DRAFT REPORT - IEA Clean Coal Centre

DRAFT REPORT

POWER PLANT DESIGN

AND MANAGEMENT FOR

UNIT CYCLING AND

LOAD FLUCTUATION

DR MALGORZATA WIATROS-MOTYKA

DEADLINE FOR COMMENTS – 5 JULY 2019

M A Y 2 0 1 9

I E A C L E A N C OA L C E N T R E A P S L E Y H OU S E , 1 7 6 U P P E R R I C H M O N D R OA D

L ON D ON , S W 1 5 2 S H U N I T E D K I N G D OM

+4 4 [ 0 ] 2 0 3 9 0 5 3 8 7 0

W W W . I E A - C OA L . ORG

POWE R PL ANT DESIG N A ND

M ANAGEME NT FO R UNIT

C YC LI NG AND LOAD

FLUCT UATIO N

I E A C L E A N C O A L C E N T R E – P O W E R P L A N T D E S I G N A N D M AN A G E M E N T F O R U N I T C Y C L I N G A N D

L O A D F L U C T U A T I O N

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AUTHOR DR MALG ORZATA WI AT R OS- MOTYKA

Malgorz ata . Wiatr os @ie a- coal . or g

IEA REPORT NU MBER

ISBN 9 78–9 2–9 029–

© IEA CLEAN COAL CEN T RE

PU BLICATION DATE

DEADLINE FOR COMMENTS – 5 JULY 2019

All comments should be emailed directly to the author

This is a draft report. It has been circulated for comment only and should not be quoted



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P R E F A C E

This report has been produced by the IEA Clean Coal Centre and is based on a survey and analysis of

published literature, and on information gathered in discussions with interested organisations and

individuals. Their assistance is gratefully acknowledged. It should be understood that the views expressed

in this report are our own, and are not necessarily shared by those who supplied the information, nor by

our member organisations.

The IEA Clean Coal Centre was established in 1975 and has contracting parties and sponsors from:

Australia, China, the European Commission, Germany, India, Italy, Japan, Poland, Russia, South Africa,

Thailand, the UAE, the UK and the USA.

The overall objective of the IEA Clean Coal Centre is to continue to provide our members, the IEA Working

Party on Fossil Fuels and other interested parties with independent information and analysis on all

coal-related trends compatible with the UN Sustainable Development Goals. We consider all aspects of

coal production, transport, processing and utilisation, within the rationale for balancing security of supply,

affordability and environmental issues. These include efficiency improvements, lowering greenhouse and

non-greenhouse gas emissions, reducing water stress, financial resourcing, market issues, technology

development and deployment, ensuring poverty alleviation through universal access to electricity,

sustainability, and social licence to operate. Our operating framework is designed to identify and publicise

the best practice in every aspect of the coal production and utilisation chain, so helping to significantly

reduce any unwanted impacts on health, the environment and climate, to ensure the wellbeing of societies

worldwide.

The IEA Clean Coal Centre is organised under the auspices of the International Energy Agency (IEA) but

is functionally and legally autonomous. Views, findings and publications of the IEA Clean Coal Centre do

not necessarily represent the views or policies of the IEA Secretariat or its individual member countries.

Neither IEA Clean Coal Centre nor any of its employees nor any supporting country or organisation, nor

any employee or contractor of IEA Clean Coal Centre, makes any warranty, expressed or implied, or

assumes any legal liability or responsibility for the accuracy, completeness or usefulness of any

information, apparatus, product or process disclosed, or represents that its use would not infringe

privately-owned rights.



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A B S T R A C T

As intermittent renewables increase their share of electricity generation, fossil units are being called

upon to operate in cycling modes more frequently, as opposed to the baseload modes for which many

were designed. More frequent and severe cycling can exacerbate damage through a variety of

mechanisms.

In this study, different modes of cyclic operation of fossil plants and strategies for managing the

negative impacts are identified. Options include new operating practices, use of advanced materials

and installation of improved control systems. Such measures can improve heat rates and reduce

number of forced outages in existing fossil plants.

This study also identifies potential trade-offs associated with technology selection for enhanced

flexibility. Examples from Germany, India, Poland and USA are given.



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A C R O N Y M S A N D A B B R E V I A T I O N S

ABS ammonium bisulphate

DCS distributed control system

EOH equivalent operating hours

ESP electrostatic precipitator

FAC flow accelerated corrosion (erosion-corrosion)

FEA finite elements analysis

FEGT furnace exit gas temperature

FGD flue gas desulphurisation

FSNL fast speed no load

HAZ heat affected zone

HP high pressure

HR heat rate

HRSG heat recovery steam generators

I&C instrumentation and control

IEACCC IEA Clean Coal Centre

IGCC integrated gasification combined cycle

IoT Internet of Things

IP intermediate pressure

MCR maximum continuous rating

MIC microbial induced corrosion

NDT non-destructive techniques

NDZ notice to deviate from zero

LP low pressure

OCGT open cycle gas turbine

OEM original equipment manufacturer

O&M operation and maintenance

PLF plant load factor

PWHT post weld heat treatment

RH reheater

SCR selective catalytic reduction

SH superheater

SNCR selective non-catalytic reduction

USC ultrasupercritical

VRE variable renewable energy



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C O N T E N T S

PREFACE 4

ABST RACT 5

ACRONYMS AND ABBREVI AT IONS 6

CONTENT S 7

LIST OF FIGU RES 9

LIST OF T ABLES 1 0

1 INTRODUCT ION 11

2 FLEXIBLE OPERATION O F POW ER PLANT S – CU RRENT STAT E AND MAIN

REQUIREMENT S 1 2

2.1 Flexible operating modes 12

2.2 Plant flexibility characteristics 12

2.3 Modes of life consumption of components/load cycling and its effects 15

2.4 Comments 17

3 INST RU MENT ATIO N AND CONT ROL (I&C) 1 8

3.1 Main types of I&C 18

3.2 I&C measures for improved plant flexibility 19

3.3 Comments 21

4 REDUCING MINIMU M LOA D 22

4.1 Stable combustion 22

4.1.1 Coal fineness and air/fuel flow optimisation 22

4.1.2 Online analysis of coal quality 23

4.1.3 Low excess air (EA) 24

4.1.4 Reliable flame monitoring 24

4.1.5 Tilting burners 24 4.1.6 Auxiliary firing with dried lignite ignition burner 24

4.2 Indirect firing (IF) 25

4.3 Changing the size and number of mills 25

4.4 Using more than one boiler 26

4.5 Thermal energy storage for feedwater preheating 27

4.6 Evaporator design 28

4.7 Sliding pressure 29

4.8 Economiser modifications (bypass and water recirculation pumps) 30

4.9 Comments 30

5 START-U P TIME IMPROV EMENTS 31

5.1 Reliable ignition 31

5.2 Repowering/integrating gas turbine 31

5.3 Thickness of wall components in boiler and turbine designs 32

5.4 External heating of boiler thick wall components 34

5.5 Advanced sealings in the turbine 34

5.6 Turbine bypass system 36



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5.7 Cleaning boiler deposits 36

5.8 Comments 37

6 LOAD RAMP RAT E IMPRO VEMENTS 38

6.1 Mill storage capacity 38

6.2 Frequency control 38

6.2.1 Condensate throttling 39

6.2.2 HP turbine bypass 39

6.2.3 Additional valve 39

6.2.4 Feedwater bypass 40

6.3 Auxiliary firing with dried lignite ignition burner in booster mode 40

6.4 Comments 40

7 PLANT PRESERVAT ION D U RING STANDBY PERIOD S 4 2

7.1 Water circuit 44

7.2 Boiler circuit 45

7.3 Reheater – turbine circuit 47

7.3.1 Condenser and feedwater heaters 48

7.3.2 Protective barrier films 48

7.4 Comments 50

8 POLLUT ION CONT ROL SY ST EMS 51

8.1 NOx Control – SCR & SNCR 51

8.2 Particulate control systems 53

8.3 Flue gas desulphurisation 53

8.4 Comments 54

9 IMPACT OF FLEXIBLE O PERAT ION ON OT HER PL ANT AREAS 56

9.1.1 Water and wastewater treatment 56

9.1.2 Auxiliary systems 56

1 0 IMPROVING FLEXIBILIT Y T HROU GH PLANT MANA GEMENT 57

10.1 Maintenance strategies 57

10.2 Fleet approach for plant maintenance management 58

10.3 Changes in operational procedures 59

10.4 Comments 60

11 COU NT RY PROFILES AND CASE ST U DIES 6 1

11.1 Germany 61

11.2 India 66

11.3 Poland 70

11.3.1 Rybnik, unit 4, Polish Energy Group (PGE) 72

11.4 USA 74

11.5 Comments 80

1 2 CONCLUSIONS 81

1 3 REFERENCES 84

SOU RCES FOR IMAGES 88



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L I S T O F F I G U R E S

Figure 1 Steam turbine EOH counter types (Chittora, 2018) 17

Figure 2 Different levels of I&C system (VGB, 2018) 18

Figure 3 Thermal energy storage example from GE (Schuele and others, 2012) 28

Figure 4 Comparison of lifetime consumption of superheater headers for design creep life of

100,000 hours and 200,000 hours (Reischke, 2012) 33

Figure 5 Part of Siemens HP turbine with the internal bypass cooling (Chittora, 2018) 34

Figure 6 Cold start-up time with and without HP internal bypass cooling (Chittora, 2018) 34

Figure 7 Example of HP turbine advanced sealing (Żbik, 2017) 35



Figure 10 Measures for fast load ramping (Chittora, 2018) 39

Figure 11 Increase of turbine swallowing capacity to use boiler storage (Chittora, 2018) 40

Figure 12 Boiler tube failures influenced by off load corrosion (Image courtesy of Uniper, 2018) 42

Figure 13 Pitting and blade failure in LP turbine (Image courtesy of Uniper, 2018) 43

Figure 14 Areas of the steam/water cycle affected by lay-up and start-up practices (Mathews, 2013) 44

Figure 15 Turbine blade before treatment (Image courtesy of Uniper) 49

Figure 16 Turbine blade after filming amine treatment (Image courtesy of Uniper) 49

Figure 17 SNCR temperature window with injection (de Havilland, 2019) 52

Figure 18 Share of energy sources in gross power production in Germany in 2018

(Clean Energy Wire, 2019) 61

Figure 19 Installed net power generating capacity in Germany 2002-2018 (Clean Energy Wire, 2019) 62

Figure 20 Estimated power demand in May 2012 and in May 2020 (Morris and Pehnt, 2014) 62

Figure 21 Old and new mill parameters of unit 7 Heilbronn station (Then, 2017) 63

Figure 22 Current installed capacity in India and projections for the future (Mazumder, 2017) 66

Figure 23 Country-wide flexibility potential based on universal metrics (Sinha, 2019) 68

Figure 24 All India – unit wise approach and capacities (Kendhe, 2019) 68

Figure 25 Power generation in Poland by source, as of 31 December 2017 (Szynol, 2018) 71

Figure 26 Past and predicted net electricity generation in Poland (Szynol, 2018) 71

Figure 27 Location and size of 200 MW+ units in Poland (Nabaglo, 2017) 72

Figure 28 Net power generation in USA, January 2007-17 (Hilleman, 2018) 75

Figure 29 Net capacity factors for coal plants from 2008 to 2017 (Black & Veatch, 2019) 76

Figure 30 Changes in coal plant’s net heat rate from 2008 to 2017 (Black & Veatch, 2019) 76



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L I S T O F T A B L E S

Table 1 Coal indicative start-up times (Parsons Brinckerhoff, 2014) 13

Table 2 Flexibility parameters of thermal power plants in europe: usual value/state-of-the-art/

best achieved (VGB, 2018) 15

Table 3 Critical power plant components likely to be affected by creep due to daily cycling and their

typical design lifetime (Kendhe, 2018) 16

Table 4 Critical power plant components likely to be affected by fatigue due to daily cycling and

their typical design start-up number (Kendhe, 2018) 16

Table 5 Market-driven approach for maintenance (VGB, 2018) 59

Table 6 Selected parameters of the plant operation after modifications to achieve 10% minimum

load (Then, 2017) 64

Table 7 Technical data of Heyden plant (Uniper, 2017) 64

Table 8 Flexibility improvement with the use of Siemens I&C in Neurath, Units D&E

(Chittora, 2019) 65

Table 9 Units and capacities identified for flexibility (Sinha, 2019) 67

I N T R O D U C T I O N



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1 I N T R O D U C T I O N

Historically, some power plant flexibility has been an important requirement to balance supply and

demand (IEA, 2018). However, in recent years the integration of variable renewable energy (VRE)

such as solar and wind into energy grids requires coal-fired power plants, to adapt to new operating

regimes to balance fluctuations in power output from intermittent energy sources. Flexible power

generation, in addition to other options such as grid and demand side management, has a key role in

ensuring adequate energy system stability (VGB, 2018).

‘Making a plant flexible is not ‘a plug and play’ solution, it is a journey’, as noted by Lockyer (2018).

This is because flexibility requirements vary between different power plants, depending on grid

characteristics, electricity market design and cost factors. For some, achieving low minimum load is

important while, for others, it is all about fast start-up and rapid ramp rates. A range of operations in

which a plant’s output changes, including starting up and shutting down, ramping up and down, and

operating at part-load is known as plant cycling (Lew and others, 2013).

Plants with dynamic cycling abilities, can take part in different markets (Then, 2017). However,

flexible plant operation can have a significant impact on a power plant and virtually all plant areas can

be affected. This is because of the increase in thermal and mechanical fatigue stresses in the different

parts of a coal-fired power plant which, together with corrosion, differential expansion and other

effects, often occurring in synergy, reduce the lifetime of many plant components (Daury, 2018;

Henderson, 2014). Unit heat rate reduction of 6–9% at 50% load operation and 25–35% at 30% load

operation is another detrimental effect, along with higher auxiliary power consumption and specific

CO2 emissions correspondingly increased (Pande and Samal, 2018). Additionally, when high

penetration of variable renewables is added to the electric grid, operating costs for fossil fuel plants

can increase by 2–5% on average (Hilleman, 2018).

Cyclic operation of power plant requires good understanding of all the issues involved, improved

monitoring of the plant operation and behaviour of critical components and a thorough strategy of

component inspection, modification and replacement (EPRI, 2013).

There are several measures that can make plant more flexible, including new technologies, processes

and plant operator skills (Then, 2017). Many of these are described in another report from the IEA

Clean Coal Centre (IEACCC) by Colin Henderson (2014). This report builds on the previous one and

presents an update on the topic. Here, technical means for achieving common flexibility requirements

for existing pulverised coal-fired power plants are described and examples of what has been achieved

so far in different countries are included as case studies. Design aspects for new plants for increased

flexibility are also included. Additionally, mitigation measures for damage arising from flexible

operation, power plant preservation during standby and plant management strategies are discussed.

F L E X I B L E O P E R A T I O N O F P O W E R P L A N T S – C U R R E N T S T A T E A N D M A I N R E Q U I R E M E N T S



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2 F L E X I B L E O P E R A T I O N O F P O W E R P L A N T S –

C U R R E N T S T A T E A N D M A I N R E Q U I R E M E N T S

This chapter describes the modes of flexible operation that will be needed to meet grid variability from

the widespread use of renewables. It reviews in general terms the flexibility capabilities of existing

units and of newer systems and examines some of the degradation processes that can result in

increased life consumption of components.

2.1 FLEXIBLE OPERATING MODES

Power plant flexible operation modes include: frequent start-ups and shut-downs, rapid ramp rates

and operating at low minimum load (VGB, 2018). Typically, cycling regimes can be classified as:

• two-shifting in which the plant is started up and shut down once a day;

• double two-shifting in which the plant is started up and shut down twice a day;

• weekend shut-down where the plant is shut down at weekends. This is frequently combined with

load-following and two-shifting;

• load-following where the plant operates for more than 48 hours at a time but varies its output as

demand changes;

• sporadic operation in which the plant operates for less than two weeks followed by shut down

for more than several days; and

• on-load cycling where, for example, the plant operates at base load during the day and then

ramps down to minimum stable generation overnight (Shibli, 2019).

As flexibility requirements vary between different plants, there is no ‘one-size-fits-all’ solution for all,

and the individual strategies required to balance the grid vary due to different specifics, technology

requirements and site conditions (VGB, 2018). However, a method that has become particularly useful

in some countries, as in Germany, is to enable very low load operation to reduce the number of

shut-downs required. This avoids the thermal stresses associated with starting up, shutting down and

ramping and consequent reduced life of many components (VGB, 2018). Shut-downs and start-ups are

associated with much greater life consumption and so cost more than load following. Cold start-ups,

after the plant has been shut down for 48 hours, are the most damaging.

2.2 PLANT FLEXIBILITY CHARACTERISTICS

Reducing the safe minimum load without requiring supporting fuels (oil, gas) also provides a larger

range of generation capacity, which helps to maintain plant operation at times when power demand is

low (Agora Energiewende, 2017). A minimum load of 10% and below is possible if various measures

are implemented, as demonstrated at some German power plants, including 800 MW Heyden




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(Kaminski, 2018). Even though operating at a very low minimum load reduces plant efficiency

significantly, with consequent higher fuel costs, the overall cost saving from avoiding shut-down will

generally make the practice worthwhile (VGB, 2018).

The start-up time of a unit is the time taken from start of operation until reaching stable minimum load.

This consists of two phases: notice to deviate from zero (NDZ) and then synchronisation to full load.

The notice to deviate from zero time covers the prior notice that a power plant requires to start up the

plant to the point of synchronisation to the grid. This includes preparation of the unit for start-up by

adjusting the boiler drum water level (in the case of subcritical units), purging the furnace of explosive

gases, lighting the burners to begin raising pressure, pressure raising, temperature matching,

blowdown of wet steam to drains and running the turbine to speed. The time taken to synchronise to

the grid varies depending on whether the unit is being brought into service from a ‘hot’ or ‘cold’ start

(see below).

The time from synchronisation up to full load depends on the design of the plant; for example, its size,

the initial material temperature and its ability to ramp these to the final conditions as the generator is

loaded. Table 1 summarises some coal-fired plant indicative start up times.

TABLE 1 COAL INDICATIVE START-UP TIMES (PARSONS BRINCKERHOFF, 2014)

Start Shut-down period, h Notice to synch,

min

Synch to full load,

min

Steam turbine

metal

temperature, °C

Hot <8 60–90 50 >400

Warm 8–48 120–300 85 250–400

Cold >48 360–420 90 205

Long term 420+ 200

There are three main types of start-up for coal-fired plants: hot, warm and cold, depending on the

temperature of the metal in the turbine (Cochran and others, 2013). Definitions of start-up type can

vary among manufacturers. Table 1 also shows the correlation between shut-down period and steam

turbine metal temperature typically used to define each start up type. Hot starts are defined as those

undertaken within 8 hours of coming off load and are generally seen during two shifting. During hot

start the metal equipment has retained much of its temperature and the steam condition can be

returned to that required for synchronisation in a relatively short time. Typically, 60–90 minutes is

sufficient to return to fast speed no load (FSNL) (when the energy is being applied to rotate to the

turbine but there is no generation of electrical power) and then synchronisation on to the grid (Parsons

Brinckerhoff, 2014).

