pumps

PumpsPumps

05/04/2012

2

Classification of Pumps

Continuous energy addition

Conversion of added energy to increase in kinetic energy (increase in velocity)

Conversion increased velocity to increase in pressure

Periodic energy addition

Added energy forces displacement of fluid in an enclosed volume

Fluid displacement results in direct increase in pressure

4

API 610 Centrifugal Pump Classification

5

O verhu ng B e tw e e n B ea ring V e rtica lly S u sp en d ed S u b m ers ib le M o to r

C e n trifu ga l P u m p

6

Foot M ounted Centerline M ounted

Horizonta l

In-Line Bearing Fram e

Vertica l

Overhung PumpsF lexibly Coupled

Flexible Coupling

Flexible Coupling

Thrust Bearings

7

In-L ine

Vertica l

O verhung Pum psR ig id ly C oupled

Rigid Coupling

No thrust bearings!

8

H orizonta l

In-L ine

Vertica l H igh Speed In tegra l G ear

O verhung Pum psC lose C oupled

9

M agnetic D rive C anned M otor

O verhung Pum psSeal less

10

1 & 2 S tage M ultistage (m ore than 2 stages)

Betw een Bearing Pum ps

11

Axia lly Split R adia lly Split

Betw een Bearing Pum ps1 & 2 S tage

12

S ingle C asing D ouble C asing

R adia lly Split Axia lly Split

Betw een Bearing Pum psM ultistage

13

Single C asing D ouble C asing

Vertica lly Suspended Pum ps

14

D iffuser Volute Tubular C asing

(Axia l / M ixed F low )

D ischarge Through C olum n

Line Shaft C antilever

Seperate D ischarge

Vertica lly Suspended Pum psS ingle C asing

15

D iffuser Volute

Vertica lly Suspended Pum psD ouble C asing

16

Working of a Centrifugal Pump

Main Parts are –

Impeller

Volute casing

17


Impeller rotates exerting centrifugal force on the liquid

Kinetic energy is created

Centrifugal force throws the liquid out

Creating low pressure at the suction eye

This forces new liquid into the impeller inlet

Liquid thrown out of the impeller is met with resistance to flow

18


The first resistance is created by the volute

As the liquid moves in the volute towards the outlet it slows down due to increasing cross sectional area

As the liquid slows down its velocity (kinetic energy) is converted into pressure

19

Head (m) = v2

2 x g

v = velocity at periphery of impeller (m/s)g = Gravitational acceleration (m/s2)

v (m/s) = N x D

2.748

N = Impeller RPMD = Impeller diameter (mm)

Relation between Head and Velocity

Head = pressure in terms of height of liquid

20

The impeller is offset in the volute to create a close clearance between the impeller and the volute at the cut water

The kinetic energy given to the liquid is proportional to the velocity at the edge of the impeller vane tip.

Faster the impeller rotates or bigger the impeller is, higher will be the liquid velocity at the vane tip.

A centrifugal pump neither creates pressure nor does it suck, it only provides flow. Pressure is just an indication of the amount of resistance to flow!


21

Why Head is used to measure the energy of a centrifugal pump?

3.6 kg/cm2

Brine Sp.gr. 1.2

30 m30 m 3 kg/cm2

Water Sp.gr. 1.0

30 m 2.4 kg/cm2

Kerosene Sp.gr. 0.8

22

Pressure at any point in a liquid is caused by a vertical column of liquid due to its weight.

Height of this column is called Static head and is expressed in meters of liquid.

Head is a measurement of the height of a liquid column that the pump could create from the kinetic energy imparted to the liquid.

Pressure is dependent on the specific gravity of a liquid but head is not.

Why Head is used to measure the energy of a centrifugal pump?

A given pump with a given impeller diameter and speed will raise a liquid to a certain height regardless of the weight of the liquid!

23

Head (m) = Pressure (kg/cm2) x 10

Specific Gravity

Pressure – Head conversion

24

Various Heads

Friction Head (hf)Total Differential Head (HT)

Velocity Head (hv)

Static Discharge Head (hd) Total Discharge Head (Hd)

Static Suction Head (hs) Total Suction Head (Hs)

Pressure Head (hp)

Vapour Pressure Head (hvp) Net Positive Suction Head Required (NPSHr)

Net Positive Suction Head Available (NPSHa)

Exit Various Heads & Continue

25

hs

hd

Ps

Vs

Vd

Static Suction Head (hs): Vertical distance between the pump centerline and the liquid surface in the suction tank.

Datum LevelPump Center Line

Back

Pd

Pvp

Next

26

hs

hd

Ps

Vs

Vd


Suction Lift (-hs): Liquid level is below pump center line.

Datum Level

Back

Pd

Pvp

Pump Center Line

Next

27

hshd

Ps

Vs Vd


Suction Head (+hs): Liquid level is above pump center line.

Datum Level

Back

PdPvp

Pump Center Line

28

hs

hd

Ps

Vs

Vd

Static Discharge Head (hd): Vertical distance between the pump centerline and the point of free discharge or liquid surface in the discharge tank.


Pd

Pvp

Next

29

Static Discharge Head (hd) and Static Suction Head (hs) change as the liquid flows.

Back

30

hs

hd

Ps

Vs

Vd

Friction Head (hf): Head required to overcome resistance to flow in the pipe and fittings.

“ hf ” depends upon the size, condition and type of pipe & fittings, flow rate and nature of liquid.

Datum Level

Back

Pump Center Line

Pd

Pvp

31

hs

hd

Pvp

Ps

Vs

Vd

Vapour Pressure Head (hvp): is the vapour pressure converted into head.

hvp increases with increase in temperature

hvp acts opposite to the surrounding pressure acting on the liquid (atmospheric pressure)

Datum Level

Back

Pump Center Line

Pd

32

hs

hd

Pvp

Ps

Vs

Vd

Pressure Head (hp): is the absolute pressure (Ps or Pd) acting on the liquid in the suction or discharge tanks.

If tank is open to atmosphere, hp = atmospheric pressure head.


Back

Pd

33

Velocity Head (hv): refers to the energy of the liquid as a result of its motion at some velocity.

It is the equivalent head in meters through which the liquid would have to fall to acquire the same velocity.

“ hv ” is relatively small in high head systems and relatively large in low head systems

hs

hd

Pvp

Ps

Vs

Vd

Datum Level

Back

Pump Center Line

Pd

34

hs

hd

Pvp

Ps

Vs

Vd

Total Suction Head (Hs) = Pressure head in suction reservoir (hps) + static suction head (hs) + velocity head at the pump suction flange (hvs) – friction head in the suction line (hfs).

Hs = reading of the gauge on the suction flange converted to meters of liquid.


Back

Pd

Hs

35

hs

hd

Pvp

Ps

Vs

Vd

Total Discharge Head (Hd) = Pressure head in discharge reservoir (hpd) + static discharge head (hd) + velocity head at the pump discharge flange (hvd) + friction head in the discharge line (hfd).

