Resilience from storage technologies and distributed generation
Introduction
3.1
This chapter begins by outlining the changing patterns of electricity
supply and demand. It then considers the challenges involved in integrating
renewable energy and decentralised forms of electricity generation into grid
networks.
3.2
The chapter then considers a range of energy storage technologies and examines
how storage technologies can contribute to the successful integration of
renewables and decentralised forms of generation and at the same time, improve
the resilience of Australia's electricity system.
3.3
Finally, the need for energy and storage system diversity is considered,
particularly in relation to the provision of certain necessary ancillary
services to grid networks.
Changing patterns of electricity supply and demand
3.4
One of the key challenges facing the electricity grid arises from the
rapidly changing nature of electricity supply and demand.
3.5
Australia has historically generated its electricity from a relatively
small number of centralised fossil-fuel power stations and delivered
electricity to a large number of consumers. However, the supply side of the
equation is undergoing rapid change. Dr Noel Simento, Managing Director for
Australian National Low Emissions Coal Research and Development, commented:
Our electricity supply has traditionally been delivered
through the state grids to state based grids and large interconnectors between
them. Our market systems were built on this basis, and it has served us well to
date in achieving a competitive objective. We are, however, in a period of
change and our commitment to reduce greenhouse gas emissions requires the
deployment of low emissions energy technologies at an increasingly rapid rate.
The inherent nature of these technologies is placing new demands on resilience
and the operation of a network to grid.[1]
3.6
At the same time, the demand side of the equation is shifting too. Over
the last several years, overall electricity demand in Australia has declined
due to factors including increased energy efficiency. Simultaneously, peak
electricity demand during extreme events (for example, prolonged heatwaves in
the summer months) has placed increasing strain on the generation and distribution
system during those periods. This trend has been quickened by the increasing
uptake of rooftop solar by households in Australia, which means that demand
from large-scale generators is lessened during the middle of the day. Mr Robert
Riebolge, Chief Network Analyst for 1414 Degrees, described these changes in
electricity demand to the committee:
The electricity demand profile in most Australian
jurisdictions is becoming characterised by peaks and troughs that are
increasingly widening and a baseload that is decreasing so that the ratio of
the difference between the peak and the trough to the base is increasing. The
generation mix and market rules in Australia have not been designed to meet
this kind of demand profile, so the resilience of the electricity
infrastructure will continue to deteriorate if measures are not put in place to
address this problem quickly.[2]
3.7
In addition, there is the rise of what has been termed the 'prosumer', meaning
an increasing number of households that also produce as well as consume
electricity. The interactions between the changing nature of electricity supply
and demand, the changing nature of generation technologies, the rise of the
'prosumer' and distributed electricity production, and the solutions offered by
various energy storage technologies are covered in the following sections.
Integrating renewables into the electricity system
3.8
The integration of renewables into the electricity system was acknowledged
by Energy Networks Australia as 'inevitable'.[3]
3.9
Despite this, it is clear that the pathway to ensuring this integration
is accomplished successfully is still being developed. For example, the
Australian Renewable Energy Agency (ARENA) outlined some of the challenges of
guaranteeing security and reliability in the electricity system and the need
for 'whole-of-system change across technology, markets and regulation' to
ensure successful integration:
As the mix of electricity generation changes to a higher
level of renewables, Australia's electricity system will need to continue to
provide secure, reliable power with more diverse, variable and distributed
energy sources. This will involve a higher level of integration with flexible
capacity, smart control systems, demand management, and improved technical standards
to help withstand unexpected and extreme events.[4]
3.10
AEMO told the committee that it is currently a challenge to integrate intermittent
renewables into the electricity market:
AEMO sees the changing generation mix, with more asynchronous
generation and intermittent generation as a challenge to the security of the
system. Our ability to balance the security and reliability of energy supplied
by these new technologies against the changing needs and preferences of the
consumer is a primary focus for AEMO. The challenges arise in managing everyday
'credible contingencies', as we call them, as well as in extreme events.[5]
3.11
AEMO outlined the work it is currently doing to address these
challenges:
To help us deal with these issues, AEMO is conducting ongoing
work in our Future Power System Security program, which aims to identify and
quantify the challenges of main power system security in the NEM. We are also
working in collaboration with the AEMC to change the market and regulatory
frameworks to ensure these issues are managed into the future.[6]
3.12
Dr Evan Franklin, a fellow of the Energy Change Institute at the Australian
National University (ANU), acknowledged the intermittent nature of renewable
energy production from wind farms, solar farms and rooftop PV. He noted that
one possible solution would be to have 'levels of ramp rate control' so that
the power output from wind and solar PV does not fluctuate so rapidly. Another
option would be to limit the speed with which intermittent generators could
alter their output. However, Dr Franklin observed that requirements or
incentives would be needed to bring about the widespread adoption of these
changes by companies and individual homeowners.[7]
3.13
Mr John Bradley, Chief Executive Officer of Energy Networks Australia, was
of the view that a new and more active role would be required from electricity
distribution businesses to help integrate renewables into grid networks:
The transition there to integrate renewables into the
