gsk - armstrong international...2012/12/15 · boiler house assessment project n 12866ser2uk 1...

GSK

Maidenhead, UK

BOILER HOUSE ASSESSMENT

PROJECT N° 12866SER2UK

1 Emission J.Zwart R. Ivanov 14/12/2012 Item Description Established Checked out Date

BOILER HOUSE ASSESMENT

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To the attention of Mr. G. Edwards Established by J.Zwart

TABLE OF CONTENTS 1 Introduction............................................................................................................................................ 3

2 Boiler house design .............................................................................................................................. 4

3 Boiler house efficiency .......................................................................................................................... 6

3.1 DIRECT EFFICIENCY ..................................................................................................................................... 6 3.2 INDIRECT EFFICIENCY ................................................................................................................................... 7

4 Recommendations on boiler house operations .................................................................................... 9

4.1.1 Avoid burner cycling .............................................................................................................. 9 4.1.2 Install feed water flow meters ............................................................................................. 12 4.1.3 Stop the Fulton steam generator ........................................................................................ 13

5 Steam distribution network assessment ............................................................................................. 14

6 Stall situations on heat exchangers .................................................................................................... 20

7 Attachments ........................................................................................................................................ 21


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1 Introduction

This report is the follow up on the Armstrong audit report issued March 23rd 2011 and the steam

distribution assessment report issued August 22nd 2011. Recommendations from the audit report were:

- to optimize the steam pressure control (pressure maintaining set)

- to improve condensate drainage from CIP systems

- to increase the new steam boilers capacities to 2x 2,5 t/h

Recommendations from the steam distribution assessment were:

- to raise the steam distribution pressure from 1,6 to 5 Bar(g)

- to link both ends of the 65mm line (PRV1) and the 80mm line (PRV2) on the Flexicell

mezzanine

- to install a 4” bypass line starting from the 80mm line in towards Flexicell and ending just after

CIP9 on the top floor of OCM

The new boiler house was commissioned in September 2012. The steam distribution pressure has

been raised to 4,7 Bar(g). Furthermore the link line on the Flexicell mezzanine has been installed.

Objective of this study is to review the new boiler house design, to verify the efficiency of the new boiler

house and check if the current system requires additional measures to assure sufficient capacity of the

steam distribution network.


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2 Boiler house design

The new boiler house has two Danstoker Opti 250, 3-pass fire tube boilers. These boilers are rated for

2500 kg/h steam at a maximum pressure of 10 Bar(g). Actual setpoint is 7,5 Bar(g) for the lead boiler

and 7 Bar(g) for the non-lead boiler. Average steam output for both boilers is calculated at 1,0 t/h.

The boilers have Dunphy modulating dual fuel burners but are mainly used on natural gas. The burners

have a turn down ratio of 1:5 (600-2950 kW). The burner control system includes Oxygen trim. Actual

average Oxygen levels vary between a normal 2 and 4%, depending on burner load.

The boilers are both equipped with economisers. The economisers cool the flue gasses down to about

120°C. Boiler water level is controlled by modulating the feed water pumps. Spill back lines, after the

economisers back to the hot well, assure sufficient water flow over the economisers.


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The boilers have both automatic TDS surface blow down and manual bottom blowdown. Actual boiler

water TDS levels vary between 2000 and 2100 ppm, resulting in a low blow down rate of 2,1%. There

is no heat recovery on the blow down.

Reversed Osmosis water is used as make up water for the boilers. This RO water is added to the hot

well, where it is mixed with return condensate. Actual RO water consumption is 117 l/h average,

corresponding to a high 88% condensate return. The hot well has a circulation pump to avoid

stratification in the tank.

Both boilers have pressure maintaining control valves with pneumatic actuators. These valves limit the

boiler steam output in case the boiler pressure gets too low. This to avoid boiler overloading, which

could result in boiler lock-out and steam quality issues due to carry-over of boiler water.


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3 Boiler house efficiency

3.1 Direct efficiency

Multiplying the gas flows by their higher heating value gives the energy consumption per boiler.

