Supercritical Power Plants

Why a supercritical power plant?

Supercritical Power plants operate at temperatures resulting in higher efficiencies – up to 46 percent for supercritical plants – and lower emissions than traditional (subcritical) coal-fired plants. The "efficiency" of the thermodynamic process of a coal-fired power describes how much of the energy that is fed into the cycle is converted into electrical energy. The greater the output of electrical energy for a given amount of energy input, the higher the efficiency.

A supercritical power plant uses a boiler/turbine system that operates at 580 degrees C; subcritical plants operate at 455 degrees C. A supercritical plant is much more efficient than a subcritical plant, producing more power from the less coal and with lower emissions.

Benefits of advanced supercritical power plants include:

o Reduced fuel costs due to improved plant efficiency. (Excellent part-load efficiency (Drop 2% at 75%/ 7% at 50%))

o Significant reduction in CO2 emissions. (CO2 Emission reduced by 15% compared to sub-critical)

o Excellent availability, comparable with that of an existing sub-critical plant.

o Plant costs comparable with sub-critical technology and less than other clean coal technologies.

o Much reduced NOx, SOx and particulate emissions.

o Compatible with biomass co-firing.

o Can be fully integrated with appropriate CO2 capture technology.

o In summary, highly efficient plants with best available pollution control technology will reduce existing pollution levels by burning less coal per megawatt-hour produced, capturing the vast majority of the pollutants, while allowing additional capacity to be added in a timely manner.

Today’s state-of-the-art, supercritical coal-fired power plants provide efficiencies that exceed 45 percent. This benefit will significantly increase the kWh produced per Kilogram of coal burned, with fewer emissions. In addition to using less coal, lower emission levels for supercritical plants are achieved using well-proven emissions control technologies:

NOx emissions: Nitrogen oxide emissions are reduced using a combination of low NOx burners and selective catalytic reduction technology.

SOx and SO2 emissions: Sulfur oxide and sulfur dioxide are captured using wet limestone-gypsum flue gas desulphurization (FGD). The product, gypsum, can be recycled for use in products such as wallboard, plaster and fertilizer.

Particulate emissions: More than 99% of particulate dust is removed via an electrostatic precipitator (ESP).

Operational problems of supercritical plants & their solutions are as follows

• Frequent Acid Cleaning – Oxygenated water treatment• High minimum stable load – Low load recirculation

Typical Supercritical Power Plants

Typical

advanced

supercritical pulverized

clean coal plant (SCPC) will use the latest and most advanced technology to improve operating efficiency and control emissions.

o Advanced SCPC technology is proveno More than 400 SCPC plants are operating successfully worldwide, including 25 with the

advanced SCPC technology Power4Georgians plans to use

o Most new coal plants planned or currently under construction in the United States use SCPC technology SCPC systems operate at higher temperatures and greater steam pressures than conventional systems. They require less coal per megawatt-hour, leading

to lower emissions per megawatt (including carbon dioxide and mercury), and lower fuel costs per megawatt, leading to higher efficiency and lower fuel costs. In short, SCPC provides the best overall balance in performance, reliability, lower emissions and cost for the company’s customers.

High Performance Coal-Fired Plants Are Cleaner

Many regions are experiencing fast growing electricity demand. Permitted emissions from power plants have been reduced to meet air quality standards. Major part of electricity produced in India comes from coal. Coal is an abundant fuel resource and forecasts show that it is likely to remain a dominant fuel for electricity generation for many years to come.

Power plant suppliers have invested heavily in generation technologies that produce power more efficiently. Enhanced plant reduces emissions of CO2 and all other pollutants by using less fuel per unit of electricity generated. Modern subcritical cycles have attained efficiencies close to 40% lower heating value (LHV). Further improvement in efficiency can be achieved by using supercritical steam conditions. Current supercritical coal fired power plants have efficiencies above 45% (LHV). A one percent increase in efficiency reduces by two percent, specific emissions such as CO2, NOx, SOx and particulates (See Figure 1).

What is Supercritical?

"Supercritical" is a thermodynamic expression describing the state of a substance where there is no clear distinction between the liquid and the gaseous phase (i.e. they are a homogenous fluid). Water reaches this state at a pressure above 22.1 mega Pascals (MPa). (See Figure ).

The "efficiency" of the thermodynamic process of a coal-fired power describes how much of the energy that is fed into the cycle is converted into electrical energy. The greater the output of electrical energy for a given amount of energy input, the higher the efficiency. If the energy input to the cycle is kept constant, the output can be increased by selecting elevated pressures and temperatures for the water-steam cycle.

Up to an operating pressure of around 19 MPa in the evaporator part of the boiler, the cycle is subcritical. This means, that there is a non-homogeneous mixture of water and steam in the evaporator part of the boiler. In this case, a drum-type boiler is used because the steam needs to be separated from water in the drum of the boiler before it is superheated and led into the turbine. Above an operating pressure of 22.1 MPa in the evaporator part of the boiler, the cycle is supercritical. The cycle medium is a single-phase fluid with homogeneous properties and there is no need to separate steam from water in a drum. Once-through boilers are therefore used in supercritical cycles.

Advanced Steels

Currently, for once-through boilers, operating pressures up to 30 MPa represent the state of the art. However, advanced steel types must be used for components such as the boiler and the live steam and hot reheat steam piping that are in direct contact with steam under elevated conditions. Therefore, a techno-economic evaluation is the basis for the selection of the appropriate cycle parameters. Figure depicts a supercritical cycle arrangement with steam parameters that yield high efficiency while allowing the use of well-proven materials.

Steam Conditions

Today’s state of the art in supercritical coal fired power plants permits efficiencies that exceed 45%, depending on cooling conditions. Options to increase the efficiency above 50% in ultra-supercritical power plants rely on elevated steam conditions as well as on improved process and component quality.

Steam conditions up to 30 MPa/600°C/620°C are achieved using steels with 12 % chromium content. Up to 31.5 MPa/620°C/620°C is achieved using Austenite, which is a proven, but expensive, material. Nickel-based alloys, e.g. Inconel, would permit 35 MPa/700°C/720°C, yielding efficiencies up to 48%. Manufacturers and operators are cooperating in publicly sponsored R&D projects with the aim of constructing a demonstration power plant of this type.

Other improvements in the steam cycle and components can yield a further 3 percentage points rise in efficiency. Most of these technologies, like the double reheat concept where the steam expanding through the steam turbine is fed back to the boiler and reheated for a second time as well as heat extraction from flue gases have already been demonstrated. However, these technologies are not in widespread use due to their cost.

Supercritical Boiler

Two Schools of Boiler Design

Bension design : Licensor Siemens AG Sulzer design : Licensor ABB

Bension Licensees Sulzer Licensees

• Deutsche-Babcock Korean Heavy Ind.• Steinmuller MHI

• AE&E ALSTOM

• BWE

• Mitsui Babcock

• Babcock Hitachi

• Babcock & Wilcox

• Ansaldo Energia

The boiler is a key component in modern, coal-fired power plants. Its concept, design and integration into the overall plant considerably influence costs, operating behavior and availability of the power plant.

Once-through boilers have been favored in many countries, for more than 30 years. They can be used up to a pressure of more than 30 MPa without any change in the process engineering. Wall thicknesses of the tubes and headers are designed to match the planned pressure level. At the same time, the drum of the drum-type boiler, which is very heavy and located on the top of the boiler, can be eliminated. Since once-through boilers can be operated at any steam pressure, variable pressure operation was

introduced into power plants at the start of the 1930s to make the operation of plants easier.

