Power Plant Dispatching in Thailand

Warit Rattanachuen

Power System Control and Operation Division

Electricity Generating Authority of Thailand, Thailand

E-mail : warit.r@egat.co.th

1. Abstract

Thailand Electricity Supply Industry (ESI) is the single buyer model that most electricity is

generated and transmitted via the main grid system which is operated by Electricity

Generating Authority of Thailand (EGAT). The optimized dispatching is done by SCU

(EGAT system control unit) who is the System Operator (SO) regulated by Energy

Regulatory Commission (ERC). For the reason of transparency, SCU is treated as a ring-

fencing unit, thence the optimization objective is the countrys least cost. EGAT (power

plants and transmission system) capital, debt and return are earned in the based electricity

tariff; whereas private power producers earn capital, debt and return in Availability/Capacity

Payment, thence pass through via the adjustment tariff. Thus, only the variable cost from both

EGAT power plants and private power producers that are related with the output power

dispatched by EGAT, which will be considered as main variable in dispatching principal and

pass through the adjustment tariff. As general power system, many constraints are taken into

account in dispatching process. Transmission system constraints force some generating units

to be must-run units; nevertheless the other transmission system constraints limit power

output from some power stations. Gas supply and pipe line constraints limit generation from

the group of plants; therefore the secondary fuel such as fuel oil or diesel oil will be the

alternative in dispatching consideration. The commercial constraints both from fuel supply

agreements and power purchase agreements force some power plants to be the must take

generating capacity; in the same manner of irrigation requirement from reservoir in Thailand.

In the operational planning phase, the commercial Linear Programming optimizer and

equations are developed by universities using in long-term (1-5 years ahead) and short-term

(day and week ahead) generation planning. The medium-term (1-4 months ahead) generation

planning is done via the in-house worksheet. Power system simulation software is employed

to simplify transmission constraints that are taken into account in generation operation

planning. Furthermore computers at the control center support the real-time system

management, and economic dispatching which is calculated by the software of energy

management system. The dispatching target is sent from the control centers computer to the

power plants control system via data communication that is a close system. Real-time

network analysis, contingency analysis and security enhancement help operators to maintain

standard security. Other tools outside the control centers computer such as, Wide Area

Monitoring or fault locator also support operators to control the power system.

2. Introduction

Thailand Electricity Supply Industry (ESI) is the single buyer model as shown in Fig1.

Around 90% of power consumption is generated, transmitted and distributed via the state-

owned utility system, and the rest power is generated and supplied by Small Power Producers

(SPPs) on their system. The power is generated by both the state-owned utility named EGAT

and private power producers, but it is transmitted by EGAT and is distributed by the state-

owned power distribution utilities. Because EGAT operates transmission system and most

power is transferred on EGAT system; thus, EGAT is both the power purchaser and the

system operator in Thailands ESI. The principal of power supply in Thailand is standardized

power delivery with reasonable price and Thais electricity tariff is based on the pass-through

principal. Same as general system operators, SCU dispatch generators based on economical

objective function with security and commercial constraints; moreover, they control

transmission main grid network that is 230 kV (kilo-Voltage) and 500 kV. The following

topics will explain about objective function, dispatching constraints and methodology both in

the operational planning phase and the real-time operational phase.

Fig1 Thais Electricity Supply Industry Fig2 Generation capacity sharing

3. Objective Function

In dispatching process, the economic is treated as the objective function; same as, in the

general power system. To understand the objective function, EGAT organization and

electricity tariff are necessary to be described. EGAT is the state-enterprise organization, and

was established as the power utility in 1969. Besides, EGAT take responsibilities in power

generation and transmission for the whole country; therefore, EGAT operates system to

minimize the total cost of electricity supply that is different from any business companies

who try to maximize profit as their target. Because EGAT owns around 47% of the power

capacity in EGAT system as shown in Fig2, so the public may not trust in EGAT system

operation and dispatching. Thus, the regulatory body called Energy Regulatory Commission

(ERC) was set in 2007 for monitoring energy system operation including the system operator,

EGAT. Therefore, Ring-fencing system operator, account unbundling and system control

license are mechanisms to regulate the EGAT system operator.

