Download Introduction - Claverton Group

A Future of Increased Fossil Plant Cycling
Implications of the Government’s Wind Farm and Other Power Generation Proposals
F Starr : Claverton Energy Group
Since 2000, the gradual run down of nuclear capacity in the UK has reduced the technical
requirement for plant cycling. At the present time, because of low gas costs, most CCGT
plants operate base load. It is the older coal plants which cycle. Wind farm capacity at 4 GW
is having little effect. However, sufficient real data from UK wind farms is now available to
estimate how this will affect power plant operation in the future. If the Government’s target
of 33 GW of wind capacity by 2020 is achieved, this will require the periodic shut down of
much of the UK’s fossil capacity, whereby some plants will be off line for days at a time. The
plants best able to adapt will be CCGTs, although present designs are probably not ideal. The
problem of extended periods of shut down will increase as more nuclear and CCS capacity is
built since these will take up more of the base load. Preliminary data from nearby countries,
including Ireland and Denmark, suggests that contrary to some beliefs, high voltage dc
networks will only have a marginal affect on the need for plant cycling in the UK.
1. Introduction
In 1998 the output from nuclear plants reached 91.2 TWh, almost 28% % of the electricity
generated in the UK. It is therefore not surprising, given that nuclear provides base load
power, the issue of two shifting was becoming a serious issue for the then relatively
inexperienced operators of CCGT plants, as well as those running steam plants, who were
more familiar with the problems. Because of this’ ETD Ltd were contracted to investigate the
maintenance and costs issues associated with two shifting, and produced two major reports on
this subject [1,2]. At the suggestion of EPRI, a conference was also organised on this
subject in 2001 [3,4].
Ten years later nuclear output had fallen to just 13% and concern about two shifting is not
what it was once. At the present time, because the cost of gas is relatively low, CCGT plants
in the UK operate base load. It is coal plants which now take care of the day-to-night
fluctuations in demand. Since most UK coal plants have a limited life, and have to be
decommissioned in 2015, under EU emission rules, there is not too much interest in long
term reliability.
However, during the ETD Two Shifting Conference, the author pointed out that from about
2010, another form of “two shifting” would start to be of concern, this resulting from the
increased dependence on wind energy and photovoltaic electricity. The point was further
emphasised in a plenary paper on advanced generating plants at the Parsons 2003 Conference
[5]. And during the author’s time at the European Commission’s Institute for Energy, at
Petten in the Netherlands, a number of papers were produced by the author and his colleagues,
on the need for IGCC-Hydrogen-CCS plants to be able to switch output from electricity
generation to hydrogen, to compensate for the variations in electricity demand. This was
shown to be the most economic and practical way of operating CCS plants [6]. More recently
in the journal, Energy Materials, the author commented on the need top ensure that future
fossil fuel plant designs have the ability to compensate for the irregularity of wind energy. In
the author’s view this is an overlooked requirement in the design of CCS plants [7].
The real facts are that, for a long time to come, most of the fossil fuel plants in the UK will
not be of the CCS type, nor will they be IGCCs, modified to produce hydrogen for the
hydrogen economy. What seems to be certain is that present wind capacity will rise from the
present level of 4GW, to, by 2020, something in the region of the Governments target of
33GW. Furthermore, after declining to a low level, 2020 nuclear output will begin to grow
again. Accordingly. fossil plant will be operating in a scenario in which it will be providing
the back up to wind power. It is the purpose of this paper to examine the implications of this.
2. The Wind Power Intermittency Issues
Most of the discussions about wind power have focused on how serious are the irregularities,
and if there are irregularities how much back of other plant will be needed. The Open
University has organised a conference on this and related issues and the papers are now
published in book form [8]. But many supporters of wind power argue that the chances of
zero wind energy being generated are insignificant. Statistical arguments are adduced in
support of these claims. It is also claimed that the demand for electricity can be reduced when
wind output falls. If the risk of zero or near zero wind is admitted to be significant, the
argument switches. It is then argued that electricity from hydro, wind farms in other countries,
or concentrated solar power, as in the Desertec scheme, can be imported into the UK.
