Aranda de Duero, SPAIN STEAM AND CONDENSATE ENERGY …

GSK Manufacturing

Aranda de Duero, SPAIN

STEAM AND CONDENSATE ENERGY AUDIT REPORT

PROJECT N° 30275

1 Emission E. Morin R. Ivanov 04/02/2011 Item Description Established Checked out Date

STEAM AND CONDENSATE AUDIT

Project N°30275

GSK MANUFACTURING Aranda, Spain

Date: 04/02/2011

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To the attention of Ms. Beatriz Herrero-Gonzalo Established by E. Morin

TABLE OF CONTENTS

1 Executive summary ................................................................................................................... 4

2 Steam budget and summary of potential savings ...................................................................... 6

3 Optimisation project n°1: Reduce Boilers Blowdown rate ......................................................... 8

3.1 CURRENT SITUATION .............................................................................................................................. 8

3.2 OPTIMIZATION ....................................................................................................................................... 9

3.3 SAVINGS CALCULATION ........................................................................................................................ 10

3.4 INVESTMENTS ...................................................................................................................................... 11

4 Optimisation project n°2: Reduce flash steam losses from feedwater tank ............................. 12

4.1 CURRENT SITUATION ............................................................................................................................ 12

4.2 OPTIMIZATION ..................................................................................................................................... 15


4.4 INVESTMENT ........................................................................................................................................ 19

5 Optimisation project n°3: Improve steam ancillaries insulation ............................................... 21


5.2 OPTIMIZATION ..................................................................................................................................... 22


5.4 INVESTMENTS ...................................................................................................................................... 23

6 Optimisation project n°4: Replace failed steam traps.............................................................. 24


6.2 OPTIMIZATION ..................................................................................................................................... 25


6.4 INVESTMENT ........................................................................................................................................ 26

7 Summary of deviations noticed during the audit ...................................................................... 27

7.1 STEAM GENERATION ............................................................................................................................ 27

7.2 STEAM DISTRIBUTION ........................................................................................................................... 28

7.3 STEAM USERS ..................................................................................................................................... 29

7.4 CONDENSATE RETURN ......................................................................................................................... 32

8 Complete check list of all verifications done during the audit ................................................... 33

9 Recommended complementary studies................................................................................... 35

9.1 ADDITIONAL ENERGY-SAVING OPTIMISATIONS ........................................................................................ 35


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9.2 ADDITIONAL OPERATIONAL OPTIMISATIONS ............................................................................................ 36

10 Appendix N°1: Determination of the January 2011 boiler house efficiency .............................. 37

11 Appendix N°2: Steam Pressure Controlled Heat Exchangers at Low Load .............................. 40


11.2 OPTIMIZATION ..................................................................................................................................... 43

11.3 SAVINGS ............................................................................................................................................. 45

11.4 INVESTMENTS ...................................................................................................................................... 45


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1 Executive summary

The energy audit conducted from January 17th till January 20th 2011 by Armstrong covers the 4 parts

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

GSK factory located at Aranda de Duero, in Spain, produces medicines as liquids, aerosols and

tablets.

Steam is mainly used by:

- Coils to produce hot air for fluid bed dryers, coating machines (GLATT) and dehumidifier

(Munters)

- Heat exchangers for sanitization, hot water production, pure steam generation

- Double jackets for reactors heating

Steam is distributed at 7 barg from the new boiler house since one year. The former boiler house is

now stopped. All steam is distributed from the Eagle building to tunnel 2 area and tunnel 1 area.

Steam pressure is then locally reduced to 6, 4 or 2 barg.

Steam is produced by 2 steam generators (Clayton), gas-fired, with a capacity of 3 tons/hr.

The average steam production of the boiler house during the audit is estimated at 0,9 tons/hr. The

steam consumption was low due to the stop of activities in the Eagle Building.

As an indicator, if we use some figures recorded in the old boiler house 2 years ago, your average

steam consumption was about 2 tons/hr.

Our calculations based upon data collected during the audit show a current steam price of 29,5 €

per ton, and an annual steam budget estimated at 133 300 €.

The steam and condensate lines are generally correctly sized.

Insulation of steam ancillaries can be improved.

The steam distribution system is under trapped, especially in front of control valves, resulting in a

serious risk of steam leaks caused by corrosion, erosion and water hammering.

All Condensate that could be recovered is sent back to the boiler house using 3 pumping traps units.

Condensate return ratio was calculated to be 70% during the audit.


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In order to identify steam leaks, operational problems etc., a steam trap survey was carried out ; in

total 98 traps were tested. The trap survey showed 15% of failed traps (leaking and plugged).

The savings calculated for optimization projects in this report were based upon engineering

assumptions, observations and standard engineering practices.

We estimate the potential energy savings of at least 9% of the estimated steam budget, which

represents a yearly saving of about 377 MWh, 72 tons of CO2 and 11 850 € (see projects 1-3-4).


