The Impacts of Renewable Energy Resource Variability on Conventional Thermal Generators

Abstracts of Conference Papers: TSBE EngD Conference, TSBE Centre, University of Reading, Whiteknights, RG6 6AF, 5th July 2011. http://www.reading.ac.uk/tsbe/

The Impacts Of Renewable Energy Resource Variability On Conventional Thermal Generators

1* 2 3 4 M. L. Kubik , P. J. Coker , C. Hunt and H. B. Awbi 1 Technologies for Sustainable Built Environments Centre, University of Reading, United Kingdom 2 School of Construction Management and Engineering, University of Reading, United Kingdom 3 AES, Richmond upon Thames, United Kingdom 4 Technologies for Sustainable Built Environments Centre, University of Reading, United Kingdom

* Corresponding author: [email protected]

ABSTRACT The Republic of Ireland and UK governments have put forward an ambitious target of 40% of electricity generation to be supplied with renewable sources by 2020. The dominant source of this energy is anticipated to come from wind power, as this is the most mature renewable technology. However, wind generation is inherently variable in its output, and this introduces significant challenges for the System Operator when balancing supply and demand. Although demand side management, energy storage and greater interconnection are all anticipated to help with dealing with the challenge of variability, conventional thermal generators will have a very significant role to play in balancing supply and demand.

Running conventional generation more flexibly in order to cater for a wind led regime reduces the efficiency of the plant, as well as shortening its lifespan and increasing O&M costs. The link between variability and the impacts on conventional generation is not well addressed in current literature, but is of vital importance for informing the development of the generation mix. This paper introduces some of the potential impacts of greater variability on conventional generators, the past work that has gone into modelling these impacts and identifies areas of future work that need to be addressed.

Keywords: Variability, intermittency, balancing, conventional generation, Ireland

1. INTRODUCTION

Recognising a global consensus of the need to limit future carbon emissions, the Irish and UK governments, along with other EU-27 member states, agreed in 2008 an EU Climate and Energy Package (European Commission 2008). In contributing towards this legislation, the UK and Irish governments have set an ambitious target of 40% of annual electricity consumption to be met by renewable sources by 2020 within the Irish all island electricity market 1. Ireland is currently heavily dependent on conventional fossil fuels (Howley et al. 2009), but is amongst the most gifted in Europe in terms of renewable wind, wave and tidal resource (Rourke et al. 2009). Energy forecasts by Walker et al. (2009) suggest that under

1 Northern Ireland and the Republic of Ireland have a single common electricity market for wholesale electricity.

Abstracts of Conference Papers: TSBE EngD Conference, TSBE Centre, University of Reading, Whiteknights, RG6 6AF, 5th July 2011. http://www.reading.ac.uk/tsbe/

the legislation set out by Ireland’s 2007 Energy White Paper and subsequent energy targets the single largest renewable will be from wind (making up 65% of the 40% target alone). Although wind generation output is to an extent predictable, wind is inherently a variable resource, and this presents additional challenges for system balancing (Laughton 2007). There are a number of technological developments available to help address the impacts of a more variable generation pattern, but conventional generation plant is expected to play a significant role in smoothing out the generation profile when there is a shortfall of wind by running more flexibly. As many of the existing thermal generators will still be operational in 2020, it is particularly important to understand the impacts of a wind led regime on their performance. Such an understanding will inform the roadmap towards the integration of the levels of wind required to meet the ambitious goals set by the government. This paper introduces the current electricity market regime and the characteristics of conventional thermal generation. The specific challenges of variability for conventional thermal generation in Northern Ireland are highlighted, a research area that existing literature does not address. A need for more research into the impacts of variability on the operation of conventional plant is identified and proposed as a future direction for research.

Figure 1 - Schematic of Northern Ireland power stations and transmission network, adapted from Kennedy (2007).

