Guest post by Riccardo Carollo of Incoteco ApS
This report provides a comprehensive description of the Irish electricity generating system and how it is evolving to cope with ever higher levels of intermittent wind power. Of particular interest, the report contains information on actual generation for specific power stations and shows how their use has declined between 2010 and 2015. The report also describes commercial / technical solutions to efficiently deal with the load balancing issue. Neither I nor Energy Matters have any commercial relationship with the companies involved: Incoteco ApS, Rolls Royce plc or Ormat inc.
- The island of Ireland experienced a rapid growth in the wind power installed capacity over the last years, with more than 3 GW all-island capacity at the end of 2015. This trend is expected to increase. Both the Republic of Ireland and Northern Ireland have agreed a target of 40% renewable share in the fuel mix by 2020 – the vast majority of it coming from onshore wind power.
- Ireland is the electric island with the highest share of wind power generation worldwide. Because of the scarcity of interconnections with other power systems and the relatively small scale of its pumped hydro storage system, the existing thermal fleet has to absorb wind power’s intermittent output. The change in the operation of the Irish CCGT fleet, in particular, has been dramatic over the last years. Since 2008, the fleet’s capacity factor has halved, falling to only 40% in 2015. Most CCGTs are now online only during peak load demand and/or when wind power output is very low or null.
- The CCGT fleet was designed for base-load operation, achieving high efficiencies (over 50%) at constant rated power output. The flexibility required from these units to integrate an increasing share of wind power has resulted in dramatically increased O&M costs, specific fuel consumption and specific CO2 emissions.
- This study examines in some detail, how the system operator is forced to cycle even “base-load” stations and call on other CCGTs that were designed as base-load units to operate intermittently as “peakers” and in-fill power suppliers from the SEMO database.
- Incoteco (Denmark) ApS has commercial involvement with two possible commercial solutions for the Irish case.
- Eos Energy Storage (http://www.eosenergystorage.com) has developed modular MW scale battery storage modules, which can be installed rapidly in virtually any grid or distributed connected location, whether at substations or directly at the wind farm site. At an ex-factory price of 160 US$/kWh (640 US$/kW), this technology is lower in cost than all its known competitors. The installation of fast-acting storage systems would absorb part of wind power’s fluctuating output, allowing the CCGT fleet to operate with higher efficiency and reduced costs. If installed at or close to the wind farm site, battery storage can also help reduce growing wind power curtailment. Curtailment has been increasing in direct proportion to the wind power installed capacity.
- The second solution Incoteco presents for this dilemma is the Trent-Ormat combined cycle gas turbine. In modules of 134 MW, this technology combines relatively high efficiency (46% HHV) with high flexibility.
- The gas turbines synchronize in 5 minutes and run to full load in another 5, while the rated power (gas + organic Rankine cycle turbine) synchronizes in only 5 minutes and reaches full output within 15 minutes after “pushing the button”. In the event of the decommissioning of one or more of the coal-fired thermal units, the replacement of the installed capacity with Trent-Ormat turbines would allow higher system flexibility and relieve the existing, high efficient CCGT fleet from absorbing much of the wind power’s intermittent output.
1) State of the Irish Power System in 2016
Ireland is an electricity island, having limited HVDC interconnections with Great Britain only, the 500 MW East-West Interconnector, commissioned in 2012, and the 500 MW Moyle Interconnector. New installations, such as the proposed Celtic Interconnector linking Ireland and France, are not expected be built before 2020 when wind penetration is supposed to be 40%.
Due to the effects of the 2008 economic recession and because of the increased efficiency in the electricity supply, the Irish energy demand has not increased during the last ten years .
Figure 1: Primary Fuel Mix for Electricity Generation for the Republic of Ireland .
The stagnation of the island’s energy demand can be seen from the plot of Figure 2. Over the last years, the Irish yearly electrical load demand has been around 35 TWh/y.
Figure 2: Annual Electricity Consumption in Ireland. Sources: , .
Wind power installed capacity has been growing. The island now has one of the highest share of wind power in its fuel mix worldwide, and the highest for a large electricity island. The trend can be seen from the plot of Figure 3. In 2015, Ireland generated over 23% of its electricity demand from wind power, which has over
3 GW of installed capacity .
Figure 3: Installed Wind Power Capacity in the Island of Ireland , .