Moreover, the suitable tariffs eliminate EGATs incentive to unreasonably dispatch with his

own generators. The generators revenue from both the state owned and the private owned

consists two parts. The first part is paid to cover equity, debt, interest and return including

fixed operation and maintenance costs. So EGAT receives the first part tariff from customers

directly via the base electricity tariff that is fixed around 5 years. And IPPs (Independent

Power Producers) also receive them as the tariff; called Availability Payment (AP), which

determines the AP rate in Power Purchase Agreement (PPA), and AP is paid when the

generator has availability to generate power with determined characteristics. The AP is not

related to energy generation, it results with IPP availability only; thus, EGAT dispatching

will not affect to Availability Payment. Another part of the generation tariff is Energy

Payment (EP) that directly relates with energy generation. EP is comprised of fuel cost and

variable operation & maintenance costs; however, the fuel cost shares around 99% of EP.

EGAT charges some parts of the electricity tariff to cover EP payment via the fuel adjustment

tariff that is calculated every 4 months by ERC.

Since EGATs dispatching target is to minimize the total cost of electricity supply, and only

EP is effected by dispatching that 99% of EP is the fuel cost; therefore, the minimizing fuel

cost can be treated as the objective function as well. Generally, the fuel cost of each power

plant comes from plant efficiency or heat rate, and fuel price. According to the dispatching

model, the heat rate curves of EGATs power plants are derived from performance testing

and the heat rate curves of IPPs are determined in PPAs that EGAT pays IPPs at guaranteed

heat rate curve in the PPA. The difference of actual fuel consumption and calculated

consumption; which is based on the guarantee heat rate curve, is the profit or loss for each

generator.

Fig3 Generation classified by fuel Fig4 Thais natural gas consumption sharing

Because real-time operators do not know the accurate fuel prices during operating the system,

thence the fuel prices in dispatching model are forecasted prices. When consider energy

generation classified by fuel as shown in Fig3, the major fuels are natural gas, coal and

hydro. Natural gas using in Thailand is supplied from 4 sources such as pipe gas from Gulf of

Thailand, on-shore gas, imported pipe gas from Myanmar and imported LNG (Liquefied

Natural Gas). All pipe gases that used in Thailand are set the price structure related to

delayed FO (Fuel Oil) price in regional market (Singapore oil market), thence the pipe gas

price can be forecasted with high accuracy. LNG price is related to the global gas market, so

the LNG price is forecasted with low accuracy. However, power generators in Thailand both

EGAT and private power plants purchase natural gas at Pool2 price, that is calculated by

weighted average natural gas from Gulf of Thailand deducted by the volume of natural gas in

Pool1 (Gas Separation Plants : GSP), Myanmar gas and LNG. As shown in Fig4, the gas

consumption in power sector is around 72% of natural gas in Pool2 and the Pool2 price is

calculated by weighted average method, thence SCU do not use Pool2 price in dispatching

model, they use different gas price based on source of natural gas that each power station

consumes. Moreover, the demand charge in pipe tariff is also eliminated from the model,

because it is calculated based on contracted demand without actual consumption

consideration. The next major fuel is coal, their prices are various mechanism. Because the

major domestic mining for power producers is operated by EGAT, therefore the domestic

coal price is regulated price. The imported coal using at IPPs and SPPs (Small Power

Producer) were determined price structure in the PPA, all of them are related to delayed

global coal market indices. The domestic hydro generation is not inputted the price to

dispatching model due to energy limitation, the maximize water value is the domestic hydro

operation principal, that will be described in later topic. Imported hydro power was set certain

tariff in the PPA already, only exchange rate effect to the tariff.

DSMs (Demand Side Management) are taken into account in the objective function. Almost

DSMs that cannot control by SCU are mixed in load model such as energy conservation,

TOU (Time of Use) customer that affects to daily load profile and energy storages by

customers etc. However, the utility energy storages such as pumped storage units are

considered in dispatching model. The different of SRMC (Short Run Marginal Cost) at each

time is the key in consideration. If the SRMC difference is more than pumped storage unit

efficiency losses when concern complete cycle both pumping and generating, the unit will be

dispatched.

