As the generation mix evolves to a higher penetration of renewables and less traditional thermal generation, there are places in the power grid where stability becomes a challenge. It’s one that can be overcome by an unexpected technology—the synchronous condenser. Adding synchronous condensers can help with reactive power needs, increase short-circuit strength and thus system inertia, and assure better dynamic voltage recovery after severe system faults.

Synchronous condenser project in Bergrheinfeld – Germany: planned, designed and erected by GE Vernova in Mannheim

If you thought that the synchronous condenser was an antiquated relic of the past, think again! Synchronous condensers are considered as motors without any connected load or generators without prime movers. They produce or absorb reactive power. It is true that synchronous condensers were used at the dawn of electricity grids as the primary plant to regulate voltage, and hundreds of them were built and installed. “But then, around 40 years ago,” explains Arthur Depoian, GE Vernova's Grid Solutions Commercial Manager who also doubles up as synchronous condenser application engineer, “new, power electronics technology emerged such that Static VAr Compensators (SVCs) and STATCOMs, with their lower costs, replaced synchronous condensers in the networks. However, even today, synchronous condensers offer other significant benefits.” Hence their more recent renaissance.

Synchronous condenser system up to 100 MVAr per machine

One of those benefits is based on the additional short-circuit strength they can provide. As further renewables penetration results in an increasing share of the world’s power generation, the power sources are frequently at considerable distances from the load centers, which has traditionally not been the case. This can in some cases cause a drop in the network’s short-circuit strength. Depoian adds, “This is what we term a ‘weak grid.’ And those remote sources, for instance wind farms, will be increasingly connected to the grid via high voltage AC and DC links.”

Dynamic voltage recovery and inertia

When a fault occurs on the grid the voltage is temporarily depressed, which requires an immediate and significant injection of vars to recover the voltage and prevent a collapse of the grid. In less severe fault situations or on a strong grid, an SVC is likely to be adequate. However, if there is a risk of more severe faults or the grid is weak, a synchronous condenser is the most secure solution. “The decision is based on a set of fault case assumptions that the utilities make for the grid and associated simulations,” adds Depoian. “But they know that if the voltage does not recover quickly, they violate grid standards and face the risk of a widespread blackout. Opting for a synchronous condenser may be the only solution or a much stronger solution.” While costs of synchronous condenser installations do vary, overall capital investment appears to be comparable to both SVC and STATCOM.

Inertia¹ may also become an important concern in the not-too-distant future. The spinning mass in the grid—generally turbines and generators at the production end of the network—creates the system’s inertia. As conventional generation (nuclear, thermal) is retired, it is often replaced by wind or solar sources, which provide less inertia. As a result, frequency stabilization becomes more challenging. FACTS-based equipment cannot provide the necessary inertia. “The question of inertia and frequency stabilization is not yet critical,” Depoian points out, “though it is already a problem in some specific island-based grids. This is an instance where synchronous condensers with their spinning mass could help resolve the problem.”

¹: Inertia is basically resistance to change in motion. Inertia of a power network helps limit frequency fluctuations when a power imbalance occurs.

The challenge of losses

Opting for synchronous condensers implies enhancing the specifications and design to fit the operator’s requirements. Parameters to be considered range from available substation footprint to long-term operating costs. The largest operating cost for synchronous condensers is electrical power losses, but certain choices can be made to reduce these:

•  improvement of the machine design to match the expected operating conditions;
 • use of slower speed salient pole machines that have lower losses at low Mvar output;
 • if the system needs to vary considerably throughout the year, installing several smaller machines rather than one large one may allow part of the installation to be turned off when not needed, thus eliminating the associated losses.

