a case study on load frequency control with automatic...

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A Case Study on Load Frequency Control with Automatic Generation Control on a Two Area

Network using MiPower

Ishan Gupta Engineer, R&D

Power Research and Development Consultants Pvt. Ltd. Bengaluru, India

[email protected]

Hemanth M. Team Lead, R&D

Power Research and Development Consultants Pvt. Ltd. Bengaluru, India

[email protected]

Abstract—This paper basically explains about the load frequency control in a multi area network. A two area network has been considered where frequency control is done using the Automatic Generation Control (AGC) system simulated in MiPower software. There are two case studies which have been explained, where the frequency behaviour has been shown under different loading conditions. In one case, the load increment was under the maximum generation limit and in the other case, it exceeded the maximum generation limit. Along with the case studies, the working of the AGC control system has also been explained in detail with its response for different loading conditions. The network has been simulated in MiPower from which the respective load flow studies results have been obtained. The AGC diagram has also been simulated in the Free Programmable Blocks module of MiPower, where the control responses have been observed and shown.

Keywords—AGC, load frequency control, generation control, area control error, MiPower.

With the increasing demand for power, a greater number of generators are being installed. It is not always feasible to install generators near load centers due to several constraints, such as unavailability of rivers or dams for a hydro power plant, and accessibility of cheap, good quality coal for thermal power plants. Such constraints create the need for supply of power from one area to another. The area with surplus generation will be supplying the power to an area with a power deficit[2-3]. In India, the North Eastern Region (NER) typically has surplus generation and low load whereas areas of the Northern Region (NR) typically have very high power demand. So, in such conditions, power is transmitted from a power surplus area to a power deficit area to meet the demand. Within these areas, power trading takes place on a contractual basis, where power is exported and imported through tie lines[4]. There are two modes in which this exchange of power takes place; i) Flat Tie Line Control, where constant power flow through the tie-line is maintained irrespective of the frequency of each area and ii) Flat Frequency Control, where constant frequency is maintained irrespective of power flow through the tie-line[1]. In this paper, the simulated test cases demonstrate the impact of an Automatic Generation Control (AGC) as a secondary control action in maintaining the frequency for different loading conditions.

I. AUTOMATIC GENERATION CONTROL (AGC)

This paper details the Automatic Generation Control (AGC) system, having three main objectives:

• To maintain system frequency at a specified nominal value (50 Hz for Indian scenario) or close to it.

• To maintain the flow of the contractually set quantity of power between system areas through tie-lines.

• To maintain generation of each unit at the most economical value [1].

An AGC works on the basis of two inputs provided by the system; i) system frequency and ii) net power flowing in or out over the tie-lines. On the basis of these inputs, the control system should be able to recognize the two scenarios that can occur between areas A1 and A2 of an inter-area system, where power export is scheduled from A1 to A2. The change in frequency of the system is given by:

∆ = − 0 (1)

Where, is the system frequency and is the nominal frequency. The change in net tie-line power flow is given by:

∆ = − (2)

Where, = Power leaving A1 − Power leaving A2 = Contractually scheduled power

There are several scenarios that occur in the system during a power mismatch scenario[5-8]. This can occur due to increase or decrease of load or generation in either area.

TABLE I. POWER IMBALANCE SCENARIO

Area A1 Frequency

Area A2

Tie-line Power Reason

Required Action

∆ < 0 ∆ > 0

Load ↑ in Area A2

Gen ↑ in Area A2 ∆ < 0

Load ↑ in Area A1

Gen ↑ in Area A1

∆ > 0 ∆ > 0

Load ↓ in Area A1

Gen ↓ in Area A1 ∆ < 0

Load ↓ in Area A2

Gen ↓ in Area A2

For each of the above mentioned scenarios, the

corresponding required action must be taken by the governor to set the required mechanical (turbine) input to the generator. In order to determine the new generation schedules that maintain the specified frequency along with

Proceedings of the National Power Systems Conference (NPSC) - 2018, December 14-16, NIT Tiruchirappalli, India

the net scheduled power flow through tie-lines, the first step is to calculate the Area Control Error (ACE), given by:

= −∆ − ∆ (3)

Where, B is the frequency bias factor in MW/Hz.

The ACE will then be passed to the subsequent section of the control system, which will direct the governors of the various participating generators to take the necessary actions for increasing or decreasing generation[9].