Once-through boilers have been designed in both two-pass and tower type design, depending on the fuel requirements and the manufacturers general practice. For the past 30 years, large once-through boilers have been built with a spiral shaped arrangement of the tubes in the evaporator zone. The latest designs of once-through boilers use a vertical tube arrangement.

In a p. f power plant, power generation cycle efficiency depends primarily on the temperature difference across the steam turbine. Increasing this temperature difference can be achieved by using higher steam temperatures and this leads to higher cycle efficiencies. Generally, the use of higher steam temperatures is also linked to increased pressures to keep the steam volume within manageable limits.

The increased pressure also increases cycle efficiency and, although this increase is a second-order effect compared with the effect of temperature, it can still make an important contribution to increasing overall plant efficiency.

The temperature difference can also be increased by reducing the cooling water temperature to the condenser, but this is largely a function of site location and explains why the highest efficiencies are displayed by plant with cold, sea-water cooling such as those on the Baltic Sea. This cooling water effect is the same for subcritical or supercritical power plant. Also, when cooling-water temperatures are too low, losses can increase because of higher steam outlet velocities, caused by too-low condenser pressures.

In a typical design, the steel structure of the boiler house is also integrated into the boiler structure. The boiler house accommodates the coal bunkers, coal feeders, coal milling plant and the forced draught and primary air fans. To minimize the space requirement, a symmetrical arrangement of the coal bunkers, feeders and milling plant, on each side of the boiler, is generally chosen. The flue gas ducts, air pre-heaters and electrostatic precipitators (ESPs) are sited outside the boiler house, with the space below the ESPs being used for the fly ash discharge systems. The two induced-draught (ID) fans are housed in a separate building to reduce noise levels at the plant.

The boiler itself is designed for a high degree of operational flexibility in its load regime. This is because most of the boilers are called on to regularly operate in a daily load following mode and are required to handle a wide range of coal types. This flexibility of design is achieved by careful selection of pressure part materials and by design features that would avoid the use of think-section components in critical areas. In this way, the cyclic stresses that cause fatigue can be minimized, where combination of these with high-temperature creep could shorten the life of these components. The furnace dimensions are chosen to meet the requirements of low-NOx emissions in the flue gases whilst minimizing the amounts of unburned carbon-in-fly-ash.

In a two–pass Benson boiler, designed by Mitsui Babcock Energy Limited, and constructed by Stork Ketels BV under license, a two-pass boiler arrangement was chosen for the plant because it offered a number of benefits, including the following:

Boiler design would reduce the capital cost of plant foundations

The vertical superheater tubes that this design allows would produce lower ash-slag adhesion

No high-temperature tube bank supports would be necessaryThe pipe-work between the boiler and steam turbine would be shorter, due to the reduced boiler height.

The boiler steam conditions (260bar, 540O

C/568O C) selected were regarded as ‘state-of-the-art’ at the time, although steam conditions in Europe and Japan have since increased to 300bar, 600 O C/610O C.

The boiler is operated in modified sliding pressure mode where the turbine inlet pressure is controlled to a level that varies with the unit load. Lower pressures at part load enable savings in feed pump power to be realized and throttling losses in the turbine control valves to be minimized. For start-up purposes and low load operation, the boiler has a circulation system incorporating two 100% circulating pumps.

Advantages of Sliding Pressure Operation are • Lesser erosion & longer life of start-up valves• Shorter start-up times • Faster load ramping due to lesser metal stress

Below~85% boiler load, steam conditions become subcritical. The boiler is operated in pressure slide until~42% load. Boiler operation from 42-100% load is at sliding pressure with open control valves to the steam turbine without throttling losses. Below 193kg/s steam, the boiler is operated in circulation mode at 110bar.

In the combustion zone of the boiler, the membrane well is spiral wound, utilizing smooth-bore tubing. This inclined-tube arrangement reduces the number of parallel paths compared with a vertical-wall arrangement and therefore increases the mass flow of steam/water mixture through each tube. The high mass flow improves heat transfer between the tube metal and the fluid inside to maintain adequate cooling of the tube metal despite the powerful radiant heat flux from the furnace fireball. In the upper furnace area, the heat flux is much lower and the transition is made to vertical tubing, via a transition header. At full load, the boiler produces 550kg/s of steam, with a boiler outlet pressure of 260bar. Table 2 shows the main boiler operating parameters.

The boiler is equipped with three super-heaters with inter-stage spray-type attemperators and two Re-heater banks (although the cycle is a single reheat one). The economizer is a horizontal, multi-loop bank with extended surface tubes.

The primary super-heater is arranged as one horizontal and one vertical bank. The secondary platen is a single-loop pendant bank and the final super-heater is also a single-loop pendant bank. At the boiler outlet, the live steam temperature is 540O C.

Boiler operating parameters

Nominal boiler rating (Mwe) Coal 630 Natural gas 650

Boiler operating conditions Main steam output (kg/s) 550

Superheater outlet pressure (Mpa) 26.0 Superheater outlet temperature (oC) 540 Reheater outlet temperature (oC) 568 Feed water temperature (oC) 291.4 Coal data Design Range *NCV (MJ/kg) 26.97 24-30

Ash (%wt) 12.09 6-16

Moisture (%wt) 7.6 6-15 Sulphur (%wt) 0.48 0.3-15

*NCV = net calorific value

The boiler re-heater system is arranged in two stages: primary and final. The primary stage comprises two horizontal banks and the final reheat stage is a folded-loop pendant bank located in the vestibule of the boiler. At the boiler outlet, the reheat steam temperature is 568OC.

Although the super-heater and re-heater stage is similar to that of a two-pass subcritical boiler design, the increase in pressure and temperature requires either thicker sections or higher-grade components. Generally, the latter solution is chosen in order to minimize fatigue damage and reduce weight. Extensive use was made of 12% chrome tubing in the high-temperature super-heater and re-heater. Modified 9% chrome pipe-work was used to connect the boiler to the turbine where necessary.

The boiler soot-blowing system comprises 107 blowers activated by a programmable logic control (PLC) system incorporating user-programmable software. Bottom-ash removal is by a scraper chain conveyor beneath the furnace and a hydraulic transport system to a bottom ash filtration reservoir.

The boiler flue gas exit temperature is~350OC. The flue gas is cooled down to 130OC in the rotating air pre-heaters.

Turbine Generator Set

There are several turbine designs available for use in supercritical power plants. These designs need not fundamentally differ from designs used in subcritical power plants. However, due to the fact that the steam pressure and temperature are more elevated in supercritical plants, the wall-thickness and the materials selected for the high-pressure turbine section need reconsideration. Furthermore, the design of the turbine generator set must allow flexibility in operation. While subcritical power plants using drum-type boilers are limited in their load change rate due to the boiler drum (a component requiring a very high wall thickness), supercritical power plants using once-through boilers can achieve quick load changes when the turbine is of suitable design.

From the boiler outlet, steam is delivered to the high–pressure (HP) turbine section of the plant via two live steam lines.

The 680MWe steam turbine by ABB consists of a single–flow HP section, a dual-flow intermediate-pressure (IP) section three dual flow low-pressure (LP) section and the generator. Steam is supplied to the HP section via four control valves and two emergency stop valves. The HP section itself is designed with a double shell casing and one extraction point for feed-water preheating.

