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Integrating renewable energy sources into smart grids using Automatic Circuit Reclosers

By

Steven Keeping, Technology Writer, NOJA Power

ABSTRACT

There is global momentum to diversify electricity generation sources for economic, environmental and security reasons. “Distributed generation” (DG) enables more companies to enter the electricity market stimulating competition, encourages the development of renewable energy (RE) and limits the impact of events such as cyber attacks. However, conventional electricity distribution networks are poorly matched to the needs of DG because they were designed to meet the demands of large generating capacity sited close to population centres.

The introduction of smart grids is helping electricity utilities move away from such centralised generation to a DG model with a significant and expanding proportion of DG. This paper looks at the challenges of integrating RE DG and shows how distribution automation (DA) equipment such as Automatic Circuit Reclosers (ACR) can form the foundations of smart grids that can overcome these challenges.

PART 1: THE RENEWABLE ENERGY REVOLUTION

The growth of distributed generation

Today’s electricity grids are characterised by large gigawatt-rated power stations typically sited away from population centres attached to high-voltage, long-distance transmission lines. Electricity from the high-voltage transmission lines is stepped-down to a medium voltage at substations sited close to consumers for distribution and secondary distribution via local infrastructure. (See Figure 1.)

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Figure 1: Conventional electricity grid.

Such infrastructure has served consumers well during the era of cheap fuel, lack of awareness of the environmental impact of carbon emissions, and political stability. But the world has changed and there are significant drivers encouraging a move away from centralised power generation to a distributed generation (DG) model.

The drivers behind the promotion of DG (and its integration into electric power system operation and planning) can be classified into three main categories: commercial, regulatory and (most significantly) environmental.[1]

Governments are generally keen to deregulate electricity markets, introduce competition and widen choice. For example, the NSW Government in Australia announced removal of price regulation in the electricity market in July 2014 in part to foster competition.[2] And in the U.S., in a program that started over 20 years ago, 17 states have deregulated their electricity sectors.

Such competition increases risk and thus favours the introduction of small-capacity DG projects over large and very expensive power stations. DG also promises to encourage many small generators that could trade in the energy market and, where appropriate market arrangements exist, trade in ancillary services.

A second economic driver is that some DG can be sited close to population (load) centres which improves power quality (for example, fewer voltage sags and swells) and supply reliability (for example, reduction in outage hours). Outages in particular can be limited if DG remains operational when surrounding areas of generation are disrupted. In contrast, it is increasingly difficult to build big new conventional generating capacity near to population centres due in large part to environmental group lobbying.

Moreover, in an increasing turbulent world energy security is uppermost in the minds of policy makers. There is a recognition that developed nations are so dependent on energy resources that disruption in supply would have huge political, economic and social impact. The European Union’s (EU) energy policy, for example, has three main goals, security of supply, competitiveness and sustainability. DG mitigates some of the risks of disruption because failure of one power source has limited impact on the whole system compared to failure of one large power plant or bulk electricity distribution feeder. This is becoming even more important as the risks of disruption extend beyond technical failure to physical- and cyber-sabotage.

However, the most significant driver for the introduction of DG is environmental. While there is still debate as to whether the cause is entirely down to human intervention, there is consensus that the planet is warming and that warming correlates with increased levels of carbon (and other “greenhouse” elements) in the atmosphere.

The Intergovernmental Panel on Climate Change’s (IPCC) latest report concludes: “The globally averaged combined land and ocean surface temperature data as calculated by a linear trend show a warming of 0.85 [0.65 to 1.06] °C over the period 1880 to 2012.”[3] (See figure 2.)

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Figure 2: Global surface temperature and CO2 concentration. Red bars indicate years warmer than the 1901 to 2000 average. (Source: NOAA/NCDC)

Another environmental driver for DG is the avoidance of construction of large new power plants and associated infrastructure such as transmission and distribution lines (although it should be noted that there are also environmental objections to alternative power sources such as wind turbines and large photovoltaic (PV) arrays).

Renewable energy’s role in a distributed grid

Developed- and developing-nations around the world are attempting to curb or reduce their carbon emissions in order to mitigate catastrophic climate change. A key tool in this global initiative is the use of renewable energy (RE).

There are currently no legally-binding targets, but several nations have taken been driven by a moral imperative to reduce carbon emissions. In Australia, for example, the long-term intent is to decrease the electricity sector’s carbon emissions by 26 to 28 percent by 2030 relative to 2005 levels. The Large-scale Renewable Energy Target––set at 33 TWh by 2020––is the main mechanism for limiting emissions growth in the sector to 2020.[4]

And China will need 150 GW of installed PV capacity and 250 GW of installed wind power capacity in order to meet its goal of getting 15 percent of its electricity from renewable sources by 2020.[5]

Heads of government have also reached an agreement at the 2015 UN climate change conference in Paris, France, to reduce carbon emissions in an attempt to limit the planet’s average temperature rise to 1.5 C. The agreement includes financial (US$100bn ($139bn) a year by 2020) and technological assistance for developing countries to help them bypass fossil fuels and move straight to RE.[6]

In developed countries RE is already having a significant impact on electricity generation. In the EU, for example, over 35 percent of electricity comes from renewable sources (including hydroelectric).[7]

(See Figure 3.)

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Figure 3: Renewable energy generation in Europe. (Red line shows renewable energy contribution to electricity generation.) (Source: EU.)