Old concept, new technology

As in many other technology domains, synchronous condensers have been constantly improved and upgraded over the years. Gone are the analog control systems and rheostats of the past that could not deliver adequate response to dynamic events. Today’s synchronous condenser comes complete with state-of-the-art digital controls and relays. Modern machines are available with either full static or brushless excitation. Full static excitation has faster response: however, many utilities prefer the lower initial cost and lower maintenance costs of brushless excitation systems. Brushless excitation uses a rotating exciter built into the shaft that is controlled by a digital automatic voltage regulator. The speed and precision of these devices allow the performance of the latest generation of synchronous condensers to exceed their SVC counterparts in some applications. Maintenance needs are also considerably reduced. Depoian comments: “They still fulfill the same function, but their technology, quality and reliability have progressed almost beyond recognition.”

Synchronous condenser system up to 200 MVAr based on Topair or Topack generator combined with a FKG generator circuit breaker

Synchronous condenser stabilizing the German network

The German transmission network is in a very particular situation. The country has closed down eight of its 17 nuclear power reactors and will retire the rest by 2022. At the same time it has set very ambitious renewable energy targets; the country has been called “the world’s first major renewable energy economy.” It is worth noting that over 65% of 2015 worldwide offshore wind farm capacity was installed in Germany. However, much of this will be transmitted via HVDC to the North and Baltic Sea shores where there are few major loads. The resulting highly variable load flow within the grid leads to voltage fluctuations and the need for enhanced reactive power control. It also reduces the inertia for the entire grid, making the need to improve short-circuit strength and frequency stability more critical.

German TSO TenneT called on GE Vernova's Grid Solutions business to adapt and install a two-pole synchronous condenser. “We needed it for high-speed dynamic voltage support and short-circuit power in case of failure on our grid,” says TenneT System Technology Engineer Dr. Simon Konzelmann. It was installed at their Bergrheinfeld substation in Bavaria, where the nearby Grafenrheinfeld nuclear power plant was recently closed down.

Synchronous condenser installed with GCB and busduct

FKG generator circuit breaker

Topair generator (50WY23Z-124 type)

The solution is based on the “Topair” range generator. This large rotating machine is normally part of a power plant. “Here, for the first time, it is installed by a TSO at one of its substations,” says Dr. Gert Hentschel, Grid Solutions Technical Solutions Manager. “The challenge was to build a standardized, yet flexible system that fits within its substation environment.” An integrated solution was designed with the assembly of a set of proven products and modern digital controls. The protection and control of the synchronous condenser and its 400 kV substation bay had to be developed for the TSO, as did the interlocking systems of the switchgear bay and the generator circuit-breaker components. The solution was installed in December 2015 and has been in trial operation since. A number of adjustments have been made to the control and protection system and the excitation has been adapted. However, as Konzelmann stresses, “so far, we are satisfied that the synchronous condenser solution does what we expected of it.

Hybrid FACTS solutions for enhanced grid resilience and performance

A novel hybrid solution consisting of the association of synchronous condenser with a static compensator can be envisaged to enhance the possibilities that a FACTS solution can offer. “Each technology (rotating versus static) will compensate the weakness of the other and all their strengths will be added,” says Guillaume de Préville, FACTS Senior Engineer at GE Vernova's Grid Solutions business. With such a solution, a STATCOM would offer the possibility of controlling the negative sequence voltage and therefore rebalance the grid system voltage, which could not be achieved by the synchronous condenser alone. With the addition of the static compensator, the hybrid solution would bring reinforced control of the sequence voltage, positive as well as negative. 

This hybrid solution would therefore have the following features:

• load balancing associated with voltage control on a weak network;
• improvement of the time response of the complete Static VAR Compensation solution;
• reinforcement of the short-circuit capability mainly brought about by the presence of the synchronous condenser;
• reinforcement of grid inertia;
• Sub-Synchronous Resonance (SSR) mitigation with the rapidity of the STATCOM response.

The power electronic-based STATCOM can bring more added functions such as grid damping or harmonic filtering by injecting current or voltage at the correct frequency.

A new sub-synchronous oscillation monitoring system provides warning of the early stages of resonance—which could otherwise lead to protection tripping or system damage—across a far wider range of frequencies than previously existing systems.

