STEAM AND CONDENSATE ENERGY AUDIT REPORT … › sites...Jul 23, 2012 · The energy audit was conducted on April 09th and April 18th 2012 by Armstrong and covers the 4 parts of the

GSK Korangi

Karachi, Pakistan

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 Korangi Karachi Pakistan,

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To the attention of Mr. Abdul Wahab Qureshi Established by J.Zwart/D.Graham

TABLE OF CONTENTS 1 Executive summary ............................................................................................................................. 3

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

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

3.1.1 Current situation .................................................................................................................... 6 3.1.2 Optimization .......................................................................................................................... 6 3.1.3 Savings calculation ................................................................................................................ 7 3.1.4 Investments ........................................................................................................................... 7

4 Optimisation project n°2: Increase condensate return bin wash area ................................................ 8

4.1.1 Current situation .................................................................................................................... 8 4.1.2 Optimization .......................................................................................................................... 9 4.1.3 Savings calculation .............................................................................................................. 10 4.1.4 Investments ......................................................................................................................... 10

5 Optimisation project n°3: Replace boiler ........................................................................................... 11

5.1.1 Current situation .................................................................................................................. 11 5.1.2 Optimization ........................................................................................................................ 11 5.1.3 Savings calculation .............................................................................................................. 11 5.1.4 Investments ......................................................................................................................... 12

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

7 Complete check list of all verifications done during the audit ............................................................ 29

8 Recommended complementary studies ............................................................................................ 32

8.1 ADDITIONAL ENERGY-SAVING OPTIMISATIONS ................................................................................................ 32

8.1.1 Heat recovery gas fired chillers ........................................................................................... 32 8.1.2 Define and monitor specific steam and condensate system KPI’s ...................................... 32

8.2 OPERATIONAL OPTIMISATIONS ...................................................................................................................... 33

8.2.1 Flooded heat exchangers .................................................................................................... 33 9 Appendix N°1: Determination of the 2011 steam production and boiler house efficiency ................. 34

10 Appendix N°2: Calculation of Boiler house efficiency ....................................................................... 36

11 Appendix N°3: Boiler house simulations ........................................................................................... 42



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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 for:

- Tray Dryers

- Jacketed Vessels

- Heat exchangers (Dehumidifiers)

- Dehumidifiers (Munters Units)-New

- Bin Wash system - New

- Autoclaves

- Clean steam/WFI

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

and to improve overall boiler house efficiency.

The total calculated steam production of the boiler house 2011 was 3472 ton (0,4 t/h average for the full

year). Our calculations based upon 2011 figures show a steam price of RS 1875,- per ton (€16,07), and

an annual steam budget of RS 6.510.700,- (€ 55.800,-). Condensate return ratio was calculated to be 59% only for 2011.

The single existing boiler has a capacity of 3 t/h and is approximately 15 years old. It is maintained by full

time boiler house personnel. The existing boiler is running at about 50% load during production hours,

but with the new steam users installed this is expected to be around 80% of its output. Steam is

distributed at 6,9 Bar(g) from the boiler house to the various steam users.

The efficiency of the current boiler is calculated at 72,6% on HHV (80,62% on LHV). However due to the

age of the boiler it is not advisable to invest in optimizations like economizers, requiring high investment,

for these boilers. The site’s facilities plan is to install an additional boiler and quotations have been

produced. The boilers will then operate as Duty/Standby. Installing a “state of the art” new packaged



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boiler unit will increase boiler house efficiency up to 81,8% on HHV (90,8% on LHV), which should

generate about RS 626.200,- /year (€ 5.370,-) of savings.

All gas on site is supplied to the existing boiler house with the exception of a small amount for bread

cookers in kitchen. This will change with the introduction of two gas fired chillers which are in the process

of being installed. The gas flow meters are controlled by the gas supply company and are not read by

the site. No other flow measurements (steam/water) were installed on site. Hence it is impossible to

calculate most basic steam system KPI’s, like steam to gas ratio’s, condensate return ratio, blow down

ratios and specific steam usage on a regular (daily) basis. It is recommended to implement an overall

steam monitoring system.