4. Constraints

As general optimization problems, the objective function search the best result in searching

area while constraint equations set the boundary that make searching area smaller. In

principal, searching in smaller area gives worse result than searching in larger area. To

expand the searching area by reducing constraints, the more infrastructure investment is

required. However, the suitable investment and acceptable constraints were considered in

investment planning process already, therefore only constraint reduction by operation

methods such as rapid load or generator shedding schemes, energize or de-energize some

transmission line etc, are employed to expand the searching area. Finally, the constraints still

appear and constraint equations modeling are necessary in dispatching process. The

dispatching constraints can be classified to 3 groups that are technical, commercial and policy

constraints. The below sub-topic will describe detail of constraints in SCU dispatching

process.

4.1.Technical constraints

The technical constraints mean any constraints that set to support power system operation

with standard securities. The constraints are consisted of operating reserve standard that is

related to characteristics of generators, transmission system constraints that limit power

generation from a group of plants or require a minimum generation from a group of plants,

fuel gas supply constraints both quantities and quality issues, environmental restriction and

the limitation of energy from reservoir.

Operating reserve requirement

Operation reserve is classified to spinning and standby reserve. Spinning reserve is the rest

power that generators who synchronize to the system can be supply when the system need.

Spinning reserve is consisted of primary response that generators will increase the power by

themselves when detect low frequency in the system and the secondary reserve that

generators will supply more power when system operator dispatch both by verbal or

computer signal via AGC (Automatic Generation Control). EGAT system set standard

spinning reserve between 750-1500 MW (Megawatt) during peak period, the lower target is

set to cover the largest unit and the upper target is set to prevent system low efficiency due to

part load operation of generators. Moreover, the operators monitor 5 minutes spinning reserve

that should not lower than 500 MW for controlling spinning reserve quality. The 5 Minutes

reserve is calculated from the summation of power that generators can increase in next 5

minutes, they are related to loading rate and the rest power of each generator. According to

another reserve, Standby reserve is the total available units that are not synchronized to the

system. It can be divided to 3 groups based on start-up time. The quick-start group will

synchronize to the system within 30 minutes, that most of them are hydro and simple cycle

gas turbine units. The dispatchers keep quick-start reserve is not lower than 750 MW for

replacing spinning reserve when the acceptable largest incident occurred. However, the

almost hydro units are limited energy supply units and simple cycle gas turbines in Thailand

use diesel oil that is very expensive, thence the operator will start CCGT (Combined Cycle

Gas Turbine) to replace quick-start reserve units and shutdown them after CCGT

synchronized to the system. Normally, SCU keep at least 1500 MW CCGT as standby

reserve any time. The rest non-synchronized units are normal standby reserve units that do

not generate power due to higher generation cost. Fig5 shows reserve requirement in EGAT

system.

Fig5 Operating reserve requirement Fig6 Must run capacity in Southern

Fig7 Must run capacity in Metropolis Fig8 Generation limitation in North-eastern

Transmission system constraints

Transmission system constraints have 2 types, one determines a unit or a group of generating

units must be run and another limits upper generation from a group of generating units.

Transmission system constraints are come from system analysis both in steady state and

dynamic condition. In EGAT system, must run units are determined in area that generation

capacity is lower than load requirement, because transmission lines that will import power to

the area have limitation such as Southern area of Thailand as shown in Fig6, etc. Other cases

of must run units are affected by reactive power demand such as Metropolis area as shown in

Fig7, etc. On the opposite site, the upper limitations are set in the area that generation

capacity is higher than load requirement, because transmission lines that will export power

from the area have limitation such as North-eastern area of Thailand as shown in Fig8, etc.

However, SCU do not determine the constraints only for normal operation but they concern

to contingency, EGAT determined the standard that the outage must not be happen when

single contingency occurred called N-1 criteria. Transmission system analyzers determine the

upper limitation and the must run units that are simplified information to generation operation

planning model. During real-time operation, the control centers computer simulates routinely

and announces the operators when contingency outage found. The operators will adjust the

generation or transmission operation to mitigate the contingency outage.