Both the Republic of Ireland and Northern Ireland have agreed the ambitious target for 2020, when 40% of the electrical energy production in the whole island is expected to come from renewable energy sources, mainly onshore wind power. It is not clear whether Ireland will succeed in reaching the 2020 target, since this depends on other factors than the installed capacity such as the capacity factor of the new installation sites, the system load demand and the wind power curtailment due to system limitations.
What does seem certain is that wind power’s installed capacity and the wind share in the fuel mix will continue increasing during the next years. Due to the high intermittency of wind power generation, and the above-mentioned lack of interconnections with neighboring power systems, the grid integration issues studies in this report will increase.
Ireland lacks significant storage systems apart from the 292 MW Turlough Hill Pumped Storage, a unit that is used to provide primary and secondary operating reserve . For these reasons, wind power intermittencies have to be mainly absorbed by the existing thermal units installed in the island.
In January 2016, there were 8 CCGT power plants registered in the SEMO database, 7 in the Republic of Ireland and 1 (Coolkeeragh CCGT) in Northern Ireland. CCGT total installed power amounts to 3.7 GW, with the individual plants’ rated power between 384 and 747 MW. All of the CCGT units are relatively new, having been commissioned between the year 2000 and 2014. These plants were originally designed for base-load operation, achieving high efficiencies in a short range around the design power output.
In addition to the CCGT fleet, there are two coal-fired power plants within the Irish system. These the 3-unit, 915 MW Moneypoint Power Station in SW Ireland and the 520 MW Kilroot Power Station in Northern Ireland. Three peat-fired plants, with overall rated power of 370 MW, are distributed around the Republic and are used to provide base-load generation. Hydro’s contribution to the fuel mix is limited, due to the limited installed capacity of 237 MW (excluding Turlough Hill pumped storage). The 640 MW open cycle gas turbine fleet complete the thermal fleet; these units are activated mainly during peak load demand .
2) The Irish Electricity Market
The Single Electricity Market Operator (SEMO) operates the all-island electricity market for Ireland.
All electricity is centrally traded through a pool system, where licensed generators sell their electricity to a licensed supplier who sells it onto the pool, and receives a single market price (SMP). The electricity market prices are set by the SEMO, and they are published on half-hourly basis and calculated after the event.
In addition to the energy payment, the market price per MWh sold, the owner of a Generating Unit may access two additional streams of revenue. These are the capacity payments – compensation for being available to generate upon instruction from the grid operator – and constraint payments – compensation for being constrained from exporting the scheduled amount of energy onto the system because of network or system limitations .
Over the last years the capacity and constraint payments for the All-Island system have been constantly over 500 and 100 millions of € respectively. These data can be found listed in Table 1. Figure 4 illustrates the trend in the yearly payments for the All-Island market (values in millions of €).
Table 1: Yearly payments for the Generating Units in the SEMO over the last years. Values in millions of €. Source: SEMO .
*Partial value for 2016, updated to April 2016.
Figure 4: Yearly Payments for the All-Island Market. Source: SEMO.
In the next years, the capacity payment mechanism is expected to change. According to the 2016 EirGrid “All-Island Generation Capacity Statement 2016-2025”  the introduction of a new Capacity Remuneration Mechanism (CRM), will be a major change for all generators. This system is expected to be operative from 2017. Until these new mechanisms can be understood by potential investors in electricity storage or alternative technologies to deliver more flexible responses to wind’s stochastic intermittency, it will not be possible to make a business case for the introduction of these.
3) CCGT Present Operation
As mentioned in the previous section, all the power plants in the Irish CCGT fleet were originally designed to perform in base-load operation. The increase in the wind power installed capacity, combined with the stagnation of the load demand, has resulted in highly variable operations for all the CCGTs, which are now primarily responsible for absorbing wind power’s constantly fluctuating power output.
