GSK Boronia sr01 - Armstrong Inc....Qnet = NCV of fuel at constant pressure = 9242.89 kcal/Nm3 Qgr =...

GlaxoSmithKline 1061 Mountain Highway

PO Box 168, Boronia VIC 3155

Australia

STEAM AND CONDENSATE AUDIT REPORT

Audit Date: 25th

to 29th

June 2012

PROJECT 90181-AUS-BOR

1 Emission S. Raikar P. Provot 27/07/2012 Item Description Established Checked out Date

STEAM AND CONDENSATE AUDIT

90181-AUS-BOR

GlaxoSmithKline, Boronia, Australia Date: 27/07/2012

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To the attention: Mr. Phillip Osborne Established by

S. Raikar

Acknowledgement

An Engineering Audit is a venture between Energy Experts and Plant Experts to define

opportunities for optimization. The contribution of the plant’s team is extremely important in this

venture. We sincerely acknowledge the contribution of the following dignitaries and site

engineering personnel whose co-operation helped to conclude to the quality of the data analysis

and conclusions.

� Mr. Phillip L Osborne - Environmental Sustainability Cluster Head

� Mr. John A. Giraud

� Mr. Gary Foley - Eng. Infrastructure Coordinator

� Mr. Robert Sedlins

We are also thankful to the all other staff members who were actively involved while collecting the

data and conducting the field trials.


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TABLE OF CONTENTS

ACKNOWLEDGEMENT________________________________________________02

1. EXECUTIVE SUMMARY________________________________________________04

2. STEAM BUDGET AND SUMMARY OF POTENTIAL SAVINGS_______________________06

3.1 OPTIMIZATION PROJECT NO1___________________________________________12

OPTIMIZE BOILER OPERATION, IMPROVE BOILER HOUSE EFFICIENCY BY BETTER BOILER

CAPCITY UTILIZATION


IMPROVE SYSTEM EFFICIENCY BY OPTIMIZING BOILER COMBUSTION, MAINTAIN CORRECT

OXYGEN IN BOILER STACK


OPTIMIZE BOILER BLOWDOWN, MAINTAIN CORRECT BOILER BLOWDOWN WATER PARAMETER


RECOVER HEAT FROM BOILER STACK TO PRE-HEAT BOILER FEED WATER


AVOID FLOODING OF RADIATOR COIL FOR AHU – BLOCK 1AND NON STERILIZATION

PACKING AREA


RECOVER FALSH STEAM FROM BFS PLANT TO HEAT CLARIFIER HOT WATER

4.0 COMPLETE CHECK LIST OF ALL VERIFICATIONS DONE DURING THE AUDIT ___________ 37

5.0 RECOMMENDED COMPLEMENTARY STUDIES _______________________________ 39

6.0 CONCLUSION AND RECOMMENDED NEXT STEP______________________________ 41


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1 Executive summary

GlaxoSmithKline is a world-leading, research-based pharmaceutical company operating in

more than 100 countries and employing more than 100,000 people world-wide. It is a global

research-based pharmaceutical and healthcare company with a mission to improve the quality

of human life by enabling people to do more, feel better and live longer.

In Australia GSK have improved people’s wellbeing by delivering the highest quality

medicines, vaccines and over-the-counter healthcare products since 1886. GSK provide

about 1600 skilled jobs across the country, working with researchers and doctors to discover

new ways of treating and preventing disease. In 2011 GSK invested $58 million a year in local

research and development, and made significant contributions to Australia’s $4.2 billion

pharmaceutical and medicinal exports.

Boronia, Victoria facility was established in 1970 after being relocated from North Melbourne,

the Boronia head office houses employees working in marketing and sales, research and

development, regulatory affairs, government and corporate affairs, finance, IT and human

resources. The manufacturing plant is the largest GSK sterile facility globally. The site houses

world leading blow-fill-seal technology, featuring eight filling machines and six packaging

lines, as well as 10 tableting lines. The most recent edition is a second Relenza line

completed in 2006. The site has the capacity to produce 1.4 billion tablets per annum,

including products for migraine, herpes, peptic ulcers, treatment of epilepsy, smoking

cessation and anti-virals. Additional capsule products are manufactured for relief of asthma

and pain management.

A microbiology laboratory is also located at the Boronia site that tests 4,000 samples each

year and a chemistry laboratory that test 11,000 samples each year.

As a part of the energy conservation activity, Armstrong has conducted an Energy audit of

Steam and Condensate network from 25th

to 29th

June 2012.

The energy audit covers the 4 parts of the steam loop: boiler house, steam distribution, steam

consumption and condensate return.


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As decided after the day on site, the initial issue we concentrated on was to check the boiler

house efficiency. Based upon our measurements and calculations during the audit, the overall

boiler house efficiency is a reasonable 82.91% on Lower Heating Value.

Since two boilers of capacity 3.4 TPH each are operated together to cater steam demand of

1.2 TPH radiation losses are high. Boiler stack oxygen is measured in the range of 5.2 – 6.8%

which is highr compared to industry standard. Both boilers are not provided with economizer.

Stack temperature is measured as 175 °C – 205 °C. With proper boiler pressure setting, fine

tuning burner and installation of economizer boiler flue gas path will help in reducing fuel

consumption by 6.0%. Boiler blowdown optimization will reduce losses by 0.4%.