Natural gas pipe line constraints

Similar transmission system, gas pipe system also has limitation. Natural gas in Thailand is

supplied by PTTPLC (PTT public company limited) that is shared more than 50% by

government. In investment planning process, the pipe system was designed to reach foreseen

demand without contingency security standard. The GSAs (Gas Supply Agreement) between

Fig9 Pipe line limitation Fig10 Daily gas using variation limitation

Fig11 East gas quality variation Fig12 Myanmar gas quality

PTTPLC and EGAT included guarantee quantity contracts for IPPs (EGAT guarantees

natural gas minimum take at IPPs) was made based on the cabinet resolution that determined

the power sector is the last priority of gas supply. Moreover, almost GSAs between PTTPLC

and EGAT were made based on best effort principal since PTTPLC was a state-own

organization but they are still effective. Thus, gas supply to power plants and pipe line

capacity for power sector are decreased when unforeseen demands happen. The unforeseen

demands are industrial, transportation and GSP. Fig9 shows the example of gas pipe line

limitation. Moreover, to maximize gas supply, the limitation of daily gas use variation is set.

It is related to pressure control in the pipe-line such as the west gas system that gas is

imported from Myanmar as shown in Fig10. These are quantity constraints of natural gas

supply, but another is quality issue. New gas-fired power plants are CCGT that require

narrow band of gas quality, while natural gas supply in Thailand has various qualities. As

shown in the Fig11, PTTPLC will vary the DPCU (Dew Point Control Unit) gas or LNG

sending-out when demand or supply changed and it will be effect to quality of gas supply in

east pipe system. The west pipe system is worse than east pipe system due to various quality

of gas production as shown in Fig12 and no any treated unit. The daily minimum and

maximum using are set as constraints to dispatching model especially when some incidents

occurred such as gas production shortfall, compressor outage, pipe line outage etc, that the

constraints will be increased from normal.

Fig13 Environmental issues Fig14 Thai water management diagram

Environmental restriction

Many environmental issues affect to every power plants. At least they must control

Particulate, Sulfur-dioxide and Nitrogen-oxide emission included water temperature released

as determined by related laws. Moreover, they must control pollutions included above

pollutions that may control better than laws as determined in the EIA (Environmental Impact

Analysis) or EHIA (Environmental and Health Impact Analysis). Because the EIA and EHIA

concern to public participation both construction and operation phases and CSR (Cooperate

Social Responsibility) is trend in Thais ESI, tri-parties committee is established for each

power plant. It is consisted of power plant representative, related government agency and

local communities. Many times, the committee determines additional environmental

restrictions, and power plants must concern during operation. The summarized environmental

issues in Thailand are shown in the Fig13.

Reservoir limitation energy

Almost hydro power plants that supply power to EGAT system are reservoir type both in

Thailand and Laos PDR. After rainy season finished, the water in reservoir is at the highest

level of the year. It is released during dry season and the water is at the lowest level of the

year before rainy season begin. In Thailand, the water storage in reservoirs is not for power

generation, it is for irrigation as the first priority, power generation is only by-product.

Therefore, reservoir management is done by RID (Royal Irrigation Department), they inform

water requirement of each river basin to EGAT and EGAT operate the hydro power station to

release determined water volume, the target of operation is maximizing water value. In

operational planning phase, RID informs water requirement to EGAT routinely, the

information is provided for coming season as weekly basis and confirms week-ahead

requirement as daily basis. The cooperated diagram of water management in Thailand is

shown in Fig14. Different from Thais reservoirs, the reservoirs in Laos PDR were designed

for power generation and almost energy is exported to EGAT system, so the PPAs allow

EGAT to manage majority water in the reservoir. The minority water is managed by Laos

PDR government agencies or power plant due to local water management and domestic

power generation. EGAT also plan to use water in Laos PDR reservoirs based on water value,

almost energy is generated during high demand period or during emergency situation. EGAT

operation planners divide the total limited energy in the reservoir to be daily energy

generation till end of season. They review the energy generation plan of Laos PDR hydro

plants every week. The operators dispatch hydro power plants based on daily water

requirement for Thailand reservoir and daily energy plan for Laos PDR reservoir, and they

will increase or decrease the generation based on updated priorities for emergency plan.