distribution system is to move towards much more active management—having good
sensing, so you can see the power quality, the voltage rise, the fluctuations
and power quality occurring in the network, and you can anticipate and respond
to that.[8]
3.14
Meanwhile, the Australia Institute submitted that what were previously the
two key obstacles to the widespread adoption of renewables, namely price and
intermittency, are now capable of being resolved:
Solar and wind costs have fallen so rapidly over the past
decade that they are now competitive with fossil fuels, so the price argument
is losing traction [while] battery and other forms of storage technology are
rapidly overcoming the variability argument.[9]
3.15
However, Mr Oliver Yates, Chief Executive Officer of the Clean Energy
Finance Corporation, pointed out that, in order to address the issue of
intermittent generation, there needed to be far greater investment in large-scale
storage technologies and electricity distribution infrastructure. However, he
also noted that storage technologies faced 'regulatory challenges in entering
the market'.[10]
3.16
The Clean Energy Finance Corporation set out what they saw as the key
factors that needed to be planned for in order to achieve a balanced grid:
-
diverse generation technologies within the system;
-
geographically diverse generation technologies so that
uncorrelated renewable resources can be drawn on from across Australia;
-
strong transmission interconnections between regions to move
power around Australia to balance supply and demand;
-
large-scale storage, whether it be in batteries, solar-thermal, pump
hydro or the coordination of small-scale batteries; and finally
-
markets and a regulatory system that encourage all of these factors
to occur at the same time.[11]
3.17
Similarly, Dr Matthew Stocks, a fellow of the College of Engineering and
Computer Science at the ANU, also noted that the current transmission network
is very weak. He argued that both storage and stronger inter-state connections
would be crucial elements in strengthening the resilience of the electricity
network because improved interconnections would strengthen the whole network
and allow stored energy to be shared more easily between states.[12]
3.18
However, Dr Stocks also made the important point that even in the case
of a grid supplied solely by renewable energy, the amount of storage required
to balance the system and the additional costs was less than might be imagined:
The work that we have done there demonstrates that, if you
distribute this generation very widely and develop an appropriate transmission
network, you need a surprisingly small amount of storage and a relatively small
amount of support to ensure that you can have a reliable balancing of energy
supply over that five-year period. We have shown that the additional premium is
quite small. We are talking less than three cents a kilowatt hour to enable the
entire system to behave in a balanced manner in order to ensure that the energy
is distributed across the country in such a way that you meet all of the
vagaries of the supply and demand in the network.[13]
3.19
The role of storage technologies in helping to integrate diverse renewable
energy generation technologies into the electricity system is discussed next. The
issue of markets, policies and regulations is discussed later in chapter 4.
New opportunities arising from storage technologies
3.20
As noted at the beginning of the chapter, the supply and demand for
electricity in Australia is undergoing rapid change. The so-called baseload
generators such as coal-fired power stations that have dominated Australia's
electricity production in the past are relatively inflexible: that is, they are
unable 'to quickly increase or reduce supply on a minute-by-minute or
hour-by-hour basis'.[14]
3.21
In addition, the ability of consumers to modify their electricity demand
is relatively limited at present. The end result of the inflexibility inherent
in the current approach to supply and demand is an excess of electricity
generation capacity because there has to be sufficient supply to meet peaks in
demand.[15]
3.22
Mr Oliver Yates, Chief Executive Officer of the Clean Energy Finance
Corporation explained to the committee that the real-time matching of supply
and demand is very rare in markets, and consequently requires some form of
balancing:
The concept of a market where [a good or service] is produced
and sold immediately, absolutely perfectly matching demand, does not exist in
many markets around the world. In many markets, there is always a period where
demand does not equal supply, and it is important that it is balanced out. [16]
3.23
Furthermore, as noted in the previous section, the increasing amount of
intermittent electricity generation in the network poses an additional
challenge in balancing supply and demand. The committee received evidence from
a range of witnesses that energy storage would have significant value in
balancing periods of shortage and excess in electricity supply and demand and
was the key component that would allow a high penetration of intermittent
renewable energy into the grid. [17]
3.24
For example, Dr Stocks made the point that Australia actually has excess
energy capacity:
We do not, in this country, have a shortage of energy; we
have a vast oversupply of energy capacity. What we have is periods of deficit
and periods of excess, and storage is very good at being able to come in and
fill that gap.[18]
3.25
Similarly, Mr Justin Flint pointed out in his submission that the
increasing availability of cost-effective storage technologies would allow a
situation where supply exceeded demand to be managed because the energy could
be stored. Conversely, where demand exceeded supply, the system could draw on
the stored energy.[19]
3.26
In addition, storage technologies can respond far more rapidly to
changes in demand than a large traditional power station. This supply response
would be further enhanced by modern communications technologies and distributed
generation.[20]
3.27
AES Energy Storage submitted that energy storage should be considered as
a viable alternative to building new generation capacity:
Power systems that need new capacity – whether it is to meet
growing peak demand or to compensate for the retirement of aging thermal
generation – should be evaluating energy storage as an economic alternative to
building new generation.[21]
Types of storage technologies
3.28
The following sections consider three types of storage technologies:
-
battery storage;
-
pumped hydro technology; and
-
thermal storage.