As it can be seen from the All-Ireland Fuel Mix during November 2015, plotted in Figure 5, CCGT energy production is highly dependent on the wind power output. During periods of low wind power production, such as the first week of November 2015, the CCGT fleet is used to cover the majority of the load demand. During periods of high wind production, wind supplies up to 46% of the demand  and the CCGT fleet is used with a low capacity factor. Coal and peat units are normally used to provide base-load generation.
Figure 5: All-Island fuel mix during November 2015. Calculations by Maria Tsagkaraki.
In this work, the data available from the Single Electricity Market Operator (SEMO) database are used to determine the operation of the generators in the island . With a detailed analysis on the single plants’ production within the CCGT fleet, it can be seen that Dublin Bay, Coolkeeragh and Whitegate CCGTs are providing most CCGT generation – although their power output also fluctuates according to the net load demand. The remaining units in the fleet – Aghada, Great Island, Huntstown, Poolbeg and Tynagh – are instead used to meet the peak and fluctuating load demand with rare episodes of higher output during periods of low wind production. This is visualized in Figure 6.
Figure 6: CCGT Power Output during November 2015. “Other CCGTs” includes Aghada, Great Island, Huntstown, Poolbeg and Tynagh CCGT. Source: SEMO.
The number of start-ups and stops and the load following cycles have increased during recent years. As examples, the power output of Tynagh and Huntstown Power Stations, have been analyzed for the years 2010 and 2015. The analyses are shown in Figure 7 and Figure 8.
Figure 7: Power output of Tynagh CCGT in 2010 and 2015. Source: SEMO.
Figure 8: Power output of Huntstown CCGT in 2010 and 2015. Source: SEMO.
The SEMO database was analyzed for November 2015 when during the first week there were particularly low levels of wind power production in Ireland. The power output of each of the 8 CCGT plants in the Irish fleet is shown in the charts of Figure 9.
Figure 9: Power outputs of each unit in the Irish CCGT fleet during November 2015. Source: SEMO.
This flexible operation greatly affects the efficiency of the CCGT fleet, as demonstrated in the report “All Island Specific CO2 Emissions CCGT Fleet and Wind Penetration 2014-2015.” by Maria Tsagkaraki . The CCGT fleet’s fuel efficiency during recent years has fallen far below the nameplate value of the individual generators, amounting to 32% HHV in 2014 and 34% HHV in 2015. Increased specific-fuel consumption of the fleet is caused mainly by the growing number of start-ups, and because of the lower efficiency when the plant is operated below the design rated power as clearly shown in Figure 7, which is typical for all the 23 months analyzed in Maria Tsagkaraki’s report .
Therefore the flexibility required from the CCGT fleet comes at a higher cost than widely believed, as explained in the next section of this report.
4) An Evaluation of the Cost of CCGT Cycling
The culmination of adding more variability and unpredictability to a power system, as the share of wind power increases, is that, lacking efficient storage, the thermal units will be required to start-up, ramp up and down and stop more often, collectively termed cycling .
Power plant cycling leads to component failures which are complex and usually involve multiyear time lagging. For this reason, a correct estimate of those costs is not an easy task to quantify.
A useful tool in this analysis has been the 2012 Power Plant Cycling Costs report  produced by Intertek APTECH for the National Renewable Energy Laboratory (NREL), a National laboratory of the U.S. Department of Energy. This report provides the most recent, available detailed review of real data available on power plant cycling costs that this author could locate.
According to the NREL report, the factors that contribute to the increased cost of CCGTs’ cycling can be summarized as:
- Increased fuel consumption due to more frequent plant start-ups, lower efficiency at part-load levels and lower efficiency arising from increased wear to components;
- Increased O&M costs, due to increased wear and tear to plant components;
- Higher rate of components failure;
- Increased environmental costs due to higher specific CO2 emissions, due to lower efficiency during start-ups, load following and operation at outputs different from the design one;
- Loss of income during the plant lifetime, due to more frequent and longer forced outages;
Because of the complexity of the topic and the present lack of other, non-fuel, statistical data, which most generators regard as confidential, the actual costs of more frequent outages are not included in this report. Instead, the author has to rely on the publicly available estimates made in the NREL Report.