The steam supply to the IP section is via two combined control and emergency stop values. The three dual-flow LP sections are also designed with double shell casing. The shafts of all the turbine sections are made by welding forged disks together, which results in a compact shaft design. The condenser of the main turbine consists of six modules, connected to the exhaust steam ducts of the three LP sections and supported on the building foundations by springs. Each condenser module has an intake and outlet water box, which means that, for both cooling water intake and outlet, there are six pipes in all, each of which can be shut off individually. Each condenser is operated at a pressure of- 35mbar.

The generator consists of stator and rotor. The stator housing is a welded construction in which the stator segments are suspended and secured. The rotor is a single-piece forging with slots milled during manufacture to accommodate the rotor winding. The rotor winding and stator core are cooled with hydrogen.

The auxiliary electrical power system has a high degree of redundancy. During normal operation, this is supplied from the generator via two station transformers. During start-up and shutdown, the auxiliary system is supplied from the local grid via a 150/50/10kV transformer. The transition between the two is carried out by two high-speed-switching devices which are also used in the event of power supply failure to switch to ‘start-up’ mode so that a controlled shutdown can be achieved without risk of damage. During plant maintenance, the 10kV plant can be connected to the local 10kV power supply. To secure safe and reliable start-up of the plant in the event of complete loss of power, the emergency supply system consists of two redundant emergency power generators.

High-Pressure Turbine (HPT)

In this section, the steam is expanded from the live steam pressure to the pressure of the reheat system, which is usually in the order of 4 to 6 MPa. In order to cater for the higher steam parameters in supercritical cycles, materials with elevated chromium content, which yield higher material strength, are selected. The wall thickness of the HP turbine section should be as low as possible and should avoid massive material accumulation (e.g. of oxides) in order to increase the thermal flexibility and fast load changes.

Intermediate-Pressure Turbine (IPT)

The steam flow is further expanded in the IP turbine section. In supercritical cycles, there is a trend to increase the temperature of the reheat steam that enters the IP turbine section in order to raise the cycle efficiency. As long as the reheat temperature is kept at a moderate level (approximately 560°C), there is no significant difference between the IP turbine section of a supercritical plant and that of a subcritical plant.

Low-Pressure Turbine (LPT)

In the LP turbine section the steam is expanded down to the condenser pressure. The LP turbine sections in supercritical plants are not different from those in subcritical plants.

Other Cycle Components

A comparison of the water-steam cycle equipment in subcritical and supercritical coal fired power plants shows that the differences are limited to a relatively small number of components i.e. to the feed water pumps and the equipment in the high pressure feed water train i.e. downstream of the feed water pumps. These components represent less than 6% of the total value of a coal-fired power plant.

High Efficiency and More Reliability

Operational Issues

More than 400 supercritical power plants are operating in the US, in Europe, Russia and in Japan. Availability of supercritical plants is equal or even higher than those of comparable subcritical plants.

There are no operational limitations due to once-through boilers compared to drum type boilers. In fact, once-through boilers are better suited to frequent load variations than drum type boilers, since the drum is a component with a high wall thickness, requiring controlled heating. This limits the load change rate to 3% per minute, while once-through boilers can step-up the load by 5% per minute. This makes once-through boilers more suitable for fast startup as well as for transient conditions.

A total of 75 operators and five shift-leaders are employed to operate the three power plants. A typical plant can be operated with a minimum of five people per shift. A two-shift team (10 field operators and one shift leader) handles the logistics on weekdays.

Main Operational Features

The operational flexibility of supercritical power plant is regarded as being a major benefit. There is no loss of flexibility in moving from subcritical to supercritical conditions and, in some respects, the once-through boiler design is more flexible than drum boiler designs. This is because, to control metal temperature differentials in thick-section components such as the drum, temperature control at startup and during ramping is more critical.

PLANT PERFORMANCE

Since it first came into full operation, the commercial and environmental performance of the supercritical plant has been excellent and has either met or, more often, exceeded expectations. Table 3 summarizes some of the key performance indicators for a typical 680 MW plant.

PARAMETER PERFORMANCE

Target Actual Cycle efficiency LHV (%) 42 42 Availability (%) 85 92 Unburned carbon (%) 5 3.5

Emissions

Particulates (mg/Nm3) 20 1.5 SO2 (mg/Nm3 ) 400 160 SO2 removal (%) 88 91 NOx (mg/ Nm3) 300 270

Fuel Flexibility is not Compromised in Once-Through Boilers

All the various types of firing systems (front, opposed, tangential, corner, four wall, arch firing with slag tap or dry ash removal, fluidized bed) used to fire a wide variety of fuels have already been implemented for once-through boilers. All types of coal as well as oil and gas have been used. The pressure in the feed water system does not have any influence on the slagging behavior as long as steam temperatures are kept at a similar level to that of conventional drum type boilers.

Life Cycle Costs of Supercritical Coal Fired Power Plants

Current designs of supercritical plants have installation costs that are only 2% higher than those of subcritical plants. Fuel costs are considerably lower due to the increased efficiency and operating costs are at the same level as subcritical plants. Specific installation cost i.e. the cost per megawatt (MW) decreases with increased plant size.

NOx Control

A typical 680 MW supercritical boiler has 36 low-NOx burners, located in three rows of six burners in each of the boiler front and rear walls in an opposed arrangement. To maximise NOx reduction, the combustion is two-stage with 24 after-air ports positioned in two rows of six on the front and rear walls of the boiler, situated directly above the burners. This type of burner system design, together with optimization of furnace dimensions, achieves very low NOx concentrations in the flue gas. The performance specification for NOx emissions is 300mg/Nm3. Actual yearly average emissions of NOx from the plant are 260-280mg/Nm3.

Particulates Control

Fly ash is separated from the flue gas in tow ESPs. Particulate collection efficiency is 99.9% with the discharge from the ESPs being conveyed pneumatically to silos.

SO2 Control

The FGD Plant is a wet limestone system. Flue gas from the ESP plant passes upwards through the FGD absorber, where the entire cross-section is sprayed with limestone suspension in four vertical stages. This removes at least 88% of the SO2, together with some remaining fly ash, chlorides and fluorides. During the process, the flue gas is cooled to 50OC. To prevent the temperature dropping below dew point and to eliminate the risk of any resulting corrosion, the cleaned flue gas is heated by 10oC before entering the stack.

FGD plant with absorber and flue gas re-heater

The SO2 removed from the flue gas reacts with the limestone to form a gypsum suspension. This suspension is collected in the FGD absorber and is returned to the spraying stages by recycle pumps.

The gypsum suspension can also be diverted to a separate tank when inspection of the FGD absorber is required. The concentration of the suspension is controlled by adding fresh limestone and extracting some of the gypsum as a suspension. This suspension is then subjected to further treatment as described in a later section of this brochure discussing management and utilization of plant residues.

Plant Monitoring and ControlProcess control cubicles and operating panels have been sited at selected locations in the plant, e. g in the plant logistics building, the FGD plant and the coal-and ash–handing silos, the ensure close proximity to the process to be controlled. In both the FGD plant and the logistics building, there is a separate control room provided with a process control console linked to the main system using fibre optics. The FGD plant control room was used during commissioning.

These systems give operating staff targeted access to all the important process data required. An alarm hierarchy is used where the plant management system display messages according to their level of priority and in the correct time sequence to enable rapid assessment of any process malfunctions.

Plant Maintenance and Monitoring

The plant was designed for a scheduled shutdown for inspection and maintenance purposes, once every two years. The mean time between failures for each of the components matches this interval. Currently, considerable effort is being made to increase this interval to three years.