This audit identified 3 optimization projects which yield to a total savings potential of RS 817.000,- (13%

of the steam budget), 440 MWh and 86 tons of CO2 (14,4% of emissions from natural gas). With

estimated investment costs of RS 7.600.000, the average payback time of these projects is relatively

high with 112 months, as it includes already the new boiler. However, simply tuning the existing boiler

would already result in almost 50% of these savings. There are other projects that require additional

study to calculate savings and investment costs.



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2 Steam budget and summary of potential savings

Based upon the utility figures for 2011:

2011 steam production:

Total yearly steam production: 2.411 MWh (3.472 t/year – 0,4 t/h)

Steam cost: 2700 RS/MWh (1.875 RS/t - €16,07/t)

Total yearly steam budget: 6.510.700 RS/year (€55.800,-/year)

Summary of identified energy-saving optimizations and their estimated yearly results: Optimisation Project Energy saving in

kWhEnergy saving

in RsDecreased CO2

emissions in tonsWater savings in Rs

Total project investment cost in Rs

Payback time in months

1. Burner tuning steam boiler* 215.655 364.231 41 6,8% 250.000 92. Increase condensate return bin wash area 69.504 190.957 17 2,9% - 400.000 263. Replace steam boiler 370.770 626.215 68 11,5% 7.200.000 138TOTAL 440.274 817.171 86 14,4% 0 7.600.000 112

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 220.000 370.000 115 19,3% 0 1.800.000 59

33,7% up to average up to9.400.000 96

* not included in total as savings are already included in nr. 3** savings based upon similar project proposal for site F268

TOTAL all projects 660.274 1.187.171 201

RESULTS OF THE DETAILED STUDIES

RECOMMENDED COMPLEMENTARY STUDIES (ROUGH ESTMATIONS)

4. Heat recovery on gas fired chillers**



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3 Optimisation project n°1: Burner tuning steam boiler

3.1.1 Current situation During the survey combustion analysis tests were carried out on the existing steam boiler.

The lowest Oxygen reading at high fire was 11.6% the average for the range was 12%

3.1.2 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.



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

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

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

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

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

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

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

3.1.3 Savings calculation

Appendix 3.2 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 3.1, showing the base line boiler house

simulation for 2011, the annual savings RS 6.510.703 - RS 6.146.471= RS 364.231 (€ 3.100,-), being 5,6% of the steam budget.

3.1.4 Investments

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

combustion analyser and train operators to adjust burners.

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

Including:

- Combustion analyser

- Operator training

Payback time for this project is less than 9 months.



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4 Optimisation project n°2: Increase condensate return bin wash area

4.1.1 Current situation

The Bin wash system has just been installed and was in the position of being commissioned whilst on

site. It was noticed that all condensate from this area was being dumped to drain.

Line drain trap at bin wash Heat exchanger drain trap

Heat exchanger drain trap Heat exchanger drain trap



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Condensate drained to ground drain

All condensate from both heat exchangers and line drain is not returned to the boiler house and is at

present discharged to drain.

4.1.2 Optimization

Condensate from this area should be returned to boiler house. This will improve the boiler feed tank

temperature, decrease boiler feed water make-up and loss of treated water. 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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Steam pressure in application 3,0 bar(g)Steam temperature in application 143,6 °CSubcooling in application 41,6 °CTemperature of drained condensate 102,0 °CEnthalpy drained condensate 426,4 kJ/kgTemperature make up water 20,0 °CEnthalpy make up water 83,6 kJ/kgSensible heat loss 342,8 kJ/kgSteam pressure 3 bar(g)Enthalpy steam 2738 kJ/kgTemperature deaerator / hot well 67 °CEnthalpy feed water 281 kJ/kgLatent heat of the steam 2457 kJ/kgSteam required to compensate heat loss 0,140 kg/kgCondensate flow 400,0 kg/hOperating hours 1825 hoursAmount of drained condensate 730.000 kgSteam required to compensate heat loss 101.836 kgSteam unit costs 1875 Rs/tonSteam costs 190.957 RsMake up water unit costs 0,00 Rs/tonMake up water costs ‐ RsSewer unit costs 0,00 Rs/m3Sewer costs ‐ RsTotal costs of drained condensate 190.957 Rs/year