Hd = reading of the gauge on the discharge flange converted to meters of liquid.


Back

Pd

Hd

36

hs

hd

Pvp

Ps

Vs

Vd

Total Differential Head (HT) = Total Discharge Head (Hd) - Total Suction Head (Hs)


Back

Pd

Hd

Hs

37

Net Positive Suction Head

Before we jump to the term NPSH, we shall understand

Parts of a Pump

Flow through Pump Inlet

Cavitation

38

Parts of a Centrifugal Pump

Pump Casing

Bearing Bracket

Shaft

Pump Feet (support)

Suction Flange (Inlet)

Discharge Flange (outlet)

Bearing Bracket Support

Mechanical Seal / Gland Packing

Bearing Cover

Vent Plug

39

Parts of a Centrifugal Pump

Bearing BracketPump Casing

Discharge Flange

Suction Flange

Shaft

Impeller

Impeller nut

Radial Bearing

Thrust Bearing

Casing Cover

Bearing Bracket Lantern

Shaft Protection Sleeve

Mechanical Seal

Inlet (Suction)

Outlet(Discharge)

Casing Wear Ring

Oil Seal

Bearing Cover

Splash Ring

Seal Flushing Pipe

Oil Chamber

Bottom Feet

Heating/ Cooling Jacket

Bearing Bracket SupportKey

Casing Drain Connection

40

Back Vane

Back ShroudFront Shroud

Outer HubVane

Vane Discharge Edge

Shaft

Suction Eye

Diameter

Impeller Nomenclature

Inner Hub

Impeller Eye

Vane Suction Edge

41

Liquid moves through decreasing cross-section area (as in a Venturi).

Liquid velocity increases as its pressure decreases not only due to Venturi effect but also frictional loss.

At the point of minimum cross-section (impeller eye) velocity is max and pressure is min.

Pressure drops down further due to shock & turbulence as the liquid strikes the edges of impeller vanes.

Results in creation of low pressure around the impeller eye and beginning of impeller vanes.

Flow Through Pump Inlet

42

If the pressure drops below the vapour pressure of the liquid at the operating temperature, the liquid will vaporize.

44

Formation of Bubbles inside the liquid

New bubbles continue to form and older ones grow in size

Bubbles get carried by liquid at high velocity from impeller eye towards impeller exit

Bubbles eventually reach the regions of high pressure within the impeller

The pressure outside of the bubble exceeds that inside of the bubble

Hundreds of bubbles collapse by bursting inwards (implosion, not explosion!)

When bubbles collapse surrounding liquid rushes to fill the void forming a liquid microjet

Creates highly localised hammering effect, pitting the impeller

An audible shock wave emanates outward from the point of collapse

Bubble Collapse pressures greater than 1GPa (10,000 bar) have been reported!

Life cycle of a bubble has been estimated to be in the order of 0.003 seconds!

45

This dynamic process of formation of bubbles inside the liquid, their growth and subsequent

collapse is called CAVITATION.

Cavitation can be of two types

Vaporous: due to vaporisation of the liquid

Gaseous: due to formation of gas bubbles in a liquid containing dissolved gas

A Centrifugal pump can handle air in the range of 1/2 % by volume. Cavitation begins if this value is increased to 6%.

Cavitation - Heart Attack of the Pump

Obstruction to flow

Impair performance – reduce capacity and head

Abnormal noise and vibrations

Damage impeller and other sensitive components

46

Impeller Cavitation Regions

47

Cavitation Pitting

48

Pumps can only pump liquid, not vapours

1 cu. ft. of water at room temperature becomes 1700 cu. ft. of vapour at the same temperature ! Hence, to pump a liquid effectively, it must be kept always in liquid form

Rise in temperature and fall in pressure induces vaporisation

The pump always needs to have a sufficient amount of suction head present to prevent vaporisation at the lowest pressure point in the pump

NPSH as a measure to prevent vaporisation

The NET POSITIVE SUCTION HEAD is the total head at the suction flange of the pump less the vapour pressure converted to fluid column height of the liquid

NPSH

49

NPSHNPSHr - Net Positive Suction Head Required

NPSHr is a function of the pump design

NPSHr is determined based on actual pump test by pump manufacturer.

NPSHr is the positive head in meters absolute required at the pump suction to overcome the pressure drop in the pump and maintain the majority of the liquid above its vapour pressure.

“Net” refers to the actual pressure head at the pump suction flange and not the static suction head.

NPSHr increases as capacity increases

NPSHr is independent of liquid specific gravity

50

NPSHNPSHa - Net Positive Suction Head Available

NPSHa is a function of the system design

NPSHa is calculated based on the system or process conditions

NPSHa is the total suction head corrected to the centerline of the first stage impeller less the vapour pressure head.

“Net” refers to the actual pressure head at the pump suction flange and not the static suction head.

NPSHa is independent of liquid specific gravity

51

hs

hd

Pvp

Ps

Vs

Vd

NPSHa = Pressure head in suction reservoir (hpi) + static suction head (hs) + velocity head at the pump suction flange (hvi) – friction head in the suction line (hfi) – vapour pressure head at the max. pumping temperature (hvp)

Datum Level

Back

Pd

Pump Center Line

52

Capacity

Flow rate with which liquid is moved by the pump

Measured in m3/hr or GPM or LPM

Capacity depends on

Liquid characteristics – density, viscosity

Pump size, inlet & outlet sections

Impeller size

Impeller rotational speed RPM

Size & shape of cavities between vanes

Pump suction & discharge temperature and pressure conditions

53

Power and EfficiencyBrake Kilo Watt (BKW)

• Mechanical power delivered to the pump shaft

Q = Capacity, m3/hr

H = Total Differential Head, m

= Efficiency, %η367

GravitySpecific HQBKW

Hydraulic Kilo Watt (WKW)

• Liquid power delivered by the pump

Q = Capacity, m3/hr

H = Total Differential Head, m

367

GravitySpecific HQWKW

BKW

KWW)( Efficiency Pump BKW = WKW + Mechanical Losses

+ Hydraulic Losses

54

Pump Performance Curve

0

10

20

30

40

50

60

70

0 10 20 30 40 50

Capacity (m3/hr)

Hea

d (m

) / E

ffici

ency

(%

)

0

2

4

6

8

10

12

14

Pum

p In

put (

BK

W)

/ N

PS

Hr

(m)

Best Efficiency PointShutoff Head Point

Run Out Point

55

Radial Thrust

Radial Force acting on Impeller = Flow (=constant) x Area

(=varying)

56

The exact points at which the forces will be generated is

determined by the Specific Speed (shape) of the impeller.

Francis vane impellers (the most popular shape) deflect at

approximately 60 and 240 degrees measured from the cutwater, in

the direction of shaft rotation.

Radial vane impellers deflect at close to 90 and 270 degrees.

