Power Systems

This tutorial was generated using Literate.jl. Download the source as a .jl file.

This tutorial was originally contributed by Yury Dvorkin and Miles Lubin.

This tutorial demonstrates how to formulate basic power systems engineering models in JuMP.

We will consider basic "economic dispatch" and "unit commitment" models without taking into account transmission constraints.

For this tutorial, we use the following packages:

using JuMP
import DataFrames
import HiGHS
import Plots
import StatsPlots

Economic dispatch

Economic dispatch (ED) is an optimization problem that minimizes the cost of supplying energy demand subject to operational constraints on power system assets. In its simplest modification, ED is an LP problem solved for an aggregated load and wind forecast and for a single infinitesimal moment.

Mathematically, the ED problem can be written as follows:

$$$\min \sum_{i \in I} c^g_{i} \cdot g_{i} + c^w \cdot w,$$$

where $c_{i}$ and $g_{i}$ are the incremental cost ($/MWh) and power output (MW) of the$i^{th}$generator, respectively, and$c^w$and$w$are the incremental cost ($/MWh) and wind power injection (MW), respectively.

Subject to the constraints:

• Minimum ($g^{\min}$) and maximum ($g^{\max}$) limits on power outputs of generators: $g^{\min}_{i} \leq g_{i} \leq g^{\max}_{i}.$
• Constraint on the wind power injection: $0 \leq w \leq w^f,$ where $w$ and $w^f$ are the wind power injection and wind power forecast, respectively.
• Power balance constraint: $\sum_{i \in I} g_{i} + w = d^f,$ where $d^f$ is the demand forecast.

Further reading on ED models can be found in A. J. Wood, B. F. Wollenberg, and G. B. Sheblé, "Power Generation, Operation and Control," Wiley, 2013.

Define some input data about the test system.

We define some thermal generators:

function ThermalGenerator(
min::Float64,
max::Float64,
fixed_cost::Float64,
variable_cost::Float64,
)
return (
min = min,
max = max,
fixed_cost = fixed_cost,
variable_cost = variable_cost,
)
end

generators = [
ThermalGenerator(0.0, 1000.0, 1000.0, 50.0),
ThermalGenerator(300.0, 1000.0, 0.0, 100.0),
]
2-element Vector{@NamedTuple{min::Float64, max::Float64, fixed_cost::Float64, variable_cost::Float64}}:
(min = 0.0, max = 1000.0, fixed_cost = 1000.0, variable_cost = 50.0)
(min = 300.0, max = 1000.0, fixed_cost = 0.0, variable_cost = 100.0)

A wind generator

WindGenerator(variable_cost::Float64) = (variable_cost = variable_cost,)

wind_generator = WindGenerator(50.0)
(variable_cost = 50.0,)

And a scenario

function Scenario(demand::Float64, wind::Float64)
return (demand = demand, wind = wind)
end

scenario = Scenario(1500.0, 200.0)
(demand = 1500.0, wind = 200.0)

Create a function solve_economic_dispatch, which solves the economic dispatch problem for a given set of input parameters.

function solve_economic_dispatch(generators::Vector, wind, scenario)
# Define the economic dispatch (ED) model
model = Model(HiGHS.Optimizer)
set_silent(model)
# Define decision variables
# power output of generators
N = length(generators)
@variable(model, generators[i].min <= g[i = 1:N] <= generators[i].max)
# wind power injection
@variable(model, 0 <= w <= scenario.wind)
# Define the objective function
@objective(
model,
Min,
sum(generators[i].variable_cost * g[i] for i in 1:N) +
wind.variable_cost * w,
)
# Define the power balance constraint
@constraint(model, sum(g[i] for i in 1:N) + w == scenario.demand)
# Solve statement
optimize!(model)
@assert is_solved_and_feasible(model)
# return the optimal value of the objective function and its minimizers
return (
g = value.(g),
w = value(w),
wind_spill = scenario.wind - value(w),
total_cost = objective_value(model),
)
end
solve_economic_dispatch (generic function with 1 method)

Solve the economic dispatch problem

solution = solve_economic_dispatch(generators, wind_generator, scenario);

println("Dispatch of Generators: ", solution.g, " MW")
println("Dispatch of Wind: ", solution.w, " MW")
println("Wind spillage: ", solution.wind_spill, " MW")
println("Total cost: \$", solution.total_cost) Dispatch of Generators: [1000.0, 300.0] MW Dispatch of Wind: 200.0 MW Wind spillage: 0.0 MW Total cost:$90000.0