The electric grid that is powering the transition to a low-carbon economy will rely increasingly on generation from renewable sources, on HVDC links and on Flexible AC Transmission System (FACTS) plant¹  to provide extra capacity and flexibility. However, increased deployment of these technologies to the grid, including series compensation and power electronic converters, has implications on system dynamic performance. It presents new challenges for stability and reliability, in particular, to avoid instability in the frequency range up to the nominal frequency of the grid, termed Sub-Synchronous Oscillation (SSO). Instability can result in large oscillations that can trip or damage plants, and an early warning system helps utilities to mitigate the risks.

SSO can take three main forms. The first of these, Sub-Synchronous Resonance (SSR), has been widely studied since the 1970s when it was identified as the cause of turbine shaft failures at the Mohave generating station in Nevada, USA. This involved interaction of shaft torsional modes with an electrical “LC” natural frequency²  created by capacitors in series with inductive transmission lines. The second, Sub-Synchronous Control Interaction (SSCI), is due to the interaction of power electronic converters, such as those contained in wind turbines and HVDC links, with the LC natural frequency of series compensated lines. Third, Sub-Synchronous Torsional Interaction (SSTI) arises from the interaction of power electronic converters with generator shaft torsional modes.

In energy management systems for transmissions networks, wide area monitoring systems (WAMS) utilize synchronized phasor measurements transmitted via the well-known IEEE C37.118 protocol at up to 50/60 frames per second (fps) for a practical observable range of up to about 10 Hz. But as Stuart Clark, WAMS Power Systems Engineer with GE Vernova's Grid Solutions business explains, “with SSO we’re dealing with much higher frequencies, 4-46 Hz, that typical WAMS measurements will not record.” 

A new Waveform Measurement Unit (WMU) was therefore developed to provide synchronized voltage and current point-on-wave measurements at 200 samples per second, streamed in real time via the C37.118 protocol as “analog” type values. Additionally, speed measurements from turbine shaft transducers can also be sent. This approach accurately represents oscillatory components in the 4-46 Hz range, and also gives visibility of the 54-96 Hz range so as to differentiate modulations such as torsional modes from added components such as LC grid modes. Note that, although not a typical implementation of the C37.118 standard, this approach is fully compliant and rates such as 200 fps are encouraged by the standard. 

The WMU is implemented on a multifunction recorder that already incorporates Phasor Measurement Unit (PMU) capability. The 200 fps voltage and current waveforms from each WMU stream are then collated, processed and stored by a central or regional WAMS server, where real-time analysis, monitoring and presentation of SSO information is performed.

¹ FACTS plant describes a range of devices, often power-electronic based, that provide flexible control of the AC transmission system. Examples include Series Capacitors, the STATCOM (Static Synchronous Compensator) and the SVC (Static Var Compensator).
² LC: Inductance (L) – Capacitance (C)

Data for the past, present, and future

Douglas Wilson, WAMS Chief Scientist at Grid Solutions, explains the different ways the results can be analyzed and used. “The most immediate use is to provide real-time SSO situational awareness and to identify interactions, particularly when connecting new plant onto the existing transmission system. Operators have to be able to understand and use the data quickly, so the results are presented in a practical wide-area map view with live data charts.” The system-wide SSO map view presents mode amplitude and alarm state across the system. “A particular challenge consisted in rationalizing oscillation information from multiple signal types from two such different domains as electrical and mechanical systems to provide a clear, effective presentation to users,” according to Wilson.

System-wide SSO Overview

Human factors are likewise central to the design of the alarm system. “Anticipation is always better than reaction when you’re managing a transmission grid, and the new system is monitored for alarms on raised amplitude or poor damping to give early warning of growing oscillations, as well as to highlight persistent mid-level oscillations that would not trigger protection but may cause excessive plant wear.” The user can configure both “alert” and “alarm” thresholds and sort the information into frequency bands of interest.