Axial flow impellers deflect close to 180 and zero degrees from

the cut water

Radial Thrust

57

0

10

20

30

40

50

60

70

0 10 20 30 40 50Capacity (m3/hr)

Hea

d (m

) /

Eff

icie

ncy

(%)

0

2

4

6

8

10

12

14

Rad

ial T

hrus

t

Pump Performance Curve & Radial Thrust

Best Efficiency PointShutoff Head Point

Run Out Point

Preferred operating range

Allowable operating range

Min. Continuous Stable Flow

58

Single Volute Vs Double Volute

59

Effect of Impeller Diameter

0

10

20

30

40

50

60

70

0 10 20 30 40 50

Capacity (m3/hr)

Hea

d (m

)

0

10

20

30

40

50

60

70

Eff

icie

ncy

(%)

60

Pump Performance Curve

61

Typical H-Q with Iso-Efficiency Curves

Capacity

He

ad

Iso-Efficiency Curves

62

System Resistance Curve

hs

hd

Pvp

Ps

Vs

Vd


Pd

Total System Head = Static System Head + Dynamic System Head

( hd – hs ) + ( hps – hpd ) ( hvd - hvs ) + ( hfd + hfs )= +

( Discharge Static Head - Suction Static Head) + (Discharge Pressure Head - Suction Pressure Head )

( Discharge Velocity Head - Suction Velocity Head + Discharge Friction Head + Suction Friction Head )

= +

( hd – hs ) + ( Pd – Ps ) x g

( Vd2 – Vs2 ) + ( hfd + hfs ) 2 x g

= +

hs = -ve, if suction lift

hs = +ve, if suction head

suffix “s” = suction

suffix “d” = discharge

= density, kg/m3

g = gravitational constant, m/s2

hf = x V2 , (loss coeff. ) 2xg

63


0

10

20

30

40

50

60

70

0 10 20 30 40 50

Capacity (m3/hr)

Hea

d (m

)

Static System Head

Dynamic System Head

64

Operating Point

0

10

20

30

40

50

60

70

0 10 20 30 40 50

Capacity (m3/hr)

Hea

d (m

) / E

ffici

ency

(%

)

Static System Head

Dynamic System Head

Best Efficiency Point

Operating Point

65

Specific Speed (Ns)Specific speed (Ns) is a non-dimensional design index

Ns, is the speed in RPM at which a geometrically similar impeller would operate if it were of such a size as to deliver 1 m3/hr against 1 m head.

Ns, is primarily used to describe the geometry (shape) of a pump impeller

Ns, is used as an index to predict certain pump characteristics

N = The speed of the pump in revolutions per minute (rpm.)

Q = Capacity in LPM at the best efficiency point

H = The total head per stage in meters at the best efficiency point

43Η

Q NNs

66

As the specific speed increases, the ratio of the impeller outlet diameter, D2, to the inlet or eye diameter, Di, decreases. This ratio becomes 1.0 for a true axial flow impeller

Values of Specific Speed, Ns

Specific Speed (Ns)

67

Impeller Types Based on Flow

Radial Flow Impeller Mixed Flow Impeller

Axial Flow Impeller

68

Impeller Types Based on Flow

Radial Flow Impeller Mixed Flow ImpellerAxial Flow Impeller

Centrifugal Axial Force Force

Head Develoved by

Low Flow High FlowHigh Head Low Head

Flow Vs Head

Lesser Steep More Steep(More Flatter)

Nature of H-Q Curve

Increases Decreaseswith flow with Flow

Power Input

Lower HigherSpecific Speed Specific Speed

Specific Speed

69

Typical Performance of a Radial Impeller

70

Typical Performance of a Mixed Impeller

71

Typical Performance of a Axial Impeller

72

Affinity Laws

Capacity Q

Hea

d H


B1

N1

N2

N3

B2

B3

N - Speed

B - Operating Point

Effect of Speed on Pump Performance

Keeping Impeller diameter D constant

H3

Q3 Q2 Q1

H2

H1 Q2 =N2

N1

x Q1

H2 =N2

N1

x H1

2

P2 =N2

N1

x P1

3

73

Affinity Laws

Capacity Q

Hea

d H


B1

D1

D2

D3

B2

B3

N – Speed (constant)

B - Operating Point

Effect of Impeller Diameter on Pump Performance

Keeping Speed N constant

H3

Q3 Q2 Q1

H2

H1 Q2 =D2

D1

x Q1

H2 =D2

D1

x H1

2

P2 =D2

D1

x P1

3

74

Effect of Viscosity on Pump Performance

Capacity Q

Hea

d H

BW

D1

D2

D3

QZ QW

HZ

HW

BZ

Pow

er P

Eff

icie

ncy

QZ = fQ x QW

HZ = fH x QH

Z = f x QW

B – Operating Point

W – Water

Z – Viscous Liquid

fQ – Capacity Correction Factor

fQ – Head Correction Factor

f– Efficiency Correction Factor

75

Viscosity Correction Chart

- use for viscosity greater than or equal to 4.0 cst

- not to use for gels, slurries, paper stock (non Newtonian liquids)

- use for pumps with conventional hydraulic design, in normal operating range, open or closed impellers

- not to use for axial, mixed flow or special hydraulic design

- do not extrapolate

76

Effect of Valve Closing on the Operating Point

B1

B2

B3

B4


Q-H Curve

Capacity Q

Hea

d H

B - Operating Point

77

Characteristics of Performance Curve

Capacity Q

Hea

d H

B - Operating Point

Flat Curve

Steep Curve

Drooping Curve (unstable)

H

Q Q

78

Parallel Operation

Two or more pumps operating in parallel

Common method for meeting variable capacity requirement

Pumps with unstable characteristics may be troublesome unless operation only on the steep portion

No pump should be operated at flows less than pump minimum flow

79

0

5

10

15

20

25

30

35

40

45

50

0 10 20 30 40 50 60 70

Capacity Q

Hea

d H

Parallel Operation

Pump 1

Pump 2

Combined

Q2

Q1

Q1+ Q2

H1= H2

System Head Curve

80

Series Operation

Two or more pumps operating in series

Common method for meeting variable head requirement

81

Series Operation

0

10

20

30

40

50

60

70

80

90

0 10 20 30 40 50

Capacity Q

Hea

d H

H2 H1 H1

+ H

2

System Head Curve

Pump 1

Pump 2

Combined

82

Types of Impellers

Closed Mixed Flow Impeller

Closed Radial Flow Impeller

Open Mixed Flow Impeller

Closed Mixed Flow Double Entry Impeller

Axial Flow Entry Impeller

Open Mixed Flow Impeller

83

Types of Impellers (Non-Clog)

Closed Three Vane ImpellerClosed Two Vane ImpellerClosed One Vane Impeller

Used for liquids containing solids

More free passage

Open One Vane Impeller Open Two Vane Impeller Open Three Vane Impeller

84

Types of Impellers (Special)

Free Flow Impeller

85

Types of Impellers (based on the no. of inlets)

Single Suction

Double Suction

86

Axial Thrust(Single Suction Impeller)

Suction Pressure

Discharge Pressure

Discharge Pressure

Discharge Pressure

Discharge Pressure

87

Axial Thrust(Double Suction Impeller)