Although the steam distribution system is old and oversized, during audit insulation surface

temperature was found within good operating practice. Insulation and leaking steam traps are

already being taken care of by other companies and are therefore not covered in this audit.

Presently all recoverable condensate from the process area along with hot water generated in

BFS plant is returned back to the boiler feed water tank. Makeup water consumption is

calculated as 6% of total steam generation. During audit, it was also observed that flash

steam form the plant is not recovered and is vented to atmosphere. Recovering this flash

steam for generating hot water can reduce heat load by 2 – 3%.

We estimate the potential energy savings of at least 9.7% of the current yearly steam

budget of 165,182 $, which represents a yearly saving of about 16,093 $, 730.2 MWh energy

and 133 tons of CO2 with payback period of 4.4 years


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2 Steam budget and summary of potential savings

Total yearly steam consumption (in 2011): 9750 t/year

Steam cost (in 2011): 16.94 $/t of steam

Total yearly steam budget (in 2011): 165,182 $/year

During the audit, two3.2TPH (2MW) boilers were operated continuously to cater plant steam

demand. Natural gas is used as fuel. Average steam generated by the boiler is 26.7 T/day at

800 to 900 kPa pressure. Since gas flow readings were erronous, gas consumption is

estimated using boiler indirect efficiency. Gas consumption for boiler is estimated as 2016

Nm3/day. Low pressure steam is injected in feed water tank to maintain boiler feed water

temperature at 85 deg C.

Boiler steam load variation with time

As most of the processes in the plant are of batch type, steam demand varies considerably.

During audit average plant steam demand was measured as 949 kg/hr with peak steam

demand of 4065 kg/hr.

A summary of our calculations is given below:

Time


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Boiler Efficiency – Indirect method

Flue gas analysis result

Boiler - B1 (Working) 1 2 3 4 5 6 7 8 9 10 Avg

O2 % 6.6 6.6 6.5 6.8 6.8 6.4 6.4 6.1 6.7 6.7 6.63

CO2 % 8.64 8.64 8.7 8.52 8.52 8.76 8.76 8.94 8.58 8.58 8.62

CO ppm 0 0 1 1 1 0 0 0 0 1 0.67

Ex Air % 45.8 45.8 44.8 47.9 47.9 43.8 43.8 40.9 46.9 46.9 46.13

Boiler - B2 (Standby) 1 2 3 4 Avg

O2 % 5.7 5.3 5.2 5.3 5.38

CO2 % 9.18 9.42 9.48 9.42 9.38

CO ppm 0 1 0 5 1.50

Ex Air % 37.3 33.8 32.9 33.8 34.45

EFFICIENCY CALCULATIONS FOR BOILER AS PER BS 845 PART I 1987

Fuel Natural Gas

Moisture in Fuel 1.5 %

Hydrogen in Fuel 23 %

Net Calorific Valve 9243 kCal/Nm3

1 Loss due to sensible heat in dry flue gases (L1)

= 7.97 %

where

Knet = const based on calorific value of fuel

= 0.39 Siegert constant

t3 = temp of flue gases leaving Boiler

= 205 deg C

ta = temp of air entering combustion system

= 21 deg C

Vco2 = Volume of CO2 in gases leaving boiler (dry)

= 9 %

( )

2

31Vco

tatknetL net

−⋅=

( )

2

31Vco

tatknetL net

−⋅=


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S. Raikar

2 Loss due to enthalpy in water in flue gases (L2)

= 2.98 %

where

mH2O = moisture in fuel

= 1.5 %

H = Hydrogen content of fuel

= 23 %

t3 = temp of flue gases leaving boiler

= 205 deg C

ta = temp of air entering combustion system

= 21 deg C

Qnet = NCV of fuel at constant pressure

= 9243 kcal/Nm3

3 Loss due to unburned gases in flue gases (L3)

= 0.00 %

where

k1 = constant

= 40

Vco2 =

= 9 %

Vco = Volume of CO in gases leaving boiler (dry)

= 0.001 %

Qnet = NCV of fuel at constant pressure

= 9242.89 kcal/Nm3

Qgr = GCV of fuel at constant pressure

= 10269.9 kcal/Nm3

4 Unbrunt Loss (L4)

L4net = For package boiler unbrunt loss are assumed as 0.5%

5 Radiation, conduction & convection losses (L5)

L5net = Boiler Rated Capacity

Qnet

ttHOmHL a

net

)1.22.4210()9(2 32

+−⋅+=

net

gr

Q

Q

VcoVco

VcoKnetL •

+

⋅=

2

13

Qnet

ttHOmHL a

net

)1.22.4210()9(2 32

+−⋅+=

net

gr

Q

Q

VcoVco

VcoKnetL •

+

⋅=

2

13


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S. Raikar

Boiler Operating Capacity

= 5.3 %

Boiler Rated Capacity 6.4 T/hr

Operating Capacity 1.2 T/hr

6 Total losses (Lt)

Ltnet L1+L2+L3+L4+L5+Blowdown loss (0.3%)

= 17.09 %

6 Thermal Efficiency η

= 82.91 %

LtnetEnet −= 100 LtnetEnet −= 100


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

Optimisation Project Energy

saving in

kWh

Energy

saving in

$.

