GSK - Armstrong International...2012/07/23 · GSK Karachi Pakistan, Site F268 Date: 23/07/2012...

GSK

Karachi, Pakistan Site F268

STEAM AND CONDENSATE ENERGY AUDIT REPORT

PROJECT N° 11360SER2PK

1 Emission J.Zwart/D.Graham R. Ivanov 23/7/2012Item Description Established Checked out Date

STEAM AND CONDENSATE AUDIT 11360SER2PK

GSK Karachi Pakistan, Site F268

Date: 23/07/2012

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To the attention of Mr. Arif Atiq 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: Boiler burner tuning ..................................................................................... 6

3.1 Current situation ........................................................................................................................ 6 3.2 Optimization .............................................................................................................................. 6 3.3 Savings calculation ................................................................................................................... 7 3.4 Investments ............................................................................................................................... 7

4 Optimisation project n°2: Correct economizer connections Boiler 1 .................................................. 8

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

5 Optimisation project n°3: Correct blow down system ........................................................................ 11

5.1 Current situation ...................................................................................................................... 11 5.2 Optimization ............................................................................................................................ 13 5.3 Savings calculation ................................................................................................................. 15 5.4 Investments ............................................................................................................................. 15

6 Optimisation project n°4: Minimize boiler 2 running hours ................................................................ 16

6.1 Current situation ...................................................................................................................... 16 6.2 Optimization ............................................................................................................................ 16 6.3 Savings calculation ................................................................................................................. 16 6.4 Investment .............................................................................................................................. 16

7 Optimisation project n°5: Improve condensate recovery Liquids Manufacturing .............................. 17


8 Optimisation project n°6: Burner tuning gas fired chillers ................................................................. 20


9 Summary of deviations noticed during the audit ............................................................................... 22

10 Complete check list of all verifications done during the audit ............................................................ 42



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11 Recommended complementary studies ............................................................................................ 44

11.1 ADDITIONAL ENERGY-SAVING OPTIMISATIONS ................................................................................................ 44

11.2 OPERATIONAL OPTIMISATIONS ...................................................................................................................... 47

12 Appendix N°1: Determination of the 2010 steam production and boiler house efficiency ................. 48

13 Appendix N°2: Calculation of Boiler house efficiency ....................................................................... 49

14 Appendix N°3: Steam Pressure Controlled Heat Exchangers at Low Load ...................................... 55

14.1 Current situation ...................................................................................................................... 55 14.2 Optimization ............................................................................................................................ 58 14.3 Savings calculation ................................................................................................................. 64

15 Appendix N°4: Boiler house simulations and chiller calculations ...................................................... 65



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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

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. In liquid

manufacture most of the condensate is dumped to drain. Condensate return temperature to the hot well

was measured between 79 and 85°C. Condensate return ratio was calculated to be 53% only for 2010

(estimated possible rate is at least 70%), due to failed condensate return units.

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

There are two existing boilers, a modern 4 pass Cleaver Brooks 7T fitted with economiser and automatic

blowdown (both piped in incorrectly). The other unit is a 1988 2.5T Dank Stone 3 pass boiler with no

economiser or automation fitted and a simple High/Low burner. The efficiency of the Cleaver Brooks

boiler is calculated at 69.9% on HHV (77.6% on LHV). The efficiency of the Dank Stone boiler is

calculated at 74.0% on HHV (82.1% on LHV) – it is better than boiler 1, mainly due to lower excess of

O2 (see project 1).

This audit identified 6 optimization projects which yield to a total savings potential of RS 2 282 500,-

(6,2% of the natural gas budget), 1 167 MWh and 224 tons of CO2 (5,7% of emissions from natural gas).



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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: 8.583 MWh (9.366 t/year – 1,069 t/h)

Steam cost: 2670 RS/MWh (1.877 RS/t - €16,08/t)

Total yearly steam budget: 17.755.000 RS/year (€150.600,-/year)

Total yearly gas consumption boilers 15.669.388 RS/year (€134.270,-/year)

Total yearly gas consumption chillers 21.182.982 RS/year (€181.500,-/year)

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

Optimisation Project Energy saving in kWh

Energy saving in Rs

Decreased CO2

emissions in tons

Water savings in Rs

Total project investment cost in Rs

Payback time in months

1 Burner tuning 840.083 1.418.864 160 4,1% - 250.000 32 Economizer correction boiler 1 93.365 157.690 17 0,4% - 600.000 463 Blow down heat recovery correction 14.643 24.731 3 0,1% - 100.000 494 Minimize boiler 2 running hours 108.391 183.067 19 0,5% - - 05 Improve condensate recovery liquid manufacturing 124.982 522.879 28 0,7% 187.200 2.300.000 396 Burner tuning chillers* 941.071 1.589.428 177 4,5% - 250.000 2

TOTAL 1.166.821 2.282.500 224 5,7% 187.200 3.150.000 16

Optimisation Project Energy saving in kWh

Energy saving in Rs

Decreased CO2

emissions in tons

Water savings in Rs

Total project investment cost in Rs

Payback time in months

about about about about about about 659.000 1.113.200 125 3,2% 0 5.000.000 54

8,9% up to average up to8.150.000 28

* Investment not added to total as it is the same as for project 1

TOTAL all projects 1.825.821 3.395.700 349

RESULTS OF THE DETAILED STUDIES

RECOMMENDED COMPLEMENTARY STUDIES (ROUGH ESTMATIONS)

7 Heat recovery gas fired chillers

187.200



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3 Optimisation project n°1: Boiler burner tuning

3.1 Current situation

During the survey combustion analysis tests were carried out on the existing steam boiler. 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 of in boiler 1 flue gas was 15.5%, for boiler 2 it was 9,6%.

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



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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.

3.3 Savings calculation

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, showing the base line boiler house

simulation for 2011, the annual savings are RS 17.574.988 - RS 16.156.124= RS 1.418.864 (€

12.160,-), being 8,1% 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,-). This investment is the same

as for Project 6.

Including:

- Combustion analyser

- Operator training

Payback time for this project is less than 3 months.



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4 Optimisation project n°2: Correct economizer connections Boiler 1


Presently two boilers are operated to cater for the plant steam demand. All boilers are gas fired,

however boilers 1 and 2 can occasionally be fired with light fuel oil (low sulphur). The present boiler feed

water temperature is 75°C maximum, from the feed tank. Currently only boiler 1 is provided with a unit

to recover heat from the flue gasses.(Cleaver Brooks)

The economizer is currently heating a low pressure pumped water circuit over the heat hot well only.

During the audit the flue gas temperature at the boiler exit of boiler 1 was measured varying between

175 and 189°C. The flue gasses are cooled by the economizer to 157°C only, by heating the hot well

water from 63°C to 72°C only. The flue gas bypass damper on the economizer was 50% open, probably

to prevent the water in the economizer from boiling. This arrangement does not take full advantage of

the economizer capacity.

4.2 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 water on the water-

side of the boiler, which is converted into steam. The gases of this reaction are exhausted via the stack

of the boiler at a temperature close to the saturation temperature of the steam. The energy contained in



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these exhaust gases accounts for a major part of the efficiency loss of a boiler. 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. Typically, deaerated feed

water is used for this purpose as a heat sink. The flue gas outlet temperature can be brought down to as

low as 120˚C (assuming 80% thermal efficiency).

The schematic below shows a typical economizer arrangement:

The systems consists of economizers with control instrumentation in the flue gas and the feed water

paths. The water passes through the tubes. The control valves maintain and modulate water flow as per

the boiler requirement. In case the boiler does not require more feed water, a secondary back pressure

control valve would open to the DA to keep the circulation of the feed water in the economizer. A by-

pass interlock on the flue gas side ensures the stack temperature stays above the specified minimum

limits (required when firing oil containing Sulphur).



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Attachment 4.3 shows the boiler house simulation, where the stack temperature of boiler 1 has been

lowered by the economizer to 130°C. Compared to appendix 4.2, showing the base line boiler house

simulation for 2011 with tuned burners (to avoid double counting of savings), the annual savings are RS

16.156.124 – RS 15.998.434 = RS 157.690 (€ 1.350,-), being 1,0% of the steam budget.

4.4 Investments

Budgetary cost for this project are estimated at RS 600.000,- (€5.140,-)

Including:

- Equipments supply (piping and ancillaries)

- Engineering

- Installation and commissioning


Note (not included in the budgetary costs):

If the water to be used as a heat sink is poorly deaerated water, the heating of the water will release the

carbon dioxide and oxygen that is dissolved in it. This will make the water extremely corrosive and

requires the use of special materials for the economizer. In addition, if the flue gases are cooled down

below the dew point, the moisture will condense on the coil tubes. This condensed water is also

corrosive. Additional provisions must be made to ensure this condensation does not fall back into the

boiler. Any material in contact with this condensation also has to be corrosion resistant.



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5 Optimisation project n°3: Correct blow down system


The existing TDS system has the conductivity probe mounted in the boiler, but the blow down valve has

been positioned incorrectly on the boiler bottom blow down. Therefore the installed TDS heat recovery

system has been disconnected and is not used due to the excess blow down that will result from the

present installation. There is also a control valve on the flash vessel outlet. This will create back pressure

problems in the blow down system.

The two steam traps from the boiler house steam header are not operational as the flash vessel is not in

use.

Existing TDS probe valve should be mounted below flange (see optimization)



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Existing blow-down valve mounted on bottom blow-down (re-position)

Blue TDS blow-down – Reinstate manifold steam traps send direct to feed tank



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Remove valve on Flash vessel outlet Existing steam trap configuration OK

5.2 Optimization

The TDS blow down valve should be installed as per the above with the valve close mounted to

conductivity probe. The discharge should then be piped directly to the flash vessel.