Multiplying the measured steam flows by the difference in feed water enthalpy and steam enthalpy ,

gives the heat output per boiler. Dividing heat output by fuel input (HHV) gives the direct efficiency of

the boilers. The graph below show gas input, steam output and boiler efficiency from November 30th till

December 11th:

The graph shows that the site steam demand varies a lot, and boiler efficiency appears to improve as

The graph shows that the boiler efficiency tends to go up when the steam load goes up. This is to be

expected as standing losses do not change with the boiler load. Furthermore burners require less

excess air on higher loads. However the variation in load does not match with the change in boiler

efficiency. The average direct boiler efficiency is 58% only. This is an indication of flow meters running

below their measuring range. The measured hourly averaged steam output of boiler 1 was only 204

kg/h (8% of the boiler capacity). The measured hourly averaged steam output of boiler 2 was only 532

kg/h (21% of the boiler capacity). Considering that the mayor steam users on site (CIP systems) run

only for about 10 minutes, tells us that most of the time the steam flows will be significantly below

hourly average.


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The installed steam flow meters are DN80 Vortex meters. These meters will not give readings when the

flow is below 188 kg/h. This explains the low direct efficiency, as the steam flow meters will be under-

reading during low loads.

3.2 Indirect efficiency

Indirect efficiency is the gas input, minus losses and consumers in the boiler house. The indirect

efficiency should match the direct efficiency. This boiler house efficiency calculation can then be used

to calculate the effect of optimizations in the boiler house. It will also reveal excessive energy losses or

problems in the boiler house.

Attachment 1shows the indirect boiler house efficiency calculation (“Boiler house simulation”). from

November 30th till December 11th.The sheet was adapted for GSK Maidenhead, but contains some

additional calculations (5 boilers, CHP etc.) that are not applicable. This calculation was based upon

information gathered from our own measurements and the Aspen monitoring system during the audit.

For information that was not available (like exact gas composition) engineering assumptions were

made based upon observations and standard engineering practices.

The average indirect boiler efficiency for boiler 1 was 80,2% on HHV (88,7% on LHV). The average

indirect efficiency for boiler 2 was 83,8% in HHV (92,8% on LHV). The difference in efficiency can be

explained by the difference in boiler load. These indirect efficiencies are more than 20% higher than the

measured direct efficiencies. There is no way to explain more than 20% difference in direct and indirect

efficiency other than under-reading steam flow meters.


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

(including hot well) and costs of steam (leaving the boiler house) is copied below:

12. Overall Boiler House EfficiencyNet total output from the boiler house (incl. CHP) 673,7 kW 100,0%Boiler house efficiency on LHV 87,9 %Boiler house efficiency on HHV 79,3 %Annual fuel consumption (LHV) 6.717 MWh/yearAnnual fuel consumption (HHV) 7.439 MWh/yearAnnual CO2 emissions (50,9 kg/GJ / 183,4 kg/MWh HHV) 1.364 tons/yearAnnual fuel costs 202.354 £/year12a. Steam generation and steam costsNet total steam heat output from the boiler house 673,7 kW 100,0%Net total steam heat output from the boiler house 5.902 MWh/yearNet dry steam production boiler house 1,010 ton/h = 8845 t/yearNet wet steam production boiler house x=1 1,010 ton/h = 8845 t/yearAnnual fuel consumption (LHV) 6.717 MWh/yearAnnual fuel consumption (HHV) 7.439 MWh/yearFuel costs for steam generation 202.354 £/year 92,4%Electricity unit costs 0,090 £/kWhElectrical pow er for the boilerhouse 20 kWElectricity costs 15.768 £/year 7,2%Make up w ater unit costs 0,81 £/m3Make up water costs 834 £/year 0,4%Costs for chemicals 0 £/year 0,0%Sew er unit costs 0,52 £/m3Sewer costs 103 £/year 0,0%CO2 unit costs 0 £/tonCO2 Emissions ( 154,3 kg/ton of dry boiler house steam) 1.364 ton/yearCO2 costs 0 £/year 0,0%Total variable steam costs 219.059 £/year 100%Total costs steam from boiler house 24,77 £/tonTotal costs steam from boiler house 0,0371 £/kWh


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4 Recommendations on boiler house operations

The boiler house has only been running since September 2012, and in the meantime many control

parameters were already optimised. However there were still some optimizations opportunities.

