🇮🇪
Bengt J. Olsson
X: @bengtxyz
LinkedIn: beos
How can an island like Ireland reach net-zero by 2050? In the modelling here, two distinct pathways
are presented – one fully renewable, and one with a significant nuclear share.
Ireland is a particularly interesting case for energy system modelling. As an island, it requires a high degree of self-sufficiency in its energy supply. At the same time, interconnection capacity is being expanded: the new Celtic Interconnector to France, together with the existing Moyle and EWIC links, will bring total interconnector capacity to about 1.7 GW.
The main domestic power sources considered for Ireland are onshore and offshore wind, solar, gas, and biomass. While gas and biomass both carry climate impacts and relatively high costs, they are included in this study for completeness. Nuclear power at different cost levels is also tested as part of the scenario set.
The model itself is a slightly adapted version of the sector-coupled framework described in this post. Ireland is represented as a one-node (“copper-plate”) system with three interacting sectors: Power, Hydrogen, and Heat. Power generation data for 2023–2024 was obtained from EirGrid (for All Ireland, including Northern Ireland) to build realistic dispatch profiles. For offshore wind, German offshore wind production data over the same period was used as a proxy, since Irish offshore statistics are not yet available.
(Jump to summary)
The resulting model looks like this:
The 2050 target system is inspired by the MaREI model (see Figure 6 in this report), but with a number of modifications. The assumed final energy consumption is structured as follows:
- Power demand:
Current electricity consumption of about 40 TWh is increased by an additional 20 TWh for transport electrification and 10 TWh for general demand growth (data centers, industrial processes, etc.). In the model, this additional 30 TWh is represented as a fixed load addition of 3.4 GW. - Hydrogen demand:
A demand of 20 TWh (LHV) hydrogen is assumed for the Power-to-X sector. In addition, further hydrogen can be produced for power generation in hydrogen turbines if this proves economical within the optimization. - Heat demand:
Approximately 35 TWh of current gas and oil heating is assumed to be converted to electrified heating and district heating. Of this, 20 % is allocated to district heating and 80 % to direct electrification with heat pumps (COP = 3). The demand profile was extracted from hourly temperature data for Ireland for the period.
Combined Heat and Power (CHP) plants are assumed to be biomass-fueled. Gas turbines are modeled with Carbon Capture and Storage (CCS), achieving 90 % CO₂ removal. The effective fuel cost for these plants is set at 80 EUR/MWh of produced electricity, consisting of a methane price of 30 EUR/MWh and an assumed 20 EUR/MWh CO₂ ETS cost. CHP has 50% efficiency for heat and 35% for power.
Nuclear power has a production profile with lower production in th summer due to revisions then, and occasional failure dips. Nuclear can slowly load-follow(6h/unit power), but only down to 50% of the peak capacity. The profile has a 86.7% capacity factor, but this factor will decrease to around 79.5% with nuclear load following.
Results and discussion
The image below illustrates the overall energy flows within and across the sectors.
70 TWh are consumed across domestic, commercial, industrial, and transport sectors. An additional 35 TWh is used for hydrogen production. Around 11 TWh goes towards converting gas and oil heating systems to heat pumps and district heating. Approximately 3.5 TWh of heat from electrolyzers is injected into the district heating system, though this figure is somewhat arbitrary. The combination of 3 x 11 plus 3.5 TWh (minus some losses in district heating distribution) meets the demand for 35 TWh of heating.
This is the overall picture, and it doesn’t vary significantly with the choice of power production mix. Now, let’s take a closer look at this production mix!
Nuclear or more renewable/gas?
The trend is clear: varying the cost of nuclear significantly impacts the production mix, mainly shifting between nuclear and renewables with enabling gas. Other factors in the mix, like increased use of batteries, hydrogen storage, and to some extent heat storage, also change, but these shifts are relatively minor compared to the main factors mentioned.
Here is the nuclear share of the system’s energy production as a function of nuclear cost.
Let’s compare two scenarios: one where nuclear energy has a CAPEX cost of 7 BEUR/GW and accounts for 43% of the energy share, and another without nuclear energy, (that is, the cost of nuclear exceeds approximately 8.2 BEUR/GW).