Battery storage
3.29
Dr Evan Franklin, a fellow at the Energy Change Institute at the ANU,
told the committee that while battery storage is an old technology, recent
advances in lithium batteries have brought the costs down.[22]
Dr Franklin noted that battery storage has already become a sizeable
industry with the result that battery storage 'can be deployed now'.[23]
3.30
Similarly, Mr Ivor Frischknecht, Chief Executive Officer of ARENA, told
the committee that while battery storage technology had historically been very
expensive, costs had fallen and would continue to fall significantly.[24]
3.31
Mr Frischknecht noted that ARENA was currently 'in the process of demonstrating
a whole variety of different ways of deploying storage and, very importantly,
getting value from storage'. Mr Frischknecht emphasised the point that getting
value from battery storage was critical to ensuring deployment on a commercial
basis.[25]
The issue of allowing batteries to capture appropriate value is a critical
matter and one to which the committee returns in the following section.
3.32
At the household scale, Mr Osborne observed that a house with a smart
battery system should be able to supply about 80 per cent of its own needs, and
buy the remaining 20 per cent 'when it is cheapest and most abundant in the
grid'.[26]
3.33
The next step beyond the generation of electricity on rooftops is the
imminent deployment of substantial amounts of battery storage. Mr Osborne noted
that Morgan Stanley has predicted that Australia could have five gigawatts of
battery storage by around 2020. As Mr Osborne noted:
...so we are going to move that five gigawatts from being out
of control, going up and down with the sun, to being in control by 2020. So it
will be the biggest controlled power station—about three or four times bigger
than Tumut 3 pumped hydro dam—by 2020. So that is not very far away. It is very
rapid.[27]
3.34
Dr Franklin told the committee that predictions about the future
uptake of battery storage systems at the household level in Australia vary from
a million in 2025 (Morgan Stanley) to 2.5 million in 2035 (Bloomberg New Energy
Finance). Dr Franklin set out both the scale of the predicted contribution
to the grid:
Two-and-a-half million households with a battery storage
system would end up being equivalent to something like 10 gigawatts of power
generation capacity if it was arranged so that it could be deployed when
required.[28]
3.35
Dr Franklin also explained the mechanism by which battery systems could
charge and discharge:
Battery systems can discharge and charge very rapidly... You
would normally charge batteries from solar during the day, of course, and have
that available in the evening. If you depleted all of the batteries in the
evening, then you would require other sources: wind or other generators to
provide that recharging of batteries.[29]
3.36
The committee also received evidence about the development of utility
scale battery storage from Australian companies including Lyon Group and Zen
Energy.
3.37
Mr David Green, a partner in Lyon Group, told the committee that over
the past two years, Lyon Group has brought together more than 1500 MW of solar
PV utility-scale projects and more than 1000 MW of large-scale battery storage
projects. Both the solar PV and battery storage projects are ready to be
deployed and be operational within two years.[30]
3.38
Mr Green also noted that funding for the solar PV projects was
underpinned by a major United States fund. The utility-scale battery storage would
be developed in Australia in alliance with Mitsubishi Corporation and AES (headquartered
in the United States).[31]
3.39
State and territory governments have embraced not only renewable energy
generation, but are also focused on battery storage. For example, Mr Simon Corbell,
a former Australian Capital Territory (ACT) Environment Minister, explained the
ACT's Next Generation Renewables Program which started in early 2016:
...the ACT government embarked on a significant program of
supporting and subsidising the rollout of battery installations at 5000
individual household and small business sites across the territory. That program
is ongoing and it highlights the importance of providing support to new
technologies to bring forward their deployment at scale, to allow lessons to be
learnt about how that deployment can take place in the most efficient way, and
to build support for a growing industry.[32]
3.40
In his current role as the Victorian Renewable Energy Advocate, Mr
Corbell told the committee that the Victorian state government had decided 'to
invest significantly in large-scale battery storage to improve grid stability
and provide for dispatchable load into the Victorian NEM region'. Mr Corbell
noted that the Victorian government had committed to developing '20 megawatts
of large-scale battery storage in grid-constrained parts of the state'.[33]
3.41
Nevertheless, the committee received evidence which suggested that even
though battery prices are declining rapidly, other storage technologies are
more cost-competitive at a utility-scale:
Battery storage technology is rapidly advancing and costs are
declining fast as production increases to meet growing demand from electric
vehicles and stationary energy storage applications. However, the cost of
batteries for bulk energy storage is still relatively high (compared to both
wholesale costs of energy and compared to other forms of bulk energy storage –
thermal and hydro in particular). This means that small, behind-the-meter
battery systems, the market being driven by retail tariff margins, will
dominate over utility-scale battery systems for some time to come.[34]
Committee view
3.42
The committee notes that the large-scale deployment of batteries at both
household level and utility-scale is imminent and will occur rapidly from this
point.
3.43
The committee considers that the rapid uptake of battery storage will
help deliver important elements of system security relatively quickly compared
to other generation and energy storage systems.
3.44
The committee is also of the view that the installation of batteries at
the household level would provide citizens with greater control over their
power and the committee returns to this theme later in the chapter in the
section on distributed generation and storage.
3.45
The committee is also aware that there are certain regulatory barriers
currently hindering the rapid deployment of storage technologies, and this
matter and associated recommendations are presented in chapter 4.
Pumped hydro storage
3.46
This section outlines two distinctly different types of pumped hydro:
-
large river-based pumped hydro storage; and
-
small off-river pumped hydro storage.