Warm starts are usually defined as those undertaken within 8 to 48 hours of coming off load. With this

period, it is not possible to maintain the plant near to operating conditions, hence it takes longer and

costs more to return the unit to service. Significant input of heat over a longer period is required to




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return the unit to service – typically 120–300 minutes to FSNL and then synchronisation on to the

grid, depending on the time since coming off load.

Cold starts are generally defined as those undertaken after 48 hours of coming off load. During that

time the plant will have lost much of its heat. However, if the boiler is full of water and fuel ready, the

unit can be returned to FSNL and synchronisation within 300–420 minutes. If the unit has been offline

for a longer time and the boiler has been drained, then the boiler must be prepared, and many auxiliary

plants brought back into operation. In such instances it can take much longer to return the plant to

service.

Start-ups are expensive not only because of the life consumption of highly stressed components, but

also due to additional fuel costs resulting from reduced efficiency from operation at off-design

conditions and reduced generation in a context of fixed costs. The relative costs of hot, warm and cold

starts are broadly 1:2:4, from all effects, including efficiency loss and life consumption of components

(Henderson, 2018).

A unit’s maximum ramp rate is typically expressed as the percentage of maximum continuous rating

(MCR) per minute at which it can be brought up and down the load range once synchronised (Parsons

Brinckerhoff, 2014). There is a significant variation of ramping up rates reported by different operators.

For the older units they are generally around 2–5%/min, but for newer ultrasupercritical (USC) units,

it can be higher, at up to 8%/min (Domenichini and others, 2013; Szewczyk, 2017). The short-term

response of a steam turbine for frequency control can be 10%/min or faster (Henderson, 2018). A fast

start-up and shut-down capability enable a quick response to changing market requirements, for

example in two shifting operation. However, this must be balanced against the significant impact on

the lifetime of the various plant components.

Table 2 shows current flexibility parameters of thermal power plants (hard coal, lignite, combined

cycle gas turbine (CCGT) and gas turbine in Germany, according to VDE and VGB (2018). Data is

provided for the usual, state-of-the art USC plants as well as for potential future ones. Values represent

the designed figures, before implementation of possible measures to enhance flexibility. As indicated,

coal-fired power plant can achieve minimum load of 40% for a typical plant, 25% for USC and 15% for

potential ones. These values are lower than for lignite, CCGT and gas turbines. Ramp-up times for cold

and hot starts for hard coal-fired units are lower than for those firing lignite but higher than for

combined cycle gas turbines and gas turbines, which are much more flexible in this respect.




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TABLE 2 FLEXIBILITY PARAMETERS OF THERMAL POWER PLANTS IN EUROPE: USUAL VALUE/STATE-OF-

THE-ART/BEST ACHIEVED (VGB, 2018)

Plant type Coal Lignite CCGT Gas turbine

Load gradient, %/min 2/4/6 2/4/6 4/8/12 8/12/15

Load range, % 40–90 50–90 40*–90 40*–90

Minimum load, % 40/25/15 60/40/20 50/40/30* 50/40/20*

Ramp-up time for hot start, h 3/2/1 6/4/2 1.5/1/0.5 <0.1

Ramp-up time for cold start, h 7/4/2 8/6/3 3/2/1 <0.1

* as per emission limits for NOx and CO

2.3 MODES OF LIFE CONSUMPTION OF COMPONENTS/LOAD

CYCLING AND ITS EFFECTS

Power plants components are constructed using a range of materials with different properties and

thicknesses. These materials expand, contract and heat up at different rates, causing various types of

damage (Koripelli, 2015). Previously, when most plants operated in baseload mode and started cold

only a few times a year, the main, though not the only, damage mechanism was creep. Creep damage

takes place when the material microstructure transforms resulting in cracking. During cycling other

damage mechanisms such as fatigue, corrosion and expansion, often happen in synergy, and increase

component damage and failure rates. Thermal fatigue in cycling units results from large temperature

swings, such as from cold feedwater entering the boiler on start-up and from steam heating up, which

create fluctuating thermal stresses within single components such as superheaters (SH) or reheaters

(RH), and between components when materials heat up at different rates (for example, welds)

(Cochran and others, 2013). The number of applications of a given degree of cyclic stress to which a

component can be subjected before failure is known as the fatigue life of the component. Thermal

fatigue interaction with creep is called creep fatigue and this type of damage is more severe than either

standalone creep or fatigue (Koripelli, 2015). According to EPRI (2013): ‘Where operational cycling

is introduced on a former baseload unit, the residual life can be greatly reduced to between 40% and

60% of the original design life because of the combined effects of creep and fatigue’.

Other typical impacts of cycling include:

• stresses on components and turbine shells resulting from pressure changes;

• wear and tear on the auxiliary equipment that is only used during cycling;

• corrosion caused by oxygen entering the system during start-up or draining for example and

changes to water quality and chemistry, resulting from, for example, falling pH; and

• condensation from cooling steam, which in turn can cause corrosion of parts, leakage of water,

and an increased need for drainage (Cochran and others, 2013).




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In power plants, various components are usually designed for operation with a specific hours of creep

life and specific fatigue cycle life. However, cyclic operation of the unit is likely to impact and consume

both creep and fatigue life of major components of the unit. For some critical components Table 3

shows typical design creep life and Table 4 shows typical design fatigue life (Kendhe, 2018). As noted

by Kendhe (2018), daily cyclic starts/stops may lead to ~40% reduction in available fatigue life, and

~25 % in available creep life for every year of operation. Of course, the available creep and fatigue life

of the components would depend on the life already consumed in normal operation since

commissioning, before the start of cycling. Therefore, it is important to assess condition of critical

components and make suitable adaptations for cyclic operation.

TABLE 3 CRITICAL POWER PLANT COMPONENTS LIKELY TO BE AFFECTED BY CREEP DUE

TO DAILY CYCLING AND THEIR TYPICAL DESIGN LIFETIME (KENDHE, 2018)

Critical components likely to be affected by creep Typical design, h

Primary SH outlet header 180,000

Final SH elements (parts) 180,000

Final SH outlet header 250,000

Intermediate RH outlet header 180,000

RH crossover pipes 180,000

Final RH outlet header 180,000

Steam pipework 250,000

TABLE 4 CRITICAL POWER PLANT COMPONENTS LIKELY TO BE AFFECTED BY

FATIGUE DUE TO DAILY CYCLING AND THEIR TYPICAL DESIGN START-UP

NUMBER (KENDHE, 2018)

Critical components likely to be affected by creep Typical design starts, No

Economiser inlet header 1000

Turbine steam chest (Throttle valves) 1000

Economiser NRVs 1500

Economic inlet header stubs 1500

Drum furniture cracking 1500

Primary outlet header 1500

Boiler stop valves 1500

Down comer attachment welds 2000

Circulating pump bodies 2000

Final SH outlet header (2Cr) 2000

Final RH stubs 2000

Intermediate SH headers 3500

Drum shell (welds) 4000

Final SH outlet headers (P-91) 5000

Final RH outlet header 5000




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There are a number of systems available that can monitor the effects of operating in flexible mode.

Both the influence of creep fatigue and low cycle fatigue on component integrity are calculated while

the unit is online. Typically, the following components are monitored: headers, manifolds (HP

superheater, reheater), steam drum, separators, piping (such as elbow after HP/RH final stage

attemperators), T-pieces (in HP bypass for example) and Y-pieces (such as before HP turbine), and

the remaining service life of these components is thereby determined (Chittora, 2019). For example,

for turbine components, the remaining life can be calculated using an equivalent operating hours

(EOH) counter. Use of the latest (fourth generation) EOH counter (see Figure 1) allows more accurate

outage planning and so enhanced operational flexibility as it considers load changes (Chittora, 2018).

Figure 1 Steam turbine EOH counter types (Chittora, 2018)

Types of steel used in various plant components, their properties and resistance to damage

mechanisms are described in detail in the IEACCC report by Nicol (2014).

2.4 COMMENTS

Flexibility requirements may vary between different power plants, depending on markets and

economics. For some, achieving lower minimum loads is the priority while, for others, the focus is on

cycling, fast start-up and rapid ramp rates. Flexible operation impacts all plant areas. Thermal and

mechanical fatigue stresses, together with corrosion and differential expansion and other effects, often

occurring in synergy, reduce the lifetime of many plant components. Technical means exist for their

mitigation.

I N S T R U M E N T A T I O N A N D C O N T R O L ( I & C )



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3 I N S T R U M E N T A T I O N A N D C O N T R O L ( I & C )

Control systems are vital for power plant operation. They allow navigation between different loads

and ensure stable operation by adjusting all related process variables. They monitor and control the

temperature and pressure inside the boiler, the feedwater mass flow in the water-steam circuit, the

load point of the coal mills and the turbine valve positions (Agora Energiewende, 2017).

Older plant control systems behave differently during full load and part load operation (VGB, 2018).

Hence the upgrade of instrumentation and control (I&C) systems improves accuracy, reliability and

speed of control. For example, it allows operation of the plant closer to the material limitations of

important components, such as the superheater headers, which means running at high temperatures

without significantly reducing the lifetime of the material. In many plants, an upgrade of I&C is

combined with plant engineering upgrades such as retrofits of the boiler, burners or turbine or other

components (Agora Energiewende, 2017).

Reliable control systems are important for all aspects of flexible plant operation – minimum load, fast

start-ups, quick shut-downs and increased ramp rates. As noted by VGB (2018), optimisation of I&C

is the most cost-effective way to improve plant flexibility and should be a precondition for other

measures (described in Chapters 4, 5 and 6). There are various process optimisation software systems

available to power plant operators including those offered by ABB, GE, Siemens, and Uniper.

This chapter outlines briefly the types of I&C in power plants and identifies some of the related

measures for improving plant flexibility. Additional I&C measures for specific performance

improvement are described in Chapters 4–6.

3.1 MAIN TYPES OF I&C

There are three different levels of I&C automation in a power plant, namely: basic I&C; fully automated

I&C; and fully automated I&C interconnected to the Internet of Things (IoT) (see Figure 2).

Figure 2 Different levels of I&C system (VGB, 2018)




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The basic I&C (level C in Figure 2), includes all measuring and protective functions as well as the basic

monitoring and control of all processes needed to operate the plant.

Fully automated I&C includes automated start-up and shut-down as well as advanced unit control

concepts and diagnostics and energy measurement functions. Condition monitoring systems and

lifetime consumption monitoring are included.

Fully automated I&C interconnected to the IoT will mean that the power plant, including all its

processes and procedures, will be integrated in a digitalised environment. This will be done using

innovative technologies such as virtual reality (to plan outages, to simulate plant behaviour) or

augmented reality (to support maintenance work) as well as big data solutions to tap the potential of

predicted maintenance. Additionally, the plant will be linked to the company-wide network.

The last two levels, A and B, are preferable for flexible power plant operation as they allow assessment

of the plant status as well as automated operation of the plant.

To optimise I&C and enhance plant flexibility, it is essential to ensure that all the existing control loops

operate smoothly. They include: spray water control, feedwater control, enthalpy control, O2/air

control and circulation control. This should be ensured, followed by the identification of optimisation

potential and implementation of appropriate solutions.

3.2 I&C MEASURES FOR IMPROVED PLANT FLEXIBILITY

The following measures for I&C improvements to enhance plant flexibility have been suggested by

VGB (2018):

• Reliable temperature measurements of thick-walled components (inner wall and middle wall).

This is essential for evaluation of the thermal stress during plant start-up and shut-down and the

corresponding lifetime consumption. Temperature measurements directly affect the firing rate.

This means keeping temperature within the required boundaries by controlling the fuel firing rate

– if it is too hot, the fuel firing rate is reduced, and if it is too cool, the rate is increased. This

measure should be considered as a precondition for other measures. Reliable temperature

measurement will optimise start-up and ramp rate.

• Accurate and reliable control of start-up fuel. This measure is to improve start-ups. Accurately

controlled mass flow of the start-up fuel allows a gentle and reproducible start-up. Appropriate

actuators (flow control valves) and flow measurements are required. This activity should also be

considered as a precondition for the other measures.

• A model-based thermal stress calculator to optimise start-up and ramp rates. Using a dynamic

wall model with physical parameters, such as heat transfer and heat distribution, allows the

temperature difference from the steam temperature to be computed, which is usually measured




20

anyway. Then the available thermal stress margin can be used as a feedback for the start-up

controller to keep the temperature difference within its allowable range.

• Adaptation of measurement ranges. Operating at minimum load requires changes in the pressure,

temperature and flow operating conditions. Consequently, a ‘standard’ measurement rate may not

be enough for lower load operation and can lead to inaccurate measurements which in turn can

adversely affect the corresponding control. Therefore, new measurement measures should be

adopted. Again, this should be considered as a precondition for other measures.

• Automatic start-up program (one button start-up) can optimise start-ups. Such a program lights

burners automatically, rolls the turbine as soon as the required conditions are reached and realises

a smooth transition between individual start-up phases to avoid unnecessary waiting times.

Automated start-up is only possible when all related drains and vents are automated too.

• Start-up optimisation (firing rate, HP bypass) – this measure concerns primary power plants

with HP bypass and has potential to reduce the cost of start-up. Mass flow of start-up fuel needs

to be accurately controlled for a smooth and reproducible start-up. This requires proper actuation

(flow control valves) and flow measurements. An appropriate degree of automation (sequential

controls) is necessary.

• Optimisation of underlying control loops (spray water control, feedwater control, enthalpy control,

O2/air control and circulation control) is essential to achieve flexible operation of power plants and

leads to start-up optimisation, minimum load reduction and improved ramp rates. Generally, this is

because these control loops are usually commissioned only at nominal load, so their performance

deteriorates at new operating points such as a reduced minimum load. Also, flexible operation depends

on the dynamic behaviour of the process rather than the stationary one; hence there are new

requirements for existing control loops. This measure is a fundamental prerequisite for all three

flexibility improvements (minimum load, fast start-ups and shut-downs and rapid ramp-ups).

• Advanced unit control – this measure can optimise minimum load reduction and ramp rates.

Advanced unit control consists of feed-forward model-based approaches that have proven to be

suitable for improving dynamic plant behaviour. Simulation environments can be used to support

commissioning by reducing the time needed for online optimisation of relevant parameters.

• General-condition monitoring system – this measure aims mainly to reduce long-term O&M

costs and has a low to medium potential to improve flexibility. A condition monitoring system

monitors crucial components for damage and identifies which elements could cause a plant to

shut down unexpectedly. This allows the operator to focus on the specific areas where maximum

damage occurs. There are various tools available which enable plant operators to estimate which

equipment requires maintenance and when. There is more information in Section 10.1 where

predictive maintenance is described.




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3.3 COMMENTS

Instrumentation and controls are vital for all aspects of flexible plant operation – minimum load, fast

start-ups, quick shut-downs and increased ramp rates. As older plant control systems behave

differently during full-load and part-load operation, their upgrade improves accuracy, reliability and

speed of control. For example, new systems allow operation of the plant closer to the material

limitations of important components, which means running at high temperatures without significantly

reducing the lifespan of the material. Optimisation of I&C is the most cost-effective way to improve

plant flexibility and should be a precondition for other measures. There are various process

optimisation software systems available.

R E D U C I N G M I N I M U M L O A D



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4 R E D U C I N G M I N I M U M L O A D

Reducing a unit’s minimum load capability will minimise the number of shut-downs required. There

are a number of aspects to achieving this. They centre on the boiler, fuel supply and combustion

systems. Reducing a boiler’s minimum load capability can be achieved for new boilers for example, by

paying special attention to evaporator design and, in existing systems, by carrying out economiser and

other modifications as well as by changes to operational practice (Henderson, 2014). Another aspect

to consider is the effect of low load operation on downstream NOx control systems and connected

equipment. This is covered in Chapter 9.

4.1 STABLE COMBUSTION

Stable combustion must be maintained at all times but is particularly important for achieving a

considerably reduced minimum load operation, when it will be more difficult to maintain the required

conditions. This is for safety reasons as well as to ensure efficient combustion with acceptable metal

temperatures in the boiler systems to minimise the detrimental effect on generation efficiency and to

keep within emissions limits and by-product quality controls. Hence it is important to understand and

mitigate the technical limitations to low burning rates. These include: fire stability, flame monitoring,

and minimising unburned coal and CO emissions. Fire stability depends on many factors, such as

changes in firing rate or fuel quality, inaccurate fuel:air ratio or uneven coal flow (Agora Energiewende,

2017).

4.1.1 Coal fineness and air/fuel flow optimisation

As said before, stable combustion is key for low load operation. It depends on many factors, including

coal quality, coal fineness, air:fuel ratio and air flows (primary, secondary, tertiary) at each burner. It

has been reported that at least 75‒80% of opportunities to improve the combustion performance at

most pulverised coal-fired plants depend on a reduction in coal particle size (Storm, 2006).

Consequently, improving particle fineness and mill performance should be a prerequisite to

combustion optimisation, especially for the reduced loads that concern us here. Accurate, reliable and

real time measurements are necessary before such optimisation takes place.

In recent years there has been considerable development of systems that measure particle fineness.

Based on several operational techniques, such as acoustic emission, electrostatic, laser and white light,

most of these technologies allow the simultaneous measurement of particle fineness as well as particles

and air velocities and fuel concentration. Most importantly, they provide reliable, real-time results.

Consequently, the direct modification of coal fineness can take place. This is achieved by several

methods, including: ensuring the correct/optimal raw coal size and its supply to the mill; keeping mill

grinding elements in good condition; applying the correct grinding pressure; setting the correct throat

clearance and air flow; maintaining the classifier and suitable mill inlet and outlet temperatures.




23

Regardless of the chosen technology, it is important to sample simultaneously all coal lines of all mills

to ensure the desired fuel fineness at all burners. More on this topic can be found in another IEACCC

report by Wiatros-Motyka (2016).

All air flows in a power plant must be measured and controlled to achieve optimum combustion at the

boiler and to avoid problems such as excessive furnace exit gas temperature, secondary combustion,

overheating in the back-pass as well as slagging (Wiatros-Motyka, 2016). However, this is not an easy

task, especially under the extremely low loads that are being considered here. Combustion air streams

in power plants are turbulent and stratified, hot, moist and laden with particles and debris. Additionally,

air ducts to and from different mills have various geometries and lengths which impact air

measurement devices, especially the more traditional ones (those used since the 1950s and 1960s), as

most of them require the installation of sufficient straight and obstacle-free pipe lengths. Additionally,

many also require field calibration. Most portable devices used to calibrate these systems require a

laminar flow that does not exist in most combustion airflow ducts. Moreover, many devices provide

air flow measurements based on an assumed cross-sectional area of the given air duct. However, air

ducts expand and contract under hot and pressurised conditions, so their cross-section changes. Hence

such measurements can have a considerable error. More advanced technologies for combustion air

flow measurement attempt to deal with the difficulties of measuring turbulent and stratified flows.