Decreased CO2

emissions in

ton

Total project

investment

cost in $.

Payback

time in

years

Optimization N˚1

Optimize boiler operation, improve

boiler efficiency by better boiler

capacity utilization

98 885 2 065 18.0 500 0.2

Optimization N˚2

Improve system efficiency by

optimizing boiler combustion

maintain correct oxygen in boiler

stack

82 679 1 726 15.1 2 500 1.4

Optimization N˚3

Optimize boiler blowdown

maintain correct boiler blowdown

water parameters

38 644 1 103 7.0 1 000 0.9

Optimization N˚4

Recover heat from boiler stack to

pre-heat boiler feed water

293 249 6 123 53.4 36 000 5.9

Optimization N˚5

Avoid flooding of radiator coil for

AHU- Block 1 and Non

Sterilization packing area

-- -- -- 15 000 --

Optimization N˚6

Recover flash steam form BFS

plant to heat Clarifier hot water

216 755 5 076 39.5 15 000 1.8

Total 730 212 16 093 133 70 000 4.4


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Note:

� Values marked as * imply a requirement of in-depth review to ascertain confirm saving potential

� Savings are calculated on only heat recovery basis.

� Savings are based on the data furnished by the plant head and data collected during the study period.

� Investment considered for the payback calculations are based on budgetary prices of the items considered and

may change depending upon implementation time & the prevailing market situation. At an Audit level

investments are calculated with an accuracy of ±25%.

The above investment and saving estimates are developed according to standard engineering

practices and are based on Armstrong’s extensive experience in steam and utility systems.

More accurate investment estimates will be available after the scope of work to be done by

AIPL is defined and jointly agreed upon by GSK and AIPL as well as upon completion of

Detailed Engineering Design.


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3.1 Optimisation Project N°1:

Optimize boiler operation, improve boiler house efficiency by better boiler capacity utilization

Current System Description and Observed Deficiency

Presently two boilers of capacity 3.2TPH are operated continuously at 850 – 950 kPa to

cater the plant steam demand. Alternately, one boiler works as lead boiler and second boiler

is operated in auto mode just to maintain the steam pressure. Plant average steam demand

is measured as 1.1 TPH with peak steam load of 4.0 TPH. Plant steam load variation with

time is shown by below graph.

Plant steam load is quite fluctuating and it varies considerably with respect to the production.

During the audit, it was observed that irrespective of steam demand, the lag boiler comes on

line to make drop in pressure. This causes both boilers to operate on part load resulting in

considerable drop in boiler efficiency. Refer below graph

Time


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During the audit, AIPL used temperature data loggers to understand boiler operation cycle.

For lag boiler cutin and cut out pressure were set at 800 – 900 kpa. From graph it’s clear

that every 2.5 to 3 hrs lag boiler fire to maintain drop in pressure.

Boiler MCR output

Peak Steam Demand

Gas Flow meter data not available 2

nd Boiler firing status in red

Plant Average steam load


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Technical Discussion

Lag boiler is required to take care of the steam demand in case of failure of the operating

boiler to maintain required pressure or to meet peak steam demand. It is recommended to

operate lead boiler at maximum load to maximize boiler efficiency.

From records, plant average steam demand is measured as 1.1 TPH with peak demand of

4.0 TPH (very rare). Considering the plant requirement, one boiler operation at full load is

sufficient to cater the plant steam load.

Keeping the second boiler in operation will increase the radiation loss thereby reducing

boiler house efficiency. Also burner firing is associated with pre purge and post purge

losses, this consumes substancial energy and increase fuel consumption.

Operating one boiler at full load and reducing frequency of burner firing of second boiler

from present once every 3 hour to once in a shift, a considerable amount of fuel can be

saved. Estimated efficiency gain is 1.3%.

Recommended Optimization

It is recommended to reduce frequency of burner firing from present once every 3 hour to

once in a shift by

Resetting the burner cut-in and cut-out pressure to

a. Cut-in at 350 kPa g

b. Cut out at 900 kPa g

Estimated Benefit

By operating boiler at maximum load, using second boiler only in case of requirement can

improve boiler house efficiency by 1.3%. In monetary terms, savings are estimated as 2065

$ annually. The savings are calculated based on 2011 annual steam generation and the

respective calculated efficiencies.


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Details of calculations

Present annual fuel consumption 735908 Nm3/annum

Rise in boiler efficiency 2.50 %

Net rise considered 50% 1.3 %

Reduction in fuel consumption 9199 Nm3/annum

Estimated annual monetary savings 2065 $/annum

Annual estimated energy saving 356 GJ/annum

98885 kWh/annum

Note: Since we cannot stop second boiler completely, only 50% gain gain in effieicy is considered for

the calculating savings.