In Australia many customers now generate their own electricity with the country having the highest penetration of grid-connected, rooftop PV systems anywhere in the world. An electricity provider in the area around Brisbane, Australia (the state capital of Queensland) reports that in mid-2015 there was 1000 MW of domestic PV capacity on a 5000 MW network. In some localities 60 percent of domestic customers have installed some PV capacity. This capacity is able to deliver up to 7 percent (1464 GWh) of the daily energy demand. Figure 4 illustrates the effect of increasing PV capacity on a Queensland feeder load on the same day over the last six years.[8]

Figure 4: The impact of domestic PV installation on feeder load (2009 to 2014). (In October 2014 the feeder serviced 2654 properties with 937 PV installations totalling 2930 kW of installed generation.) (Source: Energex)

There is also good reason to believe that in the future large numbers of consumers in developed nations will choose electric vehicles (EV) to replace conventional models. Many countries plan to encourage EVs as part of a strategy to meet emission reduction targets. However, although EVs produce no carbon emissions, they have little effect on overall emissions if the power to recharge batteries comes from fossil-fuel power stations.

In contrast, significant impacts on carbon emissions will happen if EVs can be recharged from RE sources. An energy policy that includes greater use of RE will also need to consider the impact of a

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large fleet of EVs – in particular the possibility that the majority of owners will choose to recharge at night. (See NOJA Power white paper “Using the smart grid to mitigate the impact of electric vehicles on future electricity demand”. www.nojapower.com.au.)

The challenges of integrating renewable energy

Conventional electricity systems are planned around a strategy that ensures that power generation is sufficient to comfortably meet peaks in demand with an additional margin to guarantee security of supply. At other times, and especially at night when demand is low, much of the capacity of the grid lies unused - yet large generators can’t easily be stopped and restarted.

Utilities schedule how much electricity will be needed, often up to a year in advance, based on historical and anticipated demand. Efficient “baseload” plants handle the round-the-clock electricity requirements. As electricity demand increases over the course of the day, intermediate load (or “load following”) plants are turned on. And during times of peak electricity demand, peak load plants are activated. (See Figure 5.)

Figure 5: Utilities maintain intermediate and peak load capacity to supplement baseload power generation as demand increases throughout the day. (Source: Institute for Energy Research)

Baseload plants are typically coal- and nuclear-fuelled. These efficiently provide large amounts of reliable, inexpensive power but at the expense of being hard to rapidly ramp-up or -down.

Intermediate load plants are generally combined cycle natural gas plants. These plants can ramp up electricity production pretty efficiently but are most efficient when they run for a number of hours.[9]

Peak load plants tend to be simple cycle natural gas- or oil-burning plants. These plants can increase or decrease output very quickly (reaching full output within 10 to 20 minutes), but they are not as efficient as baseload or intermediate load plants and are expensive to run. Peak demand is usually during the summer afternoons, particularly in countries like the U.S. and Australia where consumers use a lot of air conditioning.

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Hydroelectric plants are somewhat of a hybrid and can perform all of the above functions providing the plant has enough potential energy stored as water behind a dam.

The conventional electricity supply system is inherently inefficient, and much of the generating capacity continues to consume fuel and produce carbon emissions when no electricity is being generated. This is because utilities have to maintain a high level of fossil-fuel generation to ensure security of supply.

The introduction of RE DG to conventional electricity systems increases the challenges of ensuring security of supply. Even when RE provides a small fraction of a system’s total electricity, such resources may provide a large fraction of electricity on a smaller time scale or larger geographic area. For example, wind power provided 57 percent of the U.S. state of Colorado’s electricity late one night in 2012, although wind on average over the year supplied just 17 percent.

In addition to these security concerns, a greater contribution from RE introduces other major technical challenges for utilities compared with conventional generation. These technical challenges can be divided into five categories: new infrastructure, variability, power quality, grid protection and long distance transmission and distribution.

New infrastructure

In developed nations, electricity transmission and distribution networks are governed by strict engineering standards that ensure a high degree of safety and operational reliability. These standards enable DA manufacturers to supply equipment that adheres to tight specifications and makes it easier for utilities to install and maintain such equipment. However, connection of RE DG is a relatively new requirement and existing standards fail to take into account its specific demands (such as bidirectional power flow).

For example, the primary Australian Standard governing grid connection of RE DG (AS4777:2005) is limited in its scope for systems up to 30 kVA capacity. As a result, utilities generally decide that operators wishing to connect systems of greater than 30 kVA to the grid must enter a negotiated connection process. Compounding the problem, each utility has developed its own connection guidelines and standards for connection of RE DG. These requirements vary extensively.

This variation in requirements can cause uncertainty for RE DG projects, upping integration costs, adding extra engineering time to the application process and increasing the administration burden on both the RE DG operator and the utility.

The second key challenge when connecting RE DG to the distribution grid is also economic. Today, such connection typically requires the construction of additional infrastructure as prime RE sites are often sited away from existing facilities such as substations. For example, Moree Solar Farm, a 56-MW PV generating facility situated near Moree in north-west NSW, Australia, was connected to the Moree distribution network by cutting into and extending an existing 66-kV sub-transmission line by approximately 4 km to reach the solar farm. This arrangement required a new switching substation to be constructed close to the facility. In addition, the existing 66-kV sub-transmission line was upgraded to enable it to cope with the increased load.