Nuclear @ 7BEUR/GW
Power bus (TWh electricity)
===========================
WindOn 53.5
WindOff 4.4
Solar 12.9
Nuclear 49.5
Fixed 0.8
CHPpower 0.0
H2Power 0.3
GasTurbine 1.6
Battery+ 2.3
Battery- -2.7
P-to-Elyz -34.6
PowerToLargeHP -1.4
PowerToHeat -0.3
PowerToSmallHP -9.3
Load -70.4
Curtailed -0.8
Import 0.5
Export -6.3
Turlough- -0.3
Turlough+ 0.2
dtype: float64
Balance power bus : 0.0
Hydrogen bus (TWh H2 LHV)
=========================
H2fromElyz 20.8
H2toCCGT -0.7
H2toPowX -20.0
H2FromStore 5.6
H2ToStore -5.6
dtype: float64
Balance hydrogen bus : -0.0
Heat store bus (TWh heat)
=========================
Link
HeatFromElyz 3.5
HeatFromCCGT 0.0
HeatFromNuclear 0.0
CHPheat 0.0
HeatFromLargeHP 4.3
HeatFromBoiler 0.3
HeatFromStore 3.5
HeatToStore -3.6
HeatToDH -7.8
CurtailedHeat -0.0
dtype: float64
Balance heat store bus: 0.0
Loads (TWh power/H2_LHV/heat)
========================
Power loads 116.0
Hydrogen 20.0
HeatLoadDH 7.0
HeatLoad 28.0
Generators (GW)
========================
WindOn 22.8
WindOff 1.5
Solar 21.3
Fixed 0.2
Curtailed 6.9
CurtailedHeat 0.6
H2Turbine 1.4
GasTurbine 1.2
Nuclear 7.1
CHP -0.0
Export 1.7
Import 1.7
Storage (GWh)
======================
Battery 10.6
Hydrogen 608.4
Heat 321.8
Others
======================
Elyz capacity 6.7 GW
CO2 released 0.06 Mt
Total ann. cost 8.95 B€
Peak power 26.1 GW
Nuc. cap. fact. 79.5 %
Fully renewable system
Power bus (TWh electricity)
===========================
WindOn 74.3
WindOff 23.4
Solar 22.7
Nuclear 0.0
Fixed 0.8
CHPpower 0.0
H2Power 0.4
GasTurbine 8.0
Battery+ 5.9
Battery- -7.2
P-to-Elyz -34.8
PowerToLargeHP -0.9
PowerToHeat -2.0
PowerToSmallHP -9.3
Load -70.4
Curtailed -5.1
Import 0.5
Export -6.2
Turlough- -0.3
Turlough+ 0.2
dtype: float64
Balance power bus : 0.0
Hydrogen bus (TWh H2 LHV)
=========================
H2fromElyz 20.9
H2toCCGT -0.8
H2toPowX -20.0
H2FromStore 6.6
H2ToStore -6.7
dtype: float64
Balance hydrogen bus : -0.0
Heat store bus (TWh heat)
=========================
Link
HeatFromElyz 3.5
HeatFromCCGT 0.0
HeatFromNuclear 0.0
CHPheat 0.0
HeatFromLargeHP 2.6
HeatFromBoiler 2.0
HeatFromStore 3.9
HeatToStore -4.1
HeatToDH -7.8
CurtailedHeat -0.0
dtype: float64
Balance heat store bus: 0.0
Loads (TWh power/H2_LHV/heat)
========================
Power loads 117.4
Hydrogen 20.0
HeatLoadDH 7.0
HeatLoad 28.0
Generators (GW)
========================
WindOn 31.7
WindOff 8.1
Solar 37.3
Fixed 0.2
Curtailed 16.4
CurtailedHeat 0.6
H2Turbine 3.2
GasTurbine 5.1
Nuclear -0.0
CHP -0.0
Export 1.7
Import 1.7
Storage (GWh)
======================
Battery 26.3
Hydrogen 961.7
Heat 516.8
Others
======================
Elyz capacity 7.4 GW
CO2 released 0.32 Mt
Total ann. cost 9.23 B€
Peak power 37.0 GW
Summary
In summary, the main differences between the two scenarios in terms of dispatch are that in the nuclear plus renewable scenario, nuclear replaces 50 TWh of wind and solar from the fully renewable scenario.