4.1.1 Avoid burner cycling One of the problems in the steam system are occasional pressure drops. These pressure drops are

caused by sudden spikes in steam demand, usually caused by starting CIP systems. Analysis using

the Aspen monitoring system revealed that noticeable pressure drops on the secondary steam

pressure in the boiler house only occured at peak steam demands, where both boilers were stopped.

As it takes a few minutes to start a burner, due to required air purge phase, it will take several minutes

for a boiler to actually respond to a rise in steam demand. Furthermore during that response time,

primary steam pressure may drop below the set point of the pressure maintaining valve, which closes

the steam supply.

It is therefore important to reduce the risk of both boilers being stopped during low steam demand,

which is why we recommended the site (in our Steam Distribution Assessment report) to install burners

with a 10:1 turn down ration. Unfortunately the installed burners have a 5:1 (600-2950kW) turn down

ratio.


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Creating a pressure offset between the lead boiler and the non-lead boiler will reduce the risk for both

burners to be stopped at the same time. This way the lead boiler will get more running hours, and the

non-lead boiler will only have to start when the lead boiler cannot maintain its higher pressure setting.

On December 10th around 12:00 the pressure settings of the boilers were offset to 7,5 Bar(g) on the

lead boiler and 7 Bar(g) on the non-lead boiler. Furthermore the setpoint for the pressure maintaining

sets were reduced to 6 Bar(g). Secondary pressure is maintained at 4,7 Bar(g).

Additional benefit of reducing burner cycling is improved boiler efficiency. Every burner cycle starts with

a pre-purge and ends with a post purge. During each purge phase cold air is pushed through the boiler

into the stack for about 1 minute. This will obviously result in a heat loss. Changing the pressure

settings resulted in about 50% reduction of burner cycles (from 30-40 cycles per day down to around

20 cycles per day). We estimate a boiler efficiency improvement of around 1%.


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We have not observed any production related pressure drops on the secondary side in the boiler house

since. However on one occasion the site pressure did drop below 3,4 Bar(g) due to daily boiler testing

procedures.

It is recommended not to start the boiler testing of the second boiler before the first boiler is back on

line and full primary steam pressure is back.


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4.1.2 Install feed water flow meters

As explained in the previous chapter, the installed steam flow meters will not be able to record steam

flows below 188 kg/h. This makes it impossible to accurately monitor direct boiler efficiency. We

therefore recomend to install flow meters in the boiler feed waterlines (low pressure side before the

pumps) and in the economiser spillback lines (high pressure side before the orifice to avoid flash in the

meter). Subtracting spillback from the feed water will give the boilers feed water consumption.

Subtracting the blow down percentage (about 2%) will give the boilers steam output.

To have accurate blow down percentages it is also recommended to regularly test the hot well TDS.

This is currently not a standard procedure. The blow down percentage can be calculated as follows:

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


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4.1.3 Stop the Fulton steam generator

The Fulton steam generator runs to assure sufficient steam pressure (4 Bar(g)) on the shrink tunnel.

The new boiler house has proven its capability to maintain the secondary steam pressure at 4,7 Bar(g).

Running the Fulton steam generator reduces the (base) load on the new boiler house. As a result it will

cause extra burner cycling on the new boilers. This may result in pressure drops and lower efficiency of

the new boiler house.

Furthermore the efficiency and steam quality of Fulton type steam generator is generally significantly

lower than the new fire tube boilers.

We therefore recommend to minimize the use the Fulton boiler.


