7. Terrell - Boiler Feedwater Management

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Boiler Feedwater management

1

EEPC Ethylene Seminar

19-21 Oc tober 2011, Li sb on (Por tugal)

Rob Terrell, ABB Consulting, 21 October 2011




19-21 Octob er 2011, Lis bo n

© ABB Group

October 10, 2011 | Slide 2

Outline of Talk

• Process Coolers – or Boilers?

• Boiler Standards

• Waterside problems

• External treatment

• Internal Treatment

• Dosing and Control

• Summary





• Ethylene is produced by steam cracking:

• Hydrocarbon feed is diluted with steam and very briefly heated in a

furnace without the presence of oxygen at 750 –950 °C to induce free

radical reactions and form ethylene.

• In modern cracking furnaces, the residence time is reduced to

milliseconds to improve yield

• The feedstock may be naphtha, LPG, ethane or propane – the

choice of feedstock affects the downstream design

• The gas from the furnaces is immediately quenched to stop further

reactions occurring

• Conversion efficiency to produce ethylene is determined by theefficiency of the so-called Quench boilers or Transfer Line

Exchangers (TLE’s)

• Boiler design is a differentiating feature for the technology providers

Steam Raising – Ethylene Crackers

© ABB Group






Steam Raising – Ethylene Crackers - 2

• TLE design is a vertically mounted shell & tube heat exchanger with water

on shell side

• Popular design uses double tube design to ensure adequate cooling

immediately above bottom tubesheet

- Formation of steam bubbles in the water creates lift giving good

circulation

• But is it a process cooler for a critical duty – or a high pressure boiler with

unique design features…?

• From water perspective, presents specific challenges for the water

treatment and puts high demand on water quality

• Danger area is bottom tubesheet to avoid collection of deposits which

might lead to corrosion cells or cause blockage of double walled riser

tubes

• Depending on feedstock and technology provider, steam pressure may be

anywhere from 6 MPa to 13 MPa

© ABB Group






Boiler Water Quality Standards

• Feedwater and boiler water operating conditions are set by

• OPERATING PRESSURE

- Higher pressure boilers demand purer feedwater quality

• HEAT FLUX

- Rate of heat transfer per unit area of boiler tubes

- Higher heat flux boilers demand purer feedwater quality• BOILER DESIGN

- Temperature, flow rates, turn-down, ramp rates

• Manufacturer recommends operating control limits based on their experience

• International Design Standards give further guidance for acceptable operation

(ASME, EN, BS, VGB, JIS, etc.)• But are consensus standards for boiler water quality at different pressures,

heat flux and boiler design.

• Using the right feedwater quality is VITAL for the safe operation of boilers

• Getting the feedwater quality right allows more treatment options

- But a good internal treatment cannot make a poor feedwater good

© ABB Group






Water Standards UK BS2486:1997oiler Feedwater

Parameter

Non-Fired

Water Tube

Boilers > 8

MPa

Fired Water

Tube Boilers

> 12.1 MPa *

pH 9.3 to 9.8 8.5 to 9.5

Dissolved oxygen

(mg/kg O2)< 0.005 < 0.005

Total Hardness

(mg/kg)ND ND

Iron & Copper

(mg/kg)< 0.02 < 0.02

Parameter

Non-Fired

Water Tube

Boilers > 8

MPa

Fired Water

Tube Boilers

> 12.1 MPa *

pH - -

Phosphate

(mg/kg PO4)3 to 10 3 to 5

Oxygen

Scavenger

(mg/kg)

Hydrazine

or

DEHA

0.05 to 0.1 0.05 to 0.1

0.1 to 0.25 in

BFW

0.1 to 0.25 in

BFW

Dissolved solids

(mg/kg) < 50 < 10

Caustic alkalinity

(mg/kg)2 to 5 1 to 5

Silica

(mg/kg)1 to 5 < 0.5

oiler water

* At these pressures, control values should be agreed between the boiler

manufacturer and the operator. Values given in the table are for guidance only.© ABB Group






Impact on Steam Raising of Feed

Water Impurities

Impurity in feedwater

Substancecausing

problems inboiler

What do you see?

Where do you see it?

