gsk - armstrong international · 2012. 7. 16. · gsk karachi pakistan, west wharf date: 16/07/2012...

GSK

Karachi, Pakistan West Wharf

STEAM AND CONDENSATE ENERGY AUDIT REPORT

PROJECT N° 11360SER2PK

1 Emission J.Zwart/D.Graham R. Ivanov 16/7/2012 Item Description Established Checked out Date

STEAM AND CONDENSATE AUDIT

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To the attention of Mr. Noel Chong Established by J.Zwart/D.Graham

TABLE OF CONTENTS 1 Executive summary ............................................................................................................................... 4

2 Steam budget and summary of potential savings ................................................................................ 5

3 Optimisation project n°1: Burner tuning steam boilers ......................................................................... 6

3.1 CURRENT SITUATION .................................................................................................................................... 6

3.2 Optimization .............................................................................................................................. 6 3.3 Savings calculation .................................................................................................................. 7 3.4 Investments ............................................................................................................................... 7

4 Optimisation project n°2: Burner tuning gas fired chillers .................................................................... 8

4.1 Current situation ....................................................................................................................... 8 4.2 Optimization .............................................................................................................................. 8 4.3 Savings calculation ................................................................................................................ 10 4.4 Investments ............................................................................................................................. 12

5 Summary of deviations noticed during the audit ................................................................................ 13

6 Complete check list of all verifications done during the audit ............................................................ 16

7 Recommended complementary studies ............................................................................................. 19

7.1 ADDITIONAL ENERGY-SAVING OPTIMISATIONS .............................................................................................. 19 7.2 OPERATIONAL OPTIMISATIONS ................................................................................................................... 24

8 Appendix N°1: Determination of the 2011 steam production and boiler house efficiency ................ 25

9 Appendix N°2: Calculation of Boiler house efficiency ........................................................................ 27

9.1 THEORETICAL STEAM PRODUCTION ............................................................................................................. 27

9.2 COMBUSTION LOSSES ................................................................................................................................ 28 9.3 RADIATION LOSSES .................................................................................................................................... 29 9.4 CYCLING LOSSES ....................................................................................................................................... 30 9.5 BLOW DOWN LOSSES ................................................................................................................................. 31

9.6 DEARATOR OR HOT WELL STEAM CONSUMPTION .......................................................................................... 31


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10 Appendix N°3: Steam Pressure Controlled Heat Exchangers at Low Load ...................................... 33

10.1 CURRENT SITUATION .................................................................................................................................. 33 10.2 OPTIMIZATION ........................................................................................................................................... 36

10.2.1 Closed loop pumping trap ..................................................................................................... 37 10.2.2 Posipressure system ............................................................................................................. 38 10.2.3 Safety drain ........................................................................................................................... 39 10.2.4 Barometric leg ....................................................................................................................... 39 10.2.5 Condensate level control ...................................................................................................... 40 10.2.6 Mixing valve on the product side .......................................................................................... 41

10.3 SAVINGS CALCULATION .............................................................................................................................. 42

11 Appendix N°4: Boiler house simulations ............................................................................................ 43


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1 Executive summary

The energy audit was conducted on April 09th and April 18th 2012 by Armstrong and covers the 4 parts

of the steam loop: boiler house, steam distribution, steam consumption and condensate return.

Steam is used mainly for:

Process/Hot Water Heat Exchangers

Dehumidification

Process Vessels

AHU’s

Clean Steam Generators

The walkthrough during the first day of the audit indicated opportunities to increase condensate return, to

improve overall boiler house efficiency and also utilise the flue gas heat from the gas fired chillers.

Most condensate tanks on site were venting steam and were large relative to the load. One unit was not

in operation and condensate sent to drain.

The condensate return main was under significant pressure (135°C) from what appeared to be leaking

steam traps. Condensate return ratio was calculated to be 70% for 2011.

There are gas flow meters for both boilers and gas chillers, however steam and water are not measured

There are three boilers on site. The newest 2010 Robey boiler has automatic blow down fitted, none of

the boilers has an economizer. The Robey boiler has a capacity of 1 t/h and usually runs at full load.

One of the bigger 2 t/h boilers (Descon 1995 and Revomax 2005) is in hot stand by covers peak

demands. The other 2 t/h boiler is in cold stand by. The average steam site demand was calculated to be

0,49 t/h. The efficiency of the boiler house was calculated to be 72,8% on HHV (80,7% on LHV).

A limited steam budget results in long payback times for energy saving projects. This audit identified 2

optimization projects.


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2 Steam budget and summary of potential savings

Based upon the utility figures for 2011:

2011 steam production:

• Total yearly steam production: 2.537 MWh (3.699 t/year – 0,494 t/h)

• Steam cost: 2.818 RS/MWh (1.933 RS/t - €16,56/t)

• Total yearly steam budget: 7.150.000 RS/year (€61.270,-/year)

• Total yearly gas consumption chillers 11.012.356 RS/year (€94.365,-/year)

Summary of identified energy-saving optimizations and their estimated yearly results:

Optimisation Project Energy saving in

kWhEnergy saving

in RsDecreased CO2

emissions in tonsWater savings in Rs

Total project investment cost in Rs

Payback time in months

1 Burner tuning boilers 213.993 361.425 40 250.000 92 Burner tuning chillers 780.775 1.318.695 146 250.000 3TOTAL 994.767 1.680.120 186 - 250.000 2

Optimisation Project Energy saving in kWh

Energy saving in Rs

Decreased CO2

emissions in tonsWater savings in Rs

Total project investment cost in Rs

Payback time in months

about about about about about about 381.000 645.155 71 0 2.500.000 47

TOTAL 381.000 645.155 71 0 2.500.000

up to average up to2.750.000 15

TOTAL all projects 1.375.767 2.325.275 258 0

RESULTS OF THE DETAILED STUDIES

RECOMMENDED COMPLEMENTARY STUDIES (ROUGH ESTMATIONS)

7 Heat recovery gas fired chillers


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3 Optimisation project n°1: Burner tuning steam boilers

3.1 Current situation

During the survey combustion analysis tests were carried out on all steam boilers. From the results it is

clear that there is excess O2 within the combustion flue gas. This is due to excess air at the burner and

results in less efficient combustion and therefore energy loss.

The average for O2 content in boiler 1 flue gas was 10,2%, for boiler 2 it was 17%, for boiler 3 it was

10,0%.

3.2 Optimization

Combustion is a chemical reaction in which a fuel constituent reacts with oxygen and releases its heat of

reaction. As a result, all fuels need oxygen, and the natural available oxygen source is air. However, air

contains nitrogen that has no role in the combustion reaction except absorption of a portion of the

released heat of reaction. Every cubic meter of oxygen brings four cubic meter of nitrogen along with it.

This unwanted nitrogen leaves the boiler stack as a part of the waste flue gases, taking with it a portion

of the heat released from the fuel. Hence, the quantity of unwanted nitrogen has to be kept at a

minimum by controlling the oxygen level in stack gases.

There is an optimum range for O2 in the boiler. Too little will cause inefficiency due to incomplete

combustion, while too much will cause inefficiency due to high exhaust flow rates. For most burners it

must be possible to reduce the O2 percentage at full load to 2%, at 66% load to 2-3,5% and at 33% load

to 4,5%. As a rule of thumb, every additional percent O2 decreases the boiler efficiency with 0,5%.