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5 Steam distribution network assessment

As indicated in the audit report, issued March 2011, the steam load for one CIP system is considered to

be 1167 kg/h. This is based upon heating 4000 litres of water in 20 minutes (= 12.000 l/h), from 10°C to

65°C. Analysing steam flow meter readings in the Aspen monitoring system confirms the steam

consumption of a CIP set to be around 1,2 t/h.

The new boiler house will allow the following maximum site load:

Depending on the season and Supernova operating hours it may be possible to run up to 4 CIP

systems simultaneously.

Steam lines are to be sized on flow velocity and allowable pressure drop. For inside steam distribution

systems it is common not to exceed 30-40 m/sec to avoid high pressure drops, erosion and high noise

levels. Raising steam pressure reduces the specific volume of steam, and hence reduces velocity.

Raising the steam pressure from 2,6 to 5 Bar(g) increases the line capacity by 60%. This step was

taken, and current steam pressure on site is now maintained at 4,7 Bar(g) by two pressure reducing

sets in the boiler house.

To reduce steam velocities it was recommended to link both ends of the 65mm line and the 80mm line

on the Flexicell mezzanine. This link line has been installed. The link line created a local ring main

which should allow running 3 Supernova units and 2 CIP systems (or equivalent) in Flexicell

simultaneously. No pressure drops more than 0,3 Bar were recorded on the Flexicell loop since

recordings started beginning of December. This indicates that the link works well.

It was also recommended to install a 4” bypass line starting from the 80mm line in towards Flexicell

and ending just after CIP9 on the top floor of OCM. This to prevent too high steam velocities on the


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100mm line in OCM, providing CIP sets 9, 2, 3, 4 and 6. This has not been done due to high budgetary

costs (110 k£).

The sketch below shows the situation proposed in the steam distribution assessment report :


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During the study we have installed a pressure transmitter on the 100mm steam line on the top floor of

OCM, after the take-off to CIP9. A pressure probe 0-10 Bar(g) with 4-20 mA output was used. The

graph below shows 42 hours measurement.

Average pressure was 4,6 Bar(g), maximum pressure was 4,7 Bar(g) and minimum pressure was 3,2

Bar(g). The lowest pressure recorded was on the 12th of December at 17:45.


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From the Aspen monitoring system we learned that at that moment CIP sets 2, 3 and 8 were running.

The steam flow at that time was 4,2 t/h.

If we subtract 1,2 t/h for CIP 8, then this leaves 3 t/h for the steam line to the OCM top floor. Steam

pressure measured at the boiler house and at the Flexicell loop remained at 4,7 bar during this event.

This indicates that 2 CIP sets, combined with 0,6 t/h “base load” (=3 t/h) results in a pressure drop of

4,7 – 3,2 = 1,5 Bar in the 100mm steam line to the OCM top floor.


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If we simulate this pressure drop in our calculation model, this pressure drop requires an equivalent line

length (=line length compensating local restrictions like valves and elbows) of 513 meters.

InitialSteam Pressure 4,7 Bar(g)Steam quality X 1,00 Line size DN 100Line length (equivalent) 513 mFlow 3000 kg/hVelocity 33,6 m/s max 30,0 m/sFinal Steam Pressure 3,2 BarPressure drop 1,50 Bar (Wierz/Brabbée)Pressure drop 1,7 Bar (Darcy)Saturation Temperature 156,8 °CSpecific Volume 0,33 m3/kgEnthalpy Steam 2754 kJ/kg X= 1,00Sensible heat 662 kJ/kgLatent Heat 2092 kJ/kg X= 1,00Latent Energy Steam 1743,5 kW

Velocity and pressure drop in steam and condensate lines

The calculation also shows that the steam velocity at the beginning of the line will be 33,6 m/s. At the

end of the line the pressure will have dropped to 3,2 Bar and the specific volume of the steam will have

increased, but the steam flow will still be 3000 kg/h. This results in a higher steam velocity of 44,8 m/s

at the end of the line, which is more than the generally accepted standards for saturated steam lines.