The NREL report provides an estimate of the costs associated with frequent CCGT start-ups. These costs depend on the kind of the start-up, i.e. whether it is cold, warm or hot. Cycling damage increases at an inversely proportionate rate to the initial plant temperature, because of the increased thermal stress on the plant components. According to NREL , CCGT start-ups after no more than 5 hours offline can be classified as hot starts, between 5 and 40 hours as warm starts and over 40 hours offline as cold starts. It provides to the general public only lower bound, non-fuel costs associated with CCGT’s starts; those are (in 2012 US$):
35 US$/MW capacity for hot starts;
55 US$/MW capacity for warm starts;
79 US$/MW capacity for cold starts;
These numbers are median estimates. The NREL report provides 25th and a 75th percentile values as well, and recommends the use of the 75th percentile values “if a Unit is judged to have more than typical cycling usage and susceptibility compared to the generation type”, and the 25th value “if a Unit is judged to be less susceptible to cycling costs or low cycling usage compared to other units in the generation type population” . Due to the lack of more detailed data, the median value has been used by this author for the analysis of this work.
It is important to remember that the actual cost is highly dependent on the specific plant technology, years of service, components used and operating conditions. The numbers provided to the public are lower bound estimates, making any analysis based on them conservative.
In order to determine the costs associated with each CCGT in the Irish network, metered generation data from the SEMO portal has been used . The SEMO portal provides 30-minutes resolution data for each of the eight CCGTs registered in 2016 in the SEMO market for Ireland. The years from 2008 to 2015, representing those years when wind power became a significant part of the fuel mix, have been analyzed in this study.
Using the previously mentioned methodology, an estimate of the cycling costs associated with the plant start-up has been performed. The lower bound of these costs for the Irish CCGT fleet (8 units) is in the range of US$ 15-20 millions per year. The data also show a generally increasing trend over recent years, due to the increased wind power installed capacity. The peaks in the years 2010 to 2012 are caused by the
non-availability of the East-West Interconnector, which will be commissioned in September 2012. In addition, Turlough Hill pumped storage station was under maintenance between 2011 and 2012, and the Moyle Interconnector was out of service from October 2011 to February 2012 , . The lack of infrastructure to export or absorb wind power fluctuations resulted in more intense cycling of the thermal fleet, and consequent O&M costs.
Figure 10: Conservative estimate of the O&M costs of CCGTs’ start-ups.
The 2010-2012 excursion aside, the reason behind the increasing trend are to be found in the increased number of starts and stops, required by the fleet in order to absorb the increasing share of intermittent wind power output, and with the increasing share of cold starts in the total number of start-ups. The last topic that will be covered in more detail in the next section of this report.
Another cost taken into consideration in this work is the high specific fuel consumption occurring during the plant start-ups and stops. A CCGT is a complex machine, which requires a relatively long time from being offline to reaching the rated power output. During the start-up process, more fuel per MWh of generated energy is consumed than during normal operation.
A cost estimate of fuel consumption during the start-up process was performed by a UK consultant . The dataset provides detailed information about a conventional cold start-up of a 400 MW CCGT commissioned in 2004 which is considered fairly typical for the incumbent generators in Ireland.
Figure 11: Power output for a UK 400 MW CCGT commissioned in 2004. Time scale in minutes.
In this case the start-up process, as recommended by the Original Equipment Manufacturer (OEM), took a total of 103 minutes, from the plant being started to reach its rated power output. The net power output results as the sum of the gas turbine and the steam turbine power outputs, and it follow the trend presented in Figure 11.
During the entire start-up process, the 400 MW plant required a total heat input of 2837.9 GJ. Assuming the cost of fuel being 10 US$/GJ, this results in a plant start-ups cost for fuel of US$ 28,379, or approximately US$ 71 per MW of installed capacity. During the start-up the plant produces some electricity, mainly after the steam turbine is activated, as shown by the cumulative plot of Figure 10. During the first 103 minutes of operation the CCGT generates approximately 253 MWh. Because the commercial value of the electricity generated by a CCGT as it is ramping up to its contracted load is a fraction of its commercial value, the value of the electricity generated during the start-up process has been ignored in this analysis.
Figure 12: Electrical energy generated during the start-up process of the 400 MW UK CCGT .