Costs of condensate drained to sewer

4.1.4 Investments Budgetary cost for this project is RS 400.000,- (€ 3.400,-) Including:

- Equipment supply (steam operated pump, pipework)

- Installation and commissioning (local contractor)

Payback time for this optimization is about 26 Months.



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5 Optimisation project n°3: Replace boiler 5.1.1 Current situation

The single existing boiler is approx 15 years old and is maintained by full time boiler house personnel. At

present it is run in a fully manual situation, the gas fired burner moving between high fire low fire

depending on load. Should this boiler drop out, the site has no backup steam producer and therefore the

site’s facilities plan is to add an additional boiler.

The existing boiler was running at about 50% load during site visit, but with the new steam users

operational, this is expected to be around 85% of its output.

There is no economiser fitted. Blow down system both TDS and bottom is manually controlled.

Furthermore the existing boiler feed tank is too small and overflows depending on process operation.

5.1.2 Optimization

The installation of an economiser, auto blow down and O2-trim would improve boiler efficiency. However

this revamping would not be economical with the existing boiler. The site has a quotation for a new boiler

and this boiler should be fitted with the above equipment at installation.


Appendix 3.3 shows the boiler house running a new boiler, equipped with economiser, auto blow down

and O2-trim, replacing the existing boiler, producing the same amount of steam.

Compared to appendix 3.1, showing the boiler house simulation with the same output using the existing

boiler, the annual savings RS 6.510.703 - RS 5.884.488 = RS 625.215 (€5.366,-), being 9,6% of the steam budget.



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5.1.4 Investments

Existing (local) quotation is in place. Budgetary cost for this project is RS 7.200.000,- (€ 62.000,-)

Including:

- Equipments supply (3 t/h packaged boiler, economizer, TDS and bottom blowdown heat,

deaerator etc.)

- Installation and commissioning

Payback time for this optimization based on energy saving is about 138 Months. However, the main reason to install the new boiler should be the risk of lack of steam supply in case of failure of the existing

boiler. Therefore, energy savings are just one element to be added to the business case for buying a

new boiler.



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6 Summary of deviations noticed during the audit

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

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

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

bottom. There are also some areas with no trap stations prior to control valves this will allow condensate

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

Premature failure of the valves

Corrosion/erosion of heating surfaces of equipment

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

Poor temperature control of equipment due to the variable steam quality

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

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

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

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

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

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

collect.

Steam Leaks There is a small number of steam leaks around the site. However these are many gland leaks and small

flange leaks.

Insulation The insulation on site is in good condition in some parts of the site and poor in others. A separate

thermographic study had recently been conducted by another company.



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Condensate Return Condensate is returned from some areas and a site project was put in place to improve this late 2011.

However there are still a number of areas where condensate is still sent to drain (see project 2).

Condensate from Coating Technical Area AHU’s is at present going to drain. However the site is in the

process of installing new pipework.

The condensate on site is returned via a common return main with all traps being returned to the boiler

feed tank by a single common return unit.

Coating Technical Area



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Steam Trap drip legs Generally steam traps are fitted at drip legs. However it was noticed that some are installed onto mains

at trap size. If a drip leg is not correctly designed, it is possible for condensate to move over it and

continue in the system to the next trapping point. It was also noted that trap sets are fitted on bottom of

drip legs allowing all system contamination to drop into traps causing them to block and therefore

condensate to build up in the steam pipe work.

