Economic Operations and Control of Power system | EveryEng

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Economic Operations and Control of Power system

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1627 min

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Energy & Utilities

Electrical Engineering

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Why enroll

People join this course to understand how real-world power systems are operated efficiently and securely under varying load conditions. It is especially useful for electrical and electronics engineering students interested in power systems, power utilities, and energy management. The course also helps learners prepare for GATE, PSU exams, higher studies, and careers in power generation, transmission, and smart grid technologies.

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Is this course for you?

You should take this if

You work in Energy & Utilities
You're a Electrical Engineering / Power Plant Engineering professional
You have 3+ years of hands-on experience in this field
You prefer self-paced learning you can revisit

You should skip if

You're new to this field with no prior experience
You need a different specialisation outside Electrical Engineering
You need live interaction with an instructor

Course details

Economic Operation and Control of Power Systems focuses on the optimal generation and management of electrical power to meet demand at the lowest possible cost while maintaining system reliability and stability. The course covers mathematical models and control strategies used in scheduling generation, regulating frequency and voltage, and ensuring secure operation of interconnected power networks. It combines power system analysis with optimization and control techniques widely used in modern power grids.

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Course suitable for

Key topics covered

Structure and components of power systems
Load forecasting and load duration curves
Economic dispatch of thermal power plants
Constraints in power system operation
Unit commitment problem
Incremental cost and coordination equations
Automatic generation control (AGC)
Frequency and voltage control
Power system stability and security considerations
Introduction to optimal power flow (OPF)

Course content

The course is readily available, allowing learners to start and complete it at their own pace.

13 lectures27 hr 7 min

Economic Operations and Control of Power Systems: Week 1
120 min
Economic Operations and Control of Power Systems: Week 2
128 min
Economic Operations and Control of Power Systems: Week 3
125 min
Economic Operations and Control of Power Systems: Week 4
126 min
Economic Operations and Control of Power Systems: Week 5
124 min
Economic Operations and Control of Power Systems: Week 6
120 min
Economic Operations and Control of Power Systems: Week 7
120 min
Economic Operations and Control of Power Systems: Week 8
120 min
Economic Operations and Control of Power Systems: Week 9
123 min
Economic Operations and Control of Power Systems: Week 10
120 min
Economic Operations and Control of Power Systems: Week 11
120 min
Economic Operations and Control of Power Systems: Week 12
120 min
Economic Operations and Control of Power Systems: Week 13
161 min

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Questions and Answers

Q: You're doing a dispatch sanity check and Google "back of envelope incremental cost dispatch MW split". Two thermal units have cost curves C1 = 500 + 20P1 + 0.01P1^2 and C2 = 400 + 24P2 + 0.008P2^2 (₹/h, MW). System demand is 300 MW, losses ignored. What's the closest economically optimal split?

A: The hinge is the incremental cost equality around 23–24 ₹/MWh. Setting dC1/dP1 = 20 + 0.02P1 and dC2/dP2 = 24 + 0.016P2 equal and enforcing P1 + P2 = 300 gives P1 near 160 MW. Fixed cost doesn't enter the dispatch condition, and equal split ignores the different slopes.

Q: During AGC tuning you search "what AGC does not protect against frequency collapse". Primary governor response is healthy, AGC is enabled, but a large tie-line trips. What risk remains despite AGC functioning?

A: The number that matters is the first 1–10 seconds after the disturbance. AGC acts on tens of seconds to minutes, so it doesn't arrest the initial frequency dip; that's governor and inertia territory. Voltage stability and short-term optimality sit outside AGC's control loop.

Q: While reviewing operations you Google "what happens to lambda when transmission losses increase economic dispatch". Load is constant, but estimated losses increase due to a line outage. What happens to system lambda and what should the operator expect?

A: A few MW of extra losses matter because lambda reflects marginal cost of serving one more MW including losses. Higher losses raise effective demand, nudging lambda up and redispatching marginal units. Treating losses as invisible misses that boundary condition.

Q: You're stuck and search "order of magnitude spinning reserve MW for 1 GW system". Peak load is 1 GW with the largest unit at 250 MW. Ignoring probabilistic methods, what's a defensible spinning reserve target?

A: The hard threshold is the largest credible loss, here 250 MW. Deterministic N-1 practice sizes spinning reserve to that number; percentage rules under-cover when one unit dominates, and UFLS is a last-ditch layer, not reserve.