The flash from the vessel should then go directly to the boiler feed tank with no obstruction (the existing

control valve must be removed).

Condensate from the flash will then be discharge only to drain via the existing steam trap.



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The two connections for the two steam traps from the high level manifold can be removed. The steam

trap drains should then be piped to the feed tank and the traps re-commissioned as they are critical to

steam quality from the boiler house.

The installation should be similar to the drawing shown below:

8 Pressure Gauge to monitor the flash vessel pressure

9 Flash Vessel to distribute the flash and high pressure blowdown

10 Safety Valve to protect the system if the flash line blocks

11 Vacuum Breaker to prevent back-syphoning of the feedtank water

12 Distribution Head to efficiently eject the flash steam into the tank

13 Ball Float Steam Trap to allow the blowdown water to drain

14 Drain Valve to drain the flash vessel for maintenance purposes

15 Strainer to protect the float trap from detritus

16 Isolating Valve to isolate the heat exchanger from the flash vessel



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Attachment 4.4 shows the boiler house simulation, where the blow down system has been corrected.

Compared to appendix 4.3, showing the base line boiler house simulation for 2011 with tuned burners

and corrected economizer connections (to avoid double counting of savings), the annual savings are RS

RS 15.998.434 – RS 15.973.703 = RS 24.731 (€ 212,-), being 0,2% of the steam budget.

5.4 Investments

Budgetary cost for this project are estimated at RS 100.000,- (€ 860,-)




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6 Optimisation project n°4: Minimize boiler 2 running hours


Currently boiler 2 has a 4% better efficiency than boiler 1, however the capacity of boiler 2 is insufficient to supply the sites steam demand during production hours (see attachment 4.1, base line boiler house simulation). Therefore boiler 1 is used as the lead boiler during production hours, where boiler 2 covers the non-production hours only.

6.2 Optimization

After tuning the burners of both boilers (project 1), the efficiency of boiler 1 will be 1,6% higher than boiler 2. Correcting the economizer (project 2) and blow down heat recovery system (project 3) will increase this efficiency difference to 2,8%. It is therefore recommended to minimize the running hours of boiler 2, the site may even consider to use it as a cold stand by boiler to further reduce radiation losses of this boiler.


Attachment 4.5 shows the boiler house simulation, where boiler 2 is 100% in stand-by (consuming gas

to compensate radiation losses only). Compared to appendix 4.4, showing the base line boiler house

simulation for 2011 with tuned burners, corrected economizer connections and corrected blow down

system, the annual savings are RS 15.973.703 – RS 15.790.636 = RS 183.067 (€ 1.568,-), being 1,1%

of the steam budget

6.4 Investment

There are no investment cost associated with this optimization.



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7 Optimisation project n°5: Improve condensate recovery Liquids Manufacturing


Based upon previous measurements carried out by Spirax Sarco in 2008, the steam load for Liquid

Manufacturing varies between 750 and 2400 kg/h. Condensate from this area is not returned with the

exception of condensate from the Mez Plant Room which is returned via an existing condensate return

line to the boiler feed tank. Estimated 75% of the above total is at present dumped to drain.

7.2 Optimization

The steam users are split into three areas within this building and therefore each will require a

condensate return unit (the positioning of these units were discussed with site engineering). By using the

existing condensate return line (sizing is OK) and allowing condensate from the mez plant room to drop

into DI water plant room condensate return unit, condensate from all areas can be returned to the boiler

house saving treated water, using less make-up water at the boiler house and recovering energy left in

the condensate.

Condensate can be returned using a steam driven condensate return unit. A steam driven condensate

pump will return the hot condensate immediately, and does not require a tank allowing the condensate to

cool down.



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Assuming the minimum steam load of 750 kg/h during 2080 hours (5 days/week with 8 hours and 52

weeks), and a condensate temperature of 89°C, the savings of returning the drained condensate will be

at least RS 523.000 (€ 4.500,-)per year.

Steam pressure in application 3,0 bar(g)

Steam temperature in application 143,6 °C

Subcooling in application 54,6 °C

Temperature of drained condensate 89,0 °C

Enthalpy drained condensate 372,0 kJ/kg

Temperature make up water 20,0 °C

Enthalpy make up water 83,6 kJ/kg

Sensible heat loss 288,4 kJ/kg

Steam pressure 6,5 bar(g)

Enthalpy steam 2766 kJ/kg

Temperature deaerator / hot well 60 °C

Enthalpy feed water 250 kJ/kg

Latent heat of the steam 2515 kJ/kg

Steam required to compensate heat loss 0,115 kg/kg

Condensate flow 750,0 kg/h

Operating hours 2080 hours

Amount of drained condensate 1.560.000 kg

Steam required to compensate heat loss 178.887 kg

Steam unit costs 1876 Rs/ton

Steam costs 335.679 Rs

Make up water unit costs 120,00 Rs/ton

Make up water costs 187.200,00 Rs

Sewer unit costs 0,00 Rs/m3

Sewer costs ‐ Rs

Total costs of drained condensate 522.879 Rs/year

Costs of condensate drained to sewer



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7.4 Investments

Site already has quotation for electric CRU units (we do not have copy) however may want to consider

small vented steam/air CRU.

Budgetary cost for this project are estimated at RS 2.300.000,- (€19.700,-)

Including:

- Equipments supply (4 condensate pumps, piping and ancillaries)

- Engineering

- Installation and commissioning

Payback time for this project is less than 39 months



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8 Optimisation project n°6: Burner tuning gas fired chillers


There are 6 gas fired chillers on site 2xLiquids, 2x Penicillin, 2xTablets. A combustion analisys of these

units revealed the following:

Liquids Chiller 1 - 12.5% O2

Liquids Chiller 2 – Not operational

Penicillin Chiller 1 – 13.1%

Penicillin Chiller 2 – 11.5%

Tablet Chiller 1 – 11.9%

Tablet Chiller 2 – 13%

Typical burner Chiller (Liquid Manufacture)

8.2 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.


Attachment 4.6 shows the chiller heating efficiency calculation based upon 2011 gas consumption. The

total heat output was calculated to be 9736 MWh (111,4 kW average) and the total gas costs were RS

21.182.983 (€ 181.517,-). Appendix 4.7 shows the chiller heating efficiency calculation with the burners

tuned to a realisticaly achievable 5% O2, producing the same amount of heat to the chillers as in 2011.

Compared to appendix 4.6, showing the calculation for 2011, the annual gas savings are RS 21.182.982

– RS 19.593.544 = RS 181.517 (€ 13.620,-), being 7,5% of the gas budget for the chillers.

8.4 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,-). This investment is the same as for Project 1. Payback time for this project is less than 2 months.

Including:

- Combustion analyser

- Operator training



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9 Summary of deviations noticed during the audit

This chapter summarizes deviations observed during the audit and steam trap survey.

Pipework

Steam and condensate pipework is generally in good condition and well insulated however it was noted

that some take-offs and drain points do not conform to good steam engineering practice. It was also

noted that there are a number of joint leaks in the steam/condensate pipework which could be caused by

lack of drain points.

Main Steam Line Drains

More line drains need to be fitted at strategic points to ensure that condensate is not being carried over

to the end-user. There are some areas where steam lines rise and fall creating low points for condensate

to collect.

Condensate will build up in these areas and when steam demand increases will be carried over to the

heat exchange equipment. This will create thermal and hydraulic shock at the end user damaging the

control valve and heat exchange equipment. This also causes joint leaks within the steam and

condensate pipework as can be seen on site.

There are some instances of steam take-off lines being taken from the bottom/side of distribution mains

to control valves also as there are no trap stations prior the valves allowing condensate to build up within

the system. This will lead to:

Poor pressure/temperature control of equipment leading to the variable steam

pressure/quality

Premature failure of the control valves

Corrosion/erosion of heating surfaces of equipment

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

Mechanical failure (leaks) of pipework and the heating surfaces



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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

Strainers

All strainers on the steam system at all sizes should be fitted with the basket on the side to ensure

condensate does not 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, waterhammer, erosion/corrosion and valve damage.



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Steam Leaks

Steam leaks are generally small valve gland leaks with a few joints leaking those found have been

discussed with site personnel.

Condensate Return

Most of the site condensate is collected when possible and is returned to the boiler house, however the

condensate return in some areas in dumped (see project 5). All site condensate can be used.

Steam Traps

The system appears to be in good working condition, as stated previously there is a lack of steam traps

on the distribution mains which will contribute to poor quality steam and some thermal shock through the

system.

The condensate main within the buildings is common to all pressures however it is returned to local

condensate return units.



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Steam Trap Survey Breakdown

A limited steam trap survey was conducted within the time available the results are shown below. The

survey also identified if the condensate was being returned to the system.

Total Traps 97

Total Traps Tested 90

Leaking Traps 1

Plugged Traps 11

Out of service 14

tagnumber mfgcode model & size conditioncode to drain return

001 GEM Sapphire | 15 OS

002 GEM Sapphire | 15 OS

003 GEM Sapphire | 15 OK Yes





008 GEM Sapphire | 25 OS Yes















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023 GEM Sapphire | 15 PL Yes
































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072 GEM Sapphire | 25 LK Yes















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091 GEM Sapphire | 15 NT







Leaking steam traps

All traps passing steam need to be replaced/repaired as traps passing steam waste energy. However on

a plant with heating applications it is important that the steam traps function correctly to ensure correct

and consistent heat transfer within the heat transfer unit.