FeedSystem

Economiser BoilerCondensate

system

Calcium hardness Calcium carbonateSludgeScale X X

XX

Calcium hardness Calcium sulphate Scale X

Calcium hardnessand silica

Calcium silicate ScaleXX

Magnesiumhardness

Magnesiumhydroxide

Sludge X

Magnesiumhardness andsilica

Magnesiumsilicate

Sludge X X X

Silica Silica Scale X

Natural OrganicMaterial (NOM)

Organic molecules Corrosion X X

ProcessContamination

OilOil bound sludges

and cokeX

Dissolved orentrained oxygen

Oxygen Corrosion X X X X

Alkalinity(carbonate andbicarbonate)

Carbon dioxide Corrosion X X X

Free carbondioxide Carbon dioxide Corrosion X X X





Water Treatment for Boilers

• There are two treatment stages required to produce water of a suitable

quality:

• EXTERNAL TREATMENT

- reduction or removal of impurities outside the boiler

• INTERNAL TREATMENT

- conditioning of residual impurities within the boiler

• Best practice is to do as much work as possible externally and leave as little

work as possible for the internal treatment chemicals• Relying on treatment chemicals to compensate for sub-standard boiler

feedwater quality is likely to lead to premature failure

© ABB Group






EXTERNAL TREATMENT

© ABB Group






External Treatment Stages

• Removal of organic impurities (if required)

• Carbon filtration or Organic scavenging resin

• Removal of ionic impurities

• Demineralisation (deionisation)

- typically removes 92 to 98% of ions from water

- residual dissolved solids 1 to 3 mg/l, conductivity <= 5 mS/cm• Or Reverse Osmosis

- removes up to 98% of ions from water

• Polishing

• Mixed Bed ion exchange polisher

- removal of > 99.9% of ions from water

- residual dissolved solids << 1 mg/l, conductivity < 0.1 mS/cm• Or Electrodeionisation (EDI)

- Similar performance to MB, conductivity typically < 0.06 mS/cm

• Removal of Dissolved Oxygen

• Deaeration

© ABB Group






Selection of External Treatment Process

• Determined by pressure …

• Demineralised quality water required for boiler pressure > 6 MPa

- RO water quality not good enough by itself - unless two pass RO

• MB quality water required for boiler > 8 MPa

- EDI water of equivalent quality to MB water – if not better

• By economics …

• Demineralisation is cheaper than Reverse Osmosis for raw water withTDS < ~ 350 mg/l

• Mixed Bed polishing is cheaper than EDI

• And by “soft” factors

• Neutralisation of waste water

• Handling and storage of acid and caustic

• For high pressure, high heat flux process boilers, need MB polishedwater (or equivalent)

© ABB Group





19-21 Octob er 2011, Lis bo n Removal of “Natural”

Organics (NOM)

• It is important that residual organics in the raw water are removed in the

treatment process

• Residual organics may cause problems in the boiler

- Break down, especially at high pressure (> 6 MPa)

- Form organic acids which depress the pH of boiler water

- Generate CO2 which depresses the pH of condensate

• Result is corrosion of condensate mains

• Contamination of condensate with iron

• Anion resin adsorbs a large proportion of the natural organics from raw water

• Typically 70 % removal for each anion stage (including mixed bed)

• But irreversible fouling of resin may occur leading to poor water qualityand/or extended regeneration times

• RO is extremely good at removing NOM – but may suffer fouling

• If necessary, install a dedicated treatment stage if raw water organics high

• Activated carbon

• Organic scavenging resin

© ABB Group






Condensate

• Steam condensate should be pure water

• At least as good as MP polished water quality

• Already paid for purification, so want to recover and reuse as much as possible

• Biggest risk is of contamination

• Boiler water due to carryover- Generally not too harmful, already treated with chemicals