There are some locations where no drip legs have been installed on steam lines prior to control valves.

When these valves are in a closed position condensate will accumulate in front of them, and sub-cool.

This sub-cooled condensate is aggressive (low PH) and will cause corrosion of the valves and piping,

there is also a risk for thermal shock and water hammer. Also condensate build-up will affect steam

quality and cause early wear of control valves and ancillaries.

Steam Traps The steam system is generally well drained via steam traps throughout the site.

Plugged steam traps

There are a number of steam traps on site that are plugged. In some way these will affect performance

of the steam plant:

- Increased heat-up times

- Water hammer

- Poor control

- Reduced plant efficiency

It was also noted that most of the pressure gauges on site had been subjected to significant hydraulic

shock both on the condensate return and steam side.

All plugged steam traps should be checked, replaced or cleaned and returned to operation.

Leaking steam traps

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

a plant with heat exchange equipment it is important that the steam traps function correctly to ensure

correct and consistent heat transfer with-in the heat transfer unit.



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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. It is therefore vital to replace leaking steam traps to improve both the

waste from energy loss and also improve plant efficiency.

Isolation valves

Most of the traps on site are fitted with isolation, strainers and check valves according to good

engineering practice.

Steam Traps Types

There are a number of different types of traps fitted around the site. However all traps on site fall into two

categories:

Process/Heat Exchanger/AHU Traps

These traps 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.

For heat transfer applications a mechanical type of trap (Inverted bucket/Float and Thermostatic) is

recommended to enable the above conditions to be met. It is important that the load and differential

pressure is known to size the trap accurately.

All heat exchangers on site are fitted with Float and Thermostatic traps which will modulate to the

variable loads this type of equipment creates. However there are some AHU’s and Heat exchangers that

have thermodynamic traps installed which will allow the build-up of condensate. These coils work on

very low steam pressures due to the low temperature set point. The low pressures differential on the TD

traps may cause these traps to fail open, also due to the traps low capacity it is also possible for

condensate to backup within the AHU.

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.

There is a project in place to replace all existing steam traps with GEM ones.



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Jacketed Vessels Ointment Clean Area Condensate from the jacketed vessels in this area are drained from the top of the jacket which means

the jacket will operate full of condensate. The steam will enter at the top and leave at the top, the jacket

will be constantly flooded. The drain should be moved to the bottom of the vessel (a connection is

available) to ensure the jacket gives maximum heat transfer and an even heating throughout the jacket.

Existing steam trap position OK Condensate outlet from the jacket

Line Drain trap install upside down.



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Boiler Feed Tank The existing feed tank is operating at approx 85/90°C. However, at the top of the tank the water

temperature to the boilers is approx 60-65°C - this is due to stratification within the tank. The high

temperature condensate return is dropping into tank - any flash is discharged through the vent. The

introduction of a small circulation pump would ensure even heat throughout the tank and improve the

feed temperature to the boiler. The installation of sparge system could also help with the circulation and

increase the feed temperature to the boiler thereby allowing the boiler to operate to its max rated output.

(A new dearator/feed tank is included in the quotation for the new boiler.)



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Steam Pressure Controlled Heat Exchangers at Low Load

Current situation

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

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



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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.

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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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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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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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.

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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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:

- 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.



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- 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.

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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Savings

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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7 Complete check list of all verifications done during the audit

Potential optimisation Status Comments

STEAM GENERATION

Steam pressure setting OK

Feed water temp. to the boilers Not OK 70-85°C - increased condensate return will

improve this (see project 2). The stratification in

boiler feedwater tank should also be solved.

Stack temperature in front of

economizer

Not OK No economizers installed, 202°C - it is

recommended to install on new (lead) boiler as

current boiler may be too old. See project 3.

Stack temperature after eco. n.a.

Combustion air temperature OK

Oxygen rate Not OK Tuning is recommended on a quarterly basis.