Suction Pressure

Discharge Pressure

Discharge Pressure

Suction Pressure

Discharge Pressure

Discharge Pressure

Suction Pressure

Suction Pressure

88

Axial Thrust

Discharge Pressure

Discharge Pressure

Balanced Forces

Balanced Forces

Un-Balanced Forces

Un-Balanced Forces

The Unbalanced Axial Thrust on an impeller is counterbalanced by Thrust Bearings

89

Axial ThrustMethods to Reduce Unbalanced Axial Thrust

Back Vane

90


Balancing Hole

Back Wearing RingBalancing Hole

91


Balancing Disc

Counter Balancing Disc

Balancing Disc

92


Oil-lubricated thrust bearingOil-lubricated thrust bearing

Expansion chamberExpansion chamberBalancing water line to the suction casing of the pump or to the feedwater tank

Balancing water line to the suction casing of the pump or to the feedwater tank

Balancing PistonBalancing Drum(Single Piston)

93

Oil-lubricated thrust bearingOil-lubricated thrust bearing

Expansion chamberExpansion chamber Balancing water line to the suction casing of the pump or to the feedwater tank

Balancing water line to the suction casing of the pump or to the feedwater tank


Balancing Double PistonBalancing Drum (Double Piston)

94

Internal Recirculation

Suction Recirculation Discharge Recirculation

Recirculation is a flow reversal at the suction and or discharge tips of impeller vanes

Recirculation depends on impeller design

Every impeller has a critical flow at which recirculation occurs

Recirculation can cause noise, vibration & cavitation

Pumps with Low NPSHR is more susceptible to cavitation when operating in the regions of recirculation flows

Suction Specific Speed (NSS) is a guide to predict how close the pump is to be operated to the BEP to avoid recirculation and thus cavitation

95

Suction Specific Speed (NSS) Nss, is used as a non-dimensional index to predict cavitation due to

suction recirculation flow

N = The speed of the pump in revolutions per minute (rpm.)

Q = Capacity in GPM (m3/s) at the best efficiency point of top impeller

NPSH = The NPSH in feet (meters) at the best efficiency of top impeller

Higher the NSS, the closer will be the beginning of recirculation to the capacity at best efficiency

Guideline: NSS should not exceed 12,000 USGPM, ft, rpm (or 232 m3/s, m, rpm). Lower the NSS safer the pump against cavitation.

If the available NPSH is low enough to require a pump with NSS of 18,000 US units(348 metric units) then it is better to use an axial flow impeller ahead of the centrifugal impeller.

43BEP at

BEP at

NPSH

Q NNss

96

Initial recirculation

*Typical h1/D2 ratios are as follows -Double suction 0.35-0.50Multistage 0.50-0.70

1. For water pumps rated at 2500 gpm & 150 feet total head or less the min. operating flows can be reduced to 50% of the suction recirculation values shown for continuous operation & 25% for intermittent operation

2. For hydrocarbons the min. operating flows can be reduced to 60% of the suction recirculation values shown for continuous operation & 25% for intermittent operation.

97

Diffuser

Volute Casing without Diffuser

Volute Casing with Diffuser

DiffuserImpellerImpeller

98

Diffuser

Comparison of Radial Forces acting on an impeller inside a volute casing and inside a diffuser casing

99

A diffuser consists of a number of vanes set around the impeller

Flow from a diffuser is collected in a volute or circular casing and discharged through the outlet pipe

A diffuser does the same function as the volute casing in energy conversion

A diffuser converts vortex flow at the exit of an impeller into a vortex-free flow with minimum loss

A diffuser reduces the unbalanced radial forces acting on an impeller

Diffuser is used in high pressure multistage pumps, in vertical turbine (axial flow) pumps and seldom applied to a single stage radial flow pump.

Diffuser

100

Common Suction & Discharge Configurations

End Suction / Top Discharge

Top Suction / Top Discharge Side Suction /

Side Discharge

101

Axially Split Casing Pump

Single Stage, Double Suction,

Between Bearing, Side Suction / Side Discharge

Multistage Stage,Single Suction,

Between Bearing,Side Suction / Side Discharge

102

Radially Split Casing PumpSingle Stage,

Single Suction, Overhung,

End Suction / Top Discharge

Multi Stage, Ring Section,

Single Suction, Between Bearing, Top Suction / Top

Discharge

103

Barrel Casing & Ring Section

Multi Stage, Ring Section,

Single Suction, Between Bearing,

Top Suction / Top Discharge

Multi Stage, Double Casing,Single Suction,

Between Bearing, Top Suction / Top Discharge

Barrel Casing

104

Barrel Casing

Line Shaft

Impeller

Column Pipe

Guide Bearing

Pump Shaft

Bowl Casing

Thrust Bearing

Vertical (Can) Barrel Casing Pump

105

End-Suction, Back Pull-out Arrangement with Spacer Coupling

Coupling with Spacer

Discharge Pipe

Suction Pipe

106

Remove Spacer


107

Pump Suction & Discharge nozzles remain connected

to piping!


108

Back Pull-out assembly lifted!


109


110

Advantage of a Double (Barrel) Casing Pump

Suction Pipe

Discharge Pipe

Cartridge

Cartridge Removal Tools

Barrel Casing

111

Pump Priming

Earth’s atmosphere is approx. 80,000 m above the earth, resting on the earth with a weight equivalent to a layer of water 10 m deep at sea level

The weight of water is approx. 8000 times that of air

112

Centrifugal pumps can pump air at their rated capacity, but only at a pressure equivalent to the rated head of the pump.

Centrifugal pump can produce only 1/8000 of its rated water pressure when handling air

In other words, for every 1m water that has to be raised to fill the pump, the pump must produce a discharge head of approx. 8000 m, which is impossible!

Hence, it is necessary to fill the waterways in a pump with liquid before starting it.

A centrifugal pump is said to be PRIMED when the waterways of the pump is completely filled with liquid to be pumped.

Pump Priming

113

Methods of Pump Priming

Foot Valve

114


Priming Chamber

115


To Vacuum Pump

116


Self Priming Pump

117

Inducer

Inducer is an axial flow impeller fitted ahead of the centrifugal impeller to reduce the NPSH of the pump or to permit the pump to operate at higher speeds.

Impeller

Inducer

Inducer

118

Inducer

Inducer is mounted on the same shaft as that of the centrifugal impeller

and rotates at the same speed

Inducer increases the suction pressure of a conventional impeller

Although the efficiency of the inducer is low, it will not reduce the pump

overall efficiency significantly

Inducers have typically 2 but not more than 4 vanes

Capacity Q

NP

SH

r

NPSH with Inducer

NPSH without Inducer

119

Methods of Reducing Pump NPSH

Double Suction Arrangement

120


Inducer Inducer Arrangement

Impeller

121


Increase Impeller Eye Area

122

TYPICAL MATERIAL OF CONSTRUCTION

123

TYPICAL MATERIAL OF CONSTRUCTION

124

Torque – Speed Characteristics

125

Bearing Bracket

Thrust Bearings Radial Bearing

Oil Seal

Oil Seal

Deflector

Shaft

126

REQUIREMENTS OF API 610 • Scope API 610 is a standard that covers the minimum requirements for centrifugal pumps for use in petroleum, heavy duty chemical and gas industry services. It includes pumps running in reverse as hydraulic power recovery turbines.

