the th two t main i feed f d water t pump driving modes. • Thee heat eat co consumption su pt o rate ate and a d comprehensive co p e e s ve cost-based cost based coa coal consumption based on the principle of energy value analysis.

COMPARISON OF THEIR HEAT CONSUMPTION RATE • Description p of heat consumption p rate • Analysis and discuss of an example

Description of heat consumption rate • Generally speaking, heat consumption rate (HR) is the key indicator to determine thermal economy of thermodynamic cycle l andd operation ti off the th turbine t bi generator t unit. it • 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 generatedd 1kWh electricity l i i by b generating i unit. i • 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

HR 

m mainsteam hsup  h fw   m rhsteam hhrh  hcrh  PGen

The net heat consumption rate can be expressed as Formula

HR 

m mainsteam hsup  h fw   m rhsteam hhrh  hcrh  PGen  Pbfpfp

To the intermediate reheating unit whose boiler water is fed by steam-driven pump, pump the gross and net heat consumption rate are formulated as HR 

m mainsteam hsup  h fw   m rhsteam hhrh  hcrh 

HR 

PGen  Pbfp

m mainsteam hsup  h fw   m rhsteam hhrh  hcrh  PGen

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 in different generating unit, unit the net heat rate of motor-driven 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 condensing turbine-driven pump, and then net heat consumption rates in different operation conditions were obtained. 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 p y after taken into account enthalpy py rise in were calculated respectively feed water pump.

NET HEAT CONSUMPTION RATES OF FEED WATER PUMP DRIVEN BY STEAM AND ELECTRICITY OF 300MW UNIT IN SLIDING PRESSURE MODE（KJ/KW）

Comparison Co pa so : Stea Steam & Constant Co sta t Speed Motor oto • Thermal economyy of steam- driven ppumps p is better than that of motor-driven pumps in different operation loads. • In particular, thermal economy of constant speed electric pump d li declines quickly i kl in i low l loads. l d • As their operating speed is not adjusted, constant speed eelectric ect c pu pumps ps wo work in tthee va variable ab e load oad by reducing educ g the t e pump pu p 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-load low load declines much.

Comparison : Steam & Variable Speed Motor • C Comparedd to that h off the h motor-driven di mode d off variable i bl speed, d thermal economy of units which use steam-driven pumps to feed water in full load has increased but not significantly. g y • 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 electromechanical loss and ppower transmission loss. • The internal efficiency of SST changes slightly in variable load conditions, although it is lower than that of main turbine in full l d load. • At the same time SST can drive directly feed water pumps, y, because intermediate link of resultingg in better thermal economy, energy conversion and transmission is few.

EQUIVALENT QU WORK O EFFICIENCY C C • Relative equivalent q work efficiencyy 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, performed simultaneously avoiding the computational precision difficulty of small steam turbine exhaust enthalpy.

Comprehensive Cost-based Coal Consumption rate • On the basis of the principle of energy value analysis, the term of comprehensive cost-based 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 unit generating 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

• The cost of plant electrical power consumption is equal to the product of ppower consumption p p rate and ppool ppurchase pprice. • So formula of CCCR can be expressed as:

The physical meaning of CCCR • The physical meaning of CCCR is that the power consumption of 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.

Comparison Co pa so o of CCC CCCR

CO C US O S CONCLUSIONS • With the increase of unit capacity, p y, capacity p y of feed water pump correspondingly will increase. • The steam-driven mode of the variable-speed pumps by small steam t turbine t bi will ill be b more andd more acceptable t bl to t muchh more people. • A stea steam-driven d ve mode ode iss better bette than t a motor-driven oto d ve mode ode in thermal economy. • Compared with motor-driven pumps, steam-driven pumps are goodd to net electrical l i l output increases i for f large l units, i reducing d i the net heat rate of generating and CCCR.

• The small steam turbine drivingg variable-speed p ppumps p does well in declining of power consumption rate and rising of operation efficiency, thus it could replace motor-driven pumps • in i future. f t • The driving mode of boiler feed pump is mainly affected by tthermal e a economy eco o y oof syste system.. • Besides thermal economy of system, the driving mode of boiler feed pump also depends on comprehensive combination off investment i income, i operating i reliability, li bili complexity l i off system structure.

Head Vs Flow Rate & Selection of Operating Point

H f  K1  K 2 Q 2

PUMPS Running Parallel

Operation of Pumps at Low Flows •

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There are a number of unfavorable conditions which may occur separately or simultaneously when the pump is operated at reduced flows. 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. requirement The final decision on recommended minimum flow is taken after careful “techno-economical” analysis by both the pump user and the manufacturer.

Ca tat o Cavitation • •

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As the liquid flows onto the impeller of the pump it is accelerated and d iinitially i i ll iits pressure ffalls ll (B (Bernoulli). lli) The pressure subsequently increases as the fluid leaves the impeller and as the kinetic energy is recovered in the volute chamber. chamber If the pressure of the liquid falls below the vapour pressure, Pv, the liquid boils, generating vapour bubbles or cavities-cavitation. The bubbles are swept into higher pressure regions by the liquid flow, where they collapse creating pressure waves and cause mechanical damage to solid surfaces. pump p discharge g head is reduced at flow rates above the Moreover, p cavitation point. Operation under these conditions is not desirable and damages the equipment.

NPSH S (Net ( et Pressure essu e Suct Suction o Head). ead) • •

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Net Positive Suction Head Required, NPSHr NPSH is one of the most widely used and least understood terms associated with pumps. Understanding the significance of NPSH is very much essential during installation as well as operation of the pumps. pumps 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 suction flange of the pump less the vapor pressure converted to fluid column height of the liquid. •

Performance of A Damaged Impeller

Performance with Reduced Throat Area

Pump with Minor Wears

Pump with Excessive Wear

Pump with rough impeller & casing