The CO2 emissions reduction by optimizing boiler operation is estimated as 18.0 ton/year

Estimated Investment and Payback

The investment is estimated to be $ 500 it includes:

� Change in boiler pressure setting

� Service charges

The payback period for these investments would be 0.2 Year


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Improve system efficiency by optimizing boiler combustion, maintain correct oxygen in boiler stack


Presently two boilers of total capacity 3.2TPH are operated continuously to cater the plant

Steam demand. The average steam load on the boiler is 1.1 TPH with peak demand of

4.0TPH. During visit stack analysis was conducted for both the boiler to identify operating

efficiency. It was observed that the oxygen percentage in flue gases of heater for Boiler 1

was measured as 6.4 – 6.8% and for boiler to measured as 5.2 – 5.7% respectively

During study flue gas analysis was conducted for all boilers to check excess air level for

combustion. Results are as below

Boiler – B1 (Working) 1 2 3 4 5 6 7 8 9 10 Avg

O2 % 6.6 6.6 6.5 6.8 6.8 6.4 6.4 6.1 6.7 6.7 6.63

CO2 % 8.64 8.64 8.7 8.52 8.52 8.76 8.76 8.94 8.58 8.58 8.62

CO ppm 0 0 1 1 1 0 0 0 0 1 0.67

Ex Air % 45.8 45.8 44.8 47.9 47.9 43.8 43.8 40.9 46.9 46.9 46.13


O2 % 5.7 5.3 5.2 5.3 5.38

CO2 % 9.18 9.42 9.48 9.42 9.38

CO ppm 0 1 0 5 1.50

Ex Air % 37.3 33.8 32.9 33.8 34.45

Oxygen % indicated in the stack is a measure of “Stack Loss”. The higher the Oxygen

percentage in stack , the higher is the stack loss and lower the boiler efficiency. Present

combustion efficiencies of the boilers are as follows

Boiler house efficiency is calculated as 82.91 % on NCV


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Combustion refers to the rapid oxidation of fuel accompanied by the production of heat, or

heat and light. Complete combustion of a fuel is possible only in the presence of an

adequate supply of oxygen.

Oxygen (O2) is one of the most common elements on earth making up 20.9% of our air.

Rapid fuel oxidation results in large amounts of heat. Solid or liquid fuels must be changed

to a gas before they will burn. Usually heat is required to change liquids or solids into

gases. Fuel gases will burn in their normal state if enough air is present.

Most of the 79% of air (that is not oxygen) is nitrogen, with traces of other elements.

Nitrogen is considered to be a temperature reducing dilutant that must be present to obtain

the oxygen required for combustion.

Nitrogen reduces combustion efficiency by absorbing heat from the combustion of fuels

and diluting the flue gases. This reduces the heat available for transfer through the heat

exchange surfaces. It also increases the volume of combustion by-products, which then

have to travel through the heat exchanger and up the stack faster to allow the introduction

of additional fuel air mixture.

This nitrogen also can combine with oxygen (particularly at high flame temperatures) to

produce oxides of nitrogen (NOx), which are toxic pollutants. Carbon, hydrogen and

sulphur in the fuel combine with oxygen in the air to form carbon dioxide, water vapour and

sulphur dioxide, releasing 8084 kcals, 28922 kcals & 2224 kcals of heat respectively.

Under certain conditions, Carbon may also combine with Oxygen to form Carbon

Monoxide, which results in the release of a smaller quantity of heat (2430 kcals/kg of

carbon) Carbon burned to CO2 will produce more heat per pound of fuel than when CO or

smoke are produced.

C + O2 → CO2 + 8084 kCals/kg of Carbon

2C + O2 → 2CO + 2430 kCals/kg of Carbon

2H2 + O2 → 2H2O + 28,922 kCals/kg of Hydrogen

S + O2 → SO2 + 2,224 kCals/kg of Sulphur


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Each kilogram of CO formed means a loss of 5654 kCal of heat.

3 T’s of Combustion

The objective of good combustion is to release all of the heat in the fuel. This is

accomplished by controlling the "three T's" of combustion which are (1) Temperature high

enough to ignite and maintain ignition of the fuel, (2) Turbulence or intimate mixing of the

fuel and oxygen, and (3) Time sufficient for complete combustion.

Commonly used fuels like natural gas and propane generally consist of carbon and

hydrogen. Water vapor is a by-product of burning hydrogen. This robs heat from the flue

gases, which would otherwise be available for more heat transfer.

Natural gas contains more hydrogen and less carbon per kg than fuel oils and as such

produces more water vapor. Consequently, more heat will be carried away by exhaust

while firing natural gas. Too much, or too little fuel with the available combustion air may

potentially result in unburned fuel and carbon monoxide generation. A very specific amount

of O2 is needed for perfect combustion and some additional (excess) air is required for

ensuring good combustion. However, too much excess air will result in heat and efficiency

losses.

Not all of the heat in the fuel are converted to heat and absorbed by the steam generation

equipment.

Usually all of the hydrogen in the fuel is burned and most boiler fuels, allowable with

today's air pollution standards, contain little or no sulphur. So the main challenge in


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combustion efficiency is directed toward unburned carbon (in the ash or incompletely

burned gas), which forms CO instead of CO2.

Major Factors affecting Combustion Efficiency are

Stack loss

• It is the sensible heat lost through the chimney. It depends on the excess oxygen in

the flue gas and the stack temperature at the boiler outlet.

• It occurs due to variations in the air to fuel ratio over the complete boiler operating

range

Enthalpy loss

• It is the heat carried away by the water vapour in the flue gas.

• As it depends upon the fuel composition the combustion equipment cannot control

this loss unless testing of fuel is done on regular basis.

Un-burnt loss

• It is caused by insufficient air supplied during combustion or improper air and fuel

distribution in furnace .It is calculated by measuring carbon monoxide and carbon

dioxide in the flue gas.