These measurement systems range from advanced pitot tubes, through electrostatic based systems, to

virtual and optical sensors. The new systems are more accurate than the old ones and designed to avoid

clogging, corrosion and breaking. But all technologies have limitations and care should be taken to

check product specifications for limitations regarding temperature, flow, particulate, moisture, straight

run and more.

Similarly, it is necessary to control and optimise fuel distribution from each mill to its corresponding

burners. Having accurate fuel flow measurements, in all coal pipes, allows effective use of the flow

distribution devices. Recently, there has been considerable development in such systems. The most

advanced systems are effective in rope breaking, have low pressure drop hence a minimal effect on

the primary air distribution, can be installed in different pipes/configurations and with different mills,

and in most cases can be controlled automatically. More on these systems can be found in the report

by Wiatros-Motyka (2016) from the IEACCC.

4.1.2 Online analysis of coal quality

Coal quality impacts all aspects of flexible operation – minimum load, ramp rates and start up. Using

an online coal analyser helps to maintain flame stability and optimal combustion, leading to fewer trips

and faster mill response time (VGB, 2018). It is also an important prerequisite for other measures such

as one mill operation – a requirement for extremely low load running.




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4.1.3 Low excess air (EA)

Low excess air improves plant thermal efficiency by minimising the flue gas heat loss and power

consumption of fans (Daury, 2018), but it can make utilisation of high carbon ash more difficult, which

decreases efficiency. Full burnout and stable combustion must be maintained, even during low load

operation, as highlighted above.

Although oxygen measurement is a useful tool in accessing excess oxygen and is used to trim the

excess oxygen set-point and adjust the air/fuel flow, it can be affected by air ingress to the boiler.

Therefore, it should always be accompanied by CO monitoring, which is considered the most sensitive

and accurate indicator of incomplete combustion (Lockwood, 2015). As the flue gas in the convective

pass is relatively ‘stratified’ (as individual columns emitted by each burner) localised regions of high

CO and O2 can be present even in the economiser exit. Hence, it is of paramount importance to choose

not only the most suitable system but also to have the sensors placed at multi-point representative

locations so that accurate readings and consequent optimisation can take place.

There are a number of instruments which can be used to measure and/or control excess air and hence

allow optimisation of combustion. Examples include the boiler optimisation system Digital Boiler +

from GE, which can operate in two modes: low excess air mode and low load stability mode (Daury,

2018). Many systems useful for low excess air operation are described in other reports from the

IEACCC (Wiatros-Motyka, 2016; Lockwood, 2015).

4.1.4 Reliable flame monitoring

Stable combustion for minimum load operation with flame stability requires reliable flame monitoring.

Direct flame monitoring is better suited for minimum load operation than the zonal one (VGB, 2018).

Sensors should be installed at least for the burner levels active during the minimum load operation.

Flame scanners must be calibrated for low load operation. Reliable flame detection is a measure which

may also allow more reproducible start-ups (VGB, 2018).

4.1.5 Tilting burners

During minimum load operation the live steam temperature as well as that of the reheated steam

generally decreases. Installation of tilting burners allows positioning of the flame in such a way that

heat transfer can be shifted from the radiative surface to the convective heating surface. This helps to

keep the temperatures in an acceptable range and to avoid reheat attemperation at partial load (VGB,

2018; Brüggemann and Marling, 2012).

4.1.6 Auxiliary firing with dried lignite ignition burner

Auxiliary firing is a process of stabilising the fire in the boiler by combusting auxiliary fuels such as oil

or gas, in addition to the pulverised coal fired burners. This results in an overall lowering of the stable

firing rate in the boiler. It can be also used for quick increases to the firing rate, which in turn have a




25

positive impact on the ramp rate (Agora Energiewende, 2017). Auxiliary firing can also facilitate

minimum load reduction. For example, Michels (2016) reported that at the Jänschwalde lignite firing

plant in Germany, replacing the ignition burners operating on heavy oil and gas with dry-lignite

ignition burners and using plasma to ignite the lignite at the lance near the burner exit, resulted in a

minimum load reduction from 36% to 26%. The additional advantage of operating the burner with

dried lignite is that it reduces the need for high quality and more expensive fuels such as oil and gas

(Agora Energiewende, 2017). Auxiliary firing systems can also improve the overall efficiency of the

power plant, according to FDBR (2012).

4.2 INDIRECT FIRING (IF)

Conventional pulverised combustion systems pulverise the coal immediately prior to sending it to the

boiler burners. Coal milling can be decoupled from the rest of the combustion train by conversion to

indirect firing. This involves the addition of a pulverised coal storage vessel between the coal mills and

the burners. The result is a reduction in the inertia of the system, allowing ramp rates of up to 10%/min

and it avoids the need for a supplementary fuel for start-up (Henderson, 2016). Other advantages

include a faster response to instabilities in firing, which results in stable firing at low load (Agora

Energiewende, 2017).

With direct firing, pulverisers must decrease their load during low load operation. Whereas with

indirect firing, mills can operate at nominal load even if pulverised coal is not instantly required as it

can be stored in the silo. Maintaining nominal mill operation during load operation reduces net power

fed into the grid.

As direct firing requires coal mills to operate under part load during periods of low plant loading, their

efficiency decreases which results in an increase in CO2 emissions. While in indirect firing, coal mills

maintain their nominal load and can operate with optimal efficiency. Consequently, CO2 emissions are

reduced.

Indirect firing in combination with other measures can lead to a significant decrease in minimum load.

For example, according to Jeschke and others (2012), indirect firing, in addition to a stage vortex

burner retrofit, can decrease the stable minimum load firing rate to 10%. Indirect firing is also

applicable to other burners including jet burners.

Reaching a stable low load fire also means savings of the ignition fuels such as gas and oil. According

to Agora Energiewende (2017), a low stable fire can reduce the need for ignition fuels by as much as

95%.

4.3 CHANGING THE SIZE AND NUMBER OF MILLS

In a conventional direct firing configuration, reducing the net power of a power plant requires both

the burners and the mill to operate in part load. Reducing the mill load leads to an uneven air:fuel ratio




26

and can affect flame stability (VGB, 2018). Hence as at a certain firing rate the fire becomes unstable,

low load operation must be limited to avoid damaging pressure pulses that can occur in the boiler.

Generally, maintaining fire and flame stability determines the lowest threshold for low load operation

(Agora Energiewende, 2017).

Therefore, at certain net power outputs, it is feasible to shut down some mills and have the remaining

ones operate closer to their design conditions. As one coal mill typically supplies fuel to a single burner

stage, turning off a mill leads to boiler operation with a reduced number of burning stages. During

single-mill operation, only the highest burner stage is operated to release heat ‘higher’ in the boiler.

This, in combination with more excess air, compensates for lower steam and flue gas temperatures by

creating a cooler flame and more flue gas, according to Heinzel and others (2012).

Single mill operation can lower the minimum load considerably, while increasing operational stability,

in comparison with two-mill operation. This is because the limitations for minimum load operation are

shifted from boiler side (mainly flame stability) to other parts of power plant such as the water-steam

circuit. In the boiler, the lower load operation requires switching from variable pressure to minimum

pressure operation. Appropriate pressure levels in the water-steam circuit can be maintained by

holding back steam flow at the mid pressure turbine inlet (Agora Energiewende, 2017).

One mill operation should be accompanied with other options such as air/fuel flow optimisation

(see Section 4.1.1), burner modification and other measures to ensure flame stability, such as flame

scanners.

There are a number of power plants which have reduced their minimum load to about 10% by

implementing one-mill operation, among other measures. They include the Heyden plant in Germany

(see Section 12.1).

Minimum load operation can be also improved by installation of more, but smaller, mills. Although

this measure can have great potential to improve plant flexibility, it also requires high investment.

Hence, is more applicable to new plants. Similar to one-mill operation, it must be synchronised with

fuel quality and other measures such as air/fuel flow optimisation (VGB, 2018).

4.4 USING MORE THAN ONE BOILER

Using more than one boiler to supply steam to a single turbine increases plant flexibility and allows

load changes similar to those of modern gas-fired power stations (Henderson, 2014). For example,

two USC 500 MW boilers connected to one 1100 MW turbine can achieve a minimum load of 10%

(Szewczyk, 2017).

There are many advantages of having two boilers connected to one turbine, according to Browarski

(2018). They include sharing plant transport infrastructure, a water cooling system and pollution

control equipment such as FGD. Additional benefits include reducing Capex by 25–40%, on average.




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4.5 THERMAL ENERGY STORAGE FOR FEEDWATER PREHEATING

Thermal energy storage can be used for storing heat for later release. It influences net power without

changing the firing rate in the boiler. Typically, the feedwater is preheated in a heat exchanger with

steam extracted from the turbine. This increases the plant efficiency and offsets the loss of turbine

power caused by steam extraction. Releasing or absorbing heat to or from the feedwater has a direct

impact on net power, as it influences the quantity of steam extracted from the turbine (Agora


The use of a hot water storage system, which can operate for 2 to 8 hours, can reduce the minimum

power fed into the grid by 5–10%, according to Smith and Schuele (2013). Discharging the stored

thermal energy can temporarily increase net power by 5% without increasing the firing rate.

Storage system operation consists of charging and discharging cycles. During charging, the heat from

the feedwater is transported to the storage system. To maintain a constant feedwater temperature,

more steam must be extracted. This results in a reduction of net power. As charging takes place during

low load periods it results in reduction of the minimum load.

Small water tanks, for operation of less than 30 minutes can be used to improve the ramp rate (Smith

and Schuele, 2013). Other options for increasing ramp rates are discussed in Chapter 5.

More flexibility can be achieved by installing storage systems for the low- or high-pressure feedwater

(Chittora, 2018; Browarski, 2017). Figure 3 shows a simple example from GE using a storage tank

incorporating hot and cold water, with displacement of each by the other during the increased or

decreased power requirements.

At reduced output, hot water is taken off from the outlet of the deaerator whereas low pressure (LP)

condensate feed is increased. More steam extraction reduces output. When more power is needed, LP

feed heaters are bypassed, and the cold condensate displaces the hot condensate and no LP or

intermediate pressure (IP) bleed steam is required. Increased storage of hot water displaces cold water

and vice-versa. A more complex variant is available and uses additional feedwater heaters (Henderson,

2018).




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Figure 3 Thermal energy storage example from GE (Schuele and others, 2012)

4.6 EVAPORATOR DESIGN

Large load changes require that the amount of fuel and water fed transiently into the furnace be altered

significantly, individually and quickly in comparison with a steady condition. During low rates of

change in load, the amount of fuel and water fed into the furnace is readily adjusted to keep both inputs

balanced. However, when the load change rate is high, the temperature of the superheater and reheater

may differ from specification due to unexpected changes in the heat absorption of the furnace caused

by fluctuations in the heat input. These factors may limit the rate of load change. Consequently, a

furnace water wall system with good flow characteristics and flow stability is essential to improve the

rate of load change (Yamamoto and others, 2013).

Vertical internally rifled or ribbed tubing will enable higher heat transfer rates at lower water flows

(Reischke, 2012; Yamamoto and others, 2013), facilitating low load operation. Boilers with vertical

tube evaporators have several advantages over spirally wound types, as noted by Yamamoto and others

(2013). For example, they have a smaller pressure drop than spirally wound ones because of the lower

mass velocity and shorter tube lengths. Hence their boiler feedwater pump power consumption can

be lower. Additionally, vertical tube boilers have a simpler structure, so furnace supports such as

stiffeners and attachments can be significantly simplified, making their installation and maintenance

easier. As the furnace wall tubes are positioned vertically, ash can fall off easily, so less adheres to the

furnace wall. This is important especially when a high-slag coal such as subbituminous is used.

Furthermore, for spiral boilers, when the heat absorption of certain water wall tubes increases, due to




29

the detachment of slag or other factors, the metal temperature of the tubes can rise excessively. This

is compounded by the fluid flow rate being reduced due to the significant increase in friction caused

by the sharp rise of fluid volumetric velocity as the specific volume increases. Such temperature

increases in evaporator tubes can result in their deformation in a short time, shortening their lifespan.

For vertical tube boilers, in contrast, the fluid flow reduction in tubes with such transitional increases

of heat absorption is lower, so the increase in tube temperature is very limited. It must be noted that

although vertical tube boilers generally have good flow characteristics, the extremely low mass

velocity increases sensitivity to heat absorption changes. So, it is important to select appropriate mass

velocity to maintain good flow stability (Yamamoto and others, 2013).

Also, the static and dynamic stabilisation of a spiral wound evaporator of a boiler can lower minimum

load (Hamel and Nachtigall, 2013).

4.7 SLIDING PRESSURE

Traditionally, throttling has been used to vary output from a turbine while keeping the pressure

constant (Lindsay and Dragoon, 2010). However, in recent years sliding pressure operation has

become a commonly applied system in many power plants (Henderson, 2004). A critical constraint

on ramping operation is matching steam and turbine metal temperatures, and more rapid output

changes can be achieved using sliding pressure. The procedure also offers advantages over throttle

control during a start-up by establishing a flow to the turbine earlier in the sequence with lower overall

heat input. It also allows the retention of high temperatures on shut-down (Henderson, 2014).

However, as with everything, there are some disadvantages of sliding pressure operation. These

include:

• increased oxygen attack from condenser air in-leakage;

• release of steam bubbles in the economiser and primary evaporative sections on pressure

reduction which can lead to localised erosion-corrosion especially in horizontal sections, such as

the floors and roof sections;

• departure from nucleate boiling (DNB) in lower tube sections resulting in increased

concentrations of solids, corrosion and local overheating; and

• local overheating and thermal fatigue arising from disruption in flow at low loads (EPRI, 2013).

These negative effects can be mitigated by designing the boiler for sliding pressure operation.

According to Yamamoto and others (2013) such a design should incorporate a vertical evaporator with

internally rifled tubing as these are superior to spirally-wound-type with smooth tubes

(see Section 4.6).




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4.8 ECONOMISER MODIFICATIONS (BYPASS AND WATER

RECIRCULATION PUMPS)

As mentioned above, in existing units, carrying out economiser modifications can lower the minimum

load. The right temperature of the flue gas at the economiser outlet, needed for correct NOx control

operation (SCR), can be maintained by forwarding the feedwater to the evaporator by using an

economiser bypass. Conditions in the economiser must be right, such that there is an adequate

sub-cooling of the feedwater to prevent steaming (Henderson, 2014; VGB, 2018). For example, the

adjustment of a steam generator’s flue gas temperature after the economiser by adding an economiser

water-side bypass, together with feedwater recirculation pumps and pipework, achieved 30%

minimum load without economiser steaming (Hamel and Nachtigall, 2012, 2013).

4.9 COMMENTS

Operation with low minimum load minimises the number of shut-downs required which means lesser

impact on plant component life and lower operating costs. Minimum load as low as 10% is possible

with several measures implemented. There are a number of measures to achieve the low minimum

load. Those centre on the boiler, fuel supply and combustion systems. Stable combustion is a key to

achieving low minimum load operation. Successful measures deployed by various plants include:

ensuring coal quality and particle fineness, operation with low excess air, flame monitoring, fuel/ air

flow control systems, tilting burners, auxiliary firing with a dried lignite ignition burner, operation

with a lesser number of mills and only top-level burners, deploying smaller mills, thermal energy

storage for feedwater heating, vertical internally rifled evaporators, a sliding pressure operation and

economiser modifications.

S T A R T - U P T I M E I M P R O V E M E N T S



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5 S T A R T - U P T I M E I M P R O V E M E N T S

Start-up procedures are complex and expensive as they usually require auxiliary fuel such as gas or oil,

during the burners’ ignition time. Shortening start-up time and the ability to ramp up rapidly ensure a

quick response to changes in market conditions and allow plants to participate in different markets,

such as for ancillary services (VGB, 2018). There are several ways to shorten start-up times in power

plants. The main ones are described below. Some of the measures defined in the previous chapter are

also helpful for improving start-up.

5.1 RELIABLE IGNITION

Reliable ignition is a basic requirement for optimising start-up. Both plasma and electrical ignition can

optimise the start-up procedure and therefore shorten the time it takes (VGB, 2018). In the first case,

coal is ignited by hot plasma flow, so no starter fuel is required which makes significant savings

possible. The plasma ignitor such as the one developed by GE Power Solutions can be applied to

various solid fuels including biomass, hard coal and lignite as well as coal with low volatile matter

content (Withworth, 2016).

During electric ignition, coal is ignited by a hot burner nozzle heated directly by the electrical energy.

Hence significant saving can be made on ignitions fuels such as oil and gas (VGB, 2018).

5.2 REPOWERING/INTEGRATING GAS TURBINE

A gas turbine can ramp up more rapidly than a coal-fired steam turbine. For example, for hot start, a

state-of-the-art open cycle gas turbine (OCGT), takes about 5 to 10 minutes (Jeschke and others, 2012),

while a hard coal-fired power plant can take around 1 hour or more (Henderson, 2014). Repowering

of a coal-fired plant with a gas turbine increases the gross output of the power plant, improves the total

efficiency, start-up efficiency and increases ramp up rates. Repowering involves placing a gas turbine

upstream of the water - steam circuit and then transferring the thermal energy in the exhaust steam of

the gas turbine to the feedwater via heat exchangers. An increase in the gas turbine power output

increases the heat transfer to the feedwater of the feedwater-circuit. This reduces the quantity of steam

extracted from the steam turbine, resulting in increased steam turbine output (Agora Energiewende,

2017).

Repowering is especially helpful for start-up improvements as the gas turbine can provide power while

the water-steam circuit is still heating up. An increase of about 6.6% of the nominal power output has

been reported at Unit G and Unit H at Weisweiler power plant in Germany (Agora Energiewende,

2017).




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5.3 THICKNESS OF WALL COMPONENTS IN BOILER AND TURBINE

DESIGNS

Thick walled components of a power plant allow higher steam temperature and pressure operating

conditions and hence increase efficiency. However quick temperature changes in such components

generate thermal stress and shorter their life Hence there is a need to reduce the thickness of various

components to enable quicker start-ups and improve flexibility in general.

At the design stage, detailed attention is given to the selection of material properties and the wall

thickness of high temperature components, to optimise temperature ramp rates during start up.

Common thick-walled components such as boiler drums and headers, main steam pipework and steam

turbine, valves, steam chests and cylinders are limited by the material yield point. Prior to its yield

point the material behaves (deforms) elastically and returns to its original shape once the applied

stress is removed. However, once the yield point is passed, which can happen by overheating the

component using excessive rapid ramp rates, part of the deformation will be permanent and

irrevocable. Thus, it is important not to exceed the design rate of temperature rise to prevent the

premature onset of thermal fatigue cracking and to achieve the required design life for the component.

Modern control systems prevent critical thick-walled components from being heated too rapidly by

setting limits on rates of temperature rise and the maximum permitted temperature. Additionally,

there are also restrictions on the rate of loading on the electrical generators as excessive electrical

loading can generate high temperatures in the copper core of the rotor and stator (Parsons

Brinckerhoff, 2014). A thinner design for thick wall components can improve both start-up times and

ramp rates (VGB, 2018; Agora Energiewende, 2017).