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2 Steam budget and summary of potential savings

The former boiler house (Energy Central 1) was equipped by meters for all energies (gas, water,

steam, condensate) and data were recorded in a global supervision system.

However the new boiler house (Energy Central 2) is not as well equipped. There are only 1 water

meter and 2 gas meters (one for each steam generator) but data is not regularly reported.

Therefore we cannot know your gas consumption for the last 12 months and we cannot calculate

your steam production for the previous year.

Nevertheless, based upon the utility figures during our visit on site in January 2011, we can

estimate:

Boilers steam generation:

• Total yearly steam generation: 3472 MWh (4516 t/year)

• Steam cost: 38.4 €/MWh (29.5 €/t)

• Total yearly steam budget: 133 300 €/year

• Efficiency estimated: 86% (see calculation in appendix n°1)

Basic data considered:

• Gas unit costs : 25 €/MWh hhv

• Gas High Heating Value : 42.1 MJ/Nm³

• Electricity unit costs : 0.064 €/kWh

• Water costs :

o 0.35 €/m³ for city water

o 9000 €/year for Chemicals

o Total = 5 €/m³


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

Note: projects n°1, 3 and 4 should be prioritized as it is simple solutions easy to implement with a

payback time close to 1 year :


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3 Optimisation project n°1: Reduce Boilers Blowdown rate

3.1 Current situation

Water impurities and chemicals concentrate (due to evaporation) in a Clayton system as in any

other steam boiler.

To avoid boiler problems, water must be periodically discharged or “blown down” from the boiler to

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

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

energy (water, fuel, chemicals). If high concentrations are maintained, (too low blowdown) it may

lead to scaling, reduced efficiency, and could lead to water carryover into the steam compromising

the steam quality (wet steam).

Comparing to conventional firetubes steam boilers, Clayton Steam Generators have reduced

blowdown because of two factors:

• Steam Generator is a forced circulation boiler and can tolerate relatively high TDS levels in

the feedwater – as high as 8550 ppm (normal range is 3000-6000 ppm)

• Water that is blowndown is separator trap return water that has been concentrated in the

separator by a factor of, typically, 4 to 5.


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Because condensate from Clayton separator returns to the feedwater tank, the feedwater will be

concentrated and "cycled up" as in normal boiler water. In other words, the feedwater in the

feedwater tank will have the same composition as the coil water.

Therefore the blowdown rate is calculated with the following formula:

% Blowdown = C make-up water

(C Feedwater – C make-up water )

Where :

C Feed water = the measured TDS concentration in the feedwater tank

C make-up water = the measured TDS concentration in the make-up water

- The blowdown system installed on the 2 Clayton in the new boiler house is automatic: the

valve opens every 2 hours during 4 minutes.

According to Nalco monthly water analysis since June 2010, average TDS concentration values are:

- Feed water =50 ppm

- Make up water = 1520 ppm

Therefore your average blowdown rate is 3.4 %

3.2 Optimization

According to the water treatment manual from Clayton, the following water conditions must be

maintained in the feedwater (boiler water) at all operating times:

• Zero hardness

• pH 10.5–11.5 (normal range), maximum of 12.5

• Oxygen free with an excess sulfite residual of 50–100 ppm

• Maximum TDS of 8,550 ppm (normal range 3,000-6,000)

• Maximum dissolved iron of 5 ppm

• Free of suspended solids

• Maximum silica of 120 ppm with the proper OH alkalinity


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According to your water analysis, TDS concentration is half of the lowest value recommended by

Clayton. Therefore you could reduce at least by 2 the blowdown rate.

The easiest solution is to change the duration of blowdown valves opening defined in the BMS

system. In agreement with Nalco, you can reduce the blowdown duration to 2 minutes every 2 hours

for example.

Another solution consists in installing a TDS probe on the feedwater line and control the blowdown

valve continuously.

3.3 Savings calculation

Reduce Blowdown rate Existing Proposed Savings

Make-up water TDS ppm 50,0 50,0

Feedwater TDS ppm 1520,0 3000,0

Blowdown rate % 3,40 1,69 1,71

Water savings Existing Proposed Savings

Steam production of the boiler kg/h 1000,0 1000,0

Blowdown flow kg/h 34,0 16,9 17,1


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Treated Water unit costs €/m3 5,0 5,0

Water costs €/yr 1063 530 533

Fuel savings Existing Proposed Savings

Sensible heat Blowdown kj/kg 721,0 721,0

Sensible heat make up water kj/kg 50,0 50,0

Sensible heat differential kj/kg 671,0 671,0

Energy used kj/h 22823 11373 11450

Boiler efficiency % 86,0 86,0

Operating hours hr 6240 6240

Fuel used MWh/yr 46,0 22,9 23,08

Fuel unit costs €/MWh 25,0 25,0

Fuel costs €/year 1150 573 577

CO2 savings Existing Proposed Savings

Energy used Gj/yr 166 83 83

CO2 emissions kg CO2/GJ 50,6 50,6 50,6

CO2 produced t/yr 9,5 4,7 4,7

Total savings Existing Existing Proposed

Total costs €/yr 2211 1102 1109

Total energy saved by reducing the blowdown rate is estimated at 1110 €/year.