Traditional large river-based
pumped hydro
3.47
Pumped hydro has traditionally been based on large rivers. Large river-based
pumped hydro storage is a well-established technology that has been in place in
Australia and other countries for decades. Dr Stock informed the committee that:
There are more than 150 gigawatts deployed around the world,
including two gigawatts deployed within the Australian network in Tumut 3 in
the Wivenhoe scheme and also in the Shoalhaven.[35]
3.48
The ANU Energy Change Institute informed the committee that owing to its
relatively low cost, pumped hydro was the dominant form of energy storage
world-wide:
Pumped hydro energy storage is the dominant form of worldwide
energy storage because it is an established technology, is cheap and provides a
broad range of support services for the electrical grid. Water is pumped up a
height difference when there is excess energy generating capacity available
(i.e. when it is low cost) and the water is released to generate power when demand
(and hence cost) is high. Owing to its comparatively low cost, over 96% of all
energy storage installed in global electrical power systems to date have used
pumped hydro technology.[36]
3.49
However, large river-based pumped hydro storage systems have significant
environmental impacts and developments have been hotly disputed in the past. In some
cases large river-based pumped hydro storage systems have been part of water
management and diversion systems such as the Snowy river scheme. Such schemes
have delivered water to farms, but have environmental costs, including the
degradation of the diverted river.[37]
Off-river pumped hydro
3.50
Pumped hydro storage can also be operated off-river. The ANU Energy
Change Institute submitted that the small size of off-river pumped hydro means
that a wide range of sites could be developed across Australia:
Recent research, meanwhile, has shown that there are numerous
excellent sites in Australia for systems which are off-river, requiring
relatively small reservoirs (oversize farm dams) at the top and bottom of hills
with the water cycling between as supply and demand varies. Abandoned mines may
also be used as reservoirs, as per the proposed Kidston mine being developed by
Genex.[38]
3.51 The Alternative Technology Association informed the committee of
research undertaken by the Melbourne Energy Institute:
According to the Melbourne Energy Institute (MEI), the best
option is to build a dam on a tall hill or cliff. This height creates strong
water pressure, enabling significant energy to be stored with a relatively
small dam. Suitable sites are plentiful, and the theoretical cost is $200 per
kWh of usable storage capacity. When added to a solar farm, a dam to store 5
hours of generation would increase the system cost by about 25%.[39]
3.52
The Melbourne Energy Institute has developed the following table which
provides a comparison of conventional large river-based hydro, and off-river
pumped hydro systems. One of the key findings arising from the comparison is
that the much smaller size of off-river pumped hydro storage means there are
thousands of potentially suitable sites in Australia.
Table 3.1: Comparison of conventional hydro power and
off-river pumped hydro.
|
Conventional large river hydro |
Off-river pumped hydro |
Purpose |
Energy generation, irrigation, flood control, recreation |
Short-term energy storage and use |
Electricity output |
High |
High |
Water requirement |
Once-through, no recycling |
Recycled. Make-up required for evaporation minus rainfall |
Water storage period |
Months or years |
Hours |
Reservoir size |
Can be > 10,000 hectares |
5 to 50 hectares |
Location |
Yes |
Can be off-river using 'turkey-nest' |
Number of possible sites
in Australia |
Limited |
Thousands |
Source: Melbourne Energy
Institute, Pumped Hydro Energy Storage.[40]
3.53
Genex submitted that off-river pumped hydro systems have advantages
relative to battery storage systems:
-
large scale (e.g. able to provide storage for macro scale wind or
solar PV farms);
-
long lived asset—up to a century life-cycle;
-
clean and environmentally sustainable form of energy storage that
requires less mining of rare elements and less toxic materials to recycle or
dispose of after use than chemical storage systems; and
-
poses no fire risk.[41]
New off-river pumped hydro
developments in Australia
3.54
The committee notes that the Clean Energy Finance Corporation and ARENA
are assisting Genex Power to investigate the feasibility of developing an off-river
pumped hydro scheme in an old mining site at Kidston in Northern Queensland.[42]
3.55
Genex Power (Genex), an Australian public company, is currently developing
a large-scale hydroelectric pumped storage project in an old gold mining site at
Kidston in Northern Queensland.[43]
3.56
The Clean Energy Finance Corporation and ARENA provided funding for Genex
to conduct a technical feasibility study which is now complete.[44]
3.57
Genex notes that the Kidston pumped hydro storage project will be a
closed loop system that will transfer water from an upper to a lower reservoir.
The lower storage reservoir will be the existing Eldridge Pit. The upper
storage reservoir will be a 'turkey's nest' type dam constructed on the waste
rock dump to the north of Eldridge Pit. The project will also utilize the
existing Wises Pit to act as a balancing storage to hold excess water and to
mitigate flood risks.[45]
3.58
The completed Kidston pumped hydro project will have an installed
generation capacity of 250MW, with a total energy storage capacity of 1500MWh
based on a 6 hour full generation cycle.[46]
3.59
It is also possible to develop pumped hydroelectricity storage using
seawater and a cliff-top dam such as the facility in Okinawa, Japan.[47]
3.60
One such project has already been identified in Australia with ARENA
providing EnergyAustralia with $450 000 to conduct a feasibility study for
a 100MW to 200MW pumped hydro storage project close to Port Augusta and Whyalla
in South Australia's Upper Spencer Gulf.[48]
3.61
The committee also notes that ARENA has funded an ANU study to identify
potential off-river sites across Australia.[49]
Committee view
3.62
The committee draws attention to the significant difference between
traditional hydroelectric generation that involves the damming of rivers as
compared to off-river pumped hydro that can be installed on a much smaller
scale with minimal negative environmental impacts.