The author, who is a supporter of wind power, considers that such arguments are correct, but
only up to a point. The cessation of wind power would have to be extremely infrequent, for it
not to be of concern. Some of the demand in the UK can be shed, initially by reducing voltage
and frequency, giving a “brown out”. The load reduction is unlikely to be much more than
about 10%., and is a standard operational procedure even now. Some further reductions can
be made by rescheduling demand, (e.g cutting off refrigerator motors), shutting off nonessential street lighting, and “voluntary” reduction of shop display lighting. It is doubtful
whether this would reduce demand more than another 10%.
The import of power from long distance renewable sources is also a possibility. It relies on
the development of HVDC ( High Voltage Direct Current ) Grids. These will be built whether
or not Europe starts to depend on renewables. On the Continent power sharing does go on
already, using the conventional alternating current grid. But HVDC will need to be built to
ensure the most economic operation of Europe’s generating infrastructure, since there is a
limit to how far AC power can be transmitted from a power station. For the UK, and Ireland,
all the connections to the Continent would have to be direct current. Without fossil back up
we would need at least 40 GW of undersea HVDC to ensure that the UK could “ride through”
windless spells, since not all of the nearby countries would be in a position to supply the wind
deficit. At present the total carrying capacity is less than 4GW.
These arguments are all about how much back up is needed by wind. That is, if the
Government’s target of 33 GW is reached, how much fossil plant would be needed, when a
big anticyclone covers the British Isles? The author’s estimate of back up is about 30GW.
This should bring a smile to both operators and constructors! But there is another issue, which
is rarely addressed. How often will fossil plants will be generating power, and how often
these plants will be taken off line when the output from wind is close to the total demand?.
3. Real Wind Energy Statistics
3.1 Limited data for UK
Much of the material relating to the output from wind farms is given in a statistical fashion,
intended to make a particular case. Although some actual data is available about the UK
situation, there are difficulties. The National Grid publishes the variation throughout the day,
as part of the NETA (National Electricity Trading Arrangements), but the data is not retained.
In consequence it is necessary to keep one’s own records, when attempting to make an
analysis. This the author has been doing for the last 15 months.
There are other difficulties. The National Grid data only covers the wind farms directly using
the high voltage transmission network. At the time of writing, this is only 1588 MW of
capacity out of a total of about 4000 MW for all of Great Britain. Furthermore, most of the
grid connected capacity is in the north of Scotland, so the results come from a fairly local, and
inherently windy area. Because cyclonic conditions tend to be quite localised, a high output
could be being generated in Scotland, whereas in the south of England, output from wind
farms could be much more modest. This is an important point, when assessing the impact that
wind could have on the operation of back up fossil plant. Anticyclonic condtions are different.
These can spread over an enormous area, so even if wind farms were evenly spread over the
UK, the power would be of the order of a few percent of nominal capacity.
3.2 Presentation of Data
Wind power data can be presented in a variety of ways, most of which are of little use to those
operating power plants, or those who need to decide what type of power plants should be built
to compensate for the intermittency of wind.
One of the most common statements is that wind “on average” produces about a power output
equivalent to one third of the nominal capacity. Figure 1 indicates some support for this figure.
Over a nine month period, Jan-Sept 2008, wind produced 29.7% of capacity. Figure 1 shows
that there is a large variation from one month to another. In January output was up to 45%,
but in June it fell to about 12%. of the maximum possible output.
Fig 1: Average Monthly Wind Power Jan-Sept 2009
50
Average Monthly Output %
45
40
35
30
Overall Average 29.3%
25
20
15
10
5
0
Jan
Feb March April
May
June
July
Aug
Sept
Even monthly averages are not very helpful. Figure 2 shows the daily power output, as a
percentage of the electricity generated if the wind farms had been working at maximum
capacity for the full 24 hours. Figure 2 shows that January 2008 was characterised by some
very windy days, in which output reached up to 80% of capacity, but the month started with
outputs of less than 10%. Other months in the year showed similar wide ranges in output.
They are probably caused by slow moving, low pressure areas, moving across the British Isles.
