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. 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.
This is part one of a three-part article. Parts two and three will be published in forthcoming issues.
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 .
Another 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 be limited if DG remains operational when surrounding areas of generation are disrupted. 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.
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).
Heads of government have also reached an agreement at the 2015 UN climate change conference in Paris to reduce carbon emissions in order to limit the planet’s average temperature rise to 1,5°C. The agreement includes financial (US$100-billion a year by 2020) and technological assistance for developing countries to help them bypass fossil fuels and move straight to RE . In developed countries RE is already having a significant impact on electricity generation. In the EU, for example, over 35% of electricity comes from renewable sources (including hydroelectric) .
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.
By 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 large fleet of EVs – in particular, the possibility that most owners will choose to recharge at night.
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 Fig. 2.).
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 fairly efficiently but are most efficient when they run for a number of hours .
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 min.), but they are not as efficient as baseload or intermediate load plants and are expensive to run.
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.
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, the connection of RE DG is a relatively new requirement and existing standards fail to take specific demands into account, such as bidirectional power flow.
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.
Another key challenge when connecting RE DG to the distribution grid is 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. 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 .
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% of the time, it is not easy to predict far in advance when generation will occur.
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. 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.
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.
Not only should total harmonic distortion (THD – voltage) and total demand distortion (TDD – current) be kept below mandated thresholds, but deviations from the 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 Fig. 4.). Voltage variability can also cause damage to network assets and customer devices.
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 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 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 energised 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 over-voltages.
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.
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. Such a topology demands new long -distance transmission and distribution strategies delivering large amounts of power across thousands of kilometers. 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).
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 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.
Having outlined many of the challenges associated with RE DG, part two of this article, to be published next month, will deal with integrating renewable energy into smart grids.
The references for this article will be published with the online version in August 2019.
Contact John Dykes, Noja Power, firstname.lastname@example.org
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