4.2.Commercial constraints

Commercial constraints are come from the right and characteristic in any agreements that are

PPAs and GSAs. IPPs PPAs are designed based on fully dispatch basis, the dispatcher can

vary power generation or start-stop generator as much as they required but not more than the

right that determined in the PPA. The PPAs determine EGAT right with the certain number

of loading/de-loading rate, start-stop by EGAT per year and some generators limit daily load

variation. Moreover, EGAT must guarantee minimum natural gas or coal consumption in any

contract year, thence EGAT made MGSA (Master Gas Sale Agreement) with PTTPLC and

guarantee energy purchasing from coal-fired IPP.

SPPs PPAs are different from IPPs PPAs because SPP programs were introduced to

improve energy efficiency of country and promote renewable energy. The SPPs receive

higher tariff to support them and bring the programs to be successful. SPPs are separated to

non-firm and firm PPAs. EGAT cannot dispatch non-firm SPPs who can deliver power to the

system any time. The non-firm SPP generates power from various sources such as solar,

wind, biomass, biogas, mini hydro, and natural gas (Co-generation). EGAT can dispatch firm

SPPs as month-ahead schedule and guarantee to purchase energy at 80% of availability

energy generation because they must plan to supply power and steam (in case co-generation)

to their customers in industrial estates. The majority of firm SPPs are co-generation used gas

or coal and the rest are biomass power plants.

PPA of hydro power in Laos PDR is another type that the tariff has only EP. The PPAs

determine generators to declare month-ahead expected energy generation and EGAT must

purchase 95-100%. In case that EGAT purchase lower than minimum take volume, take or

pay concept will be applied. However, the take or pay volume is limited especially in rainy

season to avoid unacceptable water spill volume. The exchanged energy between EGAT and

Laos PDRs system is similar non-firm SPP but the exchanged energy between EGAT and

Malaysias system is based on bidding principal, both of them declare day-ahead price on

hourly basis and the purchasing will be confirmed after price declaration.

4.3.Policy constraints

Because EGAT is a state enterprise, the government agencies may set some policies to

deviate normal system operation. According to hydro power stations, people who locate on

the river ways may be affected by water release from hydro power plants. They may call for

problem resolution, although they located on the problems site after power plant started the

operation or they stay into the river ways. When people face the problem, local government

agencies or power plant management often set the water release restriction based on people

demands. The next example of policy constraint is renewable energy, the cabinet ordered

power utilities to purchase renewable generation as much as generators can produce.

According to natural gas that is the major fuel of Thais power generation, some power plants

must be run at maximum for high using sale gas from GSPs that make GSPs produce LPG

(Liquefied Petroleum Gas) at maximum volume, because the government aid LPG customers

to pay lower than market price and GSP can produce LPG with lower cost than imported

LPG because GSPs purchase gas in Pool1. On the opposite site, some on-shore gas and

Myanmar gas are reduced supply volume to power plants because they must supply to

transportation sector as government policy. NGV (Natural Gas for vehicle) demand grew

highly due to low price when compare with gasoline or diesel oil price. Moreover, gas supply

to power sector will be cut first in emergency situation as determined by the cabinet and

replacement fuel such as fuel oil or diesel oil have supplied limitation because of special

quality need for complying environmental law and logistics problems. Normally PTTPLC,

who supply liquid fuel to EGAT at least 80% as determined by the cabinet, requires 30-60

days lead time for the supply process.

5. Methodologies

According to methodologies that EGAT employ to operate generation system with above

objective function and constraints, many tools are used in several steps. Maintenance

scheduling manages availability of power plants in the first step, next long-term operation

planners estimate power generation included fuel demand and check the limitation in both

generation and transmission system, shorter-term operation planners make the half-hourly

generation schedule for the next day and provide it to NCC (National Control Center) who

operates system in real-time included dispatching in the last step. The detail of each step will

be described in below sub-topics. Because the dispatching is demand-supply balancing

problem, the demand description is necessary for understanding methodologies that will be

described later.