To reduce the excess oxygen content, a combustion analysis including burner tuning should be

undertaken four times per year to ensure the burner is operating efficiently. When the results of these

combustion analysis prove to be consistent, intervals could be increased.


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3.3 Savings calculation

Appendix 4.1 showd the boiler house simulation for 2011. This base line calculation considers that boiler

1 runs 24 hours, 6 days per week and 52 weeks per year at full load. The remainning gas from the

invoices was then split equally over the two other boilers, each having 50% of the running hours.

Appendix 4.2 shows the boiler house with the burner tuned to a realisticaly achievable 5% O2, producing

the same amount of steam as in 2011. Compared to appendix 4.1, the annual savings are RS 7.149.933

- RS 6.788.569= RS 361.428 (€ 3.097,-), being 5,1% of the steam budget.

3.4 Investments

Considering the presence of other burners on site (chillers) it may be beneficial for the site to buy a

combustion analyser and train operators to adjust burners.

Budgetary costs for this project are estimated at is RS 250.000,- (€ 2.150,-)

Including:

- Combustion analyser

- Operator training

Payback time for this project is less than 9 months.


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4 Optimisation project n°2: Burner tuning gas fired chillers


There are 2 gas fired chillers on site. A combustion analysis of these units revealed 16,4% Oxygen on

chiller 1 and 10,4% Oxygen on chiller 2.

4.2 Optimization

Combustion is a chemical reaction in which a fuel constituent reacts with oxygen and releases its heat of

reaction. As a result, all fuels need oxygen, and the natural available oxygen source is air. However, air

contains nitrogen that has no role in the combustion reaction except absorption of a portion of the

released heat of reaction. Every cubic meter of oxygen brings four cubic meter of nitrogen along with it.

This unwanted nitrogen leaves the boiler stack as a part of the waste flue gases, taking with it a portion


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of the heat released from the fuel. Hence, the quantity of unwanted nitrogen has to be kept at a

minimum by controlling the oxygen level in stack gases.

There is an optimum range for O2 in the flue gasses. Too little will cause inefficiency due to incomplete

combustion, while too much will cause inefficiency due to high exhaust flow rates. For most burners it

must be possible to reduce the O2 percentage at full load to 2%, at 66% load to 2-3,5% and at 33% load

to 4,5%. As a rule of thumb, every additional percent O2 decreases the combustion efficiency with 0,5%.

To reduce the excess oxygen content, a combustion analysis including burner tuning should be

undertaken four times per year to ensure the burner is operating efficiently. When the results of these

combustion analysis prove to be consistent, intervals could be increased.


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The following calculation shows the chiller heating efficiency based upon 2011 gas consumption. Chiller heating efficiency calculation Chiller 1 Chiller 2Attachment 4.3, Base line 2011Chiller operating hours (incl. hot stand-by hours) 6.570 hours/year 6.570 hours/year1. Fuel heat input %LHV %LHVFuel type: 0 Custom gas %HHV 0 Custom gas %HHVFuel consumption during operating hours 51,5 Nm3/h 51,5 Nm3/hSpecif ic w eight of the fuel 0,79 kg/Nm3 0,79 kg/Nm3Fuel consumption 40,5 kg/h 40,5 kg/hLower heating value (LHV) 39704 kJ/kg (=31230 kJ/Nm3) 39704 kJ/kg (=31230 kJ/Nm3)Higher heating value (HHV) 44057 kJ/kg (=34654 kJ/Nm3) 44057 kJ/kg (=34654 kJ/Nm3)Fuel unit costs 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3) 1688,957 Rs/MWh HHV (= 16,26 Rs/Nm3Fuel heat input (LHV) 447,2 kW 100% 447,2 kW 100%Fuel heat input (HHV) 496,2 kW 496,2 kW2. Thermal lossesTemperature f lue gas after Chiller 206,0 °C 187,0 °CTemperature outside air 30,0 °C 30,0 °CExcess air 320,9 % 88,8 %Oxygen % in f lue gas (Dry volume) 16,40 % 10,40 %2.1 Losses in dry flue gasSpecif ic f lue gas f low (dry) 43,28 Nm3/kg fuel 18,80 Nm3/kg fuelTotal f lue gas f low (dry) 1754,7 Nm3/h 762,3 Nm3/hTotal f lue gas f low (w et) 1867,9 Nm3/h 864,7 Nm3/hSpecif ic heat f lue gas (Dry volume) 1,34 kJ/Nm³.K -23,2% 1,36 kJ/Nm³.K -9,0%Energy loss in dry flue gas 115,01 kW -25,7% 44,87 kW -10,0%2.2 Losses due to moisture in fuel Moisture in fuel 0,000 kg/kg fuel 0,000 kg/kg fuelSpecif ic heat w ater in fuel 4,18 kJ/kg.K 4,18 kJ/kg.KSpecif ic heat w ater in f lue gas 1,83 kJ/kg.K 1,83 kJ/kg.KEnergy losses due to moisture in fuel 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0%Energy losses due to moisture in fuel 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0%2.3 Losses due to H2 of FuelMoisture in f lue gas 1,785 kg/kg fuel 1,785 kg/kg fuelSpecif ic heat w ater in fuel 4,18 kJ/kg.K 4,18 kJ/kg.KSpecif ic heat w ater in stacks 1,83 kJ/kg.K 1,83 kJ/kg.KEnergy losses due to H2 in fuel 55,4 kW on HHV -11,2% 54,7 kW on HHV -11,0%Energy losses due to H2 in fuel 5,1 kW on LHV -1,1% 4,4 kW on LHV -1,0%2.4 Losses due to moisture in combustion airMoisture in ambient air 0,007 kg w ater/kg air 0,007 kg w ater/kg airMoisture in ambient air 0,403 kg w ater/ kg fuel 0,400 kg w ater/ kg fuelSpecif ic heat w ater in f lue gas 1,83 kJ/kg.K -0,3% 1,83 kJ/kg.K -0,3%Energy losses due to moisture in air 1,5 kW -0,3% 1,3 kW -0,3%5. Heat gains5.1 Economizer (non condensing)Temperature stack after economizer 206,0 °C 187,0 °CHeat transfer eff iciency 100% 0,0% 100% 0,0%Heat recovered by economizer 0,0 kW 0,0% 0,0 kW 0,0%7. Chiller Efficiency and Fuel Costs

Net heat output in steam from the Chiller (LHV) 325,6 kW ( 2139 MWh) 396,7 kW ( 2606 MWh)Chiller efficiency on LHV 72,82 % 88,70 %Chiller efficiency on HHV 65,62 % 79,94 %Annual Fuel costs 5.506.178 Rs/year 5.506.178 Rs/year

The total heat output was calculated to be 4.622 MWh (527,6 kW average) and the total gas costs were

RS 11.012.356 (€ 94.365,-).