Flexible User-Defined Displays

Of equal value is the use of the stored oscillation data for further analysis and historical review. This includes:
• diagnosis of events and unusual conditions
• long-term review for system studies
• defining suitable frequency bands of interest and alarm thresholds
• validation of network and plant models. 
In addition to the 4-46 Hz range, the SSO application module provides diagnostic visibility of the 54-96 Hz range through a spectrogram to enable users to differentiate between added components, such as LC modes, and modulations of the 50 Hz waveform such as torsional modes.
 
A key advantage of this solution compared to previous approaches is that users can gain a better understanding and experience from continuous long-term observation of low-level SSO behavior, and can identify and have the opportunity to respond early to significant oscillations before automated protection is triggered and plant is tripped or bypassed. Under traditional approaches, only severe resonance effects or those occurring following a disturbance or during dedicated study periods are captured.

Historical SSO Analysis

Already delivering benefits

Practical experience to date using the SSO monitoring solution on the British national transmission grid is very encouraging. Several months of data collected from a number of WMU devices are already feeding long-term reviews of observed SSO behavior, including recommendations for further investigations. So far, the expected generator torsional modes are observable in the network voltage and current signals, as well as other high frequency oscillations likely to be related to wind farms and other power electronics systems. 

The monitoring system was used extensively in the commissioning of series compensation systems, in initial live system tests, and in subsequent network operations and tests. The detected oscillations are generally very small and well damped, with the majority in the region of 2 V and 0.1 A at the 400 kV level. Equally there have been some instances of non-torsional modes with higher amplitudes and poorer damping—behavior that was to be expected but that warrants further investigation. The observations have enabled alarm thresholds to be better configured around a baseline of normal behavior, so that any excursions of behavior with raised amplitude and poor damping can be flagged in real time and for post-event analysis. This perfectly highlights a tangible benefit of SSO monitoring: awareness of real system behavior that leads to investigation and mitigation before it becomes a problem.

“In a nutshell,” Clark concludes, “what we’re offering with this new system is substantial reassurance and security against the risks of SSO, complementing existing SSO mitigation practices. This comes from better visibility and understanding of normal and abnormal states, validation of models and studies, and improved configuration of protection-based defense.”

An interesting mode
The new Grid Solutions real-time Grid Resonance System to provide early warning of emerging SSO threats and long-term review of SSO behavior features a new substation data acquisition function, the Waveform Measurement Unit (WMU), implemented in GE Vernova’s Reason RPV311 recorder, and a new central analysis, monitoring and visualization application within the e-terraphasorpoint WAMS software suite. 

RPV311 (Processing Unit)

The solution was developed in-house by GE Vernova and demonstrated under the VISOR project3 , and has also been deployed by SP Energy Networks to support the commissioning of series compensation on the British transmission network. Analysis of the system’s data has provided added-value from the outset. In one example, an oscillatory mode, seen across a 100-mile wide area, was observed not as a generator torsional oscillation and was present independently of the status of the series compensation. The mode varied in frequency, occasionally moving close to a generator torsional mode, and showed some occurrences of reduced damping and raised amplitude. Although the amplitudes involved were very small throughout the period of monitoring, this has provided engineers with valuable information to target further investigation as a matter of prudence.

Variable speed pumped storage, the latest in large-scale storage technology, enables grid operators to integrate extensive wind and solar capacity, match supply to demand minute by minute and further enhance energy production efficiency throughout their fuel portfolio.

In November 2006, 20 million European households were left in the dark following a power blackout. Within 20 minutes, Alpine dams were able to supply about 5 million homes with 5,000 MW, with the pumped storage plant of Grand’Maison, France, accounting for up to 20%. This is a prime example of how useful pumped storage can be in balancing the grid during unplanned outages of other power plants. But that is not its only benefit.