Burner replacement not recommended as boiler

too old. See project 1.

Boiler sizing OK 1 boiler can likely cover site peak load.

Boiler blow down rate Not OK Operators blow down for too long wasting energy.

Project?

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

save chemicals not feasible on existing tank, as it

is small and does overflow on occasion

Feed-water pre-heating Not OK No economizers installed, recommended to install

on new (lead) boiler as current boiler is too old,

see project 3

Boiler stand-by time and volatility

of steam demand

n.a

Boiler blow-down recovery Not OK No heat recovery, not economical to install at

present.



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STEAM DISTRIBUTION

External leaks of steam or

condensate from pipes, flanges,

etc.

Not OK? System is generally well maintained, but some

valves should be repaired.

System design, trapping points etc. Not OK The general design of the system is good.

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 chapter 6.

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

thermographic study was carried out recently

Steam quality Not OK Blocked drain traps should be replaced. See

chapter 6

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 set

points or condensate back pressure. See chapter

6

Steam traps Not OK Existing traps are being replaced by GEM ones.



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CONDENSATE AND FLASH STEAM RECOVERY

Condensate recovered Not OK Condensate return rate is too low due to

condensate being piped to drain. Careful

monitoring to detect leaks (project 2)

Sizing of condensate return lines OK

Flash steam recovery OK Small amount of steam is vented from boiler feed

tank on occasion, but savings are too low to

justify a project.

Water hammering OK

Note: Insulation of pipes and ancillaries and operation of steam traps were not checked in details, as this issue is already covered by another company.



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8 Recommended complementary studies

8.1 Additional energy-saving optimisations

8.1.1 Heat recovery gas fired chillers

There are presently two Sanyo 450T gas fired chillers being installed to replace existing electric chillers.

The heat from the flue gas from these chillers can be utilized to heat water for heating/process. The

installation of an economiser will allow water to be heated by flue gas. It could be used for hot water loop

in Coating Technical Area. Savings potential will be 3-4% of the chillers gas consumption, providing the

hot water heat demand (heat sink) exceeds the heat available (heat source), which will very likely be the

case.

8.1.2 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



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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.

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.

8.2 Operational optimisations

8.2.1 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 chapter 6. A number of heat exchangers operating

under these conditions were identified on your site. Decreasing the load on these heat exchangers, will

cause the heat exchangers to get in a stall condition much sooner. 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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9 Appendix N°1: Determination of the 2011 steam production and boiler house efficiency

The gas flow meters are controlled by the gas supply company and are not read by the site. No other

flow measurements (steam/water) were installed on site. Hence it was only possible to calculate the

boiler house efficiency and steam production indirect. Indirect efficiency is the gas input, minus losses

and consumers in the boiler house. This boiler house efficiency calculation can then be used to calculate

the effect of optimizations in the boiler house.

The single existing boiler has a capacity of 3 t/h and is approximately 15 years old. It is maintained by full

time boiler house personnel. The existing boiler is running at about 50% load during production hours but

with the new steam users installed this is expected to be around 80% of its output. Steam is distributed

at 6,9 Bar(g) from the boiler house to the various steam users. The site’s facilities plan is to add an

additional boiler and quotations have been produced.

Appendix 3.1 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 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.



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

of steam (leaving the boiler house) is copied below:

12. Overall Boiler House EfficiencyNet total output from the boiler house (incl. CHP) 275,2 kW 100,0%Boiler house efficiency on LHV 80,6 %Boiler house efficiency on HHV 72,6 %Annual fuel consumption (LHV) 2.991 MWh/yearAnnual fuel consumption (HHV) 3.318 MWh/yearAnnual CO2 emissions (49,9 kg/GJ / 179,5 kg/MWh HHV) 596 tons/yearAnnual fuel costs 5.604.703 Rs/year12a. Steam generation and steam costsNet total steam heat output from the boiler house 275,2 kW 100,0%Net total steam heat output from the boiler house 2.411 MWh/yearNet dry steam production boiler house 0,396 ton/h = 3472 t/yearNet wet steam production boiler house x=1 0,396 ton/h = 3472 t/yearAnnual fuel consumption (LHV) 2.991 MWh/yearAnnual fuel consumption (HHV) 3.318 MWh/yearFuel costs for steam generation 5.604.703 Rs/year 86,1%Electricity unit costs 10,000 Rs/kWhElectrical pow er for the boilerhouse 10 kWElectricity costs 876.000 Rs/year 13,5%Make up w ater unit costs 0,00 Rs/m3Make up water costs 0 Rs/year 0,0%Costs for chemicals 30000 Rs/year 0,5%Sew er unit costs 0,00 Rs/m3Sewer costs 0 Rs/year 0,0%CO2 unit costs Rs/tonCO2 Emissions ( 171,5 kg/ton of dry boiler house steam) 596 ton/yearCO2 costs 0 Rs/year 0,0%Total variable steam costs 6.510.703 Rs/year 100%Total costs steam from boiler house 1.875,14 Rs/tonTotal costs steam from boiler house 2,7006 Rs/kWh



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10 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 make-up 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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11 Appendix N°3: Boiler house simulations

Appendix 3.1: Boiler house simulation based upon 2011 steam load

Appendix 3.2: Boiler house simulation based upon 2011 steam load, with tuned burner

Appendix 3.3: Boiler house simulation based upon 2011 steam load, with new boiler

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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 ZBOILER HOUSE SIMULATION SI BOILER 1 BOILER 2 BOILER 3 BOILER 4 BOILER 5 CHP BOILERHOUSE