Designing thick wall components for a shorter service time reduces their creep lifetime consumption

during plant start-up and cycling. For example, investigation of superheater headers designed for

100,000 h instead of 200,000 h of creep life has shown their much lower creep lifetime consumption

(see Figure 4) (Reischke, 2012).




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Figure 4 Comparison of lifetime consumption of superheater headers for design creep life of

100,000 hours and 200,000 hours (Reischke, 2012)

Wall thickness of pressure parts can be reduced by using a superior material or by increasing the

number of specific components such as headers. For example, research by Jeschke and others (2012)

has shown that using Alloy 617, instead of P92 steel, allows the wall thickness of high-pressure headers

to be reduced by about 23%, from 52 mm (P92) to 40 mm (Alloy 617). This increases the allowable

rate of temperature change by 60% in the load regime 50–100%. Consequently, the plant ramp rate

can be increased by 3%.

Current calculation methods, such as the Finite Elements Method (FEM) of the European Pressure

Equipment Directive (PED), simulate the real gradients in various plant parts such as headers and

enable the calculation of the (smaller) design wall thicknesses. Thus, their use during the design

process can help optimise start up time.

In the HP turbine the inner casing thickness can be reduced by internal cooling. Reduced thickness

means a faster heat-up and quicker start-up are possible. Such a cooling system is used in Siemens’

SST5-6000 turbine, which has a barrel-type construction with an inner casing (see Figure 5). A small

amount of cooling steam passes through radiant bores into a small space between the inner and outer

casings. This reduces the inner casing temperature, which results in lower creep stress and protects

the inner surface of the outer casing, allowing its thickness to be reduced. The result is that cold start-

up time is reduced by almost 50% (see Figure 6) (Chittora, 2018).




34

Figure 5 Part of Siemens HP turbine with the internal bypass cooling (Chittora, 2018)

Figure 6 Cold start-up time with and without HP internal bypass cooling (Chittora, 2018)

5.4 EXTERNAL HEATING OF BOILER THICK WALL COMPONENTS

As mentioned before, during start-up the boiler thick wall components are the limiting factor for

increasing the firing rate. Using external heating allows mitigation of the thermal stress of thick wall

components and leads to faster start-up times (VGB, 2018).

5.5 ADVANCED SEALINGS IN THE TURBINE

One of the necessities for flexibility in the turbine is that the very small clearances between stationary

and moving parts stay almost constant during variations in output. This requires careful design,




35

advanced sealings and adequate measures for uniform thermal loading (Żbik, 2017; Henderson, 2018).

This is especially important for cold start-up (Henderson, 2018, 2014).

Figure 7 Example of HP turbine advanced sealing (Żbik, 2017)





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5.6 TURBINE BYPASS SYSTEM

Turbine bypass systems are a necessity in plants designed for on/off and other flexible forms of

operation, as noted by Henderson (2018). They allow all or part of the steam to bypass the HP or LP

turbine so that the rate of temperature change in the turbine can be managed as the boiler is starting

up and shutting down (Henderson, 2014). HP turbine bypass is described in Section 6.2.

5.7 CLEANING BOILER DEPOSITS

As noted by Nicol (2014), excessive slagging and fouling will reduce boiler efficiency and lengthen

boiler start up times, through reduced heat transfer. It will also cause material over-heating and place

increased loads on tubes, both of which increase creep damage. Hence, if a greater number of start-

ups are to be encountered by a plant, it is important to keep a boiler clean online and offline if needed.

Although SC and USC boilers typically have soot blowers for online cleaning, they may still require

some offline cleaning. Soot blowers use compressed air, steam or water to knock off deposits. Modern,

intelligent soot blowers are retractable, can vary the steam/water/air pressure and use heat transfer

sensors to determine when cleaning is required. Using intelligent soot blowers allows maximum

cleaning, minimum water usage and tube damage. As with installing most new technology, it is

important that the soot blowers and corresponding sensors are set-up according to their manufacturers’

instructions which will differ from boiler to boiler. There are a number of intelligent soot blowers

available commercially, including Diamond Power’s ‘HydroJet’ and ‘SMART Clean’ systems. Typical

payback periods in fuel savings and further maintenance for Diamond Power’s intelligent soot blowers

are around 6–12 months and can eliminate the need for offline boiler cleaning for up to 20 years (Nicol,

2014). Offline cleaning can be carried out with high-pressure water and dynamite. Any large deposits

fall into the hopper, flow into the grinder and out of the sluice area. Modern cleaning with dynamite




37

can be done in 36 hours, it is much quicker and less water intensive than high pressure water cleaning,

as noted by Nicol (2014).

Similarly, there are a number of systems and sensors able to assist cleaning devices and improve boiler

operation and efficiency. Many of these are described in an IEACCC report by Lockwood (2015). One

of the recent developments in boiler optimisation tools is FTR from G.E.E.R. and AMS Ltd. It measures

fouling thickness and reflectivity and hence predicts when online boiler cleaning is needed. It can also

be used to predict the lifetime of metal tubes in the boiler, that is heat transfer surfaces and tubes. In

general, soot blowing optimisation can prevent tubes overheating and the consequent damage.

Additionally, optimisation of the operation of the soot blowing system reduces the time taken by the

soot blower and also the number of soot blowers in operation.

As noted by Martino (2013), cold starts can expand boiler tubes by up to 46 cm, which dislodges

deposits. Therefore, an unexpected consequence of cyclic operation is a reduced need to clean the

boiler.

5.8 COMMENTS

Start-up procedures are complex and expensive. Shortening them and being able to ramp up rapidly

ensure a quick response to the change in the market conditions and allows plants to participate in

different markets, such as for ancillary services. Improvements can be achieved in a number of ways.

These include: reliable ignition, integration of a gas turbine, reducing thickness of thick wall boiler

components such as headers or including more headers, external heating of boiler thick components,

cleaning of boiler deposits and in the turbine: advanced sealings, turbine bypass (HP or LP), internal

cooling of the turbine casing.

L O A D R A M P R A T E I M P R O V E M E N T S



38

6 L O A D R A M P R A T E I M P R O V E M E N T S

High ramp rates allow dynamic adjustment of net power requirements (Agora Energiewende, 2017)

and mean that power plants can participate in different markets (Then, 2017). There are various

measures which can improve load ramp rates; the most common ones are described below. Some

measures described in the previous chapter such as reduced thickness of boiler components also

impact ramping up capability.

6.1 MILL STORAGE CAPACITY

Mill storage capacity can be exploited to obtain greater supply rates of pulverised coal. This can be

achieved by adapting the grinding pressure and temporarily storing coal within the mill. Response time

improvement and storage capacities depend on the mill type (VGB, 2018).

The storage capabilities of mills can be exploited by adapting the classifier's rotational speed to get

faster heat output. A lower rotational speed of the classifier releases more coal dust to the burner

whereas a higher speed separates more coal. A dynamic classifier, in contrast to a static one, should be

used for this purpose. This measure will have greater impact if applied in conjunction with other

measures such as optimisation of the air:fuel ratio (VGB, 2018).

6.2 FREQUENCY CONTROL

As noted by Henderson (2014), many coal-fired power plants are designed to provide frequency

stabilisation on the grid through primary frequency control. These are the plants that can provide very

rapid output changes of 5% or even up to 10% within about 30 seconds (Reischke, 2012). In addition

to this very short-term response duty, coal units can also be used to provide secondary frequency

control, which requires an output change within several minutes. The response of the latter frees up

the primary frequency control units making them ready to provide an instant response again.

Providing secondary frequency control has similar implications for plant design to providing the

capability for meeting large, rapidly changing supply demand. Retaining some fossil-fired units for

primary and secondary frequency control will remain very important in the future, as many renewable

energy generators do not provide frequency control. Coal-fired plants designated for frequency

control are kept on, and so synchronised, but operating below full load, ready to provide a response

when needed (Henderson, 2014).

Methods available for primary frequency control include the well-established means of opening

throttled main steam valves, but also, recently, installing an additional valve in parallel with the

existing turbine inlet valve, condensate throttling, feedwater heater bypass and HP stage bypass

(Henderson, 2014; Chittora, 2018). Another alternative is to install a thermal storage system, for

feedwater preheating as it can also increase the load range (see Section 4.5). Figure 10 shows measures

for fast load ramping, their relative times and location in the plant (Chittora, 2018).




39

Figure 10 Measures for fast load ramping (Chittora, 2018)

6.2.1 Condensate throttling

In condensate throttling, the turbine control system opens the governor valves to use the reserve

steam storage capacity of the boiler, as in conventional throttling, but the flow of condensate to the

low-pressure feedwater heaters is reduced at the same time. Consequently, the flows of extraction

steam are reduced, leaving additional steam flow in the turbine. Maximum output can be reached after

about 30 seconds (Henderson, 2018). The technology has been demonstrated in Iskenderun, Turkey,

Neurath and Leunen in Germany and Dadri, in India. For example, the response time of 20 s for 7%

power at 80% to 100% load has been achieved at NTPC’s 500 MW Dadri unit (Siemens, nd).

6.2.2 HP turbine bypass

HP stage bypass allows additional HP steam to be admitted to the HP turbine some stages after the

first blade row when the bypass valve is opened. The system is typically designed to give a short-term

5% increase in power but can be designed for more. Normal operation at 100% maximum continuous

rating is achieved with the stage bypass valve closed. HP stage bypass is the most efficient measure for

achieving rapid load increases (1% per second) as throttling losses are at a minimum due to the use of

full arc admission. It is also available for use over the whole load range, according to Henderson (2018).

6.2.3 Additional valve

When using HP turbine bypass, throttling of control main valves is not used. Instead, the additional

valve (last main steam valve) is opened to provide additional output. This improves efficiency as the

deficit in heat rate is reduced as shown in Figure 11.




40

Figure 11 Increase of turbine swallowing capacity to use boiler storage (Chittora, 2018)

6.2.4 Feedwater bypass

Flexibility can also be increased by providing feedwater heater bypasses. It can help to reduce

minimum load by allowing a reduced final feedwater temperature, but in contrast, it may also be

designed to give a power boost; use of high-pressure feedwater heater bypass can produce additional

power for about 20–30 minutes by allowing more steam through the turbine.

6.3 AUXILIARY FIRING WITH DRIED LIGNITE IGNITION BURNER

IN BOOSTER MODE

Auxiliary firing with a dried lignite ignition burner as a measure for low minimum load was described

in Section 4.1.6. A dried lignite ignition burner can also be used during plant operation to increase

firing power and net power as well as ramp rate. This type of operation is referred to as a booster

operation and requires a coal bunker. As lignite comes from the bunker not from the mill, the time lag

between the increase in firing rate and the turbine response is reduced (Agora Energiewende, 2017).

6.4 COMMENTS

High ramp up rates allow dynamic response to net power requirements and participating in different

markets. Ramping up rates reported by different operators vary considerably. For the older units they

are generally around 2–5%/min, but for newer ultrasupercritical units, up to 8% is possible. Of course,

even higher rates can be achieved for primary frequency control. Quicker ramp rates can be achieved




41

by many of the start-up improvement measures such as turbine bypass systems. Other means include

exploring the mill storage capacity, condensate throttling, and the use of an additional turbine valve.

P L A N T P R E S E R V A T I O N D U R I N G S T A N D B Y P E R I O D S



42

7 P L A N T P R E S E R V A T I O N D U R I N G S T A N D B Y

P E R I O D S

Flexible plant operation means more start-ups and shut-downs and more periods of standby ranging

from a few hours to several days or more. Plant start-ups and shut-downs disrupt physical and chemical

conditions within the water/steam circuit, leading to corrosion and other damage mechanisms during

standby, which then affect plant operation unless proper lay-up procedures are applied. Boiler

(see Figure 12), turbine (see Figure 13), feedwater and condenser systems can be affected. In fact, a

high proportion of on-load failures originate from preventable damage caused during offload periods,

as noted by McCann (2018). Such damage can compromise start-up reliability as well as result in

serious failures during service including potentially catastrophic LP turbine blade damage. Frequent,

short-term outages from unit cycling increase by nearly an order of magnitude the percentage of

operating life and annual hours for which components are stressed or imperfectly protected (Mathews,

2013). Consequently, proper plant preservation or lay-up procedures during the standby periods are

important, regardless of the duration of shut-down or outage, and are regarded as ‘a mode of operation’

by McCann (2018).

Choosing the most applicable practices depends on site-specific factors, and the entire unit must be

considered. The practices applied may differ from outage to outage but should always focus on the

most practical and beneficial techniques for minimising equipment damage during standby (EPRI,

2014).

Figure 12 Boiler tube failures influenced by off load corrosion (Image courtesy of Uniper, 2018)




43

Figure 13 Pitting (right of figure) and blade failure in LP turbine (Image courtesy of Uniper, 2018)

Corrosion is usually the result of losing the protective oxides on metal surfaces that form a barrier to

further oxidation and other chemical attacks (EPRI, 2014). Hence maintaining a passive layer of

protective oxides is essential to prevent chemically induced damage and general metal wastage.

General corrosion produces a relatively thin layer of iron oxides as corrosion products but, because of

the large surface area of water/steam circuits, substantial quantities of them can be formed. On re-start,

they may be transported to high heat flux areas where they are deposited, inhibiting heat transfer and

promoting further damage (Shibli, 2019).

Pitting is localised corrosion, involving a part- or through-wall dissolution of tube metal. It is an

insidious form of damage, as a relatively small amount of metal loss can lead to through-wall failure,

with catastrophic results. Pitting occurs only in unprotected shut-down periods, not during operation.

This is because, during shut-down, the remaining fluids are often stagnant and may be open to the

atmosphere, which leads to their saturation with oxygen, initiating corrosion. Chloride ions [Cl¯] and

low pH conditions cause a break down in the passive layer and quickly penetrate the imperfections in

the protective oxide, leading to aggressive acidic conditions and progression of damage. As oxygen

plays a role, elimination of oxygen and ensuring minimum chloride concentrations are required to

fully combat pitting activity. Other anions also can attack the passive film (EPRI, 2014).

Figure 14 shows areas of the steam/water cycle affected by corrosion, deposits, and air ingresses

during start-ups/shut-downs and standby periods.




44

Figure 14 Areas of the steam/water cycle affected by lay-up and start-up practices (Mathews, 2013)

7.1 WATER CIRCUIT

Maintaining correct water chemistry is of paramount importance to avoid corrosion-induced failures

of the boiler, turbine, or condenser. Wet lay-up of the water circuit provides chemistry conditions

during standby that are like those when the plant is operating. It entails filling the components and

connecting piping with treated demineralised water with low dissolved oxygen (less than 10 ppb) and

appropriate chemicals for the metallurgy of the system. During the procedure, the equipment is kept

closed to prevent any introduction of air. Other methods such as nitrogen capping or draining are not

practical or plausible for cycling units, as noted by EPRI (2014).

During run-down and shut-down of a unit, the condenser performance for air removal and deaeration

declines. Once the steam flow to the condenser stops, the vacuum conditions and air removal are lost,

and the condensate is fully aerated. Likewise, following depressurisation of the unit, the deaerator

stops working and sometimes acts as a source of aeration. Flow through the circuit is still needed to

fill the boiler or maintain the liquid volume as a result of contraction during shut-down and cooling of

the components. These conditions result in high oxygen levels in the water circuit. Chemically

reducing oxygen with the addition of reducing agents is ineffective and can damage protective oxide

coatings for ferrous materials. If excess reducing agent is used, high ammonia levels are produced on

start-up which lead to high corrosion of steam side copper components (EPRI, 2014).

pH control of the of the preboiled circuit is often lost during shut-down as the alkaline water is

acidified by CO2 from air entrainment and from the increase make-up to the cycle with aerated water.

Make-up water is also untreated so there is no pH adjustment. The water circuit transports make-up

water to the boiler or evaporator to supply the void created by the thermal contraction of the water

(EPRI, 2014).




45

The lay-up and stabilisation of the corrosion products in the water circuit of cycling units is important

as these units spend a disproportionate amount of time in shut-down and start-up operations. This

means there is a possibility of excessive transport of corrosion products to the steam generating

equipment and consequent excessive deposition and associated damage (EPRI, 2014).

There are several approaches to layup and preservation of the water circuit which address the above

challenges and promote a more trouble-free start-up (EPRI, 2014). They include:

• Hotwell bubbler for oxygen removal that incorporates a steam or nitrogen sparging/bubbling

system near the hotwell outlet for removal of non-condensable gases from the condensate.

• The use of steam or nitrogen sparger in the deaerator storage tank. This offers significant

advantages on start-up for deaeration and for pre-heating the boiler feedwater as it allows the

thermal differentials at the economiser inlet or boiler water downcomer to be minimised.

• Addition of a pipe from the economiser inlet or deaerator outlet to the condenser hotwell or

condensate pump’s suction to allow hotter water to circulate through some deaeration devices or

to add a side stream deaeration device to maintain low oxygen content. Periodic circulation using

condensate pumps or an external pump eliminates areas of stagnation which reduces the

potential for pitting.

• Closing the deaerator vent prior to shut-down to prevent the introduction of air into the

feedwater as it is sprayed into the deaerator. Maintaining steam pressure or nitrogen to keep the

vapour space if possible (EPRI, 2014).

7.2 BOILER CIRCUIT

In boilers corrosion can occur both inside the tubes and on the flue gas side of components. Usually

the corrosion on the flue gas side surfaces results from interactions between moist air and tube

deposits that contain sulphuric acid. Damage is more likely on the water-side of tubes, where there is

potential for general corrosion, crevice corrosion and pitting (Shibli, 2019).

When offline, a boiler’s internal condition remains stable for only a short time. This is because the

alkaline boiler water and the alkaline condensates, which have protective properties, are acidified by

CO2 from the atmosphere as soon as air enters the system. Consequently, the risk of corrosion and

other damage to metal surfaces is high, and proper preservation is needed. Corrosion can be inhibited

by various measures, applicable to short- or long-term offline periods, including:

• water or moisture removal by drying (long term);

• replacement of the atmospheric oxygen with nitrogen (short term);

• adjustment of the aqueous chemistry to a pH of around 9.5–12.5 (short term);




46

• application of corrosion inhibitors to the aqueous environment or the vapour phase (short and

long term); and

• coating the metal to prevent contact with water (long term) (Moore, 2018).

Preservation by dryness is the most effective storage for longer lay-up periods, according to Moore

(2018), who says that the ideal process for drying the boiler and for its preservation during longer

lay-ups should comprise:

• blow-down of the boiler under pressure 2–7 bar (0.2–0.7 MPa);

• open the drum doors, vents and drains for a day or so, with the boiler still hot so the water

evaporates;

• run the condenser vacuum pumps for a few hours to remove water vapour from the steam

pipework,

• isolate the steam turbine and condenser, by leaving the vacuum pumps operating, to vacuum dry

the condenser; and

• the dryness in the boiler is then sustained by dehumidifiers, injecting dry air at the top of the

boiler with the lower vents and drains left open.

The disadvantage of this method is that the return to service will be delayed by the time taken to fill

and vent the boiler (Moore, 2018) hence is not suitable for a frequently cycling unit.