The benefit of constructing a new substation close to the RE generating facility is that it incorporates protection and power quality capabilities that enable RE to be safely switched in and out of the grid as required. The key downside is that a substation is very expensive and requires ongoing maintenance and upgrading. The capital investment in substations to connect RE to the grid can often make projects economically unviable.[10]

Variability

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RE sources are both more uncertain and more variable than conventional generators. (Uncertainty describes the inability to predict in advance timing and magnitude of changes in generation output while variability describes the change of generation output due to fluctuations of wind or sun.) For example, while a wind farm might reliably produce power for 40 percent of the time, it is not easy to predict far in advance when generation will occur. Figure 6 illustrates how the hourly output from a single wind farm varied over 30 successive days. Generally, PV panel output is more variable than wind––dropping by as much as 70 percent due to passing clouds––but is less uncertain.

Figure 6: U.S. wind farm output on 30 successive days. (Source: California ISO.)

Even during periods of availability, there is no guarantee that the wind- and PV-generated power will coincide closely with demand, introducing additional technical challenges.

Variability becomes increasingly difficult to manage as the penetration levels of RE increase (but is mitigated to some extent by spreading the resources over wider geographic areas, siting resources in areas of known high wind or solar activity, and improving forecasting techniques).[11]

Utilities make reliability of the grid the most critical priority. This priority drives up the cost of RE integration, because utilities must hold large amounts of reserves to cover an unexpected loss of RE. An analysis of wind plant experience to date in the U.S. shows that reserves have been increased up to 9 percent to accommodate wind penetration of 15 percent.[12]

Power quality

Power quality is determined by AC frequency and voltage consistency, the presence of undesirable harmonics (components of the electricity supply oscillating at multiples of the nominal frequency) and outages. RE DG such as PV panels, for example, can introduce disturbances into the distribution network as an artefact of the inversion that converts the DC voltage of the panel into line AC voltage.

Utilities are required to meet standards for power quality or face penalties. For example, AS/NZS 61000.3.6––which advises on emission limits for non-linear loads in medium- and high-voltage systems––states that the total harmonic distortion (THD) for medium voltage grids should be no greater than two percent at the “point of common connection”. Not only should THD (voltage) and total demand distortion (TDD – current) be kept below mandated thresholds, but deviations from the

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nominal voltage (“sags” and “swells”) and interruptions (caused by factors such as tree branches and animals shorting feeders) must also be monitored and minimised.

In addition, the harmonics introduced by RE DG can overload the distribution grid generating heat that eventually damages equipment and insulation. Such damage raises utilities’ maintenance costs and increases the risk of outages. Consumers’ equipment, particularly that using large electric motors, can also be affected.

Voltage sags and swells are, for example, common in urban areas with high penetration of PV panels. Rapid changes in power output cause rapid voltage fluctuations outside of normal regulated limits. (See Figure 7.) Voltage variability can also cause damage to network assets and customer devices.

Figure 7: Voltage variability is common in areas with high PV panel penetration and can cause voltages to rise above normal regulated limits. (Source: Clean Energy Council.)

For isolated power networks, such as wind farms, the frequency challenges become more prominent, affecting network stability and reliability. Even a short term imbalance between generation and load can have a large impact on the system frequency and subsequent power reliability for customers. In extreme cases, poorly balanced generation and load can cause grid collapse and the potential to undermine reliability and lifetime of utility assets or customer appliances. If isolated power networks are connected to the wider grid, then the power quality issues take on greater significance because they could cause problems for consumers who reside some distance away from the RE generation capacity.

These power quality issues dictate that power quality measurements and monitoring take on greater significance for grids with high levels of RE DG. To make matters even tougher, monitoring and control of distribution networks with significant RE DG contribution tends to be more difficult since the boundary between generation and the grid is poorly defined.

Grid protection

Grid protection systems are designed to protect customer supply and operate to strict programmed limits on how much power can be allowed to flow in the event of a fault. When RE resources are introduced to this grid model, the operation of protection systems becomes more complex by: Making

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it more difficult to detect faults, particularly in “fringe-of-grid” networks; increasing the current that can flow in the event of a fault, such that a network could approach, or even exceed, set fault levels; increasing the likelihood of nuisance tripping due to reverse power flows on radial networks, and increasing the risk of an “electrical island” forming during a fault.

Such “islanding” is a major challenge when integrating RE DG as it introduces unintentional operational issues. These issues include: Increased incidence of hazardous energized downed conductors; damage to switchgear and other equipment due to protection equipment operating on live conductors that form part of the island; delayed restoration of service in the event of a fault; increased danger to maintenance crews repairing faults; degradation of power quality within the island, and increased potential of damaging overvoltages.

The conventional grid caters primarily for one-way power flow, from centralised generation, through transmission- and distribution-networks, to low- and medium-voltage networks serving customers. However, RE DG can generate power flows at the customer end of the network, reversing conventional power flows. These reverse flows can cause problems with network protection systems and, in isolated power networks, can adversely affect network stability.

Furthermore, RE DG increases the risk of grid “collapse”. RE DG installations typically comprise lower generation capacity than conventional power stations. For example, according to the U.S. Energy Information Administration (EIA), in 2013, the country’s 1,212 coal-fired power station provided 330,000 MW of capacity (an average of 272 MW per station). In comparison, 977 wind farms promised a maximum capacity of 61,000 MW (62 MW per station) and 874 solar farms offered just 6,600 MW (7.7 MW per station).[13]

This lower capacity prevents the RE generation maintaining the specified voltage and frequency under fault conditions which can result in grid collapse and widespread consumer inconvenience. New technology such as synchronized phasors (“synchrophasors” – a time-synchronized measurement of frequency and phase angle) will be required to predict these collapses and isolate faults and/or generators.

Long distance transmission and distribution

RE is often distributed remote from centres of demand because reliable wind- and solar-energy typically occurs away from population centres. In the U.S., for example, major population centres are clustered on east and west coasts while the majority of reliable RE is situated in the middle of the country. (See Figure 8.)

