Performance Analysis of Pumps P M V SubbaraoAssociate ProfessorMechanical Engineering DepartmentIIT DelhiA Machine Solely responsible for Introduction of Life in Working fluid.

Classification of Pumps

Pumps in Steam Power PlantsTurbogenerator & Auxiliaries 3 sets.Steam generatore 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.

Boiler Feed PumpsGeneral. Boiler feed pumps are used to pressurize water from the deaerating feedwater heater or deaerating hot process softener and feed it through any high pressure closed feedwater heaters to the boiler inlet. Discharge from the boiler superheated steam in order to maintain proper main steam ternperature to the steam turbine generator.Types. There are two types of centrifugalmulti-stage boiler feed pumps commonly used in steam power plantshorizontally split case and barrel type with horizontal or vertical (segmented) split inner case. The horizontal split case type will be used on boilers with rated outlet pressures up to 6Mpa. Barrel type pumps will be used on boilers with rated outlet pressure in excess of 6MPa.

Expectations from A PumpBF PumpGenerate Required Live Steam Conditions !Hydraulic Power Source

Design criteriaPump head will be maximum at zero flow with continuously decreasing head as flow increases to insure stable operation of one pump, or multiple pumps in parallel, at all loads.Pumps will operate quietly at all loads without internal flashing and operate continuously with- out overheating or objectionable noises at minimum recirculation flow.Provision will be made in pump design for expansion of(a) Casing and rotor relative to one another.(b) Casing relative to the base.(c) Pump rotor relative to the shaft of the driver.(d) Inner and outer casing for double casing pumps.All rotating parts will be balanced statically - and dynamically for all speeds.

Pump design will provide axial as well as radial balance of the rotor at all outputs.One end of the pump shaft will be accessible for portable tachometer measurements.Each pump will be provided with a pump warmup system so that when it is used as a standby it can be hot, ready for quick startup. This is done by connecting a small bleed line and orifice from the common discharge header to the pump discharge inside of the stop and check valve.Hot water can then flow back through the pump and open suction valve to the common suction header, thus keeping the pump at operating temperature.Pump will be designed so that it will start safely from a cold start to full load in 60 seconds in an emergency, although it will normally be warmed before starting as described above.

A General Pump

Geometrical Features of Pump Impeller

Micro Fluid Dynamics of PumpSuction Discharge

Variation of Absolute Pressure inside A PumpFlow Pathpabsolute

Cavitation As the liquid flows onto the impeller of the pump it is accelerated and initially its pressure falls (Bernoulli). The pressure subsequently increases as the fluid leaves the impeller and as the kinetic energy is recovered in the volute 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. Moreover, pump discharge head is reduced at flow rates above the cavitation point. Operation under these conditions is not desirable and damages the equipment.

NPSH (Net Positive Suction Head).Net Positive Suction Head Required, NPSHrNPSH 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 can pump only liquids, not vaporsRise in temperature and fall in pressure induces vaporizationNPSH as a measure to prevent liquid vaporizationNet 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.

NPSH

Loss of NPSH

NPSHr is a function of pump design NPSH required is a function of the pump design and is determined based on actual pump test by the vendor. As the liquid passes from the pump suction to the eye of the impeller, the velocity increases and the pressure decreases. There are also pressure losses due to shock and turbulence as the liquid strikes the impeller. The centrifugal force of the impeller vanes further increases the velocity and decreases the pressure of the liquid. The NPSH required is the positive head in feet absolute required at the pump suction to overcome these pressure drops in the pump and maintain the majority of the liquid above its vapor pressure.The NPSH is always positive since it is expressed in terms of absolute fluid column height. The term "Net" refers to the actual pressure head at the pump suction flange and not the static suction head.

NPSHr increases as capacity increasesThe NPSH required varies with speed and capacity within any particular pump. The NPSH required increase as the capacity is increasing because the velocity of the liquid is increasing, and as anytime the velocity of a liquid goes up, the pressure or head comes down. Pump manufacturer's curves normally provide this information. The NPSH is independent of the fluid density as are all head terms.