Service personnel are assisted by a plant diagnostics system that includes automatic analysis and reporting of the entire instrumentation and control system. This ensures rapid fault detection and leads to reduced repair time. Since 1998, the plant has achieved a high availability, reaching a maximum availability of 95.9% in that year.

Management and Utilization of Residues

The benefits of maximizing the utilization of power station residues are well recognized and considerable care is taken to optimize boiler combustion conditions to produce high quality fly ash and bottom ash.

The fly ash from the ESPs (~120,000t/y) is conveyed pneumatically to silos where it is loaded into lorry or ships. Both systems are equipped with facilities for both wet and dry ash handing. As an alternative, the fly ash can be loaded into storage silos, equipped with similar handling facilities. Online measurement of unburned carbon (UBC) and daily sampling are used to control fly ash quality. The main market is the concrete industry as cement replacement.

Bottom ash (17,000t/y), removed from the base of the boiler, is transported by a hydraulic transport system to a filtration reservoir, consisting of three basins where it is dried out on a filter bed. The filter bed is cleaned with rinsing water and compressed air. When this treatment is complete, the ash is either loaded into lorry or into storage. The bottom ash carries a quality mark with a product certificate, ‘E bottom ash’, which guarantees that it can be used in environmentally friendly and economic applications, whether integrated in road foundations or in civil engineering works.

All the bottom ash is sold and this is used mostly in road construction. The rinsing water is recycled in the bottom-ash system and excess water, due to a continuous fresh supply, is re-used as supply water for the FGD plant.

Considerable effort is also made to maximize the utilization of FGD residues. Reacted limestone slurry from the FGD plant is dewatered in hydro-cyclones and centrifuges to produce a gypsum powder of <5% residual humidity and >95% purity. The plant produces ~ 60,000t/y of high-grade gypsum, all of which is sold to the building construction industry for the manufacture of gypsum blocks and boards. The high quality of the gypsum produced is achieved by careful pH control and continuous extraction of wastewater to reduce contamination and control the levels of chloride in the suspension. The water from the limestone dewatering process is re-circulated back to the FGD system. A multi -stage wastewater treatment system is also used to remove dissolved heavy metals and floating particles.

Measures have also been taken to reduce pollution by storing coal on concrete impermeable to water and by collecting and purifying seepage water before recycling.

Case Study-Typical C&I Architecture (6 X 1,036 MW)

Ultra-supercritical plants use new advanced clean coal technology that allows operation at elevated steam temperatures and pressures. Ultra-supercritical technologies are becoming more prevalent because they can boost the efficiency of coal-based electricity generation by more than 50 percent, while maintaining superior environmental performance.

The digital automation solution consists of digital plant architecture and predictive maintenance software, as well as intelligent field devices.

The system will monitor and control the boiler, sequence control system, electric control system, modulating control system, furnace safeguard supervisory system, flue gas desulphurization (FGD) system and balance-of-plant processes. The system will also provide feed-water pump electro-hydraulic control and interface to the turbine controls as well as to PLCs controlling soot blowing, dust removing, ash and slag handling, and plasma ignition.

The integrated solution will unify boiler and turbine operations, which translates into a number of significant operational benefits. Fully coordinated boiler and turbine control not only enhances unit-wide compatibility, but also contributes to improved unit stability, responsiveness and thermal efficiencies; tighter overall control of plant operations; and a more streamlined view of key plant and turbine parameters.

The contract for 2 units calls for supply a total of 64 redundant controllers (32 per unit), 10 operator stations (five per unit) and four engineering stations (two per unit). In all, the system will manage 28,044 hard I/O points (14,022 points per unit) and will incorporate 12 Foundation™ fieldbus segments (six per unit) and 16 PROFIBUS DP segments (eight per unit), to network 174 Foundation fieldbus devices ( 87 per unit)  and 154 PROFIBUS DP devices (77 per unit). Use of predictive maintenance software will initially streamline configuration of these intelligent devices, translating into cost savings and increased unit startup efficiency. On an ongoing basis, the technology will further increase the availability and performance of the two units by providing online access to instrument and valve process information, predictive diagnostic information, and automatic documentation of field device maintenance information – all of which contribute to ongoing efficiency of plant operations and maintenance activities.

Startup System

When configuring control systems for the startup system of a once through boiler, it is important to know whether the startup separator/flash tank is allowed to reach supercritical pressures. The answer to this question will determine whether the separator will be integral to the boiler, or bypassed by the use of special valving schemes. The control scheme will depend on the type of configuration used.

For startup systems that use separator vessels that do not obtain once-through pressures, a valve scheme is used to bring the boiler to once-through operation (supercritical pressures). The initial fluid circulation (pre-firing) through the boiler is from the feed pump discharge header through a feed water control valve, through the boiler water walls to the water wall outlet header. From there, the circulation continues through a water wall pressure control valve to a separator vessel, and then through control valves to the condensate systems. This completes the cycle.

Figure above depicts the circulation scheme in pre-firing mode. This mode is also called cold water cleanup mode, and it is used to adjust the water chemistry to predetermined values prior to firing the boiler. This mode is used until the water cation conductivity is less than one micro mho at the inlet of the economizer.

The flash tank/separator serves as a moisture separator during startup to keep the water that will be carried through to the turbine – much like steam drum in a conventional sub-critical boiler.

In the cold water cleanup mode, the water wall pressure is being held to a set point determined by a program based on the water wall temperature. This program typically moves the water wall pressure form a nominal minimum pressure to the supercritical operator pressure. A water wall pressure control valve is controlling the feedwater flow. The flow set point is dependent on the boiler design, and is determined by the minimum flow the boiler needs for safe circulation.

With CE once-through boilers, the minimum flow requirements are separated from the water wall protection by the use of an integral recirculation system. The recirculation system allows for lower minimum flow of approximately 10 percent of full boiler load, which not only minimizes heat rejection during startup, but allows the transfer from the bypass system to once-through operation to take place without a sudden drop in steam temperature.

The feedwater pumps will be controlled to hold a feedwater discharge header pressure. This set point is determined by adding about 200 psi to the current water wall pressure set point. As the water wall pressure is programmed, the feedwater pump header pressure will also increase, In CE units, the feedwater bypass valve is used during startup and low loads at a maximum rating of about 20 percent of the boiler load. After that, the feedwater bypass valve is held open and the feedwater flow is controlled by the speed of the boiler feedpump.

The feedwater bypass valve is positioned by a characterized signal, which is generated by the feedwater demand. The feedwater demand is also the set point for the feedwater flow. The output of the feedwater flow controller trims the boiler feed pump speed demand, as well as the feedwater bypass valve demand to regulate feedwater flow. Recirculation control is provided for both the startup boiler feed pump and the main feed pumps.

The level and pressure are controlled in the separator vessel by two independent valves. The discharge valve at the low point on the vessel controls the level and a

valve at the upper section of the vessel controls the pressure. Both valves discharge to the condenser.

As heat input into the boiler increases, the valve transfers take place and the steam is routed from the separator to the turbine, and, finally, all the steam bypasses the separator completely.

The control system will control all aspects of the separator control as well as the valve transfers.

The valve transfers basically reroute the steam path from the separator to a bypass valve. As the bypass takes more

steam flow a non-return valve isolates the separator outlet. The separator inlet valve, which was controlling water wall pressure, is programmed to close as the bypass opens. Once the separator is isolated, a programmed ramp coordinates the firing rate and the boiler outlet pressure control to eventually bring the boiler to wide open bypass valves and the system to super critical operating pressure controlled by the turbine (or bypass system).