- But may contain caustic high pH corrosion in steam/condensate

system

• Leakage from, e.g. turbine condensers

• Leakage from process

• If have no way of purifying before use, can result in poor quality feedwater and

damage to boilers if undetected

• Recommend condensate polishing to ensure boiler feedwater quality is good

at all times

• As a minimum, must monitor condensate quality…

© ABB Group




Deaeration – The Removal of Oxygen

• Even extremely low concentrations of oxygen

can cause major corrosion problems in the

boiler

• These problems are most severe in high

pressure / high heat flux boilers, but are still

serious in low pressure boilers• Most vulnerable sections to attack are the

feedwater system and the economiser

• If oxygen reaches the steam drum of the

boiler, it will be stripped off - but will then

cause corrosion problems in the top of the

drum and the condensate system

• Primary removal of oxygen is external, but

oxygen scavenger still has to be added to

remove any residual oxygen

10

8

6

4

2

0

10080604020

D i s s o l v e d O x y g e n m g / l

Temperature oC

• solubility of oxygen is ~ 8 mg/l atambient temperature, falling to 0

mg/l at 100 oC



© ABB Group




Deaeration Problems

• In general, deaerators are passive and give very good performance over a widethroughput range - designed to operate as low as 30% of rated output

• Can be upset by:

• Rapid variations in throughput

• Variations in condensate return as percentage of throughput

• Variations in condensate temperature, especially if too hot

• Need DT > 15 oC to maintain performance

• Also suffer mechanical problems:

• Slow deterioration of internal gaskets, e.g. around spray nozzles

• Corrosion of sprays and trays

• Blocked sprays

• Deaerator cracking in storage tank

• Strongly recommend on-line dissolved oxygen analyser for HP boilers

• Also recommend thorough inspection of deaerator internals at plant turnarounds

• Must include inspection of sprays / trays



© ABB Group






INTERNAL TREATMENT

© ABB Group






SCALE

CONTROL

POLYMER TREATMENTS

PHOSPHATES

POLYPHOSPHATES

CORROSION

CONTROL

CARRYOVER

CONTROL

PHOSPHATESSODIUM HYDROXIDE

AMMONIA

pH CONTROL CONDENSATE

AMMONIA

MORPHOLINE

CYCLOHEXYLAMINE

METHOXYPROPYLAMINE

OXYGEN

SCAVENGERS

HYDRAZINE

METHYLETHYLKETOXIME

HYDROQUINONE

ERYTHORBIC ACID

DIETHYLHYDROXYLAMINE

CARBOHYDRAZIDE

AMINES

MONOETHANOLAMINE

Internal Treatment – HP Boiler

Treatment Chemicals

© ABB Group





19-21 Octob er 2011, Lis bo n Feedwater Treatment -

Oxygen Scavengers• Many different types available.

• Hydrazine

• Hydrazine substitutes, for example

- carbohydrazide

- diethylhydroxylamine

- hydroquinone

- methyl ethyl ketoxime

• Note: These products are all out of patent and are therefore not exclusive to anysupplier

• All the scavengers listed work

• But be aware there may be some (corrosive) decomposition products, e.g. organicacids, aldehydes, etc

• Oxygen scavenging reactions proceed quicker at higher temperatures

• But may be slow at lower temperatures in feedwater pipework and economiser• Reactions proceed quickest when pH is > 8.5

• (Still) Recommend use of hydrazine for high pressure / high heat flux boilers

• Simplest, least problematic breakdown products, easy to analyse, bestperformance and cheapest

• But MUST be handled correctly

• Oxygen scavengers are NOT substitutes for external oxygen removal © ABB Group






Feedwater Treatment – pH Control

• Important to maintain feedwater pH above 8.5 to

• Reduce feedwater system corrosion and

• Give the oxygen scavenger the best chance of working

• Normally rely on recovered condensate containing amines to control the

feedwater pH• But if polish the condensate, will also remove the amines and have to dose

pH control agent to raise the pH

• Most commonly use ammonia to raise pH

• Target is 9.0 to 9.5 if all steel metallurgy

• Target is 8.5 to 9.2 if copper or copper alloys present

• Alternatively may use volatile amines as part of boiler water treatment

program (see later) or condensate treatment program

© ABB Group






Boiler Water Treatment - pH Control

• We only treat boiler water because of impurities in the feedwater

• Extremely pure water would require no chemical treatment

• The less pure the water, the more chemical treatment we have to

add

• Sometimes it is necessary to add chemicals which can damage the

boiler to compensate for even more damaging contaminants• When selecting which boiler water treatment program to use, it is

essential to allow for ALL the operational conditions which occur -

changes in water quality, potential contaminants, etc..