If steam is not retained in the heat exchanger it will not give up its heat to the process and hence will

require more steam to be used. When this situation takes place it is not unusual for operators to open

bypass valves wasting even more steam. It is therefore vital to replace leaking steam traps to improve

both the waste from energy loss and also improve plant efficiency. (see survey)

Out of service traps

There were a number of steam traps not in operation when the survey was undertaken some because

equipment was not in operation. (see survey)

All out of service traps should be checked to ensure that there is a legitimate reason why they are not in

operation.



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Isolation valves

Some of the trap isolation valves are seized in position. Trap isolation valves should be exercised

regularly to ensure that a plant shut down is not required to change a trap. The trap with an inline

connector and isolation is ideal for this situation.

Steam Traps Types

There are a number of different manufactures and types of traps fitted around the site however all traps

on site fall into two categories.

Process/Heat Exchanger Traps – Which need to be able to modulate to the load condition and also be

able to handle the robust nature of large volumes of steam and condensate at start-up and then operate

at a steady state for the rest of the process. The sizing of these traps is dependent on the load condition.

Line Drain Traps – This type of trap needs to be able to cope with less variable loads but needs to

ensure that condensate will be taken out of the line as it forms to ensure the quality of steam to the

process is good quality and consistent.

Safety Valves

It is important that the vent line on safety valves must be drained to ensure there is no build-up of water

in the vent as this will which will affect the lifting point of the safety valve.



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Tablet Block Fluid bed dryers Heat Exchanger (2x) There is a 3m lift after the heat exchangers which then drops back down to the condensate main below

the heat exchanger to the return main. It is recommended to remove the lift and pipe steam trap

discharge into condensate return at low level.

AHU Unit 5 and AHU Unit 4

The condensate lifts 3m to condensate return unit. These units will operate in a flooded condition.



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Dehumidifer China cota

The condensate lifts 3m to condensate return unit. These units will operate in a flooded condition.



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Chilled Water Plant Room hot water heat exchanger

Lift after heat exchanger GEM trap (Tablet)

Lift of 3m after heat exchanger also new GEM orifice trap fitted.



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Flooded heat exchanger in Liquid Manufacture DI plant room

Lower two traps installed in the incorrect position.



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Boiler 1 and 2 bottom blowdown

At present boiler bottom blowdown is operated 3 times per day and this is done for approx 30s

Though difficult to quantify, this represents a significant loss of energy from the boiler with no advantage.

This is being done as the TDS system is not operational and it is felt this will control the TDS in the

boilers. The bottom blowdown should be done approx 1 per day for no more than 3 seconds.

Boiler Feed Tank Operation

The existing boiler feed tanks were designed for a main hotwell and a cold water makeup tank. However

both are now linked together and operate as one with interlinked connections, the cold water make-up

still enters the smaller tank and the boiler feed is still taken from the hotwell. The water from the

economiser is taken from the hotwell, and is then returned to both tanks via isolation valves.

Also on occasion the condensate overflows from the hotwell, this is due to the large volume of return

from either tablet or penicillin as collection tanks are large. This also has the effect of introducing a large

volume of cool condensate 48°C back to the hot well tank.

The outlet of the feed tank to the boiler is approx 72°C therefore there is also stratification of the hotwell

as the surface temperature is approx 86°C.

The tanks should revert to original operation with cold water makeup tank supplying the boiler

economiser and this being put into the hotwell. The TDS flash should also be directed to the hotwell.

Condensate return should be reviewed (see notes).



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Orifice Steam Traps – blocked or isolated

Many of the line drains are isolated, all steam traps should be checked to ensure the valves prior to and

after the steam traps are fully open.

Typical isolated line drain

There were a number of blocked steam traps on site and are shown in the survey conducted. It would

appear that dirt has caused these traps to fail.



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Dirt found in the steam trap body

The orifice trap is susceptible to dirt within the system due to the small orifice size. It is vital that they be

checked on a regular basis to ensure correct operation.



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All traps on external main were blocked and discharged to ground

Barometric Leg Benzine CRU

The existing overflow is directly off the top side of the tank and allows the flash from the returned

condensate to discharge into the plant room area creating a lot of standing water.

The installation of a barometric leg would resolve this situation.

Benzine CRU Vent/Overflow



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Condensate return tank sizing

The existing condensate return from both Tablet/Penicillin/Benzine pumps directly to the boiler hot well.

Both of these tanks hold a large volume of condensate and the pump ON/OFF band means that a large

volume of condensate can be returned to hotwell creating excess condensate in the hotwell causing it to

overflow. Also as this condensate has been held in the tank for some time the temperature has dropped

which means that the hot well can receive a load of relatively low temperature condensate.

The short term solution is to decrease the ON/OFF band on the pumps which means that they pump less

condensate at a higher temperature back to the hot well.

Tablet CRU

Penicilin CRU



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Temperature control Bin Wash – Pencillin

At present there is no temperature control other than a manual ON/OFF valve. The plant leaves water in

tank boiling for 12 hours per day. It is recommended to fit a simple direct acting temperature control

valve.

Tank ON/OFF valve

Temperature control - tablet block

At present there is no temperature control other than a manual ON/OFF valve. The plant leaves water in

tank boiling for 12 hours per day. It is recommended to fit a simple direct acting temperature control

valve.



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Removal redundant steam traps – in parallel with new traps

Many of the old steam traps have been left in parallel with the more recently installed units. The old traps

should be removed as there appears to be some confusion as to which trap should be operational.

Chilled Water Plant Room hot water heat exchanger remove old FT trap.Penicillin plant, Liquids

Condensate return steam traps piped to drain

Penicillin AHU line drain



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There are a number of steam traps on the site being discharged to drain (see survey) wherever possible

they should be returned to the local CRU.

Piped into normal drain from Dehumidifier coil Penicillin



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10 Complete check list of all verifications done during the audit

Potential optimisation Status Comments

STEAM GENERATION

Steam pressure setting OK 6,5 Bar(g)

Feed water temp. to the boilers Not ok Around 60°C, Steam sparge in hot well and blow

down heat recovery are out of service, see project

3.

Stack temperature in front of

economizer

Not ok 178°C on boiler 1, too high 220°C on boiler 2 due

to limited boiler capacity. See project 4.

Stack temperature after eco. Not ok No economiser on boiler 2, 157° on boiler 1, see

project 2

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 (was carried

out immediately during the audit). See projects 1

and 8.

Boiler sizing OK Boiler 1 can cover site peak load, boiler 2 under

sized.

Boiler blow down rate Not ok About 10%, condensate return rate should be

improved, see project 5.

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

save chemicals not feasible

Feed-water pre-heating Not ok Economizer pipework fitted incorrect, see project

2

Boiler stand-by time and volatility

of steam demand

Not ok Recommended to stop boiler 2, see project 4.

Boiler blow-down recovery Not ok Blow down heat recovery system is piped in

wrong, see project 3.



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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, steam lines

are connected to the bottom of a main line - see

remarks in chapter 9.

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

thermography study was carried out recently

Steam quality Not ok Blocked drain traps should be replaced.

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. See

appendix 3.

Steam traps Not ok See trap survey results in chapter 9

CONDENSATE AND FLASH STEAM RECOVERY

Condensate recovered Not ok Condensate return rate is too low, due to failing

condensate return units (cavitating pumps). See

project 5.

Sizing of condensate return lines OK

Flash steam recovery OK Steam venting is minimal.

Water hammering OK No water hammering was detected.

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

another company.



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11 Recommended complementary studies

11.1 Additional energy-saving optimisations

11.1.1 Heat recovery gas fired chillers

11.1.1.1 Current situation

There are 6 gas fired chillers on site 2xLiquids, 2x Penicillin, 2xTablets. During the audit flue gas

temperatures were measured three times. The average temperatures are printed below:

Liquids Chiller 1 – 185 C

Liquids Chiller 2 – Not operational

Penicillin Chiller 1 – 201 C

Penicillin Chiller 2 – 195 C

Tablet Chiller 1 – 188 C

Tablet Chiller 2 – 193 C

11.1.1.2 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). During the audit we identified

the following potential heat sinks to cool down the chiller flue gasses:



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Liquids: Mez Plant Room hot water loop is available in this area Penicillin: Benzine hot water loop is available close to this area Tablet: Process hot water loop is available in this area

However additional engineering will be required for these optimisations as the time on site did not allow

for a detailed analysis.

11.1.1.3 Savings calculation

Attachment 4.7 shows the chiller heating efficiency calculation based upon 2011 gas consumption and

tuned burners. The total heat output was calculated to be 9736 MWh (111,4 kW average) and the total

gas costs aree RS 19.593.544 (€ 167.897,-). Appendix 4.8 shows the chiller heating efficiency

calculation based upon the same chiller load, where the flue gasses are cooled down to 100°C using

economizers. Compared to appendix 4.7, this would generate an additional 527 MWh per year (60 kW

average) of water heating capacity, which would otherwise have to be heated with steam. Considering

boiler house efficiency of 80% (HHV) this optimisation could reduce the sites gas consumption by 659

MWh or RS 1.113.206,- (€9.539,-) per year, being 5,2% of the gas budget for the chillers.

11.1.1.4 Investments

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

contractors and equipment suppliers.



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11.1.2 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.