3.4 Investments

No investment is required to change the blowdown frequency on the BMS System.

However we estimate the budget to install a TDS controlled blowdown valve at 9000 €.

Payback time for this optimization would be more than 7 years.


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4 Optimisation project n°2: Reduce flash steam losses from feedwater

tank


In the new boiler house, 7 barg saturated steam is produced by 2 Clayton generators.

The principle of steam production is the following:

Make-up water and return condensate are blend in the feedwater tank. Feedwater is pumped into

the heating coil, flowing through the spiral single passage section of the coil in a direction opposite

of the combustion gases, where it is rapidly heated to steam temperature. As the fluid leaves the

generator section, it passes through helically wound water wall section, into the separator nozzle in

the steam separator. The centrifugal force in the nozzle separates dry steam from excess water,

which returns to the lower section in the separator. Steam is delivered through the steam discharge

outlet located at the top of the steam separator. The excess water is returned to the feedwater

through the steam trap.

This system allows delivering 99% dry steam within a short time.


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In order to keep the coil wet at all operating conditions and assure a very good steam quality, a

minimum of 20% excess water is required.

This part of excess water is heated from feedwater tank temperature to saturation (170°C/7 barg)

and evacuated by the steam trap at the separator outlet. This condensate is then sent to the

atmospheric feedwater tank.

Consequently a part of condensate will vaporize from 7 to 0 barg generating 13.5% of flash steam in

the feedwater tank.

Condensate from separator going back to the feedwater tank is useful to maintain the feedwater at

high temperature (90°C minimum required).

We indeed observed that the average temperature in the tank is above 95°C.

Therefore, no extra-steam is needed to maintain the temperature.

However the feedwater tank is still overheated.

Usually, condensate from separator is connected to the bottom of the feedwater tank (under the

water level) using a sparger tube :


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This configuration allows maximizing the heat usage and insures a good homogenization of

feedwater temperature in the tank.

However in the new boilerhouse, condensate is connected to the top of the feedwater tank :

Consequently, flash steam generated is not completely condensed and is evacuated through the

vent to the atmosphere.


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Excess feedwater load

In theory, a minimum of 20% excess water is required for a good operation of the steam generator.

This percentage is set and the feedwater pump has a fixed pumping rate.

It is possible to check if the amount of excess water is in a normal range as it is directly linked to the

amount of condensate evacuated from the steam trap.

The Clayton booklet explains how :

We did measure the opening time for the steam trap when the Clayton was at 25-30% load. I was

about 10 minutes per hour. This value is too high considering the explanation above. We therefore

conclude that the amount of excess water set is too high (about 40%) and so is the amount of flash

steam generated in the feedwater tank.

4.2 Optimization

To prevent from too much flash steam loss at the feedwater tank vent we recommend to:

1. Check with your Clayton distributor if a technician can reduce the amount of excess

water pumped to run properly the generators

2. Move condensate connections from the top to the bottom of the feedwater tank using

a sparger tube : it will help to have an homogeneous feedwater temperature in the

tank

3. Recover condensate heat to preheat combustion air up to 50°C. The solution consists

in installing a coil to heat combustion air using a part of condensate from Clayton

separator.


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Considering our observations and measurement on site, we can estimate the cost of this flash

steam loss:

Fuel savings Existing

% of revaporisation (7 to 0 barg) 13,5%

Flash steam flow estimated ton/h 0,066

safety factor 10%

Energy loss kW 37

operating hours hr 6240

yearly Energy used MWh/year 232

boiler efficiency % 86

Fuel used MWh/year hhv 300

Fuel unit costs €/MWh hhv 25

Fuel costs €/year 7506

CO2 savings Existing

Energy used Gj/yr 1081

CO2 emissions kg CO2/GJ 50,6


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CO2 produced t/yr 55

Water savings Existing

Flash steam flow estimated kg/h 0,066

safety factor 10%

Yearly water lost m³/year 371

Water unit costs €/m3 5,0

Water costs €/yr 1853

In conclusion, we estimate the total potential savings at 9360 €/year.

1. Solution 1 : reduce excess feed water rate on the pump

Considering your installation, the Clayton specialist technician will decide how much it is possible to

reduce the amount of excess water pumped.

