POWER SYSTEM OPERATION AND CONTROL
Energy management system is the process of monitoring, coordinating and controlling the generation, transmission and distribution of electrical energy. The physical plant to be managed includes generating plants that produce energy fed through transformers to the HV transmission network(grid), interconnecting generating plants, and load centers.
Since transmission systems provide negligible energy storage, supply and demand must be balanced by either generation or load. Production is controlled by turbine governors at generating plants, and automatic generation control is performed by control center computers remote from generating plants. Load management, sometimes called demand-side management, extends remote supervision and control to subtransmission and distribution circuits, including control of residential, commercial, and industrial loads.
Energy management is performed at control center, typically called system control centers, by computer systems called energy management systems /EMS/. Data acquisition and remote control is performed by SCADA.
AGC consists of two major and several minor functions that operate on –line in real time to adjust the generation against load at minimum cost. The major functions are load frequency control and economic dispatch, and the minor functions are reserve monitoring, which assures enough reserve on the system; interchange scheduling, which initiates and completes scheduled interchanges; and other similar monitoring and record functions /load forecast, fault allocation, trouble analysis/.
Generation control and ED minimize the current cost of energy production and transmission within the range of available controls. Energy management is a supervisory layer responsible for economically scheduling production and transmission on a global basis and over time intervals consistent with cost optimization.
2. LF and QV Control
Although there are many things to control in power system, majorly we control voltage and frequency by controlling other parameters of the generators, load and other devices in the system.
For efficient and secured power system- maintain reliability, security, stable, operate in most economical way, better quality (frequency with in the limit (3%), voltage (5% HV, 10% LV)).
Frequency is global phenomena ( same in one node and other), voltage is local phenomena (one point and another point is different). Eg. Change of frequency and voltage affect normal operation of the system.
Frequency control can be achieved by controlling active power which is possible at generation (injecting power) and load end (consuming power). It is preferred to control the power at generation side and load end control is done during the emergencies.
Total Generation < demand = frequency fall. -- generation increase, or load decrease/ very expensive b/c it affect power reliability.
Total Generation > demand = frequency rise. – generation decrease /load increase not at hand/
Therefore, the explanation is energy can go no where but stored in the form of kinetic energy and when load increases, this stored energy will be taken to supply the demand and hence stored kinetic energy will decrease and hence speed decrease. -> the frequency of the system will decrease because of the reduction of speed of generator [f=NP/120]. The same is true for 2nd case!
Reactive power control is responsible mainly for voltage control which is a local problem.
2.1 Load Frequency Control
In a power system the load demand is continuously changing. In accordance with it the power input has also to vary. If the input - output balance is not maintained a change in frequency will occur. The control of frequency is achieved primarily through speed governor mechanism aided by supplementary means for precise control.
LFC consists of three major parts.
(i) Speed governing system
(ii) Rotating components (turbine-generator)
(iii) load and power system.
2.1.1 Speed governing system
- The speed governing mechanism includes
A- Speed Governor
The essential part are centrifugal flyballs driven directly or through gearing by the turbine shaft. The mechanism provides upward and downward vertical movements proportional to the change in speed.
B- Linkage Mechanism
These are links for transforming the flyballs movement to the turbine valve through a hydraulic amplifier and providing a feedback from the turbine valve movement.
C- Hydraulic Amplifier
Very large mechanical forces are needed to operate the steam valve. Therefore, the governor movements are transferred into high power forces via several stages of hydraulic amplifiers.
D- Speed Changer
The speed changer consists of a servomotor which can be operated manually or automatically for scheduling load at nominal frequency. By adjusting this set point, a desired load dispatch can be scheduled at nominal frequency.
The speed governing system is the primary LFC loop and its simple schematic representation is shown above.
In order to understand the operation, we should consider two cases, i.e. the first is when speed changer is given Raise or Lower command but speed of the turbine remains constant and second when speed of turbine is changed but command is not given to the speed changer. Under these conditions, the position of the joints will be changed according to the applied phenomena.