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Adding the load of an extra CIP system on the same line would increase the steam load to 4,2 t/h. This

would result in a pressure drop of 3,4 Bar, leaving only 1,3 Bar(g) at the same location.



Though it is only a rough calculation, it clearly shows that it will not be possible to run three CIP sets

simultaneously on the 100mm steam line on the OCM top floor. It should be considered that the

pressure sensor was located just after the CIP9 take-off. CIP 2, 3, 4 and 6 are further down the line and

pressure at these locations will therefore be even lower. Installation of the proposed link line will be required in case the site wants to run 3 CIP sets simultaneously, or if the site wants to extend production in the future.


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6 Stall situations on heat exchangers

The Steam Distribution Assessment report issued August 22nd 2011 provides recommendations for all

stalled heat exchangers on site. Attachment 1 of the Steam Distribution Assessment report explains

how stall situations occur on steam pressure controlled heat exchangers, and it provides 6 typical

solutions to resolve them.

Upgrading the boiler house and raising site steam pressure does not change any of the

recommendations of this report, due to the fact that every heat exchanger has its own pressure

reducing valve and actual secondary pressure in the heat exchanger does not depend on primary

steam pressure in the steam distribution network.


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7 Attachments

- Attachment 1: Boiler house simulation 30-11-2012 till 11-12-2012

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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: 4 Norway export to UK %HHV 4 Norway export to UK %HHV 4 Norway export to UK %HHV 4 Norway export to UK %HHV 4 Norway export to UK %HHV Fuel type: 0 Custom gas Measured make up water flow 0,117 m3/hFuel consumption during operating hours 20,5 Nm3/h 53,9 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 96% Bal.error: 0%Boiler capacity 2,5 ton/h (=1,7MW) 2,5 ton/h (=1,7MW) 10,0 ton/h (=0MW) 10,0 ton/h (=0MW) 10,0 ton/h (=0MW) DA feed water flow 1,03 m3/hSpecific weight of the fuel 0,78 kg/Nm3 0,78 kg/Nm3 0,78 kg/Nm3 0,78 kg/Nm3 0,78 kg/Nm3 Specific weight of the fuel 0,72 kg/Nm3 Conductivity make up water * 0 µs/cmFuel consumption 16,0 kg/h 42,1 kg/h 0,0 kg/h 0,0 kg/h 0,0 kg/h Fuel consumption 0,0 kg/h Conductivity condensate * 0 µs/cmLower heating value (LHV) 47493 kJ/kg (=37094 kJ/Nm3) 47493 kJ/kg (=37094 kJ/Nm3) 47493 kJ/kg (=37094 kJ/Nm3) 47493 kJ/kg (=37094 kJ/Nm3) 47493 kJ/kg (=37094 kJ/Nm3) Lower heating value (LHV) 50010 kJ/kg (=35882 kJ/Nm3) Condensate return % 88,4 %Higher heating value (HHV) 52600 kJ/kg (=41082 kJ/Nm3) 52600 kJ/kg (=41082 kJ/Nm3) 52600 kJ/kg (=41082 kJ/Nm3) 52600 kJ/kg (=41082 kJ/Nm3) 52600 kJ/kg (=41082 kJ/Nm3) Higher heating value (HHV) 55493 kJ/kg (=39816 kJ/Nm3) Calculated make up water flow from conductivity 0,00 m3/hFuel unit costs 27,2 £/MWh HHV (= 0,31 £/Nm3) 27,2 £/MWh HHV (= 0,31 £/Nm3) 27,2 £/MWh HHV (= 0,31 £/Nm3) 27,2 £/MWh HHV (= 0,31 £/Nm3) 27,2 £/MWh HHV (= 0,31 £/Nm3) Fuel unit costs 30 £/MWh HHV (= 0,33 £/Nm3) Temperature return condensate 89,0 °CFuel heat input (LHV) 211,6 kW 100% 555,2 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 80,0 °CFuel heat input (HHV) 234,3 kW 614,9 kW 0,0 kW 0,0 kW 0,0 kW Fuel heat input (HHV) 0,0 kW 100% Temperature deaerator 