Fig 2 :Proportion of Wind Capacity on National Grid
Jan-Sept 2009
100.0
Average Daily Ouput %
90.0
80.0
70.0
60.0
50.0
40.0
30.0
20.0
10.0
0.0
0
30
60
90
120
150
180
Days Through 2009
210
240
270
300
3.3. Variations within the day
Operators of fossil power plants are used to having to vary output from day to night. In the
UK, at the present time, the daily variation in demand in winter is from about 55 GW during
the winter evening peak down to about 35 GW in the early hours of the morning. There is
about 7GW of base load nuclear on the system, the effect of which is to increase the need for
fossil power plants to load follow or two shift. The availability of about 3 GW of hydro and 23 GW of undersea direct current links to France and Ireland tend to dampen out the need for
cycling. So variability occurs even now, but the point is that both the demand and the supply
of electricity can be predicted with a high degree of reliability. Operators can also decide
months or even years in advance ( as is the case for nuclear) which plants to take off line for
maintenance or repair.
With wind energy, this is not possible. Figures 1 and 2 show that although there can be
extended low wind periods in the summer, even then there can be wide day-to-day variations.
Hence fossil plant needs to be in a good state of availability at all times. Hence, what the plant
operator really needs to know is how quickly the output from the wind sector rises and falls
during a one day period. Figure 3 is a method of showing what the operator may encounter.
Fig 3 : Typical Variation in Wind Output During One Day
Daily Windpower Variation in MW
1400
1200
Constant High
Output
1000
Very Irregular
Output
800
600
Constant Low
400 Output
200
0
1
2
3
4
5
6
7
8
9
10
Days Through Month
The bars on the chart represent the types of variation in power outputs which could come
from a set of widely distributed wind farms in the UK. These are schematic, but do represent
what actually happens, as will be shown later in the paper. Days 1 and 2 on the chart are a
period when there is little wind. In such conditions, a large proportion of back up plant would
need to be put on line. Over the full two days, the back up plant would be running at a
constant high level. Sales of electricity would be high, and, because the variations in load are
small, there would be little plant damage. The bars on Days 4 and 5 are the converse, where
the wind farm sector generates a lot of power at a fairly constant level. In these circumstances
fossil plant would be shut down, there would be no sales of electricity, but there would be a
risk of damage during start up.
Days 7 and 8 are the worst situation. On Day 7 the wind begins to drop quite quickly, so back
up plant has to be brought rapidly on line. On Day 8 the wind rises again so the fossil plant
has to be taken off line again.
Data of this type has now been accumulated for over 400 days, so enough information has
been obtained to make reasonable conclusions. Each day (the author’s holiday’s excepted)
the maximum and minimum outputs from the UK grid-connected wind capacity have been
logged. This data is then used to construct bar charts for each month. Those for September
and July 2009 are shown in Figures 4 and 5. The times of maximum and minimum outputs,
have also been noted, but for clarity are not shown on the bar charts. For the bigger daily
variations in wind power, the times between low and high outputs are typically between 12
and 24 hours. For both July and September the capacity connected to the Grid was 1426 MW.
Fig 4: Daily Variation in Power Output in September 2009
Daily Variation in Windpower MW
1200
1000
800
600
400
200
0
1
3
5
7
9
11
13
15
17
19
21
23
25
27
29
Days Through September
It will be apparent that in September 2009 there was a period of about ten days, in the middle
of the month, in which wind output was low. Back up plants would have been at full output
on Days 10 to 18, and it would have been a good continuous run. At the end of the beginning
and end of the month the fluctuations in output during the day were much more marked. On
Day 8, for example, the actual wind output reached about 75% of capacity, but it will be
apparent that despite the high amount of electricity generated, the minimum fell to about 600
MW and the maximum rose to 1100 MW during the day.
Fig 5 : Daily Variation in Power Output in July 2009
Wind Power Range in MW
1200
1000
800
600
400
200
0
1
3
5
7
9
11
13
15
17
19
21
23
25
27
29
31
Day in July 2009
Fig 6: Proportion of Maximum Possible Electrical Output
in July 2009
Proportion of Possible Output
100
90
80
70
60
50
40
30
20
10
0
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31
Days through July 2009
In July 2009, Figure 5 shows that the variations in wind output increased during the month.