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Figure 8: RE sources and demand centres can be thousands of kilometres apart.

Such a topology demands new long distance transmission and distribution strategies delivering large amounts of power across thousands of kilometres. High-voltage DC (HVDC) transmission is the best option for long distance transmission because it offers several advantages. Chief among these are lower cost infrastructure and reduced line losses compared with AC systems. Other advantages include easier power transmission between grids running at different frequencies (for example, 50 and 60-Hz systems).[14]

However, decades of investment in high-voltage AC (HVAC) is likely to see it continue to be the dominant transmission and distribution technology in the medium term. One option being explored is an increase from 36-kV to 72-kV AC transmission for offshore wind farms. 72-kV AC transmission offers several advantages such as short circuit power reduction, lower electrical losses and reduced voltage drop.

Moreover, because 72-kV transmission lines have lower impedance than 36-kV systems, more power can be transmitted per feeder and transformer, resulting in a reduction in cables, circuit breakers and transformers. Longer feeder lengths can also be used before stability problems occur.[15]

PART 2: INTEGRATING RENEWABLE ENERGY WITH SMART GRIDS

What is a smart grid?

Smart grids enable utilities to overcome the technical challenges of RE DG integration by dramatically improving the control and flexibility of electrical distribution.

While there is no official definition of the smart grid, the U.S. National Institute of Standards and Technology (NIST) offers a concise description. NIST says the smart grid is “a modernised grid that enables bidirectional flows of energy and uses two-way communication and control capabilities that will lead to an array of new functionalities and applications”. (See Figure 9.)

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Figure 9: The smart grid promises a modernised network that enables bidirectional flows of energy and uses two-way communication. (Source: International Renewable Energy Agency.)

To make this vision of smart grids a reality requires the introduction of computerised digital technology, automated control and autonomous systems to electricity distribution. Such investment would provide the foundation for a grid that is more reliable than conventional infrastructure, offering fewer and briefer outages, ‘cleaner’ power and ‘self-healing’ properties.

Implementation includes fitting each device on the network with sensors to gather data, and adding bidirectional digital communication between the devices in the field and the utility’s network operations centre. Another key feature of smart grids is the automation technology that lets the utility adjust and control each individual device from a central location.

Smart grids automatically monitor, protect, and optimise the operation of their interconnected elements from the central and distributed generators through the high-voltage transmission- and distribution networks, to industrial users and end-use consumers. These enhanced networks promise improved efficiency that reduces total energy demand by limiting line losses and encouraging consumers to reduce consumption. This improved efficiency and decreased consumption, together with greater use of efficient fossil fuel- and RE-power sources, reduces the generation of carbon emissions and other pollutants.

A smart grid’s continuous monitoring allows automated systems or operators to detect and act upon dangerous situations or security breaches that threaten reliable and safe operation of the network. In addition, cyber security and privacy protection for customers is significantly enhanced.

Residential consumers can take advantage of smart metering which will offer greater choice and control over electricity use. Consumers will also be able to buy “intelligent” appliances that can autonomously determine when to operate based on the cost of power at a particular time. In addition, consumers will be able to operate as microgenerators, feeding power back to the grid through bidirectional distribution lines. (See NOJA Power white paper “Carbon emission reductions by the implementation of a smart grid”. www.nojapower.com.au.)

The smart grid will utilise the same high-voltage (i.e. above 100 kV) transmission lines used for contemporary long distance- and high capacity-transmission. Substations will then convert high voltage to medium voltage (usually 34.5 kV or below, often 11-to-16 kV) for distribution and secondary distribution.

The distribution lines in a smart grid will also be equipped with distribution automation (DA) devices. Such units will be essential for protecting the integrity of the grid, isolating faulty lines, re-routing power to communities affected by line failures (by reversing power flow if necessary) and switching in RE resources (when they are able to provide power) to cover demand peaks.

Smart grids can do much to help meet the challenge of integrating RE generation together with a wide range of diverse conventional electricity resources. For example, imagine PV generation and a set of commercial and industrial electricity consumers all tied together with smart grid communication and control technologies. In one scenario, rapid communication technologies will warn operators of approaching clouds allowing a smooth transition from PV to conventional supply using DA to switch the direction of power flow and back again when the sun reappears.

In a second scenario, customers might be prepared to subscribe to an “interruptible tariff” whereby they would be prepared to accept reduced power flows (in the event of cloud cover) in return for a cheaper electricity price. Smart meters would record the interruptions and in the future the system could even be extended to warn intelligent appliances of impending power reductions allowing them to switch to stored power sources (such as the consumer’s EV batteries) for the duration of the interruption. Later, when the sun goes down and the evening wind picks up, a smart grid could

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switch to wind turbine power to recharge the EV’s batteries ready for the following morning’s commute.

Smart grids also help resolve the challenges of RE DG. The technology can provide system operators with continual, real-time information on how these systems are operating and allow precise control. Such close monitoring and control will encourage utilities to consider RE DG as an alternative to traditional large-scale power plants.

Moreover, detailed data on RE DG output and performance can help the utility place an accurate figure on the value of the RE DG. Similarly, the data can help the utility determine the proper price to pay the RE DG system owners or operators for their systems’ output.[16]

Overcoming variability

Smart grids enable utilities to manage the variability challenges that come with large RE generation contributions to the electricity supply. Today, RE variability is handled almost exclusively by ramping conventional reserves up or down on the basis of forecasts. However, smart grids will allow seamless augmentation of RE DG by easing installation of energy storage on the grid, using fast-acting conventional generation when RE resources are expected to decrease, and enhancing long-distance transmission such that a utility can access larger pools of RE resource to balance regional and local excesses or deficits.