CASE I: Speed changer is given Raise command and speed is constant.
CASE II: Speed changer is constant and speed is increased.
Hence a relation can be established based on the above facts.
xc = k1 f– k2 Pref
xd = k3 xc + k4 xe
xe = - k5 xd dt
Where k1 , k2, k3 and k4 are constants and depend on the length of arms and k5 depends on oil pressure and geometries of cylinder.
Let us define
k1 k2/ k4 = kg – static gain of governor
1 / k4 k5 = Tg – static gain of governor
k2/ k1 = R – Regulation of speed governor
Substituting and Simplifying , we get
This can be represented using block diagram as shown below.
2.1.2 Turbine model
The figure illustrate the turbine-generator mechanical connection.
The turbine-generator model depends on whether we have hydro-turbines, or in case of steam turbines we have reheat or non-reheat type of steam turbines.
For a simple a non-reheat type turbine model is given by a single time constant,
Taking input power to the turbine is Pv /power from the valve opening/ and output power is mechanical power Pm, the block diagram becomes
2.1.3 Generator Model
The basic configuration of turbine and generator is shown in the figure below.
Here, based on swing
For a change in mechanical and electrical power, the above equation using per unit system becomes,
Taking Laplace transform, we get
2.1.4 Load Model
In general, power system loads are a composite of a variety of electrical devices, For resistive loads, such as lighting and heating loads, the electrical power is independent of frequency. In case of motor loads, such as fans and pumps, the electrical power changes with frequency due to changes in motor speed. The overall frequency-dependent characteristics of a composite load may be expressed as
Where PL is the non-frequency-sensitive load change, f is the frequency-sensitive load change, and D is expressed as percent change in load divided by percent change in frequency.
Substituting the above equation to the previous model (generator model), we get the following block diagram
Using transfer function of closed loop can be G(s)/1 + G(s) H(s), the above model can be further simplified as follows [taking G(s) = 1/2Hs and H(s) = D]
2.1.5 Single control area
In the previous sections models for turbine-generator, power system and speed governing systems are obtained. In practice, rarely a single generator feeds a large area. Several generators connected in parallel, located also, at different places will supply the power needs of a geographical area. Quite normally, all these generators have the same response characteristics in load demand. Such a coherent area is called a control area in which the frequency is assumed to be the same throughout in static as well as dynamic conditions.
In such a case, it is possible to define a control area, grouping all the generators in the area together and treating them as a single equivalent generator, i.e for purpose of developing a suitable control strategy, a control area can be reduced to a single speed governor, turbo-generator and load system. Putting together, the carious models derived so far a single control area can be conceived as shown below.
The basic requirements to be fulfilled for successful operation of the system are
The generation must be adequate to meet all the load demand.
The system frequency must be maintained with narrow and rigid limits.
The system voltage profile must be maintained within reasonable limits
In case of interconnected operation, the tie line power flows must be maintained at the specified values.
Should the generation be not adequate to balance the load demand, it is imperative that on e of the following alternatives be considered for keeping the system in operating condition:
Starting fast peaking units
Load shedding for unimportant loads, and
The block diagram of single area system, where the gain and time constant in each block are as described in the individual section before, is as shown below.
2.1.6 ANALYSIS OF SINGLE AREA SYSTEM
The above model shows that there are two important incremental inputs to the load frequency control system - Pref, the change in speed changer setting, and PL, the change in load demand. Let us consider a simple situation in which the speed changer has a fixed setting (Pref, = 0.) and the load demand changes. This is known as free governor operation.
In the given condition, the block diagram will be simplified as
A. LOAD CHANGE ONLY Considering Ts < TTG << TP and KSKTG 1, the dynamic response which is giving the change in frequency as a function of the time for a step change in load can be obtained as follows
where G(s) = KP/(1+sTP ) and H(s) =1/R.