2. BACKGROUND

2.1. THE IRISH ALL ISLAND ELECTRICITY MARKET

Since November 2007, a single electricity market (SEM) has operated for the whole island of Ireland, combining the two previously separate Northern Ireland and Republic of Ireland systems. The SEM consists of a gross mandatory electricity pool, which all generators bid into (Pöyry 2007). All generators that make themselves available to the system are paid a capacity payment, designed to cover the capital costs of constructing the unit in the first place. The system operators, SONI for Northern Ireland and EirGrid for the Republic of

Abstracts of Conference Papers: TSBE EngD Conference, TSBE Centre, University of Reading, Whiteknights, RG6 6AF, 5th July 2011. http://www.reading.ac.uk/tsbe/

Ireland, select the most cost effective plant2 to satisfy an unconstrained schedule of demand from this pool based upon the operating characteristics submitted by the generator units in the market. All such merit order units are paid a system marginal price (SMP), determined by the cost of the most expensive (marginal) unit required to meet demand. System constraints, such as plants being non-operational for maintenance, the need for voltage regulation, or limits to the amount of electricity that can be carried by certain transmission lines, are then imposed and the necessary changes are made to construct a constrained schedule of demand. The key difference is that generators asked to run due to system constraints instead of on merit are only reimbursed their operating costs, and make no operating profit. This already presents a challenge for operators in Northern Ireland, as although they are part of a whole island market, there is limited interconnection across the border into the Republic of Ireland (Figure 2). This bottleneck prevents many merit order plant in the Republic of Ireland from satisfying demand in Northern Ireland. Further challenges emerge with the introduction of more variable generation; these will be addressed later in this paper (see Figure 4).

2.2. CONVENTIONAL THERMAL GENERATION

In conventional power stations, mechanical power is produced by a heat engine that transforms thermal energy, obtained from the combustion of a fuel, into kinetic energy. This kinetic energy is used to drive a generator and produce electricity that can be exported for use elsewhere. Thermal power plants are normally classified by their prime mover (usually a gas or steam turbine, or a combined cycle of both) and their fuel source (e.g. nuclear, fossil fuel, geothermal, biomass). Although there are basic similarities between many variants of conventional generation, and generally their performance is based upon similar characteristics, there are also some important differences which influence their operation, efficiency, flexibility and cost. This section of the paper identifies the key types of conventional generation and their characteristics. Table 1 summarises the main conventional generation plant in Northern Ireland.

2 The term “unit” and “plant” are used interchangeably in this paper; however, strictly speaking a power plant may be made up of multiple generator units. The difference is clarified in Table 1.

Abstracts of Conference Papers: TSBE EngD Conference, TSBE Centre, University of Reading, Whiteknights, RG6 6AF, 5th July 2011. http://www.reading.ac.uk/tsbe/

Table 1 - Summary of conventional generation capacity in Northern Ireland

Location Plant typei Fuel Units Capacity/unit MSGiii/unit Ballylumford Steam plant Gas 3 180MW 60MW Single shaft CCGT Gas/oil 1+1 100MW (combined) 65MW CCGT/OCGTii Gas/oil 2+1 2x160MW + 2x68MW 180MW +113MW OCGT (quad aero Oil 2 58MW derivative) Coolkeeragh CCGT Gas/oil 1+1 240MW (combined) Kilroot Steam plant Coal/oil 2 220/260MW 110/70MW OCGT (twin aero Oil 2 29MW derivative) OCGT Oil 2 44MW i. CCGT is an acronym for combined cycle gas turbine, OCGT for open cycle gas turbine. ii. Ballylumford’s 2+1 CCGT was designed to operate flexibly with or without the HRSG units. iii. Minimum stable generation (not applicable to OCGT as these only run at peak loads).

2.2.1. STEAM POWER PLANTS

In these power plants a steam turbine is used to produce electricity, based upon the thermodynamic Rankine cycle. The basic principle of a subcritical steam plant is shown in Figure 3(a); fuel is combusted in a boiler, the heat is used to turn water into steam, which drives a series of turbines “T”, before the steam is condensed back into water and the cycle is completed by pumping the water back to the boiler. Despite the simplicity of its basic operation, a large number of auxiliary systems are required in order to deliver the fuel, maximise the efficiency of this process and clean up the exhaust emissions. The exact set up of a power plant depends on the nature of the fuel it uses; both in terms of optimisation of design and the equipment required.