On start up systems that maintain the separator vessel at once through pressures, in-line cyclone separators and a separator vessel are used as a collection point for the water that exits the cyclone separators, as well as a drum for the boiler at subcritical pressures. The control system maintains the vessel level by controlling a valve that discharges to the condensate system. The system pressure is maintained outside of the boiler by the turbine and/or a steam bypass system. In this case, the control system will control all aspects of the separator control, as well as the control of the system pressure via turbine valves or a steam bypass system. These start up systems do not have the complexity of the valve transfer schemes, but do carry the overhead of having a pressure vessel at super critical pressures.

Once fire is put in the boiler, the fuel input is programmed to raise water wall temperature at a given rate.

This firing rate raises the temperature and enthalpy of the system and will govern all the control actions ending with the turbine at operating super critical pressure and minimum once through load. The method of bringing the boiler to once-through mode at supercritical pressures is different depending on which start up system is used.

After a fire is put in the boiler, the fuel input is also programmed to raise water wall temperature at a given rate. As water wall temperature rises, the system pressure set point raises the system pressure using the steam bypass or turbine valves as well as raising the set point for the feed water header pressure. As the system pressure and system enthalpy increase with the firing rate, the cyclone separators extract water to the separator vessel and the remaining steam is passed through the boiler super heaters to the turbine.

The vessel level control valve controls the vessel level. The control system, using the separator vessel level as an index, will balance the firing rate and the system pressure to ensure that the separator vessel stays at saturation conditions up to supercritical pressure. Once the system is above super critical pressure, the separator level control valve is closed and the boiler is brought up to the final operating pressure.

Functional Description of Auto Control loops

Why the Control is Critical?

• No energy reserve as in drum

• Turbine steam demand to be met in real-time

• Feed flow & Firing rate are Critical Parameters

• Control Oscillation to be avoided

• Integrated control requirement (FGD, ESP, SCR etc)

• Scope for advanced control, fuzzy logic & modeling

General Requirements

The open- and closed loop controls shall interact closely between themselves to guide the plant operation towards optimal functioning. In general, frequent operator’s intervention shall be avoided and the control intelligence built into the system shall be adequate to perform routine functions. However, each Control Loop shall have an auto / manual selector station and setter to allow operator’s intervention during abnormal plant conditions.

When set in AGC (Automatic Generation Control) mode, Coordinated Master Control shall receive and react to the signal from Owner’s load dispatch center. The signal of unit status shall be answered back. Plant demand load set point or “Target Megawatts” shall be set and adjusted in “remote” automatic mode from load dispatch center according to grid control demand with frequency variation control signal as feed forward or in manual mode by the plant operator (during start up or emergencies) by the unit load setter at unit control room. The details of interface shall be decided during detailed engineering stage between Owner and Contractor.

The “Target Megawatts” command received from Owner’s LDC shall be checked for quality (the received signal may be of the range -15 mA -0- + 15 mA) and excursion beyond permissible limits. The signal shall be filtered to eliminate superimposed noise and scaled to match the signal reference range of DCS in F(x) block. Whether this signal will be allowed to pass through will depend on whether the received signal is of acceptable quality and whether the Operator decides to leave the plant control to AGC.

The transfer card will also have provision for imposing directional blocks (block increase or block decrease) dictated by control system so that when the plant is not ready to accept any further increase or decrease commands from AGC due to equipment limitation, the same will be blocked.

Out of the two cases, in case of ‘block increase’ situation, signifying that some major equipment has been driven to the extreme, a further transfer at downstream will cause the target load set point to change over to a computed value based on the factors causing directional block, to bring the load down, if necessary, to permissible limit.

The target load shall be monitored at this level as ‘LDC final target’ and also at ‘as received from LDC’ level.

The next transfer occurs down the line to a computed set value in case any of ‘run back’ or ‘run up’ or run down’ is active, causing the ‘LDC final target’ to be overridden under emergency situations. The resulting signal is low auctioned with the ‘maximum load limit’ and high auctioned with ‘minimum load limit’ set by plant operator.

Two ‘feed forward’ signals are superimposed on the target set point to accelerate its responsiveness. First is a negative step signal causing lowering of the target set so long as the run down condition is ‘active’. Second is a positive step signal causing raising of the target set so long as the run up condition is ‘active’. These will cause rapid debottlenecking of the constraints leading to the run down or run up.

To avoid ‘bumps’ in the control response due to sudden transfers as stated above, the ‘target set point’ has to pass through a ‘rate of change limiter’ to restrict the ‘ramp’ within acceptable limits. Under normal circumstances, the load variation rate is preset by the operator at a fixed value, which is low auctioned with the rate set by turbine stress evaluator.

Under run up or run down situations the aforesaid rate is overridden by a faster rate. However, in case no run up or run down condition is present but run back situation has occurred, the rate set is overridden by an even faster rate. This resulting signal is the “AGC current target”.

Frequency error/ turbine speed error is superimposed on the set point at this stage as feed forward for responsiveness.

Start-up pattern i.e whether the plant condition is cold, warm, hot or very hot or the shut-down pattern i.e whether it is turbine cooling shut-down or normal shut-down shall be selectable under guidance from physical parameters like turbine metal temperature.

Fuel flow control, air flow control, feed water flow control, EH governor control, etc. shall be properly tuned and controlled to meet constant or ramp load variation. The equipment shall be capable of coordinating the action of the controls in the boiler / turbine / generator unit so as to produce safe and stable operation automatically and maintain generator output, steam temperature, steam pressure, excess air (oxygen) at their desired set values. The control shall produce stable combustion, low values of unburned carbon in fly ash, and no black smoke under the steady load and load-variation.

Automatic control and adjustment of load shall be carried out in between load range 35% and 100% rated load in Automatic Plant Control mode.

Automatic runback operation in coordination with coal mill & burner control system and various others control systems shall be performed in the event of failure of major auxiliary equipments and others which require sudden reduction in output.

Starting up and preferential shutting down of coal mills under varying load conditions shall be under automatic sequence control based on set priorities and shall not require any operator assistance other than notifying the operator about the actions being initiated. Complete automatic control shall be possible with automatic plant control system in coordination with mill-burner control system.

The necessary locking devices at the air failure and power failure shall be provided for all regulating duty pneumatic control to maintain plant load under failure conditions with notification to plant operator.

Automatic operation at any mode of the plant including the unit starting up and shutdown, the unit runback, the load rejection and so on shall be achieved by means of the automatic switching of the control mode (auto / manual auto-tracking mode at each control loop, the boiler follow mode, the turbine follow mode, the unit coordinated mode, etc.), the automatic changing

of the various set points, the various function generators and so on. Transfer between one mode to another mode shall be bumpless without disturbing the process.

Control stations on operator’s station shall be grouped logically in functional blocks for compactness and ease of operation.

Protective interlocking circuits shall be provided for safety against erroneous manipulations.

Protective circuits against control system internal faults such as modules and operating ends shall be furnished.

The basic function of the Automatic Plant Control shall be, but not limited to the followings:

Bidder shall furnish the scheme of control loops & write up on his system for approval of Owner.