Partial fractions for the expression can be simplified as follows:
Based on this, the above expression can be simplified
The laplace transform of the above equation is as follow
Where = and k = =
The plot of change in frequency versus time for first order approximation given above is as shown below.
steady state result (at t = )
Therefore, we can say that the LFC system posses inherently steady state error for a step input of load change provided that the reference setting remains unchanged.
B. REFERENCE SETTING CHANGE ONLY: Consider now the steady effect of changing speed changer setting with load demand remaining fixed. Similar to the previous condition, letting Ts < TTG << TP and KSKTG 1, the simplified block diagram and transfer function becomes
Where G(s) = KP/(1+sTP) and H(s) =1/R
Following the same procedure as case A, the steady state change in frequency due to change in reference setting will have similar expression:
If the speed change setting is changed by Pref while the load demand changes by PL, the steady state frequency change is obtained by superposition, i.e.
According to the above equation, the frequency change caused by load demand can be compensated by changing the setting of the speed changer, i.e.
, for f = 0.
Therefore, for this purpose, a signal from f is fed through an integrator to the speed changer resulting in the block diagram configuration shown below.
Now, the analysis on input-output relation results
Neglecting TS and TTG /both have << Tp/ and KSKTG 1, the above equation becomes,
Then, the change in steady state frequency is
Here we find that the steady state change in frequency has been reduced to zero by the addition of the integral controller. In central load frequency control of a given control area, the change (error) in frequency is known as Area Control Error (ACE). The additional signal fed back in the modified control scheme presented above is the integral of ACE.
From the above analysis, it is clear that proportional integral and derivative control strategy can be applied for load frequency control. While proportional control is inherent in the feedback through the governor mechanism itself, derivative control when introduced improves transient performance and ensures better margin of stability for the system.
The selection of the gain controller /in the secondary LFC/ should be such that i. control loop must be stable, ii. Frequency error should return to zero
COMPOSITE SYSTEM IN A SINGLE CONTROL AREA: The composite power/frequency characteristics of a power system thus depends on the combined effect of the droops of all generator speed governors. It also depends on the frequency characteristics of all the loads in the system. where Meq /equivalent generator/ = M
For a system with n generators and a composite load-damping constant of D, the steady-state frequency deviation following a load change PL is given by
2.1.7 TIE-LINE CONTROL
An extended power system can be divided into a number of load frequency control areas interconnected by means of tie lines in order i. to get commercial benefit from neighboring systems ii. to meet sudden requirement of electric power and improve reliability iv. Reduce in installed capacity. The major disadvantages are control system becomes complex and any disturbance in one system is reflected in the other area .
The control objective now is to regulate the frequency of each area and to simultaneously regulate the tie line power as per inter-area power contracts. As in the case of frequency, PI controller will be installed so as to give zero steady state error in tie line power flow as compared to the contracted power.
Power transported out of area A is given by
where , are power angles of equivalent machines of the two areas.
For incremental changes in 1 and 2 , the incremental tie line power can be expressed as
Where T12 is synchronizing coefficient.
Since incremental power angles are integrals of incremental frequencies (f1 and f2), the above equation can be written as
Similarly the incremental tie line power out of area B is given by
The block diagram of the system based on the above analysis is given below
The steady state response of this two area system can be determined as follows.
Consider the speed changer position is fixed (Pref1 and Pref2) and there are step load changes in both areas (PL1 and PL2).
The turbine input change (Pm1 ss & Pm2 ss) due to the valve opening by the regulation characteristics in the two areas in steady state condition becomes , Pm1 ss = - (1/R1) Fss ; Pm2 ss = - (1/R2) Fss
Under this condition &
Solving for steady state frequency and tie line power, we get &
Where 1 = D1 + 1/R1 and 2 = D2 + 1/R
We thus conclude from the preceding analysis that the two area system, just as in the case of a single area system in the uncontrolled mode, has a steady state error but to a lesser extent and the tie line power deviation and frequency deviation exhibit oscillations that are damped out latter.
