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
3
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
Working of a Centrifugal Pump
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
Working of a Centrifugal Pump
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!
Working of a Centrifugal Pump
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
Static Suction Head (hs): Vertical distance between the pump centerline and the liquid surface in the suction tank.
Suction Lift (-hs): Liquid level is below pump center line.
Datum Level
Back
Pd
Pvp
Pump Center Line
Next
27
hshd
Ps
Vs Vd
Static Suction Head (hs): Vertical distance between the pump centerline and the liquid surface in the suction tank.
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.
Datum LevelPump Center Line
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.
Datum LevelPump Center Line
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.
Datum LevelPump Center Line
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.
Datum LevelPump Center Line
Back
Pd
Hd
36
hs
hd
Pvp
Ps
Vs
Vd
Total Differential Head (HT) = Total Discharge Head (Hd) - Total Suction Head (Hs)
Datum LevelPump Center Line
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
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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
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If the pressure drops below the vapour pressure of the liquid at the operating temperature, the liquid will vaporize.
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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!
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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
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Impeller Cavitation Regions
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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
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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
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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
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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
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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
Datum LevelPump Center Line
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
System Resistance Curve
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
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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
System Resistance Curve
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
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Affinity Laws
Capacity Q
Hea
d H
System Resistance Curve
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
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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
System Resistance Curve
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
Axial ThrustMethods to Reduce Unbalanced Axial Thrust
Balancing Hole
Back Wearing RingBalancing Hole
91
Axial ThrustMethods to Reduce Unbalanced Axial Thrust
Balancing Disc
Counter Balancing Disc
Balancing Disc
92
Axial ThrustMethods to Reduce Unbalanced Axial Thrust
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
Axial ThrustMethods to Reduce Unbalanced Axial Thrust
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
End-Suction, Back Pull-out Arrangement with Spacer Coupling
107
Pump Suction & Discharge nozzles remain connected
to piping!
End-Suction, Back Pull-out Arrangement with Spacer Coupling
108
Back Pull-out assembly lifted!
End-Suction, Back Pull-out Arrangement with Spacer Coupling
109
End-Suction, Back Pull-out Arrangement with Spacer Coupling
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
Methods of Pump Priming
Priming Chamber
115
Methods of Pump Priming
To Vacuum Pump
116
Methods of Pump Priming
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
Methods of Reducing Pump NPSH
Inducer Inducer Arrangement
Impeller
121
Methods of Reducing Pump NPSH
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
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