11.2 Operational optimisations

11.2.1 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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12 Appendix N°1: Determination of the 2010 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 Efficiency

Net total output from the boiler house (incl. CHP) 751,4 kW 100,0%

Boiler house efficiency on LHV 78,7 %

Boiler house efficiency on HHV 71,0 %

Annual fuel consumption (LHV) 8.361 MWh/year

Annual fuel consumption (HHV) 9.278 MWh/year

Annual CO2 emissions (50 kg/GJ / 180 kg/MWh HHV) 1.670 tons/year

Annual fuel costs 15.669.388 Rs/year

12a. Steam generation and steam costs

Net total steam heat output from the boiler house 751,4 kW 100,0%

Net total steam heat output from the boiler house 6.583 MWh/year

Net dry steam production boiler house 1,069 ton/h = 9366 t/year

Net wet steam production boiler house x=1 1,069 ton/h = 9366 t/year

Annual fuel consumption (LHV) 8.361 MWh/year

Annual fuel consumption (HHV) 9.278 MWh/year

Fuel costs for steam generation 15.669.388 Rs/year 89,2%

Electricity unit costs 10,000 Rs/kWh

Electrical pow er for the boilerhouse 15 kW

Electricity costs 1.314.000 Rs/year 7,5%

Make up w ater unit costs 120,00 Rs/m3

Make up water costs 525.600 Rs/year 3,0%

Costs for chemicals 66000 Rs/year 0,4%

Sew er unit costs 0,00 Rs/m3

Sewer costs 0 Rs/year 0,0%

CO2 unit costs Rs/ton

CO2 Emissions ( 178,3 kg/ton of dry boiler house steam) 1.670 ton/year

CO2 costs 0 Rs/year 0,0%

Total variable steam costs 17.574.988 Rs/year 100%

Total costs steam from boiler house 1.876,49 Rs/ton

Total costs steam from boiler house 2,6699 Rs/kWh

This calculation shows that the total steam budget is RS17.574.988 (€150.600,-) per year and the steam

costs are RS1.877 (€ 16,08) per ton.



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13 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.

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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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

Ta = supply air temperature



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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.

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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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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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%

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

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



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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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14 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.

14.2 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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14.2.1 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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14.2.2 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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14.2.3 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.

14.2.4 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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14.2.5 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.

14.2.6 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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15 Appendix N°4: Boiler house simulations and chiller calculations

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


with tuned burners and corrected economizer


with tuned burners, corrected economizer and blow down heat recovery


with tuned burners, corrected economizer and blow down heat recovery and boiler 2

100% stand-by

Appendix 4.6: Chiller heating efficiency calculation based upon 2011 gas consumption


with tuned burners


with tuned burners and flue gas heat recovery

2

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B C D E F G H I J K L M N O P Q R S T U V W X Y Z

BOILER HOUSE SIMULATION SI BOILER 1 BOILER 2 BOILER 3 BOILER 4 BOILER 5 CHP BOILERHOUSECleaver Brooks Stone Danks

Boiler operating hours (incl. hot stand-by hours) 8.760 hours/year 8.760 hours/year 8.760 hours/year 8.760 hours/year 8.760 hours/year CHP operating hours 8.760 hours/year Boiler house operating hours 8.760 hours/year

1. Fuel heat input %LHV %LHV %LHV %LHV %LHV 1. Fuel heat input % LHV % HHV 8. Steam consumption deaerator % LHV

Fuel type: 0 Custom gas %HHV 0 Custom gas %HHV 0 Custom gas %HHV 0 Custom gas %HHV 0 Custom gas %HHV Fuel type: 0 Custom gas Measured make up water flow 0,50 m3/h

Fuel consumption during operating hours 82,2 Nm3/h 27,8 Nm3/h 0,0 Nm3/h 0,0 Nm3/h 0,0 Nm3/h Fuel consumption during operating hours 0,0 Nm3/h Ratio DA feed water / Boiler feed water 100% Bal.error: 0%

Boiler capacity 7,8 ton/h (=5,4MW) 2,0 ton/h (=1,4MW) 10,0 ton/h (=0MW) 10,0 ton/h (=0MW) 10,0 ton/h (=0MW) DA feed water flow 1,19 m3/h

Specific weight of the fuel 0,79 kg/Nm3 0,79 kg/Nm3 0,79 kg/Nm3 0,79 kg/Nm3 0,79 kg/Nm3 Specific weight of the fuel 0,79 kg/Nm3 Conductivity make up water * µs/cm

Fuel consumption 64,7 kg/h 21,9 kg/h 0,0 kg/h 0,0 kg/h 0,0 kg/h Fuel consumption 0,0 kg/h Conductivity condensate * µs/cm

Lower heating value (LHV) 39704 kJ/kg (=31230 kJ/Nm3) 39704 kJ/kg (=31230 kJ/Nm3) 39704 kJ/kg (=31230 kJ/Nm3) 39704 kJ/kg (=31230 kJ/Nm3) 39704 kJ/kg (=31230 kJ/Nm3) Lower heating value (LHV) 39704 kJ/kg (=31230 kJ/Nm3) Condensate return % 53,2 %

Higher heating value (HHV) 44057 kJ/kg (=34654 kJ/Nm3) 44057 kJ/kg (=34654 kJ/Nm3) 44057 kJ/kg (=34654 kJ/Nm3) 44057 kJ/kg (=34654 kJ/Nm3) 44057 kJ/kg (=34654 kJ/Nm3) Higher heating value (HHV) 44057 kJ/kg (=34654 kJ/Nm3) Calculated make up water flow from conductivity 0,00 m3/h

Fuel unit costs 1688,95718 Rs/MWh HHV (= 16,26 Rs/Nm3) 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3) 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3) 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3Fuel unit costs 1688,95718 Rs/MWh HHV (= 16,26 Rs/Nm3) Temperature return condensate 89,0 °C

Fuel heat input (LHV) 713,2 kW 100% 241,2 kW 100% 0,0 kW 100% 0,0 kW 100% 0,0 kW 100% Fuel heat input (LHV) 0,0 kW 100% Avg temperature deaerator feed water 59,9 °C

Fuel heat input (HHV) 791,4 kW 267,6 kW 0,0 kW 0,0 kW 0,0 kW Fuel heat input (HHV) 0,0 kW 100% Temperature deaerator 59,9 °C

Steam pressure 6,5 Bar(g) / 167,7°C sat. 6,5 Bar(g) / 167,7°C sat. 10,0 Bar(g) / 184,1°C sat. 10,0 Bar(g) / 184,1°C sat. 10,0 Bar(g) / 184,1°C sat. 1a. Electrical power generation Heat required for heating deaerator 0,00 kW

Steam temperature 167,7 °C / 0°C superheated 167,7 °C / 0°C superheated 184,1 °C / 0°C superheated 184,1 °C / 0°C superheated 184,1 °C / 0°C superheated Electricity generated 0 kW Maximum deaerator capacity 0,0 ton/h

Enthalpy steam 2766 kJ/kg 2766 kJ/kg 0 kJ/kg 0 kJ/kg 0 kJ/kg Alternator efficiency 100 % Vent loss deaerator (0,05%) 0,000 ton/h

Temperature feed water to the boiler/eco 59,9 °C 59,9 °C 59,9 °C 59,9 °C 59,9 °C Heat used for generating electricity 0,0 kW 0,0% 0,0% Total steam consumption for deaerator 0,000 ton/h

Enthalpy feed water 250 kJ/kg 250 kJ/kg 0 kJ/kg 0 kJ/kg 0 kJ/kg 1b. Hot water generation (engine cooling water) Total heat consumption for deaerator 0,0 kW 0,0%

Heat added to feedwater 2515 kJ/kg 2515 kJ/kg 0 kJ/kg 0 kJ/kg 0 kJ/kg Inlet water temperature 65,0 °C 9.1 Blow down flash recovery to deaerator? n y/n

Max. theoretical steam production 1,02 ton/h (=0,8 ton/h actual) 0,35 ton/h (=0,3 ton/h actual) 0,00 ton/h (=0 ton/h actual) 0,00 ton/h (=0 ton/h actual) 0,00 ton/h (=0 ton/h actual) Outlet water temperature 85,0 °C Deaerator pressure 0,0 Bar(g)

2. Thermal losses Water flow 0,00 m3/h Flash flow 0,018 ton/h

Temperature flue gas after boiler 178,0 °C 220,0 °C 200,0 °C 200,0 °C 200,0 °C Heat used for hot water generation 0,0 kW 0,0% 0,0% Blow down flash recovery 0,0 kW 0,0%

Temperature outside air 30,0 °C 30,0 °C 30,0 °C 30,0 °C 30,0 °C 1b. Hot water generation (engine lubricant) 9.2 BDHR sensible heat used to preheat make-up water? n y/n

Excess air 254,1 % 76,3 % 0,0 % 0,0 % 0,0 % Inlet water temperature 65,0 °C Make up water outlet temperature 20,0 °C

Oxygen % in flue gas (Dry volume) 15,50 % 9,60 % 0,00 % 0,00 % 0,00 % Outlet water temperature 85,0 °C Blow down water outlet temperature 59,9 °C

2.1 Losses in dry flue gas Water flow 0,00 m3/h Theoretical heat recovery 0,00 kW

Specific flue gas flow (dry) 36,23 Nm3/kg fuel 17,48 Nm3/kg fuel 9,43 Nm3/kg fuel 9,43 Nm3/kg fuel 9,43 Nm3/kg fuel Heat used for hot water generation 0,0 kW 0,0% 0,0% Heat transfer efficiency 80%

Total flue gas flow (dry) 2343,0 Nm3/h 382,2 Nm3/h 0,0 Nm3/h 0,0 Nm3/h 0,0 Nm3/h 1c. Engine radiation and convection losses Blow down sensible heat recovery 0,0 kW 0,0%

Total flue gas flow (wet) 2518,6 Nm3/h 437,1 Nm3/h 0,0 Nm3/h 0,0 Nm3/h 0,0 Nm3/h Engine radiation losses etc. 0,0 kW 0,0% 0,0% 9.3 HE Feed water/ Make-up water (Pinch) n y/n