The following table shows savings calculation if the rate is decreased by 10% :


Feewater flow m³/hr 1,1 1,1

Excess feedwater rate % 40% 30% 10%

Excess water flow / condensate m³/hr 0,44 0,33 0,11

% of revaporisation (7 to 0 barg) 13,5% 13,5%

Flash steam flow estimated ton/h 0,059 0,045 0,015

Energy loss kW 37 28 9

operating hours hr 6240 6240

yearly Energy used MWh/year 232 174 58

boiler efficiency % 86 86

Fuel used MWh/year hhv 300 225 75

Fuel unit costs €/MWh hhv 25 25

Fuel costs €/year 7506 5629 1876



CO2 emissions kg CO2/GJ 50,6 50,6

CO2 produced t/yr 55 41 14


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Water savings Existing Proposed Savings

Flash steam flow estimated kg/h 0,059 0,045 0,015

Yearly water lost m³/year 371 278

Water unit costs €/m3 5,0 5,0

Water costs €/yr 1853 1390 463

The total savings would be 2340 €/year.

2. Solution 2 : Move the condensate connections to the bottom of the tank with a sparger tube

The modification will imply an increase of the feedwater temperature pumped to the generators.

We estimate this increase at 5°C. The efficiency gain on steam production will be about 0.5%.

Boiler efficiency Existing Proposed Savings

Feedwater temperature °C 93,0 98,0

Boiler efficiency % 86,0 86,5 0,5


yearly Energy used GJ/yr 12499,2 12499


Fuel used MWh/yr hhv 4486 4460 25,93

Fuel unit costs €/MWh hhv 25,0 25,0

Fuel costs €/year 112145 111496 648



CO2 emissions kg CO2/GJ 50,6 51


Savings are poor (less than 1000 €) because steam production is very low. If the steam demand

increases, savings will follow.


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3. Solution 3 : preheat combustion air using hot condensate

The preheating of combustion air from ambient to 50°C will lead to an efficiency improvement by

1.5%:

Boiler efficiency Existing Proposed Savings

Intake air temperature (average) °C 18,0 50,0

Stacks temperature °C 120,0 120,0

Oxygene content % 7,0 7,0



yearly Energy used GJ/yr 12499,2 12499


Fuel used MWh/yr hhv 4486 4409 76,90

Fuel unit costs €/MWh hhv 25,0 25,0

Fuel costs €/year 112145 110222 1922



CO2 emissions kg CO2/GJ 50,6 51


4.4 Investment

1. Solution 1 : reduce excess feed water rate on the pump

Budgetary cost for this project is estimated under 1000 €.

Payback time for this optimization is less than 6 Months.

2. Solution 2 : Move the condensate connections to the bottom of the tank with a sparger tube

Budgetary cost for this project is 3000 €.

Payback time for this optimization is about 55 Months.


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3. Solution 3 : preheat combustion air using hot condenste

Budgetary cost for this project is 13 100€.

Including:

- Air ducts, condensate coil, valves, controls

- Installation work

At level of steam generation seen during the audit, payback time for this optimization is about 82

Months.


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5 Optimisation project n°3: Improve steam ancillaries insulation


Not only for safety reason, must hot surfaces have effective insulation to

prevent excessive heat loss by radiation. The basic function of insulation

is to retard the flow of unwanted heat transfer. There is more chance of

part of steam to condense during distribution if the pipelines are not

properly insulated.

There is a closely interrelated efficiency between boilers and their

distribution systems. The losses occurred in the distribution systems have

a significant impact on boiler operations. When these losses are minimized, boiler plant efficiency is

improved.

We observed some valves and filters on steam lines which are not insulated in your steam

distribution system.

The following table shows the non-insulated equipments identified during the audit:

Location Ancillaries length or DN Pressure loss

type number (mm) (barg) (W)

Boiler house (Eagle)

Back Pressure valves valve 2 80 7 2106

Eagle building

2nd floor South valve 2 100 7 2796

Pressure Reducing Station strainer 1 100 7 1398

Pressure Reducing Station valve 1 100 4 1137

GLATT 6115 valve 2 32 4 745

2nd Floor North Lavado valve 1 32 4 373

2nd Floor North Lavado valve 1 40 4 425

4th floor south valve 3 40 2 1069

4th floor south strainer 1 40 2 356

Tunnel 2 aera

1st floor VP37 valve 1 50 6 618


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VP43 valve 1 50 6 618

near VP43 strainer 1 50 6 618

VP44 valve 1 40 4 425

to MDU1500 strainer 1 40 4 425

Glatt sala 544 - VP56 valve 2 32 6 869

Glatt sala 544 - VP56 strainer 1 32 6 435



Glatt sala 535 - VP38 strainer 1 32 6 435

Tunnel 1 aera

VP16 valve 1 65 3 614

VP4 valve 1 65 3 614

The total radiation loss is calculated at 16882 W.

5.2 Optimization

We recommend installing insulated jackets on all ancillaries located in

steam lines above DN25. These jackets are easy to remove in case of

maintenance operations.


SAVINGS Calculation

Total radiation losses 16882 W

Operating hours 6240 h

Annual loss (time corrected) 105,3 MWh/yr

Steam production efficiency 86,0% (lhv)

Annual primary energy loss 122,5 MWh lhv/yr

Annual primary energy loss 135,6 MWh hhv/yr

Fuel cost 25,00 €/MWh

Annual financial loss 3391 €/yr

CO2 emissions 24,7 t CO2/year

Savings calculated are 3400 €/year.