By Day 31 the variations during each day had become very large, from about 130 MW
minimum to 1000 MW maximum. Compare this graph with a Fig 6, which is of the more
conventional type, which shows the actual power output for each day. Note that once the
electrical output reaches more than 15% of the possible, the variations in output became
significant. For example on Day 31, the power generated was only 28% of the maximum
possible of 34224 MWh ( from 1426 MW of capacity).The time period for this change was
less than 18 hours
4. Implications for Future Power plant Operation
The Government has a targets of 33GW of wind energy by 2020. Providing all the power is
used this would be equivalent to about 10 GW of conventional plant in continuous operation,
and would save an equivalent amount of gas and coal. These savings would only be realised if
wind farms got priority, and all other plant and inter connecters acted as back up.
Some of the implications of this for plant operation in 2020 can be considered using the data
from September 2009. During this particular month the maximum daytime power demand
varied between 38 and 46 GW. The minimum demand was about 28 GW and occurred during
the early hours of the morning.
In the middle of the month, the output from wind was low . On Day 15, the worst day for
wind, the output varied from 0.8% to a peak 4.8% of capacity Accordingly if we had 33GW
of wind on the system, on Day 15 the output from wind would have ranged from 0.3 GW to a
maximum of 1.65 GW. Hence, even the minimum early morning demand of 28 GW would
have required back equivalent of more than 26 GW. A good aspect of these low wind periods
is that the daily variation in wind output is quite low. This can be accommodate by a minor
amount of load following by those plants which are on line.
The situation at the beginning and end of the month is much more difficult. Day 4 was one of
the most difficult, when the output from wind changed from 263 MW to 929 MW. This
corresponds, in terms of 33GW of capacity, to a change from 6 GW to 21 GW. This implies
that about 15 GW of conventional plant capacity would have had to be taken off line, in order
to accept the daily variation in output from wind.
This change is about the same level as the day to night variation in demand which we
experience today. However, related to the question of the change in demand is the actual
power level from wind which on several days peaked at over 1100 MW. Scaling this to 33
GW of capacity, this corresponds to about 26 GW of output. But by 2020, the UK can expect
to have operating about 4 to 5 GW of nuclear plant. Accordingly there will be 30 GW of wind
and nuclear which will get priority over fossil plant. If high winds coincide occur at night, all
fossil plant and some of the nuclear will need to be shut down, for short periods.
The situation for fossil plant is not much better if the high winds in September occur during
the daytime when demand is higher. Peak demand ranges from about 35 GW during a
weekend in the early part of September, to mid-week evening peaks of 45 GW in the later
part of the month. Average daytime demand is around 40GW. It follows that between about 5
and 15 GW of fossil plant will be two shifting.
However, because of the irregularity of wind during the high wind periods, during the times
when the wind falls away to 6 GW and if the contribution from nuclear plant, hydro and
interconnecters is included, fossil plant will have contribute about 30 GW of power. A large
proportion of these fossil plants will need to be having to be run up from zero to maximum
output in a few hours.
5. Types of Plants for Wind Farm Back Up and Maintenance Issues
5.1 Operational Issues
The only plants which are being built in the UK at present are those of the CCGT type, and in
one respect they are reasonably good as back up. That is, discounting the impact on
component life, CCGTs can be started up and shut down very quickly. Operationally they
have some important drawbacks. Part load efficiency is not high, hence normal load range has
to be from 75-100%. And in the summer time, when air temperatures are high, gas turbine
output falls because of lower air densities and higher compressor inlet temperatures.
Hopefully, the reduced summertime demand will help compensate for this, but the reduced
hot weather output from CCGTs will create additional problems in the control of Grid
frequency and voltage.
At the present time the tendency is to use coal fired steam and nuclear plant for frequency and
voltage control, but as the amount of generating capacity falls from these, the onus will fall on
the CCGTs. Unfortunately, doing frequency control, using the gas turbine section of a CCGT,
is not a good idea. As Grid frequency decreases, because the CCGT is slaved to the Grid,
compressor speed falls and the amount of air flowing into the combustor drops. To prevent
turbine overheating, fuel must be reduced so the amount of power that can be generated also
drops. In short it is the beginning of a downward spiral to which the only solution is to reduce
the demand on the Grid.
If CCGTs are to assist properly in frequency and voltage control, the steam section of the
plant needs to be run partly throttled (so that extra steam turbine power can be made
available during a frequency dip). It should be noted that because of the irregularity of wind,
voltage and frequency variations are more likely to be encountered than we experience at the
present time.