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The following calculation show the chiller heating efficiency with the burners tuned to a realisticaly

achievable 5% O2, producing the same amount of heat to the chillers as in 2011. Chiller heating efficiency calculation Chiller 1 Chiller 2Attachment 4.4, 2011 production with tuned burnersChiller operating hours (incl. hot stand-by hours) 6.570 hours/year 6.570 hours/year1. Fuel heat input %LHV %LHVFuel type: 0 Custom gas %HHV 0 Custom gas %HHVFuel consumption during operating hours 45,4 Nm3/h 45,4 Nm3/hSpecif ic w eight of the fuel 0,79 kg/Nm3 0,79 kg/Nm3Fuel consumption 35,7 kg/h 35,7 kg/hLower heating value (LHV) 39704 kJ/kg (=31230 kJ/Nm3) 39704 kJ/kg (=31230 kJ/Nm3)Higher heating value (HHV) 44057 kJ/kg (=34654 kJ/Nm3) 44057 kJ/kg (=34654 kJ/Nm3)Fuel unit costs 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3) 1688,957 Rs/MWh HHV (= 16,26 Rs/Nm3Fuel heat input (LHV) 393,6 kW 100% 393,6 kW 100%Fuel heat input (HHV) 436,8 kW 436,8 kW2. Thermal lossesTemperature f lue gas after Chiller 206,0 °C 187,0 °CTemperature outside air 30,0 °C 30,0 °CExcess air 28,3 % 28,3 %Oxygen % in f lue gas (Dry volume) 5,00 % 5,00 %2.1 Losses in dry flue gasSpecif ic f lue gas f low (dry) 12,42 Nm3/kg fuel 12,42 Nm3/kg fuelTotal f lue gas f low (dry) 443,3 Nm3/h 443,3 Nm3/hTotal f lue gas f low (w et) 530,9 Nm3/h 530,9 Nm3/hSpecif ic heat f lue gas (Dry volume) 1,38 kJ/Nm³.K -6,8% 1,37 kJ/Nm³.K -6,0%Energy loss in dry flue gas 29,63 kW -7,5% 26,31 kW -6,7%2.2 Losses due to moisture in fuel Moisture in fuel 0,000 kg/kg fuel 0,000 kg/kg fuelSpecif ic heat w ater in fuel 4,18 kJ/kg.K 4,18 kJ/kg.KSpecif ic heat w ater in f lue gas 1,83 kJ/kg.K 1,83 kJ/kg.KEnergy losses due to moisture in fuel 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0%Energy losses due to moisture in fuel 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0%2.3 Losses due to H2 of FuelMoisture in f lue gas 1,785 kg/kg fuel 1,785 kg/kg fuelSpecif ic heat w ater in fuel 4,18 kJ/kg.K 4,18 kJ/kg.KSpecif ic heat w ater in stacks 1,83 kJ/kg.K 1,83 kJ/kg.KEnergy losses due to H2 in fuel 48,7 kW on HHV -11,2% 48,1 kW on HHV -11,0%Energy losses due to H2 in fuel 4,5 kW on LHV -1,1% 3,8 kW on LHV -1,0%2.4 Losses due to moisture in combustion airMoisture in ambient air 0,007 kg w ater/kg air 0,007 kg w ater/kg airMoisture in ambient air 0,123 kg w ater/ kg fuel 0,122 kg w ater/ kg fuelSpecif ic heat w ater in f lue gas 1,83 kJ/kg.K -0,1% 1,83 kJ/kg.K -0,1%Energy losses due to moisture in air 0,4 kW -0,1% 0,3 kW -0,1%5. Heat gains5.1 Economizer (non condensing)Temperature stack after economizer 206,0 °C 187,0 °CHeat transfer eff iciency 100% 0,0% 100% 0,0%Heat recovered by economizer 0,0 kW 0,0% 0,0 kW 0,0%7. Chiller Efficiency and Fuel Costs


Compared to the previous calculation, showing the calculation for 2011, the annual gas savings are RS

11.012.356 – RS 9.693.661 = RS 1.318.695 (€ 11.300,-), being 12,0% of the gas budget for the chillers.


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4.4 Investments

Considering the presence of other burners on site (chillers) it may be beneficial for the site to buy a

combustion analyser and train operators to adjust burners.

Budgetary costs for this project are estimated at is RS 250.000,- (€ 2.150,-)

Including:

- Combustion analyser

- Operator training

Payback time for this project is less than 3 months.


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5 Summary of deviations noticed during the audit

This chapter summarizes deviations observed during the audit. All issues were discussed with plant

personnel during the audit

Boiler 3 blow down

Boiler 3 has only bottom blow down, the surface blow down connection is not used, where impurities

typically float on the surface of the boiler water. Bottom blow down is intended to remove deposits from

the bottom of the boiler, and this kind of blow down should only be performed for less than 10 seconds

per day. Maintaining TDS levels with bottom blow down only will lead to excessive blow down flows

without sufficiently lowering the TDS where it matters. Steam quality issues due to foaming and carry

over are likely to happen.

Steam traps roof dehumidifiers

The steam traps installed on the roof dehumidifiers are ALL in full blow through condition therefore the

condensate return temperature was extremely high as the rest of the condensate from site is returned

via existing pumps. A combination of steam in the return line and atmospheric CRU has led to pipe

failure and problems with water hammer and the pumps on CRU. It is recommended to replace these

steam traps as soon as possible.

Steam Mains

Steam take-off lines are generally being taken from the top of distribution mains to heat transfer

equipment as per good steam practice. However some lines to process equipment is taken from the


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bottom, also there some areas with no trap stations prior to control valves this will allow condensate to

build up causing water hammer, corrosion/erosion with-in the system. This will lead to

• Premature failure of the valves

• Corrosion/erosion of heating surfaces of equipment

• Poor heat transfer and hence longer than required heat-up times

• Poor temperature control of equipment due to the variable steam quality

• Mechanical failure (leaks) of pipe work and the heating surfaces

Drain Pockets

The distribution system generally has enough steam traps installed on steam lines with a few exceptions

(see above)

Control valves are not protected by a steam trap installation prior to the valves. This will allow

condensate to build up before the valve which will back up to the nearest line drain. When the control

valves operate significant thermal and hydraulic shock will take place also poor control and slow start-up

conditions.

Where possible a steam trap should be fitted to protect equipment but also to ensure steam main is full

of steam and ready to give quick start-up.

Steam traps are fitted with line sized connections to steam mains on site; these should be installed with

a collection pocket to allow condensate from the main to be collected within the pocket.

Also the steam trap pocket should always be at the bottom of the steam main if possible at the lowest

point where the condensate collects.

Typical arrangement should be:

Up to 100mm Line size pocket length 2Dia

Up to 200mm, min 100mm pocket length 2Dia

250mm above D/2 pocket length Dia


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Strainers All strainers on the steam system at all sizes are fitted with the basket hanging down, allowing

condensate to collect in the body and reducing the free surface area. When fitted prior to a control valve

it will ensure that when the control valve opens the condensate and dirt collected will travel through the

valve causing, water hammer, erosion/corrosion and valve damage.

It is recommended that all strainers be turned through 90 degrees to ensure that condensate will not

collect.


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6 Complete check list of all verifications done during the audit

Potential optimisation Status Comments

STEAM GENERATION

Steam pressure setting Ok 8 Bar(g)

Feed water temp. to the boilers Not ok Around 75°C, Steam sparge in hot well is out of

service

Stack temperature in front of

economizer

Ok High 210°C on boiler 1 due to high load. 190°C

on other boilers. Savings from switching duty

boiler will be eliminated by higher radiation losses

of larger boilers.