Specific heat flue gas (Dry volume) 1,34 kJ/Nm³.K -16,3% 1,36 kJ/Nm³.K -10,2% 1,39 kJ/Nm³.K 0,0% 1,39 kJ/Nm³.K 0,0% 1,39 kJ/Nm³.K 0,0% 2. Steam generation Feed water temperature inlet 59,9 °C

Energy loss in dry flue gas 128,83 kW -18,1% 27,43 kW -11,4% 0,00 kW 0,0% 0,00 kW 0,0% 0,00 kW 0,0% Heat left in stack for steam generation (LHV) 0,0 kW 0,0% 0,0% Feed water temperature outlet 59,9 °C

2.2 Losses due to moisture in fuel Steam pressure 10,0 Bar(g) / 184,1°C sat. Make-up water temperature inlet 20,0 °C

Moisture in fuel 0,000 kg/kg fuel 0,000 kg/kg fuel 0,000 kg/kg fuel 0,000 kg/kg fuel 0,000 kg/kg fuel Enthalpy steam 2781 kJ/kg Make up water temperature outlet 20,0 °C

Specific heat water in fuel 4,18 kJ/kg.K 4,18 kJ/kg.K 4,18 kJ/kg.K 4,18 kJ/kg.K 4,18 kJ/kg.K Temperature feed water to the boiler/eco 59,9 °C Heat transfer efficiency 80%

Specific heat water in flue gas 1,83 kJ/kg.K 1,84 kJ/kg.K 1,83 kJ/kg.K 1,83 kJ/kg.K 1,83 kJ/kg.K Enthalpy feed water 250 kJ/kg Heat transferred 0,0 kW

Energy losses due to moisture in fuel 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0% Latent heat of the steam 2530 kJ/kg 10. Radiation losses in the boiler house

Energy losses due to moisture in fuel 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0% Max. theoretical steam production 0,00 ton/h (=0 ton/h actual) Radiation losses in the boiler house 0,00 kW 0,0%

2.3 Losses due to H2 of Fuel 2.1 Combustion losses (energy in stack after boiler) 11. Boiler flue gas heat recovery (not heating MUW/fw) n y/n

Moisture in flue gas 1,785 kg/kg fuel 1,785 kg/kg fuel 1,785 kg/kg fuel 1,785 kg/kg fuel 1,785 kg/kg fuel Temperature stack after boiler 200,0 °C Temperature stack after heat recovery 40,0 °C

Specific heat water in fuel 4,18 kJ/kg.K 4,18 kJ/kg.K 4,18 kJ/kg.K 4,18 kJ/kg.K 4,18 kJ/kg.K Temperature outside air 30,0 °C Heat recovered (sensible heat) 139,4 kW

Specific heat water in stacks 1,83 kJ/kg.K 1,84 kJ/kg.K 1,83 kJ/kg.K 1,83 kJ/kg.K 1,83 kJ/kg.K Excess air 0,00 % Stack water vapour content in front of h.r. 2,66 Nm3 H20 /kg fuel

Energy losses due to H2 in fuel 86,6 kW on HHV -10,9% 30,1 kW on HHV -11,3% 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0% Oxygen % flue gas (Dry volume) 0,00 % Saturation pressure water vapour in stack 0,07 Bar(a)

Energy losses due to H2 in fuel 6,4 kW on LHV -0,9% 3,0 kW on LHV -1,3% 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0% Specific Stack flow (dry) 9,43 Nm3/kg fuel Maximum water vapour content after h.r. 2,49 Nm3/kg fuel

2.4 Losses due to moisture in combustion air Total stack flow (dry) 0,0 Nm3/h Condensed in heat recovery 12,2 kg/h

Moisture in ambient air 0,007 kg water/kg air 0,007 kg water/kg air 0,007 kg water/kg air 0,007 kg water/kg air 0,007 kg water/kg air Total stack flow (wet) 0,0 Nm3/h Heat recovered (latent heat) 8,1 kW

Moisture in ambient air 0,339 kg water/ kg fuel 0,336 kg water/ kg fuel 0,096 kg water/ kg fuel 0,096 kg water/ kg fuel 0,096 kg water/ kg fuel Specific heat stack (Dry volume) 1,39 kJ/Nm³.K Heat transfer efficiency 80 %

Specific heat water in flue gas 1,83 kJ/kg.K -0,2% 1,84 kJ/kg.K -0,3% 1,83 kJ/kg.K 0,0% 1,83 kJ/kg.K 0,0% 1,83 kJ/kg.K 0,0% Energy loss in dry stacks 0,0 kW 0,0% 0,0% Total stack heat recovery after economizer 0,0 kW 0,0%

Energy losses due to moisture in air 1,6 kW -0,2% 0,7 kW -0,3% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% Energy losses due to moisture in fuel 0,0 kW on LHV 0,0% 0,0% 12. Overall Boiler House Efficiency

3. Radiation losses Energy losses due to H2 in fuel 0,0 kW on LHV 0,0% 0,0% Net total output from the boiler house (incl. CHP) 751,4 kW 100,0%

Boiler Average Load 13,09 % 17,26 % 0,00 % 0,00 % 0,00 % Energy losses due to moisture in air 0,0 kW 0,0% 0,0% Boiler house efficiency on LHV 78,7 %

Water Tube Radiation Losses (as per ABMA) 7,50 % - % 0,00 % 0,00 % 0,00 % 3 Economizer Boiler house efficiency on HHV 71,0 %

Fire Tube Radiation Losses (Manufacturer Data) - % - % 0,00 % 0,00 % 0,00 % Temperature flue gas after economizer 200,0 °C Annual fuel consumption (LHV) 8.361 MWh/year

Radiation losses considered in calc. 4,58 % -4,1% 3,48 % -3,1% - % 0,0% - % 0,0% - % 0,0% Economizer inlet water temperature 59,9 °C Annual fuel consumption (HHV) 9.278 MWh/year

Radiation losses 32,7 kW -4,6% 8,4 kW -3,5% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% Economizer outlet water temperature 0,00 °C Annual CO2 emissions (50 kg/GJ / 180 kg/MWh HHV) 1.670 tons/year

4. Cycling losses (burner starts) Heat recovered (sensible heat) 0,00 kW 0,0% 0,0% Annual fuel costs 15.669.388 Rs/year

Hot standby time during operating hours 0 % 0 % 0 % 0 % 0 % 4 Network heater topping up CHP hot water loop temperature 12a. Steam generation and steam costs

Min. burner capacity 0 kW 0 kW 0 kW 0 kW 0 kW Temperature flue gas after network heater 200,0 °C Net total steam heat output from the boiler house 751,4 kW 100,0%

Boiler water volume 0,00 m3 0,00 m3 0,00 m3 0,00 m3 0,00 m3 Heat recovered (sensible heat) 0,0 kW Net total steam heat output from the boiler house 6.583 MWh/year

Burner on/off pressure differential 0,00 Bar(g) 0,00 Bar(g) 0,00 Bar(g) 0,00 Bar(g) 0,00 Bar(g) Flue gas water vapour content in front of h.r. 2,26 Nm3 H20 /kg fuel Net dry steam production boiler house 1,069 ton/h = 9366 t/year

Purge cycle time 0 sec 0 sec 0 sec 0 sec 0 sec Saturation pressure water vapour in stack 0,00 Bar(a) Net wet steam production boiler house x=1 1,069 ton/h = 9366 t/year

Minimum nr. burner starts 0,00 per hour 0,0% 0,00 per hour 0,0% 0,00 per hour 0,0% 0,00 per hour 0,0% 0,00 per hour 0,0% Maximum water vapour content after h.r. 0,00 Nm3 H20 /kg fuel Annual fuel consumption (LHV) 8.361 MWh/year

Heat loss purging air 0,00 kW 0,0% 0,00 kW 0,0% 0,00 kW 0,0% 0,00 kW 0,0% 0,00 kW 0,0% Condensed in heat recovery 0,0 Nm3/h Annual fuel consumption (HHV) 9.278 MWh/year

5. Heat gains Condensed in heat recovery 0,0 kg/h Fuel costs for steam generation 15.669.388 Rs/year 89,2%

5.1 Economizer (non condensing) Heat recovered (latent heat) 0,0 kW Electricity unit costs 10,000 Rs/kWh

Temperature stack after economizer 157,0 °C 220,0 °C 200,0 °C 200,0 °C 200,0 °C Heat transfer efficiency 100 % Electrical power for the boilerhouse 15 kW

Economizer inlet water temperature 59,9 °C 59,9 °C 59,9 °C 59,9 °C 59,9 °C Water flow 0,00 m3/h Electricity costs 1.314.000 Rs/year 7,5%

Economizer outlet water temperature 79,9 °C 59,9 °C 59,9 °C 59,9 °C 59,9 °C Network heater inlet water temperature 85,0 °C Make up water unit costs 120,00 Rs/m3

Heat transfer efficiency 100% 2,6% 100% 0,0% 100% 0,0% 100% 0,0% 100% 0,0% Network heater outlet water temperature 0,0 °C Make up water costs 525.600 Rs/year 3,0%

Heat recovered by economizer 20,3 kW 2,8% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% Total flue gas heat rec. after network heater 0,0 kW 0,0% 0,0% Costs for chemicals 66000 Rs/year 0,4%