Coal fired steam plants are good at load following, and can operated down to about 40% of
design output without too much loss of efficiency. The main drawback is a fairly long start
up time. This is not too much of a disadvantage when operating in today’s two shifting mode,
but will be more of a concern in 2020 when units have been taken off line for several days. As
the September and July figures show, steam plant would not be the best choice for back up, in
the late Spring, Summer, or early Autumn. They would be useful in the winter period, at least
up to the time when the combination of wind and nuclear did not reach a critical value.
We now come to those low emission plants, namely nuclear and steam plants of the CCS
(Carbon Capture and Storage) type. Because of the high capital costs, whether in the case of
the plants them selves, or because of the CO2 pipelines and storage sites for CCS units, the
intention is to use them for base load. It is clear, however, that once wind capacity reaches a
reasonably high level, the prospects for any type of base load plant are limited. Some of the
proponents say that future nuclear will be able to load follow, and there seems little doubt that
CCS steam plant will have reasonable load following ability. The issue will be operating costs.
In some countries OCGTs (One Cycle Gas Turbine) are used for back up. Back in 1970, the
CEGB considered building 20 GW of aeroderived gas turbines, running on gas oil. This is a
possible longer term option for the UK, and if public opinion continues to block the nuclear
and coal plant option (whether CCS or not), the OCGT could become the quick, emergency,
and politically acceptable solution. Very rapid start ups are possible from such units, and
since the alternator is not geared to the main gas turbine shaft , frequency and voltage control
is possible. Indeed such units fit very well into a distributed or grid. The main drawbacks are
that the gas consumption will be 30-40% higher than a CCGT and capital costs of the basic
equipment are likely to be higher.
5.2 Metallurgical Issues
The plants currently being built in the UK are CCGTs, and it is these which are likely to
provide the majority of the back up in 2020. Where thermal fatigue issues are being
investigated the focus should be on the equipment and components used in these plants,
rather than coal fired steam
CCGT gas turbine, hot section components are obviously at risk. Here, although modern
materials have helped, the main reason why turbine blades can tolerate inlet temperatures in
the 13-1400°C range is through the use of thermal barrier coatings and intense internal
cooling. Very high temperature gradients develop, and, in consequence, high stresses. The
materials used for blading are of the single crystal or directionally solidified type, which will
cause problems in both experimental testing and FE analysis.
Turning now to the steam section of the CCGT, this will be of more familiar ground to most
metallurgists. The main issues to be understood in experimental and life assessment
investigations are:
 That the rapidity of start up of CCGTs far exceeds that of conventional steam plant
 Every start up of the HRSG in a CCGT is effectively a cold start
 Without adequate draining, severe temperature differentials can develop between
adjacent tubes, resulting in high tube stresses and hogging and sagging of headers
 The compact design of HRSGs tends to result in poor tube-to-header welding practices
Whether the steam turbines in CCGTs are likely to be more severe stressed than in steam
plant is debateable. High pressure and reheat turbines (if fitted), are of smaller dimensions
than those used in steam plant. On the other hand temperature cycling is likely to be more
severe.
6. Discussion
Wind power is starting to have some operational effects in Britain already. On Easter Monday
2010, a holiday in the UK, high winds coincided with a period of low demand. In
consequence about 700 MW of wind capacity was disconnected from the Grid. If wind farms
are to be profitable, or make a real contribution to reducing carbon emissions, this cannot be
the general policy. .
Careful planning to compensate for the irregularities of wind is essential. Energy conservation
and measures to reduce CO2 emissions may have an adverse affect on the ability to use wind
power properly. Denmark is a country that has invested heavily in fossil fuelled cogeneration
and has installed a large amount of wind capacity. Unfortunately, in the winter time the
demand for heat results in cogeneration plants having to work at high output to provide
sufficient space heating. Although it is possible to vary the ratio of electricity to cogeneration
heat to some extent, when the wind farm output is high there can be a huge surplus of
power. This can go into the Nordic pool, where some is used for pumped storage. Some can
be sent to Germany. This tends to be at times when German wind farms are at high output and
power prices may be low. A number of independent studies have been made highlighting this
situation. Nevertheless, Denmark is able to rely on extensive alternating and direct current
grids to export its surplus wind and import power, when there is a deficiency.