Radiation loss

• It is the heat lost through surface of the boiler.

• It depends on boiler insulation, loading pattern, boiler size and compactness.

• A higher loading pattern results in a lower radiation loss.

As per the standard the oxygen percentage in boiler stack (with NG) should be 1.0 – 2.5%.

As observed from the flue gas analysis oxygen in boilers stack varies considerably from 5.2

to 6.8%.

It was understood from GSK that the boiler maintenance is subcontracted to a local vendor;

presently they check the stack oxygen once every month however burner tuning is not

done. It is recommended to tune the burner continuously so as to maintain correct O2

parameter (3%, as burner is old) in boiler stack.


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Below graph explain variation of boiler efficiency with change in stack oxygen


It is recommended to tune boiler regularly and maintain boiler stack oxygen 2.5 – 3.5%.

Note: As per good engineering practice oxygen percentage in stack for NG fired boiler

should be between 1 to 2.5% refers above graph; however the installed boilers are 20

years old. Burners are also of old technology, achieving 1 – 2.5% stack oxygen with these

burners will be difficult.

Estimated Benefit

Maintaining correct oxygen in boiler stack efficiency can be improved by 1%. Estimated

monetary savings are 1726 $ annually. The savings are calculated based on 2011 annual

steam generation and the respective calculated efficiencies.


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Net rise in efficiency 1.05 %




82679 kW/annum

Note: Since oxygen in the stack will be maintained by manually check 80% net rise is considered for

calculating savings.

The CO2 emissions reduction by optimizing combustion is 15.1 ton/year


The investment is estimated to be 2500 $ it includes:

� Portable handheld flue gas analyser

� Service charges for boiler tuning every 30 – 45 day

The payback period for these investments would be 1.4 years


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Optimize boiler blowdown maintain correct boiler blowdown water parameters


Currently soft water and plant returned condensate is used as boiler feed water. During

audit boiler water analysis was done, analysis report is as follows.

Boiler blowdown water average TDS variation for last six month. (Data is taken form

Hydroflow record)

It was observed that boiler blowdown water TDS is maintained less than 1000 ppm.

Estimated present boiler blowdown percentage is calculated as 3.5% which is high

compared to industry norms.

Boiler Water Feed Water

TDS ppm 890 30

pH 11.34 7.69


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The raw water TDS entering softener plant is measured as 40 - 50 ppm. This water is then

mixed with plant returned condensate collected in condensate tank pumped to the boiler

drum. During the audit, feed water temperature at feed water tank is measured as 85˚C.

Presently conductivity based automatic blowdown controller is installed on both boiler

bottom blowdown valve. During the audit, automatic blowdown system was in operation

and blowdown was given based on drum water conductivity.

The boiler drum water sample was checked and conductivity was maintained in a range of

1200 - 1500 µS/cm.


Even with the best pre-treatment programs, boiler feed water contains some degree of

impurities such as suspended and dissolved solids. As water evaporates, these impurities

are left behind and accumulate inside the boiler. The increasing concentration of dissolved

solids leads to carryover of boiler water into the steam, causing damage to piping, steam

traps and even process equipment. The increasing concentration of suspended solids

forms sludge, which impairs boiler efficiency and heat transfer capability.

However maintaining boiler drum TDS lower then Maximum permissible value increases

blowdown loss as hot boiler water is drained off

To avoid boiler problems, water must be periodically discharged or “blowdown” from the

boiler to control the concentrations of suspended and total dissolved solids in the boiler

water. Bottom blowdown is performed periodically to remove sludge accumulated from the

bottom of the boiler.

The importance of boiler blowdown is often overlooked. If the blowdown rate is too high,

energy (water, fuel, chemicals) is wasted. If high concentrations are maintained, (too low

blowdown) it may lead to scaling, reduced efficiency and to water carryover into the steam

compromising its quality (wet steam). The blow down rate is calculated with the following

formula:


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% Blowdown = C Feedwater

(C Boiler – C Feedwater)

Where

CFeedwater= the measured concentration of the selected chemical in the feed water

(Conductivity, TDS, Alkalinity, Chlorine)

CBoiler = the measured concentration of the same chemical in the boiler

Note that the feed water concentration depends on the make-up water quality and the

condensate return ratio.

The ASME guidelines "Consensus on Operating Practices for the Control of Feed water

and Boiler Water Quality in Modern Industrial Boilers," shown in the tables below, are

frequently used for establishing optimum blow down rate.

Water Chemistry for Water tube Boilers - ASME Guidelines


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For installed water tube boiler as per boiler manual boiler blowdown water TDS is required

to be maintained as 2000 ppm


It is recommended to reset boiler blowdown control system set point to 2500 µS/cm.

Estimated Benefit

Maintaining correct boiler water TDS not only save energy but also help in preserving

precious water. Estimated monetary savings are 1103 $ annually. The savings are

calculated based on 2011 annual steam generation and the respective calculated

efficiencies.