3.63
The committee considers that off-river pumped hydro-electricity storage
has the potential to provide a significant contribution to the effective
operation and resilience of Australia's electricity systems.
3.64
The committee also notes the potential for coastal pumped hydro storage
which only requires a single reservoir, is not susceptible to drought or
evaporation, and has the potential to be co-located near wind and solar
electricity generators.
3.65
Combining renewable generation systems with nearby off-river pumped
hydro can provide an excellent way to balance the variable timing of renewable
electricity supply with the fluctuations in electricity demand.
3.66
The committee also notes that a combination of pumped hydro, batteries,
and thermal storage has the capacity to provide a full range of ancillary
services required for electricity system stability and this matter is dealt
with later in this chapter.
3.67
Finally, the committee received evidence about regulatory changes that
could encourage the deployment of large scale pumped hydro (and thermal energy)
storage systems. These matters are discussed in chapter 4.
Thermal energy storage
3.68
Thermal energy storage is a technology that stores thermal energy by
heating or cooling a storage medium so that the stored energy can be used at a
later time for heating and cooling applications and power generation. There are
three kinds of thermal energy storage systems:
-
sensible heat storage
that is based on storing thermal energy by heating or cooling a
liquid or solid storage medium (e.g. water, sand, molten salts, rocks);
-
latent heat storage
using phase change materials or PCMs (e.g. from a solid state into a
liquid state); and
-
thermo-chemical storage
(TCS) using chemical reactions to store and release thermal energy.[50]
3.69
The International Renewal Energy Agency summarised the relative
performance of the above systems as follows:
A TES [thermal energy storage] system's economic performance
depends substantially on its specific application and operational needs,
including the number and frequency of storage cycles. In general, PCM and TCS
systems are more expensive than sensible heat systems and are economically
viable only for applications with a high number of cycles. In mature economies
(e.g. OECD countries), a major constraint for TES deployment is the low
construction rate of new buildings, while in emerging economies TES systems
have a larger deployment potential.[51]
The storage of thermal energy (typically from renewable
energy sources, waste heat or surplus energy production) can replace heat and
cold production from fossil fuels, reduce CO2 emissions
and lower the need for costly peak power and heat production capacity. In
Europe, it has been estimated that around 1.4 million GWh per year could be
saved— and 400 million tonnes of CO2 emissions
avoided—in the building and industrial sectors by more extensive use of heat
and cold storage. However, TES technologies face some barriers to market entry.
In most cases, cost is a major issue. Storage systems based on TCS and PCM also
need improvements in the stability of storage performance, which is associated
with material properties.[52]
3.70
Many applications of thermal energy storage use and store heat directly,
however the technology can also be effective for storing or creating electrical
energy. The committee was informed about two types of thermal energy storage
for electricity, one based on molten salt and the other based on molten
silicon.
Molten salt with solar-thermal
power
3.71
Molten salt and related thermal storage technologies are often used in
conjunction with concentrating solar-thermal power (CSP) systems. CSP systems use
a large array of mirrors to concentrate sunlight onto a 'receiver' where the
energy is collected by heating a fluid. This fluid can be stored and used later
to make steam and run a turbine to produce electricity.[53]
3.72
The ANU Solar Thermal Group explained that CSP with integrated storage
was capable of delivering utility-scale round-the-clock solar energy:
The particular benefit of CSP is that its configuration
allows energy storage as an easily and cost effectively integrated part of the
system. Systems with as much as 15 h of storage capacity have been installed
(eg Gemasolar, Spain and Crescent Dunes, USA), achieving commercial supply of
24-h solar energy for the first time.[54]
3.73
The ANU Solar Thermal also noted the potential for CSP systems to be
hybridised in order to manage the transition to a totally renewable electricity
grid:
CSP systems can also be hybridised with small amounts fossil
or biomass fuels, for higher levels of reliability with minimal redundant
equipment, a configuration which may [assist] in a reliable migration towards
100% renewables in coming years. CSP systems can also be beneficially
hybridised with other renewables such as PV.[55]
3.74
The Australian Solar Thermal Energy Association told the committee that
most new CSP systems and more than half of the existing CST systems incorporate
intermediate storage use molten salt thermal energy storage to provide
dispatchable energy:
Concentrating Solar Thermal Power plants use steam turbines
with synchronous generators for power generation and have thermal energy
storage built in to the overall system for typically 6-15 hours of full load
operation at any time that dispatch is desired. Their ideal size is in the
range 50–250MW.[56]
3.75
Importantly, CSP also provides a range of ancillary benefits
traditionally supplied by coal-fired generators and are capable of being
configured to provide black-start capability.[57]
3.76
The ANU Solar Thermal Group argued that while CSP with storage is more
expensive than wind and solar PV systems (that provide no storage or ancillary
benefits), studies in the United States indicate that CSP with storage is
cheaper than batteries (and likely to remain so for the foreseeable future) and
pumped hydro.[58]
3.77
Further advantages of CSP with molten salt storage include:
-
minimal carbon footprint;
-
ability to withstand changing climatic conditions;
-
a decrease in the annualised cost of electricity with integrated
storage; and
-
significant potential job creation from production of local
content.[59]
Molten silicon
3.78
The committee was informed about another thermal energy storage
technology based on molten silicon. Silicon has a high melting point, 1414
degrees Celsius, which allows for high efficiency energy recovery relative to
lower temperature thermal technologies.[60]
3.79
1414 Degrees Limited is a South Australian company set up to
commercialise a Thermal Energy Storage System (TESS) originally developed by
the CSIRO. 1414 Degrees informed the committee that TESS possesses a
significant competitive advantage over other storage technologies because of
its scalability and high energy density:
The heat store is constructed from readily available, low
cost components and production units will be containerised and modular.