Stack temperature after eco. Not ok No economisers installed. Limited steam budget

does not allow investing in economizer

installation.

Combustion air temperature Ok Boilers take air from inside of boiler house,

ambient temperature relatively high.

Oxygen rate Not ok All burners should be tuned regularly. See

projects 1 and 2.

Boiler sizing ok Boiler 1 may be undersized for peak loads, but as

long as the site runs a hot stand by boiler it

should be ok.

Boiler blow down rate Not ok Boiler 3 has no surface blow down. TDS readings

in boiler log sheets seem inconsistent an vary

between 1400 and 3600ppm.

Deaerator pressure n.a. Non–pressurized hot well. Pressurized DA to

save chemicals not feasible

Feed-water pre-heating n.a.

Boiler stand-by time and volatility

of steam demand

Ok 1 duty boiler, 1 hot stand by, 1 cold stand by.

Boiler blow-down recovery Ok Limited steam budget does not allow investment

for blow down heat recovery.


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STEAM DISTRIBUTION

External leaks of steam or

condensate from pipes, flanges,

etc.

ok

Ok, system is generally well maintained.

System design, trapping points etc. Not ok The general design of the system is ok. However,

in several locations strainers are fitted with

baskets down, drip legs are missing.

Insulation ok Insulation on site appears to be in good condition,

thermography study was carried out recently

Steam quality Not ok Risk for carry over (wet steam) from boiler 3 due

to missing surface blow down.

Steam pressure level Ok

STEAM USERS

Condensate drainage and air

venting from heat exchangers

Not ok Most heat exchangers and coils operate in a

flooded condition due to low temperature

setpoints or condensate back pressure. All

controls are on/off. See appendix 3.

Steam traps Not ok Steam traps roof dehumidifiers full blow through.

Full trap survey recommended

CONDENSATE AND FLASH STEAM RECOVERY

Condensate recovered Not ok 70% condensate return. Failing condensate

return units and pipework due to leaking steam

traps.

Sizing of condensate return lines ok

Flash steam recovery Not ok Steam venting due to leaking steam traps, these

should be replaced.

Water hammering Not ok Water hammering due to leaking steam traps.

Note: Insulation of pipes and ancillaries was not checked in details, as this issue is already covered by

another company.


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7 Recommended complementary studies

7.1 Additional energy-saving optimisations

7.1.1 Heat recovery gas fired chillers

7.1.1.1 Current situation

There are 2 gas fired chillers on site. During the audit flue gas temperatures were measured. The

average temperature for chiller 1 was 206°C. The average temperature for chiller 2 was 187°C.

7.1.1.2 Optimization

During combustion, the carbon from the fuel combines with the oxygen and gets converted in to CO2.

This oxidation reaction is exothermic and liberates heat. This heat is absorbed by the chiller. The gases

of this reaction are exhausted via the stack of the chiller. The energy contained in these exhaust gases

accounts for a major part of the efficiency loss. It is therefore important to recover the maximum amount

of energy out of these gases by using economizers.

An indirect heating type economizer consists of a coil heat exchanger, with finned or un-finned tubes,

placed in the exhaust gas flow as a section of the ductwork or stack. With this type of economizer, the

water flows through the tubes and absorbs the excess heat from the flue gas.

The flue gas outlet temperature can be brought down to as low as 100˚C when used to heat hot water

systems (depending on the heat sink temperature and thermal efficiency).

Additional engineering will be required for these optimisations as the time on site did not allow for a

detailed analysis.


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7.1.1.3 Savings calculation

The following calculation shows the chiller heating efficiency based upon 2011 gas consumption and

tuned burners. Chiller heating efficiency calculation Chiller 1 Chiller 2Attachment 4.4, 2011 production with tuned burnersChiller operating hours (incl. hot stand-by hours) 6.570 hours/year 6.570 hours/year1. Fuel heat input %LHV %LHVFuel type: 0 Custom gas %HHV 0 Custom gas %HHVFuel consumption during operating hours 45,4 Nm3/h 45,4 Nm3/hSpecif ic w eight of the fuel 0,79 kg/Nm3 0,79 kg/Nm3Fuel consumption 35,7 kg/h 35,7 kg/hLower heating value (LHV) 39704 kJ/kg (=31230 kJ/Nm3) 39704 kJ/kg (=31230 kJ/Nm3)Higher heating value (HHV) 44057 kJ/kg (=34654 kJ/Nm3) 44057 kJ/kg (=34654 kJ/Nm3)Fuel unit costs 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3) 1688,957 Rs/MWh HHV (= 16,26 Rs/Nm3Fuel heat input (LHV) 393,6 kW 100% 393,6 kW 100%Fuel heat input (HHV) 436,8 kW 436,8 kW2. Thermal lossesTemperature f lue gas after Chiller 206,0 °C 187,0 °CTemperature outside air 30,0 °C 30,0 °CExcess air 28,3 % 28,3 %Oxygen % in f lue gas (Dry volume) 5,00 % 5,00 %2.1 Losses in dry flue gasSpecif ic f lue gas f low (dry) 12,42 Nm3/kg fuel 12,42 Nm3/kg fuelTotal f lue gas f low (dry) 443,3 Nm3/h 443,3 Nm3/hTotal f lue gas f low (w et) 530,9 Nm3/h 530,9 Nm3/hSpecif ic heat f lue gas (Dry volume) 1,38 kJ/Nm³.K -6,8% 1,37 kJ/Nm³.K -6,0%Energy loss in dry flue gas 29,63 kW -7,5% 26,31 kW -6,7%2.2 Losses due to moisture in fuel Moisture in fuel 0,000 kg/kg fuel 0,000 kg/kg fuelSpecif ic heat w ater in fuel 4,18 kJ/kg.K 4,18 kJ/kg.KSpecif ic heat w ater in f lue gas 1,83 kJ/kg.K 1,83 kJ/kg.KEnergy losses due to moisture in fuel 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0%Energy losses due to moisture in fuel 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0%2.3 Losses due to H2 of FuelMoisture in f lue gas 1,785 kg/kg fuel 1,785 kg/kg fuelSpecif ic heat w ater in fuel 4,18 kJ/kg.K 4,18 kJ/kg.KSpecif ic heat w ater in stacks 1,83 kJ/kg.K 1,83 kJ/kg.KEnergy losses due to H2 in fuel 48,7 kW on HHV -11,2% 48,1 kW on HHV -11,0%Energy losses due to H2 in fuel 4,5 kW on LHV -1,1% 3,8 kW on LHV -1,0%2.4 Losses due to moisture in combustion airMoisture in ambient air 0,007 kg w ater/kg air 0,007 kg w ater/kg airMoisture in ambient air 0,123 kg w ater/ kg fuel 0,122 kg w ater/ kg fuelSpecif ic heat w ater in f lue gas 1,83 kJ/kg.K -0,1% 1,83 kJ/kg.K -0,1%Energy losses due to moisture in air 0,4 kW -0,1% 0,3 kW -0,1%5. Heat gains5.1 Economizer (non condensing)Temperature stack after economizer 206,0 °C 187,0 °CHeat transfer eff iciency 100% 0,0% 100% 0,0%Heat recovered by economizer 0,0 kW 0,0% 0,0 kW 0,0%7. Chiller Efficiency and Fuel Costs

Net heat output in steam from the Chiller (LHV) 359,1 kW ( 2360 MWh) 363,1 kW ( 2386 MWh)Chiller efficiency on LHV 91,24 % 92,25 %Chiller efficiency on HHV 82,22 % 83,14 %Annual Fuel costs 4.846.831 Rs/year 4.846.831 Rs/year The total heat output was calculated to be 4.622 MWh (527,6 kW average) and the total gas costs are

RS 9.693.661 (€ 83.065,-).