Each area consists of several generators which contribute to the total generation change on the basis of their respective base points and participation factors (pf). The required change in generation is calculated by[1]:

= − ∆ (4)

∆ = − (5)

Where, is the new desired output is the base-point generation

is the participation factor for unit ∆ is the change in total generation is the new total generation.

A. Implementation of AGC

In a modern AGC system, three inputs are received through telemetry channels, i.e. power output of each committed unit, power flow over tie-line and system frequency. The AGC logic is the combination of ACE logic, generation allocation logic and unit control logic. The ACE and unit error outputs are summed and passed through an integrator with gain K. The value of this gain K must be chosen wisely, as it may cause the system to diverge instead of attaining the desired set point of tie-line power or frequency[10-12]. The output of the integrator is passed to the generation allocation logic whose output is then passed to the unit control logic for computation of unit error, based on which a raise or lower request will be sent through telemetry channels to the governor to properly control the valves or gates. The AGC block diagram is depicted in Fig 1.

Fig. 1. Block diagram of AGC

II. SIMULATION

In this paper, a system with four generating units i.e. Unit A, B, C and D has been considered, with the total capacities of each unit as shown; Unit A: 1720MW (7×210MW + 1×250MW), Unit B: 1700MW (2×500MW + 1×700MW), Unit C: 1035MW and Unit D: 460MW.

There are two areas X and Y, having loads of 600MW and 500MW respectively, connected with the generating region through individual tie-lines. Within the generating region, generating units A and B are supplying a load of 1800MW at Bus 11, while generating units C and D are supplying a load of 500MW at Bus 16. The two buses, Bus 11 and Bus 16 are inter-connected through a transmission line. This combined system is connected to the external network represented by an equivalent grid, which functions as the slack bus for load flow. All the generating units have steam turbine governing systems. Units A and B have only primary governor control whereas units C and D have both primary and secondary governor control. Hence, units C and D will participate in AGC.

Initially, load flow study is performed on the system to obtain the schedules for different generating units based on the given load. In this normal operating condition, power balance is maintained, with voltage and frequency within specified limits.

In this paper, two case studies are presented which show the action of primary control and secondary control. The load demand at Bus 16 will be increased such that it does not exceed the maximum available generation in one case, and exceeds the maximum available generation in another case. In both cases, the effect of primary and secondary control actions on the frequency of the system will be observed. Generating units C and D will be participating in AGC with participation factors of 0.6 and 0.4 respectively.

The comprehensive power system analysis package ‘MiPower’ has been used to model the network, including the AGC control system block, and to perform load flow and transient stability studies for each case study.

Fig. 2. Typical two area system simulated in MiPower


III. AGC DESIGN

Design and tuning of the AGC is a very important part of frequency control. While designing the AGC, appropriate values need to be selected to get the desired output.

A. Selection of integrator gain ‘K’

The ACE obtained from the sum of errors in frequency and tie-line flows is passed through an integrator prior to the generation allocation logic. The integrator gain must be selected properly to achieve the desired response with less oscillations and minimum settling time. Fig.3 shows the frequency response for different values of integrator gain ‘K’.

Fig. 3. Frequency response under loading less than max generation limit with different values of integrator gain

For a value of K = 0.01, the response shown is too slow to achieve the desired frequency. When K is increased to 0.05, faster response is achieved. On further increase of K to 0.08, the system is able to achieve the desired frequency, albeit with the presence of small oscillations. At K = 0.24, the oscillations are completely damped in the least settling time. If the gain is further increased, peak overshoots may be observed. For K = 0.5, an overshoot peak is present, which settles down in few seconds. So, in this case, the optimal value of K = 0.24 achieves the desired frequency of 50Hz with the least settling time and minimum oscillations.

Fig. 4. Frequency response under loading beyond the max generation limit with different values of integrator gain

In the second case, where the load is increased beyond the available spinning reserve, the desired frequency of 50Hz is not achieved and the possibility of minimizing the ACE is less. Hence, for different values of K, the responses obtained

are similar, with the exception of the slower response observed for K = 0.01.

Fig. 5. ACE response for Case1) Loading less than maximum generation limit. Case 2) Loading beyond than maximum generation limit

The behavior of ACE in the two cases can be observed in Fig.5. In the first case, the ACE has reduced to zero whereas in the second some error still persists in the system.