Hence, in interconnected operation to avoid these deviations and also to enable each area control the changes in such a fashion that it absorbs its own load change in steady state, area control error signals should be sent to reference (speed changer) in the two areas respectively as follows
Using laplace transform
The general block diagram for a two area system can now be developed as shown below.
2.2 QV CONTROL
Industrial and domestic loads, both, require real and reactive power. Hence, generators have to produce both real and reactive power. Reactive power is required to excite various types of electrical equipment as well as transmission network.
Basically, the reactive power transmitted over a line a great impact on the voltage profile. Hence, by controlling the production, absorption and flow of reactive power at all levels in the system, the control of voltage levels is accomplished.
For efficient and reliable operation of power systems, the control of voltage and reactive power should satisfy the following objectives;
Voltage at the terminals of all equipment in the system are within acceptable limits.
The reactive power flow is minimized so as to reduce losses to a practical minimum.
Important generators of reactive power are
over-excited synchronous machines
capacitor banks, the capacitance of overhead lines and cables
Static var compensators
Important consumers of reactive power are
inductive static loads, shunt reactors, inductance of overhead lines and cables
under-excited synchronous machines,
Transformer inductances, induction motors
Static var compensators
For some of these, the reactive power is easy to control, while for others it is practically impossible. The most important devices for reactive power and voltage control are described hereafter.
2.2.1 ANALYSIS OF GENERATOR VOLTAGE CONTROL
Generators are often operated at constant voltage by using an AVR which senses the terminal voltage level and adjusts the excitation to maintain constant terminal voltage also maintain the reactive output at the required level.
The main purpose of the excitation system of a synchronous machine which may be either DC excitation, AC excitation or Brushless excitation scheme is to feed the field winding with direct current so that the main flux in the rotor is generated. The relation between terminal voltage and induced voltage of alternator can be expressed as
Under different loading conditions especially when there is constant real power and variable reactive power demand, the terminal voltage will vary.
Consider that the current is operating at unity power factor and hence, no reactive power generation at the alternator. For there is any change in reactive power demand, the alternator acts to supply the demand, if there is no any other device to respond. If excitation is not changed depending on the condition, the terminal voltage of the alternator deviate from the desired value. This in turn, affects the voltage distribution in the system. In order to avoid this problem the excitation of the alternator has to take action accordingly.
To understand how voltage can be maintained using excitation system, consider the following
The function of important components and their transfer function is given below
Potential transformer: It gives a sample of terminal voltage, VT
Differencing device: at the feedback point, Vref - VT = e
Error amplifier: It demodulates and amplifies the error signal. eA = kA e, where kA is amplifier gain.
SCR power amplifier and exciter field: It provides the necessary power amplification to the signal for controlling the exciter field.
where ie is the change in exciter field current. If 1A change in field current produce k volt change in the output, then ef = kA ie. The transfer function of the exciter using laplace can be expressed as
Alternator: Its field is excited by the main exciter voltage. Under no-load it produces a voltage proportional to field current. The input voltage signal ef to the generator field, when applied to the circuit results in the following Kirchoff’s voltage equation.
… If the output voltage changes by v, then where Lfa is the mutual inductance between the field and stator phase winding. Hence, the transfer function for the generator block will be
The voltage regulator loop can be represented by the following block diagram
The cascaded transfer function blocks can be combined into single block
2.2.2 OTHER CONTROLLERS
Shunt Reactors: are used to compensate for the effects of line capacitance, particularly to limit voltage rise on open circuit or light load.
Shunt Capacitors: supply reactive power and boost local voltages. They are used throughout the system and are applied in a wide range of sizes.
Synchronous condenser: is a synchronous machine running without a prime mover or a mechanical load. By controlling the field excitation, it can be made to either generate or absorb reactive power.