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5.4 Investments

Budgetary cost for this project is 6000 €.

Including:

- On site measurement to prepare tailor-made manufacturing of the jackets

- Supply of insulation jackets

- Installation

Payback time for this optimization is less than 21 Months.


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6 Optimisation project n°4: Replace failed steam traps


A full trap survey was done during our audit. There are 98 steam traps identified and listed on your

steam system drawings. 15 of the installed traps were failing (13 leaking, 2 plugged) and 34 could

not be tested as the units were out of service.

The details of the trap survey and its results are available on SteamStar trap management online

platform.

Here are the access parameters of this trap survey:

Login : [email protected]

Full Name : Beatriz Herrero Gonzalo

Password : B34Tr1ZH3Rr3

Website : www.steamstar.com

Summary of results:


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6.2 Optimization

We recommend replacing all steam traps indentified as failed.

Leaking steam traps mean losses of steam. It may also reduce condensate evacuation from process

by creating a back-pressure in the return lines.

Besides, steam in condensate return lines may generate water hammers which can damage your

installation and ancillaries (valves, pressure reducing valve, heat exchangers).

Blocked traps compromise steam quality and cause corrosion and erosion of steam lines and

auxiliaries, resulting in high maintenance costs and increased down time due to system failures.

These traps should be individually evaluated and should be cleaned or replaced by correctly sized

and installed traps.

Some of failed traps were not installed properly (reversed or inclined).

We also noticed a wrong selection for traps n°14-34-35, the pressure differential available is 4.5

barg whereas the steam pressure is 7 barg.



Steam losses calculated by Steamstar kg/h 50,450

Energy loss kW 29











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Steam losses kg/h 50,450




Total savings would be 7350 €/year.

6.4 Investment

The budgetary cost for replacing all failing traps is 8000 €.

Including:

- Equipments supply (traps)

- Installation by a mechanical contractor

- Project management

Payback time for replacing all failing traps, including blocked traps, is 13 Months.


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7 Summary of deviations noticed during the audit

7.1 Steam generation

Steam is produced by the Energy Central 2 since 2010. This new boiler house is not well monitored

yet.

Gas meters data on the 2 steam generators are not read regularly. As natural gas is also used for

hot water boilers in the Energy Central 1, it is not possible at the moment to know exactly fuel

consumption used to produce steam.

The make-up water meter is reported every day during the daily maintenance (decalcify water).

Some other data are measured and reported to the BMS System:

However some of these probes do not work properly (stacks temperatures, steam temperature) and

only steam pressure is recorded (trends available).

Consequently it is not possible to check on a regular basis the good functioning of the new boiler

house.


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Gas meters should at least be reported once per month. The best would be to connect meters to the

BMS system (same for water) and record values.

We also recommend you to check if the steam and condensate flowmeters used in the old boiler

house cannot be moved to the new steam production system.

7.2 Steam distribution

Missing condensate drain points

Poor drainage of steam lines will cause accumulation of condensate in the steam distribution

system, thus causing a serious safety hazard for water hammering.

Also on many locations there are no drip legs installed on steam lines in front of control valves. In

some situations there are several meters vertical steam line above a control valve, without a drain

point (especially for Munters feed). When these valves are in a closed position condensate will

accumulate in front of these control valves, and sub-cool. This sub-cooled condensate is aggressive

(low PH) and will cause corrosion of the valves and piping. Also there is a risk for thermo shock and

water hammering. Furthermore accumulated condensate will compromise steam quality and cause

early wear of piping and ancillaries due to erosion.

Steam line size between Eagle and Tunnel 1&2

We have checked the steam line size for the connection between Eagle and Tunnel 1&2.

« Low point »


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Steam is distributed at 6 barg in a DN65 pipe. As steam velocity should not exceed 30 m/s in the

pipe, the maximum steam flow you could sent safely to Tunnel 1&2 is 1220 kg/hr.

Steam lines DESIGN

Steam pressure 6 Bar(g)

X value 1,00

Line diameter DN 65

Flow 1220 kg/h

Steam velocity 30,0 m/s max 30,0 m/s

Steam temperature 164,9 °C

specific volume 0,27 m3/kg

Steam enthalpy 2763 kJ/kg X= 1,00

Sensible heat 697 kJ/kg

Latent heat 2066 kJ/kg X= 1,00

Latent input 700,1 kW

Currently it is not a problem as your real steam consumption for these areas is lower. However, if for

some reason the steam demand is increased you have to be aware of this limit.

7.3 Steam users

Main steam users are the GLATT systems and the dehumidifier Munters which need hot air.

The factory use 8 GLATT and 9 Munters in the whole site.

-GLATT systems (for coating machines and fluid bed dryers)

Each air handling unit is equipped with 2 or 3 steam coils.