PSP flexibility: attractive for grid operators

Pumping water to store energy is not a new concept in itself. Pumped storage is the largest and most cost-effective means of storing energy for electricity grids, far beyond compressed air, lithium-ion and other storage technologies in use today. It is also an economically and environmentally efficient way of stabilizing supply on a minute-to-minute basis. When demand is low, a pumped storage plant (PSP) uses off-peak electricity to pump water from a lower reservoir to a higher reservoir.  

Then, when demand is high, the water is released and flows down to the lower reservoir through turbines that, within seconds, generate electricity and feed it into the network. This has been done for decades, with growing efficiency: nowadays, up to 80% of the energy consumed during the storage cycle is recovered and can be sold when demand peaks.

Double-fed induction at the heart of variable speed technology 
Double-fed induction machines with static frequency converters feeding the rotor is the preferred architecture for motor generators in variable speed PSPs with unit outputs above 50 to 100 MW. The rotor design of double fed induction machines is significantly different from conventional synchronous machines because the rotor of a double-fed induction motor generator has a three-phase rotor winding wound into a cylindrical rotor. By feeding the rotor with a low frequency AC current, a magnetic field rotating at the right speed is created to compensate for the turbine’s speed variation. 

As a result, it generates a magnetic field rotating at a constant speed – a fraction of the grid frequency – in the stator. This means the turbine rotation speed can be adjusted to benefit from the flywheel effect to perform fast power output or input variation or to optimise turbine or pump efficiency and regulate pumping water.

In addition, pumped storage enables utilities to operate their other energy sources at their most efficient levels, allowing fossil-fired and renewable energy sources to be run optimally. And it is precisely this last point that explains the recent boost of interest in pumped storage as part of an integrated solution to smooth out the fluctuations inevitable with increasing penetration of intermittent energy sources such as wind and solar power, since it can use their production at times of high output and low demand. “The real innovation at the heart of this growth comes from ‘variable speed’ pumped storage,” says Olivier Teller, PSP Product Director at GE Vernova's Grid Solutions business. “The possibility of changing the pumping power makes pumped storage plants much more flexible, which is very attractive for operators in balancing the grid.”

The grid always has to balance power generation and consumption precisely, and this balancing is harder to obtain with intermittent power sources. “So during low demand periods, variable speed pumped storage may be viewed as a much better alternative to bringing other flexible assets, such as gas plants, on line just to regulate the grid.”

To put it simply, Grid Solutions' variable speed technology allows power plant owners to adjust the amount of energy they pump at night or when there is a light load, meaning that conventional thermal power plants that are operated for frequency adjustment can be stopped. This helps utilities operate their fleets more economically while reducing CO2 emissions.

“Load balancing can be achieved using a clean, renewable energy source, replacing costly fossil fuels traditionally used for peaking,” Teller points out.

Extending the PSP operational envelope

With an installed base of 56 GW of pump turbines and motor generators, Grid Solutions is currently developing 6 GW of PSP projects worldwide. Three gigawatts are variable speed, and the other three are of the fixed speed type. Besides the flexibility benefit, some sites actually require variable speed, since a variable speed PSP can sustain a higher variation in the height (or head) between the water in the two reservoirs. “Challenging sites such as Nant de Drance in Switzerland and Tehri in India would have been impossible to exploit without variable speed pumps,” says Teller. 

All GE Vernova's in-house products and technologies for hydraulic turbines are designed and developed in the Global Technology Center (GTC) in Grenoble, France. This centre manages all the product development phases, from identification of customer need to aftersales service.

In 2008, Grid Solutions at GE Vernova expanded the GTC, equipping its scale model test laboratory with two new test rigs, bringing the total number of test rigs to six and doubling the site’s testing capacity.

With a pumped storage market expected to grow by 60% over the next four years (mostly in China and Europe), the GTC is now looking forward to extending PSP operational envelopes towards more challenging conditions (1) such as very high or very low head (>800 m and <50 m), increased head range, underground and sea operation, small decentralised PSPs, etc., as well as enhancing flexibility and power range.

(1) 40% of European PSPs are expected to be variable speed.