• Why is API 610 Published? API 610 has been written to ensure a minimum standard for: SafetyReliabilityMaintainability

• Pump Types Covered API 610 covers all types of centrifugal pumps, these include: – Horizontal and vertical – Single stage, two stage and multi-stage – Single case and double case (barrel type) – Vertical sump and vertical canned (or double case)

127

FEATURES OF API 610• Long Reliable Life

– API pumps must be designed and constructed for a minimum service life of 20 years and at least 3 years of uninterrupted

operation (clause 2.1.1). In practice there are many API 610 pumps in industry that have been operating for in excess of 40 years and many oil refineries are now reporting MTBF figures in excess of 7 years.

• Casing Design – The pump pressure casings must be designed using the stresses,

welding and inspection practices given in the pressure vessel code (2.2.1).

– Overhung pumps, between bearings radially split pumps, multi-stage pumps and vertical double case pumps are to be designed with a pressure rating equal to the lesser of 4,000 kPa-g or an ANSI 300# flange rating (2.2.2).

– Radially split casings are required if temperature of fluid is above 200 deg C, the fluid SG is less than 0.7 or the discharge pressure is above 10,000 kPa-g (for flammable or hazardous fluids) (2.2.6).

– Overhung horizontal single stage pump casings should have centerline supports (2.2.9).

128

FEATURES OF API 610• External Nozzle Forces and Moments – API 610 lists the maximum forces and moments, which the pump nozzles

must be able to take, and still give satisfactory performance. Case distortion and shaft misalignment are considered when assessing satisfactory performance (2.4.1).

– The pump must meet these requirements without any bearing housing support (3.3.6).

• Rotors – Default impeller design is closed and constructed as a one piece casting.

Except on vertical suspended pumps, impellers must be keyed to the shaft and secured by a cap screw or cap nut, which in turn must have a positive mechanical locking method (2.5.1, 2.5.2, 2.5.3)

– Shaft runout is limited to 0.001 inch (2.5.6). – Shaft stiffness must limit the deflection at the mechanical seal faces to

0.002 inch (2.5.7). This is most important for long mechanical seal life.

• Wear Rings – Pumps must have renewable wear rings on both the casing and impeller

(2.6.1). The minimum wear ring clearances are specified (2.6.4).

129

FEATURES OF API 610• Mechanical Seals – There is now an API standard for mechanical seals, API 682 (2.7). – Both API 610 and API 682 specify seal chamber dimensions. These dimensions help

ensure an ideal environment for the mechanical seal. External Nozzle Forces and Moments

• Vibration – API 610 specifies maximum allowable vibration levels – nominally 3.0 mm/s RMS

unfiltered, at the bearing housing (2.8.3). • Balancing

– Single stage and two stage pumps: impellers dynamic balanced to Grade G1.0 (2.8.4.1).

– Multi-stage pumps: impellers and major components balanced to grade G1.0, rotors balanced to G2.5 (5.2.4.2)

• Bearings – Minimum L10 design bearing life is 25,000 hours, at rated conditions (table 2.7). In

practice most API 610 pumps will have an L10 bearing design life far in excess of this figure.

– Bearing housings must have constant level oilers fitted. • Rotors

– Default impeller design is closed and constructed as a one piece casting. Except on vertical suspended pumps, impellers must be keyed to the shaft and secured by a cap screw or cap nut, which in turn must have a positive mechanical locking method (2.5.1, 2.5.2, 2.5.3)

– Shaft runout is limited to 0.001 inch (2.5.6). – Shaft stiffness must limit the deflection at the mechanical seal faces to 0.002 inch

(2.5.7). This is most important for long mechanical seal life.

130

FEATURES OF API 610• Drivers – Driver power ratings must be at least equal to the following (table 3.1): – Motor kW Percentage of Rated Pump Power <22 125% 22-55 115% >55 110%

• Baseplates – Strict guidelines are given for baseplate design. These design criteria ensure minimal

misalignment of pump and driver shafts (3.3.5). – Baseplates must be single piece drain rim or drain pan design, to ensure that any

leakage is contained within the baseplate (3.3.1, 3.3.2). – Pump and drive train components must have mounting pads, fully machined flat and

parallel. Values are specified for measuring compliance (3.3.3). • Inspections

– The manufacturer must keep quality records for at least 20 years (4.2.1.1). • Material Inspections

– The purchaser should specify which parts are to be subjected to surface and subsurface examination, and the type of examination required (i.e. magnetic particle, liquid penetrant, radiographic or ultrasonic) (4.2.1.3).

– The standard lists the appropriate procedure and acceptance criteria for these examination methods (4.2.2).

• Testing – All pressure casings must have a hydrostatic pressure test, with liquid at a minimum of

1.5 times the maximum allowable working pressure (refer to the standard for special provisions) (4.3.2).

– All pumps are to be performance tested unless stated otherwise. The standard gives detailed requirements for the testing and tight tolerances on test results (4.3.3).

– NPSHR and Complete Unit Tests (i.e. test of pump and driver train complete with all auxiliaries) are optional, to be performed when specified (4.3.4).

131

FEATURES OF API 610• SUMMARY

– Heavy duty casing design – Centerline supports – Low shaft stiffness ratio – Low shaft deflection at the seal faces – Long design bearing life – Low vibration levels – High allowable forces and moments on nozzles – Stringent testing requirements

132

Need to Seal a Pump

133

Shaft Protection Sleeve

Shaft

Impeller

Stuffing Box / Seal Chamber

134

Need to Seal a Pump

Shaft

ProcessFluid

Leakage

EnvironmentPump Wall

135

G la nd P ack ing M e cha n ica l S e a l

S e a l T yp es

136

Gland Packing

Packing

Lantern Ring (Seal cage)

Stuffing BoxGland

Shaft

Shaft Sleeve

137

Mating Ring

Primary Ring Secondary Sealing Element

Secondary Sealing Element

Shaft

Stuffing Box (Seal Chamber)

Mechanical Seal

138

Mechanical SealPrinciple Components

1. A rotating face (primary ring)

2. A stationary seat, (mating ring)

3. A secondary sealing element

4. A mechanical loading device to press face and seat together, and

5. Auxiliary components

139

Mechanical Seal

O-Ring

Shaft

Mating Ring

Primary Ring

Snap Ring

O-Ring

DiskSprings

Retainer

Set Screw

Seal Head (Rotating)

Mating Ring Assembly

(Stationary)

140

GlandPump Housing

Process Fluid

Invisible Leakage: Fluid Evaporates Upon Reaching Atmosphere

Primary Ring Mating Ring

Process Fluid Acts as Lubricant Between Faces

Mechanical Seal

141

Without Lubrication, Faces Run Dry And Overheat

Gland

Pump Housing

No Fluid Or Dry Running

Primary Ring Mating Ring

Mechanical Seal

142

Heat Transfer• Conduction• Convection

Mechanical Seal

143

Injection

• Removes Heat• Replenishes Cool Clean Lubricating Liquid• Removes any solids

FlushingMechanical Seal

144

Single Seal Flushing By - Pass from Discharge (API Plan 11)

By- pass Line fromPump Discharge to Seal Gland

Discharge

Flow

Suction

Mechanical Seal

145

Balance ratio is used to control the face load.