• Primary control for High Pressure boilers is to stop corrosion by

controlling pH in a narrow band.

• Achieved by the addition of

- phosphates (if it is not used for scale prevention)

- sodium hydroxide

- ammonia and/or neutralising amines

© ABB Group




Boiler Water Treatment

Options for HP Boilers

7 8 9 10 11 12

INCREASING FEEDWATER IONIC CONCENTRATION

INCREASING FEEDWATER PURITY

INCREASING BOILER PRESSURE

4 MPa6 MPa9 MPa12 MPa

<0.1 5 to 101 to 3<0.2Approx Feedwater Conductivity microSiemens/cm

APPROXIMATE BOILER WATER pH

Oxygenated

Treatment

All Volatile Treatment

Coordinated or CongruentPhosphate Treatment

Phosphate +Caustic Treatment

Caustic +

Polymer Treatment

Note: This is a schematic diagram only and, for control conditions, reference should be made directly to International

Standards such as BS, VGB, ASME. Exact conditions vary with boiler design, fuel and operating conditions.

The boiler pressures and feedwater qualities indicated are approximate.

Phosphate +Caustic + Polymer

2 MPa3 MPa

Equilibrium

Phosphate

Combined

Oxygenated

Treatment


Coordinated or Congruent

Phosphate Treatment

Equilibrium

Phosphate

© ABB Group







• Uses amines to provide alkalinity plus hydrazine or other suitable oxygen scavenger(may be same amines as for condensate protection)

• Only used when the feedwater quality is extremely good and of consistent quality

• Amines not good enough to protect boiler if acidic anions (Cl-, SO42-) present

• Sodium leakage from demin plant will result in free caustic in the boiler

• Suitable for systems with high percentage of condensate return

• May be the only treatment suitable for very high rated industrial boilers

• Gives very high quality steam - suitable for high efficiency turbines

• pH typically controlled in range 8.7 to 9.2 - but can be managed as low as pH 8.0 if

feedwater is pure enough

• Amine concentration adjusted to give right pH

• Easiest treatment to control



© ABB Group




Neutralising amine Relative

Neutralising

Capacity

Relative

Basicity

Distribution

Ratio

Distribution

Ratio

Distribution

Ratio

ppm CO2 perppm amine

Kb * 10^6 0 psig 200 psig 1000 psig

Morpholine 0.506 3.1 0.4 1.6 0.98

MOPA 0.494 102 1.0 2.4 2.5

Ethanolamine 0.72 32 0.07 0.15 0.29

Ammonia 2.588 16 10 4.2

Choice of Amines for AVT

•Looking for low distribution ratio for boiler protection and high distribution ratio forcondensate system protection

• Higher basicity means using less treatment chemical

• But beware - if basicity is too high, low dosage rate may be difficult to control

adequately

• Typically use:

• Morpholine• Methoxypropylamine (MOPA)

• Monoethanolamine (MEA)

• But beware of corrosion/erosion problems in high flow areas with some amines






19-21 Octob er 2011, Lis bo n The Use of Phosphate in

High Pressure Boilers

• Phosphate is one of the oldest internal boiler treatments

• In LP and MP boilers it is used to prevent the formation of hard,insulating scales

• In MP and HP boilers, it is used to control the pH

• We use the BUFFERING capacity of phosphate to• Reduce the pH swings which would occur if we used caustic (a muchstronger base)

• Control the boiler water so that it does not contain any free caustic

- Which may be corrosive where there is a concentrationmechanism (under deposits, in crevices)

• But phosphate is subject to precipitation at high temperature• Known as Phosphate Hideout

• Can result in formation of deposits and wildly fluctuating pH

© ABB Group






Phosphate Treatment Programs

• The properties of phosphate have led to the development of differenttreatment programs:

1. Equilibrium Phosphate

2. Congruent Phosphate

3. Coordinated Phosphate

• These programs operate at different phosphate concentrations anddifferent pH ranges determined by the quality of the boiler feedwater

In simple terms:

• The purer the boiler feedwater,

- The lower the pH range required to prevent corrosion and

• The lower the phosphate concentration required toachieve this pH

© ABB Group




The Buffering Capacity of Phosphate

• Phosphate reacts with low concentrations of caustic to from different phosphate compounds

resulting in a smaller change in pH

• We can use this property to limit or prevent free caustic from being present in the boiler water