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The first one is called the “anti-freezing” coil. It is used to pre-heat outside air to 20-30°C.

Often the control valve is a thermostatic one and it is not protected by a drain point upfront.

Therefore this valve may leak rapidly.

Besides, considering the low temperature setting, the steam load in the coil may be low and there

may not be enough pressure to push condensate in the return line. This condition leads to flooded

coils which decrease the heat efficiency and generate slight water hammers. (see appendix n°2 for

detailed explanation)

The second and third steam coils are used to heat the air to 75-85°C. Most of them are equipped

with an automatic ON/OFF valve upfront the control valve. This prevent from steam leaks. However,

we highly recommend installing a steam trap in front of control valves which are installed in “low

point” to prevent from water hammering.

.

The GLATT equipments installed in the Eagle building are also equipped with start-up steam traps.

This steam traps open only with a pressure differential less than 1.5 barg. It allows evacuating

condensate to the sewer when steam pressure is less than back-pressure.

We observed that finally the valves after these steam traps are closed because you lose too much

condensate to the sewer. To avoid this situation you could install a system to push condensate in

the return at any operating condition (see appendix n°2).


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-Dehumidifier Munters (for air conditioning)

The Munters system uses a desiccant rotor to remove humidity from outside air.

This desiccant rotor needs to be regenerated using hot air.

The air is heated by a steam coil up to 125°C.

Steam pressure needed is 4.25 barg (indicated in Munters datasheet).

Steam feeding lines are well equipped with control valves and automatic ON/OFF valves.

However there is no drainage point before all valves. Consequently, when the valve is closed,

condensate accumulates in steam line.

- Steam pressure levels

Many pressure reducing stations are installed on steam distribution lines.

However the steam pressure level is not always adapted to the need.

Munters dehumidifiers are designed to use 4.25 barg, but we have seen some equipment fed with 4

barg or even 2 barg steam. Therefore the desiccant regeneration may not be efficient and the

humidity control hazardous.

For GLATT dryers, steam pressure levels are also various:

- WSG120-sala 531, GLATT1350-sala 535 = 3 barg

- GLATT-sala 544 = 4.5 barg

- WSG120-sala 602, Climatiz.Recubrid.- sala 607 = 5 barg


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- GLATT 6115-6102-6106, Eagle = 4 barg

Steam pressure levels should be adjusted considering these parameters:

� Hot air temperature needed

� The lower the steam pressure, the higher the latent heat which is transferred in

the coil

� The lower the pressure, the higher the specific volume (attention to be paid to

steam pipe size)

� If steam pressure is less than condensate return back-pressure, you may cause

condensate accumulation inside the coil.

-Linea AVAMYS (2 double jacketed reactors)

We observed that there is only one steam trap for the 2 condensate outlets of reactors.

This configuration can only work if the reactors do not run in the same time; otherwise you may have

troubles to evacuate condensate from one of the reactors to the return line.

7.4 Condensate return

Condensate from Tunnel 1 area is collected and sent to Tunnel 2 area with an old pumping-trap.

The condensate header and the pump have been relocated recently and the steam trap on the

motive steam line has not been re-installed. We recommend you to insert the steam trap again to

prevent from rapid erosion and steam leaks on the check valve at the pump steam inlet.

In a general way, there is no high back pressure in condensate return lines as you use 3

atmospheric condensate pumps. In Tunnel 1 and Eagle they are located at the same level or under

steam users. Thus condensate back-pressure is close to 0.

However in tunnel 1, some steam users located on the first floor are “under” the condensate pump

installed on the second floor. Therefore these steam users may be more sensitive to condensate

return back-pressure.


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8 Complete check list of all verifications done during the audit

Potential optimisation Status Comments

STEAM GENERATION

Steam pressure setting OK 7 barg is good compromise. 6 barg would certainly

be too low for distribution (lines sizing restrictions)

Feed water temp. to the boilers OK 93°C measured on the feedwater pump. Clayton

requires a minimum of 90°C

Stack temperature in front of

economizer

NA Not possible to measure on Clayton boilers.

Stack temperature after economizer OK Refer to combustion analysis or temperatures

reported in the BMS system (when repaired)

Combustion air temperature To be improved Ambient

Oxygen rate OK 5-7% depending on the firing rate

Boiler sizing OK

Boiler blow down rate To be improved Could be reduced to fit with Clayton

recommendations

Refer to optimization project n°1

Deaerator pressure NA Atmospheric feedwater tank

Feed-water pre-heating NA

Boiler stand-by time and volatility of

steam demand

OK Clayton steam generators have a good response

for these conditions

Boiler blow-down recovery NA Blowdown is too low at current steam demand to

recover energy within 5 years payback


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STEAM DISTRIBUTION

External leaks of steam or condensate

from pipes, flanges, etc.

OK No leak has been observed during the audit

System design, trapping points etc. To be improved Steam lines have all been interconnected to

distribute steam in both ways (from and to Eagle).