For example, a pulverised coal3 power plant requires a stockpile to store the coal, a conveyer mechanism to deliver coal to the plant, mills to grind the coal into a fine dust before injecting it into the boiler, electrostatic precipitators to remove particulates from the flue gas and a facility to dispose of the ash. This list is by no means exhaustive, but serves to illustrate that although the core operation of a steam plant is identical, the additional processes to facilitate this with a certain type of fuel are complex. Similarly, the boiler in a coal fired power plant has a different optimal size and geometry to that of oil or gas fired boiler, so while a plant can be designed to run flexibly on multiple fuels (desirable from a security of supply as well as fuel pricing point of view) it is at the expense of efficiency and operating costs.

3 This is further complicated if different types of coal are considered; for example, lignite coal produces very large quantities of ash compared to bituminous coal, or if different types of coal combustion are used; such as Circulating Fluidised Beds (CFB) rather than Pulverised Coal (PC). To keep this paper focused, only the technologies present in Northern Ireland are discussed.

Abstracts of Conference Papers: TSBE EngD Conference, TSBE Centre, University of Reading, Whiteknights, RG6 6AF, 5th July 2011. http://www.reading.ac.uk/tsbe/

Water Condenser Combustion Exhaust Chamber gas

T Fuel C T Fuel Pump Steam Boiler Air inlet (a) (b)

Figure 2 - Simplified schematic of (a) A steam plant (b) An open cycle gas turbine.

2.2.2. GAS TURBINE POWER PLANTS

Gas turbines operate under the Brayton Cycle. A simplified Open Cycle Gas Turbine (OCGT) schematic is shown in Figure 3(b). Air is drawn into the compressor “C” and compressed, combined with a fuel and ignited. The combustion passes through a gas turbine “T” that is used to drive a generator and produce an electrical output. Modern OCGTs can be more efficient than older steam plant, are very reliable and are able to respond very quickly to a need for generation, taking only minutes to be brought to full load from an off state, and can even be controlled autonomously without anyone manning the plant. However, OCGTs generally have quite high running costs, hence their use is primarily as peaking plant on an electricity system; turning on only for short periods to meet spikes in demand. Furthermore, their performance is influenced by the weather, as the ambient temperature and pressure influences their efficiency and output capacity. The most flexible gas turbines are aeroderivative; these are based on jet engine designs which can handle load changes even faster than industrial OCGT machines but do this at the expense of efficiency and operating costs. A wide variety of fuels can be used to power a gas turbine. Natural gas is commonly used in land-based gas turbines while light oil distillates (e.g. kerosene) can be used as an alternative fuel and to power aero derivative gas turbines. Diesel oil or specially treated residual oils can also be used, as well as combustible gases derived from blast furnaces, refineries and the gasification of solid fuels such as coal, wood chips and bagasse (Langston & Opdyke 1997).

2.2.3. COMBINED CYCLE POWER PLANTS

Combined cycle gas turbines (CCGT) combine the features of a gas turbine with a steam plant. Rather than rejecting the hot exhaust gases as in an OCGT (Figure 3(b)), these are passed into a Heat Recovery Steam Generator (HRSG) unit, using the exhaust heat to convert water to steam and use this to produce further mechanical work in a very similar manner to a conventional steam plant (Figure 3(a)). A CCGT plant yields even higher efficiencies than an OCGT, but at the loss of some operational flexibility. Multiple gas turbines may be coupled to the same steam turbine for efficiency of design; such CCGTs are described as “+1” units, so, for example, two gas turbine units and one steam turbine are referred to as a “2+1” CCGT. Other configurations also exist outside of Northern Ireland.

2.3. KNOWLEDGE GAP

Abstracts of Conference Papers: TSBE EngD Conference, TSBE Centre, University of Reading, Whiteknights, RG6 6AF, 5th July 2011. http://www.reading.ac.uk/tsbe/

Despite the importance of operating conventional plant with high levels of integrated wind, outside of the industry very little research into these aspects has been carried out. A large number of energy modelling tools have been developed to model the integration of more variable renewable resources; however, none have been designed to examine the impacts on conventional generators (Connolly et al. 2010). Oswald et al. (2008) recognise that volatile swings in renewable energy output affect loading cycles for conventional plant and that the impacts on generators are not well recognised. However, these are only discussed qualitatively. Pöyry (2009) modelled the market (i.e. financial) impacts of high levels of variable wind generation, using broad high-level characteristics of plant generation categories. However, there was no focus on the technical impacts or consideration of lower efficiencies, increased wear and other such aspects discussed in Section 3. SKM (2008) carried out some modelling work on the costs and carbon savings of future plant mixes, but again assumed no reduction in efficiency of conventional plant. Meibom et al. (2009) is one of the few academic studies to have looked directly at the impacts of increased part loading and more flexible operation of power plants using stochastic optimisation modelling. However, this study focused on the costs and only in Germany and Scandinavia under 2010 levels of wind. Although there is some research in this area, there is a lack of literature addressing the impacts of many of the issues that are described in Section 3. There is a need to understand what characteristics are most desirable from conventional plant to facilitate the high levels renewables legislated for in Ireland, as well as better understanding the impacts that a flexible operating regime will have on the existing conventional generation plant.