Unit Master or Coordinated Mode

Plant demand load set point or “Target Megawatts” signal shall manage the load and throttle pressure by sending parallel demand signals to the boiler master and turbine-generator master controllers. Demand signal shall be modified for frequency error and shall be limited by auction when the unit capability is reduced for any reason such as the loss of an auxiliary like one draft fan, a boiler feed pump, and so on. Load control station shall

have maximum and minimum adjustable load limits set administratively as well as limit of load changing rate guided by thermal stress limits of major equipment.

During normal operation, coordinated control shall be exercised aggregating boiler and turbine inputs by target load and load change rate commands (central load dispatching commands, or manual setting), with various corrections made to enable Boiler control and Turbine control.

Directional blocking of the unit demand (increase/decrease of load) will be provided based on the extreme operating status of equipment and applicable process conditions.

The run up and run down actions shall be provided for reducing the deviations when the respective final control elements are in the extreme positions and are unable to correct the error. Run up and run down actions shall override the unit demand signal till the adverse conditions are cleared.

The system shall provide automatic run-back facility based on the load demand signal on loss of critical auxiliary equipment. The limits and rate of run back shall be pre-determined according to the individual capacity of each auxiliary equipment and shall be supervised by Turbine Stress Evaluator. The control system shall have capability for implementation of the functional requirement with true characteristics of equipment.

In case of full load rejection, the turbine-generator shall remain in service, supplying the station service power (house load operation). The boiler steaming capacity shall be quickly reduced to correspond to the capacity of HP and LP bypass systems plus the house load and operation is to be carried on at sliding pressure mode.

The unit load demand shall also be corrected by deviation in system frequency. This correction provides a change in unit load demand equivalent to the expected change in megawatt output due to any deviation in system frequency.

The boiler master controller demand shall be used as a feed forward signal to the feedwater master controlling the feedwater flow and the firing rate master controlling the fuel and air flow to adjust to unit energy demand.

Feed forward signals will be calibrated initially to produce a specific relationship between turbine steam flow and boiler firing rate on one hand and unit output on the other hand. However the relationship may change due to changes in system parameters such as cycle efficiency, heating value of coal, feed water temperature etc. When such a change occurs, it will be reflected in a steady state error in megawatt output. A controller shall be provided to automatically recalibrate the feed forward signals by reducing the steady state error to zero.

In addition to providing operator with the ability to set and observe unit load, the Unit Coordinated Control master shall allow the operator to select either constant or variable (sliding) pressure operation. The sliding pressure mode shall be adopted during start-up and reduced load operations principally to avoid erosion of throttling valves. Sliding pressure operation shall allow the turbine valves to be maintained at optimum position as the unit shall be ramped to load. Sliding pressure operation shall be permitted with Unit Coordinated Control master in auto mode.

When Unit Coordinated Control master shall be in Boiler Follow Mode-2 or Turbine Follow Mode-2, described below, Unit Coordinated Control mode shall be selected. Two sub-modes shall be permitted as follows:

In Coordinated Boiler Follow Mode boiler master and turbine master shall be in auto mode. Boiler master shall control the boiler demand to control throttle pressure. The turbine master shall modulate the EH governor using UCC demand as feed forward trimmed by turbine MW controller. The UCC demand shall track the MW to eliminate MW error.

In Coordinated Turbine Follow Mode boiler master and turbine master shall be in auto mode. The turbine control shall use feed forward based on UCC demand trimmed by turbine throttle pressure controller. The turbine master shall modulate the EH governor to control throttle pressure. Boiler master shall control the fuel firing rate based on feed forward from UCC demand trimmed with the boiler MW controller. The UCC demand shall track the MW to eliminate MW error.

Boiler Follow ModeIn the boiler follow mode, boiler throttle pressure master controller trims the megawatt load setting to maintain the throttle pressure at set value. When, for example, the throttle pressure is below the set point, the fuel, feedwater and air are increased by ramping up the boiler master

demand and vice versa. Two variants of Boiler Follow Mode are foreseen.

In Boiler Follow Mode-1 the boiler master shall be on automatic mode and turbine master shall be left on manual mode. The boiler master controls the throttle pressure and the turbine governor control is adjusted by the operator. The UCC (Unit Coordinated Control) demand tracks the governing valve position in a characterized algorithm linking it to MW.

In Boiler Follow Mode-2 the UCC demand shall be extended to both boiler master and turbine master, both and the UCC in automatic mode. Target load shall be set at UCC. Boiler master shall control the throttle pressure based on UCC signal with throttle pressure controller trim. Turbine master shall only receive the UCC signal without MW trim.

If runback occurs in this mode, the system shall automatically transfer to turbine following mode when turbine governor is on automatic.

Turbine Follow Mode

Turbine master shall be in charge of throttling the EH Governor valves. In the turbine follow mode the UCC demand shall be trimmed by turbine throttle pressure to create turbine master demand. Two variants of Turbine Follow Mode are foreseen.

In Turbine Follow Mode-1 the turbine master shall be on automatic mode and boiler master shall be left on manual mode. The turbine master controls the throttle pressure and the operator shall control the load manually by changing the Boiler master demand. The UCC shall track the Boiler master for smooth transfer of Boiler master to auto.

In Turbine Follow Mode-2, the UCC demand shall be extended to both boiler master and turbine master, both and the UCC in automatic mode. Target load is set by UCC. Turbine master shall control the throttle pressure based on UCC signal with turbine throttle pressure controller trim.

In the turbine following mode the megawatt control shall be the responsibility of the boiler and throttle pressure shall be controlled by the turbine control system. In this mode the unit demand shall be subject to maximum and minimum limits, rate of change, interlocks and run backs etc.

When turbine following mode is in automatic, all runbacks, run-ups limits and rate of change shall be automatic.

Manual Mode & Base Mode

Manual mode shall be the lowest level mode in the hierarchy. In this mode the Boiler Master Control including the air, fuel and feedwater loops and Turbine Master Control are switched over to manual mode and the unit will be controlled manually. Generation error and Frequency error will not affect the demand signal. As a variant, in base mode, the Boiler Master and Turbine Master Control shall be in manual mode. However, one sub-loop either air, fuel or feedwater as well as the firing rate ratio will be on automatic mode. This shall help internal tracking of the UCC.

Boiler Master Control

Variation in unit load (MW) at any operating point of the boiler is signified by proportional enhancement/reduction of steam flow at boiler outlet, as the steam demand of the turbine varies to match the load. At a stable operating point of the boiler, any increase in load will reflect as more steam flow with consequent reduction in steam pressure and temperature, transiently and vice-versa. It is the role of Boiler Master to maintain outlet steam temperature and pressure stable under all load conditions while catering to the varying demand of steam flow. Steam pressure shall be regulated by regulating the feedwater pressure while matching the steam flow (and therefore feed water flow) requirement. The enhanced/reduced steam flow consequently calls for proportional enhancement/reduction of heat transfer, if the quality of the steam is to be maintained. Therefore, the superheat temperature shall be regulated by controlling the firing in the boiler. It is therefore essential that proportionality is maintained between feedwater flow and fuel flow. So long as proportionality is maintained between the two, the attemperation requirement remains fixed, in the long term. However, considering the high inertia of the thermal system, the superheater temperature control shall be performed by attemperation water flow control in the short term. Feed water to firing rate ratio, by means of a lead-lag control shall be maintained constant to maintain the rated attemperation flow.

The usual fuel/air lead/lag with oxygen trim control shall ensure that the furnace does not starve of air under varying load condition and shall ensure complete combustion of fuel.