Drying out of the cold boiler has been also advised by ‘some respected groups’, as noticed by Moore

(2018). It consists of injecting nitrogen from cylinders or blowing compressed air through or leaving

trays of desiccants in the drums and vapour phase inhibitors. However, these methods also have

attendant disadvantages (Moore, 2018).

In the case of frequently cycling units, the simplest solution to preserve the boiler waterside is to

increase the pH and oxygen scavenger concentration before shut-down. There are various chemicals

available for the purpose. Other boilers parts which are wet and cannot be flooded can be preserved

by the use of nitrogen blankets or wet film protection – tri-sodium phosphate (TSP) can be sprayed

onto their surfaces using skids with spray heads, according to Moore (2018).

If no hot blowdown is performed, boiler parts such as pendant superheaters, reheaters, drain-lines,

horizontal pipework, feedwater systems and others will retain water. These may be protected by wet

storage, which includes flooding them with an alkaline solution with an oxygen reducing agent added

(Moore, 2018).




47

7.3 REHEATER – TURBINE CIRCUIT

As explained earlier, the corrosion of turbine components can compromise start-up reliability as well

as result in serious failure during service.

Both reheater and turbine are subject to deposition of ‘dry’ chemical compounds during normal

operation. These may be hygroscopic at ambient conditions and form aggressive chemical solutions

on shut-down, increasing the likelihood of corrosion, unless the moisture is removed through purging

and drying.

As noted by Caravaagio (2014), dry storage is the proven and best lay-up practice for the reheater and

steam turbine. Residual heat of the turbine is usually adequate for maintaining dry conditions for about

24–36 hours, but condensation and oxygen will initiate corrosion once a relative humidity greater than

40% or the ‘dew point’ temperature is reached. Reheaters that are force-cooled require immediate

purging of steam vapour as exclusion of oxygen-laden air is difficult.

Water-soluble turbine deposits can be removed during shut-down using special operating techniques

to lower the amount of superheat in the incoming steam resulting in a wetness factor in excess of 3%

throughout the turbine set. This will solubilise the ‘water soluble’ deposits, resulting in weakly

concentrated solutions that can be rinsed and carried away. Careful monitoring is required to assure

the effective removal of moisture, liquid and highly concentrated residual. Wet steam washing of HP

turbines should include the use of cold reheat drains to prevent carryover of contaminant-rich liquid

to the reheater (EPRI, 2014).

Dehumidified air through the entire turbine flow path can be used to capture residual moisture. The

moisture-laden air is purged – usually at the condenser – until the desired level of humidity, typically

less than 35–40%, is achieved before the cycle is closed to incorporate a continuous flow of air through

the circuit. The dehumidification system is not used until the unit has moderately cooled (EPRI, 2014).

Another possibility is to maintain the condenser vacuum once the generator is disengaged and pull

vacuum through the turbine set and the reheater. Clean dry air with an ambient relative humidity

lower than 40% is introduced through the cold reheat piping to purge the residual vapour. Once purged,

only flow sufficient to prevent moisture laden air in the condenser from entering the LP turbine is

necessary. Warm air from the reheater and IP turbine helps maintain LP turbine temperatures near

65°C for several days. Oxygen solubility decreases at higher temperature and at temperatures above

65°C its solubility is low enough to limit pitting of turbine components (EPRI, 2014).

Nitrogen filling or film forming can also be used to preserve the reheater-turbine circuit (McCann,

2018).




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7.3.1 Condenser and feedwater heaters

Lay-up protection of steam extraction from the turbine to the condenser and feedwater heaters is

difficult for units not planning extended shut-down, as noted by EPRI (2014). This is because there is

residual moisture present in these areas, even when drained and they are not normally isolated from

the turbine.

Consequently, lay-up of the condenser and feedwater heaters is very difficult for cycling plants

(Caravaagio, 2014). Also, these components represent some of the largest surface areas of low alloy

carbon steel and/or copper alloy material in the plant. These can be subject both to corrosion and

different forms of damage. This results in the transport of corrosion products (iron and copper) in the

feedwater to the boiler and turbine where they can be deposited and cause damage. This can lead to

major tube failures and water induction to the operating turbine with devastating and catastrophic

results.

7.3.2 Protective barrier films

Protective barrier films protect equipment by creating a barrier between the metal’s oxide surface and

any water or moisture present. Such barrier treatments include vapour phase corrosion inhibitors,

known also as vapour phase inhibitors (VPI), and filming amines, also referred to as film forming

amines or polyamines. Both provide comparable protection. For an explanation of the mechanisms of

how they work, see EPRI (2014).

The application methodology differs for VPI and filming amines. As VPI compounds must be added

after the equipment is removed from service and cooled, the technique is not viable for units with

short term outage. However, filming amines can be used during both operational and idle conditions.

The effectiveness of filming amines for protection against pitting and crevice corrosion of turbine

steels and the noticeable reduction of material wastage by single phase flow accelerated corrosion

(FAC) has been demonstrated by EPRI (2014). The filming amine is added into the water/steam

circuit through a chemical addition system before the unit is shut down. Then it travels through the

entire water/steam cycle and gradually forms a protective film on all the metal components. The

protection is effective in both wet and dry conditions. Figure 15 and Figure 16 show a turbine blade

before treatment and after amine application.




49

Figure 15 Turbine blade before treatment (Image courtesy of Uniper)

Figure 16 Turbine blade after filming amine treatment (Image courtesy of Uniper)

It is important to apply the correct amount of amines as insufficient application can result in increased

localised corrosion in areas of inadequate inhibition, whereas excessive dosing may have some

unwanted effects and result in the likely sloughing of iron deposits or sludge formation. Condensate

polisher resin fouling has been noticed with the use of filming amines; hence condensate polishers

should be bypassed and removed from service during dosing of filming amines for lay-up.

For sufficient protection, 10–50 milligrams of amine per square metre of surface area (10–50 mg/m2)

is required. This can translate into a large amount of product as the surface area of a typical coal-fired

unit can range from 50,000–100,000 m2, depending on the unit size and design (EPRI, 2014).




50

7.4 COMMENTS

Cycling operation increases the number of start-ups/shut-downs and standby periods. These change

the water/steam equilibrium and lead to corrosion and other damage mechanisms during standby

periods, unless proper lay-up procedures are applied. Damage initiated during standby period affects

plant operation and reliability. All water/steam circuits need to be preserved. There is no

‘one-size-fits-all’ solution for plant lay-up and the most appropriate method depends on site-specific

conditions.

Wet storage of the water systems and often the boiler is considered the most practical approach for

cycling units. pH adjustment and elimination of oxygen are essential. The procedure includes complete

deaeration of the condensate and feedwater and prevention of air entering the boiler and superheater.

The latter can be achieved by nitrogen blanketing and/or maintaining boiler pressure. pH adjustments

of all the liquid, including condensed steam in the superheater, must be equal to or higher than normal

pH conditions.

The wet lay-up practices in all parts of the water/steam cycle can be enhanced using filming amines as

a corrosion inhibitor. These are dosed to the entire circuit before the unit shut-down and their dosage

needs to be controlled precisely.

The best method for preserving the reheater and steam turbine is dry storage. Residual heat of the

turbine can typically maintain ‘dry’ conditions for 24–36 hours, but once a relative humidity greater

than 40% or the ‘dew point’ temperatures are reached, condensation and oxygen will initiate corrosion.

Reheaters that are force-cooled require immediate purging of steam vapour, as exclusion of oxygen

laden air is difficult to achieve. Dry reheaters, like the turbine, are subject to condensation and aeration

when cooling.

Preservation of condensers and the shell (steam) side of feedwater heaters is difficult. Both systems

are often the major areas of corrosion during unit shut-down and the source of deposit forming

corrosion products during start-up.

Filming amines can provide corrosion protection for the of the reheater, turbine condenser and

feedwater heater. Applied during operation in advance of shut-down, the method enables quick return

to service, and hence is applicable for frequently cycling units.

Monitoring of lay-up conditions is required to ensure the protective conditions are maintained.

P O L L U T I O N C O N T R O L S Y S T E M S



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8 P O L L U T I O N C O N T R O L S Y S T E M S

Flue gas treatment needs to comply with environmental norms in all cycling conditions. However, the

performance of emission control systems can be affected by off-design conditions arising from the

flexible operation of power plants. This chapter describes briefly the main effects on NOx, SOx and

particulate control and ways to mitigate them.

8.1 NOX CONTROL – SCR & SNCR

Selective non-catalytic reduction (SNCR) reduces NOx by injecting a reagent, either ammonia or urea,

into the boiler’s furnace at locations which have an appropriate temperature window, typically

between 900–1150°C depending on the reagent and conditions of SNCR operation (Wiatros-Motyka,

2018). Operating at different load regimes changes the temperature profile within the boiler and hence

impacts the effectiveness of the system (Żmuda, 2019). For example, if the reagent is injected in the

part of the furnace where the temperature is too high, the ammonia, or urea decomposed to ammonia,

will produce additional NOx. Alternatively, if the temperature is too low, the NOx reduction reaction

will not occur, and the ammonia will remain as ammonia slip and be wasted. Additionally, ammonia

slip can react with SO3 present in the flue gas to form ammonium sulphate and ammonium bisulphate

(ABS). Ammonium bisulphate tends to condense on the cooler surfaces of the air heater and can cause

significant loss of efficiency, in addition to mechanical damage (Xu and others, 2015). Therefore,

effective operation of the system at various load regimes requires temperature monitoring within the

furnace and reagent injection in areas with the appropriate temperature window (Żmuda, 2019). The

use of multiple zones of injection and the ability to take injectors in and out of service as needed, allows

for chemical release within the desired chemical and thermal environment. This approach provides

good opportunities for effective NOx and ammonia slip control and has been commercially proven

even on units as large as 660 MW (Boyle, Stamatakis and de Havilland, 2015). Figure 17 shows the

temperature profile within the furnace during full load and part load operation and how an SNCR must

inject the reagent in different locations due to the temperature changes (de Havilland, 2019).




52

Figure 17 SNCR temperature window with injection (pink – the reagent injection, white – ammonia slip,

purple – temperature window) (de Havilland, 2019)

Similar to SNCR, selective catalytic reduction (SCR) systems need to operate in an appropriate

temperature range (usually 300–400°C) to be effective and avoid various problems. As the

temperature of the flue gas changes with the cycling regime, maintaining it at the required level at the

SCR inlet is essential to prevent blocking of the catalyst and harm to the air heater from deposition of

ammonium bisulphate. For SCR, the conventional solution is to add a flue gas or water-side economiser

bypass so the flue gas temperature at low load can be kept at the design value. Other options include:

closer monitoring of flue gas inlet conditions (ammonia, SO3 and temperature distribution) in the SCR

and modifying the inlet temperature distribution using baffles (static mixer). Installation of a heating

system for hot gas carrying components can also shorten start-up times (Henderson, 2014). Where

none of the mechanical methods mentioned previously can be applied, it is also possible to use

chemical injection. For example, Santee Cooper Cross Station had a limit on low operating loads caused

by ammonium bisulphate formation at the SCR. However, by using injecting magnesium hydroxide,

the SO3 content in the flue gas was reduced thereby allowing the plant to operate at lower loads without

the risk of ABS formation (Davis, Rummenhohl, Benisvy and Schulz, 2013).




53

More on NOx control systems and their other operational requirements can be found in another

IEACCC report by Wiatros-Motyka (2018).

8.2 PARTICULATE CONTROL SYSTEMS

Particulate control systems such as electrostatic precipitators (ESPs) and fabric filters (FF) can

accommodate rapid load changes provided that the temperature does not fall too low, that is below

90°C.

Generally, ESP perform better at low loads because of the reduced proportion of unburnt carbon in

ash and the increased residence time of the gases in the precipitator which allows more of the dust to

be collected. This is the case providing that the temperature in the precipitators does not fall below

the dew point, as any moisture can lead to a build-up of dust, which, if pozzolanic, can be difficult to

remove. Low temperature can also increase corrosion due to the presence and subsequent

condensation of acid gases (EPRI, 2013).

If the temperature falls below 90°C, it may be necessary to install a warming system. This could be in

the form of a gas burner system to pre-heat the precipitators while the unit is being brought back on

load.

According to EPRI (2013), while starting up the boiler, typically the precipitators are not energised

until stable combustion has been established. This may create problems with emissions into the local

environment. So, it may be necessary to review the operating procedure with a view to energising the

precipitators earlier in the start-up process.

One way to minimise problems caused by a lower temperature is to isolate some of the precipitator

banks during the early stages of the start-up. Passing the gas through just one bank will limit the cooling

and possible deposition of dust and/or residue from the start-up oil burner combustion to this one

bank. The impact on emissions from this one bank taking some time to recover to normal is less than

if all the precipitator banks are affected (EPRI, 2013).

In the case of bag filters, the main problem is to avoid temperatures dropping below the dew point.

8.3 FLUE GAS DESULPHURISA TION

Flue gas desulphurisation (FGD) needs sophisticated control to work efficiently in cycling mode as

there are various problems which can occur when operating in this way.

It can be possible to save energy consumption for FGD at part load by updating the control systems

and switching off some circulation pumps. The number of shut-downs and start-ups needs to be

minimised to avoid slurry solidification and accumulation of start-up fuel oil residues on linings, as

well as averting long warm-up periods. It is normal practice to keep the FGD unit in stand-by mode in

case of a short outage period. This avoids solid deposits and enables the FGD unit to start removing




54

SO2 quickly (Hofelsauer, 2019). Keeping within the required emissions limits during rapid load

changes requires sophisticated control and an increased liquid:gas ratio may be needed.

Lime or limestone are the typical FGD reagents and are often fed into the absorbers at a fixed rate.

Reagent feeding should be dosed automatically to keep the pH value constant. During low load

operation, there will be an excess of reagent in the slurry, in the case of fixed feeding only, which

although it increases the rate of SO2 removal, may also result in increased scaling.

Additional difficulties may occur during rapid load changes when it will be necessary to match the

throughput of the scrubber with the required reagent. The time delay characteristics require an

adequate control system to anticipate load changes. Failure to balance the throughput with the reagent

may lead to high alkali levels and corrosion of the equipment. This can be overcome by improved

water treatment management and upgrading of adsorber lining materials to some extent. Normally,

the absorber island is manufactured in highly anticorrosive material which reduces the risk

(Hofelsauer, 2019).

As noted by EPRI (2013), during operation with reduced load, the incoming gas temperature is likely

to be low, which may impact the reaction rates. The temperature in the absorber is mainly fixed by the

adiabatic saturation temperature. However, the reaction rate can be recovered by increasing the

liquid:gas ratio and pH set point (Hofelsauer, 2019). Where regenerative heat exchangers are used,

the net effect may be a substantial decrease in exit temperature which will reduce gas buoyancy and

induce dew point corrosion in the ductwork and chimney. Hence, it is usual in the USA, when cycling,

to bypass FGD plant until temperatures have been stabilised (EPRI, 2013).

In the EU the FGD units do not have flue gas by-pass, so all components are designed for potentially

corrosive conditions, as noted by Hofelsauer (2019).

8.4 COMMENTS

Emission control systems can be affected by off-design conditions from the flexible operation of power

plants. The main effects result from flue gas temperature changes during the cycling regime. Therefore,

maintaining the temperature at the required level is essential, particularly for NOx controls. There are

various ways to achieve this. For example, an additional heater for flue gas prior to the SCR inlet has

been used. In the case of SNCR, the use of multiple zones of injection and the ability to take injectors

in and out of service as needed, allows for effective NOx removal.

FGD may be affected by flexible operation more than NOx and PM control systems and it requires

sophisticated controls to work efficiently in cycling mode. The number of shut-downs and start-ups

needs to be minimised to avoid slurry solidification and accumulation of start-up fuel oil residues on

linings, as well as averting long warm-up periods.




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ESPs and FFs for particulate control generally cope well with flexible operation conditions providing

that the flue gas temperature does not fall below 70°C.

I M P A C T O F F L E X I B L E O P E R A T I O N O N OT H E R P L AN T A R E A S



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9 I M P A C T O F F L E X I B L E O P E R A T I O N O N O T H E R

P L A N T A R E A S

This chapter describes briefly the impact of flexible plant operation on water and wastewater

treatment and on the auxiliary systems.

9.1.1 Water and wastewater treatment

As described in Chapter 7, feedwater can be a major source of the impurities entering the boiler which

can lead to corrosion and failure of various components in the boiler, turbine and condenser and result

in subsequent plant outages. Water chemistry deteriorates with cycling and it is important to maintain

its quality at all times (Cochran and others, 2013).

Other constraints to consider when cycling, include the capacity and availability of the water

treatment plant. This is because flexible operation increases drainage losses and hence water demand.

Therefore, it may be necessary to install additional capacity for both water storage and production

(EPRI, 2013).

9.1.2 Auxiliary systems

During start-up and operation at reduced load, a power plant operates at off-design conditions. This

affects its thermal efficiency by reducing boiler and turbine performance and leads to high power

consumption by the auxiliary systems including major fans and feedwater pumps. Therefore, it is

important to make sure that auxiliary systems have reliable actuators and valves as well as flexible

drive motors. These allow for faster and more accurate flow control and reduce energy losses

(Henderson, 2014; VGB, 2018). Hence replacement of old equipment with new alternatives is

recommended and will improve start up optimisation, ramp rates and operation at low load

(VGB, 2018).

Installation of dampers in air, both primary and secondary, and flue gas ducts as well as in the primary

air cooler (PAC) can help start-up optimisation. This is because dampers in these positions keep the

boiler warm, so the warm start capability period can be extended to approximately 60 hours (VGB,

2018).

Generator cooling technology can be changed. Water-cooled stator windings are more robust against

thermal stress than hydrogen cooled ones. A change in that respect will improve start-up optimisation

and ramp rates. Thermal stress at generator windings is a limiting factor (VGB, 2018).

I M P R O V I N G F L E X I B I L I T Y T H R O U G H P L AN T M A N A G EM E N T



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1 0 I M P R O V I N G F L E X I B I L I T Y T H R O U G H P L A N T

M A N A G E M E N T

As more intermittent renewable sources are added to grids worldwide, new strategies and effective

management are needed to mitigate and/or avoid the higher probability of equipment failure and

consequent reduction in plant life, the critical risk of process safety and increased O&M costs (Hillman,

2018).

As mentioned before, the requirements for flexibility vary between plants and there is no

‘one-size-fits-all’ solution to achieve plant flexibility. However, there are common aspects that the

power plant management should consider while making their assets more flexible, according to VGB

(2018). These include:

• Implementation of new business models: aligning plant operation with commercial strategies, such

as providing ancillary services;

• Change management: raising awareness of the need for flexibility and implementing the change

processes;

• Skills and talent management programs that ensure the required level of technological expertise

and motivation are gained by various groups of power plant personnel including management,

operational, maintenance staff and coordinators (operation, grid);

• Quality awareness: raising awareness of the importance of quality and adherence to O&M

practices; and

• Organisation: implementation of new work flows, procedures and processes, especially for

maintenance that aligns with new operating regimes such as two-shifting, load following and

weekend shut-downs (VGB, 2018).