Present annual Steam generation 9750000 kg/annum

Present Boiler water TDS 890 ppm

Boiler feed water TDS 30 ppm

Present Blowdown 3.5 %

Present Blowdown 340116 kg/annum

Expected Boiler water TDS 1700 ppm

Boiler feed water TDS 30 ppm

Expected Blowdown 1.8 %

Expected Blowdown 175150 kg/annum

Reduction in Blowdown quantity 164967 kg/annum



38644 kW/annum

Annual estimated water saving 165 m3/annum


The CO2 emissions reduction by optimizing blowdown is 7.0 ton/year


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The investment is estimated to be 1000 $ it includes:

� Service charges for resetting blowdown control system

The payback period for these investments would be 0.9 year


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Recover heat from boiler stack to pre-heat boiler feed water


There are two boilers of capacity 3.2TPH each installed in the plant. Both boilers are more

than 20 year old. During study it was observed that two boilers were operated continuously

to cater the plant steam demand. The average plant steam load was measured as 1.1 TPH

with peak steam demand of 4.1 TPH using existing installed steam flow meter. Boiler

steam pressure is maintained at 900 kpa g. Burner modulates according to plant steam

load variation to maintain the drum steam pressure.

During the study flue gas analysis was conducted for all boilers to check excess air level

for combustion. Results are as below

Boiler – B1 (Working) 1 2 3 4 5 6 7 8 9 10 Avg

O2 % 6.6 6.6 6.5 6.8 6.8 6.4 6.4 6.1 6.7 6.7 6.63

CO2 % 8.64 8.64 8.7 8.52 8.52 8.76 8.76 8.94 8.58 8.58 8.62

CO ppm 0 0 1 1 1 0 0 0 0 1 0.67

Ex Air % 45.8 45.8 44.8 47.9 47.9 43.8 43.8 40.9 46.9 46.9 46.13


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O2 % 5.7 5.3 5.2 5.3 5.38

CO2 % 9.18 9.42 9.48 9.42 9.38

CO ppm 0 1 0 5 1.50

Ex Air % 37.3 33.8 32.9 33.8 34.45

Also in order to understand the variation in boiler stack temperature variation, data logging

has been done for 6hrs duration. Results are as below

Presently no heat recovery units are installed on the boiler flue gas outlet to recover heat.

From above graph it was observed that boiler stack temperature varies considerably from

175 – 215°C. Higher the stack temperature, higher stack losses and lower boiler efficiency.


It is required to clear boiler (fire side) every six months, any soot deposit on the tube

surface retard the heat transfer increasing stack temperature and reducing boiler

efficiency.

During combustion, the carbon from the fuel combines with the oxygen and gets converted

in to CO2. This oxidation reaction is exothermic and liberates heat. This heat is absorbed

by the water on the water-side of the boiler, which is converted into steam. The gases of

this reaction are exhausted via the stack of the boiler at a temperature close to the

saturation temperature of the steam. The energy contained in these exhaust gases

accounts for a major part of the efficiency loss of the boiler. It is therefore important to

recover the maximum amount of energy out of these gases by using economizers. An


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

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

of economizer, the water flows through the tubes and absorbs the excess heat from the

flue gas. Typically, a de-aerated feed water is used for this purpose as a heat sink. The

flue gas outlet temperature can be brought down to as low as 120 ˚C (for NG)

“Economizer” is a shell and tube type heat exchanger (radiator) places in the flue gas path

of the boiler. Flue gases are passed on shell side and water is passed on tube side. The

control valves maintain and modulate water flow as per the boiler requirement. Bypass

interlock ensures safety in case of low stack temperature. Natural gas being clean and

cheap fuel, using natural gas for boiler can reduce operating cost substantially. Reduction

in operating cost will help in reducing production cost thereby increasing profit margins.

Below is the basic schematic for installation of economizer on boiler


Armstrong recommends to installing economizer on boiler stack to recover heat to pre heat

boiler feed water.


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Estimated Benefits

Installing economizer on boiler flue gas path will improve boiler efficiency by 3 – 4%

thereby reduce fuel consumption. Estimated monetary savings are 1103 $ annually the

savings are calculated based on 2011 average steam production and the respective

efficiencies.



Present boiler house efficiency 82.91 %


Net rise in efficiency considered 3.7 %

Reduction in Fuel Consumption 27280 Nm3/annum



293249 kW/annum

The CO2 emissions reduction by using economizer is 53.4 ton/year


The investment is estimated at 36000 $ It includes:

� Economizer (one unit)

� Single element drum level control (control valve on water line)

� Piping and accessories

� Erecting And Commissioning

The payback of this installation is expected to be 5.9 years

Note:

Due to long payback cost of only one economizer is considered for pay back calculation.

Here assumption is lead boiler will be boiler installed with economizer.


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Avoid flooding of radiator coil for AHU- Block 1 and Non Sterilization packing area

Current system description and observed deficiency

During the audit, it was observed that the steam coils used in AHU of block 1 and non

sterilization packing area found flooded. It was observed that steam supply pressure for

these AHU coils is 3 barg. Control valve installed after pressure reducing station modulates

steam flow as to maintain process temperature of 20 – 35 ˚C. Currently orifice traps are

installed to drain the condensate from the coil.

During the audit it was observed that trap was failed under flooding condition and thus AHU

was not able to maintain required air temperature. Below are thermography image of the

radiator coil are

Block 1 AHU Coil

Left side Coil Middle Coil Right Side coil

Non Sterilization packing area coil


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The condensate temperature is measured in the range of 15 - 20˚C.