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The following calculation shows the same chiller heating efficiency calculation based upon the same

chiller load, where the flue gasses are cooled down to 100°C using economizers. Chiller heating efficiency calculation Chiller 1 Chiller 2Attachment 4.5, 2011 production, tuned burners and economizersChiller operating hours (incl. hot stand-by hours) 6.570 hours/year 6.570 hours/year1. Fuel heat input %LHV %LHVFuel type: 0 Custom gas %HHV 0 Custom gas %HHVFuel consumption during operating hours 45,4 Nm3/h 45,4 Nm3/hSpecif ic w eight of the fuel 0,79 kg/Nm3 0,79 kg/Nm3Fuel consumption 35,7 kg/h 35,7 kg/hLower heating value (LHV) 39704 kJ/kg (=31230 kJ/Nm3) 39704 kJ/kg (=31230 kJ/Nm3)Higher heating value (HHV) 44057 kJ/kg (=34654 kJ/Nm3) 44057 kJ/kg (=34654 kJ/Nm3)Fuel unit costs 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3) 1688,957 Rs/MWh HHV (= 16,26 Rs/Nm3Fuel heat input (LHV) 393,6 kW 100% 393,6 kW 100%Fuel heat input (HHV) 436,8 kW 436,8 kW2. Thermal lossesTemperature f lue gas after Chiller 206,0 °C 187,0 °CTemperature outside air 30,0 °C 30,0 °CExcess air 28,3 % 28,3 %Oxygen % in f lue gas (Dry volume) 5,00 % 5,00 %2.1 Losses in dry flue gasSpecif ic f lue gas f low (dry) 12,42 Nm3/kg fuel 12,42 Nm3/kg fuelTotal f lue gas f low (dry) 443,3 Nm3/h 443,3 Nm3/hTotal f lue gas f low (w et) 530,9 Nm3/h 530,9 Nm3/hSpecif ic heat f lue gas (Dry volume) 1,38 kJ/Nm³.K -6,8% 1,37 kJ/Nm³.K -6,0%Energy loss in dry flue gas 29,63 kW -7,5% 26,31 kW -6,7%2.2 Losses due to moisture in fuel Moisture in fuel 0,000 kg/kg fuel 0,000 kg/kg fuelSpecif ic heat w ater in fuel 4,18 kJ/kg.K 4,18 kJ/kg.KSpecif ic heat w ater in f lue gas 1,83 kJ/kg.K 1,83 kJ/kg.KEnergy losses due to moisture in fuel 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0%Energy losses due to moisture in fuel 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0%2.3 Losses due to H2 of FuelMoisture in f lue gas 1,785 kg/kg fuel 1,785 kg/kg fuelSpecif ic heat w ater in fuel 4,18 kJ/kg.K 4,18 kJ/kg.KSpecif ic heat w ater in stacks 1,83 kJ/kg.K 1,83 kJ/kg.KEnergy losses due to H2 in fuel 48,7 kW on HHV -11,2% 48,1 kW on HHV -11,0%Energy losses due to H2 in fuel 4,5 kW on LHV -1,1% 3,8 kW on LHV -1,0%2.4 Losses due to moisture in combustion airMoisture in ambient air 0,007 kg w ater/kg air 0,007 kg w ater/kg airMoisture in ambient air 0,123 kg w ater/ kg fuel 0,122 kg w ater/ kg fuelSpecif ic heat w ater in f lue gas 1,83 kJ/kg.K -0,1% 1,83 kJ/kg.K -0,1%Energy losses due to moisture in air 0,4 kW -0,1% 0,3 kW -0,1%5. Heat gains5.1 Economizer (non condensing)Temperature stack after economizer 100,0 °C 100,0 °CHeat transfer eff iciency 100% 5,1% 100% 4,2%Heat recovered by economizer 22,3 kW 5,7% 18,2 kW 4,6%7. Chiller Efficiency and Fuel Costs


Compared to appendix 4.7, this would generate an additional 279 MWh per year (31,9 kW average) of

water heating capacity, which would otherwise have to be heated with steam. Considering boiler house

efficiency of 73,1% (HHV) this optimisation could reduce the sites gas consumption by 381 MWh or RS 645.155,- (€5.528,-) per year, being 6,7% of the gas budget for the chillers.


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7.1.1.4 Investments

Calculation of the investment costs for this project requires additional study in corporation with local

contractors and equipment suppliers.


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7.1.1.5 Define and monitor specific steam and condensate system KPI’s

Often energy losses in steam and condensate systems are “invisible” and therefore not immediately

recognized. Losses can exist for a long period of time before they are fixed.

We recommend to define and monitor steam system specific KPI’s. These KPI’s will allow early

discovery of deviations causing loss of energy, water or chemicals. Furthermore it will allow you to create

historic system performance trends which can be very helpful in the process of continuous system

improvement.

Typical “high level” and minimum KPI’s to monitor would be:

- Boiler house efficiency (steam to gas ratio)

- Specific steam consumption (per building, per degree day, per ton of product etc.)

- Condensate recovery rate

Any deviation from these top level KPI’s could be further investigated using highly recommended second

level KPI’s like:

- Individual boiler efficiency

- Hot well and deareator steam consumption

And after the second level KPI’s a third level could be monitored, like:

- Economizer efficiency (future)

- Blow down rate

- Combustion efficiency

- Boiler load

- Condensate return temperatures

It will be obvious that the deeper the level of KPI’s, the more measurements have to be taken. However

the deeper the level, the less frequent these measurements will be required.


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It is not possible to predict future savings from early discovery of potential energy losses. However on

most sites history has shown that significant losses could have been prevented when the right KPI’s

were monitored regularly.

Defining and monitoring the optimum level of KPI’s requires tailoring for each plant and requires close

co-operation with plant personnel. Armstrong has developed a KPI-monitoring system called a “Steam

Dashboard” that could be tailored and implemented.

7.2 Operational optimisations

7.2.1 Flooded heat exchangers

Poor drainage of condensate from pressure controlled heat exchangers could have an impact on

productivity (decreased heat exchange surface and unstable heating temperature) and on maintenance

(leaking heat exchangers due to corrosion and water hammering). The reasons for this phenomenon

and possible solutions are described in details in appendix 3. A number of heat exchangers operating

under these conditions were identified on your site (Hot water loops, AHU coils). In case flooding of heat

exchangers starts creating important productivity and maintenance problems, we recommend studying in

more details the best solution for each concerned heat exchanger.


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8 Appendix N°1: Determination of the 2011 steam production and boiler house efficiency

Appendix 4.1 shows the indirect boiler house efficiency calculation (“Boiler house simulation”). The sheet

was adapted for this specific site, but contains some additional calculations (economizers, 5 boilers,

CHP etc.) that are not applicable. This calculation was based upon information gathered during the audit.