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/year1. Fuel heat input %LHV %LHV %LHV %LHV %LHV 1. Fuel heat input % LHV % HHV 8. Steam consumption deaerator % LHVFuel 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 0,16 m3/hFuel consumption during operating hours 39,4 Nm3/h 0,0 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 3,0 ton/h (=2,1MW) 2,0 ton/h (=0MW) 10,0 ton/h (=0MW) 10,0 ton/h (=0MW) 10,0 ton/h (=0MW) DA feed water flow 0,44 m3/hSpecific 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/cmFuel consumption 31,0 kg/h 0,0 kg/h 0,0 kg/h 0,0 kg/h 0,0 kg/h Fuel consumption 0,0 kg/h Conductivity condensate * µs/cmLower 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 % 58,8 %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/hFuel 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 95,0 °CFuel heat input (LHV) 341,4 kW 100% 0,0 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 67,2 °CFuel heat input (HHV) 378,8 kW 0,0 kW 0,0 kW 0,0 kW 0,0 kW Fuel heat input (HHV) 0,0 kW 100% Temperature deaerator 67,2 °CSteam pressure 6,9 Bar(g) / 169,9°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 kWSteam temperature 169,9 °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/hEnthalpy steam 2768 kJ/kg 0 kJ/kg 0 kJ/kg 0 kJ/kg 0 kJ/kg Alternator efficiency 100 % Vent loss deaerator (0,05%) 0,000 ton/hTemperature feed water to the boiler/eco 67,2 °C 67,2 °C 67,2 °C 67,2 °C 67,2 °C Heat used for generating electricity 0,0 kW 0,0% 0,0% Total steam consumption for deaerator 0,000 ton/hEnthalpy feed water 281 kJ/kg 0 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 2487 kJ/kg 0 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/nMax. theoretical steam production 0,49 ton/h (=0,4 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) 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 0,007 ton/hTemperature flue gas after boiler 202,0 °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/nExcess air 120,6 % 76,3 % 0,0 % 0,0 % 0,0 % Inlet water temperature 65,0 °C Make up water outlet temperature 20,0 °COxygen % in flue gas (Dry volume) 12,00 % 9,60 % 0,00 % 0,00 % 0,00 % Outlet water temperature 85,0 °C Blow down water outlet temperature 67,2 °C2.1 Losses in dry flue gas Water flow 0,00 m3/h Theoretical heat recovery 0,00 kWSpecific flue gas flow (dry) 22,16 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) 685,8 Nm3/h 0,0 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) 765,1 Nm3/h 0,0 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/nSpecific heat flue gas (Dry volume) 1,35 kJ/Nm³.K -11,7% 1,36 kJ/Nm³.K 0,0% 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 67,2 °CEnergy loss in dry flue gas 44,23 kW -13,0% 0,00 kW 0,0% 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 67,2 °C2.2 Losses due to moisture in fuel Steam pressure 10,0 Bar(g) / 184,1°C sat. Make-up water temperature inlet 20,0 °CMoisture 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 °CSpecific 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 67,2 °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 281 kJ/kg Heat transferred 0,0 kWEnergy 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 2500 kJ/kg 10. Radiation losses in the boiler houseEnergy 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/nMoisture 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 °CSpecific 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) 46,6 kWSpecific 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. 2,40 Nm3 H20 /kg fuelEnergy losses due to H2 in fuel 42,2 kW on HHV -11,1% 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% Oxygen % flue gas (Dry volume) 0,00 % Saturation pressure water vapour in stack 0,07 Bar(a)Energy losses due to H2 in fuel 3,8 kW on LHV -1,1% 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% Specific Stack flow (dry) 9,43 Nm3/kg fuel Maximum water vapour content after h.r. 1,80 Nm3/kg fuel2.4 Losses due to moisture in combustion air Total stack flow (dry) 0,0 Nm3/h Condensed in heat recovery 15,3 kg/hMoisture 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) 10,2 kWMoisture in ambient air 0,211 kg water/ kg fuel 0,210 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 0,0% 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 0,6 kW -0,2% 0,0 kW 0,0% 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 Efficiency3. 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) 275,2 kW 100,0%Boiler Average Load 16,47 % 0,00 % 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 80,6 %Water Tube Radiation Losses (as per ABMA) - % 0,00 % 0,00 % 0,00 % 0,00 % 3 Economizer Boiler house efficiency on HHV 72,6 %Fire Tube Radiation Losses (Manufacturer Data) - % 0,00 % 0,00 % 0,00 % 0,00 % Temperature flue gas after economizer 200,0 °C Annual fuel consumption (LHV) 2.991 MWh/yearRadiation losses considered in calc. 3,64 % -3,3% - % 0,0% - % 0,0% - % 0,0% - % 0,0% Economizer inlet water temperature 67,2 °C Annual fuel consumption (HHV) 3.318 MWh/yearRadiation losses 12,4 kW -3,6% 0,0 kW 0,0% 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 (49,9 kg/GJ / 179,5 kg/MWh HHV) 596 tons/year4. Cycling losses (burner starts) Heat recovered (sensible heat) 0,00 kW 0,0% 0,0% Annual fuel costs 5.604.703 Rs/yearHot 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 costsMin. 