Static var compensators (SVCs): may be comprised of two different elements, i.e TCR and TSC. By delaying the firing of the thyristors, a continuous control of the current through the reactor can be obtained, with the reactive power consumption varying between 0 and V2/X.
By combining the TCR with a suitable number
of capacitor banks, a continuous control of the
reactive power can be achieved by a combination
of capacitor bank switching and control of reactor
current. The control system of the SVC controls
the reactive output so that the voltage magnitude
Of the controlled node is kept constant.
3. OPTIMAL POWER FLOW
3.1 ECONOMIC OPERATION /ED-Economic Dispatch/
The economic dispatch problem consists in allocating the total demand among generating units so that the production cost is minimized.
Generating units have different production costs depending on the prime energy source used to produce electricity (mainly coal, oil, natural gas, uranium, and water stored in reservoirs).
In addition to continuous decisions on how to allocate the demand among generating units, the economics of electricity generation also requires the calculation of an optimum time schedule for the start-up and shutdown costs of the generating units. (since the units’ start-up or shutdown costs can be significant, on/off scheduling decisions must be optimally coordinated with the ED of the continuous generation outputs.
Each generating unit is assigned a function, Ci(PGi), characterizing its generating cost in $/h in terms of the power produced in MW, PGi, during 1hr. This function is obtained by multiplying the heat rate curve, expressing the fuel consumed to produce 1MW during 1hr, by the cost of the fuel consumed during that hour. /Note that the heat rate is a measure of the energy efficiency of the generating unit/.
Considering n generating units, the total production cost is
where Pgi is unit generation level
If the system total demand is PD total and all generating units contribute to supply this demand, total production or generation must be
The ED problem consists of minimizing the total cost with respect to the unit generation output subject to the above power balance, and to the generating unit operational limits
Using the method of Lagrange multipliers, neglecting losses and generating limits for simplicity, we have L(P,) = F(P) + G(P) where F(P) is objective function for minimization and G(P) is equality constraint. Therefore,
The necessary conditions are given as
Hence, we get
The above equation states that at the optimum all the generating stations operate the same incremental cost for optimum economy and their incremental production cost is equal to the Lagrange multiplier at the optimum.
In addition to the load should be taken up always at the lowest incremental cost, it must be ensured that the generations so determined are with in their capacities. Under this circumstance, the Lagrange function becomes
where new multipliers, are incorporated, corresponding to the minimum and maximum power outputs of each generating unit.
The first-order necessary optimality conditions become
Hence, the marginal cost will be operated at equal incremental cost if the generation is with in the limits. Otherwise, the generation has to be kept constant at the capacity limit for that unit and eliminated from further optimum calculations.
3.2 ECONOMIC SCHEDULING INCLUDING LOSSES
Electric power transmission or "high voltage electric transmission" is the bulk transfer of electrical energy, from generating power plants to substations located near to population centers. This is distinct from the local wiring between high voltage substations and customers, which is typically referred to as electricity distribution. In this process, some part of electric energy is lost as transmission and distribution loss.
The size of the power systems increased enormously, with long transmission lines connecting several power generating stations extending over large geographical areas transferring power to several load centers.
With this development, it has become necessary to consider not only the incremental fuel costs but also incremental transmission losses incurred in these line while power is transmitted.
Here, the previous equality constraint is modified by including losses and the Lagrange function becomes
Applying the necessary conditions for the minimum L
The sum of the incremental production cost of power at any plant i and the incremental transmission losses incurred due to generation Pi at bus i charged at the rate of must be constant for all generators and equal to . This constant is equal to the incremental cost of the received power.
One of the most important, simple but approximate methods of expressing transmission loss as a function of generator powers is through B-coefficients. This method uses the fact that under normal operating condition the transmission loss is quadratic in the injected bus real powers.
where Pi and Pj are real power injection at bus i and j, and Bij is loss coefficients.