Operational data was copied from boiler log sheets, and measured during the audit. Fuel input for this

calculation was taken from the monthly gas invoices. For information that was not available engineering

assumptions were made based upon observations and standard engineering practices.

Summary of the results of the indirect boiler house calculation, showing boiler house efficiency and costs

of steam (leaving the boiler house) is copied below: 12. Overall Boiler House EfficiencyNet total output from the boiler house (incl. CHP) 338,8 kW 100,0%Boiler house efficiency on LHV 81,1 %Boiler house efficiency on HHV 73,1 %Annual fuel consumption (LHV) 3.128 MWh/yearAnnual fuel consumption (HHV) 3.471 MWh/yearAnnual CO2 emissions (49,9 kg/GJ / 179,5 kg/MWh HHV) 623 tons/yearAnnual fuel costs 5.862.127 Rs/year12a. Steam generation and steam costsNet total steam heat output from the boiler house 338,8 kW 100,0%Net total steam heat output from the boiler house 2.537 MWh/yearNet dry steam production boiler house 0,494 ton/h = 3699 t/yearNet wet steam production boiler house x=1 0,494 ton/h = 3699 t/yearAnnual fuel consumption (LHV) 3.128 MWh/yearAnnual fuel consumption (HHV) 3.471 MWh/yearFuel costs for steam generation 5.862.127 Rs/year 82,0%Electricity unit costs 10,000 Rs/kWhElectrical pow er for the boilerhouse 15 kWElectricity costs 1.123.200 Rs/year 15,7%Make up w ater unit costs 120,00 Rs/m3Make up water costs 134.666 Rs/year 1,9%Costs for chemicals 30000 Rs/year 0,4%Sew er unit costs 0,00 Rs/m3Sewer costs 0 Rs/year 0,0%CO2 unit costs Rs/tonCO2 Emissions ( 168,4 kg/ton of dry boiler house steam) 623 ton/yearCO2 costs 0 Rs/year 0,0%Total variable steam costs 7.149.993 Rs/year 100%Total costs steam from boiler house 1.932,88 Rs/tonTotal costs steam from boiler house 2,8184 Rs/kWh This calculation shows that the total steam budget is RS7.149.993 (€61.268,-) per year and the steam

costs are RS1.932 (€ 16,56) per ton.


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9 Appendix N°2: Calculation of Boiler house efficiency

Where boiler efficiency only focuses on the steam output of the boiler, the boiler house efficiency

considers the steam output from the total boiler house. The boiler house efficiency will obviously be less

than the boiler efficiency. A poor boiler house efficiency will not automatically mean that there is a

problem in the boiler house. For instance a low condensate return ratio will increase the deaerator ’s (hot

well) steam consumption and decrease the boiler house efficiency (less steam output at the same fuel

consumption). Reversely a steam trap passing live steam in to the condensate return may reduce the

deaerator ’s steam consumption. This is why we first want to explain the main components which are in

the boiler house efficiency calculation sheets included in this report.

9.1 Theoretical steam production

In a steam boiler water from the dearator is evaporated to saturated steam at a certain pressure. In

steam tables the Enthalpy of the steam and the feed water can be found. The difference is the amount of

heat (in kJ) that has to be added to every kg of feed water to generate the same amount of steam.

Every fuel has a unique composition and energy content described by its fuel specifications. When

available the fuel specifications by the vendor should be used. Two heating values are typically assigned

to fossil fuels depending upon whether the latent heat of the water formed during the combustion is

included (HHV: higher heating value) or excluded (LHV: lower heating value). In Europe it is common to

use LHV.

In a CHP, the flue gasses have already delivered part of their energy content to the engine before

entering the CHP boiler. If we subtract this mechanical and thermal energy from the total fuel input, the

remaining energy is available for the CHP steam boiler.


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9.2 Combustion losses

In fact a boiler is a large heat exchanger. An economizer, which pre-heats the feed water from the

deaerator with combustion gasses, is included in the boiler system. Thus the boiler feed water enters the

boiler system at deaerator temperature, and leaves the boiler as steam at saturation temperature. The

combustion gasses leaving the boiler system can therefore never be colder than the dearator

temperature In practice a well designed feedwater economizer can lower the stack temperature to about

25°C above the dearator temperature, which is 130°C. (or about 120°C in case of a non pressurized hot

well). The final design temperature is dependent on which fuel is used (on Fuel boilers the economizer is

often designed to keep stack temperatures above 180C) When there is no economizer, the stack

temperature will always be above the steam saturation temperature; the larger the heat exchanging

surface, the lower the back end temperature will be.

To ensure that all fuel is burned and no carbon monoxide is generated, all burners use excess air. This

extra air required for gaseous fuels is typically about 15%. Significantly more may be needed for liquid

and solid fuels. Also combustion in CHP engines will require much more excess air. Although required,

higher excess air wastes fuel for a number of reasons. Supply air cools the combustion system by

absorbing heat and transporting it out the exhaust flue. It should be considered here that Nitrogen does

not play a chemical role to produce heat, and it makes up about 80% of the combustion air.

It is obvious that the stack losses cannot be fully eliminated and that the amount of stack losses is

effected by the stack temperature and the excess air percentage.

The Siegert formula is widely used in Europe to determine flue losses (qA) and efficiency:

qA = (Ts – Ta) x ( (A2 / (21-O2) )+ B)

efficiency = 100 - qA

Where: qA = flue losses

Ts = flue temperature


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Ta = supply air temperature

O2 = measured volumetric oxygen percentage

A2, B = fuel dependent constants

The following values are prescribed for some common fuels:

Siegert constants Fuel type A2 B

Natural gas 0,66 0,009

Fuel oil light 0,68 0,007

Fuel oil heavy 0,68 0,007

Town gas 0,63 0,011

Coking oven gas 0,6 0,011

LPG(Propane) 0,63 0,008

A more accurate way to calculate flue losses is to calculate the required combustion air flow, the

resulting flue gas flow and composition, and the specific heat from the flue gasses, from the chemical

fuel composition. Measuring ambient and flue gas temperatures will then also allow calculating flue gas

losses. This method is used in our calculations.

9.3 Radiation losses

The radiation losses of a boiler is the energy loss of this boiler to its environment. As for every heat

exchanging process, the amount of heat transferred depends on the temperature differential between

the boiler (steam pressure) and its environment, the design of the boiler (heat exchanging surface) and

the quality of its insulation. Typically the radiation loss of a water tube boiler lies around 1 % of the

maximum boiler capacity, for a fire tube boiler the radiation losses are usually around 0,6% of the

maximum boiler capacity. As none of the parameters mentioned before changes with the boiler load, this

is a fixed number. With boilers operating at a low load, this number can be a significant percentage of

the load.


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9.4 Cycling losses

Normally not taken in to account (considered to be included in the radiation losses) is the purge loss of a

boiler. Every time the burner starts (pre-purge) and stops (post purge), the burner fan will purge the

boiler with air for about 2 minutes. This purge air will be heated as it passes the hot boiler, and this

energy will also be lost. Part if it may be recovered by an economizer though. Normally this purge loss is

very small compared to the boiler load, but when the load decreases and the number of burner starts

increases, this energy loss will have an effect on the boiler efficiency.