Closing Force Opening Force

Balance Ratio

Mechanical Seal

146

Balance ratio is the ratio of the closing area to the opening area.

Ac

A o

Balance Ratio = Closing Area

Opening Area

Balance Ratio

Mechanical Seal

147

Balance Ratio

Mechanical Seal

An Unbalanced Seal

AAc oFc

Fc = p x Ac

P = Fc / Ao

= (p x Ac) / Ao

148

Balance Ratio

Mechanical Seal

AoAc

A Balanced Seal

149

Mechanical Seal

O-ring must move axially

Pusher SealSecondary Sealing Element

150

Mechanical Seal

Static O-ring

Non Pusher SealSecondary Sealing Element

151

Mechanical Seal

Teflon Bellows

Elastomeric Bellows

Half Convolution

Welded Metal Bellows

V Rings U Cup Wedge Encapsulated O Ring

O Ring

Secondary Sealing Element

152

Mechanical Seal

Pusher Non-Pusher

O-ring secondary seal must slide along shaft as seal face wears

Bellows secondary sealexpands to accommodateface wear. Bellows tail is stationary against shaft

vs.

153

Mechanical Seal

Classical “Tandem”

Process seal Backup seal

Process seal Barrier fluid seal

Classical “Double”

Multiple Seal Arrangements

154

Mechanical Seal

Process

Buffer Atmosphere

Pre

ssur

e

Unpressurised (Tandem)

Un-Pressurised Arrangement

155

Mechanical SealPressurised Seal Arrangement

ProcessBarrier

Atmosphere

Pre

ssur

e

PRESSURISED (double)

156

Mechanical SealCategories of Mechanical Seal

– Pusher / Bellows

– Cartridge / Conventional

– Wet Seals / Gas seals

– Split / Whole

– Single / Double

157

Mechanical SealMerits of Pusher & Non-Pusher Seals

• O ring seals• Wedge seals

• More material options• Higher Pressures• Easier to manufacture

• Metal Bellows• Rubber Bellows• PTFE Bellows

• No ‘hang up’• Better abrasive handling• More tolerant to

misalignments

PUSHER SEALS(NON BELLOWS)

NON PUSHER SEALS(BELLOWS)

158

Mechanical SealCartridge Seal

O-RingMetal

Bellows

ElastomerBellows

159

Mechanical SealMerits of Cartridge Seals & Conventional Seals

• Easier to fit - reliable• Factory set – reliable• Less downtime in

replacement

• Less expensive• Adaptable

CONVENTIONAL(COMPONENT)

CARTRIDGE SEALS

160

Mechanical SealNeed for Flushing Plans & Sealing Systems

Pumped Liquid may be …

• Too hot

• Too cold

• Too viscous

• Prone to solidify or crystallise

• Abrasive

• Close to boiling point

• Contains dissolved gases

• The liquid can not get to the seals

• Dangerous liquid

• Sensitive liquid

Such a liquid if used for seal flushing may

damage the seal and cause seal failure. Hence, the need to

condition the liquid before being used as a seal

flushing liquid for satisfactory seal

operation

161

API PLANS

• Seals generate heat and require lubrication while face sealing. These systems are used to dissipate this generated heat and cool the seal faces thus extending the seal life

Flushing Liquid

Fluid which is introduced into the seal chamber on the process fluid side in close proximity to the seal faces typically used for cooling & lubricating the seal faces

FLUSHING

PROVIDES LUBRICATION.

REMOVES HEAT GENERATED BETWEEN RUBBING FACES.

INCREASES MARGIN BETWEEN VAPOUR PRESSURE AND STUFFING

BOX PRESSURE. KEEPS LIQUID INSIDE STUFFING BOX IN CONSTANT

CIRCULATION.

IN CASE OF EXTERNAL FLUID FLUSHING - FLUSHING DOES

NOT ALLOW ABRASIVES TO REACH SEAL FACES.

Plan 01

Integral (internal) re circulation is from discharge to seal. A connection is made from an area behind the impeller, near discharge to seal chamber. Recommended for clean fluids.

Plan 01 (if possible to provide in the stuffing box) is superior to Plan11 for the liquids, which may become viscous or freeze at lower temperature. This minimizes the risk of freezing of the fluids in the piping.

Disadvantage - No control on the flush flow rate.

Plan 01

Plan 02

The stuffing box is dead-ended (with no circulation of fluid).

This plan is preferred plan for the clean and relatively cool liquids having sufficient (at-least 1 kg/cm2) margin between vapour pressure and stuffing box pressure.

Care should be taken to vent the stuffing box properly. One 5 mm diameter hole at the topmost position of the throat should be provided for venting purpose.

Depending on the requirement cooling or heating is provided in the stuffing box jacket.

For liquids at self ignition temperature API Plan 02 is not recommended.

Plan 02

Plan 11

A line with flow control orifice is connected from the discharge side of the pump into the gland flush connection. It is default seal flush plan.

Orifice must be sized properly.

Minimum orifice size recommended is 3 mm. For larger pressure drop multiple orifice is recommended instead of reducing the size of orifice.

Plan 11

Orifice

Horizontal Pump

Suction

Orifice

From Seal

Plan 13

Vertical Pump

Suction

Orifice

From Seal

Plan 13

A line is connected from the gland, through a flow control orifice, to the suction piping. It is standard flush plan for vertical pumps where stuffing box pressure is equal to discharge pressure.

Whenever stuffing box pressure is more than suction pressure, API PLAN 13 is better than API PLAN 11.

In this plan liquid moves away from the seal face instead of impinging on to it ( API Plan 11) and the stuffing box pressure reduces making the seal more comfortable.

Plan 13

MEDIA FROM DISCHARGETO SEAL CHAMBER THRUORIFICE.

MEDIA FROM SEAL CHAMBER TO SUCTION THRU ORIFICE.

Plan 14

It is combination of Plan 11 and Plan13. It is mostly used for vertical pumps handling volatile liquids. In Plan 13 because of throat bush, pressure in the seal area may drop and liquid may vaporise. Plan 11 provides cool fluid to the seal area whereas Plan 13 provides complete venting in the seal area.

Plan 14

Plan 21

A line with orifice is connected from the discharge side of the pump through a flow control orifice and cooler into the seal chamber.

It provides cool flush to the seal. This plan is the best for liquids at self ignition temperature. In the event of seal leakage, cool liquid will continue to reach seal faces as long as the pump is running ,ensuring that hot liquid does not come out.