A TESS module approximately the size of a 40ft shipping container could
house 10MWhth of energy storage and to scale up, modules may be
added and to scale down, modules may be removed or smaller ones manufactured.
For all sizes of the TESS, the heat store shares a common design principal.[61]
3.80
The committee was informed that the TESS was well suited to medium scale
energy storage and had a number of advantages, including:
-
the potential to be installed in any location;
-
low environmental impact due to use of abundant, relatively
non-toxic materials;
-
an ability to supply both electricity and heat;
-
simultaneous and rapid charging and discharging;
-
the potential to be very cost effective; and
-
the ability to provide ancillary services as the energy recovery
system will be a rotating generator.[62]
3.81
Silicon based TESS is complimentary to other storage technologies as
shown in the following table. It can operate as:
-
smaller 'behind the meter' technology (TESS-EC (energy consumer))
for commercial energy consumers that require heat as well as electricity; or
-
bulk grid storage technology (TESS-GRID).
Table 3.2: Comparison of energy storage technologies
Rating
|
Technology
|
Discharge time
|
Efficiency
|
Network benefits
|
<10MWh/h
|
TESS-EC
Super capacitors
Lithium Ion
Advanced Lead Acid Flow Batteries
Sodium sulphur
|
High hours
Minutes
Low hours
High hours
|
Medium
High
High
|
Demand management
Peak shaving
Peak shifting
Time of use tariffs
PV self-sufficiency
Network augmentation deferral
|
Between 10MWh/h and 100MWh/h
|
TESS-Grid
Molten salt
Compressed air energy storage
|
High hours
|
Medium
Medium
Low
|
Network augmentation deferral
Congestion relief
Utilisation of surplus renewables
Frequency regulation
Spinning reserve
Voltage support
|
100MWh/h
|
Pumped hydro storage
|
High hours
|
Medium
|
Frequency regulation
Spinning reserve
Voltage support
Arbitrage
|
Key: TESS-EC = 'behind the
meter' Energy Consumer storage technology
TESS-Grid = bulk
grid storage technology
Source: 1414o, Submission
51, p. 3.
Committee view
3.82
The committee considers that thermal storage technologies such as those
discussed above have the potential to make significant contributions to the
operation and resilience of Australia's electricity networks. The committee
views these technologies as being complementary to other storage technologies,
including batteries and pumped hydro. In particular, it appears that thermal
storage technologies may offer a number of advantages for medium or
intermediate scale storage of electricity and other forms of energy.
3.83
From the evidence that the committee has received it appears that there
is an abundance of complementary technology options for energy storage to
facilitate the operation and resilience of Australia's electricity networks.
Ancillary services provided by a diversity of energy storage systems
3.84
A range of ancillary services such as system inertia, spinning reserve
and synchronous capacity for frequency and voltage support are essential for
the security of the electricity system.
3.85
One of the main arguments traditionally raised against the greater use
of intermittent renewable energy is the inability of renewable technologies to
provide the ancillary services that were typically rendered by fossil
fuel-fired power generators.
3.86
Dr Noel Simento, Managing Director of the Australian National Low
Emissions Coal Research and Development, explained that traditional synchronous
generators such as coal-fired power stations have traditionally provided
inertia and voltage support to the network at no additional cost.[63]
3.87
Mr Karl Rodrigues, Acting Director of Energy at the CSIRO, acknowledged
that while storage technologies would be particularly useful as a means of
sharing the increase in intermittent renewable electricity in the grid, he
noted that some means of providing system inertia would still be needed for
frequency control.[64]
3.88
However, the committee received evidence that a diversity of storage
technologies, in addition to providing a readily available source of power, can
support other aspects of electricity network operations and resilience,
including black-start capabilities, an issue that has become particularly
pertinent in the aftermath of the power black-out in South Australia in September
2016.
3.89
The Energy Change Institute explained that the characteristics offered
by pumped hydro vary according to how it is configured:
Pumped hydro plants can be configured in a number of
different ways: most plants use a single turbine/pump set and a single electric
machine (generator/motor), but some may use a separate turbine and pump with a
single machine, or for greatest flexibility but highest cost a separate
turbine-generator and pump-motor configuration. Configuration and electric
machine type together determine the ability of the plant to offer flexibility
in terms of power system operation.[65]
3.90
The Energy Change Institute also explained how direct electro-mechanical
synchronous pumped hydro can provide black-start capability
Synchronous pumped hydro systems can provide black start
capabilities without requiring additional power generation support. Such
systems are thus well-suited to rapid recovery after region-wide black events
(such as occurred in the South Australian system in September 2016) with
conventional hydro plants typically considered be the generator of choice for
initiating system black starts.[66]
3.91
Genex noted that pumped hydro 'has the potential to support grid
stability through inertial spinning reserve and very fast ramp rates from zero
to 100 per cent in minutes'.[67]
3.92
The Energy Change Institute set out the contributions that a diverse mix
of storage technologies could contribute to the resilience of electricity
infrastructure—including very fast primary frequency response, spinning
reserve, inertia, voltage stability, energy balancing, and black-start
capability—as Australia transitions to an electricity system based largely (or
even solely) on intermittent renewable generation:
-
Battery storage will provide:
-
very fast dynamic primary frequency response;
-
secondary response (or spinning reserve) services;
-
local demand smoothing; and can also
-
facilitate islanded or microgrid operation.