104,8 °CSteam pressure 7,4 Bar(g) / 172,2°C sat. 7,4 Bar(g) / 172,2°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 29,60 kWSteam temperature 172,2 °C / 0°C superheated 172,2 °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 2770 kJ/kg 2770 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 88,0 °C 88,0 °C 88,0 °C 88,0 °C 88,0 °C Heat used for generating electricity 0,0 kW 0,0% 0,0% Total steam consumption for deaerator 0,044 ton/hEnthalpy feed water 368 kJ/kg 368 kJ/kg 0 kJ/kg 0 kJ/kg 0 kJ/kg 1b. Hot water generation (engine cooling water) Total heat consumption for deaerator 29,6 kW -3,9%Heat added to feedwater 2402 kJ/kg 2402 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 0,32 ton/h (=0,3 ton/h actual) 0,83 ton/h (=0,8 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 0,2 Bar(g)2. Thermal losses Water flow 0,00 m3/h Flash flow 0,003 ton/hTemperature flue gas after boiler 192,0 °C 192,0 °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 10,0 °C 10,0 °C 10,0 °C 10,0 °C 10,0 °C 1b. Hot water generation (engine lubricant) 9.2 BDHR sensible heat used to preheat make-up water? n y/nExcess air 18,5 % 14,3 % 0,0 % 0,0 % 0,0 % Inlet water temperature 65,0 °C Make up water outlet temperature 10,0 °COxygen % in flue gas (Dry volume) 3,60 % 2,90 % 0,00 % 0,00 % 0,00 % Outlet water temperature 85,0 °C Blow down water outlet temperature 104,8 °C2.1 Losses in dry flue gas Water flow 0,00 m3/h Theoretical heat recovery 0,00 kWSpecific flue gas flow (dry) 13,63 Nm3/kg fuel 13,10 Nm3/kg fuel 11,29 Nm3/kg fuel 11,29 Nm3/kg fuel 11,29 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) 218,5 Nm3/h 551,3 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) 261,7 Nm3/h 664,5 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) 1,38 kJ/Nm³.K -6,5% 1,38 kJ/Nm³.K -6,2% 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 104,8 °CEnergy loss in dry flue gas 15,20 kW -7,2% 38,40 kW -6,9% 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 88,0 °C2.2 Losses due to moisture in fuel Steam pressure 10,0 Bar(g) / 184,1°C sat. Make-up water temperature inlet 10,0 °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 10,0 °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 104,8 °C Heat transfer efficiency 80%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 Enthalpy feed water 438 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 2343 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 2,094 kg/kg fuel 2,094 kg/kg fuel 2,094 kg/kg fuel 2,094 kg/kg fuel 2,094 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 10,0 °C Heat recovered (sensible heat) 28,4 kWSpecific 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 Excess air 0,00 % Stack water vapour content in front of h.r. 3,21 Nm3 H20 /kg fuelEnergy losses due to H2 in fuel 26,2 kW on HHV -11,2% 68,8 kW on HHV -11,2% 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 2,9 kW on LHV -1,4% 7,6 kW on LHV -1,4% 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) 11,89 Nm3/kg fuel Maximum water vapour content after h.r. 1,16 Nm3/kg fuel2.4 Losses due to moisture in combustion air Total stack flow (dry) 0,0 Nm3/h Condensed in heat recovery 99,4 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) 66,4 kWMoisture in ambient air 0,135 kg water/ kg fuel 0,131 kg water/ kg fuel 0,114 kg water/ kg fuel 0,114 kg water/ kg fuel 0,114 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 -0,1% 1,83 kJ/kg.K -0,1% 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 0,2 kW -0,1% 