• Only adjacent pairs can coexist

• i.e. DSP can not exist in solution with caustic

• So if Na : PO4 ratio is < 3 : 1, caustic can not be present

PA MSP DSP TSP Caustic

H3PO4 NaH2PO4 Na2HPO4 Na3PO4 NaOH

phosphoric acid monosodium phosphate disodium phosphate trisodium phosphate sodium hydroxide

3210 >3Sodium to

Phosphate

Ratio

Addition of sodium hydroxide





Phosphate Hideout

• “Hideout" is the precipitation of "sodium phosphate" under high temperature conditions.

• Occurs

• At boiler pressures > 13 MPa continuously or

• At pressures as low as 9 MPa where the heat flux is high or under rapid load swings

• Occurs due to a fall in solubility of one particular phase of composition Na2.6H0.4PO4

which precipitates on the heat transfer surfaces

• Apparent loss of phosphate can result in a sudden - and alarming - change in pH of the

boiler water

• If Na:PO4 ratio in BW is < 2.6:1 when hideout starts, pH will fall rapidly

• If Na:PO4 ratio is > 2.6:1 in BW when hideout starts, pH will tend to remain steady or

rise due to the formation of free caustic - which will be corrosive under the

phosphate deposits

• If Na:PO4

ratio = 2.6 :1 when hideout starts, pH will fall in controlled manner

• Best defence is to actively manage the Na:PO4 ratio at ~ 2.6:1 (for boilers up to 12 MPa)

• Although pH will fall, it will recover when boiler load decreases.

• NOTE: phosphate hideout does NOT occur at lower

pressures/temperatures

• Ratio below 3:1 is maintained to prevent free caustic being present



Ph h t Hid t



Phosphate Hideout –

Impact on pH

aim to operate at

2.6 : 1

Na to PO4 ratio

1 2 3 4 5 6 7 8 9 10 20 30 40 50

10.3

10.2

10.1

10.0

9.9

9.8

9.7

9.6

9.5

9.4

9.3

9.2

9.1

9.0

2.22.32.62.83.0

p

H

Total ortho-phosphate (mg/l)

InitialComposition

Free

Caustic

Sodium to Phosphate Ratio





Caustic may not be a problem…

• Just because there is caustic in the boiler does not mean that it will fail

• Many medium to high pressure boiler treatments depend on caustic for protection

• Caustic is only a problem if it is allowed to concentrate

• Dry-out• Under deposits

• Departure from nucleate boiling

• Poor circulation at low rates

but caustic concentration can reach > 50% if the conditions are right…

• Caustic offers good protection when there are acidic ions present• e.g. chloride, sulphate

• and when there is silica in the feedwater

- Reduces silica volatility

- Controls silica deposition



© ABB Group




1. Equilibrium Phosphate Treatment

• Developed by EPRI to overcome problems of phosphate corrosion

• Aim to operate at a phosphate concentration where Phosphate Hideout is no

longer a problem

• Applicable to boilers operating > 10 MPa

• Control conditions are unique to each boiler

• Raise PO4 to 10 to 20 mg/l

• Allow residual to "decay" until stable

• Typical Operating Conditions:

• PO4 0.1 to 3 mg/l

• pH 8.3 to 9.3• NaOH < 1 mg/l

• Not (usually) applied for boilers operating at lower pressure

• Requires very high and consistent quality feedwater



© ABB Group




2. Congruent Phosphate Treatment

• Suitable for high quality feedwaters only.

• NOT suitable if acidic ions (chloride, sulfate) present or if sodium slip from

demin plant

• Uses blend of disodium phosphate and trisodium phosphate which gives a sodium

to phosphate ratio of 2.6:1 plus suitable oxygen scavenger

• When phosphate hideout occurs, pH change is limited and controlled

• Precipitated species is “congruent” with composition in solution

• Demands active management of the sodium to phosphate ratio

• You can’t just add a 2.6 : 1 blended product and ignore it…

• Suitable for boilers >11 MPa where phosphate hideout under load conditions is a

problem.