-
Pumped hydro technology will be used for:
-
provision of inertia;
-
primary frequency response;
-
secondary spinning reserve;
-
medium term (in the order of days) energy balancing;
-
voltage stability; and
-
black-start capabilities.
-
Concentrating solar power with thermal storage can provide:
-
inertia;
-
voltage stability;
-
short to medium term (hours to overnight) energy balancing;
-
some spinning reserve capability; and
-
black-start capabilities.[68]
Benefits arising from decentralised electricity generation
3.93
Some of the challenges facing Australia's electricity system have arisen
from a lack of diversity and the centralisation of electricity generation and
storage which makes the system inflexible and unable to respond to challenging
events. In the past the system has been characterised by a small number of
large scale generation facilities and a very small number of large scale
storage systems (large river pumped hydro such as the Snowy scheme). Mr Steve
Blume, President of the Australian Solar Council, provided an example of the
potential challenges facing centralised systems:
Take, for example, the UK. If they build that nuclear power
plant of 2,000 gigawatts, that will be eight per cent of their electricity
system. If that goes out, even for maintenance, what do you use to get the
eight per cent when that is not running? It is a big question. If you start
relying on individual things that is what will happen.[69]
3.94
In contrast to the challenges facing a centralised system, several
witnesses commented on the potential benefits of decentralising electricity
generation in Australia through the further uptake of household solar PV and
battery storage.
3.95
Innovative approaches are springing up without market intervention. The
committee heard evidence from software providers, Reposit Power, about the
'community power station' concept:
We add intelligence to home and business energy systems, so
these are home and businesses that are investing in solar panels on their roofs
and batteries, usually wall-mounted batteries. We do a couple of things. One is
we make those systems achieve a lower bill for the consumer by adding
intelligence behind the meter, making those systems interact better with
appliances that they have in their home and business. We also allow those
systems to band together when it makes sense and form what I will call for
today a 'community power station'. That is a power station that can operate
very much like a hydro dam or a pump storage dam: it can consume energy when it
is cheap and produce energy when it is expensive. When it is not required,
those systems all go back to helping the home or business have a low energy
bill and a good interesting electricity experience.[70]
3.96
Mr Luke Osborne, Director and Chief Operating Officer of Reposit Power,
expanded on the potential of the 'community power station' to provide
resilience through distributed generation:
It is decentralised...this power station is everywhere. It is
everywhere where there are homes and businesses, and already there are 1½
million homes and businesses that have solar panels on their roofs, and they
are distributed everywhere there are populations. So decentralisation is
inherently safer, if you like, than centralisation because you do not have a
point of failure. If we think about what happened in South Australia: we lost
transmission lines, which then led to the loss of the interconnector, which
then lost the whole state. Those are problems of centralisation. You do not
have that in a decentralised world. We can lose one or two houses or one or two
businesses, but that is not important in the context of the whole community
power station.[71]
3.97
Dr Andrew Mears, Director and Chief Executive Officer of SwitchDin,
similarly argued that decentralised electricity generation would help
future-proof electricity infrastructure by increasing system resilience:
a decentralised energy service based around renewable energy
technology and battery storage is a key factor for building a futureproof and
resilient electricity infrastructure. What has happened in many countries,
including Australia, is that we have seen a deconvolution of the energy sector.
We have moved from a time when we had very centralised governance arrangements
around a centralised infrastructure. We are moving to disaggregate those governance
arrangements, so now we have separate retail, distribution, transmission and
generation elements in our energy system... [W]e are getting much greater
participation now for consumers in this energy market, which did not exist
before, so there is a much more a dynamic marketplace. I think that inherently
brings us a more resilient electricity sector.[72]
3.98
Mr Osbourne also informed the committee that a 'community power station'
can potentially be implemented very quickly because the additional
infrastructure (over and above panels and batteries that residents are already
installing) is cheap and easy to implement and the approval processes are far
simpler than for a larger industrial scale facility.[73]
3.99
In summary, Mr Osbourne contended that the key advantages of 'community
power stations' were that they were:
-
fast to respond;
-
decentralised;
-
cheap to build; and
-
quick to approve.[74]
3.100
Dr Mears was of the view that SwitchDin had resolved the issues of integration
and control, thereby enabling small-scale, distributed systems to participate
in the new energy sector of the future.[75]
3.101
Similarly, Mr Osborne stated that companies facilitating distributed
generation were already operating successfully within the NEM:
I do not think there are many barriers at all. We are up and operating.
A customer can go right now and buy our gear. They can put it on their house.