Energy storage can help resolve many of the challenges relating to the existing grid. In particular, storage helps to deal with variability, but it can also play a key role in managing power flows. Commonly deployed electrical energy storage technologies include electrochemical storage (batteries) flywheels, pumped hydro storage, specialised storage systems such as compressed-air energy storage, superconducting magnetic energy storage, supercapacitors and fuel cells.

Energy storage is already being trialled or deployed by a number of Australian networks. For example, TransGrid, an NSW, Australia, transmission services provider, has commenced a hybrid demand management trial known as iDemand. The trial, located in western Sydney, incorporates 98 kW of PV generation combined with 400 kWh of Lithium-polymer (Li-pol) battery storage. The trial aims to demonstrate how PV and storage can work together to provide a resilient and versatile mechanism for managing peak load.

The system is integrated with energy efficiency measures on-site, aiming to reduce the local peak load by as much as 50 percent. However, to date, the high cost of installation has limited uptake of network storage to niche applications, and restricted installations to relatively high-level positions in the network.

PART 3: THE ROLE OF THE ACR IN A SMART GRID

Implementing a smart grid will require extensive use of DA to allow faster and more precise control than is typical for conventional systems. Enhanced control will be essential for resolving the challenges of integrating RE.

Automatic Circuit Reclosers (ACR or “auto-recloser”) are fundamental components of the DA underpinning future smart grids. (See Figure 10.) Moreover, modern devices such as NOJA Power’s OSM series ACRs provide a comprehensive suite of automation and protection features. The ACRs perform voltage measurements on all six bushings, current measurement on all three phases and provide extensive power quality and data logging capability as well as many of the switching, bidirectional protection, control and communication capabilities required to integrate RE generation into the electricity grid.

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Figure 10: ACRs are fundamental components of smart grids.

The primary role of an ACR is to act as a switch and circuit breaker, enabling power re-routing––either in the event of Fault Protection, Isolation and Restoration (FPIR) events or the interfacing of local sources of RE to supplement base load in times of peak demand––demanded by a smart grid to maintain high availability.

ACRs operate in cases of faults, for example, when a phase-to-phase or phase-to-ground fault increases the current in the feeder above normal levels. The ACR can also be triggered by a fault resulting in a current lower than normal levels, as, for example, in the case of a fallen conductor touching a high resistance surface such a concrete. By re-routing the supply via remote switching of other ACRs, the utility can quickly restore power to customers affected by the original fault.

Smart grid building blocks

In addition to their primary role as switches and circuit breakers, modern ACRs are designed as building blocks for smart grids. As such they have many capabilities which make the devices ideal for smart grid applications like the integration of RE DG.

NOJA Power, for example, has included sectionalizer functionality in its firmware platform for the OSM series ACRs. The functionality allows utilities to configure the ACR as a conventional auto-recloser, a sectionalizer or to function as either device depending on the application. The ACR is able to perform all three functions in either direction of the electricity feeder.

To ensure that utilities take full advantage of the capabilities of DA such as ACRs, technicians need to be familiar with the equipment. This can be challenging for personnel that have previously worked with traditional utility equipment. Equipment suppliers are working to ease this transition. For example, NOJA power offers its Smart Grid Automation (SGA) software, a PC-based software suite that enables engineers to develop, test and debug smart grid functionality for ACRs.

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SGA software multiplies smart grid customisation options and adds the capability of distributing the resulting applications simultaneously across groups of ACRs. Such applications help make smart grid implementations easier to develop, deploy and modify.

The software uses IEC 61499 as the basis for constructing the applications. IEC 61499 is an open standard for distributed industrial automation systems aiming at portability, reusability, interoperability and reconfiguration of distributed applications. The IEC 61499 model includes processes and communication networks as an environment for embedded devices, resources and applications.

Economic benefits

There are currently no easy fixes to the challenge of widely-varying and somewhat vague specifications for the connection of greater than 30-kVA capacity RE DG to the grid. However, as the penetration of RE DG climbs, the issue is under careful consideration. In Australia, for example, the Clean Energy Council has produced a report which describes the challenge and recommends the priorities that should be addressed to simplify “IES” (“Inverter Energy Systems” such as solar and wind generation) connection.[17]

Among these recommendations are to develop: Standardised protection requirements for IES connections; post installation, commissioning/testing and maintenance requirements for IES; standardised utility technical assessments for IES connection, and standards and utility guidelines for the connection of hybrid/IES.

As RE DG systems become more prevalent, the need for standardised connection will become more pressing. Safety and reliability are the highest priority for utilities and the absence of guidelines has encouraged them to take a conservative approach, leading to expensive connection schemes that can make some RE DG schemes economically unviable. NOJA Power is doing its part by working with utilities to draw up practical RE DG connection guidelines in the absence of standards which provide satisfactory safety and protection without excessive design and engineering costs.

Once pragmatic RE DG connection specifications have been agreed, the use of ACRs as the primary connection device can lower the cost of connection. ACR functionality already includes bidirectional protection, power quality monitoring and communication technology (see below). With the addition of extended bidirectional-, rate of change of frequency- and vector shift-protection (particularly combined with synchrophasors) tomorrow’s products could operate as a highly cost-effective interface between RE DG and the distribution grid.

Next-generation ACRs with these capabilities promise to make today’s uneconomic RE DG projects viable because the cost and complexity associated with building substations would be eliminated. NOJA Power has embarked on a development program to enhance its ACRs specifically for RE DG connection to the distribution grid.