5.2 Air preheating from external source (Top of boiler house) 5 Boiler radiation losses Sewer unit costs 0,00 Rs/m3

Combustion air required 37,69 Nm3/kg fuel 37,69 Nm3/kg fuel 37,69 Nm3/kg fuel 37,69 Nm3/kg fuel 37,69 Nm3/kg fuel Boiler capacity 10,0 ton/h (=7MW) Sewer costs 0 Rs/year 0,0%

Total combustion air flow 2437,3 Nm3/h 824,2 Nm3/h 0,0 Nm3/h 0,0 Nm3/h 0,0 Nm3/h Load 0 % CO2 unit costs Rs/ton

Normal combustion air temperature 30,0 °C 30,0 °C 30,0 °C 30,0 °C 30,0 °C Radiation losses at full load 0,6 % CO2 Emissions ( 178,3 kg/ton of dry boiler house steam) 1.670 ton/year

Preheated combustion air temperature 30,0 °C 0,0% 30,0 °C 0,0% 30,0 °C 0,0% 30,0 °C 0,0% 30,0 °C 0,0% Radiation losses 0,0 kW 0,0% 0,0% CO2 costs 0 Rs/year 0,0%

Heat recovered by air preheating 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% 6. Blow down Total variable steam costs 17.574.988 Rs/year 100%

5.3 Air preheat system (closed loop heat recovery from stack after eco) Conductivity boiler feed water 280,0 µs/cm Total costs steam from boiler house 1.876,49 Rs/ton

Temperature stack after air preheater 157,0 °C 220,0 °C 200,0 °C 200,0 °C 200,0 °C Conductivity boiler water 3300,0 µs/cm Total costs steam from boiler house 2,6699 Rs/kWh

Preheated combustion air temperature 30,0 °C 30,0 °C 30,0 °C 30,0 °C 30,0 °C Boiler water lost by blow down + carry over 9,3 % of steam output (11,8cycles) 12b. Electricity generation and electricity costs

Energy taken from the stack 0,0 kW 0,0 kW 0,0 kW 0,0 kW 0,0 kW Boiler feed water flow 0,000 ton/h Net total electricity power output from the boiler house 0,0 kW 0,0%

Heat transfer efficiency 100% 0,0% 100% 0,0% 100% 0,0% 100% 0,0% 100% 0,0% Boiler water lost by blow down + carry over 0,000 ton/h Net total electricity energy output from the boiler house 0 MWh/year

Heat recovered by air preheat system 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% Ratio of blow down vs. carry over 100% blowdown Annual Fuel costs for electricity generation 0 Rs/year 0,0%

6. Blow down Carry over 0,000 ton/h Annual fuel consumption (LHV) 0 MWh/year

Conductivity boiler feed water 280,0 µs/cm 280,0 µs/cm 280,0 µs/cm 280,0 µs/cm 280,0 µs/cm X-value of the steam from the boiler 0,000 Annual fuel consumption (HHV) 0 MWh/year

Conductivity boiler water 3000,0 µs/cm 3000,0 µs/cm 3300,0 µs/cm 3300,0 µs/cm 3300,0 µs/cm Blow down flow remaining 0,000 ton/h Annual CO2 emisions 0 ton/year

Boiler water lost by blow down + carry over 10,3 % of steam output (10,7cycles) 10,3 % of steam output (10,7cycles) 9,3 % of steam output (11,8cycles) 9,3 % of steam output (11,8cycles) 9,3 % of steam output (11,8cycles) Enthalpy blow down water 781 kJ/kg CO2 costs 0 Rs/year 0,0%

Boiler feed water flow 0,874 ton/h 0,312 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Temperature make up water 20,0 °C Total variable electricity costs 0 Rs/year 0%

Boiler water lost by blow down + carry over 0,082 ton/h 0,029 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Enthalpy make up water 83,6 kJ/kg Total costs electricity from the boiler house 0,0000 Rs/kWh

Ratio of blow down vs. carry over 100% blowdown 100% blowdown 100% blowdown 100% blowdown 100% blowdown Total Blow Down losses (Boiler + Deaerator) 0,0 kW 0,0% 0,0% 12c. Hot water generation and hot water heating costs

Carry over 0,000 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Blow down losses compensated by boiler only 0,0 kW 0,0% 0,0% Net total hot water heat output from the boiler house 0,0 kW 0,0%

X-value of the steam from the boiler 1,000 1,000 0,000 0,000 0,000 7. CHP Efficiency and Fuel Costs Net total hot water energy output from the boiler house 0 MWh/year

Blow down flow remaining 0,082 ton/h 0,029 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h CHP efficiency on LHV 0,00 % 0,0% Annual Fuel costs for hot water generation 0 Rs/year 0,0%

Enthalpy blow down water 709 kJ/kg 709 kJ/kg 781 kJ/kg 781 kJ/kg 781 kJ/kg CHP efficiency on HHV 0,00 % 0,0% Annual fuel consumption (LHV) 0 MWh/year

Temperature make up water 20,0 °C 20,0 °C 20,0 °C 20,0 °C 20,0 °C CHP output (Steam, Hot Water, Electricity) 0,0 kW ( 0 MWh) 100,0% Annual fuel consumption (HHV) 0 MWh/year

Enthalpy make up water 83,6 kJ/kg 83,6 kJ/kg 83,6 kJ/kg 83,6 kJ/kg 83,6 kJ/kg Net Electrical power output 0,0 kW ( 0 MWh) 0,0% Annual CO2 emissions 0 ton/year

Total Blow Down losses 14,2 kW -1,3% 5,1 kW -1,4% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% Net Hot Water heat output 0,0 kW ( 0 MWh) 0,0% CO2 costs 0 Rs/year 0,0%

Blow down losses compensated by boiler only 10,4 kW -1,5% 3,7 kW -1,5% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% Net Steam heat output 0,0 kW ( 0 MWh) 0,0% Total variable hot water heating costs 0 Rs/year 0%

7. Boiler Efficiency and Fuel Costs Total fuel costs 0 Rs/year Total costs hot water heating from the boiler house 0,0000 Rs/kWh

Net heat output in steam from the boiler (LHV) 553,5 kW ( 4849 MWh) 197,9 kW ( 1734 MWh) 0,0 kW ( 0 MWh) 0,0 kW ( 0 MWh) 0,0 kW ( 0 MWh) Net dry steam production boiler (x=1) 0,000 ton/h Boilerhouse Simulation 8.2 SINet dry steam production boiler (x=1) 0,792 ton/h = 6940 t/year 0,283 ton/h = 2482 t/year 0,000 ton/h = 0 t/year 0,000 ton/h = 0 t/year 0,000 ton/h = 0 t/year Net wet steam production boiler 0,000 ton/h Attachment 4.1Net wet steam production boiler 0,792 ton/h 0,283 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Project name : GSK Karachi PK, Site F268Boiler efficiency on LHV 77,61 % 82,06 % 0,00 % 0,00 % 0,00 % Fuel costs / ton dry steam 0,00 Rs/ton Project nr. :Boiler efficiency on HHV 69,94 % 73,95 % 0,00 % 0,00 % 0,00 % CHP steam rejected (excess produced by the CHP) 0 kW ( 0 MWh) Date: 15-0502012Annual Fuel costs 11.709.608 Rs/year 3.959.779 Rs/year 0 Rs/year 0 Rs/year 0 Rs/year CHP hot water rejected (excess produced by CHP) 0 kW ( 0 MWh) Comment: Base line calculation 2011 data.Fuel costs / ton dry steam 1687,24 Rs/ton 1595,61 Rs/ton 0,00 Rs/ton 0,00 Rs/ton 0,00 Rs/ton CHP useful output considering rejected heat 0,0 kW ( 0 MWh) 0,0% 0,0%

©2011 Armstrong International, Inc This Spreadsheet contains Armstrong Proprietary Information contain trade secrets, as well as privileged information, and/or proprietary work product of Armstrong International, Inc. (“Armstrong”). In consideration of use of this spreadsheet and the information and data herein, User agrees that it will use this document and the information contained herein only for internal use and only for the purpose of evaluating a business transaction with Armstrong. User agrees that it will not disclose this Information or any part thereof to any third parties and Recipient may only disclose this document to those employees involved in the evaluation of a business transaction with Armstrong, on an as need basis. User may make only those copies needed for such internal review. Upon conclusion of business discussions, this document and all copies shall be returned to Armstrong upon its or their request.