They can choose a plan from one of a number of retailers that are for battery
participants and that allow them to do this interactive stuff. We can do it
today, and that is because in the nineties we went through a great reform. We
built the NEM... I think it is well designed. We can operate in it.[76]
3.102
Mr Blume was of the view that aggregators were the future of the
electricity market:
There will be aggregators who will look at individual
businesses and homeowners and what their energy resources are and they will
say: 'We'll give you a deal. Here's the deal. We will manage your system for
you.'[77]
3.103
The committee heard numerous examples of community led-proposals that
had grasped or were working towards this goal. For example, Mr Phil Browne
submitted that:
It makes great sense that the government should lead the
way...by creating a network of many solar energy plants with battery storage
distributed across the country. In addition to being cheaper in the long term,
these solar plants would distribute power to local communities, and
importantly, in the event of a storm disrupting power supply, it would not
cause the massive loss of power to most of the state as occurred in South Australia
when the current distribution grid was destroyed in a super storm.[78]
3.104
The Northern Alliance for Greenhouse Action noted that collaborative
action to develop distributed energy networks might lead to some unlikely
partnerships between the public and private sector:
The design of local energy solutions requires collaboration
between parties that have traditionally not worked in close partnership, such
as local governments and electricity networks. Distributed energy resources
require participation and collaboration from diverse stakeholders in order to
ensure that overall system security and reliability is maintained.[79]
3.105
Local energy trading was seen as a particularly important driver in
reducing the costs of new energy storage technology through economies of scale:
...local energy trading improves the return on investment of
energy storage and related devices significantly which will serve to increase
the frequency of uptake and accelerate the reduction in system costs in
accordance with technology maturity curves.[80]
3.106
Concerns were raised that the shift to decentralised electricity
generation by consumers created uncertainty that neither government nor
industry can control. Mr Bradley warned that:
Customers could drive 25 to 40 per cent of all system
expenditure between now and 2050. The significance of that is it is going to be
over $200 billion worth of expenditure that is actually determined by customers
or their agents. In that environment, neither the industry nor governments can
command and control the way in which the system develops.[81]
3.107
Mr Bradley stated, however, that the right incentives from both government
and industry would lead to better market outcomes:
All we can do is send incentives. So that is government
sending incentives, which is around carbon abatement, through outcome based
carbon policy. In the industry's case, it is sending incentives about the
potential rewards for customers that could use their solar and batteries to
help reduce the need for network expenditure and rewarding customers for those
kinds of services.[82]
3.108
Dr Mears added that with such a system consumers may become 'prosumers'
and there may need to be different mechanisms to reflect the value of their
contributions to the electricity system:
The Power of Choice review has led to transformations in the
expectation of incumbents around what the consumer will mean in the future of
this sector. The really big shifts that need to happen are about extending that
more deeply. How do consumers who are now becoming what we call
'prosumers'—they are producing energy as well as consuming energy—fully
participate? At the moment, for example, if your solar system generates
excessive electricity, you can export it onto the network. You are remunerated
with an amount, which perhaps does not reflect the potential value you could
otherwise get if you were allowed to find a better buyer for that electricity,
for example. So enabling the sorts of peer-to-peer trading opportunities, being
able to quantity the costs that the networks would charge for allowing you to
do that sort of activity and clarifying or making these process more
transparent would enable a whole range of new business models for energy
services.[83]
Electricity demand management
3.109
The committee also heard about other smart devices that can contribute
to managing electricity demand. Mr Blume explained how what are termed 'demand response
enabling devices' work:
They are very simple little things. There are 750 000
households with them on their hot-water systems. And what do they do? When
there is big demand, they either pump electricity into those hot-water systems
or turn the hot-water systems off. There are about half a million of them on
air conditioners, and they drive the air conditioners. It is not like all of a
sudden your air conditioner turns off and you think, 'Bugger—I've got no air
conditioning.' They turn it off in lumps all over the network—two minutes off
here, two minutes off there. That is called demand response, and the demand
response technology up until now has not been used very much.[84]
3.110
Energy Networks Australia noted developments in Australia that help
incentivise fleets of millions of distributed energy resources to contribute
towards lowering the cost of the centrally delivered infrastructure:
The kinds of resources we are talking about are not only
solar—or solar with smart inverters, particularly—or storage; they are also
sophisticated demand response programs. There are aggregators of demand
response that will offer customers a simple interface to allow them to control
devices like hot water or pool pumps, so that they can respond on call and help
beat the peak and manage the peak lopping...[85]
Committee view
3.111
The committee considers that a diversity of distributed generation and
storage technologies have the potential to greatly enhance the operation and
resilience of Australia's electricity networks. The committee further considers
that in Australia we are collectively past the small scale proto-typing of such
technologies and it is now time to move forward with a detailed scoping study
for substantial deployments of distributed generation and storage technologies.
The committee wishes to emphasise that the scoping study it is recommending
should address academic research on the resilience of distributed systems.
3.112
The committee affirms that it is essential for the Commonwealth government
to show leadership in the high level design of Australia's electricity system.
While acknowledging that markets will play a necessary role in the implementation
of the electricity system, left to their own devices, markets and corporations cannot
and will not achieve an overall design for Australia's electricity system that
is in the best interests of Australia and its people.
Recommendation 3
3.113
The committee recommends that the Commonwealth government conduct
a detailed scoping study to evaluate options for distributed generation, new
software services, and storage technologies to contribute to the resilience of
Australia's electricity networks.
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