An extra 1,000 MW from a cavern under the Swiss Alps 
Switzerland, with its mountainous landscape, is a very active producer of hydroelectricity, which represents more than half of the total energy produced in the country. The steep altitude differences in the Swiss Alps create a particularly favourable environment for the use of pumped storage power plants. In 2009, Kraftwerk Linth-Limmern AG (KLL) decided to extend its Linthal power plant in the Glarus Canton of east-central Switzerland by constructing a new underground pumped storage facility that will pump water from Lake Limmern up to Lake Mutt (which is 630 m higher, at an altitude of 2,474 m). The water is pumped through a pair
of 1 km-long penstocks inclined at 45°, in order to reuse it for electricity production when needed. Grid Solutions will provide
four new 250 MW variable speed pump turbine and motor generator units. “The facility, which is installed in a giant underground cavern, will have pump and turbine capacities of 1,000 MW, boosting KLL’s output from the current 450 MW to 1,450 MW and putting it, in terms of power delivery, on a par with the Swiss Leibstadt nuclear power plant,” says Thomas Kunz, Global R&D Product Development Director at GE Vernova's Grid Solutions business. Many innovative components had to be developed for this project. The first units are to be installed next year, and Linthal commercial operation is due to begin in 2015.

A suitable STATCOM can be used to ensure that wind turbines comply with increasingly tight grid codes, particularly the low-voltage ride-through requirement. It also needs to be compact and flexible.

Over the last 20 years, wind power has asserted itself as an increasingly important part of the energy production landscape. The 2011 World Wind Energy Report projected that by the end of that year, total capacity would be around 245,000 MW and meet 3% of global electricity demand. Since then, the Global Wind Energy Council states that by 2020, 8-12% of global electricity could be supplied by wind power.

The rise of wind power has emerged as a challenge to the technology used to generate it and, as more and more renewable energies flow into the grid, grid operators have grown concerned about stability. Accordingly, they are introducing ever more stringent grid codes to ensure that grids can integrate renewable energy smoothly. Not all wind turbine technologies can comply with such demanding strictures, however. One that cannot on its own is the doubly fed induction generator (DFIG). Until recently, DFIGs were the most widely used variable-speed wind turbines. A DFIG’s stator is directly connected to the grid while the rotor is connected through a power electronic converter, which controls the generator’s speed and power factor. The converter is rated at around 30 % of the turbine’s nominal capacity, which was ample for wind turbine applications until grid codes required turbines to stay connected to the network during voltage drops to ensure low-voltage ride-through (LVRT).The drawback of DFIGs is that, in the event of a voltage dip, the voltage of the grid connected stator changes suddenly.

In the event of a sudden load change or low voltage incident like a short circuit in the grid, a STATCOM responds fast.

The rotor voltage is too low to compensate and so a disturbance current flows through the stator and rotor, damaging the converter. The DFIG’s original control strategy was to trip, but grid codes now require generators to ride through voltage drops and feed reactive power into the network to stabilize it. The only alternative is to enlist the support of a shunt-connected dynamic reactive power source. The most widely used is the thyristor-based static VAr compensator (SVC). But SVCs do not fit the requirements for (i) fast dynamic response, (ii) short overload capability, or (iii) the ability to provide maximum reactive output current during sharp voltage drops. However, one dynamic reactive-power compensator that does deliver on all three counts, and so ensures ride-through in the event of a network fault, is the static synchronous compensator, or STATCOM.

How STATCOMS ensure ride-through

“In the event of a sudden load change or low voltage incident like a short circuit in the grid, a STATCOM responds fast,” explains Ralf Jessler, Managing Director at GE Vernova's Grid Solutions business in Konstanz, Germany. It feeds capacitive reactive power into the network, increasing voltage at the point of common coupling (PCC), so helping the DFIG to stay connected for as long as it takes to isolate the short circuit. Once the fault has been cleared, however, the DFIG may experience the same kind of difficulties as it did when the fault occurred. The STATCOM must therefore once again stabilise the voltage at the PCC. “This is no issue,” adds Jessler, “because the STATCOM responds dynamically, in milliseconds, changing its reactive power from capacitive to inductive.”