10.1 MAINTENANCE STRATEGIES

Plant cycling increases wear and tear on various components, hence adopting an appropriate

maintenance strategy is key to a successful flexible operation.

There are three types of maintenance operation:

• Reactive – failure based;

• Preventive – interval based; and

• Predictive – condition based (Smith, 2001).




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Reactive maintenance takes place when equipment fails. This strategy is always expensive as the failure

of key equipment can cause a unit to be shut down, possibly for a long time. So, in addition to the high

maintenance costs there is also a substantial loss in revenue.

Preventive maintenance involves scheduled inspections, tests, repairs and replacement of critical

components. It is carried out on a calendar or operating time interval and it aims to extend equipment

life, reduce premature equipment failures and increase equipment availability. Preventive

maintenance has been in use for many years as an effective tool to reduce maintenance costs and

improve reliability for base load operating power plants where the life span of a piece of equipment is

well known and when consistent failure mechanisms are understood (Smith, 2001).

Predictive maintenance, in contrast to the standard operating procedure of scheduled preventive

maintenance, identifies what elements could cause a plant to shut down unexpectedly and gives them

priority for maintenance over equipment that will not harm operations in the event of failure.

Predictive maintenance techniques use diagnostic and performance data, maintenance histories,

design data and operating logs to determine the condition of the equipment. This allows maintenance

engineers to schedule maintenance more efficiently. For example, Gainesville Regional Utilities in

Florida, USA, reported that since it began focusing on prediction ahead of failures, based on

sophisticated data-driven algorithms, a 50% reduction in time spent troubleshooting suspected valve

problems was obtained (Maize, 2018). There are many tools now available in the market which can

help to achieve an effective, pro-active maintenance plan containing both preventive and predictive

elements (EPRI, 2013).

10.2 FLEET APPROACH FOR PLANT MAINTENANCE MANAGEMENT

When a power plant company owns several plants a fleet approach for maintenance should be

considered (VGB, 2018). This has several benefits including: standardisation, harmonised working and

reporting procedures and the exchange of experience. Plants can be categorised based on market

requirements. For example, in Germany, the following approach in which plants are categorised into

three categories has been developed:

• must run plants – those which need to fulfil a dedicated power purchase agreement and/or

heat-supply contract;

• market followers – those which adjust their operating regime to the merit-order based market

with a large share of cycling operation; and

• reserve plants – those which need to be available to provide power on demand (VGB, 2018).

Table 5 gives an overview of the market-driven fleet approach for the plant categories above. The

other approach is to categorise plants into technology driven groups, based on similar equipment (such

as boiler, turbine) deployed.




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TABLE 5 MARKET-DRIVEN APPROACH FOR MAINTENANCE (VGB, 2018)

Must run (contractual) Market follower Reserve

Characteristics Operation according to

customers’ needs for

electricity and/or heat

Market prices rule plant

operation

Operation on demand of

the Transmission System

Operator (TSO)

Availability >90% <80% On demand

Utilisation 70–80% 35–50% 1–5%

Maintenance approach • Preventative

maintenance in-wear-

intensive areas (mills,

boiler, FG-cleaning)

• Condition-based

maintenance

• Overhaul cycles and

durations are

time-dependent

• Risk-based maintenance

• Advanced condition

monitoring

• Overhaul cycles are

cost-optimised and

based on equivalent

operating hours

• Long standstills

• Conditioned-based

maintenance

• Frequent plant tests

and start-ups to secure

reliable operation if

requested

• Long standstills

• Need for a concept to

maintain know-how

10.3 CHANGES IN OPERATIONAL PROCEDURES

Existing plant operators frequently need to modify their operating procedures to meet new flexibility

requirements. This is usually achieved by experimenting with different operational procedures over a

period of time and can provide significant savings in costs associated with unit cycling (Cochran and

others, 2013). For example, Cochran and others (2013) reported that a 480 MW unit in the USA

lowered its minimum load from a typical 40–50% to 19% by physical modifications in the boiler,

pulverisers, turbines, generator rotors and condenser and changes in operating practices. Once the

physical modifications were introduced, 90% of future cost savings came from adjustment to the

operating procedures. New procedures for training in boiler ramp rates have been reported to be

particularly effective. Other examples included:

• Forced cooling. A plant owner experimented with accelerated forced cooling for the boiler, so it

could be shut down more quickly to repair some tubes and be back online within two days.

However, despite maintaining temperature changes within the equipment specification, an

increase in corrosion fatigue related failures was noticed after a year of such practice. Once the

plant returned to natural cooling, the failure rate decreased. Consequently, a new shut-down

procedure included keeping the boiler shut for the first four hours, which is natural cooling.

• Monitoring of economiser inlet headers. Intermittent additions of cold water to the hot inlet

header can cause it to crack so it is important to keep any temperature changes arising from this

close to the value recommended by the manufacturer. In the case of this plant, it was 37.8°C. In

fact, the plant owner decided to take further precautions and keep the temperature differences to

less than 30°C.




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• Layup procedures. These were established based on the time the unit was offline. For example,

for short outages the boiler was drained while hot, while nitrogen blankets were used for longer

outages. The procedures resulted in reduced boiler tube failures and corrosion.

• Pressure part management. This included reviewing each pressure component and establishing

causes of degradation and failure.

• Other changes to boiler operating procedures, including: a metal temperature monitoring

programme; a tube replacement and inspection strategy; thermal and cyclic fatigue inspections

and repair programmes; a fly ash erosion programme to reduce tube failure; and inspection

programmes for expansion joints, dissimilar welds and flow-accelerated corrosion.

• Temperature monitoring for turbine parts. Training and monitoring procedures, with associated

monitoring equipment, were established to monitor temperature changes of major components

and, where appropriate, limit ramp rates.

• Water chemistry maintenance. As water chemistry varies with cycling, the chemistry staff

remain on site at all hours. A chemistry management system based on ISO standards was also

developed.

• Maintenance strategies for environmental controls.

• Breaker maintenance. The maintenance and inspection programmes for low and medium

voltage breakers were modified.

• Overall monitoring programmes. This included comparison with other plants reports on best

practices associated with cycling (Cochran and others, 2013).

10.4 COMMENTS

Flexible operation impacts on various plant areas and brings new challenges. Therefore, new strategies

and effective management are needed to mitigate and/or avoid higher probability of equipment failure

and consequent reduction in plant life, critical risk of process safety and increased O&M costs. These

involve maintenance strategies and adopting new, or modifying existing, operational practices. The

latter are especially recommended for older plants which have limited remaining service life where it

is not viable to retrofit new systems.

C O U N T R Y P R O F I L E S A N D C A S E S T U D I E S



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1 1 C O U N T R Y P R O F I L E S A N D C A S E S T U D I E S

This chapter describes what is happening in some countries where flexibility is a growing issue. The

chosen examples show different measures adopted by power plants to increase their flexibility.

11.1 GERMANY

‘In 2000, Germany became the first major economy to place an all-in bet on wind and solar power,

passing a much-copied law that offered high guaranteed feed-in tariffs for renewable energy’, noted

Buck (2019). As the German government has invested hundreds of billions of euros in renewable

energy, its share in the energy mix has risen sharply, from 10% in 2005 to just over 40% at the

beginning of 2019, and the plan is to increase it further to 65% by 2030 (Buck, 2019). Consequently,

in Germany coal plant flexibility has become more important than efficiency during the last 10 years,

(Damm, 2018). Figure 18 shows sources of energy generation in Germany in 2018, while Figure 19

shows the change in the power generation mix from 2002 to 2018. With plans to phase out nuclear

power by 2022 and coal by 2038, the mix will continue to change in favour of renewable sources (Buck,

2019).

Figure 18 Share of energy sources in gross power production in Germany in 2018 (Clean Energy Wire,

2019)




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Figure 19 Installed net power generating capacity in Germany 2002-2018 (Clean Energy Wire, 2019)

Figure 20 shows the frequent changes in power output of conventional power plants in response to

fluctuating wind and solar output for a week in May 2020, with an equivalent week in 2012 for

comparison. Greater flexibility of German plants has been achieved by a combination of various

measures, examples of which are given below.

Figure 20 Estimated power demand in May 2012 and in May 2020 (Morris and Pehnt, 2014)




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Heilbronn, unit 7, hard coal power plant

The 800 MW unit 7 of Heilbronn station is an example of one that has achieved a significant reduction

in minimum load. In operation since 1985, the unit has a once-through, tangentially-fired boiler with

hard coal supplied by four bowl type mills. It was designed to operate with 30% minimum load.

However, in 2012-13 it underwent several modifications so that it could achieve 10% net (15% gross)

minimum load. The improvements included replacement of four mills to increase their capacity. New

mills also have the advantage of dynamic classifiers. Figure 21 shows a comparison of some old and

new mill parameters. Mill replacement was followed by modification of outlet ducts and primary air

adjustments.

Figure 21 Old and new mill parameters of unit 7 Heilbronn station (Then, 2017)

Other changes included modification of instrumentation and controls, one mill operation and

additional flame scanners. Only the highest burner level is used during one-mill operation as it gives

more stability than operating with two mills and burners at different levels. In addition, the boiler is

operated with a higher air to fuel ratio to help maintain a higher live steam and reheat steam

temperature.

Table 6 shows the changes in the selected parameters of the plant after lowering its low minimum load

from 30% to 15% gross.




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TABLE 6 SELECTED PARAMETERS OF THE PLANT OPERATION AFTER MODIFICATIONS TO ACHIEVE 10% MINIMUM

LOAD (THEN, 2017)

Summary post-modifications Full load Minimum load

Main steam temperature, °C 540 505

Reheat steam temperature, °C 540 467

Heat input, % 100 14

Boiler efficiency, % 94 92

W/S cycle efficiency, % 45.7 38

Generator power output, MW 812 105

Auxiliary power consumption, MW 38 27

Net power output, MW 774 (100%) 78 (10%)

Net efficiency, % 41 26

Heyden coal-fired power plant

Another example where significant flexibility improvement has been achieved in the German coal

fleet is the 875 MW Heyden power plant. In operation since 1987, the plant has demonstrated stable

operation at 10% minimum load with one mill operation. Originally an 800 MW unit, it has also

increased its maximum capacity by 75 MW. Some of the technical details of the plant are presented in

Table 7.

TABLE 7 TECHNICAL DATA OF HEYDEN PLANT (UNIPER, 2017)

General 1987 Start operation

Installed capacity 800 MWe

Today’s capacity 875 MWe

Efficiency full load 41%

Steam 2700 t/h

Supercritical pressure 21.5 MPa

Supercritical temperature 544°C

Intermediate pressure/temperature 4.6 MPa/545°C

Flexibility

Minimum load 20%/180 MW

Since: 01-06-2017 11%/100 MW

Ramp rate 15–20 MW/min

Hot start time to grid 1 hour

Hot start time to full load 3 hours




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Neurath lignite power plant

Another example of a plant which has notably improved its flexibility is the lignite-fired Neurath,

where instrumentation and controls were retrofitted to two 600 MW units, D and E. The principal

achievements of this upgrade were a reduction of the minimum load by 43% (from 400 MW to

270 MW), an increase in the ramp rate from 5 MW/min to 15 MW/min, and an increase of the

secondary reserve capability to 70 MW in 15 min (Chittora, 2019). Details are shown in Table 8.

TABLE 8 FLEXIBILITY IMPROVEMENT WITH THE USE OF SIEMENS I&C IN NEURATH, UNITS D&E (CHITTORA, 2019)

Starting situation Contract Proven (trial run) Further possible

potential

Load gradient 5 MW/min 12 MW/min 15 MW/min 20 MW/min

Minimum load

(gross)

440 MW 290 MW 270 MW (without

bypass operation)

250 MW (with risks, for

example, minimum fire

interlock)

Primary frequency

control (PFC)

18 MW by

throttling of

inlet valves

18 MW by

condensate

throttling

45 MW 50 MW

Secondary

frequency control

(SFC)

N/A 66 (75) MW 100 MW 110–115 MW

Simultaneous PFC

and SFC

N/A 18 MW

66 (75) MW

18 MW

75 MW Still under investigation

Jänschwalde lignite power plant

A 500 MW unit at the lignite-fired Jänschwalde power plant improved its flexibility by replacing its oil

burners with dry lignite ones and the use of plasma-induced ignition. This allowed the minimum load

to be reduced from approximately 36% to 18% (from 180 MW to 90 MW). A significant reduction of

start-up costs was also reported, as dry lignite is a cheaper start-up fuel than oil (Then, 2017).

German utilities have gained considerable experience in making their assets flexible and they share

this knowledge via several different international collaborations. For example, in 2017 the German

Federal Ministry of Economic Affairs and Energy (BMWi) initiated a study of available technologies

for flexible operation of thermal power plants – the Flexibility Toolbox. This study has been compiled

by VGB PowerTech e.V. and its Indian partner organisation EEC (Excellence Enhancement Centre)

jointly with Steag Energy Services GmbH under the auspices of the Indo-German Energy Forum

(IGEF). The toolbox includes 40 different flexibility enhancement measures that require a plant

retrofit or major technical intervention. It also highlights the need for staff training and changes to

operating procedures. The study is available from the VGB website at:

https://www.vgb.org/en/flexibility_toolbox.html. The interested reader is refered there for more

examples of flexiblity improvements successfully deployed in German plants.

https://www.vgb.org/en/flexibility_toolbox.html




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11.2 INDIA

India is on an economic growth path and additional power capacity is much needed for further

development. Coal-fired power plants are a significant part of the energy mix (57%, 196 GW as of

September 2018, (CEA 2018)) and more are being built to meet the increasing demand. However,

India is also committed to lowering it carbon intensity and has an ambitious aim of over 40% of

non-fossil fuel capacity by 2030 (see Figure 22). This means that despite new coal power plants coming

online, the proportion of coal in the country’s energy mix will decrease and coal plants will face a new

challenge of increased flexibility to back up intermittent energy sources.

Figure 22 Current installed capacity in India and projections for the future (Mazumder, 2017)

Indian hard coal is challenging as it has a high ash content. Three-quarters of current coal production

has an ash content of 30% or greater, with some approaching 50%. In comparison, coal traded on the

international market rarely exceeds 15% ash. Most of the ash in Indian coal is so-called inherent ash

which is difficult to remove below 30% prior to combustion. The high ash content reduces the calorific

value of the coal which is why most of the coal currently produced in India falls in the range

3500-5000 kcal/kg (15–21 MJ/kg). This is lower than the average heat content of coals typically found

in other large coal producing countries, such as China, Russia and the USA (IEA, 2015).

The high ash content of Indian coal means that a longer residence time in the furnace is needed for the

carbon to burn out, so the boilers need to be around 20% larger than those running on lower-ash coal

(Cornot-Gandolphe, 2016). Also, when high ash coal is burnt, the temperature in the burner near-field

decreases leading to lower volatile matter yield, which translates to lower combustion stability,

compared to coals with lower ash content (Daury, 2018). And as mentioned before, combustion

stability is important for achieving low minimum load. Consequently, it will be difficult to achieve

very low load for plants burning Indian coal unless coal cleaning prior to combustion takes place.




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Having said that, Indian plants are unlikely to be able to lower their minimum load from the current

55–70 % to less than 30% for some years to come (Henderson, 2018).

By 2022, the installed capacity of renewable energy in India is expected to increase from 74 GW (as

of 2018) to 175 GW, of which 100 GW will be solar (IGEF, 2018). Coal power plants are expected to

provide the majority of the system flexibility required to support this large amount of solar. Hence

some studies have considered how the integration of renewable energy will affect coal-fired power

plant operations and the strategies that should be adopted. CEA and GTG-RISE analysed the

requirement for flexibility by 2022 from coal-based stations based on technoeconomic criteria (Sinha,

2019). For this purpose, data from all Indian power plants such as their size and age, make of the boiler

and turbine, type of mills, coal quality, past plant load factors (PLF), ramp rates, minimum load, heat

rate (HR), location and variable costs with respective state merit order were collected and analysed.

From this, they established the capacities of the plants that can be made available for different modes

of flexibility. Out of a total coal-fired installed capacity of 231 GW, almost 82 GW of flexible capacity

can be made available. The flexible capacity units were categorised based on merit order dispatch as:

• Flexible-daily start (83 units of approximately 13 GW capacity). These are small units of

210 MW and below, with a heat rate over 2550 kcal/kWh (10669 kJ/kWh) and units which will

likely be very low in the merit order in 2022.

• Flexible-low load (139 units of approximately 48 GW capacity). These are units which will be

scheduled partly in 2022, and are mostly 200 MW and above.

• Flexible with efficiency retrofit (80 units of approximately 21 GW capacity). These units have a

heat rate in excess of 2550 kcal/kWh (10669 kJ/kWh) which will be retrofitted for flexible

operations (Sinha, 2019).

Supercritical plants have been categorised as the baseload units together with some efficient subcritical

plants. However, it was noted that some of the non-pit head supercritical units will find it difficult to

be scheduled because of the high variable cost and will be required to operate flexibly (Sinha, 2019).

More details of the categories are given in Table 9.

TABLE 9 UNITS AND CAPACITIES IDENTIFIED FOR FLEXIBILITY (SINHA, 2019)

Operation Mode Capacity, MW Number of units

Baseload 139,720 299

Flexible with efficiency retrofit* 20,740 80

Flexible-daily start 12,925 83

Flexible-low load 48,385 139

Plant retire/replace with supercritical 9370 86

Total 231,139 687

* inefficient units with a heat rate >2550 kcal/kWh (10669 kJ/kWh), can run on flexible operation with

efficiency retrofits




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Figure 23 shows the coal-fired power plants’ flexibility potential country-wide. Plants in almost all the

provinces will be affected by integration of renewable energy sources into the grid.

Figure 23 Country-wide flexibility potential based on universal metrics (Sinha, 2019)

Figure 24 shows a unit-wise approach and capacities, which if adopted, will make it possible to achieve

optimised cost and CO2 emission results while simultaneously supporting the flexibility requirements

of 2022 and beyond, as noted by Kendhe (2019).

Figure 24 All India – unit wise approach and capacities (Kendhe, 2019)




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Currently, there are various flexibility initiatives including NTPC’s (the largest government-owned

company) international collaboration in the Indio-German Energy Forum (IGEF), USAID and with

original equipment manufacturers (OEMs) including BHEL, GE and Siemens, and with Engie Lab.

For example, in the IGEF pilot studies for assessing the potential and feasibility of flexible operation

carried out by VGB at NTPC’s 210 MW Dadri and 500 MW Simhandri units, it was found that greater

flexibility can be achieved with minimal interventions and cost, until 55% minimum load is reached.

The study resulted in a guideline for achieving three levels of minimum load: 50%, 40% and 25%.