Bidirectional power flow and protection

In conventional grids power typically flows in a single direction, from centralised power generation to industrial, commercial and domestic consumers. However, smart grids are able to support bidirectional flows that will be common as consumers become producers when the sun shines or the wind blows. (See Figure 11.) Smart grids must offer this support while still maintaining a high level of reliability and network protection. ACRs are the key component in ensuring that the smart grid can meet these criteria.

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Figure 11: Smart grids can support bidirectional power flow.

An example of this flexibility comes from Melbourne Water, a water supplier to consumers in the Victorian capital. The company operates an 8-MW induction generation plant at its Thomson Reservoir facility. The water utility takes power from the grid or switches to co-generation when its induction generation plant is operational and excess capacity is available. The local electricity utility, SP AusNet, can switch in or out the additional capacity depending on demand.

The NOJA Power OSM series ACR at Thomson Reservoir enables this bidirectional switching and integrates seamlessly with SP AusNet’s advanced grid control systems. Importantly, the ACR also provides bidirectional protection; it can monitor and protect the distribution line in both directions and can trip at different current levels depending on the direction of electricity flow. At the reservoir, the ACR trips at a lower current for power being generated than for power being supplied. This arrangement allows the electricity utility to precisely control the peak current fed into the grid––to protect voltage-sensitive devices among other requirements––while permitting Melbourne Water to draw as much current as it needs from the grid during times of peak demand.

In other smart grid applications, coordinated operation allied with supervisory software and custom algorithms allow OSM series ACRs to detect, for example, a single-phase fault in a three-phase system, isolate a small a section of feeder, advise the exact location of the fault to maintenance staff, determine capacity requirements and re-route sufficient power to as many consumers as possible - without requiring intervention from human operators.

The OSM series ACRs continuously monitor voltage and current on all six bushings and NOJA Power is now developing hardware to enable these ACRs to detect fault currents as low as 0.2 A. This capability, coupled with new software algorithms, will enable the ACRs sited at intervals along a feeder to narrow down a fault location when a single feeder has been isolated at the substation by a device such as a ground fault neutraliser (GFN) – enabling maintenance crews to be quickly directed to the fault.

The OSM series ACR’s Negative Phase Sequence (NPS) protection is also valuable to utilities with very long feeders. Such feeders typically exhibit high impedance that can mask faults far down a line because the high resistance results in upstream current changes too small to trigger protection devices. However, because NPS protection looks for phase imbalance rather than current anomalies,

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the high impedance of a long line becomes irrelevant and faults can be detected anywhere along the feeder’s length. This protection capability is a key advantage when RE DG is sited remotely from demand centres.

Power quality

As power generation becomes more diversified and RE DG contributes an increasing proportion of the total supply, monitoring of power quality will become more critical. Utilities will be responsible for ensuring high power quality when switching in RE generation and for isolating the supply rapidly if problems occur, to limit the risk of damage to network and consumer assets. Modern ACRs can help utilities meet these obligations. For example, the OSM series ACRs can measure harmonic distortion, interruptions, and sags & swells, helping to prevent power contamination. The power quality information is available via a display for on-site technicians, or remotely accessible for staff based at a distant location. The ACR’s power quality measurement tool is supplied as standard.

There is evidence that industrial and domestic users are already compromising power supply quality in contemporary grids. The University of Wollongong in NSW, Australia, is conducting a long-term power quality monitoring project which has found that the incidence of harmonics in the Australian medium-voltage distribution grid almost doubled over a three-year period in the first decade of this century and the trend is likely to continue.[18]

ACRs such as NOJA Power OSM series can assist utilities in meeting their power quality obligations – which will become increasingly tougher as more RE DG is added to the grid. The ACRs are able to record power supply data for customer-determined durations, sections of feeder and user base. Once the data collected from the ACR is analysed, waveforms are displayed and harmonics identified for all three phases, allowing the utility to quickly react to problems.

Synchrophasors and islanding prevention

ACR manufacturers like NOJA Power are working hard to incorporate synchrophasor technology in their products. Such technology will be critical if ACRs are to become practical alternatives to substations for interfacing RE DG to the grid. Synchrophasor technology is not yet commercially available, but is likely to be a standard feature of the next generation of ACRs.

Synchrophasors have become increasingly relevant since a 2004 U.S.-Canada investigation recognized that many of North America’s major blackouts have been caused by “inadequate situational awareness” for grid operators, and recommended the use of synchrophasors to provide a real-time, wide-area grid visibility.

A synchrophasor is a time-synchronized measurement of a quantity described by a phasor (which includes magnitude and phase information). A phasor is a complex number that represents both the magnitude and phase angle of voltage and current sinusoidal waveforms at a specific point in time. (See Figure 12.) Synchrophasors provide a real-time measurement of electrical parameters from across the power system and can be combined to provide a precise and comprehensive overview.[19]

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Figure 12: Synchrophasors are time-synchronized measurements of magnitude and phase information.

Devices called Phasor Measurement Units (PMU) measure voltage and current and then derive parameters such as frequency and phase angle. Data reporting rates are typically 30 to 60 Hz, and may be higher. In contrast, current supervisory control and data acquisition (SCADA) report rates are slower (4 to 6 Hz). The precise timing of synchrophasor measurements allows rapid identification of details such as oscillations and voltage instability that cannot be seen directly from SCADA measurements.

