La profesionalización a través de la danza en contextos de diversidad

5.5.1 Interconnectors and British system

Interconnection between the SEM and GB is represented by East West (EWIC) at 500MW for ROI to GB and Moyle at 450MW in winter and 410MW in summer for NI to GB. In Chapters 7 and 8 the interconnector flows are fully fixed on a DA schedule, with the exception of forced outages occurring on the lines. The interconnector flows match the export and import energy from AI

5. MODELINPUTS 5.5 British System data

to GB of 2200GWh and 1500GWh [58] through modification of the GB shadow price. This was considered carefully as interconnector usage has an effect on OCGT usage in the model and was viewed as important to adjust to receive realistic OCGT usage.

The interconnector usage is based on the difference in the price between the AI and GB systems. Therefore adjustment of the interconnector flows is achieved by adjustment of the single GB generator running costs. These adjustments are a more simplified version of what was carried out to achieve the GB generator running costs as shown in [62]. It should be noted that due to the GB shadow price rising at night and lowering during the day the GB generation cost data from [139] was not used and the GB generation cost data from [158] was used instead. This GB generation cost data is made up of heat rates, variable operation and maintenance (VOM) charges and a GB gas fuel price.

Adjustment of the interconnector flows was manually achieved by two

adjustable variables and was carried across all scenarios unchanged. First, the variations that occur over the year were separated from the summer and winter average year running costs. The variations in the costs over the year control the quantity of net flow on the interconnectors, therefore the larger the variations of the GB price, the larger, the net flows on the interconnectors.

Secondly, the average winter and summer running costs to the year are adjusted proportionally to achieve the correct import-export ratio but this also has an effect on net flow over the interconnecter. The higher the average GB price the more frequently GB will import from AI. The “wheeling charges back” that are present in [158] are ignored as it is assumed by 2020 that interconnector flow will transfer with equal ease in both directions. In place of this a flat wheeling charge of ¤2/MWh is introduced in both directions.

Therefore the end result of the modifications to GB price is an adjustment of the variability of the price and summer/winter average prices however keeping the six intervals per day and summer/winter variations of the original data in proportion to each other as in [158].

The GB system demand for 2020 was developed from 2011 GB data taken from the National Grid website³. The 2011 30 minute GB system demand time-series, from a peak demand of 55.11GW and total energy requirement (TER) of 308.3TWh was manipulated to achieve a peak demand of 61.00GW

3http://www.nationalgrid.com/uk/Electricity/Data/Demand+Data/

Investigation of factors driving the costs of operating the 2020 Irish power system with large-scale wind generation.

95 Edward V. Mc Garrigle

5.5.2 British system non-synchronous penetration limit

A constraint was placed on the GB region consisting of an SNSP limit of 70%.

This limit was assumed as no reference has been found on this particular issue for GB. However due to GB’s large nuclear fleet it is assumed that there must be a limit on instantaneous renewable energy penetration on the GB system [17]. This was to more realistically deter or even prevent imports to GB from the SEM in times of GB high wind generation on the GB system. This results in times where the interconnectors cannot be used preventing exports from SEM and resulting in additional wind curtailment in SEM.

A step change that could occur between the GB SNSP limit of 70% being reached or not, which could result in oscillation on the interconnectors occurring where full interconnector export would be available during one simulation step followed by no availability on the next and again available following this. This resulted in 950MW of exports oscillation on or off during the certain times. This was mitigated by averaging the availability of the interconnector over four hours and the removal of any point values of on or off. This issue also contributed to the generator oscillation problems

discussed in Section 4.7.4 due to the correlation of wind energy output that exists between AI and GB as shown in Section 5.4.2.

Chapter 6

How much wind energy will be curtailed on the 2020 Irish power system?

NB: it should be noted that there has been a terminology change from the publication of this paper and submission of this thesis. The term

Transmission Constraints Groups (TCGs) used in this Chapter is the same as the System Operational Constraints (SOCs) used in the rest of the document.

6.1 Abstract

This paper describes a model of the 2020 Irish electricity system which was developed and solved in a mixed integer programming, unit commitment and economic dispatch tool called PLEXOS®. The model includes all generators on the island of Ireland, a simplified representation of the neighbouring British system including proposed wind capacity and

interconnectors between the two systems. The level of wind curtailment is determined under varying levels of three influencing factors. The first factor is the amount of offshore wind, the second is the allowed limit of system non-synchronous penetration (SNSP) and the third is inclusion or exclusion of transmission constraints. A binding constraint, resulting from the 2020 EU renewable energy targets, is that 37% of generation comes from wind. When the SNSP limit was increased from 60% to 75% there was a reduction in wind curtailment from 14% to 7%, with a further reduction if the proportion of

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wind capacity installed offshore is increased. Wind curtailment in the range of SNSP limit of 70-100% is influenced primarily by the inclusion of

transmission constraints. Large changes in the dispatch of conventional generators were also evident due to the imposition of SNSP limits and transmission constraints.