As the process side temperature is very low the control valve at the inlet modulate. When

process reaches required temperature, it causes valve to close. The steam inside the

radiator coil condenses causing vacuum. Though vacuum breaker are installed to break

the vacuum, to remove the condensate a positive differential pressure is required. With

negative differential pressure or zero differential pressure the condensate cannot come out

of the coil and cause temporary water logged condition. The condition is referred as “Stall

condition”. The condensate get sub cooled releasing CO2 thus causing corrosion and

leakages in condensate lines. Also two different temperature zones in heat exchanger

cause heat exchange to buckle causing steam and condensate leakage.

Below is the schematic for installing pumping trap for AHU coil


Armstrong recommends installing pumping traps for AHU coil application where process

temperature is below 90°C.


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Estimated Benefits

Installation of pumping trap will help in avoiding stall phenomenon for coil resulting better

condensate evacuation form the coil thus better process temperature control. Such benefits

cannot be estimated in monetary value however better process parameter will result in

huge intangible savings.


The investment is estimated as 15000 $ It includes:

� Double duty trap (5 units)

� Piping, Insulation, Erecting and Commissioning


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Recover flash steam form BFS plant to heat Clarifier hot water


In GSK, BFS plant is one of the major consumers of steam. Steam is cosumed in pure

steam generator at 3.0 barg, Distillation column at 7 barg and WFI PHE at 4 barg.

Condensate from all these equipmets is collected in a common tank located near clarifier.

The liquid condensate is pumped back to boiler feed

water tank and generated flash steam is vented to

atmosphere.

Steam load of these equipment is estimated as below

Pure Steam Generator – 950 kg/h

Distillation Colum – 250 kg/h

WFI PHE – 200 kg/h

Maximum flash steam generated is estimated as 65

kg/h


When steam heats the process liquid, around 75% of its energy is transferred to process

and steam condenses. Balance 25 % energy is held by the condensed water. The

condensate is distilled water, having almost zero TDS. Condensate when discharged

through steam trap from a higher to a lower pressure. Certain amount of condensate re-

evaporates, and is referred to a Flash Steam.

The proportion that evaporates varies according to the level of pressure reduction between

the ‘steam’ and ‘condensate’.


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About half of the energy mentioned above is lost through flash steam if it is not recovered.

Flash Steam recovery is therefore an essential part of achieving an energy efficient

system.

Advantage of Recovering Flash Steam

� Flash Steam has high heat content.

� Using flash steam in heating feed water de-aerator or Hot water system will reduce live

steam injection.

� Conserve energy as well as precious water.


Armstrong recommends using this flash steam to preheat water in clarifier using steam

coil. Since clarifier is located next to condensate tank the piping required is minimum.

Estimated Benefits

By recovering flash steam for hot water generation will save $ 5076 annually. The savings

are calculated based on 2011 average steam production and the respective efficiencies.

Approximate Amount of Flash Steam

in Condensate

Condensate

85%

Flash Steam

15%

Approximate Amount of Flash Steam

in Condensate

Condensate

85%

Flash Steam

15%

Approximate amount of Energy in Flash

Steam & Condensate

Flash Steam

50%

Condensate

50%

Approximate amount of Energy in Flash

Steam & Condensate

Flash Steam

50%

Condensate

50%


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Average flash steam loss from condensate tank

in BFS plant

35 kg/h

Estimated fuel Saving 2.3 Nm3/h



216755 kWh/annum

Annual estimated water savings 306.6 m3/annum

The CO2 emissions reduction by using flash steam is eastimated as 39.5 ton/year


The investment is estimated at $ 15,000. It includes:

� Steam coil for Clarifier

� Piping with insulation, Installation and commissioning

� Labour Costs

The payback of this installation is expected to be 1.8 years

* Note - Investment considered budgetary, detail costing has to be taken form supplier


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4.0 Complete check list of all verifications done during the audit

Potential Optimization Status Comments

Boiler House

Boiler Pressure Setting Appropriate

Feed water temperature to the

boiler

Okay Measured 85 °C

Stack Temperature Not okay, to be

improved by

installing

economizer

Economizer not installed, Stack

temperature measured as 175 –

215 °C. Required stack

temperature is 120 °C.

Combustion air temperature Okay

Oxygen in boiler stack Not okay, to be

improved by burner

tuning

Stack oxygen is measured in the

range of 5.2 – 6.8%. Required

stack oxygen is 1 – 2.5%

Boiler Sizing Okay

Blowdown rate Not okay, to be

improved by

resetting automatic

blowdown

controller

Present boiler average drum

TDS is 890 ppm. Recommended

is 2000 ppm

Deaerator Pressure Okay Atmospheric Deaerator

Boiler blow-down recovery Not installed Not economically feasible

Steam Distribution

External leaks of steam or

condensate from pipes, flanges,

etc.