Synchrophasors enable utilities to reduce the number of outages and restore power more quickly in the event of failure. In a 2014 study by the California Energy Commission forecast that the use of synchrophasor technology would save US$260 million ($371 million) in net present value annualized benefits, taking into account avoided customer outages and reduced electricity costs.[20]

Other applications of Synchrophasors include adaptive protection, real time-monitoring and -control, but perhaps the important application of the technology is islanding detection. Traditional methods for islanding detection use local voltage and frequency information. However, local detection schemes cannot detect islanding in a timely manner if the power (real and reactive) mismatch between the source and the local load is small.

Other traditional schemes rely on circuit breaker status communication, open-phase detectors and trip commands to detect islanding and isolate the source. Such schemes are simple in concept but must be adapted to topology changes in the power system. These adaptation requirements can result in a system with many communications links and poor reliability.

Another limitation to traditional approaches is the inability to scale with future requirements. For example, present standards require disconnection for sagging voltage under high demand. With a small amount of generation, such a requirement is reasonable, but disconnecting a high-density PV generation source would aggravate the low voltage level rather than mitigate the problem.

In contrast, synchrophasors provide precise wide-area measurements and a means for detecting islanding under nearly all load and generation conditions. (ACRs equipped with synchrophasor technology would detect early signs of islanding and switch to swap generation sources or shed loads

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to prevent an island forming.) Operators gain better situational awareness, and are able to better detect oscillations and more closely track voltage stability.

Synchrophasor technology can also be extended to allow PV generation to improve low-voltage conditions under heavy loading or to provide power for an islanded set of customers – an important consideration as greater PV generation is incorporated into the grid.[21]

Communications

Reliable communications are vital for the precise control of the DA that will be needed to integrate RE into the electricity grid. Smart grids leverage established wired- and wireless-communication technologies such as the cellular network and the Internet in addition to local area networks (LAN) like Ethernet and Wi-Fi.

For example, NOJA Power’s RC15 supervisory control and data acquisition (SCADA)-ready controller for its OSM series ACRs incorporates a cellular network modem that supports 2G (such as GSM), 3G (UMTS) and 4G (LTE) mobile communications network technologies. This cellular integration enables utilities to communicate with the RC15 controller over long distances on cellular networks to operate or interrogate the ACR, change settings or download new firmware. Long-distance communication is a key requirement for smart grid implementations, particularly for isolated installations. In addition, cellular connectivity enables the RC15 controller to automatically integrate with other SCADA systems.

The RC15 cubicle also incorporates Wi-Fi wireless connectivity allowing multiple substation-based ACRs to be linked into the substation’s wireless LAN (WLAN) to accelerate set up or software upgrading. Finally, the RC15 controller includes GPS capability providing mapping co-ordinates which can then be used for automatic population into SCADA mapping systems.

Utilities are already making use of NOJA Power’s communication technology as they develop their smart grids. For example, Colombian utility Electrocaquetá used NOJA Power’s ACRs to overcome the challenge of installing smart grid infrastructure in remote and hard to access areas by linking the devices to control centres using the cellular network. (See Figure 13.) The ACRs are connected (via routers) to the cellphone network and then through the Internet using Virtual Private Networks (VPN) to a server installed in the client’s control centre.[22]

Figure 13: A Colombian utility used NOJA Power’s ACRs to overcome the challenge of installing smart grid infrastructure in remote areas by linking the devices to control centres using the cellular network. (Source: PTI S.A.)

While using existing communication infrastructure, smart grids require specialised protocols to ensure rapid, reliable, secure communication between SCADA master stations (or Control Centres),

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Remote Terminal Units (RTU) and Intelligent Electronic Devices (IED). Because smart grids are still under development, globally accepted protocols are still evolving, but there is growing support for IEC 61850 and IEE 1815 (DNP3). Major DA manufacturers are steadily introducing support for these protocols which will ensure communication interoperability between the key elements of tomorrow’s smart grids.

NOJA Power, for example, provides support for IEC 61850 on its OSM series ACRs. IEC 61850 enables fast, reliable communication between the company’s ACRs and IEDs from other manufacturers used in electricity distribution systems.

IEC 61850 is a family of international standards that specify the use of a set of communication protocols for the integration of all protection, control, measurement and monitoring functions in a smart grid. The protocol builds on earlier protocols including Manufacturing Message Specification (MMS) and Generic Object-Oriented System Event (GOOSE). MMS provides the vertical supervisory and control functions that allow devices to record data and then report that data to other equipment while GOOSE is a horizontal process coordination function used for high-speed sharing of information.

The standard is now being extended beyond the original scope of substation automation into the domains of managing wide-area electrical transmission and distribution systems and the control of DG including RE.

Communication security is a key concern. There is a realisation by authorities that smart grids’ reliance on Internet Protocol (IP) technology for communication makes it possible for hackers and other malevolent forces to disrupt control systems and disable critical infrastructure. A report[23] conducted by California State University for the California Energy Commission, for example, concluded that smart grids were increasingly vulnerable to cyber security issues such as confidentiality of user information, integrity of demand response systems, integrity and availability of SCADA systems, and integrity and availability of EVs. The report suggested that smart grids should be designed with measures to counter these vulnerabilities.

In part to defend against unauthorised access, the Institute of Electrical and Electronic Engineers (IEEE), formally adopted DNP3 in July 2010, defining the protocol in IEEE 1815-2010.[24] DNP3 already plays a crucial role in SCADA systems employed to monitor and control contemporary grids where it is used by SCADA Control Centres, RTUs and IEDs. The protocol was designed with an emphasis on security and reliability making it a natural choice for smart grids. The latest version, DNP3-SAv5, defines a security architecture that uniquely identifies devices or multiple individual “users” of a device, provides for separate update keys for each device or user and supports encryption. An update supports symmetric or asymmetric public key infrastructure mechanisms.