The disadvantage is that heat loss is more, also cooling water requirement is high.

Plan 21

Plan 23

In this plan process fluid is recirculated with the help of a pumping ring in the seal chamber through a cooler and back in to the seal chamber.

A Plan 23 flushing system is most effective way of providing a cool flush to the seal faces. In this arrangement fluid in seal chamber is isolated from that in the impeller area of the pump by a throat bush. Use of an internal circulating device to circulate the fluid through a closed loop cooler allows the cooler to continuously cool a recirculated stream rather than a continuous (hot) stream from discharge to seal (Plan 21). The cooler is required to cool the liquid in the loop. Therefore cooler size reduces drastically as compared to Plan 21 cooler. Also the cooling water requirement is much less than Plan 21.

Plan 23

Coolers for API Plan 21 & 23

Air Fin Coolers

NATURAL

DRAUGHT

Plan 23M

Plan 23: Process liquid through coil & cooling liquid through shell.

Plan 23M: Process liquid through shell & cooling liquid through coil

Modified API plan by ESSIL

Plan 23M

It is shell and tube type heat exchanger.

Advantages:

Vapour Lock : Plan 23 is not self venting

Friction loss: More in Plan 23

Heat transfer rate: The pot area is sufficient to carry away heat generated by the seal and soaked heat. In majority of the cases if proper thermal barrier is provided at the bottom of the throat bush cooling water coil is not required.

Plan 31

Solid Sp.Gravity should be at least 2 times media Sp. Gravity.

Process liquid is recirculated through a cyclone separator to the seal. Solid particles are centrifuged through cyclone separator and sent back to suction. The Plan is specified for services containing solids with a specific gravity at least twice that of the process fluid.

Normally cyclone separators do not remove the solids effectively and cause seal failure. Even if the efficiency of cyclone separator is 92%.about 8% of the finer particles reach to the seal faces. The finer particles can enter between the seal faces and cause damage to the seal.

Plan 31

Cyclone Separator

STRAINER

ORIFICE

PRESSUREGAUGE

EXTERNAL FLUSH TO SEAL

Plan 32

Flushing product is brought from an external higher pressure source to the seal.. This plan is excellent for liquid containing solids/ abrasives. The flushing fluid mixes with the product. Therefore it must be ensured that the flushing fluid is compatible with the product. A close clearance throat bush restricts the product to come to the seal area and also increases the pressure margin.

Flushing fluid dilutes the product. Therefore unnecessarily more liquid should not be circulated .

Plan 32

Plan 41

Solid Sp.Gravity should be at least 2 times media Sp. Gravity.

It is combination of Plan 21 and Plan 31. Process liquid is recirculated through a cyclone separator and cooler to the stuffing box. The plan is recommended for hot liquids containing solids. Specific gravity of the solid particles should be at least twice that of the process fluid. Solid particles are centrifuged through cyclone separator and sent back to suction.

If the process liquid is very dirty or is slurry, it may choke the cooler.

Plan 41

In this plan an external reservoir provides a dead ended blanket for the fluid to the quench connection of the gland.

Plan 51

Plan 52

Barrier Fluid Properties

One of the most important properties of a goodbuffer or barrier fluid is its viscosity.

A good buffer or barrier fluid should be a goodheat transfer fluid.

A good barrier or buffer fluid should not presentany potential danger whether equipment is runningor stationary.

The fluid must be compatible with themetallurgy, elastomers and other materialsof the sealing system.

Barrier Fluid Properties

The fluid should also be highly compatible withthe process pumpage being sealed.

Foaming risks are to be avoided.

Fluid stability must be ensured for a longermaintenance cycle time.

In this plan external reservoir provides buffer fluid for the outer seal of an un-pressurized dual seal arrangement ( Arrangement 2). During operation an internal pumping ring provides circulation. The reservoir is connected to a vapour recovery system and is maintained at a pressure less than the pressure in the seal chamber. It is normally used for the applications where process fluid leakage to atmosphere must be minimised and contained. Plan 52 works best with clean, non-polymerising pure products that have vapour pressure more than the buffer system pressure. Leakage of higher vapour pressure process liquid into buffer system will flash in the seal pot and escape into the vent system.

Leakage of the process fluid will mix with the buffer fluid and contaminate the buffer fluid over a time. Therefore the buffer fluid must be compatible with the process fluid.

Plan 52

Plan 53

In this plan external pressurised barrier fluid reservoir provides fluid for to the seal chamber. The Plan 53 is for double back to back seal (Arrangement 3). During operation an internal pumping ring provides circulation. It is normally used for the applications where process no fluid leakage to atmosphere is permitted.

The barrier fluid must be pressurised to about 1.5 to 2 kg/cm2 above the pump seal chamber pressure. Inner seal leakage (if any) will be barrier fluid into the product and no process fluid will be allowed to leak in to barrier fluid area.

Plan 53 is selected over Plan 52 for dirty, abrasive or polymerising products which may either damage the seal faces or cause problem with the buffer fluid system if Plan 52 was used.

Plan 53

Plan 53A

Plan 53B

Pressurised barrier fluid circulation with bladder accumulator. Cooler outside the reservoir.

Plan 53C

Pressurised barrier fluid circulation with piston accumulator. For Dynamic tracking of system pressure

Plan 54

In Plan 54 cool clean product from an external source is supplied. The supply pressure must be at-least 1.5 kg/cm2 greater than the pump seal chamber pressure.

Plan 54 is used for the fluids where the process fluid is hot, contaminated with solids or both.

In Plan 54 care should be taken of barrier fluid system. A contaminated system may cause seal failure. A properly engineered barrier fluid system is typically complex and expensive. Where these systems are properly engineered they provide most reliable system.

Plan 54

QUENCHING

KEEPS ATMOSPHERE AWAY

TOXIC FLUIDS

CRYSTALLIZING PRODUCTS

CRYOGENIC APPLICATIONS

HIGH FREEZING POINT FLUIDS

HIGH TEMP. FLUIDS WHICH DECOMPOSE IN CONTACT WITH ATMOSPHERE

FLUID HAVING TENDENCY TO BECOME VISCOUS IN CONTACT WITH ATMOSPHERE

ADDITIONAL ADVANTAGES

PROVIDES HEATING / COOLING TO SEAL FACES.

KEEPS AREA OUTSIDE SEALS CLEAN

Plan 61

Tapped and plugged connect for purchaser’s use.

Plan 62

Plan 62

In Plan 62, a quench stream is brought from an external source on atmospheric side of the seal faces.

The quench fluid can be clean water, steam or low pressure Nitrogen.

Quenching is provided to keep atmosphere away. In following conditions atmosphere must be kept away from the seal face.

1) Toxic fluids

2) Crystallising products.

3) Cryogenic Application.

4) High Freezing point fluids.

5) High temp. Fluids, which decompose in contact with

atmosphere.

6) Fluid having tendency to become viscous in contact

with atmosphere.