Cross-limiting of between the feedwater flow and the firing rate shall ensure that the ratio between the two remain within permissible limits. While transient conditions persist at changing load, the boiler master signal shall be transiently modified in order to achieve over or under firing. Such the transient signal modification shall be applied for the fuel flow control, the air flow control, the steam temperature control and other necessary control loops in order to maintain the various parameters safe and stable during any mode of the operation.

Boiler master shall develop the demand signals for feedwater flow and firing rate (fuel flow) to the boiler. The demand for firing rate (fuel flow) shall be modified by feed flow to firing rate ratio function.

The boiler master control station shall be designed to allow manual control of the boiler input demand.

FEED WATER DEMAND

Turbine Master Control

The MW demand signal from unit master shall compare to the actual MW signal and the deviation signal shall be transmitted to EHG Load controller. This controller produces the governor control valve position demand signal.

During the unit initial start-up the manual mode (the auto-tracking mode) shall be applied followed by sliding pressure mode until the turbine valve transfer is completed during which the turbine EHG speed controller shall control the turbine speed, the initial block loading and the valve transfer. And then the turbine load control shall be handed over to the unit master control and the turbine master shall automatically set on auto mode.

Beyond the sliding pressure regime, the main steam pressure is maintained constant and the machine load shall be controlled by throttling the turbine governor value.

Under fixed pressure operation, the turbine governor control valve controls MW but when the main steam pressure controller, overseeing the control finds pressure error larger than the set limit, control mode of this valve shall be transferred to the main steam pressure control to unload the machine as necessary for pressure recovery. The main steam pressure control shall also be used when the boiler master is on manual mode.

Turbine master control signal shall be transmitted to the digital electro-hydraulic (EH) governor system.

Fuel Flow Control

The fuel flow control shall regulate the supply of coal and oil (if load carrying gun is employed) to the furnace to maintain optimum efficiency at varying load conditions. During combustion of coal, some modulating influence shall be introduced to take account of responses of mills and boilers, clogging of coal, and variations in coal properties.

The feed water side of the boiler master cross-limiting circuit shall use two selectors to compare the feedwater demand (Boiler Master) to total fuel flow to the boiler. If the fuel flow increases, the ratio control shall increase the feed flow accordingly and vice-versa.

Similarly, the firing rate side of the boiler master shall use two cross-limiting selectors’ circuits to compare the fuel flow demand (Boiler Master) to total feed-water flow. If the feed flow increases, the ratio control shall increase the fuel flow demand accordingly and vice-versa

Since the ratio function is incorporated only in the firing rate side of the cross limiter, correction shall be made in the selectors to account for the ratio to keep the selectors in balance. A dead-band shall be introduced in the cross limiters to allow limited excursions during rapid load changes. The cross limiters shall be limited, in turn by absolute limits to circumvent runaway condition of feed-water pumps.

A mill master, heavy oil control and light oil control stations shall permit manual operation of the pulverized coal flow and fuel oil flow respectively.

For coal burning, the summation of total coal flow shall be compared with the fuel flow demand signal, the error signal modulates the output of the coal feeders. The feeder speed reset signal shall be derived from the differential pressure across the mill.

Means of correcting control disturbance due to changes in the calorific value of the fuel shall be provided.

The process of changing of operation from firing light fuel oil to firing heavy fuel oil and from heavy fuel oil to exclusive firing of coal at the time of loading up the boiler and the reverse from exclusive firing of coal to heavy fuel oil at the time of unloading the boiler preparatory to shutting down, i.e. switching of fuels, shall be carried out automatically. However, the mill system start-up / shutdown group sequence control shall be manually initiated.

The fuel mixing ratio set point station shall be used to obtain the desired proportion of the fuels used i.e. oil / coal during mixed firing operation of the boiler based on quantities and calorific values.

Comparison of the signal with total air flow and total fuel flow shall be continuously carried out to prevent an unsafe (air deficient) condition from arising at any time.

BTU COMPENSATION

Air Flow Control

In order to achieve safe and efficient combustion the correct fuel air ratio shall be maintained at all times and an air rich mixture shall always be present when increasing and decreasing load. Oxygen and BTU corrections shall be included in the air side to ensure proper combustion, minimize heat losses and reduce carbon oxide presence in flue gas stream.

Secondary air flow shall be measured on both L.H.S and R.H.S in 2-O-O-3 mode and shall be compensated for temperature (2-O-O-3) and pressure (1-O-O-2) on either side. The flows will be added (depending on the running status of each fan) to form total secondary air flow signal. Air flow signals for each side shall be maintained equal by balancing in the air flow control loop.

Total primary air flow computed in a similar fashion shall be added to secondary air flow to compute total air flow. Total air flow shall be monitored by three limit value detectors for <25% flow in a 2-O-O-3 configuration for tripping the furnace.

The firing rate signal from the fuel master shall be high selected with fuel flow on the airflow demand side and low selected with air flow on the fuel demand side.

The lead-lag selector mentioned above shall maintain the proper relationship between fuel and air flow by correcting the firing rate signal on the air side only.

Excess Oxygen in the flue gas shall be measured at economizer outlet. This analysis shall be used to form part of the automatic air fuel ratio control system. The measured values shall be validated in a two-out-of-three algorithm before being applied to the loop. The measures Oxygen shall be compared with a load dependent set point in a PID controller. The auto/manual station shall permit the operator to manually set the desired bias and corrections.

After the lead/lag auctioning, the air demand shall be trimmed for excess air and BTU. BTU correction shall be performed by calculating the difference between input energy (total fuel in) and energy output (total steam flow). This adjustment shall have a long time constant to ignore mismatches during transients.

The corrected air demand shall (i) be compared with temperature and pressure compensated airflow and the deviation shall be used to reposition the forced draught fan pitch controls to satisfy the airflow requirements, (ii) correct the fuel flow demand by adding correction factor to actual fuel flow calculation and (iii) shall incorporate a minimum airflow limit, set normally at 25% to ensure safe boiler operation at low loads.

The actual total air flow being the sum of primary air and the secondary air, at two different temperatures, mass flow shall be computed by compensating for density by measuring the flowing temperature.

Directional blocking shall be applied to the air flow loop from the furnace pressure control. If furnace pressure is already too positive, there shall be a raise inhibit on air flow signifying that the load increase shall be blocked. Similarly, the reverse will occur when the furnace pressure is already too low.

Directional blocking shall be extended to UCC if air flow is too much or too less compared to the demand, FD vanes are driven to extreme. FD vane shall not be permitted to be set on auto mode in case the furnace draft control is on auto mode.

Synchronizing circuit between the two fans shall be provided for equal or unequal sharing (by biasing) with respect to vane position or motor current or air flow etc on each side.

Bidder may offer fine tuning facility of excess air based on carbon monoxide in flue gas.

Super-heater Steam Temperature Control

Superheater Steam Temperature Control shall be capable of dealing with sudden load changes and other disturbances with a minimum variation in steam temperature which will also mean a minimum variation in super-heater tube metal temperature and thus the stress.

The two important temperatures in the boiler are the water wall outlet and the boiler outlet (final) temperatures. If the feed water flow and firing rate stay in balance, these temperatures will stay stable. If either temperature moves too far from set point, there is a ratio control between the boiler master and the firing rate master which will change the firing rate only (feed water flow side stays the same) The typical scheme controls the final temperature and uses water wall temperature as an override only.

The final temperature can also be controlled using the standard cascaded control scheme with spray valves. Since there are two methods to control the final temperature in a once through, firing rate or sprays, the control determines the most efficient method.