Although 50% and 40% minimum loads are possible with moderate investment, 25% minimum load is

currently not an economically viable option under Indian conditions. Various measures have been

suggested to improve flexibility including the use of: combustion optimisation and online combustion

management system; two–mill operation; advance frequency control; online coal analyser; automated

start-up sequence; and installation of online condition monitoring system. Additionally, under this

programme, VGB and Siemens carried out further tests at 490 MW Dadri Unit 6, which showed that a

minimum load of 40% could be sustained with some retrofits. These included: mill scheduler, main

and reheater steam temperature control, automated start of fans and modulating recirculation valves

for boiler feed pumps. Currently, the station is in the process of installing the necessary retrofits to

enable operation at 40% minimum load. To date, Siemens has successfully carried out a retrofit of

condenser throttling to provide a faster primary response, of a 7% power increase in 20 seconds, (Sinha,

2019; Chittora, 2019).

A study carried out by Intertek under USAID’s GTG-RISE (Greening the Grid-Renewable Integration

and sustainable Energy) project at four units, looked at how to minimise the damage associated with

cycling associated damage and how to improve the flexibility of these plants. The units were NTPC’s

200MW Ramagundam and 500 MW Jhajjar and two GESCL units of Ukai. The recommendations that

resulted included:

• use of automated start-up and shut-down management software to mitigate the existing cycling

damage;

• installation of the latest generation of programmable flame scanners;

• modification of some mills and the corresponding burners for low load operation with a burner

designed for normal combustion of the typical fuel at much lower coal flows;

• installation of upper furnace thermal mapping by zones to identify problems with specific

burners;

• installation of automated superheater drains;

• replacement of the air preheater’s soot blower swing arm steam cleaner with traveling lance soot

blowers with multiple nozzles for through cleaning of the APH;




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• nitrogen blanketing of demineralised water storage tanks to prevent oxygen-saturated feedwater

addition to the boiler and subsequent corrosion; and

• optimisation of maintenance and inspection procedures based on component wise costs and

damage modelling. Installation of condition monitoring equipment (Sinha, 2019).

Another flexibility initiative carried out by NTPC and Engie Lab Laborelec in a 200 MW Dadri units

and 500 MW Farakka unit was on the cost of cycling and damage modelling. The main

recommendations of this study included:

• optimisation of control loops;

• installation of electrical heating system on thick-walled components and turbine casing;

• automation of drain and vents;

• turbine efficiency upgrades for 4% heat rate improvement;

• installation of the latest online software for monitoring and improving the heat rate;

• installing EOH counters for improved maintenance performance; and

• online vibration monitoring (Sinha, 2019).

Other tests such as those carried by BHEL under the GTG-RISE program at the 500 MW Mouda unit

and by J-COAL under Indo-Japan Cooperation at the 500 MW Vindhayachai unit 11, studied the

measures needed to achieve higher ramp rates, of up to 3% (Sinha, 2019).

After the success of its numerous pilot projects, NTPC is adopting a fleet-wise approach to make its

units flexible, with support from Indo-German cooperation and GTG-RISE, USAID.

Capacity building initiatives

The present simulators in India are all for baseload operation. Flexible operation requires a different

skill set, so training is an important component of preparation for its introduction. Consequently,

teams from Indian power stations have undergone ‘train the trainers’ programmes in Germany and

USA. Exchange and knowledge sharing through international cooperation has helped in learning from

the experiences of the utilities who have been operating flexibly for years (Sinha, 2019).

11.3 POLAND

Although coal’s share in the energy mix in Poland has diminished from 90% in 2005 to 78% in 2017

(Maćkowiak Pandera, 2018), coal is, and will remain, an important source of electricity generation for

the next few decades, at least until 2050 (Szynol, 2018). In contrast to most EU countries, there are

still new coal-fired plants being built; six units with a total capacity of 4200 MW are expected to come

online by 2020 (Szynol, 2018). However, as energy demand is growing in Poland, at 1.2% a year on

average from 2005 to 2017, most of it, in the last 10 years or so, has been met by increased use of

renewable energy sources (RES) (hydropower, 2 %; onshore wind, 13%; biogas, 1%; biomass, 2%; and




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PV, 1%) (Maćkowiak Pandera, 2018). This has been driven by EU climate and energy policies (Szynol,

2018).

Figure 25 shows the fuel structure of the energy mix as of 31 December 2017. It shows that hard coal

and lignite provided nearly 80% of electricity generation and renewables only 8.4% (Szynol, 2018).

Figure 26 shows past and predicted net electricity generation by source to 2050 (Szynol, 2018),

indicating that more RES will be added, including offshore wind.

Figure 25 Power generation in Poland by source, as of 31 December 2017 (Szynol, 2018)

Figure 26 Past and predicted net electricity generation in Poland (Szynol, 2018)

As highlighted in Poland’s long-term diversified energy scenario, ‘Polish Energy Policy by 2050’

(Ministry of Economy, 2014), wind, gas-fired, combined heat and power (CHP) and biomass plants

will be given priority in supplying energy to the grid, followed by new 900 MW class USC coal units

which will run as baseload, whereas smaller subcritical units of 200–390 MW capacity will provide




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energy during peak times. Figure 26 shows the predicted electricity generation in Poland during a

winter’s day in the 2030s.

There are currently 54 units of 200 MW+ capacity at nine locations, as shown in Figure 27. Their

combined capacity is 12,263 GW and each of them is projected to work around 4000 h/y until about

2038. Most of them have already undergone renovations and retrofits to comply with EU legislation

and to extend their operational life by up to 20 years, while in the case of one unit (Rybnik nr 4), also

to improve its flexibility.

There are currently two programmes which aim to find solutions to make these units more flexible.

First, the Bloki 200+ project, co-founded by the state and the European Commission, will start later in

2019 to look at how these can be flexed to meet future needs. Solutions tested on two selected utilities

are expected to be applicable to larger units of 300 and 500 MW.

The other programme (IFCAMS) is a collaboration between Rafako S.A. a Polish boiler manufacturer,

Energoprojekt Katowice an engineering firm, the utility Tauron Wytwarzanie, the Silesian University

of Technology and the Cracow University of Technology and aims to find low-cost solutions (such as

I&C upgrades) for 200 MW+ class units (Browarski, 2019). It started in 2017 and tested its initial

theoretical assumptions in November 2018 in Tauron’s Łaziska power plant. Implementation of the

solutions tested will take place later in 2019 or in 2020.

Figure 27 Location and size of 200 MW+ units in Poland (Nabaglo, 2017)

11.3.1 Rybnik, unit 4, Polish Energy Group (PGE)

The Polish Energy Group (PGE) power plant in Rybnik (PGE Rybnik) is in the Upper Silesia region of

Poland and consists of eight subcritical units with a total capacity of 1800 MW (8 units x 225 MWe).




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This case study describes measures taken at Unit no. 4 which consists of a front-fired boiler type

OP-650 (subcritical with vertical water walls, skin case type with natural circulation and 650 t/h

nominal live steam load) and a turbine type 13K215 (with 3 pressure stages and nominal live steam

parameters of 12.75 MPa and 535°C). The unit has nominal power of 135–225 MW (net) and burns

local hard coal with a 20–30% ash content.

When owned by EDF the unit underwent various upgrades in 2013-17 to make it compliant with EU

legislation, optimise combustion, prolong its operational lifetime, and to improve its operational

flexibility.

Intensive trial runs took place to determine its maximum and minimum stable operational parameters

to improve its flexibility, following which several measures were implemented in the boiler and

turbine.

Improvement of starts ups

The ARB (Automatyczny Rozruch Bloku), system developed in house by EDF and Transition

Technologies, allows for an automatic start-up process from the ignition of the first oil burner to

achieving a minimum load operation. It controls several parameters including: the boiler drum’s

saturated temperature ramp rate; steam pressure at the boiler outlet; electric power ramp rate; fuel

ramp rate suitable for thermal rating of thick wall components; steam pressure before turbine

synchronisation and position of the turbine control valves.

DCS modernisation for lower minimum load and extended maximum load

Distributed control system modernisation allowed the reduction of minimum load from 135 MW to

90 MW (from 58% to around 39%) and an increase in maximum load from 225 MW to 230 MW. This

was possible through better control of various parameters and the introduction of new control units:

pressure in the combustion chamber, air flow control unit, live steam control unit with spray water

units, reheated steam control unit, boiler drum water level, condenser water level, and the unit

coordinate control (UCC).

Combustion optimisation

A number of measures were implemented to optimise combustion, including installation of the boiler

self-learning (artificial intelligence) system SILO. The system looks at 36 steered variables such as

distribution of air and fuel, O2 set points, load of coal feeders, and considers four possible disturbances:

unit load set point, mill units operation configuration, fuel quality and grinding quality. This allows

control of the live and reheat steam temperatures, average NOx, NOx balance distribution (between

left and right side), CO balance (between left and right side) and outlet O2 level. Remote controls of

mill grinding quality, flame scanners and the online acoustic flue gas temperature measurement system

(AGAM) were also installed.




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During baseload operation, coal is supplied by five ball ring mills. To accommodate lower loads, tests

with 2 and 3 mills were performed, with mill loading as low as 12%. The optimum mill configuration

for the 90 MW minimum load was found to be three mills supplying fuel to two top burner levels.

Air/fuel flow was optimised by various means. 1D modelling using EBSILON® and CFD modelling

using ANSYS® Fluent software allowed identification of the air/coal imbalance in relation to

secondary air flow as a source of maldistribution in furnace temperature. The imbalances are corrected

in real time using the air and fuel distribution control system and the DCS.

Online stress monitoring systems for thick wall components and other elements (BOTK and SKPP)

An online monitoring system, BOTK, developed in-house by EDF and Cracow University of

Technology, was installed for online stress monitoring of boiler drum outlet headers of superheaters

and reheaters. The system uses the temperature values measured on the external surface of monitored

components; based on these it calculates continuously the effective stress level and loss of residual

lifetime and indicates the remaining time for which they can be safely operated.

Lowering minimum load required additional monitoring of surface metal temperature on the

superheaters and reheaters tubes. This was achieved by installation of the SKPP system (system

developed in house by EDF and Institute of Power Engineering in Warsaw) which calculates maximum

allowable temperatures in the SH & RH tubes in each plate.

Measures in the turbine

Measurers in the turbine included modernisation of the low-pressure stage with installation of

advanced sealings as well as retrofit of last stage blades which can suffer from erosion during low load

operation (Nabaglo, 2017).

11.4 USA

Most of the US coal-fired power plants were built before the 1990s and nearly all were built for

baseload generation. Natural gas-fired gas turbines, both open and combined cycle, became the

technology of choice, with major deployment in the early- to mid-2000s (Hoffmann, 2019).

As in many countries, the USA’s energy mix has been changing in recent years. Figure 28 shows

changes in the sources of the net power generation between January 2007 and January 2017. As it

shows, the coal share decreased by 38%, natural gas increased by 54% and wind soared by 558% during

the ten-year period.




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Figure 28 Net power generation in USA, January 2007-17 (Hilleman, 2018)

Hoffmann (2019) stated that “until recently, there was a significant fuel price advantage for coal over

natural gas. Because the marginal cost of generating electricity from coal was usually lower than that

of generating electricity from natural gas, coal units continued to be dispatched for baseload and were

rarely dispatched as load following. Without a significant driver to invest capital for efficiency

improvements and/or increasing flexibility, few coal plant owners proceeded with improvement

projects” (Hoffman, 2019).

“Now with sustained low-cost natural gas, coal has lost much of the fuel price advantage. Coal units

are more often moved towards the back of the dispatch merit order which, in theory, would provide

the driver to undertake improvement projects” Hoffmann (2019). However, only a few major projects

have been undertaken by coal-fired plants, examples of which are given as case studies.

Figure 29 shows the net capacity factor of coal-fired power plants from 2008 to 2017. The results are

from 90 electricity generating units of less than 200 MW, 150 units of 200-500 MW, and 207 units of

500 MW or more gross capacity. All the categories experienced a downward trend, with the smallest

units’ net capacity factors falling just over 30%, 200–500 MW around 15%, and 500 MW or greater

units around 18–19%.




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Figure 29 Net capacity factors for coal plants from 2008 to 2017 (Black & Veatch, 2019)

The change in the coal plants’ operating regimes has had many impacts on their performance,

including: heat rate, equivalent availability factor (EAF) and reliability. As one example, the changes

in heat rate for the unit size ranges given above are shown in Figure 30. As evident from the plot, net

heat rate increased for all plants, with the smallest increase for the largest size units and the greatest

for the units below 200 MW capacity. Coal-fired power plants that had undergone a fuel switch were

excluded from the population, so the change in net capacity factor and heat rate is due mostly to

reduced demand, reduced operating load, and increased starts and stops (Black & Veatch, 2019).

Figure 30 Changes in coal plant’s net heat rate from 2008 to 2017 (Black & Veatch, 2019)

The detail for the following case studies was supplied by Black & Veatch (2019) and the power plants

described wish to remain anonymous.




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Case study 1

This case study describes flexibility improvements in two plants (Plant 1 and Plant 2) belonging to the

same utility.

Plant 1 is a forced circulation 670 MW unit using tangential firing with six coal mills. Plant 2 is a natural

circulation 700 MW unit using wall firing with ten coal mills. Both units are equipped with cold-side

ESP, SCR and wet FGD.

As part of a major fleet-wide effort to improve the competitiveness of their coal assets, the utility

examined over sixty different ways to improve operations and/or capital equipment at Plant 1 and 2

to achieve stable operation at reduced load, greater flexibility and with cycling. While the typical stable

minimum load was between 20% and 25% on both plants, tests had been carried out to try to reduce

this to 10%. For Plant 2, it was found that the natural circulation design was not amenable to such

low-load operation, and the prospect of adding a booster feedwater pump was explored to assist with

operation and maintain nucleate boiling below 15% of MCR.

One of the first operations-related changes made concerned using the utility’s monitoring and

diagnostics centres to create a controllable losses report for each plant, as well as a low-load operations

report. This allowed a clear review of operations and efficiency impacts, and the identification of

factors that might assist with such considerations and coal mill stability at lower loads. Some of the

specific items that were examined included:

• A review of SCR performance after short-term and extended outages, to determine whether ash

deposition on the SCR during the outages was causing blockage of the flue gas paths.

• A review of the tube failure history, and whether tube failures correlated with cycling operation

or starts/stops of the unit. These were divided into cold/warm/hot starts to determine whether

any specific type of operation was potentially more stressful than other types.

• Examination of the air flow balance, temperature balance, and operation of the coal mills,

feeders, primary air, and air heater systems during low-load operation, to help operators gain

greater confidence when operating with only two mills. Typically, operators at both plants were

unwilling to run the plants for extended periods with only two mills in service. This was because

of the concern that transient fluctuations in air or fuel flow might cause one mill to trip, leading

to one-mill operation, which would be unstable and trip the entire plant. Computer simulators

were then used to assist operators in becoming more comfortable and familiar with two-mill

operation.

Extended operation with one mill in service was not explored at this time due to safety concerns but

may be explored in the future. At another plant belonging to this utility, one-mill operation is being




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explored with natural gas burners as support, so a trip of one mill might not trip the unit, providing

that the gas burners are able to ramp up their heat input rapidly.

Means to improve the reliability of critical generating components during extended shut-down periods

due to long-term cycling, were also examined. For example, operation modes such as three months

on/three months off during the year (operating in summer/winter) were considered. While exploring

how operations could be improved, the following recommendations were made:

• Extra cleaning of the SCRs via soot blowing should be performed any time the plant is expected

to be offline for more than 4–5 days. It was found, especially in the warmer months, that high

humidity was leading to significant agglomeration of fly ash in the SCR, which hindered NOx

removal after re-start.

• Corrosion due to residual water in the low-pressure section of the steam turbine was a recurrent

problem. To mitigate this, an external heater was used to help dry the LP turbine and reduce

corrosion.

Both plants found that ash fallout in the flue gas ductwork could be significant at low flue gas flow

rates, in some cases building up to a couple of metres. This not only caused a flow restriction upon

start-up or ramp-up, but when the plants were shut down for some time, the high ambient humidity

would react with the ash, causing solidification. Also, ductwork collapse became a real risk. Hence

careful cleaning of all flue gas ductwork subject to ash deposition when the load was reduced was

introduced. Alternatively, the plant should be shut down subsequent to a load reduction for more than

4–5 days. It was found that the critical flue gas velocity for ash dropout was around 0.31 m/sec.

Plant 2 experienced problems with their wet FGD at the new minimum loads. Firstly, the plant

operators did not have experience with FGD’s chemistry adjustments at low-load operation. As the

original equipment manufacturer process flow and process chemistry guidelines for the plant did not

recommend operation below 40% of maximum output, there was some guesswork involved for

balancing the scrubber chemistry at low loads (pH, calcium/sulphur ratio, oxidation air flow, and

more). It was found that some substantial differences in chemistry were needed at 10–15% load, but

not for 20–25% load.

Secondly, at low additive feed and recycle flow rates there was often solid particle dropout in the lines,

which led to unstable flow and sometimes line blockage. To mitigate this, the use of variable frequency

drives (VFDs) for the main pumps in the system has been recommended, but not yet deployed.

As long-term operation data from both plants have been reviewed, a concern was raised as to the

potential for flow-accelerated corrosion due to cold feedwater being injected into a preheated header

during warm starts. Some methods for preheating the feedwater have been discussed, however no

solution has been found at this stage.




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Other items have been examined or deployed too. These include: using dynamic classifiers in the coal

mills to improve fineness performance at low mill loads, VFD deployment on all major plant motors

such as primary air fans, forced draft fans, induced draft fans, mill and circulating water pumps.

Improved methods of ‘bottling up’ the plants during short-term market-driven offline periods have

been discussed, to retain as much heat as possible and to shorten start-up time (Black & Veatch, 2019).

Case study 2

This case study describes operational flexibility improvement projects at a power plant from another

utility. The plant consists of two nearly identical 400 MW forced circulation units, using wall-firing

with three coal mills and equipped with hot-side ESP, SCR, a mercury capture system, and wet FGD.

This plant does not face such operational challenges of cycling as the first case study; nonetheless, it

faces a constraint with respect to its environmental permit for operations. Namely, the SCR at the plant

is sensitive to the inlet gas temperature. Consequently, cycling and load flexibility were curtailed due

to the need to maintain the plant output at between 70% and 80% MCR to maintain the correct

temperature for its SCR operation. Additionally, low flue gas temperatures were also found to lead to

a greater chance of sticky ash deposition within the SCR catalyst. However, this was a minor issue

overall due to the hot-side ESP removing most of the ash prior to the SCR. ESP air in-leakage of up to

10% has also been a concern, resulting in the flue gas temperature often decreasing by 25°C to 75°C

across its length, thus further reducing the SCR inlet temperature.

One of the mitigation measures implemented was the addition of a system to extract steam from the

main steam line during operation and apply it to the final feedwater heater. This increased the inlet

water temperature of the economiser and minimised the temperature drop of the flue gas across it.

This allowed for faster SCR warm-up and a lowered minimum load of 50–60% of MCR while meeting

the NOx emissions limit. The additional benefit of this so-called ‘pegging system’ was its deaeration

effect which should help reduce dissolved gases in the feedwater, thus reducing corrosion potential

during cold unit operation.

An additional flexibility improvement measure was the development of plant simulators in a local

virtual control room, so the operators could be trained to operate under unexpected or transient

conditions.