Substituting this to the previous first derivative equation, we get
If the incremental costs are represented by a linear relationship following a quadratic characteristics, then ICi(PGi) = ciPi + di
Substituting PGi = Pi + Pdi, and simplifying for Pi
For any particular value of , the above equation can be solved iteratively by assuming initial values of Pi . Iterations are stopped when Pis converge within a specified accuracy.
It should be understood that losses can be considered not only as a constraint but also as objective function.
3.3 HYDRO-THERMAL SCHEDULING
Most of the power systems are a mix of different modes of generating station of which thermal and hydro generating units are predominant. The hydro plants can be started easily and can be assigned load in very short time. This is not so in case of thermal plants, as it requires several hours to bring the boiler, super heater, and turbine system ready to take the load allotment. For this reason, the thermal plants are more suitable to operate as base load plants, leaving hydro plants to operate as peak load plants.
Whatever, may be the type of plant, it is necessary to utilize the total quantity of water available in hydro development so that maximum economy is achieved.
Considering the operation time to be T, let us divide into intervals 1,2,….J to suit the load curve so that
The equality constraint for the total volume of water available for discharge over this period is
where wj is the water rate for interval j
The fuel cost required to be minimized over this period T is given as
For load balance assuming loads are constant during this interval and head of water is also remain constant, the equality constraint is
PSGj + PHGj - PDi = 0.
The input-output characteristic for the equivalent hydro plant is
w = w(PH)
The Lagrange function for minimization subject to the above constraints is
For any specific value of j, the necessary conditions are
Solution to the above equations gives the economic generations at steam and hydro plants over any time interval. The incremental production cost at the steam plants must be the same as incremental production cost at the hydro plants.
3.4 OPTIMAL POWER FLOW ANALYSIS TOOLS
There are various optimization methods have been proposed to solve the optimal power flow problem in iterative techniques, some of which are refinements on earlier methods. These include:
Gradient descent method: is a first-order optimization algorithm. To find a local minimum of a function using gradient descent, one takes steps proportional to the negative of the gradient (or of the approximate gradient) of the function at the current point.
Newton’s method: is a method for finding successively better approximations to the zeroes (or roots) of a real-valued function.
Linear programming methods: is a technique for the optimization of a linear objective function, subject to linear equality and linear inequality constraints.
Quadratic programming methods: is a special type of mathematical optimization problem. It is the problem of optimizing (minimizing or maximizing) a quadratic function of several variables subject to linear constraints on these variables.
Interior point method: are a certain class of algorithms to solve linear and nonlinear convex optimization problems.
3.5 SECURITY CONSTRAINED OPF
So far we have been primarily concerned with the economical operation of a power system. An equally important factor in the operation of a power system is the desire to maintain system security.
Security of supply is a measure of the power system’s capacity to continue operating within defined technical limits even in the event of the disconnection of a major power system element such as an interconnector or large generator or any piece of equipment in the system due to either internal or external causes such as lightning strikes, objects hitting transmission towers, or human errors in setting relays.
Reliability is a measure of the power system’s capacity to continue to supply sufficient power to satisfy customer demand, allowing for the loss of generation capacity.
Hence, the EMS has to operate the system at minimum cost, with the guaranteed alleviation of emergency conditions such as violations of operating limits, contingencies.
System security can be said to comprise three major functions that are carried out in an energy control center:
System monitoring: supplies the power system operators with pertinent up-to-date information on the conditions of the power system. Telemetry systems measure and transmit the data, and then digital computers in a control center process and inform the operators in case of an overload or out of limit.
Contingency analysis: this model possible system troubles (outages) before they occur i.e, it carries out emergency identification and “what if” simulation. This allows the system operators to locate defensive operating states where no single contingency event will generate overloads and/or voltage violations.
Corrective action analysis: permits the operator to change the operation of the power system if a contingency analysis program predicts a serious problem in the event of the occurrence of a certain outage. Thus, this provides preventive and post-contingency control.