Economic dispatch with adjustable incremental costs

In the following exercise we adjust the incremental cost of generator G1 and observe its impact on the total cost.

function scale_generator_cost(g, scale)
return ThermalGenerator(g.min, g.max, g.fixed_cost, scale * g.variable_cost)
end

start = time()
c_g_scale_df = DataFrames.DataFrame(;
# Scale factor
scale = Float64[],
# Dispatch of Generator 1 [MW]
dispatch_G1 = Float64[],
# Dispatch of Generator 2 [MW]
dispatch_G2 = Float64[],
# Dispatch of Wind [MW]
dispatch_wind = Float64[],
# Spillage of Wind [MW]
spillage_wind = Float64[],
# Total cost [$] total_cost = Float64[], ) for c_g1_scale in 0.5:0.1:3.0 # Update the incremental cost of the first generator at every iteration. new_generators = scale_generator_cost.(generators, [c_g1_scale, 1.0]) # Solve the economic-dispatch problem with the updated incremental cost sol = solve_economic_dispatch(new_generators, wind_generator, scenario) push!( c_g_scale_df, (c_g1_scale, sol.g[1], sol.g[2], sol.w, sol.wind_spill, sol.total_cost), ) end print(string("elapsed time: ", time() - start, " seconds")) elapsed time: 0.16880106925964355 seconds c_g_scale_df 26×6 DataFrame Rowscaledispatch_G1dispatch_G2dispatch_windspillage_windtotal_cost Float64Float64Float64Float64Float64Float64 10.51000.0300.0200.00.065000.0 20.61000.0300.0200.00.070000.0 30.71000.0300.0200.00.075000.0 40.81000.0300.0200.00.080000.0 50.91000.0300.0200.00.085000.0 61.01000.0300.0200.00.090000.0 71.11000.0300.0200.00.095000.0 81.21000.0300.0200.00.0100000.0 91.31000.0300.0200.00.0105000.0 101.41000.0300.0200.00.0110000.0 111.51000.0300.0200.00.0115000.0 121.61000.0300.0200.00.0120000.0 131.71000.0300.0200.00.0125000.0 141.81000.0300.0200.00.0130000.0 151.91000.0300.0200.00.0135000.0 162.0300.01000.0200.00.0140000.0 172.1300.01000.0200.00.0141500.0 182.2300.01000.0200.00.0143000.0 192.3300.01000.0200.00.0144500.0 202.4300.01000.0200.00.0146000.0 212.5300.01000.0200.00.0147500.0 222.6300.01000.0200.00.0149000.0 232.7300.01000.0200.00.0150500.0 242.8300.01000.0200.00.0152000.0 252.9300.01000.0200.00.0153500.0 263.0300.01000.0200.00.0155000.0 Modifying the JuMP model in-place Note that in the previous exercise we entirely rebuilt the optimization model at every iteration of the internal loop, which incurs an additional computational burden. This burden can be alleviated if instead of re-building the entire model, we modify the constraints or objective function, as it shown in the example below. Compare the computing time in case of the above and below models. function solve_economic_dispatch_inplace( generators::Vector, wind, scenario, scale::AbstractVector{Float64}, ) obj_out = Float64[] w_out = Float64[] g1_out = Float64[] g2_out = Float64[] # This function only works for two generators @assert length(generators) == 2 model = Model(HiGHS.Optimizer) set_silent(model) N = length(generators) @variable(model, generators[i].min <= g[i = 1:N] <= generators[i].max) @variable(model, 0 <= w <= scenario.wind) @objective( model, Min, sum(generators[i].variable_cost * g[i] for i in 1:N) + wind.variable_cost * w, ) @constraint(model, sum(g[i] for i in 1:N) + w == scenario.demand) for c_g1_scale in scale @objective( model, Min, c_g1_scale * generators[1].variable_cost * g[1] + generators[2].variable_cost * g[2] + wind.variable_cost * w, ) optimize!(model) @assert is_solved_and_feasible(model) push!(obj_out, objective_value(model)) push!(w_out, value(w)) push!(g1_out, value(g[1])) push!(g2_out, value(g[2])) end df = DataFrames.DataFrame(; scale = scale, dispatch_G1 = g1_out, dispatch_G2 = g2_out, dispatch_wind = w_out, spillage_wind = scenario.wind .