The temperature of the exhaust gasses after they have passed the boiler is very close to the steam

temperature. To calculate the heat loss we have to calculate the amount of exhaust gas, and heat these

gasses from boiler room temperature to steam temperature. For the vent air flow we assume that the air

flow is the same as the combustion air flow at the maximum burner load.

It is complicated to predict the amount of burner starts, especially when only the average steam load is

known. The way we estimate it is the following:

- The burner only stops when the minimum burner rating is higher than the average burner load.

When the burner stops the boiler acts like a steam accumulator; excess sensible heat from the

feed water volume produces steam to cover the average burner load. In fact the boiler water

flashes due to a pressure drop.

- The burner has to restart when the pressure has dropped below minimum. When the burner

starts, the excess capacity of the burner adds sensible heat again to the boiler feed water

volume, and the pressure rises again. The burner has to stop when the maximum steam

pressure is reached.

- The total burner cycle time is now cool down time + purge time + heat up time. The number of

cycles is now 1/cycle time.

- Every time the burner starts the boiler is vented with maximum flow of combustion air (=

calculated average combustion air flow / average load). In our calculation we consider this air to

be heated to the steam temperature.


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9.5 Blow down losses

The boiler blow down system includes the valves and the controls for the continuous (surface) blow

down and the bottom blow down services. Continuous blow down removes a specific amount of boiler

water (often measured in terms of a percentage of the feed water flow) in order to maintain a desired

level of total dissolved solids in the boiler. Setting the flow for the continuous blow down is typically done

in conjunction with the water treatment program. Some systems rely on the input of sensors that detect

the level of dissolved solids in the boiler water. Boiler blow down rates typically vary between 4 to 8 % of

the boiler feed water flow, but can be significantly lower when there is a high condensate return rate or

when there is a reversed osmosis system installed. The continuous blow down water has the same

temperature and pressure as the boiler water. Before sending this high energy water to the sewer, it can

be send to a flash tank where this flash tank permits the recovery of low pressure flash steam.

The bottom blow down is performed to remove particulates and sludge from the bottom of the boiler.

Bottom blow downs are periodic and typically performed according to a schedule.

The continuous blow down flow can be calculated using measured conductivities:

Blow down % = µs/cm feed water / (µs/cm boiler water - µs/cm feed water ) x 100%

9.6 Dearator or hot well steam consumption

The dearator (or hot well) consumes steam for two reasons. First the deaerator has to heat up the

mixture of returned condensate and make-up water to the deaerating temperature which is typically

105°C / 0,2 bar(g) for a pressurized deaerator. Second the gasses which are released from the feed

water have to be removed (vented) from the deaerator. With the vented gasses, always some steam

escapes. The amount of steam vented is usually 0.05% of the deaerator tank capacity.

The amount and temperature of the feed water that has to be heated by the deaerator or hot well usually

is derived from the conductivity measurements of the return condensate and the makeup water. Another


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way is by measuring the makeup water flow and compare this with the net steam production that is be

expected from the boiler looking at the fuel consumption. When the condensate return ratio and the

temperatures of the return condensate and the makeup water are known, the temperature of the mixture

can be calculated.

The vent line from the dearator is always over-sized as it has to discharge the non condensable gasses

under all circumstances. Worst case scenario here is maximum load of the boilers at minimum

condensate return rate.


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10 Appendix N°3: Steam Pressure Controlled Heat Exchangers at Low Load


Within the steam system, there are several pressure controlled heat exchangers operating at low loads.

Within these heat exchangers, liquids or gasses (air) are heated along with the steam. Most of the time

the desired medium temperature is below 100°C, and the heat exchanger is working at partial load.

Under these conditions, regardless of brand or model, problems may occur due to the physical

properties of the steam.

An audit is only a short visit on site, in which it is impossible to see all operating conditions. Most

problems with heat exchangers only occur at certain conditions. For instance, operation of heat

exchangers for building heating may only be a real problem during the fall and the spring, when partial

loads are typical. Due to the variability of these problems they are often not recognized in time, and can

cause process bottlenecks, loss of production, loss of temperature control and increased maintenance

costs.

Control of steam pressure can be designed in two ways: modulating or on-off. In both cases the control

valves are modulated by the measured temperature of the heated media. Steam pressure controlled

heat exchangers at low loads almost always produce sub-cooled condensate.

Modulating Controls

The steam pressure after a modulating control valve is always lower than the steam pressure in the up

steam lines, unless the system is working at full load which is a rare operating condition.

When heating a product to a temperature below 100ºC, the required steam temperature will often be

close to 100ºC, as the latent heat of the steam is used to transfer the energy as the steam condenses.

Steam temperatures lower than 100ºC, has a pressure below atmospheric pressure. If the steam

pressure after the steam control valve is less than the pressure in the condensate line, there will be no


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driving force (pressure differential) available to push the condensate out of the heat exchanger and move

it to the condensate receiver. The condensate will back up in the heat exchanger, and will become

flooded. This situation is often called a “stall situation”. As the condensate backs up in the heat

exchanger, it will exchange sensible heat with the product, where the condensate becomes sub-cooled

(matching the product temperature). The infrared pictures below show the condensate backing up in a

shell and tube heat exchanger as well as a plate and frame heat exchanger, and the resulting

temperature differences in it.

The more a heat exchanger is oversized, the sooner it will operate at a partial load and the more the

condensate will sub-cool.

During a stall condition, the output of a heat exchanger is no longer controlled by the steam pressure

and the resulting amount of steam through the control valve. In fact the output is now continuously

controlled (limited) by the condensate level inside the heat exchanger. A few centimetres change of

condensate level will have a huge impact on the heat output. A pressure change of only 10 centimetres

water column (= 0,01 Bar) on steam inlet or condensate outlet (= back pressure) can be the difference

between 0% and 100% output. In the best case scenario the control system will balance the

steam/product differential. However even the best control system cannot control the back pressure

variations in the condensate return system. Therefore, in most cases the following is observed:


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Due to the condensate backing up the amount of heated surface in the heat exchanger is reduced, and

the desired set point product temperature cannot be reached. As a reaction to this, the steam control

valve will open, thus providing enough pressure differential to push out the condensate. When this

happens all the heating surface in the heat exchanger is available again causing a sudden rise in the

product temperature. There will be an overshoot in temperature which the controls will try to correct by

closing the steam control valve. This cycle will repeat and control valves will “hunt” searching for

balance. Hunting control valves, and actuators, wear quicker and tend to leak. The most critical aspect of

cycling control valves is that the frequent changes in temperature will cause local material stresses in the

heat exchanger, which over time can cause failures and leaks (especially in stainless steel). In addition

the presence of relatively cold condensate may cause water hammer and corrosion inside the heat

exchanger which can also lead to leaks. These leaks often occur on the outside of the heat exchanger

(gasket failure), where they will be clearly visible. However these leaks can just as easily occur inside a

heat exchanger, thus causing contamination issues and even blockage of heat exchangers.

Lowering the condensate back pressure will reduce the risk of condensate backing up in the heat

exchanger, which provides two system improvements. First, it will reduce the loss of exchanger capacity,

and second, it reduces the risk of water hammer. Often when condensate is backing up, the condensate

lines are drained to the sewer. This is only a temporary fix and is a great loss of energy and can raise

waste water temperatures above safe limits.