Many IEDs support DNP3-SAv5, including NOJA Power’s RC10 controller, which ensures secure, interoperable communications with other IEDs on the smart grid.

High voltage support

Raising voltage and significantly lowering current reduces losses when transmitting high power over long distances. This has seen, for example, the development of 72-kV distribution lines to replace 36-kV lines for offshore wind farm electricity delivery. In the future, HV DC is likely to be the preferred transmission mode for long distances and commercial solutions are already established. For example, the Chinese have installed an HV DC transmission project, the Xiangjiaba line, terminating in Shanghai, which operates at 800 kV and delivers 6 GW of power over 2000 km. High-voltage transmission is likely to lead in turn to distribution lines carrying even higher voltages than the 72-kV AC systems already deployed for some RE DG installations.

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Today’s ACRs have been developed to operate on medium voltage distribution systems with NOJA Power’s products, for example, designed to operate on lines operating up to 38 kV under normal conditions. However, development is under way that will allow the products to deal with the higher AC (and future) DC voltages that are likely to result as RE DG penetration increases.

Ready for the future

Commercial, regulatory and environmental pressures are rapidly changing the way the world generates electricity. The old model of centralised generation is not flexible enough to meet these rising demands. Instead utilities are turning to DG to reduce reliance on large, capital intensive, fossil-fuelled power stations and take advantage of RE resources, including an increasing percentage from microgenerating “prosumers” (consumers with wind or PV microgeneration capacity who periodically return power to the grid).

DG with a large proportion of RE demands a radical restructuring of electricity generation, transmission and distribution to deal with the challenges of the cost of new infrastructure, variability, power quality, protection and long distance transmission and distribution that currently limit the potential of new technologies.

Smart grids with modern DA such as ACRs can overcome these challenge provided that governments commit to reform of the regulatory environment to stimulate competition and utilities commit to investment in the equipment and staff training required to implement smart grid technologies.

NOJA Power is committed to the development of the next generation of intelligent ACRs with the protection, monitoring, communication and high voltage features that will make the products a cost-effective alternative to substations for interfacing RE DG to the network. Key among these developments is the addition of synchrophasor technology to enable the precise wide-area monitoring and control that will be vital if ACRs are to replace substations as the interface between RE DG and consumers.

Huge benefits would flow from investments in smart grids that encourage RE DG, primarily a reduction on reliance on fossil-fuelled power stations and stimulation of development of RE technologies and associated industries such as energy storage and EVs, resulting in a major reduction in carbon emissions.

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Figure 14: Smart grid investment will help cut carbon emissions.

References

1. “Integrating distributed generation into electric power systems: A review of drivers, challenges and opportunities,” J.A. Pec ̧et al, Electric Power Systems Research, 9 October 2006. 2. http://www.resourcesandenergy.nsw.gov.au/energy-consumers/energy-sources/electricity/removal-of-electricity-price-regulation, retrieved 14 December 2015. 3. “Climate Change 2014: Synthesis Report,” contribution of Working Groups I, II and III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change, R.K. Pachauri and L.A. Meyer (eds.), IPCC, 2014. 4. “Electricity network transformation roadmap. Interim Program Report,” ENA/CSIRO, December 2015. 5. http://af.reuters.com/article/commoditiesNews/idAFB9N0XZ02620150519, retrieved 14 December 2015. 6. http://www.bbc.com/news/science-environment-35073297, retrieved 14 December 2015. 7. “EU energy, transport and CHG emissions: Trends to 2050,” European Commission, December 2013. 8. Presentation at NOJA Power Distributor Conference, Energex, October 2015.

9. “Electricity generation,” Institute for Energy Research, September 2014. 10. “Lessons learned in the development of Moree Solar Farm,” Fotowatic Renewable Ventures. 11. “Integrating Renewable Energy Electricity on the Grid,” American Physical Society. 12. “Estimating the impacts of wind power on power systems—summary of IEA Wind collaboration,” H. Holtinen, 2008. 13. http://www.eia.gov/electricity/annual/html/epa_04_03.html, retrieved 2 February 2016.

14. https://en.wikipedia.org/wiki/High-voltage_direct_current. 15. “Evaluation of 72 kV collection grid on Offshore Wind Farms,” by Muhamad Reza1 et al, ABB PS Consulting, 2012.

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16. “Smart grids and renewables: A guide for effective deployment,” International Renewable Energy Agency, March 2013. 17. “Priorities for inverter energy system connection standards,” Clean Energy Council, Australian Government, June 2015. 18. “The Australian long term power quality monitoring project”, University of Wollongong, 2008. 19. “Using Synchrophasor Data during System Islanding Events and Blackstart Restoration,” North American Synchrophasor Initiative. 20. “Timing Is Everything,” R. Bush, T&D World Magazine, 2016. 21. “Smart Anti-Islanding Using Synchrophasor Measurements,” M. Mills-Price and B. Flerchinger. North American Synchrophasor Initiative. 22. “Cellular networks bring remote smart grid installations to life,” Juan Carlos Quijano, Miguel Fuertes, PTI S.A., June 2015. 23. “Smart Grid Cyber Security, Potential Threats, Vulnerabilities and Risks,” California State University Sacramento, May 2012. 24. “IEEE Standard for Electric Power Systems Communications - Distributed Network Protocol (DNP3),” IEEE, 2010.

© NOJA Power 2016. www.nojapower.com.au