3. IMPACTS OF VARIABILITY ON CONVENTIONAL GENERATORS

The impacts of higher levels of variable generation are broadly accepted to be twofold; the issue of day-to-day balancing of supply and demand and the longer term planning of sufficient capacity from the right mix of plant. Much topical work has gone into understanding the characteristics of variable resources, particularly wind, but broadly this has focused on lower penetrations (< 20% levels) of wind specifically and very few studies look particularly at the impact on conventional generators (Kubik, Coker & Hunt 2010b). Further issues are the occurrence of low probability high swings in renewable generation output (described here as “events”) that may require conventional plant to operate outside their usual operational characteristics (“excursions”). This section of the paper introduces some of the ways in which the conventional generators described in Section 2.2 may be impacted by the integration of a high penetration of variable renewable energy generation.

Abstracts of Conference Papers: TSBE EngD Conference, TSBE Centre, University of Reading, Whiteknights, RG6 6AF, 5th July 2011. http://www.reading.ac.uk/tsbe/

£/MWh Unconstrained schedule to £/MWh Unconstrained schedule to meet demand meet demand SMP Wind SMP Wind

Capacity Capacity (a) (b)

Figure 3 – Visualisation of plant ranked by merit order showing how increasing wind on a system pushes conventional plant off the unconstrained schedule.

3.1. IMPACT ON MERIT ORDER

The concept of the all island electricity market and how it operates was introduced in Section 2.1. The issue of “bottlenecking” due to a lack of interconnection between Northern Ireland was described, which requires generators in Northern Ireland to run “constrained on” and asked to generate in preference to more cost effective merit order plant. The introduction of wind has further impacts on merit order, as illustrated in Figure 4. Wind is a near zero operating cost generation technology, so increasing levels of wind capacity from (a) to (b) pushes existing conventional plant further down the merit order. For a constant system demand, this reduces the system marginal price (SMP) for the constrained schedule, meaning merit order generators make smaller profits on the electricity they produce, and also pushes more conventional generators off the merit order schedule, meaning they make no profit on operation, and have to remain viable on their capacity payment alone. Although the intention of this is to drive down system costs, it creates an unattractive market for investment in the right mix of conventional generation plant to facilitate the operation of a wind led regime. The Northern Ireland System Operator (SONI) has a “3 generator” rule in Northern Ireland for system security purposes. At any one time, three units must be kept running, so that if one were to suffer an unplanned outage, the other two could ramp up their production to meet the system demand. As power plants have a minimum stable generation level (MSG) below which they cannot be securely synchronised with the grid, an increased level of wind generation presents a challenge in keeping enough generators online to meet this requirement. A particular time period of concern is night time, where wind generation is typically stronger and demand is at its lowest. Traditionally, generator operation instructions from the system operator are driven by system demand. However, as wind forms a significant contribution to the energy mix, the swings in wind output are likely to become the dominant driver dictating when conventional generation will be asked to run. This is problematic for conventional generators, as although demand patterns are relatively predictable into the future, wind can only be accurately forecast in the short term. Conventional generators try to time their planned outages for maintenance (typically at the timescale of weeks to months) to minimise the impact to their revenue and this is much harder to achieve in a wind led regime.