0,5 kW -0,1% 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) 673,7 kW 100,0%Boiler Average Load 12,68 % 33,28 % 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 87,9 %Water Tube Radiation Losses (as per ABMA) - % - % 0,00 % 0,00 % 0,00 % 3 Economizer Boiler house efficiency on HHV 79,3 %Fire Tube Radiation Losses (Manufacturer Data) - % 2,39 % 0,00 % 0,00 % 0,00 % Temperature flue gas after economizer 200,0 °C Annual fuel consumption (LHV) 6.717 MWh/yearRadiation losses considered in calc. 4,73 % -4,3% 1,80 % -1,6% - % 0,0% - % 0,0% - % 0,0% Economizer inlet water temperature 104,8 °C Annual fuel consumption (HHV) 7.439 MWh/yearRadiation losses 10,0 kW -4,7% 10,0 kW -1,8% 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 (50,9 kg/GJ / 183,4 kg/MWh HHV) 1.364 tons/year4. Cycling losses (burner starts) Heat recovered (sensible heat) 0,00 kW 0,0% 0,0% Annual fuel costs 202.354 £/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 600 kW 600 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 673,7 kW 100,0%Boiler water volume (corrected) 68,87 m3 68,87 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 5.902 MWh/yearBurner on/off pressure differential 0,50 Bar(g) 0,50 Bar(g) 0,00 Bar(g) 0,00 Bar(g) 0,00 Bar(g) Flue gas water vapour content in front of h.r. 2,85 Nm3 H20 /kg fuel Net dry steam production boiler house 1,010 ton/h = 8845 t/yearPurge cycle time 120 sec 120 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 1,010 ton/h = 8845 t/yearMinimum nr. burner starts 0,64 per hour -1,0% 0,20 per hour -0,1% 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) 6.717 MWh/yearHeat loss purging air 2,38 kW -1,1% 0,73 kW -0,1% 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) 7.439 MWh/year5. Heat gains Condensed in heat recovery 0,0 kg/h Fuel costs for steam generation 202.354 £/year 92,4%5.1 Economizer (non condensing) Heat recovered (latent heat) 0,0 kW Electricity unit costs 0,090 £/kWhTemperature stack after economizer 120,0 °C 120,0 °C 200,0 °C 200,0 °C 200,0 °C Heat transfer efficiency 100 % Electrical power for the boilerhouse 20 kWEconomizer inlet water temperature 88,0 °C 88,0 °C 88,0 °C 88,0 °C 88,0 °C Water flow 0,00 m3/h Electricity costs 15.768 £/year 7,2%Economizer outlet water temperature 110,5 °C 108,9 °C 88,0 °C 88,0 °C 88,0 °C Network heater inlet water temperature 85,0 °C Make up water unit costs 0,81 £/m3Heat transfer efficiency 100% 3,2% 100% 3,1% 100% 0,0% 100% 0,0% 100% 0,0% Network heater outlet water temperature 0,0 °C Make up water costs 834 £/year 0,4%Heat recovered by economizer 7,5 kW 3,6% 19,1 kW 3,4% 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 0 £/year 0,0%5.2 Air preheating from external source (Top of boiler house) 5 Boiler radiation losses Sewer unit costs 0,52 £/m3Combustion air required 15,06 Nm3/kg fuel 15,06 Nm3/kg fuel 15,06 Nm3/kg fuel 15,06 Nm3/kg fuel 15,06 Nm3/kg fuel Boiler capacity 10,0 ton/h (=6,5MW) Sewer costs 103 £/year 0,0%Total combustion air flow 241,6 Nm3/h 633,9 Nm3/h 0,0 Nm3/h 0,0 Nm3/h 0,0 Nm3/h Load 0 % CO2 unit costs 0 £/tonNormal combustion air temperature 10,0 °C 10,0 °C 10,0 °C 10,0 °C 10,0 °C Radiation losses at full load 0,6 % CO2 Emissions ( 154,3 kg/ton of dry boiler house steam) 1.364 ton/yearPreheated combustion air temperature 10,0 °C 0,0% 10,0 °C 0,0% 10,0 °C 0,0% 10,0 °C 0,0% 10,0 °C 0,0% Radiation losses 0,0 kW 0,0% 0,0% CO2 costs 0 £/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 219.059 £/year 100%5.3 Air preheat system (closed loop heat