On-off controls

As with modulating controls, very similar conditions occur in an on-off controls. The steam valve opens

when there is a heat demand. A positive pressure differential is created, and the condensate in the heat

exchanger is pushed out. The heating surface in the heat exchanger is exposed and the capacity rises.

Before all of the condensate is pushed out, the desired temperature is reached and the steam valve

closes. During this cycle the steam trap does not receive condensate with a temperature above 100ºC.

When the steam valve closes, the steam in the heat exchanger will condense, thus creating a vacuum in

the heat exchanger. This vacuum will pull condensate back from the condensate line unless there is a

check valve in place. The condensate inside the heat exchanger will continue to cool down (sub-cool).


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When the steam valve opens again, the hot steam will be in contact with the relatively cold condensate.

When this occurs there is a serious risk for thermal water hammer to occur. Over time these water

hammers, and the presence of cold aggressive condensate, can cause leaks.

Installing a vacuum breaker and a check valve may eliminate the vacuum and the backing-up of

condensate, but it will also allow air to enter the system. This air has to be vented from the heat

exchanger otherwise it will reduce the effective steam temperature, and as a result, the heat exchanger’s

capacity. Air in the condensate system will cause corrosion.

10.2 Optimization

A number of solutions have been developed to solve the problems with heat exchangers at low/partial

loads. Finding the most effective and efficient solution would require custom tailored engineering.

Basically there are six methods to remove the condensate from a flooded heat exchanger with steam

pressure control:

• a closed loop pumping trap

• a Posipressure system

• a safety drain trap

• a barometric leg

• change to condensate level control

• a mixing valve on the product side


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10.2.1 Closed loop pumping trap

A closed loop pumping trap arrangements uses a balancing line to equalize the pressure in the heat

exchanger and the pumping trap. Condensate will drain by gravity toward the pump, and will be pushed

out using steam pressure. The diagram below shows a typical setup:


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10.2.2 Posipressure system

A Posipressure system allows air or nitrogen to push out the condensate as soon as the steam pressure

inside the heat exchanger is less than the back pressure in the condensate system. When using a

Posipressure system, the condensate return system should be able to handle small quantities of air or

Nitrogen. The steam traps applied should be inverted bucket traps, and the condensate receiver has to

be vented. The diagram below shows a typical setup for this arrangement:


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10.2.3 Safety drain

A safety drain is a second trap that is sized to handle the same load as the primary trap. It is located

above the primary trap and discharges into an open sewer. When there is sufficient differential pressure

across the primary trap to operate normally, condensate drains from the drip point, through the primary

trap, and up to the overhead return line. When the differential pressure is reduced to the point where the

condensate cannot rise to the return, it backs up in the drip leg and enters the safety drain. The safety

drain then discharges the condensate by gravity.

10.2.4 Barometric leg

A barometric leg can be created by moving the steam trap to a lower position. Every meter the trap is

positioned below the heat exchanger will generate 0,1 Bar pressure differential. Reversely, lift of

condensate after the steam trap or back pressure in the condensate return system, will reduce (or even

eliminate) the effect of the created barometric leg. Of course this option will only work if sufficient height

differential is available. A steam temperature of 60°C requires a barometric leg of 8 meters!


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10.2.5 Condensate level control

On condensate level controlled heat exchangers full steam pressure is applied on the heat exchanger.

The capacity of the heat exchanger is controlled by changing the level of condensate inside the heat

exchanger. The submerged part of the heat exchanger works as a condensate after cooler. Condensate

from a condensate level controlled heat exchanger is always sub cooled.

Heat exchangers have to be specially designed to work on condensate level control. There should be

sufficient height differential between minimum and maximum condensate level to allow accurate control.

Horizontal heat exchangers cannot be used for condensate level control. Furthermore the heat

exchanger should be able to handle mechanical stress due to local temperature variations, and the heat

exchanger should be able to handle sub-cooled (low pH) condensate. Most plate and frame heat

exchangers are not suitable for condensate level control. Vertical hairpin heat exchangers, with steam

and condensate in the shell and product in the tubes, work best on condensate level control.

Part of the product is exposed to maximum steam pressure and hence maximum steam temperature; not

every product can handle these high temperatures. Caution is advised on applications where the steam

temperature could exceed boiling temperature of the heated product (reboilers on distiller columns). Due

to local high temperatures inside the heat exchanger, the product will very likely start boiling at these hot

spots. The product vapours will implode again as soon as they mix with the colder product ( cavitation).

The result will be similar to water hammering on steam systems, only this time it occurs on the product

side. Both can cause leaks and provide a serious health and safety hazard.

Controlling on condensate level is a slow process. In the event the condensate level control valve (or

controls) fails, or if the controls cannot keep up with sudden load changes, live steam may enter the

condensate return system. During this event, the heat exchanger will work on full capacity. The pressure

in the condensate return system will suddenly increase, which may disturb other processes. These

events will soon be recognized by process operators. Passing live steam into the condensate return

system furthermore represents a serious safety issue. To control this safety risk, a number of

precautions can be applied:


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- A temperature alarm in front of the condensate discharge valve. This alarm closes the steam

inlet in case the condensate temperature exceeds a certain set point.

- A float switch on the shell of the heat exchanger. Low condensate level generates a signal to

close the steam inlet valve.

- Installation of a mechanical steam trap in front of the level control valve. The steam trap opens

for condensate and closes as soon as steam enters the steam trap. Advantage of this solution is

that it will secure operation, however the heat exchanger will work on full capacity.

Another risk using condensate level control, is that the heat exchanger will be fully flooded with

condensate (up to the steam inlet valve), in case there is no demand for heat. This could also induce

water hammering. This can be prevented by the following measures:

- A high condensate level switch closing the steam inlet on too high condensate levels.

- A mechanical steam trap at the highest condensate level. The excess condensate will be

discharged by this steam trap.

10.2.6 Mixing valve on the product side

Instead of controlling the product temperature by modulating the steam pressure, it is also possible to fix

the steam pressure and blend the heated product with cold product. In this case the steam pressure has

to be fixed at a pressure exceeding the condensate back pressure, thus securing that condensate will be

pushed out of the heat exchanger. This (too) high steam pressure will overheat the product. This

overheated product can be cooled down again by blending it with non heated product.

Caution should be taken however, as local overheating however can cause scaling and fouling issues in

heat exchangers. Furthermore the elevated steam pressures will result in elevated condensate

temperatures. As a result more flash steam will be generated, which has to be recovered to maintain

system efficiency. Also this flash steam may require enlargement of condensate return lines in order to

prevent water hammering.


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The installation of closed loop pumping trap systems, a Posipressure system or a condensate level

control, will return condensate back to the boiler house. Often on flooded heat exchangers this

condensate is drained to sewer and therefore lost. It can increase the heat exchangers capacity, and

may speed up production processes. More important are the savings achieved from improved system

reliability and controllability, however these are often difficult to quantify. The safety drain will not

improve the condensate return, but will save the coils from freezing and prevent process time downs and

maintenance labour to repair.


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11 Appendix N°4: Boiler house simulations

Appendix 4.1: Boiler house simulation based upon 2011 steam load

Appendix 4.2: Boiler house simulation based upon 2011 steam load,

with tuned burners

gsk - armstrong international · 2012. 7. 16. · gsk karachi pakistan, west wharf date: 16/07/2012...

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