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 275,2 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 2.411 MWh/yearBurner 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 0,396 ton/h = 3472 t/yearPurge 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 0,396 ton/h = 3472 t/yearMinimum 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) 2.991 MWh/yearHeat 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) 3.318 MWh/year5. Heat gains Condensed in heat recovery 0,0 kg/h Fuel costs for steam generation 5.604.703 Rs/year 86,1%5.1 Economizer (non condensing) Heat recovered (latent heat) 0,0 kW Electricity unit costs 10,000 Rs/kWhTemperature stack after economizer 202,0 °C 220,0 °C 200,0 °C 200,0 °C 200,0 °C Heat transfer efficiency 100 % Electrical power for the boilerhouse 10 kWEconomizer inlet water temperature 67,2 °C 67,2 °C 67,2 °C 67,2 °C 67,2 °C Water flow 0,00 m3/h Electricity costs 876.000 Rs/year 13,5%Economizer outlet water temperature 67,2 °C 67,2 °C 67,2 °C 67,2 °C 67,2 °C Network heater inlet water temperature 85,0 °C Make up water unit costs 0,00 Rs/m3Heat transfer efficiency 100% 0,0% 100% 0,0% 100% 0,0% 100% 0,0% 100% 0,0% Network heater outlet water temperature 0,0 °C Make up water costs 0 Rs/year 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% Total flue gas heat rec. after network heater 0,0 kW 0,0% 0,0% Costs for chemicals 30000 Rs/year 0,5%5.2 Air preheating from external source (Top of boiler house) 5 Boiler radiation losses Sewer unit costs 0,00 Rs/m3Combustion air required 23,48 Nm3/kg fuel 23,48 Nm3/kg fuel 23,48 Nm3/kg fuel 23,48 Nm3/kg fuel 23,48 Nm3/kg fuel Boiler capacity 10,0 ton/h (=6,9MW) Sewer costs 0 Rs/year 0,0%Total combustion air flow 726,9 Nm3/h 0,0 Nm3/h 0,0 Nm3/h 0,0 Nm3/h 0,0 Nm3/h Load 0 % CO2 unit costs Rs/tonNormal 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 ( 171,5 kg/ton of dry boiler house steam) 596 ton/yearPreheated 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 6.510.703 Rs/year 100%5.3 Air preheat system (closed loop heat recovery from stack after eco) Conductivity boiler feed water 290,0 µs/cm Total costs steam from boiler house 1.875,14 Rs/tonTemperature stack after air preheater 202,0 °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 2,7006 Rs/kWhPreheated 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 9,6 % of steam output (11,4cycles) 12b. Electricity generation and electricity costsEnergy 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/yearHeat 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/yearConductivity boiler feed water 290,0 µs/cm 290,0 µs/cm 290,0 µs/cm 290,0 µs/cm 290,0 µs/cm X-value of the steam from the boiler 0,000 Annual fuel consumption (HHV) 0 MWh/yearConductivity 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/yearBoiler water lost by blow down + carry over 10,7 % of steam output (10,3cycles) 10,7 % of steam output (10,3cycles) 9,6 % of steam output (11,4cycles) 9,6 % of steam output (11,4cycles) 9,6 % of steam output (11,4cycles) Enthalpy blow down water 781 kJ/kg CO2 costs 0 Rs/year 0,0%Boiler feed water flow 0,441 ton/h 0,000 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 0,043 ton/h 0,000 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/kWhRatio 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 costsCarry 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 0,000 0,000 0,000 0,000 7. CHP Efficiency and Fuel Costs Net total hot water energy output from the boiler house 0 MWh/yearBlow down flow remaining 0,043 ton/h 0,000 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 719 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/yearTemperature 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/yearEnthalpy 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/yearTotal Blow Down losses 7,5 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 5,2 kW -1,5% 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%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) 275,2 kW ( 2411 MWh) 0,0 kW ( 0 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) 0,398 ton/h = 3490 t/year 0,000 ton/h = 0 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/hNet wet steam production boiler 0,398 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Project name : GSK Karachi PK, Koranji SiteBoiler efficiency on LHV 80,61 % 0,00 % 0,00 % 0,00 % 0,00 % Fuel costs / ton dry steam 0,00 Rs/ton Project nr. : 11360SER2PK, attachment 3.1Boiler efficiency on HHV 72,65 % 0,00 % 0,00 % 0,00 % 0,00 % CHP steam rejected (excess produced by the CHP) 0 kW ( 0 MWh) Date: 15-05-2012Annual Fuel costs 5.604.703 Rs/year 0 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 1605,90 Rs/ton 0,00 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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STEAM AND CONDENSATE ENERGY AUDIT REPORT … › sites...Jul 23, 2012 · The energy audit was conducted on April 09th and April 18th 2012 by Armstrong and covers the 4 parts of the