- w_out, total_cost = obj_out, ) return df end start = time() inplace_df = solve_economic_dispatch_inplace( generators, wind_generator, scenario, 0.5:0.1:3.0, ) print(string("elapsed time: ", time() - start, " seconds")) elapsed time: 0.16114115715026855 seconds For small models, adjusting specific constraints or the objective function is sometimes faster and sometimes slower than re-building the entire model. However, as the problem size increases, updating the model in-place is usually faster. inplace_df 26×6 DataFrame Rowscaledispatch_G1dispatch_G2dispatch_windspillage_windtotal_cost Float64Float64Float64Float64Float64Float64 10.51000.0300.0200.00.065000.0 20.61000.0300.0200.00.070000.0 30.71000.0300.0200.00.075000.0 40.81000.0300.0200.00.080000.0 50.91000.0300.0200.00.085000.0 61.01000.0300.0200.00.090000.0 71.11000.0300.0200.00.095000.0 81.21000.0300.0200.00.0100000.0 91.31000.0300.0200.00.0105000.0 101.41000.0300.0200.00.0110000.0 111.51000.0300.0200.00.0115000.0 121.61000.0300.0200.00.0120000.0 131.71000.0300.0200.00.0125000.0 141.81000.0300.0200.00.0130000.0 151.91000.0300.0200.00.0135000.0 162.01000.0300.0200.00.0140000.0 172.1300.01000.0200.00.0141500.0 182.2300.01000.0200.00.0143000.0 192.3300.01000.0200.00.0144500.0 202.4300.01000.0200.00.0146000.0 212.5300.01000.0200.00.0147500.0 222.6300.01000.0200.00.0149000.0 232.7300.01000.0200.00.0150500.0 242.8300.01000.0200.00.0152000.0 252.9300.01000.0200.00.0153500.0 263.0300.01000.0200.00.0155000.0 Inefficient usage of wind generators The economic dispatch problem does not perform commitment decisions and, thus, assumes that all generators must be dispatched at least at their minimum power output limit. This approach is not cost efficient and may lead to absurd decisions. For example, if$d = \sum_{i \in I} g^{\min}_{i}$, the wind power injection must be zero, that is, all available wind generation is spilled, to meet the minimum power output constraints on generators. In the following example, we adjust the total demand and observed how it affects wind spillage. demand_scale_df = DataFrames.DataFrame(; demand = Float64[], dispatch_G1 = Float64[], dispatch_G2 = Float64[], dispatch_wind = Float64[], spillage_wind = Float64[], total_cost = Float64[], ) function scale_demand(scenario, scale) return Scenario(scale * scenario.demand, scenario.wind) end for demand_scale in 0.2:0.1:1.4 new_scenario = scale_demand(scenario, demand_scale) sol = solve_economic_dispatch(generators, wind_generator, new_scenario) push!( demand_scale_df, ( new_scenario.demand, sol.g[1], sol.g[2], sol.w, sol.wind_spill, sol.total_cost, ), ) end demand_scale_df 13×6 DataFrame Rowdemanddispatch_G1dispatch_G2dispatch_windspillage_windtotal_cost Float64Float64Float64Float64Float64Float64 1300.00.0300.00.0200.030000.0 2450.0150.0300.00.0200.037500.0 3600.0300.0300.00.0200.045000.0 4750.0450.0300.00.0200.052500.0 5900.0600.0300.00.0200.060000.0 61050.0750.0300.00.0200.067500.0 71200.0900.0300.00.0200.075000.0 81350.0850.0300.0200.00.082500.0 91500.01000.0300.0200.00.090000.0 101650.01000.0450.0200.00.0105000.0 111800.01000.0600.0200.00.0120000.0 121950.01000.0750.0200.00.0135000.0 132100.01000.0900.0200.00.0150000.0 dispatch_plot = StatsPlots.@df( demand_scale_df, Plots.plot( :demand, [:dispatch_G1, :dispatch_G2], labels = ["G1" "G2"], title = "Thermal Dispatch", legend = :bottomright, linewidth = 3, xlabel = "Demand", ylabel = "Dispatch [MW]", ), ) wind_plot = StatsPlots.@df( demand_scale_df, Plots.plot( :demand, [:dispatch_wind, :spillage_wind], labels = ["Dispatch" "Spillage"], title = "Wind", legend = :bottomright, linewidth = 3, xlabel = "Demand [MW]", ylabel = "Energy [MW]", ), ) Plots.plot(dispatch_plot, wind_plot) This particular drawback can be overcome by introducing binary decisions on the "on/off" status of generators. This model is called unit commitment and considered later in these notes. For further reading on the interplay between wind generation and the minimum power output constraints of generators, we refer interested readers to R. Baldick, "Wind and energy markets: a case study of Texas," IEEE Systems Journal, vol. 6, pp. 27-34, 2012. Unit commitment The Unit Commitment (UC) model can be obtained from ED model by introducing binary variable associated with each generator. This binary variable can attain two values: if it is "1," the generator is synchronized and, thus, can be dispatched, otherwise, that is, if the binary variable is "0," that generator is not synchronized and its power output is set to 0. To obtain the mathematical formulation of the UC model, we will modify the constraints of the ED model as follows: $$$g^{\min}_{i} \cdot u_{t,i} \leq g_{i} \leq g^{\max}_{i} \cdot u_{t,i},$$$ where$u_{i} \in \{0,1\}.