Steam line between Eagle and tunnels 1 and 2 is

undersized for high steam demands.

It misses many trapping points in front of control

valves and in “low points”.

Insulation To be improved Refer to optimization project n°3

Steam quality To be improved Steam quality is good at the outlet of the boiler

house but is progressively decreased by the lack of

drip legs in front of steam users

Steam pressure level To be improved There are many pressure reducing stations. The

pressure level is not always adapted to the steam

usage.

Water hammering OK No water hammering has been observed in the

distribution lines

STEAM USERS

Condensate drainage and air venting

from heat exchangers

OK

Steam traps To be improved 15% failed traps identified

Some traps are wrongly mounted (inclined,

reversed)

CONDENSATE AND FLASH STEAM RECOVERY

Condensate recovered OK

Sizing of condensate return lines OK

Flash steam recovery To be improved Flash steam could be recovered on condensate

receivers. A vent condenser exists in tunnel 2 but is

not used anymore.

Water hammering OK


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9 Recommended complementary studies

9.1 Additional energy-saving optimisations

Flash steam recovery

We have observed a significant flash steam loss from the vent of condensate header-tunnel 2.

A part of it is probably due to the leaking traps.

Therefore when the failed traps are replaced, the losses should be lower.

We noticed during our visit that there is a heat exchanger installed on the vent line. A part of sanitary

hot water was used to condense flash steam. However this recovery does not work anymore as this

sanitary hot water loop is no longer used in the building. The valves are closed.

We could not get any data about this vent condenser during the audit (kW ?, water flow ?).

However, it could be interesting to use this equipment in the future if you can find a need of water

preheating in the same area.

We have estimated some potential savings :


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Flash steam flow estimated ton/h 0,020

Energy loss kW 13








Flash steam flow estimated kg/h 0,020








9.2 Additional operational optimisations

Flooded heat exchangers:

Poor drainage of condensate from low temperature controlled heat exchangers could have an

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

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

phenomenon and possible solutions are described in details in appendix 2. Almost all anti-freezing

coils on GLATT equipments are operating under these conditions. 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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10 Appendix N°1: Determination of the January 2011 boiler house

efficiency

BOILER SIMULATION CLAYTON

Boiler operating hours (incl. hot stand-by hours) 6.240 hours/year

1. Fuel power input % LHV

Fuel type: 8

Fuel consumption during operating hours 61,1 Nm3/h

Specific weight of the fuel 0,77 kg/Nm3

Fuel consumption 47,2 kg/h

Lower heating value (LHV) 49318 kJ/kg (=38082 kJ/Nm3)

Higher heating value (HHV) 54608 kJ/kg (=42167 kJ/Nm3)

Fuel unit costs 25 €/MWh HHV (= 0,29 €/Nm3)

Fuel power input (LHV) 646,6 kW 100%

Fuel power input (HHV) 716,0 kW

Steam pressure 7 Bar(g) / 170,4°C sat.

Enthalpy steam 2768 kJ/kg

Temperature feed water to the boiler/eco 93 °C

Enthalpy feed water 389 kJ/kg

Latent heat of the steam 2380 kJ/kg

Max. theoretical steam production 0,98 ton/h

2a. Combustion losses (boiler only)

Temperature stack after boiler 160 °C

Temperature ambient air 18 °C

Excess air 45,0 %

Oxygen % flue gas (Dry volume) 7,00 %

Stack flow 15,82 Nm3/Nm3 fuel

Total stack flow 966,8 Nm3/h

Specific heat stack 1,37 kJ/Nm³.K

Power in stack (sensible heat) 52,14 kW -8,1%

2c. Economizer (non condensing)

Temperature stack after economizer 120 °C

Economizer inlet water temperature 93,0 °C

Economizer outlet water temperature 102,6 °C

Heat transfer efficiency 100%

Power recovered by economizer 14,7 kW 2,3%

2d. Air preheating from external source (Top of boiler house)

Combustion air required 14,85 Nm3/Nm3 fuel

Total combustion air flow 907,8 Nm3/h

Normal combustion air temperature 18,0 °C

Preheated combustion air temperature 18,0 °C Power recovered by air preheating 0,0 kW 0,0%


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3. Radiation losses

Boiler capacity 3,1 ton/h (=2MW)

Load 32 %

Radiation losses at full load 0,2 %

Radiation losses 4,1 kW -0,6%

4. Blow down

TDS Make-up water 50,0 ppm

TDS Feed water boiler 1520,0 ppm

Boiler water lost by blow down + carry over 3,4 % of steam output (30,4cycles)

Boiler feed water flow 1,319 ton/h

Boiler water lost by blow down + carry over

0,043

ton/h

X-value of the steam from the boiler 1,000

Blow down flow remaining 0,043 ton/h

Enthalpy blow down water 721 kJ/kg

Temperature make up water 12,0 °C

Enthalpy make up water 50,2 kJ/kg

Total Blow Down losses (Boiler + Deaerator) 8,1 kW -1,3%

Blow down losses compensated by boiler only 4,0 kW -0,6%

5. Energy losses due to excess of water

Feed water tank pressure 0,0 bar(g)