In sum, then, a STATCOM ensures low voltage ride-through because it can continue to generate rated output or short time overload current even at low system voltages. Low-voltage ride-through is doubtless the most important capability required of a STATCOM, as illustrated by a wind farm project in Dunneil, Ireland, where the turbines were augmented by Grid Solutions' novel STATCOM, SVC MaxSine™. Without it, the generators would have fallen short of the local grid code for LRVT as they failed to produce enough reactive power to compensate the steep voltage drops. To help a DFIG ride through a fault event, overload capability is crucial. “Most STATCOMS are installed for voltage drops caused by short circuits, which seldom happens,” explains Jessler. “So we tailored MaxSine™ to deliver high overload for the 10 or 20 seconds it takes to isolate the short circuit. That way, we were able to make it smaller.” What’s more, an effective overload capability helps reduce the STATCOM’s installed power capability, which reduces its cost.

 We tailored MaxSine™ to deliver high overload for the 10 or 20 seconds it takes to isolate the short circuit.

Hybrid compensator keeps prices and flicker low
Brief dips in line voltage, causing, for instance, brief changes in lighting levels, are known as “flickers” and are a sign of poor power quality. They are typically caused by large loads whose active and reactive power demand fluctuates. The technology of choice for reducing flicker is the static VAr compensator (SVC). SVCs are traditionally used for reactive power compensation in such heavy industry applications as electric arc furnaces (EAF). However, the thyristors controlling the reactive power do not have enough bandwidth (i.e. they cannot respond quickly enough) to respond to fast changes in the load. The result is as much as a half-cycle time delay. Consequently, an SVC has at best a flicker mitigation capability of just 65 % and a flicker reduction factor of 2, which is often inadequate. These figures stand in contrast to those of VSC-based STATCOMs, which continuously control the output current and thus compensate load changes immediately. STATCOMS can achieve a flicker reduction factor of 6, while SVCs are more cost-effective when compensation power is high (above 20 MVAr). The ideal solution would appear to be an SVC-STATCOM hybrid. Alstom R&D teams have developed a concept known as “Hybrid SVC” that they have tested with an electric arc furnace. The result is a highly reliable compensation system with a flicker reduction performance that is almost as good as a STATCOM’s. It is 20 % cheaper to install than a STATCOM and costs 50 % less to operate.

Low losses, small size, high flexibility

At the heart of the SVC MaxSine™ is a voltage source converter with a three-level neutral-point clamped topology (3L-NPCVSC) and a patented control system. The main advantage of the 3L-NPC-VSC is that it enables commutation at low voltages. It also improves the harmonics spectrum and increases the quality and quantity of output voltage, thereby reducing the flicker level significantly in the network. The patented control system is what enables SVC MaxSine™ to respond to sudden network changes or resetting in a matter of milliseconds. It is key to the compensator’s prime function – ensuring the generator’s LVRT capability. Second only to ride-through in wind power applications is the importance of controlling power losses. SVC MaxSine™ considerably reduces transmission line and reactive power losses, thus offsetting losses that may occur through frequent switching of the converter.

Should one module malfunction or fail, other units continue to operate, so avoiding downtime

Also, because it is a medium-voltage system, it requires fewer power electronic devices to be switched on than low-voltage compensators, whose multiple devices must all pass current and therefore generate losses. Flexibility is a key feature of the SVC MaxSine™ STATCOM solution. Unlike conventional SVCs, which have to be re-dimensioned according to the prevailing network impedance and harmonics, the SVC MaxSine™ interoperates with existing network equipment and works with it to deliver compensation performance more effectively than a conventional STATCOM. Also its control system can be reconfigured to meet applications ranging from wind farms to power-hungry arc furnaces. With its compact, modular power electronics units housed in a container, SVC MaxSine™ can be configured to meet varying needs. The modular design then contributes to its high operational availability. The power electronic modules (each sealed in a steel container) are arranged in parallel, each acting as an amplifier and feeding current into the network.