Note: It is to be noted that the net positive suction head required (NPSHr) number shown on the pump curves is for fresh water at 20C and not for the fluid or combinations of fluids being pumped.

Available NPSH At Site

Net Positive Suction Head available, NPSHaNet Positive Suction Head Available is a function of the system in which the pump operates. It is the excess pressure of the liquid absolute over its vapor pressure as it arrives at the pump suction, to be sure that the pump selected does not cavitate. It is calculated based on system or process conditionsA limit on Low Pressure feed water heat generation.Performance of Deaerator influences NPSHa.

Deaerator Outlet Conditions

NPSHa in a nutshell

NPSHa = Pressure head + Static head - Vapor pressure head of your product Friction head loss in the piping, valves and fittings.All terms in feet absoluteIn an existing system, the NPSHa can also be approximated by a gauge on the pump suction using the formula: NPSHa = hpS - hvpS hgS + hvShpS = Barometric pressure in feet absolute. hvpS = Vapor pressure of the liquid at maximum pumping temperature, in feet absolute. hgS = Gauge reading at the pump suction expressed in feet (plus if above atmospheric, minus if below atmospheric) corrected to the pump centerline. hvS = Velocity head in the suction pipe at the gauge connection, expressed in feet. NPSHa should always be greater than NPSHr

In-situ Expectations from A PumpBF PumpHydraulic Power Source

In-Situ Demand

Matching of A Pump with Site

Head Vs Flow Rate & Selection of Operating Point

Performance of A Damaged Impeller

Performance with Reduced Throat Area

Pump with Minor Wears

Pump with Excessive Wear

Pump with rough impeller & casing

Pump with lower NPSH

Boiler Feed Pump/TurbinePERFORMANCE TEST PROTOCOLBoiler feed pump/turbine sets should be tested on a routine basis to determine their current performance level. The important boiler feed pump/turbine performance indices are pump capacity, total dynamic head (TDH) at rated speed, and relative pump/turbine set efficiency.This test protocol provides a method for measuring pump performance on a repeatable basis. These measurements allow you to reliably detect changes in equipment condition and operating efficiencies. Adequate information should be developed to determine if a problem exists in the turbine, the pump, or both. In addition, pump performance, relative to one another, should be determined to provide guidance for maintenance efforts. Where applicable, test results need to be compared to design and previous test results.

Pump Performance ParametersPump tests may be classified as shop tests, field tests, index tests or model tests. This protocol describes the index field testing method to determining the general condition of the boiler feed pump/turbine. An index test helps guide overhaul efforts by detecting changes in pump performance. In general, pump performance is described in terms of efficiency and TDH.Pump Efficiency, pumpThe ratio of useful power output to shaft power

hthr, Turbine throttle steam enthalpyhexit, Turbine exit steam enthalpy

Enthalpy Drop in BFP TurbineEnthalpy Drop, hthr & hexh (for non-condensing turbines) can be determined from pressure and temperature measurements. Condensing turbines provide an additional challenge because the exhaust enthalpy cannot be accurately determined with commercially available instrumentation. A reduction in turbine efficiency requires that additional steam be extracted to provide the same power output. In this case, the performance of the pump is unchanged, and the capacity and the TDH at rated conditions should be normal. In addition, a reduction in pump efficiency requires that additional steam be extracted to raise pump speed to match the system head requirement. In this case, pump capacity and TDH at rated conditions will be lower than normal.When considering pump performance, test results must be corrected to a standard condition for comparison. The Affinity Laws state that test flow, head, and water horsepower can be extrapolated from test speed values to design speed values by multiplying each parameter by a correction factor.

For flow, the correction factor is the ratio of design speed (5,600 rpm) to test speed. For total head, the corrections factor is the ratio squared. For water horsepower, it is the ratio cubed. To use these relationships, an accurate measurement of pump speed must be made during the test.