Tip:
Highlight text to annotate it
X
Let’s look at how ramp rate constraints can affect the Real-time Dispatch schedules.
Each generator has a ramp rate – how quickly it can raise or lower the amount of MW it produces, to meet the exact levels required of it.
Generators provide this information to the System Operator through their energy offers.
The System Operator’s Scheduling, Pricing, and Dispatch tool (SPD) then uses this information in formulating dispatch instructions.
Here's the scenario:
The generator is set to 300 MW at the start of this trading period.
The System Operator’s SPD tool produces Real-time Dispatch solutions every 5 minutes for a 5 minute period.
The offered ramp rate of this particular generator is 10 MW per minute, allowing SPD to increase or decrease the output of the generator by up to 50 MW in the dispatch solutions.
The first dispatch solution produced indicated that the generator is to reduce output by 50 MW to 250 MW.
• The second dispatch solution produced moved the generator’s output down further by another 50 MW to 200 MW.
All remaining dispatch solutions in the 30 minute trading period indicated that no further variation in generation output was required.
The actual generation looks something like this
The System Operator’s SPD tool is used to calculate final prices for billing purposes.
In contrast to Real-time Dispatch solutions where SPD is required to produce dispatch instructions for a 5 minute period,
final pricing requires SPD to produce a single price at each node for every 30 minute trading period.
This allows SPD to produce a solution with the absence of 5 minute ramp rate restrictions.
In this scenario, this would mean SPD could move the generator’s output by up to 300 MW for the 30 minute trading period.
In this case, SPD has optimised the set point for the 30 minute trading period to be 180 MW in final pricing.
There is a clear discrepancy between the final pricing set point of 180 MW, and that produced by SPD for the Real-time Dispatch.
This can occur for a variety of reasons, and often comes down to the difference in data sources used in formulating the different types of schedules.
For example, final pricing uses averaged, actual metered load data, which is often different to the forecasted load figures used by Real-time Dispatch.
Let’s calculate what the Real-time Dispatch set points translate to, in a 30 minute trading period.
To do this, we'll need to find the average dispatch set points, and the average actual generation for the 30 minute trading period.
We can see the average dispatch instructions over the 30 minute trading period is 208 MW and the average actual generation is 217 MW.
In the next animation, we'll look at how the constrained on costs are calculated using this information.