% of revaporisation (7 to 0 barg) 13,5%

Water excess 40,0 %

Feed water flow 1,319 ton/h

Condensate flow out of separator 0,484 ton/h

Condensate enthalpy 721 kJ/kg

Temperature make up water 12,0 °C

Enthalpy make up water 50,2 kJ/kg

Flash steam flow 0,066 ton/h

Energy loss from condensate 44,7 kW -6,9%

6. Boiler Efficiency and Fuel Costs

Net power output in steam from the boiler 556,4 kW ( 3472 MWh) 86,0%

Net steam production boiler 0,791 ton/h = 4938 t/year Boiler efficiency on LHV 86,05 %

BOILERHOUSE SIMULATION

Boiler house operating hours 6.240 hours/year

6. Steam consumption feed water tank % LHV

Measured make up water flow 0,29 m3/h

Enthalpy make-up water 50,16 kJ/kg

Feed water flow to boilers 1,32 m3/hr

Enthalpy feed water 388,74 kJ/kg

Enthalpy condensate from separator (liquid phasis) 712,30 kJ/kg

Enthalpy flash steam from condensate (separator) 2259,04 kJ/kg


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Temperature condensate from factory 95,00 °C

Condensate flow (from factory) 0,50 t/hr

Over heat 41,11 kW

Estimated flash flow lost 0,066 t/hr

Condensate return rate 69,3%

10. Overall Boiler House Efficiency

Net total power output from the boiler house (incl. CHP) 556,4 kW 100,0%

Boiler house efficiency on LHV 86,0 %

Boiler house efficiency on HHV 77,7 %

Annual fuel consumption (LHV) 4.035 MWh/year

Annual fuel consumption (HHV) 4.468 MWh/year

Annual CO2 emissions (50,6 kg/GJ / 182,2 kg/MWh HHV) 814 tons/year

Annual fuel costs 111.694 €/year

10a. Steam generation and steam costs

Net total steam power output from the boiler house 556,4 kW 100,0%

Net total steam heat output from the boiler house 3.472 MWh/year

Net dry steam production boiler house 0,724 ton/h = 4516 t/year

Annual fuel consumption (LHV) 4.035 MWh/year

Annual fuel consumption (HHV) 4.468 MWh/year

Fuel costs for steam generation 111.694 €/year 83,8%

Electricity unit costs 0,064 €/kWh

Electrical power for the boilerhouse 30 kW

Electricity costs 11.981 €/year 9,0%

Make up water unit costs 0,35 €/m3

Make up water costs 628 €/year 0,5%

Costs for chemicals 9.000 €/year 6,8%

Sewer unit costs 0,00 €/m3

Sewer costs 0 €/year 0,0%

CO2 unit costs 0,00 €/ton

CO2 Emissions ( 180,3 kg/ton of dry boiler house steam) 814 ton/year

CO2 costs 0 €/year 0,0%

Total variable steam costs 133.303 €/year 100%

Total costs steam from boiler house 29,52 €/ton

Total costs steam from boiler house 0,0384 €/kWh


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11 Appendix N°2: Steam Pressure Controlled Heat Exchangers at Low

Load


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

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

of the time the desired medium temperature is below 100°C, and the heat exchanger is working at

partial load. Under these conditions, regardless of brand or model, problems may occur due to the

physical properties of the steam.

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

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

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

partial loads are typical. Due to the variability of these problems they are often not recognized in

time, and can cause process bottlenecks, loss of production, loss of temperature control and

increased maintenance costs.

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

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

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

Modulating Controls

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

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

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

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

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


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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 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 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.

In the best case scenario the control system will balance the steam/product differential. However, in

most cases the following is observed:

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


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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.

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 control. 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). 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


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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.

11.2 Optimization

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

low/partial loads. Finding the most effective and efficient solution would require custom tailored

engineering. Basically there are three 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 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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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. The

diagram below shows a typical setup for this arrangement:

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.


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11.3 Savings

The installation of closed loop pumping trap systems, or a Posipressure system, 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 coil from freezing and prevent process time downs and

maintenance labour to repair.

11.4 Investments

Average budgetary cost for the installation of a closed loop pumping trap system on an existing heat

exchanger is 14000 €.

Average budgetary cost for the installation of a Posipressure system on an existing heat exchanger

is 8000 €.

Average budgetary cost for the installation of a Safety Drain on an existing heat exchanger is 1700€.

Included:

- Equipments supply (piping, pumping trap / Posipressure, valves etc. )

- Installation by a mechanical contractor

- Engineering and project management

Payback time for these optimizations depends on the specific situation.

Aranda de Duero, SPAIN STEAM AND CONDENSATE ENERGY …

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