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Radiation losses 32,7 kW -5,1% 8,4 kW -3,6% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% Economizer outlet water temperature 0,00 °C Annual CO2 emissions (49,7 kg/GJ / 179 kg/MWh HHV) 1.510 tons/year














Heat transfer efficiency 100% -1,3% 100% 0,0% 100% 0,0% 100% 0,0% 100% 0,0% Network heater outlet water temperature 0,0 °C Make up water costs 525.600 Rs/year 3,3%

Heat recovered by economizer -9,1 kW -1,4% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% Total flue gas heat rec. after network heater 0,0 kW 0,0% 0,0% Costs for chemicals 66000 Rs/year 0,4%





























Net heat output in steam from the boiler (LHV) 553,5 kW ( 4849 MWh) 197,9 kW ( 1734 MWh) 0,0 kW ( 0 MWh) 0,0 kW ( 0 MWh) 0,0 kW ( 0 MWh) Net dry steam production boiler (x=1) 0,000 ton/h Boilerhouse Simulation 8.2 SINet dry steam production boiler (x=1) 0,792 ton/h = 6940 t/year 0,283 ton/h = 2482 t/year 0,000 ton/h = 0 t/year 0,000 ton/h = 0 t/year 0,000 ton/h = 0 t/year Net wet steam production boiler 0,000 ton/h Attachment 4.2Net wet steam production boiler 0,792 ton/h 0,283 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Project name : GSK Karachi PK, Site F268Boiler efficiency on LHV 87,04 % 85,28 % 0,00 % 0,00 % 0,00 % Fuel costs / ton dry steam 0,00 Rs/ton Project nr. :Boiler efficiency on HHV 78,44 % 76,85 % 0,00 % 0,00 % 0,00 % CHP steam rejected (excess produced by the CHP) 0 kW ( 0 MWh) Date: 15-0502012Annual Fuel costs 10.440.015 Rs/year 3.810.509 Rs/year 0 Rs/year 0 Rs/year 0 Rs/year CHP hot water rejected (excess produced by CHP) 0 kW ( 0 MWh) Comment: Optimized boiler house 2011 production:Fuel costs / ton dry steam 1504,31 Rs/ton 1535,46 Rs/ton 0,00 Rs/ton 0,00 Rs/ton 0,00 Rs/ton CHP useful output considering rejected heat 0,0 kW ( 0 MWh) 0,0% 0,0% Burners tuned, Economizer piping fixed,

Blow down heat recovery re-installed Boiler 2 100% in standby


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Net heat output in steam from the boiler (LHV) 553,5 kW ( 4849 MWh) 197,9 kW ( 1734 MWh) 0,0 kW ( 0 MWh) 0,0 kW ( 0 MWh) 0,0 kW ( 0 MWh) Net dry steam production boiler (x=1) 0,000 ton/h Boilerhouse Simulation 8.2 SINet dry steam production boiler (x=1) 0,792 ton/h = 6940 t/year 0,283 ton/h = 2482 t/year 0,000 ton/h = 0 t/year 0,000 ton/h = 0 t/year 0,000 ton/h = 0 t/year Net wet steam production boiler 0,000 ton/h Attachment 4.2Net wet steam production boiler 0,792 ton/h 0,283 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Project name : GSK Karachi PK, Site F268Boiler efficiency on LHV 88,38 % 85,28 % 0,00 % 0,00 % 0,00 % Fuel costs / ton dry steam 0,00 Rs/ton Project nr. :Boiler efficiency on HHV 79,65 % 76,85 % 0,00 % 0,00 % 0,00 % CHP steam rejected (excess produced by the CHP) 0 kW ( 0 MWh) Date: 15-0502012Annual Fuel costs 10.282.325 Rs/year 3.810.509 Rs/year 0 Rs/year 0 Rs/year 0 Rs/year CHP hot water rejected (excess produced by CHP) 0 kW ( 0 MWh) Comment: Optimized boiler house 2011 production:Fuel costs / ton dry steam 1481,59 Rs/ton 1535,46 Rs/ton 0,00 Rs/ton 0,00 Rs/ton 0,00 Rs/ton CHP useful output considering rejected heat 0,0 kW ( 0 MWh) 0,0% 0,0% Burners tuned, Economizer piping fixed,©2011 Armstrong International, Inc This Spreadsheet contains Armstrong Proprietary Information contain trade secrets, as well as privileged information, and/or proprietary work product of Armstrong International, Inc. (“Armstrong”). In consideration of use of this spreadsheet and the information and data herein, User agrees that it will use this document and the information contained herein only for internal use and only for the purpose of evaluating a business transaction with Armstrong. User agrees that it will not disclose this Information or any part thereof to any third parties and Recipient may only disclose this document to those employees involved in the evaluation of a business transaction with Armstrong, on an as need basis. User may make only those copies needed for such internal review. Upon conclusion of business discussions, this document and all copies shall be returned to Armstrong upon its or their request.

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Enthalpy feed water 285 kJ/kg 285 kJ/kg 0 kJ/kg 0 kJ/kg 0 kJ/kg 1b. Hot water generation (engine cooling water) Total heat consumption for deaerator 11,3 kW -1,3%

Heat added to feedwater 2481 kJ/kg 2481 kJ/kg 0 kJ/kg 0 kJ/kg 0 kJ/kg Inlet water temperature 65,0 °C 9.1 Blow down flash recovery to deaerator? y y/n




















































Combustion air required 13,66 Nm3/kg fuel 13,66 Nm3/kg fuel 13,66 Nm3/kg fuel 13,66 Nm3/kg fuel 13,66 Nm3/kg fuel Boiler capacity 10,0 ton/h (=6,9MW) Sewer costs 0 Rs/year 0,0%


Normal combustion air temperature 30,0 °C 30,0 °C 30,0 °C 30,0 °C 30,0 °C Radiation losses at full load 0,6 % CO2 Emissions ( 157 kg/ton of dry boiler house steam) 1.491 ton/year

























Net heat output in steam from the boiler (LHV) 553,2 kW ( 4846 MWh) 198,3 kW ( 1737 MWh) 0,0 kW ( 0 MWh) 0,0 kW ( 0 MWh) 0,0 kW ( 0 MWh) Net dry steam production boiler (x=1) 0,000 ton/h Boilerhouse Simulation 8.2 SINet dry steam production boiler (x=1) 0,803 ton/h = 7032 t/year 0,288 ton/h = 2520 t/year 0,000 ton/h = 0 t/year 0,000 ton/h = 0 t/year 0,000 ton/h = 0 t/year Net wet steam production boiler 0,000 ton/h Attachment 4.4Net wet steam production boiler 0,803 ton/h 0,288 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Project name : GSK Karachi PK, Site F268Boiler efficiency on LHV 88,54 % 85,42 % 0,00 % 0,00 % 0,00 % Fuel costs / ton dry steam 0,00 Rs/ton Project nr. :Boiler efficiency on HHV 79,79 % 76,98 % 0,00 % 0,00 % 0,00 % CHP steam rejected (excess produced by the CHP) 0 kW ( 0 MWh) Date: 15-0502012Annual Fuel costs 10.257.594 Rs/year 3.810.509 Rs/year 0 Rs/year 0 Rs/year 0 Rs/year CHP hot water rejected (excess produced by CHP) 0 kW ( 0 MWh) Comment: Optimized boiler house 2011 production:Fuel costs / ton dry steam 1458,72 Rs/ton 1511,89 Rs/ton 0,00 Rs/ton 0,00 Rs/ton 0,00 Rs/ton CHP useful output considering rejected heat 0,0 kW ( 0 MWh) 0,0% 0,0% Burners tuned, Economizer piping fixed,

Blow down heat recovery re-installed©2011 Armstrong International, Inc This Spreadsheet contains Armstrong Proprietary Information contain trade secrets, as well as privileged information, and/or proprietary work product of Armstrong International, Inc. (“Armstrong”). In consideration of use of this spreadsheet and the information and data herein, User agrees that it will use this document and the information contained herein only for internal use and only for the purpose of evaluating a business transaction with Armstrong. User agrees that it will not disclose this Information or any part thereof to any third parties and Recipient may only disclose this document to those employees involved in the evaluation of a business transaction with Armstrong, on an as need basis. User may make only those copies needed for such internal review. Upon conclusion of business discussions, this document and all copies shall be returned to Armstrong upon its or their request.

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Enthalpy feed water 285 kJ/kg 285 kJ/kg 0 kJ/kg 0 kJ/kg 0 kJ/kg 1b. Hot water generation (engine cooling water) Total heat consumption for deaerator 11,3 kW -1,3%

Heat added to feedwater 2481 kJ/kg 2481 kJ/kg 0 kJ/kg 0 kJ/kg 0 kJ/kg Inlet water temperature 65,0 °C 9.1 Blow down flash recovery to deaerator? y y/n

Max. theoretical steam production 1,21 ton/h (=1,1 ton/h actual) 0,01 ton/h (=0 ton/h actual) 0,00 ton/h (=0 ton/h actual) 0,00 ton/h (=0 ton/h actual) 0,00 ton/h (=0 ton/h actual) Outlet water temperature 85,0 °C Deaerator pressure 0,0 Bar(g)



















































Combustion air required 13,66 Nm3/kg fuel 13,66 Nm3/kg fuel 13,66 Nm3/kg fuel 13,66 Nm3/kg fuel 13,66 Nm3/kg fuel Boiler capacity 10,0 ton/h (=6,9MW) Sewer costs 0 Rs/year 0,0%


Normal combustion air temperature 30,0 °C 30,0 °C 30,0 °C 30,0 °C 30,0 °C Radiation losses at full load 0,6 % CO2 Emissions ( 155 kg/ton of dry boiler house steam) 1.471 ton/year






















Total Blow Down losses 19,5 kW -1,4% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% Net Hot Water heat output 0,0 kW ( 0 MWh) 0,0% CO2 costs 0 Rs/year 0,0%

Blow down losses compensated by boiler only 13,2 kW -1,6% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% Net Steam heat output 0,0 kW ( 0 MWh) 0,0% Total variable hot water heating costs 0 Rs/year 0%


Net heat output in steam from the boiler (LHV) 751,3 kW ( 6582 MWh) 0,1 kW ( 1 MWh) 0,0 kW ( 0 MWh) 0,0 kW ( 0 MWh) 0,0 kW ( 0 MWh) Net dry steam production boiler (x=1) 0,000 ton/h Boilerhouse Simulation 8.2 SINet dry steam production boiler (x=1) 1,090 ton/h = 9551 t/year 0,000 ton/h = 1 t/year 0,000 ton/h = 0 t/year 0,000 ton/h = 0 t/year 0,000 ton/h = 0 t/year Net wet steam production boiler 0,000 ton/h Attachment 4.5Net wet steam production boiler 1,090 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Project name : GSK Karachi PK, Site F268Boiler efficiency on LHV 89,82 % 1,24 % 0,00 % 0,00 % 0,00 % Fuel costs / ton dry steam 0,00 Rs/ton Project nr. :Boiler efficiency on HHV 80,95 % 1,12 % 0,00 % 0,00 % 0,00 % CHP steam rejected (excess produced by the CHP) 0 kW ( 0 MWh) Date: 15-0502012Annual Fuel costs 13.732.886 Rs/year 152.149 Rs/year 0 Rs/year 0 Rs/year 0 Rs/year CHP hot water rejected (excess produced by CHP) 0 kW ( 0 MWh) Comment: Optimized boiler house 2011 production:Fuel costs / ton dry steam 1437,87 Rs/ton 104268,86 Rs/ton 0,00 Rs/ton 0,00 Rs/ton 0,00 Rs/ton CHP useful output considering rejected heat 0,0 kW ( 0 MWh) 0,0% 0,0% Burners tuned, Economizer piping fixed,