Good No steam leakages identified in

the plant

Steam Quality Okay No corrosion, erosion problem

reported

Sizing of steam lines Oversized Changing to correct sizing not

economically possible


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Potential Optimization Status Comments

Steam Pressure drop Good No pressure drop observed in

the plant

Steam pipe insulation Okay Surface temperature checked

and found with permissible limits

Pressure reduction Okay All pressure reducing station

found working satisfactory

Steam Consumption

Condensate draining and air

venting for AHU

Not okay, to be

improved

Most of the AHU coil found

flooded with condensate

Steam Trap Survey Okay Orifice traps installed

Condensate and flash steam Recovery

Condensate recovery Good All recoverable condensate form

the plant and header traps is

recovered back to boiler feed

water tank

Sizing of condensate return line Okay No water hammering observed

Flash steam recovery Not okay, to be

improved

Flash steam from BFS plant to

be recovered for Clarifier water

heating


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5.0 Recommended complementary studies

The initial energy audit did not allow us to study in details all identified potential

optimisations. Here is the list of projects that are still to be developed in details to identify

the best solution and allow its implementation.

5.1 Additional energy-saving optimisations

Heat recovery on compressor

Presently three 553.13 CFM (90kW) compressors are installed in the compressor house.

Both compressors are provided with VSD’s. One compressure is operated continuously to

cator plant air requirement. Average loading of the comperssure is 60 - 80% based on

plant load. During the audit the compressor power was measured form installed power

meter. The monthy average power consumption for the compressor is measured as 77.08

kW. The compressor is not provided with heat recovery unit, heat of compression is

dissipated to cooling tower. Currently plant is using refrigerent dryer to remove moisture

from compressed air.

As much as 80-93% of the electrical energy used by an industrial air compressor is

converted into heat. In many cases, a properly designed heat recovery unit can recover

anywhere from 50- 90% of this available thermal energy and put it to useful work heating

air or water. Oil-free rotary screw compressors offer a much better opportunity for heat

recovery. As typical with all compressors, the input electrical energy is converted into heat.

Discharge temperatures from the low and high pressure elements can be over 148°C. This

heat appears at the low-pressure and high-pressure compression elements, intercooler

and aftercooler.


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Energy Recovery Opportunity

1. HOC dryer can be used to dry compressed air inplace of exisiting refrigerent dryer.

Energy Conservation by Heat of Compression type compressed air dryer is a

breakthrough in compressed air drying technology. The hot air from the oil-free air

Compressor at 120°C or higher temp, is used directly for regeneration of the desiccant

bed in the compressed air dryer. After regeneration, this air is cooled down to 40°C in

the water cooled after cooler and then it is dried in second tower. Thus the use of

heaters is eliminated. For eg. in the 6 + 6 Hrs. Cycle the hot air is fed for regeneration

of desiccant bed for 4 Hrs. and for balance 2 Hr. a changeover takes place where the

air is first cooled in an after cooler, then dried and before going to the outlet, cools the

regenerated desiccant bed, thus bringing it down to ambient temperature. This cycle is

reversed for the next 6 Hrs. where the Adsorber drying the air in the previous cycle

goes for regeneration and vice versa.

There is considerable power saving in these type of Compressed Air Dryers and the

dew point is also better than the Refrigerated type of Compressed Air Dryers.

Main Advantage of Heat of Compression Type Compressed air dryer is the energy

conservation and heat recovery achieved which is being wasted in After cooler in the

conventional air dryers is now used to reactivate the desiccant.

Optimization

Armstrong recommends to eveluate this opportunity with original HOC dryer

manufacturer.


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6.0 Conclusions and Recommended Next Steps

The Steam and Condensate Engineering Audit has defined a total potential of $ 16 093

savings that are summarized in the following table.

Sr.

No Description

Energy

(GJ/Year)

Fuel

(kWh/year)

Water

(KL/Year)

Financial

Savings

($./annum)

CO2

Emission.

Reduction

(Ton/Year)

1

Optimization N˚1

Optimize boiler operation, improve

boiler efficiency by better boiler

capacity utilization

356 98 885 -- 2 065 18.0

2

Optimization N˚2

Improve system efficiency by

optimizing boiler combustion ,

maintain correct oxygen in boiler

stack

298 82 679 -- 1 726 15.1

3

Optimization N˚3

Optimize boiler blowdown maintain correct boiler blowdown water parameters

139 38 644 165 1 103 7.0

4

Optimization N˚4

Recover heat from boiler stack to

pre-heat boiler feed water

1056 293 249 -- 6 123 53.4

5

Optimization N˚5

Avoid flooding of radiator coil for

AHU- Block 1 and Non Sterilization

packing area

System

benefits -- -- -- --

6

Optimization N˚6

Recover flash steam form BFS plant

to heat Clarifier hot water

780 216 755 306 5 076 39.5

The savings only include utilities savings. Maintenance, safety and process optimizations are not

represented in those numbers. Armstrong would be glad to prepare a proposal for their

implementation. The other projects will need a step of further engineering to define the exact

solution and refine the investments in order to be able to provide a turnkey proposal.


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Confidentiality Notice

This engineering audit report has been submitted to M/s. GSK Boronia, Australia in confidence

and it contains trade secrets, as well as privileged information, and/or proprietary work product of

Armstrong International Pvt. Ltd. (AIPL), In consideration of the receipt of this report and the

information and data herein, Recipient 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 Recipient agrees that it will not disclose this report 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 AIPL, on a need basis. Recipient may make only those

copies needed for such internal review. Upon conclusion of business discussions, this document

and all copies shall be returned to AIPL upon its or their request.

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GSK Boronia sr01 - Armstrong Inc....Qnet = NCV of fuel at constant pressure = 9242.89 kcal/Nm3 Qgr =...

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