Countries such as Spain and Portugal are better placed than Denmark to cope with wind
intermittency. They do not have extensive connections to the rest of Europe, but can rely on a
massive amount of hydro as back up.
Britain, and Ireland are not in the fortunate position as other European countries, They do not
have good connections to other parts of Europe, nor have much hydro capacity. It also seems
that even it existed, undersea HVDC connections to the Continent may not be of too much
value in the medium term, especially if North West Europe continues to expand its wind
capacity. When wind output is low is low here it tends to be low in Denmark, the
Netherlands, NW Germany and Belgium. The ideal situation is when Britain and Ireland are
short of power, these other countries are in surplus, but this is not the case .
The practical situation is that CCGTs will provide most of the back up. However, it appears
from a recent workshop in London on “UK's Future Power Options” that little consideration is
being given to either the financial or technical implications. One of the authors colleagues from his
days at British Gas, Chris Hodrien, and now a contributor to the Claverton Energy Group attended this
Workshop, and initiated a discussion on intermittency, following a presentation by Poyry on this
subject, whose analysis broadly followed the conclusions of this paper.
Hodrien’s summary of the discussion is given as an Appendix. The essential points are that wind
intermittency will play havoc with the pricing policy and that the CCGTs presently being specified are
base load designs. The intermittency of wind and need to bring fossil plant on line quickly will lead to
pricing spikes of up to £7700/MWh. When there is a wind surplus, prices could become negative.
How fossil plant operators will cope with this is debatable.
7. Conclusions
By 2020 the UK Government envisages that Britain will have 33GW of wind farms. To
estimate what are the implication for fossil and nuclear plant at that time, data has begun to be
collected from wind farms connected to the National Grid. So far, about 15 months worth of
data has been accumulated over period Jan 2009 to March 2010.
Three main features of wind farm output can be distinguished :
A: Low wind farm output for a number of days
B: High and steady wind farm output for a number of days
C: Wide fluctuations in wind farm output during each day
Both high and low steady outputs (Type A and B), present no particular operating problems
for fossil plants, although B could imply the need for plants to start up from cold or warm
conditions. This is in contrast to present day circumstances where genuine two shifting results
in daily hot starts. The most serious situation (Type C) as exemplified by wind farm output in
September 2009, is where there are wide daily fluctuations. In this, many plants would need
to suddenly go from cold start to full load , and then back to being off line in a few hours. In
some circumstances all coal, gas and electricity would need to be shut down for several days.
Of the plants being built CCGTs, although not ideal for coping with wind intermittency, are
more suitable than any form of coal fuelled steam plant. Although CCS and PWR nuclear
forms of power generation will be able to load follow, it seems unlikely that financial and
technical issues will preclude these being completely shut down, as is desirable when there is
a lot of wind energy.
It follows that future HIDA type studies should have as a focus the hot section components of
industrial gas turbines and the high temperature sections of HRSGs.
References
1 F.Starr, J. Gostling and A.Shibli “Damage to Power Plant Due to Cycling” ETD Report
1002-HP-1001 c/o European Technology Development Ltd 2000 www.etd1.co.uk
2 IA. Shibli and F. Starr “Damage to Combined Cycle Gas Turbines Due to Cyclic
Operation” ETD Report 1012-iip-09 c/o European Technology Development Ltd 2002
www.etd1.co.uk
3 Proc of Seminar on “Cyclic Operation of Power Plant- Technical Operation and Cost
Issues” ed Shibli, Starr, Viswanathan and Gray (2001) London, England
4 RP. Skelton and F. Starr, “Introduction and Report of Discussion to Seminar on
Cyclic Operation of Power Plant 2001” Materials at High Temperature 4, 18 (2001)
5 F. Starr “Cyclic Operation of Advanced Energy Conversion Systems: Past, Present
and Future” Proceedings 6th Parsons Turbine Conference Dublin, (2003)
6 F. Starr, E. Tzimas, M. Steen and S.D. Peteves “Flexibility in the Production of
Hydrogen and Electricity from Fossil Fuel Plants” IHEC Conference , Istanbul (2005)
7 F.Starr “Meeting the Challenge of Carbon Capture (Are some real issues being
neglected?)” pp 137-141 Energy Materials Vol 3, No 3 Sept 2008
8 “Renewable Electricity and the Grid-The Challenge of Variability” ed Godfrey Boyle,
Earthscan 2007
Appendix
C Hodrien, an experienced energy technologist, raised the renewables intermittency
issue during questions at the Advanced Power Generation Technology Forum/
Energy Generation & Supply KTN workshop on 'UK's Future Power Options' in
London on 17 March 2010. This note summarises some of the main points which came
out.