$In this constraint, if$u_{i} = 0$, then$g_{i} = 0$. On the other hand, if$u_{i} = 1$, then$g^{min}_{i} \leq g_{i} \leq g^{max}_{i}$. For further reading on the UC problem we refer interested readers to G. Morales-Espana, J. M. Latorre, and A. Ramos, "Tight and Compact MILP Formulation for the Thermal Unit Commitment Problem," IEEE Transactions on Power Systems, vol. 28, pp. 4897-4908, 2013. In the following example we convert the ED model explained above to the UC model. function solve_unit_commitment(generators::Vector, wind, scenario) model = Model(HiGHS.Optimizer) set_silent(model) N = length(generators) @variable(model, 0 <= g[i = 1:N] <= generators[i].max) @variable(model, 0 <= w <= scenario.wind) @constraint(model, sum(g[i] for i in 1:N) + w == scenario.demand) # !!! New: add binary on-off variables for each generator @variable(model, u[i = 1:N], Bin) @constraint(model, [i = 1:N], g[i] <= generators[i].max * u[i]) @constraint(model, [i = 1:N], g[i] >= generators[i].min * u[i]) @objective( model, Min, sum(generators[i].variable_cost * g[i] for i in 1:N) + wind.variable_cost * w + # !!! new sum(generators[i].fixed_cost * u[i] for i in 1:N) ) optimize!(model) status = termination_status(model) if status != OPTIMAL return (status = status,) end @assert primal_status(model) == FEASIBLE_POINT return ( status = status, g = value.(g), w = value(w), wind_spill = scenario.wind - value(w), u = value.(u), total_cost = objective_value(model), ) end solve_unit_commitment (generic function with 1 method) Solve the unit commitment problem solution = solve_unit_commitment(generators, wind_generator, scenario) println("Dispatch of Generators: ", solution.g, " MW") println("Commitments of Generators: ", solution.u) println("Dispatch of Wind: ", solution.w, " MW") println("Wind spillage: ", solution.wind_spill, " MW") println("Total cost: \$", solution.total_cost)
Dispatch of Generators: [1000.0, 300.0] MW
Commitments of Generators: [1.0, 1.0]
Dispatch of Wind: 200.0 MW
Wind spillage: 0.0 MW
Total cost: $91000.0 Unit commitment as a function of demand After implementing the unit commitment model, we can now assess the interplay between the minimum power output constraints on generators and wind generation. uc_df = DataFrames.DataFrame(; demand = Float64[], commitment_G1 = Float64[], commitment_G2 = Float64[], dispatch_G1 = Float64[], dispatch_G2 = Float64[], dispatch_wind = Float64[], spillage_wind = Float64[], total_cost = Float64[], ) for demand_scale in 0.2:0.1:1.4 new_scenario = scale_demand(scenario, demand_scale) sol = solve_unit_commitment(generators, wind_generator, new_scenario) if sol.status == OPTIMAL push!( uc_df, ( new_scenario.demand, sol.u[1], sol.u[2], sol.g[1], sol.g[2], sol.w, sol.wind_spill, sol.total_cost, ), ) end println("Status:$(sol.status) for demand_scale = \$(demand_scale)")
end
Status: OPTIMAL for demand_scale = 0.2
Status: OPTIMAL for demand_scale = 0.3
Status: OPTIMAL for demand_scale = 0.4
Status: OPTIMAL for demand_scale = 0.5
Status: OPTIMAL for demand_scale = 0.6
Status: OPTIMAL for demand_scale = 0.7
Status: OPTIMAL for demand_scale = 0.8
Status: OPTIMAL for demand_scale = 0.9
Status: OPTIMAL for demand_scale = 1.0
Status: OPTIMAL for demand_scale = 1.1
Status: OPTIMAL for demand_scale = 1.2
Status: OPTIMAL for demand_scale = 1.3
Status: OPTIMAL for demand_scale = 1.4
uc_df
13×8 DataFrame
Rowdemandcommitment_G1commitment_G2dispatch_G1dispatch_G2dispatch_windspillage_windtotal_cost
Float64Float64Float64Float64Float64Float64Float64Float64
1300.01.00.0100.00.0200.00.016000.0
2450.01.00.0250.00.0200.00.023500.0
3600.01.00.0400.00.0200.00.031000.0
4750.01.00.0550.00.0200.00.038500.0
5900.01.00.0700.00.0200.00.046000.0
61050.01.00.0850.00.0200.00.053500.0
71200.01.00.01000.00.0200.00.061000.0
81350.01.01.0850.0300.0200.00.083500.0
91500.01.01.01000.0300.0200.00.091000.0
101650.01.01.01000.0450.0200.00.0106000.0
111800.01.01.01000.0600.0200.00.0121000.0
121950.01.01.01000.0750.0200.00.0136000.0
132100.01.01.01000.0900.0200.00.0151000.0
commitment_plot = StatsPlots.@df(
uc_df,
Plots.plot(
:demand,
[:commitment_G1, :commitment_G2],
labels = ["G1" "G2"],
title = "Commitment",
legend = :bottomright,
linewidth = 3,
xlabel = "Demand [MW]",
ylabel = "Commitment decision {0, 1}",
),
)