• pH controlled in the range 9.3 to 9.8

• Phosphate concentration 3 to 10 mg/l



© ABB Group


EEPC Eth l S i



Congruent Phosphate Treatment

1 2 3 4 5 6 7 8 9 10 20 30 40 50

10.3

10.2

10.1

10.0

9.9

9.8

9.7

9.6

9.5

9.4

9.3

9.2

9.1

9.0

2.22.32.62.83.0

p

H

Total ortho-phosphate (mg/l)

Sodium to Phosphate Ratio

aim to operate at

2.6 : 1

Na to PO4 ratio

Free

Caustic



© ABB Group


EEPC Eth l S i



3. Co-ordinated Phosphate Treatment

• Standard treatment for medium to high pressure boilers up to ~ 10 MPa with excellent

twin bed demineralised feedwater (or poor Mixed Bed quality feedwater + some returned

condensate

• Blend of phosphate designed to give a sodium to phosphate ratio of < 3 : 1

• Required if feedwater quality is less than perfect, i.e. slippage of acidic ions such as

chloride and sulphate or slippage of sodium ions from demineralisation plant• Allow the sodium to phosphate range in the boiler water to vary between 2.6 to 1 and

> 3 : 1 such that the water is either caustic-free or has only low concentration of

caustic at any time

• Not suitable for use in boilers where phosphate hideout occurs

• Presence of deposits undesirable in presence of caustic and other impurities

• Typically use PO4 in range 6 to 10 mg/l

• For better water quality, aim to restrict caustic excess to 5 to 10 mg/l.

• Control at pH 9.5 to 10.0

• A “poor man’s” congruent phosphate treatment… if the feedwater quality is not good

enough.



© ABB Group


EEPC Eth l S i

EEPC Eth l S i





Condensate Protection

• Low pH in the steam condensate, e.g. due to degradation of residual

organic contaminants, can result in condensate system corrosion

• Solution is to raise the pH by the use of volatile alkalis

• Amines are used where

• There is a high percentage condensate recovery• There is evidence of corrosion in the condensate mains (iron,

leakage)

• There is a turbine which needs to be protected

• Note: Primarily for use with phosphate treatments as these provide

no steam system protection

• If using AVT program, should not need to add additional amines –

but do need to check that chosen amine provide sufficient

protection to whole system



© ABB Group


EEPC Eth l S i




• Neutralising amines protect against low pH

• Use amines with low Distribution Ratio if protecting near system

- e.g. morpholine

• Use amines with high Distribution Ratio if protecting far system

- e.g. cyclohexylamine

• The higher the basicity, the higher the pH generated and the less you need

• Most amines have relatively low basicity and cannot be used to raise the pH

much above 10

• Control on the basis of pH in the returned condensate, not amine in the boiler

blowdown• Target pH for iron systems is > 8.5

• Target pH in copper and iron mixed systems is 8.9 to 9.1

• Confirm effectiveness by monitoring iron at strategic points in condensate return

system

• Use filming amines to protect against oxygen attack if oxygen ingress likely



© ABB Group





Neutralising amine

Relative

Neutralising

Capacity

Relative

Basicity

Distribution

Ratio

Distribution

Ratio

Distribution

Ratio

ppm CO2 per ppm

amineKb * 10^6 0 psig 200 psig 1000 psig

Cyclohexylamine 0.444 440 4.0 16 9.3

Morpholine 0.506 3.1 0.4 1.6 0.98

DMPA 0.427 40 1.7 5.2 3.3

MOPA 0.494 102 1.0 2.4 2.5

GE Betz Diamine 0.863 200 0.45 1.9 2.7

Ethanolamine 0.72 32 0.07 0.15 0.29

DEAE 0.376 66 1.7 4.5 3.4

Ammonia 2.588 16 10 4.2




© ABB Group







Which Treatment to Use?

Program

BFW QualityEase of

Use

Boiler Operating Pressure

< 0.1

μS/cm

< 0.2

μS/cm

< 0.3

μS/cm

< 1

μS/cm 10 MPa 11 MPa 12 MPa 13 MPa 14 MPa

AVT ?

Equilibrium

Phosphate ?

Congruent

Phosphate ?

Co-ordinated

Phosphate ? ?