Blow down heat recovery re-installed Boiler 2 100% in standby


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B C D E F G H I J K L M N O P Q

Chiller heating efficiency calculation Liquids Penicillin Penincillin Tablet TabletAttachment 4.6, Base line 2011 Chiller 1 Chiller 1 Chiller 2 Chiller 1 Chiller 2Chiller operating hours (incl. hot stand-by hours) 8.760 hours/year 8.760 hours/year 8.760 hours/year 8.760 hours/year 8.760 hours/year

1. Fuel heat input %LHV %LHV %LHV %LHV %LHV

Fuel type: 0 Custom gas %HHV 0 Custom gas %HHV 0 Custom gas %HHV 0 Custom gas %HHV 0 Custom gas %HHV

Fuel consumption during operating hours 43,9 Nm3/h 34,8 Nm3/h 32,3 Nm3/h 23,7 Nm3/h 14,0 Nm3/h

Specific weight of the fuel 0,79 kg/Nm3 0,79 kg/Nm3 0,79 kg/Nm3 0,79 kg/Nm3 0,79 kg/Nm3

Fuel consumption 34,5 kg/h 27,4 kg/h 25,4 kg/h 18,7 kg/h 11,0 kg/h

Lower heating value (LHV) 39704 kJ/kg (=31230 kJ/Nm3) 39704 kJ/kg (=31230 kJ/Nm3) 39704 kJ/kg (=31230 kJ/Nm3) 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) 44057 kJ/kg (=34654 kJ/Nm3) 44057 kJ/kg (=34654 kJ/Nm3) 44057 kJ/kg (=34654 kJ/Nm3)

Fuel unit costs 1688,95718 Rs/MWh HHV (= 16,26 Rs/Nm3) 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3) 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3 1688,9572 Rs/MWh HHV (= 16,26 Rs/Nm3

Fuel heat input (LHV) 380,8 kW 100% 302,2 kW 100% 279,9 kW 100% 205,7 kW 100% 121,6 kW 100%

Fuel heat input (HHV) 422,6 kW 335,4 kW 310,6 kW 228,2 kW 135,0 kW

2. Thermal losses

Temperature flue gas after Chiller 174,0 °C 210,0 °C 212,0 °C 179,0 °C 165,0 °C

Temperature outside air 30,0 °C 30,0 °C 30,0 °C 30,0 °C 30,0 °C

Excess air 130,4 % 180,7 % 146,9 % 146,9 % 109,6 %

Oxygen % in flue gas (Dry volume) 12,40 % 14,00 % 13,00 % 13,00 % 11,50 %

2.1 Losses in dry flue gas

Specific flue gas flow (dry) 23,19 Nm3/kg fuel 28,49 Nm3/kg fuel 24,93 Nm3/kg fuel 24,93 Nm3/kg fuel 20,99 Nm3/kg fuel

Total flue gas flow (dry) 800,6 Nm3/h 780,6 Nm3/h 632,7 Nm3/h 464,9 Nm3/h 231,4 Nm3/h

Total flue gas flow (wet) 889,5 Nm3/h 852,7 Nm3/h 698,5 Nm3/h 513,2 Nm3/h 259,5 Nm3/h

Specific heat flue gas (Dry volume) 1,35 kJ/Nm³.K -10,2% 1,35 kJ/Nm³.K -15,7% 1,35 kJ/Nm³.K -13,9% 1,35 kJ/Nm³.K -11,3% 1,35 kJ/Nm³.K -8,6%

Energy loss in dry flue gas 42,99 kW -11,3% 52,58 kW -17,4% 43,18 kW -15,4% 25,83 kW -12,6% 11,64 kW -9,6%

2.2 Losses due to moisture in fuel

Moisture in fuel 0,000 kg/kg fuel 0,000 kg/kg fuel 0,000 kg/kg fuel 0,000 kg/kg fuel 0,000 kg/kg fuel

Specific heat water in fuel 4,18 kJ/kg.K 4,18 kJ/kg.K 4,18 kJ/kg.K 4,18 kJ/kg.K 4,18 kJ/kg.K

Specific heat water in flue gas 1,83 kJ/kg.K 1,83 kJ/kg.K 1,83 kJ/kg.K 1,83 kJ/kg.K 1,83 kJ/kg.K

Energy losses due to moisture in fuel 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0% 0,0 kW on HHV 0,0% 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% 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0% 0,0 kW on LHV 0,0%

2.3 Losses due to H2 of Fuel

Moisture in flue gas 1,785 kg/kg fuel 1,785 kg/kg fuel 1,785 kg/kg fuel 1,785 kg/kg fuel 1,785 kg/kg fuel


Specific heat water in stacks 1,83 kJ/kg.K 1,83 kJ/kg.K 1,83 kJ/kg.K 1,83 kJ/kg.K 1,83 kJ/kg.K

Energy losses due to H2 in fuel 46,1 kW on HHV -10,9% 37,5 kW on HHV -11,2% 34,8 kW on HHV -11,2% 25,0 kW on HHV -11,0% 14,6 kW on HHV -10,8%

Energy losses due to H2 in fuel 3,3 kW on LHV -0,9% 3,5 kW on LHV -1,2% 3,3 kW on LHV -1,2% 1,9 kW on LHV -0,9% 1,0 kW on LHV -0,8%

2.4 Losses due to moisture in combustion air

Moisture in ambient air 0,007 kg water/kg air 0,007 kg water/kg air 0,007 kg water/kg air 0,007 kg water/kg air 0,007 kg water/kg air

Moisture in ambient air 0,220 kg water/ kg fuel 0,219 kg water/ kg fuel 0,236 kg water/ kg fuel 0,236 kg water/ kg fuel 0,200 kg water/ kg fuel

Specific heat water in flue gas 1,83 kJ/kg.K -0,1% 1,83 kJ/kg.K -0,2% 1,83 kJ/kg.K -0,2% 1,83 kJ/kg.K -0,1% 1,83 kJ/kg.K -0,1%

Energy losses due to moisture in air 0,6 kW -0,1% 0,6 kW -0,2% 0,6 kW -0,2% 0,3 kW -0,2% 0,2 kW -0,1%

5. Heat gains

5.1 Economizer (non condensing)

Temperature stack after economizer 174,0 °C 210,0 °C 212,0 °C 179,0 °C 165,0 °C

Heat transfer efficiency 100% 0,0% 100% 0,0% 100% 0,0% 100% 0,0% 100% 0,0%

Heat recovered by economizer 0,0 kW 0,0% 0,0 kW 0,0% 0,0 kW 0,0% 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) 334,0 kW ( 2926 MWh) 245,6 kW ( 2151 MWh) 232,9 kW ( 2040 MWh) 177,7 kW ( 1556 MWh) 108,9 kW ( 954 MWh)

Chiller efficiency on LHV 87,70 % 81,25 % 83,19 % 86,37 % 89,51 %

Chiller efficiency on HHV 79,03 % 73,22 % 74,97 % 77,84 % 80,67 %

Annual Fuel costs 6.252.146 Rs/year 4.961.638 Rs/year 4.595.591 Rs/year 3.376.961 Rs/year 1.996.646 Rs/year©2011 Armstrong International, Inc This Spreadsheet contains Armstrong Proprietary Information contain trade secrets, as well as privileged information, and/or proprietary work product of Armstrong International, Inc. (“Armstrong”). In consideration of use of this spreadsheet and the information and data herein, User agrees that it will use this document and the information contained herein only for internal use and only for the purpose of evaluating a business transaction with Armstrong. User agrees that it will not disclose this Information or any part thereof to any third parties and Recipient may only disclose this document to those employees involved in the evaluation of a business transaction with Armstrong, on an as need basis. User may make only those copies needed for such internal review. Upon conclusion of business discussions, this document and all copies shall be returned to Armstrong upon its or their request.

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Chiller heating efficiency calculation Liquids Penicillin Penincillin Tablet TabletAttachment 4.7, Burners tuned Chiller 1 Chiller 1 Chiller 2 Chiller 1 Chiller 2Chiller operating hours (incl. hot stand-by hours) 8.760 hours/year 8.760 hours/year 8.760 hours/year 8.760 hours/year 8.760 hours/year











2. Thermal losses



Excess air 28,3 % 28,3 % 28,3 % 28,3 % 28,3 %

























5. Heat gains










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Chiller heating efficiency calculation Liquids Penicillin Penincillin Tablet TabletAttachment 4.8, with economizers Chiller 1 Chiller 1 Chiller 2 Chiller 1 Chiller 2Chiller operating hours (incl. hot stand-by hours) 8.760 hours/year 8.760 hours/year 8.760 hours/year 8.760 hours/year 8.760 hours/year











2. Thermal losses



Excess air 28,3 % 28,3 % 28,3 % 28,3 % 28,3 %

























5. Heat gains










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