dispatch_plot = StatsPlots.@df(
uc_df,
Plots.plot(
:demand,
[:dispatch_G1, :dispatch_G2, :dispatch_wind],
labels = ["G1" "G2" "Wind"],
title = "Dispatch [MW]",
legend = :bottomright,
linewidth = 3,
xlabel = "Demand",
ylabel = "Dispatch [MW]",
),
)

Plots.plot(commitment_plot, dispatch_plot)

Nonlinear economic dispatch

As a final example, we modify our economic dispatch problem in two ways:

• The thermal cost function is user-defined
• The output of the wind is only the square-root of the dispatch
import Ipopt

"""
thermal_cost_function(g)

A user-defined thermal cost function in pure-Julia! You can include
nonlinearities, and even things like control flow.

!!! warning
It's still up to you to make sure that the function has a meaningful
derivative.
"""
function thermal_cost_function(g)
if g <= 500
return g
else
return g + 1e-2 * (g - 500)^2
end
end

function solve_nonlinear_economic_dispatch(
generators::Vector,
wind,
scenario;
silent::Bool = false,
)
model = Model(Ipopt.Optimizer)
if silent
set_silent(model)
end
@operator(model, op_tcf, 1, thermal_cost_function)
N = length(generators)
@variable(model, generators[i].min <= g[i = 1:N] <= generators[i].max)
@variable(model, 0 <= w <= scenario.wind)
@objective(
model,
Min,
sum(generators[i].variable_cost * op_tcf(g[i]) for i in 1:N) +
wind.variable_cost * w,
)
@constraint(model, sum(g[i] for i in 1:N) + sqrt(w) == scenario.demand)
optimize!(model)
@assert is_solved_and_feasible(model)
return (
g = value.(g),
w = value(w),
wind_spill = scenario.wind - value(w),
total_cost = objective_value(model),
)
end

solution =
solve_nonlinear_economic_dispatch(generators, wind_generator, scenario)
(g = [847.3509933774712, 648.6754966887423], w = 15.788781193899027, wind_spill = 184.211218806101, total_cost = 190455.298013245)

Now let's see how the wind is dispatched as a function of the cost:

wind_cost = 0.0:1:100
wind_dispatch = Float64[]
for c in wind_cost
sol = solve_nonlinear_economic_dispatch(
generators,
WindGenerator(c),
scenario;
silent = true,
)
push!(wind_dispatch, sol.w)
end

Plots.plot(
wind_cost,
wind_dispatch;
xlabel = "Cost",
ylabel = "Dispatch [MW]",
label = false,
)