| Difference analysis | Fully Renewable (TWh) | Nuclear @ 7 BEUR/GW (TWh) | Difference (TWh) |
|---|---|---|---|
| Wind – Onshore | 74.3 | 53.5 | -20.8 |
| Wind – Offshore | 23.4 | 4.4 | -19 |
| Solar | 22.7 | 12.9 | -9.8 |
| Nuclear | 0 | 49.5 | +49.5 |
| Gas | 8 | 1.6 | -6.4 |
| Curtailment | -5.1 | -0.9 | 4.2 |
| Load | -117.4 | -116 | 1.4 |
| Battery loss | -1.3 | -0.4 | 0.9 |
| Balance | 4,6 | 4.6 | 0 |
Main differences
Replacing 50 TWh of renewable with nuclear energy has several impacts on the system:
- A more compact system – Peak power demand falls from 37 to 26 GW, which likely eases the burden on the transmission network.
- Reduced storage needs – Battery capacity drops from 26 to 11 GW ( -61%), while required heat and hydrogen storage volumes shrink by 37%.
- Increased stability – While not part of this work, 7 GW of nuclear power would contribute significantly to the system inertia and the handling of reactive power.
- Lower annual system cost – Total costs decrease by about 3%, equivalent to roughly €280 million per year.
- This cost reduction should be viewed as highly indicative rather than definitive, since it depends on many uncertain assumptions.
In the fully renewable scenario, Ireland would need to increase its onshore wind power capacity sevenfold, and add 24 GW of offshore wind. Reaching 32 GW of onshore wind alone would require about 6,400 turbines of 5 MW each. Given Ireland’s size and the land requirements of onshore wind, this scale of expansion could be highly challenging.
In the renewable-plus-nuclear scenario, the required increase in onshore wind is more modest—around a fivefold expansion. A more realistic alternative may be to substitute part of the onshore capacity with offshore wind, albeit at a somewhat higher cost, since only 4.4 GW of offshore wind is allocated in this scenario.
Other Observations
- Combined Heat and Power (CHP), fuelled by biomass, is largely squeezed out of the optimisation due to its relatively high cost.
- Instead, large-scale heat pumps and excess heat from electrolyser operation supply the district heating system.
- Nuclear heat is not utilised in this model, but in reality it could be an important source for district heating.
- The fully renewable scenario relies more on heat-only boilers, likely to make use of excess solar power that would otherwise be curtailed.
- The Turlough Hill pumped hydro plant is too small to have a noticeable effect at the system level.
- Instead, 11–26 GWh of battery storage is used for daily balancing.
- Hydrogen turbines provide only a very small share of gas-based power; in practice, they could likely be omitted and replaced entirely by natural gas turbines (with CCS).
Appendix: Cost assumptions
| Asset | Overnight cost (MEUR/MW) | FOM (% of OC) | VOM (Marginal cost) (EUR/MWh) | Lifetime |
|---|---|---|---|---|
| Solar | 0.33 | 3% | 0.5 | 25 |
| Wind – Onshore | 1.1 | 2% | 1 | 25 |
| Wind – Offshore | 2.2 | 2% | 2 | 25 |
| Gas turbine (H2/NG) | 1 / 1.5 | 2% | 4 / 82.5 | 25 |
| Nuclear | 7, 9 | 2% | 10 | 60 |
| Combined heat/power | 1 (per MW fuel) | 3% | 32.5 (per MWh fuel) | 40 |
| Electrolyzer | 0.6 | 2% | 2 | 25 |
| Battery (4h) | 0.15 | 3% | 0 | 15 |
| Hydrogen storage | 1000 EUR/MWh | 2% | 0 | 40 |
| Heat storage | 1000 EUR/MWh | 1% | 0 | 50 |
| Heat-only boiler | 0.08 | 2% | 1.5 | 40 |
| Heat pump | 0.6 | 2% | 2 | 25 |
| District Heating (dist only) | 1 | 2% | 0 | 50 |
| Import | – | – | 100 | – |
| Export | – | – | -25 | – |