3.5.1 SECURITY ASSESSMENT: CONTINGENCY ANALYSIS
The evaluation of the security degree of a power system is a crucial problem, both in planning and in daily operation. Without considering dynamic issues, power system security must be interpreted as security against a series of previously defined contingencies, therefore, the concept of security and its quantification are conditioned.
Operations personnel must know which line or generation outages will cause flows or voltages to fall outside limits. To predict the effects of outages, contingency analysis techniques are used.
Security assessment or Contingency analysis procedures model single failure events (i.e., one-line outage or one-generator outage) or multiple equipment failure events (i.e., two transmission lines, one transmission line plus one generator, etc.), one after another in sequence until “all credible outages” have been studied. For each outage tested, the contingency analysis procedure checks all lines and voltages in the network against their respective limits.
A. CONTINGENCY DEFINITION:- the list of contingencies to be processed whose probability of occurrence is high.
The question is how to select the contingencies to analyze in detail in such a way that none of the problematic ones would be left unattended, also taking into account the required speed of response imposed by real time operation.
One way to gain speed of solution in a contingency analysis procedure is to use an approximate model of the power system. For many systems, the use of linear sensitivity method which shows the approximate change in line flows for changes in generation on the network configuration /derived from the DC load flow method/ provides adequate capability. However, the limitation attributed to the DC power flow is that only branch MW flows are calculated and there is no knowledge of MVAR flows or bus voltage magnitudes.
The linear sensitivity factors are basically two types:
Generation shift factors – change in line flow (fl) due to generation outage (Pi)
Line outage distribution factors - change in line flow (fl) due to line outage (fk)
The flow on line l, under the assumption that all the generators in the interconnection participate in making up the loss, use the following
The power flow on line l with line k out can be determined using ‘d’ factors
B. CONTINGENCY SELECTION: – these contingencies are ranked in rough order of severity employing contingency selection algorithms to shorten the list.
The idea of performance index seems to fulfill this need. The definition for the overload performance index (PI) is as follows:
The selection procedure then involves ordering the PI table from largest value to least. The lines corresponding to the top of the list are then candidates for the short list.
One way to perform an outage case selection is to perform what has been called 1P1Q method. Here, a decoupled power flow is used to determine power flow through the lines and voltage at the nodes. Thus, a different PI can be used,
3.5.3 OPERATING STATES:
The correct comprehension of the role played by the different activities involved in the system operation implies classifying of the possible system states as a function of the security degree. There are four different states:
Normal state – all the system variables are within the normal range and no equipment is being overloaded. The system operates in a secure manner and is able to withstand a contingency without violating any of the constraints.
Alert state – all system variables are still within the acceptable range and all constraints are satisfied. However, the system has been weakened to a level where a contingency may cause an overloading of equipment that places the system in an emergency state. If the disturbance is very severe, the in extremis state may result directly from the alert state.
Emergency state: – if a sufficiently sever disturbance occurs when the system is in the alert state. In this state, voltages at many buses are low and/or equipment loadings exceed short-term emergency ratings. The system is still intact and may be restored to alert state by the initiating of emergency control
Extremis: - if measures taken are not effective, the result is cascading outages and possibly a shut-down of a major portion of the system. Control actions, such as load shedding and controlled system separation, are aimed at saving as much of the system as possible from a widespread blackout.
Restorative state: - represents a condition in which control action is being taken to reconnect all the facilities and to restore system load. The system transits from this state to either the alert state or the normal state, depending on the conditions.
4. COMPUTER CONTROL OF POWER SYSTEM
The ability to perform operations at an unattended location from an attended station or operating center and to have a definite indication that the operations have been successfully carried out can provide significant cost savings in the operation of a power system.
Devices to control equipment remotely have been used for many years, and the need for remote indication as well as control led to the development of equipment that could perform the operations, monitor them, and report back to the control center that the desired control action had been satisfactorily affected. At the same time it is often important to transmit such information as loads and bus voltages to an operating center.