B. Desired Power calculation

The second section of AGC is the ‘Generation Allocation Logic’. In this section, the difference of the post-integration error and the total generation obtained will be provided to all the participating generators in the ratio of their participation factors (pf). In this case, units C and D will have participation factors of 0.6 and 0.4 respectively. The sum of participation factors for any number of generators considered will always be unity. This indicates that 60% of the error signal will be passed to unit C and the remaining 40% will be passed to unit D. For each generator, the difference of the obtained output and the base power of the generator is computed. This difference is actually the continuous reference power input provided to the governor of the generator. Before being passed to the governor, the continuous signal is converted to a pulsating signal in the final section of the AGC.

C. Pulse application:

The continuous signal obtained in the previous section must not be directly passed to the governor, as the connected turbine system and the associated valve controller has a high time constant, typical of mechanical bodies which cannot act as fast as electrical machines. Hence, the continuous signal is converted into a pulsating signal. This pulsating signal will hold a particular value for a defined pulse time, following which the value becomes zero for a very brief duration till the next pulse begins. This way, the governor gets sufficient time to stabilize the frequency with the obtained reference power signal, which is kept constant for the duration of each pulse. The pulsating signal is generated through a sine wave generator, as shown in Fig. 6.

Fig. 6. Reference pulse generator block diagram


Fig. 7. Pulse waveforms of different stages of pulse generator

A sine wave at a particular frequency is passed through the Zero Crossing Detector (ZCD). At the zero crossing point of the sine wave, an impulse signal with unit magnitude will be generated and passed through a ‘NOT’ gate whose output will be zero at the zero crossing point. This unit step pulse holds the instantaneous value of continuous signal where it matches with zero crossing point12]. Fig. 7 clearly illustrates the final reference pulse for the Sample/Hold (S/H) circuit, where a sine wave with a time period of 8s has been generated. At every 4th second till the simulation time period, a unit impulse will be generated at the output of the ZCD. Thus, for a total duration of 20s (2.5 cycles), 5 pulses have been generated. The inputs to the S/H circuit are the continuous signal and the pulse signal.

During each pulse, the instantaneous value of the continuous signal will be held till the next zero crossing. Fig. 8 shows the block diagram for the generation of pulsating signal from the continuous input.

Fig. 8. Continuous input and pulsating signal for loading less than maximum generation limit.

In Fig. 9, both the continuous signal and the pulsating signal can be observed for both generating units

participating in AGC. Initially, a sudden change of load causes a lot of changes in . Once the system frequency begins to settle near the desired value, both curves begin to overlap each other.

In the second case, where the load is increased beyond the available generation, the ACE is greater. After the disturbance, the continuous signal for both units is

observed to be oscillatory. In response to this input, the output pulsating signal is also oscillatory in nature. This shows that the control system output along with the governor, attempts to settle the frequency at some point in order to minimize the ACE. However, at any given instant, the ACE cannot be completely nullified due to unavailability of sufficient generation in the system. In Fig. 10, both the continuous signal and the pulsating signal for both generating units are observed to be oscillating with decreasing amplitude for a simulation time of 200s. So, as the ACE still persists, the system is able to settle at a new frequency of 49.8Hz instead of the nominal value of 50Hz.

Fig. 9. Continuous input and pulsating signal for loading beyond the maximum generation limit.

IV. RESULTS

A. Loading less than maximum generation limit

In this case, the initial load of 500 MW at Bus 16 is increased to 900MW. When the load increases, the frequency suddenly dips due to the generator droop action. Due to the mismatch in reference frequency and actual system frequency, the primary control action i.e. turbine-governing system starts acting. The primary control increases the gate opening to a certain limit, providing more steam input, which in turn causes the frequency to rise. In Fig. 10, the graph for the condition without AGC shows only the primary action where, after the load is changed, the frequency dips to 49.3Hz from the nominal value of 50Hz.

Fig. 10. Frequency response with and without AGC under loading less than maximum generation limit


In the first scenario, the primary control tries to restore the nominal frequency, but it is able to increase the frequency only up to 49.8Hz. This is the major drawback of primary control. So, without AGC, the system is unable to achieve the original system frequency, even though the generators have sufficient spinning reserve to meet the increased load.

In the second scenario, AGC is present in the system as a secondary control. Along with the primary control action, the secondary control action will also act to change the or

as per the ACE and generation allocation logic. This action will increase the scheduled generation of participating generating units and successfully restore the system frequency to the desired value. Initially, a sudden overshoot is observed due to the large error value of ACE, which becomes negligible after a few seconds following which the system achieves the desired frequency.

Fig. 11. Mechanical input to of the unit C and D under loading less than the maximum generation limit.