Quenching fluid keeps area outside seals clean and provides heating / cooling to seal faces

Plan 62

Plan 62

Recommended flow rates:

Media: WaterFlow: 1

lpmPressure: 0.5 kg/cm2

Media: Steam

Flow: 1 m3/hrPressure: 0.5

kg/cm2

Plans for dry containment seals and single seals

Plan 71, 72, 74, 75 and 76 are for the dry containment seal. Plan 71, 72 and 74 are similar to Plan 51,52 and 54. Instead of liquid ,gas is provided between the two seals. Plan 75 and 76 are for single seal as well as for containment seals.The leakage collection. Plan 75 is for non volatile liquids and Plan 76 is for volatile liquids.

Plan 71

This is used in Tandem (Arrangement 2) un pressurized dual seals, which utilize a dry containment seal and where no buffer gas is supplied but the provision to supply a buffer gas is desired. Buffer gas may be needed to sweep inner seal leakage away from the outer seal into a connection system or to dilute the leakage, but it is not specified.

Plan 72

Plan 72 is used Tandem (Arrangement 2) un-pressurized dual seals, which utilize a dry containment seal and where buffer gas is supplied. The buffer gas can be used to sweep inner seal leakage away from the outer seal to a collection system and /or dilute the leakage so the emissions from the containment seal are reduced.

Plan 72

Plan 74

Plan 74

The system is used on dual pressurized seals (Arrangement 3),where the barrier medium is a gas. They are the gas barrier equivalent to the traditional plan 54 liquid barrier system. The most common barrier gas is nitrogen The supply pressure to the to the seal is typically at least 0.17 Mpa (1.7 bar) (25 ps) greater than the seal chamber pressure. This results in small amount of gas leakage into the pump, with most of the gas barrier leakage to atmosphere. This arrangement should never be used where the barrier gas pressure can be less than the sealed pressure If this were to happen the entire barrier gas system could become contaminated with the pump fluid.

Plan 74 systems are typically used in services which are not too hot (within elastomer property limits) but which may contain toxic or hazardous materials whose leakage cannot be tolerated. Because they are pressurized dual seal systems, leakage to the system is eliminated under normal conditions. Plan 74 may also be used to obtain very high reliability, since solids or other materials which may lead to premature seal failure cannot enter the seal faces.

Plan 74

Plan 75

Plan 75

Systems are typically used on Arrangement 2, unpressurised dual seals, which also utilize a dry containment seal and where the leakage from the inner seal may condense. They may be used with a buffer gas (Plan 72) and without a buffer gas (Plan 71)

If an unpressurised dual seal is installed, usually it is because leakage of the pumped fluids to the atmosphere must be restricted more than can be done with an arrangement 1 seal. Therefore a mean is needed to collect the leakage and route it to a collection point. The Plan 75 system is intended to perform this collection for pump fluids that may form some liquid (condense) at ambient temperature

Plan 76

System is typically used on arrangement 2, unpressurised dual seals, which also utilize a dry containment seal and where leakage from the inner seal will not condense. They may be used with a buffer gas (plan 72) or without a buffer gas (Plan 71).

If an unpressurised dual seal is installed, usually it is because if leakage of the pumped fluid into the atmosphere must be restricted more than can be done with an Arrangement 1 seal. Therefore a means is needed to route the leakage to the collection point. The Plan 76 system is intended for services where no condensation of the inner seal leakage or from the collection system will occur.

Plan 76

220

PUMP VIBRATIONS

• BASIC SOURCES OF VIBRATION

– MECHNAICALLY INDUCED

– SYSTEM INDUCED

– OPERATION INDUCED

221

PUMP VIBRATIONS

– MECHNAICALLY INDUCED• BAD BEARINGS• BENT SHAFT• UNBALANCED ROTOR• CHECK VALVE INSTALLED BACKWARDS• MISALIGNMENT• LOOSENESS• SOFT FOOT• MAXIMUM SIZE IMPELLER

222

PUMP VIBRATIONS

– SYSTEM INDICED• PARTIALLY / PLUGEGD STARINER• CLOGGED IMPELELR OR SUCTION LINE• INSTALLATION

– OPERATIONALLY INDICED• CAVITATION• FLOW • SPEED• INSUFFICIENT IMMERSION OF SUCTION

PIPE OR BELLMOUTH

223

PUMP VIBRATIONS

– ACCEPTABLE LIMITS AS PER API 610

•

224

PUMP VIBRATIONS

– API 610 REQUIREMENTS

225

PUMP VIBRATIONS

226

PUMP VIBRATIONS

Trouble shooting

• Classification of Failure causes

• Common Problems in Centrifugal Pumps

• Specific Failure Cases

• Troubleshooting

• Modern methods of Troubleshooting

• Pump Troubleshooting Software

Classification of Failure Causes

• Design Related

The problems related specifically to the design parameters of the pump which are specified by the Process Engineer / Machinery Engineer / Vendor’s Counterpart in the Pump Mechanical Datasheet.

• Operation Related

The problems related to the operation of the pump at site/shop due to reasons dependent/independent of its design.

Common Failures in Centrifugal pumps

• Insufficient Capacity / Insufficient Head

• Internal recirculation

• Cavitation

• Excessive Power Consumption

• Excessive Noise and Mechanical Vibrations

Insufficient capacity

• The problem is in a. The Pumpb. The Suction side c. The Discharge side

• The problem is in a. The Pumpb. The Suction side c. The Discharge side

Insufficient Head

Internal Recircultion

• Suction Recirculation

- Cause and Effect

• Discharge Recirculation

- Cause and Effect

Cavitation

• What is Cavitation?

• Causes of Cavitation

- Vaporization

- Air Ingestion

- Internal Recirculation

- Flow Turbulence

- Vane Passing Syndrome

Excessive Power Consumption

• Reasons could be due to

- use of oversized pump

- change in product

- increase in bearing loading

- starting procedure could be a problem

- too much axial thrust

Excessive Noise and Mechanical Vibrations

• Unbalance• Critical Speed• Resonance with natural Frequencies• Misalignment• Hydraulic Disturbances• Cavitation• Surging • Water Hammer• Other Reasons

Troubleshooting• Skill takes time to develop

• Pump may be a cause of a symptom

• Regulations may have additional safety precautions

• Make sure suction and discharge gages are available

• Verify pump speed

• Verify motor amps, voltage and power factor

• Make sure drivers are locked before doing any inspection

• Information gathering

– What is different from when it ran fine?

– When was the last maintenance work done? What was done?

– How do things look?

– Get the basics: inlet and discharge pressure, flow, speed, liquid, temperature, viscosity, duty

• Noise?

Troubleshooting

• Rotation

• Loss of suction

• Loss of developed head

• Wear

• Viscosity

• Pulsations, vibrations, noise

• Amps and power

• Hydraulics, mechanics, electrics

237

THANK YOU

pumps

Documents

pressurized

unpressurised

h1 h2 b3

total differential

unpressurised

dry containment

hfd hfs

stuffing box