4.1 SUPERVISORY CONTROL AND DATA AQUSITION /SCADA/
Supervisory control: is the SCADA function used to control commands to field equipment (digital devices, set points) under the supervision of the RTUs, from the operator or from another application, through a user-callable Application Programming Interface (API).
This allows to operate
two state devices, such as switching devices, with associated open/close commands
adjustable devises such as transformer tap changer with associated raise/lower commands
power units with set points, with interfacing with the AGC function
Almost all modern dispatch and operating centers of power systems are now provided with at least some SCADA system equipment.
SCADA equipment has proven to be efficient and economical for power system operations. It is a very effective aid for station operators, making it possible for them to maintain relatively complete knowledge of conditions on the portions of the system for which they are responsible.
The term Supervisory Control is normally applied to remote operation(control) of such devices as motors or circuit breakers, and the signalling back (supervision) to indicate that the desired operation actually has been affected where as Data Acquisition means data is collected from RTUs, substation and power plant’s digital control system, other control centers, manual entries, automatic calculations, and any data from other applications.
Supervisory master units: is the heart of the system. All operator initiated operations of an RTU are made through the master unit and are reported back to the master from the RTUs. Modern supervisory master units consist of a digital computer and equipment to permit communications between the master and the RTUs.
In addition to computer, peripheral equipment necessary for the proper operation of the system is provided. Such equipment consists of
keyboards or other means of entering data and commands into the computer
CRTs or monitors
Printer to provide the operator at the master station with written messages of actions performed by the master and of data obtained from RTUs.
Digital-to-Analogue converters to convert the digital data message information (on such items as line current, bus voltage, frequency, power, and reactive power flow) to analogue form that can be used to supply indicating or recording instruments.
Remote terminal units: are located at selected stations, ad are either wired to perform certain preselected functions or, in modern units, equipped with microcomputers which have memory and logic capabilities.
The RTUs are also equipped with modems so that they can accept messages from the master and signal back to the master that messages have been received and the desired operations performed.
Transducers in the remote units are used to convert such quantities as voltage, current, watts and vars to direct current or voltage proportional to the measured quantity, and then by means of analogue-to-digital converters convert the quantity to digital form, used by the system for transmission from the remote to the master.
SCADA system applications: in addition to the remote supervisory control, status monitoring, various other programs can be incorporated in such systems to improve operations and minimize the manual effort required of power system operators. Some of these are
Automatic generation control:- control systems that are responsive to frequency variations, cost factors, transmission losses, etc
Security monitoring:- checking the limits of loading and other quantities in order to determine whether the system is at or near at alert or emergency state.
Online load flow:- when sufficient information is telemetered to the master unit, a load flow program can be developed to predict loading of lines and stations under selected future conditions using actual operating data.
The reliability of a SCADA system is very important, and several means are used to ensure maximum reliability for such system. Most master units are dual computers, with one as a primary unit and the other on standby to take immediate control, usually automatically, if primary unit should fail.
4.2 AUTOMATIC LOAD DISPATCHING
The Load Dispatch Department is the nerve centre for the operation, planning, monitoring and control of the power system. Electricity cannot be stored and has to be produced when it is needed. It is therefore essential that power system is planned and operated optimally & economically. This is the main objective of Load Dispatch Centre.
Major Functions of Load Dispatch Center:
To ensure integrated operation of the power system.
To give directions and exercise supervision and control which is required for integrated operation to achieve maximum economy and efficiency in power system operation.
Scheduling and Re-Scheduling of available resources for optimum and economic operation of the power system.
To coordinate shutdowns for the Generating Units and Sub-station equipment, including transmission lines taking into consideration continuity of supply with quality.
System Restoration in a systematic manner in shortest possible duration, following Grid Disturbances.
Accounting of Energy handled by the State System.
Compiling & Furnishing data pertaining to Power System Operation.