Abstracts of Conference Papers: TSBE EngD Conference, TSBE Centre, University of Reading, Whiteknights, RG6 6AF, 5th July 2011. http://www.reading.ac.uk/tsbe/

3.2. OPERATIONAL IMPACTS

In the future conventional generation displaced by wind will have to operate more flexibly. However, running plant more flexibly typically reduces efficiency (a power plant tends to achieve its best efficiency at or near its capacity output), increases operating costs and increases emissions per unit of electricity generated. In the past, conventional steam generators and CCGT plants were typically designed to operate as baseload for the system; providing a predictable and continuous output of power, while OCGT units provided the flexibility of dealing with peak loads. Having to more frequently ramp up and down generation to balance out fluctuations in wind generation will increase wear on units, shorten their lifespans and increase the costs of maintenance. This also places a different emphasis on which characteristics are important in a generator. Plant with a large turndown (able to operate at a minimum stable generation that is a low percentage of its rated capacity) becomes desirable in a variable wind led regime, and plant start-up characteristics from cold, warm and hot states also become important. Depending how long it has been since a unit was last synchronised to the grid there are different start up profiles. The rate of start-up has to be limited due to a number of factors, but a significant limitation is differential expansion rates in the steam turbine between the stator and rotor; the rotor heats up and expands much faster than the stator because it is physically a much smaller mass of metal. This compromises the fine tolerances that are used to improve efficiency. Operational two-shifting, where a unit operates cyclically on a two eight-hour shift on, one eight-hour shift off principle, may become more common, as this keeps most generators in a hot start up state that they can be quickly brought online from. The value of ancillary services as wind penetration increases on a system will also rise. Conventional generation is able to provide voltage regulation (controlling reactive power levels on the grid; important for efficient electricity transmission and distribution) and restorative system inertia to keep the system frequency at 50Hz when a unit trips and the generation it provides is suddenly lost, something that existing installations of wind in Ireland cannot provide at present. Conventional generators also tend to consume a large amount of their own power (particularly at lower loads) to run auxiliary systems such as fans, pumps and mills. As these do not all need to be operational all of the time, there is possible scope for smarter control of this load as an ancillary service to help balance supply and demand. Future volatility of fossil fuel prices may increase the value of fuel diverse conventional generation. For example, Kilroot power station (Table 1) is able to operate on coal or oil. Running on fuel oil is more expensive, but allows a minimum stable generation of 70MW per unit rather than 110MW with coal, as oil burns in a much more stable manner than coal. This may be of increasing value as the system operator has to free up capacity for more wind on the system. At present, the market rules requires strictly monotonically increasing price bids, so the operators at Kilroot are not permitted to start operating on oil (at higher cost) and switch to coal when the 110MW threshold has been reached. Ballylumford’s 2+1 CCGT plant (Table 1) has been designed so that it can flexibly operate as an OCGT by isolating its HRSG units. This is something that CCGT plants are not normally designed to do. This OCGT/CCGT flexibility is rarely used in the current market schedule, but may be of future value and interest.

Abstracts of Conference Papers: TSBE EngD Conference, TSBE Centre, University of Reading, Whiteknights, RG6 6AF, 5th July 2011. http://www.reading.ac.uk/tsbe/

4. CONCLUSIONS

This paper has introduced the nature of the significant challenge faced by the Irish Electricity market if intends to meet its goals for a wind penetration of 40% by 2020. The variability of this energy source will have an impact on the operation of conventional plant, particularly in Northern Ireland where there are physical and market constraints in play. A number of generating plant characteristics become increasingly significant with rising penetrations of wind generation, and conventional plant will need to change their operating regimes to maintain commercial viability. These characteristics include:

• The ability to plan maintenance periods to minimise commercial losses. • Plant turn down and start-up profiles. • The ability to two-shift plant operation. • Fuel flexibility. • Plant ancillary system load management. • CCGT/OCGT flexibility.

Past research by the authors (Kubik et al. 2011) has considered the nature of wind resource characteristics against the background of the Irish Electricity Market (Kubik et al. 2010a, Kubik et al. 2010b), but further work is needed to link these characteristics to those of generating plant. This is an area that the authors intend to pursue in future research.

ACKNOWLEDGEMENTS

The authors would like to extend their thanks to David Bothwell, Roger Graham and Brian Mongan all of whom provided data, insight and guidance that made this paper possible. They also wish to acknowledge the funding of the EPSRC, without whom this research would not have taken place.

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Abstracts of Conference Papers: TSBE EngD Conference, TSBE Centre, University of Reading, Whiteknights, RG6 6AF, 5th July 2011. http://www.reading.ac.uk/tsbe/

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