© ABB Group







DOSING AND CONTROL

© ABB Group







Chemical Injection Points

• Oxygen scavenger MUST be added into the bottom of the storage

chamber of the deaerator or into the down-leg from the deaerator

• To allow as much time as possible for the chemicals to work

• To provide as much protection as possible to the BFW system

• Polymer treatments (if required to prevent fouling) should be added to

the BFW system downstream of the oxygen scavenger injection

• High DO may impair the polymer activity

• AVT and Condensate protection (if needed):

• Neutralising amines into the BFW line after the deaerator or with

the oxygen scavenger

- Treats all the furnaces together• Filming condensate treatments (amines, ACT, etc) to be added

directly into the steam (non-volatile)

© ABB Group







Chemical Injection Points - 2

• Historically phosphate has been added directly into the boiler steam

drum, but this may not be practical for plants with multiple furnaces

• Although will give the best control over boiler water chemistry

• Common line dosing of phosphate downstream of the deaerator is

possible as long as there is no direct steam attemperation

• Potential for corrosion in superheaters• But common line dosing gives poorer overall control, especially if

blowdown rates from the furnaces are different

• Caustic, if required, is normally added at the same point as the

phosphate treatment

• Recommend use of pre-formulated dosing chemicals without dilution

• Reduces need for chemical handling and dosing errors

© ABB Group







Blowdown control

• Continuous Blowdown (CBD) controls TDS

• Manually through hand-valve

• Automatically by TDS controller

- Based on cation conductivity measurement (KHI), not direct

conductivity (K25)

• Important not to blow the boiler down too much• Should aim to control between 90% and 100% of recommended

figure.

• Extra blowdown costs money, 1% blowdown = 0.25% energy

• Need minimum TDS value as well as maximum TDS value

• If using common-line dosing, small variations in blowdown rates may lead

to unacceptable conditions in some boilers – over- or under-concentration• Working to the average is not acceptable – every boiler needs to be

correctly managed

• Automatic blowdown control provides best results

© ABB Group







Control limits

• Boiler water control limits are set to minimise the operating risks to the boilers

• Based on extensive experience with a wide range of boiler designs andoperating pressures

• CONTROL LIMITS ARE NOT OPTIONAL

• Essential to control the boilers to ensure remain within the limits at all times

• Operating outside the limits, even for short periods, will result in cumulative,irreversible damage which will

• Shorten the life of the boilers

• Affect the operating efficiency

• even if the damage does not show itself immediately

• JUST BECAUSE IT HASN’T FAILED DOES NOT MEAN THAT IT WON’T FAIL!

© ABB Group







Control of Boiler Water

• First step is to set Inner and Outer Control limits

• Outer Limits set for

• Safety

• Economy

• Need to set both minimum and maximum limits!

• Aim to stay within Outer Limits 100% of time and within Inner Limits > 90%

• Allow time for effect of adjustment to show.

• Boilers have “lag” effect

• May take 24 hours for half the effect of any adjustment to be seen

• If within “outer” control limits, make adjustments in chemical dosing ratesof NO MORE THAN 5% in any day

• If your operators cannot achieve required level of control, try to do it yourself – itreally is a lot more difficult than you think it is!

Inner limits set forReliabilityEfficiency

© ABB Group







SUMMARY

© ABB GroupOctober 10, 2011 | Slide 45






Chemical Treatment of High Pressure

Boilers Simple Guide

• Control by numbers:

1. Make sure the feedwater quality is consistently excellent – and monitor

2. Deaerate to consistently high standard – and monitor

3. Use the minimum amount of the least damaging internal treatment that is safe,based on the feedwater quality

- The worse the feedwater quality, the more damaging the chemicaltreatment is likely to be…

4. Install, manage and maintain good chemical dosing equipment

5. Maintain the blowdown valves – automatic control will give better results

6. Set realistic, consistent Control Limits in accordance with best practice

7. Monitor, monitor, monitor. Apply Zero Tolerance approach to excursions

8. Respond appropriately to results to stay within Control Limits

9. Inspect, don’t assume

• Waterside failures are not inevitable. Failures after 15 or 20 years are“premature”.

• It is not a matter of luck – just good practice. Boiler damage is cumulative

© ABB GroupOctober 10, 2011 | Slide 46






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7. Terrell - Boiler Feedwater Management