The Irish CCGT fleet was commissioned between the year 2000 and 2014, and each plant is equipped with similar but different technologies, which can cause the start-up curve and the specific fuel consumption being different from the one used in the datasheet. In addition to that, the “basis” datasheet refers to a cold start, while many of the actual start-ups are warm or hot, resulting in less fuel to increase the temperature of the plant components and faster start-up time. Finally, sometimes a CCGT is required to be online but at the rated power, with or without the activation of the steam turbine; therefore, the real-time start-up curves are different from the one on which the calculations have been based.
This behavior can be seen from the plot here below, where various, real-time start-ups are plotted for two registered power outputs at the Tynagh and Great Island CCGTs. All the start-ups occur during November 2015. The power output has been converted to per unit values as a ratio of the plant’s rated power. The time scale is in minutes.
Figure 13: Comparison between the power output in the CCGT model and four examples of real CCGT start-ups during November 2015. Data source: SEMO.
It can be seen how the actual start-up process for gas-fired plant can differ significantly from the OEM’s recommended model. It appears that in Ireland some units are required by the system operator to activate only the gas turbine side of the CCGT in case of low demand, resulting in a lower plant efficiency.
Based on the conservative fuel cost of 10 US$/GJ, an average value of 70 US$/MW cap. for any plant start-up has been assumed. The resulting cycling cost figure, sum of the fuel cost and the O&M start-up costs, results to be in the range of many tens of millions of US$. This is shown in the chart of Figure 14.
Figure 14: Conservative estimate of the costs associated with the CCGT fleet start-ups over the years, inclusive of O&M and additional fuel consumption.
It is important to remember that this is a very conservative figure, since the cycling costs estimates are based on the NREL lower bound estimates . The non-fuel costs associated with the increased ramping have not been evaluated due to the lack of transparent data.
5) Analysis of the CCGT Capacity Factor
From the data gathered from the SEMO database, it can be seen that the capacity factor of the Irish CCGT fleet has been steadily decreasing over the last years, from around 80% in 2008 to approximately 40% in 2015. The trend is illustrated in the following plot.
Figure 15: Irish CCGT capacity factor over the years. Source: SEMO.
The decrease in the capacity factor results in an increased share of cold starts in the total number of a CCGT’s start-ups, as mentioned in the previous section of this report, and consequently higher cycling costs. As an example, the number of start-ups of Tynagh CCGT, classified as cold, warm and hot, is plotted in the figure below. As described in the previous section of this report, based on the analysis done in the NREL report , cold starts are defined as start-ups after more than 40 hours being offline, warm from 5 to 40 and hot starts after no more than 5 hours offline.
Figure 16: Number of start-ups per type of Tynagh CCGT. Sources: SEMO, NREL.
A similar trend can be seen from the following plot, showing the number of start-ups of the entire CCGT fleet installed in Ireland. As for the cycling costs trend plotted in Figure 10 and Figure 14, the unusually high values for the years 2010 to 2012 were caused by the unavailability of the East-West Interconnector and temporary but extended faults in the Moyle Interconnector and Turlough Hill pumped hydro station.
Figure 17: Number of start-ups per kind of the Irish CCGT fleet. Sources: SEMO, NREL.
The decrease of the CCGT capacity factor is directly related to the increase in wind power installed capacity, and consequently with the increasing share of stochastic renewable energy in the Irish fuel mix. A direct comparison between the wind power installed capacity in the island and the average capacity factor of the CCGT fleet are shown in Figure 18.
Figure 18: Comparison between the average capacity factor of the Irish CCGT fleet and the cumulative wind power installed capacity in the Republic of Ireland.
If the 2020 goal for wind power is met, requiring approximately 4000 MW of installed wind capacity in the ROI alone , a linear approximation results in the CCGT fleet capacity factor falling to less than 20%.
The individual CCGTs in the fleet have a widely diversified operation, as it can be seen in Figure 19. It is worth noticing how the newer installations, such as Great Island CCGT and Aghada CCGT (commissioned in 2014 and 2010 respectively), have been used less than older, less efficient units such as Dublin Bay (commissioned in 2002) or Coolkeeragh CCGT (commissioned in 2005).