recovery from stack after eco) Conductivity boiler feed water 42,0 µs/cm Total costs steam from boiler house 24,77 £/tonTemperature stack after air preheater 120,0 °C 120,0 °C 200,0 °C 200,0 °C 200,0 °C Conductivity boiler water 3300,0 µs/cm Total costs steam from boiler house 0,0371 £/kWhPreheated combustion air temperature 10,0 °C 10,0 °C 10,0 °C 10,0 °C 10,0 °C Boiler water lost by blow down + carry over 1,3 % of steam output (78,6cycles) 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 £/year 0,0%6. Blow down Carry over 0,000 ton/h Annual fuel consumption (LHV) 0 MWh/yearConductivity boiler feed water 42,0 µs/cm 42,0 µs/cm 42,0 µs/cm 42,0 µs/cm 42,0 µs/cm X-value of the steam from the boiler 0,000 Annual fuel consumption (HHV) 0 MWh/yearConductivity boiler water 2000,0 µs/cm 2000,0 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 2,1 % of steam output (47,6cycles) 2,1 % of steam output (47,6cycles) 1,3 % of steam output (78,6cycles) 1,3 % of steam output (78,6cycles) 1,3 % of steam output (78,6cycles) Enthalpy blow down water 781 kJ/kg CO2 costs 0 £/year 0,0%Boiler feed water flow 0,288 ton/h 0,789 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Temperature make up water 10,0 °C Total variable electricity costs 0 £/year 0%Boiler water lost by blow down + carry over 0,006 ton/h 0,017 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Enthalpy make up water 41,8 kJ/kg Total costs electricity from the boiler house 0,0000 £/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 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/yearBlow down flow remaining 0,006 ton/h 0,017 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 £/year 0,0%Enthalpy blow down water 729 kJ/kg 729 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 10,0 °C 10,0 °C 10,0 °C 10,0 °C 10,0 °C CHP output (Steam, Hot Water, Electricity) 0,0 kW ( 0 MWh) 100,0% Annual fuel consumption (HHV) 0 MWh/yearEnthalpy make up water 41,8 kJ/kg 41,8 kJ/kg 41,8 kJ/kg 41,8 kJ/kg 41,8 kJ/kg Net Electrical power output 0,0 kW ( 0 MWh) 0,0% Annual CO2 emissions 0 ton/yearTotal Blow Down losses 1,2 kW -0,3% 3,2 kW -0,3% 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 £/year 0,0%Blow down losses compensated by boiler only 0,6 kW -0,3% 1,7 kW -0,3% 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 £/year 0%7. Boiler Efficiency and Fuel Costs Total fuel costs 0 £/year Total costs hot water heating from the boiler house 0,0000 £/kWh

Net heat output in steam from the boiler 187,8 kW ( 1645 MWh) 515,5 kW ( 4516 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) 0,281 ton/h = 2466 t/year 0,773 ton/h = 6768 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 0,281 ton/h 0,773 ton/h 0,000 ton/h 0,000 ton/h 0,000 ton/h Project name : GSK MaidenheadBoiler efficiency on LHV 88,77 % 92,84 % 0,00 % 0,00 % 0,00 % Fuel costs / ton dry steam 0,00 £/ton Project nr. : 12866SER2UKBoiler efficiency on HHV 80,16 % 83,83 % 0,00 % 0,00 % 0,00 % CHP steam rejected (excess produced by the CHP) 0 kW ( 0 MWh) Date: 14-12-2012Annual Fuel costs 55.831 £/year 146.522 £/year 0 £/year 0 £/year 0 £/year CHP hot water rejected (excess produced by CHP) 0 kW ( 0 MWh) Comment: Boilerhouse efficiency based uponFuel costs / ton dry steam 22,64 £/ton 21,65 £/ton 0,00 £/ton 0,00 £/ton 0,00 £/ton CHP useful output considering rejected heat 0,0 kW ( 0 MWh) 0,0% 0,0% readings from 30-11-2012

till 11-12-2012©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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