Poyry presented a short summary of their recent detailed Wind Intermittency modelling
study predicting the technical and market effects of the Government’s planned 33 GW
wind
power
programme.
They
had
identified
both
dramatic
future
intermittent/unpredictable supply/demand imbalances and the resulting 'nightmare' power
trading market impacts (occasional huge short-term spot market spikes up to £7700/MWh
and negative prices down to -£40/MWh!).
Poyry also emphasised that, if wind output were given priority due to its ROC support,
there would be a statistically significant frequency of occasions when all fossil plant was
backed-off, and even some events where up to half the nuclear capacity was backed-off
too. They foresaw that this would seriously adversely affect the operating economics of
remaining fossil (and even nuclear) plant on the grid, but did not touch in their short
presentation on the detailed technical issues of meeting the very rapid/large predicted
grid-wide load swings. Poyry described the impact of these demand swings on the
operation of fossil plant as ‘way beyond’ current plant 2-shifting practice. This also
'overlapped' with OFGEM’s presentation, where they admitted among other things that
the current market system was not currently paying sufficient for intermittent backup
services to enable the construction of new purpose-designed backup plant. Both
organisations were ringing loud alarm bells.
However, detailed costed near-term fossil-based technical solutions for coping with wind
intermittency to keep pace with the growing wind power programme were not highlighted
in any of the papers. The apparent issue that the predicted remaining fossil/ nuclear plant
mix over this period would cope very badly with the big load swings predicted by Poyry (in
terms of both energy losses, pollution emissions, operating economics and plant life
degradation) (and any new supercritical coal plant probably even worse), and that the
fossil fleet would become almost entirely devoted/relegated to wind backup duty by 2025,
did not seem to have dawned on the majority of the other conference speakers. There
seemed to be a rather naive, un-justified mind-set, especially from DECC and
Renewables UK (ex-BWEA), that the trading market ‘would somehow cope’ with the
existing/near-term mix of fossil plant. It appeared that neither DECC nor the UK power
industry had conducted any systematic study of the technically best plant types to provide
cycling backup services for the huge new wind fleet, never mind sanctioning or
encouraging their construction, a situation which Hodrien described as outrageous. In
particular, the idea that using purpose-built new-build high efficiency (42-47% LCV) gasfuelled OCGT turbines, especially rapid-start aeroderivatives such as the 64 MW RR
Trent-60 and the 100 MW GE LMS-100, could possibly be one of the best near-term
technical/economic solutions to the provision of renewables back up was apparently not
under consideration by any of the main players. Rolls Royce Energy gas turbines, maker
of the industrial Trent GT, were apparently not even at the Forum. Hodrien pointed out
that at least a significant minor part of their fuel could be obtained at high overall
efficiency and minimal GW impact from a large-scale programme of ROC-supported
renewable biogas (Anaerobic Digestion or gasification of bio-crops and wastes of all
types) supplied via the gas grid– this beneficial option too had clearly not been
considered.
An EON UK representative stated, during questions, that they had not specifically taken
projected wind back up service operation modes into account in designing their very
latest CCGT plants (with a 40 year future design life) and were not considering any opencycle units. Poyry stated that the operation of CCGTs at low load factors was already a
significant commercial issue. Furthermore they stated that investment in most new
CCGT's was already having to be justified on an average annual load factor as low as
900* hours/year (10%!) now, which could decline to only 100 hours/year (1%!) with 30
GW wind on the grid in 2030!
Hodrien comments that given this scenario in which even CCGTs experience very little
use, it is not surprising that no one is seriously interested in proposing new coal plant. It
also seems apparent that future scenarios will include a significant amount of nuclear .It
is the combination of variable wind plus high load factor nuclear which squeezes out the
demand from back up fossil plants, whether they are CCGTs or coal, as shown to
dramatic effect by the Poyry study.