Figure 19: Capacity factor of the individual CCGT units in the Irish fleet over the years. Source: SEMO.
It seems that location, and therefore possibly the grid’s existing configuration rather than the nameplate efficiency of the power plants, plays the most important role in determining the use of each individual CCGT.
As an example, the capacity factors of Dublin Bay CCGT, located in the Dublin area, and Tynagh CCGT, located in County Galway, are compared in the plot below. The older, less efficient Dublin Bay power plant is operated at nearly the maximum of its potential, probably due to its strategic location.
Figure 20: Comparison between the capacity factor of Dublin Bay and Tynagh CCGTs with the Irish fleet’s average.
During the last few years, three CCGTs – Dublin Bay in the Dublin area, Whitegate in the Cork area and Coolkeeragh in Northern Ireland – provided most base-load operation, while the remaining plants in the CCGT fleet were activated during peak load demand and/or during periods with low or null wind power generation.
6) Proposed Commercial Measures for Mitigating the High Costs of Wind Integration in Ireland
Incoteco (Denmark) ApS is working with two possible technologies that might ease wind power integration in the Irish scenario while lowering its costs. These are MW scaled battery modules and the Trent-Ormat combined cycle gas turbine respectively.
Battery Storage Technology
The Eos Aurora 1000|4000 is a promising candidate for battery storage solutions in Ireland. It can deliver 1MW of energy for 4 hours continuously with a millisecond response. This would allow multiple modular units to absorb rapidly wind power fluctuations and to compensate for forecast errors. Due to its rapid response time, the unit can also provide frequency regulation, an important ancillary service in an electricity island such as Ireland.
The Eos Aurora’s zinc hybrid cathode (ZnythTM) sealed battery technology allows the unit to have a long cycle life (5000 cycles at 100% DOD) and is (to our knowledge) the lowest priced energy storage produce on the global market today. According to Eos’ datasheet, the retail price for DC modules over 10 MW is 160 US$/kWh (640 US$/kW), ex-factory, USA.
The unit has a high cycle efficiency, over 75% at 100% DOD, which is about the same as most modern pumped hydro installations. As a comparison, the only installed storage system now installed in Ireland is the Turlough Hill pumped storage station, which appears to operate with an average efficiency of 55% during 2015 . The most important technical features of the Eos Aurora technology are summarized in the following table:
Table 2: Eos Aurora 1000|4000 Technical Specifications
Battery storage could be integrated into the Irish grid for three main purposes:
1) To reduce the cycling stress on the present thermal fleet, allowing these to be more fuel efficient;
2) To displace the least efficient CCGT units used for balancing and infill power in the fleet;
3) To reduce wind power curtailment, while providing the foregoing services;
Reduce Stress of CCGT Units
The use of the CCGT fleet to absorb wind power fluctuation has proven to be expensive and inefficient in terms of O&M, fuel consumption and CO2 emissions. The wide spread use of such storage systems allows a power system to decouple (to some extent) demand and production, by storing part of the excess energy in times of overproduction and injecting it into the network when needed. Storage capacity in Ireland can relieve the thermal fleet from absorbing part of wind power intermittency; by doing so, cycling, ramping and the high costs associated with these would be reduced.
Battery storage presents significant advantages over the competitive technologies in Ireland. A new, 650 M€ pumped hydro installation, rated at 360 MW, has been proposed for the Irish system . This shows a clear interest from the investors in a major capital investment in energy storage; however, the time scale of the investment does not match with the ongoing increase in wind power installations and the ambitious 2020 targets – only 4 years from the time this report was produced. Modular MW scale battery storage can also be installed before 2020, in many locations, including the built environment and at wind farms.
MW scale battery storage could ease wind power integration into the network, while allowing the existing CCGT fleet to operate more efficiently and with reduced cycling costs.
Displace Least Efficient Units in the Fleet
Battery storage can be used to displace the least efficient operations of the CCGT fleet and help the remaining units in the fleet operate in more optimal conditions. Three CCGTs (Tynagh, Huntstown and Poolbeg) showed a drastic reduction in their capacity factor over the recent years. It is possible that some of these units should be decommissioned for lack of operation in the near future.