As the coal mills at this unit are known to have problems with low-load operation and turndown,

extensive maintenance and some upgrades have been carried out to improve fineness control at a

variety of load points as well as utilising pre-dryers and crushers upstream of the mills to improve the

mill coal inlet feed size and moisture content. Audio and vibration sensors at many different points

are used to monitor the performance of the mills. In contrast to the units described in Case 1,

single-mill operation can be employed at each plant; but this is avoided because of the potential for a




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single mill trip to take the entire plant offline. Consequently, it is unlikely that the minimum load would

ever be reduced below 40% without further improvements to the plant.

VFD deployment has been considered for several large plant motors. However, it has not been

undertaken widely to minimise capital expenditure at the plant. Also, FGD scrubber chemistry has

been problematic at low-load operation, but as loads below 50% are not often encountered, no

significant modifications have been made. The plant does have the ability to directly add hydrated lime

to the scrubber feed to increase removal efficiency, but efforts are underway to improve scrubber

operation to avoid use of the more expensive lime product (Black & Veatch, 2019).

11.5 COMMENTS

Coal-fired power plants have to adapt to new operating regimes as more intermittent energy sources

are integrated into the electricity grids of many countries. Flexibility requirements vary between

regions and individual plants, as evident from the country profiles and case studies. There are several

measures available but there is no ‘one-size-fits-all’ solution and achieving greater plant flexibility is a

result of many trials.

C O N C L U S I O N S



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1 2 C O N C L U S I O N S

The integration of variable renewable energy (VRE) such as wind and solar into grids means that

coal-fired power plants must adopt new operating regimes to balance fluctuations in power output

from these sources. The growing role of VRE has become central to the energy policies of advanced

economies, especially in the EU, but it also plays an important role in the United Nations Sustainable

Development Goals (SDGs) that support energy development in the emerging economies. Goal 7, that

promotes affordable and clean energy, encourages the development of more sustainable energy

sources in the form of VRE, but also in the form of advanced fossil fuel technologies, where cleaner

coal technologies could have a role, especially in flexible mode to support VRE deployment. Flexible

coal-fired power plants, in addition to other options such as grid and demand-side management, will

thereby ensure vital stability of the electricity grid.

Coal-fired power plants designed for baseload operations now run in cycling modes with faster ramp

rates, low load and on/off cycling. Operation at off-design conditions increases the wear and tear of

plant components and brings new challenges. As more VRE sources are added to the grid worldwide,

the need for flexible operation is only going to increase. Consequently, new strategies and effective

management are required to mitigate and/or avoid the higher probability of equipment failure and

consequent reduction in unit life, the critical risk of process safety and increased costs (Hillman, 2018).

The flexibility of existing power plants can be improved in various ways. They include retrofitting new

technologies, modifying existing, or adopting new, operating procedures and staff training, from

operating personnel to managerial level. This latter option is frequently overlooked.

Control systems are vital for power plant operation. They allow navigation between different loads

and ensure stable operation by adjusting all related process variables. Older plant control systems

behave differently during full load and part load operation (VGB, 2018). Hence the upgrade of I&C

systems improves accuracy, reliability and speed of control. For example, it allows operation of the

plant closer to the material limitations of important parts, such as the superheater headers, which

means running at high temperatures without significantly reducing the lifetime of the component.

Optimisation of I&C is the most cost-effective way to improve plant flexibility and should be a

precondition for other measures. In many plants, an upgrade of I&C is combined with plant

engineering upgrades such as retrofits of the boiler, burners or turbine or other components (Agora


Operation with low minimum load minimises the number of shut-downs required which reduces the

impact on plant component life and lowers operating costs. Minimum load as low as 10% is possible if

various measures are implemented, as demonstrated by numerous plants in Germany. Means to

achieve the low minimum load centre on the boiler, fuel supply and combustion systems. Stable

combustion is key to achieving it. It depends on a number of factors, including: firing rate or fuel




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quality, to prevent inaccurate fuel:air ratios or uneven coal flow. Various plants have achieved success

by: operation with low excess air, flame monitoring, fuel/air flow control systems, tilting burners,

auxiliary firing with a dried lignite ignition burner, operation with fewer mills and only top-level

burners, deploying smaller mills, thermal energy storage for feedwater heating, vertical internally

rifled evaporators, a sliding pressure operation and economiser modifications.

Start-up procedures are complex and expensive as they usually require auxiliary fuel during burners’

ignition time. Shortening start-up time and being able to ramp up rapidly ensure a quick response to

changes in the market conditions and allow plants to participate in different markets, such as for

ancillary services. Start-up times in power plants can be shortened by several measures. These include:

reliable ignition, integration of a gas turbine, reducing thickness of thick wall boiler components such

as headers or including more headers, external heating of thick boiler components, and cleaning of

boiler deposits. Measures in the turbine include: advanced sealings, turbine bypass (HP or LP), internal

cooling of the turbine casing.

Many of the improvements for start-up aid high ramp up rates, which allow dynamic adjustment to net

power requirements. Additional measures include exploring mill storage capacity, condensate

throttling, and the use of an additional turbine valve.

Designers of new plants have an opportunity to include flexibility requirements in their design. For

example, use of new advanced materials for thick-wall high-pressure components such as headers, or

designing them based on a shorter baseload operational life have been shown to reduce life

consumption during rapid cycling. Vertical evaporators with internally-rifled tubing have shown good

flow characteristics and flow stability, valuable in improving the rate of load change during flexible

operation. Designing plant for a sliding pressure operation is also recommended. Additionally, plants

which include a condensate throttling system can increase their primary frequency response

significantly. Other design features include steam cooling of the inner turbine casing as well as HP and

feedwater heaters bypass and thermal energy storage for feedwater preheating. The designers of new

power plants, however, may face a conflict between flexibility and efficiency.

The performance of emission control systems can be affected by off-design conditions arising from

the flexible operation of power plants. The main effects arise from the temperature of the flue gas that

changes with the cycling regime. Hence maintaining the temperature at the required level is essential,

particularly for NOx controls. There are a number of ways this can be achieved. For example, the use

of an additional heater for flue gas prior to SCR inlet has been practised. While in the case of SNCR,

the use of multiple zones of injection and the ability to take injectors in and out of service as needed,

allows for chemical release within the desired chemical and thermal environment.

In the case of flue gas desulphurisation (FGD), the number of shut-downs and start-ups needs to be

minimised to avoid slurry solidification and accumulation of start-up fuel oil residues on linings, as




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well as averting long warm-up periods. It is normal practice to keep the FGD unit in stand-by mode in

case of short outage periods. This avoids solid deposits and keeps the FGD unit ready to start quickly

to remove SO2. FGD may be affected by cycling operation to a greater extent than NOx and PM

controls; hence it needs sophisticated control to work efficiently in cycling mode. PM controls usually

cope well with flexible operation conditions providing that the flue gas temperature does not fall below

70°C.

A high proportion of on-load failures originate from preventable damage caused during offload periods.

The risks are higher for cycling units as frequent start-ups/shut-downs and standby periods disrupt

the physical and chemical conditions within the water/steam circuit, leading to corrosion and other

damage during standby. The resulting damage can be catastrophic. Thus, proper preservation of the all

water-steam circuits is essential. There are various methods available, which should be selected based

on the plant’s individual characteristics.

The impacts of flexible operation on various areas of power plants areas well known and the technical

means exist to mitigate them. Equally important are plant management strategies. These involve

maintenance strategies and adopting new, or modifying existing, operational practices. These

measures are especially recommended for older power plants which have a limited remaining service

life where it may not be viable to retrofit new systems.

As evident from case studies, the meaning of flexibility varies from power plant to plant based on grid

characteristics, electricity market design and cost factors. Hence there is not a ‘one-size-fits-all’

solution and achieving greater plant flexibility is a result of many trials. In the words of Professor

Lockyer: “it is a journey” (2018).

The technologies described in this report enable coal plants not only to extend their dynamic

capabilities as flexible back-up to VRE, but to maintain their performance as close to optimum as

possible during such flexible operation, although there is usually some negative influence on plant

efficiency. However, by minimising this impact, minimising degradation of plant equipment, and

maintaining pollutant control system performance, the environmental benefits of VRE integration can

be maximised, and the partial offset due to reduced efficiency and the more costly operation of cycling

coal plant is kept to a minimum.

R E F E R E N C E S



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1 3 R E F E R E N C E S

Agora Energiewende (2017) Flexibility in thermal power plants. Available at: https://www.agora-energiewende.de/fileadmin2/Projekte/2017/Flexibility_in_thermal_plants/115_flexibility-report-WEB.pdf June 2017. Accessed on 05 Nov 2018. Boyle, Stamatakis and de Havilland Advanced SNCR NOx Reduction Experience on Multiple Large Utility Boilers (2015)

Black & Veatch (2019) Flex Plant Case Studies National Energy Technology Laboratory, Pittsburgh, March 14, 2019.

Browarski R (2017) Koncepcja strategiczna modernizacji blokow klasy 200 MW (In Polish). Presented at: II Seminarium na temat Programu 200+, Warszawa, Poland (May 2017)

Buck T (2019) Germany: Angela Merkel’s tarnished legacy on the environment The country’s green credentials are under scrutiny https://www.ft.com/content/887637e8-2085-11e9-b126-46fc3ad87c65

Caravaagio M (2014) Layup practices for cycling units Available at https://www.power-eng.com/articles/print/volume-118/issue-8/features/layup-practices-for-cycling-units.html

Chittora S (2018) Flexible operation of Thermal Power Plants in India – Experience so far. Presented at: ‘Improving power plant flexibility – paving the way for greening the Grid’, NTPC Power Management Institute, Noida, India 27 Sep 2018

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S O U R C E S F O R I M A G E S

Figure

Number

Caption Attribution Source

7 Example of HP turbine advanced sealing Żbik, 2017 personal communications



12 Boiler tube failures influenced by off

load corrosion

McCann, Uniper, 2019 personal communications

13 Pitting (bottom of the figure) and blade

failure in LP turbine

McCann, Uniper, 2019 personal communications

15 Turbine blade before treatment McCann, Uniper, 2019 personal communications

16 Turbine blade with filming amine McCann, Uniper, 2019 personal communications

17 SNCR temperature window with the

injection

de Havilland, 2019 personal communications

http://www.eecpowerindia.com/codelibrary/ckeditor/ckfinder/userfiles/files/13_Uniper%20Presentation%20EFO%20and%20Adjusting%20Operating%20regimes%20.pdf

http://www.eecpowerindia.com/codelibrary/ckeditor/ckfinder/userfiles/files/13_Uniper%20Presentation%20EFO%20and%20Adjusting%20Operating%20regimes%20.pdf

https://www.theguardian.com/environment/2019/feb/07/coal-power-station-cottam-to-close-after-half-a-century%20(7

https://www.theguardian.com/environment/2019/feb/07/coal-power-station-cottam-to-close-after-half-a-century%20(7

http://www.powermag.com/vietnam-reconsiders-new-coal-fired-power-plants/








Full Name Organisation Country

Andrew Ivory Low Emissions Coal and CO2 Storage Branch Australia

Robert Ceic GHD Australia

Peter Warbrooke Pegnel Australia

Arif Syed Department of Resources, Energy and Tourism Australia

Rohan Stanger University of Newcastle Australia

Martin Oettinger ACALET Australia

Noel Simento ANLECRD (Australian National Low Emissions Coal) Australia

Geoff Gay TRUenergy Australia

Justin Flood Delta Electricity Australia

Kelly Thambimuthu CO2CRC Australia

Greg Evans Minerals Council of Australia Australia

Stephen Malss ACALET Australia

Chris Greig The University of Queensland Australia

Brad Page Global CCS Institute Australia

Zain Westmacott Stanwell Australia

Greg Evans ACALET Australia

Steve Malss ACALET Australia

Jason Waters Synergy Australia

Stephen Wilson Cape Otway Associates Australia

Steven Kulibaba HRL Technology Pty Ltd Australia

Shane Carruthers GDF SUEZ Australian Energy Australia

Peter Redlich Energy Technology Innovation Division Australia

David McManus Brown Coal Innovation Australia Limited Australia

Andy Wearmouth Synergy Australia

Tristian Kemp CSIRO Energy Technology Australia

Leigh Miller Stanwell Australia

Margaret Sewell Department of Resources, Energy and Tourism Australia

Mark Weaver Department of Resources, Energy and Tourism Australia

Michela Secci ANLECRD (Australian National Low Emissions Coal) Australia

Kai Tullis European Commission Belgium

Brian ricketts EURACOAL Belgium

Vassilios Kougionas European Commission Belgium

Peter Horvath European Commission Belgium

Qu Sijian BRICC China

ZHENG Yunzhe Electric Power Planning & Engineering Institute (EPPEI) China

Wang Lin Beijing Research Institute of Coal Chemistry China

Qiuye Xie Electric Power Planning & Engineering Institute (EPPEI) China

Rui Sun Electric Power Planning & Engineering Institute (EPPEI) China

Li Xiang Electric Power Planning & Engineering Institute (EPPEI) China

Yunzhe Zheng Electric Power Planning & Engineering Institute (EPPEI) China

Raimund Malischek International Energy Agency France

Sabine van den Broek Forschungszentrum Jülich GmbH Germany

Oliver Then VGB Germany

Jürgen-Friedrich Hake Forschungszentrum Jülich GmbH Germany

Helmut Vierrath NULL Germany

Roland Aeckersberg Loesche GmbH Germany

Markus Becker GE Germany

P Selvakumaran N/A India

Kankaraj Ganesh Palappan Bharat Heavy Electricals Limited (BHEL) India

P S Guruchandran Bharat Heavy Electricals Limited (BHEL) India

R Sukumar Bharat Heavy Electricals Limited (BHEL) India

Narendra Prasad Bharat Heavy Electricals Limited (BHEL) India

R Dhanuskodi Bharat Heavy Electricals Limited (BHEL) India

S Chandrasekaran Bharat Heavy Electricals Limited (BHEL) India

V Vasudevan Bharat Heavy Electricals Limited (BHEL) India

Page 1 of 3


D Ramakrishnan Bharat Heavy Electricals Limited (BHEL) India

P Ashokkumar Bharat Heavy Electricals Limited (BHEL) India

I Naga Mohan Bharat Heavy Electricals Limited (BHEL) India

K Ganesh Palappan Bharat Heavy Electricals Limited (BHEL) India

Alessandro Lanza Sotacarbo S.p.A. Italy

Stefano Giammartini Sotacarbo S.p.A. Italy

Gianni Serra Sotacarbo S.p.A. Italy

Ennio Macchi Politecnico di Milano Italy

Giorgio Cau Unica Italy

Fumihiko Tamamushi IHI Corporation Toyosu IHI Japan

Yoshinori Itaya Nagoya University Japan

Masaki Onozaki The Institute of Applied Energy Japan

Takashi Hongou UBE Industrial Ltd Japan

Masashi Hishida None Japan

Mikio Miyake Japan Advanced Institute of Science & Japan

Tadaaki Shimizu Niigata University Japan

Akira Ohki Kogoshima University Japan

Yasuo Ohtsuka None Japan

Toshinori Kojima Seikei University Japan

Isao Mochida Kyushu University Japan

Akira Tomita Elsevier Japan

Masanobu Hasatani Aichi Institute of Technology Japan

Mitsuru Sasaki Kumamoto University Japan

Koichi Miura Kyoto University Japan

Tetsuo Aida Kinki University Japan

Ichiro Naruse Nagoya University Japan

Mikio Sato CRIEPI Japan

Takashi Kuwabara Tokyo Electric Power Japan

Ken Okazaki Tokyo Institute of Technology Japan

Makoto Nunokawa NEDO (New Energy and Industrial Technology Development Organization) Japan

Yasuhiro Yamauchi NEDO (New Energy and Industrial Technology Development Organization) Japan

Harumitsu Suzuki NEDO (New Energy and Industrial Technology Development Organization) Japan

Takeshi Murakami NEDO (New Energy and Industrial Technology Development Organization) Japan

Nobuyuki Zaima NEDO (New Energy and Industrial Technology Development Organization) Japan

Hideaki Tanaka NEDO (New Energy and Industrial Technology Development Organization) Japan

Maciej Bialek Ministry of Energy Poland

Ireneusz Pyka GIG Central Mining Institute (Glowny Instytut Gornictwa) Poland

Anna Margis Polish Ministry of Energy Poland

Lucyna Szoltysek GIG Central Mining Institute (Glowny Instytut Gornictwa) Poland

Graham Chapman Siberian Coal Energy Company (SUEK) Russian Federation

Julia Lykova Siberian Coal Energy Company (SUEK) Russian Federation

Sergei A. Grigoriev Siberian Coal Energy Company (SUEK) Russian Federation

Graham Chapman Siberian Coal Energy Company (SUEK) Russian Federation

Sumaya Nassiep Eskom South Africa

Nickki Wagner University of the Witwatersrand South Africa

Gail Gordon University of the Witwatersrand South Africa

Brian North CSIR South Africa

Nikki Fisher Anglo American South Africa

Christopher Gross Eskom South Africa

Rosemary Margaret Sarah Falcon University of the Witwatersrand South Africa

Jovita Juodaityte Eskom South Africa

Sumaya Nassiep Eskom South Africa

Titus Mathe Eskom South Africa

Deidre Herbst Eskom South Africa

Mandy Rambharos Eskom South Africa

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Vikesh Rajpaul Eskom South Africa

Charmaine Wolf Eskom South Africa

Adam Luckos Sasol South Africa

Prach Chongkittisakul Banpu Public Company Limited Thailand

Akaraphong Dayananda Banpu Public Company Limited Thailand

Charintorn Techakunaruksa Banpu Public Company Limited Thailand

Chatphol Meesri Banpu Public Company Limited Thailand

Waleed Salman DEWA UAE

Jamal Shaheen Alhammadi DEWA UAE

Neil Grant DEWA UAE

Mohammad Jame DEWA UAE

Stuart Mitchell Doosan United Kingdom

Andy Timms Doosan Babcock United Kingdom

John Gale N/A United Kingdom

John Gale IEA Greenhouse Gas R&D Programme United Kingdom

Stuart Mitchell Doosan Babcock United Kingdom

Charles Conroy Greenbank Group, UK United Kingdom

Brenda Robinson Doosan Babcock United Kingdom

Steve Mills IEA Clean Coal Centre United Kingdom

Vivek Savarianadam Greenbank Group, UK United Kingdom

Gregory Kelsall GE United Kingdom

Michael Reid Duke Energy United States

Rosalind Carter US Department of Energy (DOE) United States

Jarad Daniels US Department of Energy (DOE) United States

Bernard A. Kenney US Department of Energy (DOE) United States

Ronald Schoff EPRI United States

Scott Smouse US Department of Energy (DOE) United States

Wally Chinitz General Applied Science Labs Inc. United States

Ayaka Jones US Department of Energy (DOE) United States

Jay Braitsch US Department of Energy (DOE) United States

Adam Wong US Department of Energy (DOE) United States

Regis Conrad US Department of Energy (DOE) United States

Bhima Sastri US Department of Energy (DOE) United States

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