5.1.Electricity Demand

The Fig15 shows daily load curve of EGAT system. It has 3 peak periods, morning and

afternoon peak periods are influenced by business and industrial demands, and the evening

peak period is come from residential load. The system load on weekdays increase at 10pm

due to TOU tariff that several medium and large industrial customers applied, the tariff

during off-peak period started at 10pm is very low. Moreover, the system load increase

sharply at 8am 1pm and 6:30pm and decrease rapidly at noon and 5pm. Thus, the operators

must be prepare the generation system to response both maximum power demand and

behavior of demand. For operational planner, the Fig16 shows monthly load profile that

related to the temperate, the load is high in summer season (March-May), and low in winter

season (November-February), because the air-condition loads affect to demand. EGAT past

records show around 300 MW changed when ambient temperate changed 1 degree Celsius.

Fig15 Daily load curve Fig16 Monthly peak demand

5.2.Maintenance Scheduling

Grid Code determines generators to propose 7 years maintenance schedules and operational

planners consider the proposal based on availability reserve, fuel supply maintenance plan,

related constraints and replacement cost before propose revised schedule back to generator.

Both of them will finalize the schedules and review the schedules every year. Generator must

confirm outage plan quarter-ahead, month-ahead, week-ahead and day-ahead as determined

in the Grid Code. The planners use developed program that EGAT purchased a commercial

optimization tool box using Linear Programming and equations developed by domestic

universities funded by EGAT R&D (Research and Development). The program suggests the

better schedules to operational planners that will negotiate to generators based on the

suggestion. Normally, the system prefers outage during low demand period such as winter

season, Sunday, holiday and off-peak period (in case short outage). To support planner

negotiation, PPAs allow the planner set different hourly AP payment called Weight 2 years

forward, the Weight is multiplied on AP based value. The Fig17 shows example of Weight

for a power plant in a year. In the case that the generation outage proposals are related to

other transmission outage proposals or may bring system to be more risk situation, the

planner will coordinate with transmission system analyzers to find out the best outage

schedule or determine necessary constraints as shown in Fig18.

Fig17 Different Weight for managing outage Fig18 Planned outage coordination

Fig19 Long-term planning coordination Fig20 Medium-term planning coordination

5.3.Operational planning

The planners make the generation plan and fuel consumption routinely. The first plan in

monthly basis is called yearly planning that the plans for next 2-4 years are made every

quarter, for present and the next year are made every month. The planners use the same

software that used in the maintenance scheduling process and adjusted the plan with

additional related constraints that are not inputted to maintenance scheduling software. The

next step is monthly planning that is made on daily basis for next 4 months and review every

half of month. The planners use in-house worksheet to make monthly plan that estimate

energy generation of each generator based on fuel cost and related constraints, after that the

planners calculate fuel consumption at each power station. SCU planned to start the R&D

program for developing software for yearly and monthly planning with a domestic university

using the commercial optimization tool box that EGAT have license. According to

transmission system simulation, the planners estimate power generation of each generating

unit at afternoon peak, evening peak, light load and Sunday peak for each season since

present year to next 4 years and update them every 6 month, that are provided to transmission

system analyzer who will check the constraints using commercial power system simulation

software and feed them back to the planner. Moreover, the planner make the half an hourly

basis unit power generation on a typical weekday and Sunday in next month for rechecking

transmission system problem again. The month-ahead transmission system analysis will

concern major transmission outages. The coordination between generation planners and

transmission analyzers is shown as diagram in Fig19 and Fig20.

The shorter-term operation planning is week-ahead planning that are made on half an hourly

basis for typical weekday, Saturday and Sunday, and estimate energy generation included

fuel consumption on the rest days in week on daily basis. The planners use the developed

software by a domestic university in EGAT R&D program using the same commercial

optimization tool box that employs Linear Programming. The weekly planners concern to

coordination among generation, transmission and gas system. Any constraints and foreseen

outages in all system are considered, the long-time start-up reserved units are considered to

re-synchronize in this plan. The priorities of fuel replacement in emergency condition

included hydro extra release are set in this step. The last plan is daily planning for next day

that employ weekly plan as the guide and is made on half an hourly basis with the same

software. The changed situation is taken into account in this step, the reserved CCGT are

considered to re-synchronize in this step. The updated foreseen events in generation,

transmission and gas systems are mitigate in daily planning. Fig21 shows the diagram of

coordination in shorter-term planning.