It is also likely that the coal-fired units may be closed to reduce carbon emissions between 2020 and 2025, requiring their capacity to be replaced, MW for MW .
Partly replacing these thermal units with battery storage could be a solution to improve the performances of the remaining fleet. The installation of MW scale battery storage can efficiently absorb wind power fluctuations and allow the remaining CCGT fleet to operate at higher capacity factors and closer to their design power ratings, therefore more efficiently. The use of fast-acting battery storage to absorb most of the wind power fluctuations would eventually allow the rest of the CCGT fleet to operate with less ramping and possibly fewer start-ups, thus reducing O&M costs, specific fuel consumption and lower specific CO2 emissions.
Reduce Wind Power Dispatch-down
Dispatch-down of wind energy refers to the amount of wind energy that is theoretically available, but cannot be used. Dispatch-down due to overall power system limitations is referred to as curtailment, while dispatch-down due to a local network limitation is referred to as a constraint .
During 2014, according to the EirGrid report , 4.1 % of the total wind energy generated in the whole island of Ireland was lost due to down-regulation, accounting for 277 GWh. Lost wind power production is currently on an upward trend. The increase in the wind power dispatch-down is directly proportional to the wind power installed capacity and the increase in wind generation connected to the system . A tentative forecast based on a linear approximation is shown in Figure 21.
Figure 21: Wind power down regulation over the last years and linear forecast to 2020. Source: EirGrid.
With the increasing trend of wind power installations, it is unlikely that unremunerated wind power curtailment can increase if no countermeasures are applied. Assuming that Ireland would reach the 2020 target for 40% renewables in the fuel mix, with approximately 13 TWh of energy produced from wind power, a linear approximation of the curtailment figure for the years currently available leads to a down-regulation level around 8% – i.e. 1 TWh. This is clearly only a forecast, based on the available data during April 2016.
The release of the 2015 EirGrid curtailment report, expected in the first half of 2016 and not available at the time this report has been released, would make any analysis on this topic more accurate.
Modular battery storage solutions could be installed directly at the wind farm site, minimizing line losses and contributing towards the easing of the network’s limitations. If placed on the DC side of a wind farm – where possible – this technology has the advantage of no need for additional DC/AC conversion than the one already available on the wind farm site, resulting in reduced installation costs.
However, EOS’s production will not start until the third quarter of 2016 and large-scale production will not start until 2017, for a global market. Where ever EOS batteries are installed, it is likely that the owner operators will require at least three years of proving experience before any mass roll-out at the scale of hundreds of MW can happen before (say) 2020. Even then, global demand at the scale of GW per year is unlikely before the mid-2020s.
Until then, Ireland will need to rely mostly upon thermal power stations to mitigate the growing operational costs and increasing unreliability of its frame-type CCGTs.
This novel CCGT technology is immediately available. The system module is 132 MW, and consists of two 55 MW Rolls-Royce Trent aero derivative gas turbines and a 22 MW (net) Ormat Organic Rankine Cycle (ORC) turbine. Both these components are designed for flexibility; the Trent-Ormat CCGT can start up fast and reach an HHV efficiency of 46% at full load. The gas turbines synchronize with the grid in 5 minutes from a cold start and runs to full load in another 5. The ORC Turbine takes 10 minutes to run up to full load from cold but overlaps with the second 5 minutes of the gas turbine, so the whole plant is up to full load in 15 minutes from cold. This time is reduced to 10 minutes if the ORC turbine is still warm from running within 40 hours.
This technology is well suited for Ireland, where great flexibility is required from the thermal units in order to absorb rapid wind power fluctuations.
This smaller combined cycle gas turbine, in multiple-unit locations, including existing power station sites can supply rapid capacity and allow the incumbent CCGT fleet to perform more efficiently and more often in base-load operation, while the Trent-Ormat installed capacity would be used to compensate wind power intermittent output.
To achieve Ireland’s ambitious targets for CO2 reduction, it will need to close its out-of-IED-compliance coal-fired units by or before 2021. The Trent-Ormat CCGT would ideally replace these MW for MW to maintain Ireland’s need for reliable dispatchable capacity.