Fig.11 shows the mechanical power for units C and D with just primary control and primary with secondary control. For unit C, just the primary control was able to increase to 820MW, whereas the combination of primary and secondary control was able to increase to around 1050MW. Similarly, for unit D, of 300MW and 400MW could be achieved for each case.

B. Loading beyond than maximum generation limit

In this case, the initial load of 500 MW at Bus 16 is increased to 1300MW, which is significantly greater than the maximum spinning reserve. Due to this large change, the frequency suddenly dips to a low value of 48.3Hz.

In the first scenario, with just the primary control action, the frequency can be increased up to a value of 49.3Hz only, though there is some amount of leftover spinning reserve.

In the second scenario, the combination of primary control and secondary control (AGC) enables full utilization of the available spinning reserve in order to meet the higher load demand and improve the frequency to 49.7Hz. However, the desired frequency cannot be obtained due to the large disparity between demand and available generation. The frequency response for both the scenarios can be observed in Fig 12.

Fig. 12. Frequency response with and without AGC under loading beyond the maximum generation limit

Fig. 13. Mechanical input to of the unit C and D under loading beyond the maximum generation limit.

Fig. 13 shows the mechanical power for units C and D with just primary control and primary with secondary control. For unit C, just the primary control was able to increase to 1042MW, whereas the combination of primary and secondary control was able to increase to around 1050MW. Similarly, for unit D, of 390MW and 460MW could be achieved for each case.

No significant change was observed for unit C since it was already operating near its maximum generation limit. In the case of unit D, some spinning reserve remained, which was utilized by the secondary control action.

V. CONCLUSION

The case studies presented in this paper explain the different scenarios occurring in a large system involving tie-lines and inter-area power flow. The power drawal from one area to another should be within a limited range. If one area draws power within the maximum available generation limit, then the system will be able to regain the desired system frequency with the help of AGC. If the power drawal is more than the maximum generation limit, the system will not be able to achieve the desired frequency, but it will be able to achieve some frequency less than it would with the use of AGC. Apart from the effect of AGC on frequency under different loading conditions, the working of AGC has also been explained in detail.


VI. FUTURE WORK

The scope of this work can be extended with the implementation of solar and wind energy in the system. Most of the time, variable frequency is obtained in case of wind where the wind speed keeps on fluctuating. So in that case, the application of a control system is much more required. Solar also varies with the intensity of sunlight as well as clouds covering the sun. Thus sudden loss of generation on the system will lead to dip in frequency. So that scenario can also be showcased along with the proper control to maintain it back to the nominal value of 50Hz.

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Control. New York, NY: Wiley, 1996.

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[3] Q. Liu and M. Ilic, “Enhanced automatic generation control (e-agc) for future electric energy systems,” in IEEE Power and Energy Society General Meeting, 2012, pp. 1–8.

[4] H. Bevrani and T. Hiyamag, Intelligent Automatic Generation Control Taylor and Francis Group, LLC, 2011.

[5] Ross, C. W., “A Comprehensive Direct Digital Load-Frequency Controller,” IEEE Power Industry Computer Applications Conference Proceedings, 1967.

[6] de Mello, F. P., Mills, R. J., B’Rells, W. F., “Automatic Generation Control-Part I: Process Modeling,” IEEE Transactions on Power Apparatus and Systems,Vol. PAS-92, March/April 1973, pp. 710-715.

[7] de Mello, F. P., Mills, R. J., B’Rells, W. F., “Automatic Generation Control-Part II: Digital Control Techniques,” IEEE Transactions on Powder Apparatus and Systems, Vol. PAS-92, March/April 1973, pp. 716-724.

[8] P. W. Sauer and M. A. Pai, Power System Dynamics and Stability . Upper Saddle River, NJ: Prentice Hall, 1998.

[9] IEEE Committee Report, “Dynamic Models for Steam and Hydro Turbines in Power System Studies”, IEEE PES Winter Meeting, New York, Jan./Feb. 1973. (Paper T 73 089-0).

[10] L. Wang and D. Chen, “Extended term dynamic simulation for AGC with smart grids,” in IEEE Power and Energy Society General Meeting, July 2011, pp. 1–7.

[11] H. Chen, R. Ye, X. Wang, R. Lu, "Cooperative Control of Power System Load and Frequency by Using Differential Games", IEEE Transactions on Control Systems Technology, vol. 23, no. 3, pp. 882-897, May 2015.

[12] Ross, C. W., “Error Adaptive Control Computer for Interconnected Power Systems,” IEEE Transactions on Power Apparatus and Systems, Vol. PAS-85, July 1966, pp. 742-149.


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