The typical scheme is that when the spray valves are in manual, the feed water-firing rate (FW/FR) ratio is used to correct for final temperature control.

If the spray valves are in automatic, they are the primary control for the final temperature. Typically another controller is put in the feed-water/firing-rate ratio circuit that looks at spray valve position (or temperature difference across the spray point). The object is to keep the sprays in operation at low spray flow. If the sprays are too low, the firing rate will increase which causes the conventional final temperature control to open the sprays to hold final. If the sprays are to high, the opposite will occur.

The FW/FR ratio circuit also has an override from waterwall temperature that will take control away from the final to hold waterwall temperature. If waterwall temperature gets too low, the unit cannot sustain supercritical conditions.If the controls are linearized correctly, these units can move load quickly and still be stable.

The system shall include those features necessary for safe operating practice and shall provide stable control during transients conditions.

Such feature as anticipatory control based on state variables shall be applied to the loop in for anticipatory and immediate action when the boiler load is varied.

The superheat control loop shall also include a technique for quick restoration of temperature by ‘boosting’ the spray flow when load changes have occurred.

The final boiler steam temperature shall be controlled by two independent methods. First, since the boiler acts as a heat exchanger, the ratio between the heat input (firing rate) and heat takeaway (feed-water flow) shall affect the final temperature. Second, spray water introduced in the super-heater section also impacts the final steam temperature.

The overall temperature control scheme shall coordinates the two methods as follows :

01) The feed water / firing rate ratio stations shall control the long term final temperature which in turn shall control inputs to the ratio function between the boiler and firing rate masters.

02) The spray valves shall control the short term final temperature.

In this scenario the sprays shall always be available for transient (short term) temperature control.

Under the correct feed-water / firing rate ratio, the inter-stage final temperatures shall be controlled to set-points derived from the boiler load index. The final (boiler outlet) temperature shall be controlled to the boiler design temperature.

Boiler design temperatures shall be controlled using cascaded type control schemes. The upstream controller PID shall control the temperature leaving a superheater section (interstage or boiler outlet) by adjusting the setpoint of the downstream controller PID. The downstream controller shall be controlling the temperature immediately after the spray that is entering the super-heater section.

The feed-water flow to the firing rate ratio shall also be controlled by a cascaded control scheme.

The downstream controller shall control the waterwall temperature (separator temperature) and shall quickly impact the firing rate (and waterwall temperature) since it is adjusting the firing rate demand from the Boiler Master to the firing rate master.

The upstream controller shall directly control the spray flow to the superheat sections through the firing rate.

If the spray flow is found greater than set-point at a given load and with a final temperature at set-point, the upstream controller shall reduce the set-point for the downstream controller (water-wall temperature). The resulting reduction in firing rate in turn shall reduce the final temperature. The sprays shall adjust (reduce) to bring the final temperature back to set-point and in doing so, shall also bring the spray flow to set-point. This loop shall be slow acting and shall be meant to keep the sprays in play so that they can active during boiler load changes.

The spray flow set-point shall be derived from the boiler load index and calculated to be a percentage of the current boiler load.

When the spray control shall be set in manual, the feed-water to firing rate ratio shall be automatically transferred to directly control the final superheat temperature through firing rate adjustments.

Since the downstream PID controller in this scheme is actually controlling the water-wall temperature, protection can be added to this loop to keep the water-wall temperature within limits.

To improve the performance of the loop the temperature measuring wells shall be designed for fast response

Reheat Steam temperature control

Reheat Steam temperature control shall primarily be done by proportioning gas dampers through parallel damper biasing system.

Reheat attemperator water shall only function as an emergency measure to bring down hot reheat temperature. During normal operation there shall not be any reheat spray flow.

Load Runback Variables

In case of major plant internal disturbance the unit shall carry on operation at a reduced load level and the grid frequency control system shall be taken out of service.

The load shall be reduced by the automatic run-back system which reduces or holds the unit load according to the capacity of main auxiliary systems.

The failure of any of the following plant systems or plant variable are to be included in the run-back system:

a) I. D. Fans

b) F.D. Fans

c) P.A. Fans

d) Air preheaters

e) Boiler circulation water pumps

f) Boiler Feed Water Pumps

g) H.P. Feed Heaters

h) L.P. Feed Heaters

i) Condensate extraction pumps

j) Coal Mills

k) CW Pumps

l) Load Shedding

Islanded Operation

In the case of the load rejection due to the external disturbances, the unit shall carry on operation at the minimum boiler load operating the turbine bypass system.

The load shall be reduced to the minimum boiler load by the automatic run-back system. Items not limited to the following shall be taken into account to make sure the safe and stable operation :

a) The quick opening of the HP and LP Turbine Bypass System.

b) Fuel fast cut back maintaining stable flames at the residual burners.

c) Sufficient spray water to the HP and LP bypass system shall be available.

Furnace Draft Control

Furnace pressure control shall generally adjust the regulating inlet dampers of ID fans and the fan speed to maintain constant negative pressure at the furnace chamber. Speed adjustment will come into picture when the pressure excursion will be beyond certain limit. Bidder can furnish any alternative scheme for his system offered.

Average FD fan demand, through a characterizer, provide the feed forward signal for the ID Fan inlet dampers. The PID controller shall compare and maintain the furnace pressure at the desired set point. The non-linear gain of the controller shall be desensitized near the set point to avoid minor oscillation.

It shall be possible for the entire operational process from starting of the draught system at the time of starting a unit to stopping of the system during shutting down of the unit to be automatically controlled in accordance with the pressure set for the interior of the furnace.

A safety override feature shall act as a counter-measures against explosions and implosions for safe operation of boilers. The override shall come into operation on high pressure deviations to adjust the demand signal for the ID fans. The safety circuit shall quickly bias the inlet dampers, based on air flow, when MFT occurs. The override shall withdraw itself when the furnace pressure comes within its Norman excursions. The safety system will requisition MFT when predefined limits of pressure are exceeded.

In the event of any limitation occurring in the draught plant capability, the draught plant shall continue to operate under automatic control at or close to the new operational limit, and the unit generation shall be automatically ramped down to match the group or subgroup constraint in an orderly manner.

The control system and means of measurement shall be designed to enable accurate repeatable automatic control of combustion to be carried out over the load range from 35% rated output to boiler MCR.

Forward path steady state and dynamic compensators whose parameters are load dependent and which account where necessary for the number of draught fans in operation shall be incorporated in the furnace pressure modulating loop.

Directional blocking shall be extended to UCC if furnace draft is too much or too less compared to the set value, ID dampers are driven to extreme.

Synchronizing circuit between the two fans shall be provided for equal or unequal sharing (by biasing) with respect to damper position or motor current etc on each side.

Mill Outlet Temperature Control

Mill outlet temperature shall be maintained at set value by varying positions of hot air damper and cold air damper.

Deaerator and Hot Well Level Control

Deaerator level shall be maintained by regulating condensate flow control valve in the main condensate line to deaerator. This will be 3 E control consisting of Deaerator level, Feed-water flow including SH & RH attemperation flow and condensate flow along with extraction steam flow to deaerator and HP heater drain flow to deaerator. Hotwell level will be maintained by regulating the valves “DM water make up to hotwell” and “Dump to condensate tank”.

Balance of plant controls

Other balance of controls not limited to the following shall be provided:

a) HP Heater level control- normal & emergency drain

b) LP heaters level controls- normal & emergency drain

c) GSC level control

d) Deaerator pegging steam pressure control

e) Flash tank level control