- Ireland is expecting to increase its already high share of wind power in its fuel mix during the next years.
- By 2020, 40% of the electricity production is predicted to come from renewable energies, mainly onshore wind power.
- Because of the scarcity of interconnections and storage units, the installed thermal fleet – mostly CCGTs originally designed for base-load operation – has to absorb wind power fluctuations. With increased wind penetration, the overall capacity factor of all CCGT’s has halved over the past 8 years from 80% to 40%. Three plants (Aghada, Tynagh and Poolbeg CCGTs) are already operating below a 25% capacity factor. All plants are subject to an increase in power output fluctuations compared with the past. This is causing the gas-fired CCGTs to be operated far below their nameplate efficiency, with consequent higher specific fuel consumption and specific CO2 emissions, therefore of costs to Irish consumers and the unprofitability of investors.
- New units in the fleet are affected as well, the key factor in determining the use of a power station in Ireland appears to be its location rather than its nameplate efficiency.
- Apart from the fuel consumption, cycling has high costs associated with the wear of the plant components occurring with more frequent start-ups and stops and ramping. A lower bound estimate of these costs is in the range of millions of € per year for the Irish fleet.
- Battery storage can be rapidly installed in the island in order to absorb wind power fluctuations, reducing the cycling stress on the gas-fired units. If installed directly at the wind farm site, battery storage can reduce wind power curtailment, an issue expected to become more and more important as the wind power installed capacity increases. However, these will first have to be trialed at different locations and for different applications at as many locations as can be justified commercially.
The decommissioning of Moneypoint and Kilroot coal-fired power plants will open up a new demand for more flexible gas-fired capacity. The market needs flexible, fast responding and reliably fuel efficient capacity to replace the decommissioned coal capacity and to improve the overall efficiency of the system and thereby reduce CO2 emissions.
- The Trent-Ormat gas turbine looks like an ideal replacement for coal-fired stations and decommissioning frame-type CCGT, because of its high efficiency and operational flexibility.
- Investment criteria for new power stations and/or storage units in Ireland are not clear, because of the continuing uncertainty about the possible streams of revenue that a generating/storage unit will be able to access in the next years.
- In the light of the high and growing costs of integrating wind power, these commercial uncertainties need to be resolved as the issues of supplying non-wind generation multiply to the detriment of investors and the Irish public alike.
 Sustainable Energy Authority of Ireland (December 2014). Energy in Ireland – Key Statistics 2014;
 IWEA. Wind Statistics. From http://www.iwea.com/_windenergy_onshore;
 private communication at EirGrid
 Global Wind Energy Council (2015). Annual Market Update 2014;
 UK Department of Energy & Climate Change;
 EirGrid, All-Island Generation Capacity Statement 2016-2025, 2016;
 IWEA, Stormy Week Sees Wind Energy Hit Record Generation, November 2015. Available at http://www.iwea.com/pressreleases;
 Single Electricity Market Operator. Available at: http://www.sem-o.com/
 Maria Tsagkaraki (February 2016). All Island Specific CO2 Emissions CCGT Fleet and Wind Penetration 2014-2015. Incoteco;
 Niamh Troy, Generator Cycling due to High Penetrations of Wind Power, August 2011;
 National Renewable Energy Laboratory, Power Plant Cycling Costs, April 2012;
 E.V. Mc Garrigle, J.P. Deane, P.G. Leahy, How much wind energy will be curtailed on the 2020 Irish power system?;
 The Irish Times, January 2016. Available at: http://www.irishtimes.com/business/energy-and-resources/hydro-electric-power-station-to-be-developed-in-co-tipperary-1.2492364;
 Energy & Natural Resources, Ireland’s Transition to a Low Carbon Energy Future Department of Communications, December 2015;
 EirGrid, Annual Renewable Energy Constraint and Curtailment Report 2014, December 2015;
 IWEA, Wind Energy and the Electricity Market,
Available at: http://www.iwea.com/windenergyandtheelectricitymar;
 CIA, The World Factbook, Available at: https://www.cia.gov/library/publications/the-world-factbook/
 Department of Enterprise, Trade and Investment, Energy in Northern Ireland 2016, March 2016.