Fig21 Short-term planning coordination Fig22 AGC diagram

5.4.Dispatching

Normally, NCC receives generation schedule from the short-term planners. The schedule is

used as the guide to start/stop generating unit, to monitor water release from major reservoir

and to control hourly gas consumption. However, the actual system always deviates from

plan and NCC must adjust the power generation from each generator to balance demand and

supply with the objective function and constraints. EGAT dispatching is based on the Grid

Code that determined unit dispatching basis, therefore any dispatched instruction will be

made for each generating unit different from plant dispatching basis that dispatchers instruct

to plant supervisor and they will dispatch each generating unit in their plant again. The

communication between NCC and power plants has 2 types. One is verbal dispatching that is

confirmed by authorized document and NCC uses verbal dispatching to start/stop generating

units, to increase/decrease power of power stations that cannot control by using AGC, to

change or mix fuel use and to turn on/off remote control function of power stations. Another

is AGC that calculates the suitable power generation of each generating unit and sends the

signal to generating unit controlling system. AGC has many modes that are suitable for

different situation or different generator characteristics and NCC can use different mode for

each generator on the same time. CE (Controlled Economic dispatch) is employed in normal

situation that the major target is economic, the heat rate curve of each generating unit and

fuel prices are inputted to the model, the target power of each unit is calculated every 5

minutes, and the dispatch signal based on frequency deviation and target power is sent to

generators every 6 seconds. BP (Manual Base-Point) use in high load changing period or

emergency situation, the target power is inputted by the operators, and the dispatch signal

based on frequency deviation and target power is sent to generators every 6 seconds as well.

EX (External source) receive the target power from external calculation, such as another

program that limits power generation from a group of generators due to transmission line

constraint etc. BL (Base-point schedule) send target power to generator based on planned

schedule such as testing unit etc. AV (Average) mode calculates the target power from high

and low limit, it is suitable for narrow band control such as generators who limit daily load

changing cycle. Fig22 shows the diagram of AGC.

NCC does not consider economic only, they must control the security of power system. The

AGVC (Automatic Generation Voltage Control) is employed to control voltage as AGC.

NCC set the voltage target or reactive power target at their computer and the signals are sent

to power plants control system. Real-Time Network analysis (RTNET) software scans the

system every 3 minutes and Real-Time Contingency Analysis (RTCA) software finds the

system weak points every 3 minutes too. When the control computer found the weak points

from contingency checking, the Real-Time Security Enhancement (RTSENH) software will

suggest operators to adjust power generation or power flow or other to prevent the

contingency events. Moreover, the operators can use Study Network analysis (STNET)

software to capture the actual system at any time and analyze the system as lesson learning or

to find out the detail of interested events. Fig23 and Fig24 show the real-time securities

monitoring and NCC action when emergency outage requested. Moreover, Wide Area

Monitoring (WAM) supports NCC to monitor and prevent instability event especially on

regional system interconnection and Fault Locator helps NCC to analyze the incident

especially in the transmission line.

Because the NCC computer can control directly to generating units, therefore NCCs

computer is designed as a close system with duplicate control center concept. Double control

center rooms located in different provinces, double computer servers are installed and

operated redundant all time.

Fig23 Real-time securities monitoring Fig24 Emergency outage requested

6. Conclusions

The previous topics show the dispatching is a complicated optimization problem especially in

the actual large power system. The objective function requires the corrected main variables

that the operational planners and dispatchers must analyze the relation between each related

variables and result. Many variables inputting may give the better results but it makes

optimizer to take more computation time, the computation time is a very serious issues in

operation phase especially when emergency occurred. Constraints affect the dispatching and

must be taken into account, but the constraints equations developing is a difficult job. The

software that creates the equation by itself is required. Moreover the helpful tools, the success

of dispatching is required the coordination among related energy systems and the balancing

of securities and economical objectives.