It is a simple matter to add or remove them according to requirements. And should one module malfunction or fail, other units continue to operate, so avoiding downtime.

Geomagnetically induced currents (GICs) are caused by the sun’s coronal ejections. They may cause severe power grid instabilities and affect the normal operation of transformers. Some experts are persuaded that GIC could cause a major blackout.  Others are less certain.  Hence, the need for simulations of the phenomena as a step towards mitigating the risks for the networks.

Polar lights. Source ShutterStock

Variations in the sun’s activity have a powerful influence on our planet and may even damage its electrical infrastructure. This is particularly the case with coronal mass ejections (CMEs) when the solar corona releases huge quantities of plasma, a phenomenon that can happen up to three times a day at solar maxima. Fortunately, few of these ejections are directed toward the Earth, but when they are, masses of charged particles¹ may create “electrojets” of millions of amperes in the ionosphere. These electrojets induce local potential differences at the Earth’s surface, causing geomagnetically induced electrical currents that could affect the normal operation of metallic infrastructure such as oil and gas pipelines, railroads and power transmission grids.

The first recorded manifestation of these GICs occurred in 1847, when it was found that they were responsible for the breakdown of an electrical telegraph network. In March 1989, a severe geomagnetic storm caused the collapse of the Hydro-Québec power grid in a matter of seconds, and 6 million people were left without power for hours. Since then, power utilities all over the world have invested in evaluating the GIC risk and developing mitigation strategies.
 
¹It takes these particles up to three days to travel from the Sun to the Earth.

The GIC issue for power networks

“Geomagnetically induced currents used to be regarded as a cause of transformer failures due to internal heating from stray loss,” explains Ray Bardsley, GE Vernova's Grid Solutions business' Lead Engineer, Electrical Design. “However, modern thinking is that GICs do not normally cause transformer failures directly; but the effects GIC have on transformers can cause severe network disturbances such as grid instabilities and even blackouts.”

How does this happen? “Due to the local voltage differences induced by the electrojets at the Earth’s surface, a quasi-direct current (DC)—i.e., a current of very low frequency— may flow along transmission lines, entering and exiting via transformer neutral earthing points that are at slightly different voltages,” Ray Bardsley explains. Being quasi-DC, GICs cause the transformer core to have a very high AC magnetization current during a small part of each cycle, creating a high reactive power demand on the system. Moreover, the transformer is led to emit high levels of current harmonics into the system. These effects, caused by the asymmetric half-cycle core saturation, may result in protective relay malfunction. Moreover, the DC amplitude varies during a GIC event as it is transient (GICs occur for a few hours and then go away) and may have some high peak values between lower levels. “Therefore, customers increasingly demand information on GIC risks and expect the assurance that their equipment and grid are well designed and protected against GIC problems,” explains Alessandra Sitzia, GE Vernova's Grid Solutions business – Team Leader, Electrical Design.

²3D simulations are done in the frequency domain to reduce calculation time.

Numerical simulations are needed

“As testing the effect GICs have on a transformer is difficult to do safely, Grid Solutions decided to simulate the process using its SLIM proprietary electromagnetic finite-element simulation software for transformers,” Dr. Sitzia adds. To assess the resulting phenomena and associated risks to the network, a combination of 2D time-domain and 3D frequency-domain simulations² were performed for three different scenarios—no GIC, GIC at 10 amperes, and GIC at 100 amperes—to obtain estimations of some of the transformer behavior such as the core magnetizing current amplitude and harmonics, the revised flux distribution in the transformer tank, localized heating, etc.

Adverse effects due to high reactive power and harmonics

Simulation results  show that the AC magnetization current during a GIC event becomes asymmetric, with a very large increase of amplitude on one half cycle, but almost nothing on the other half cycle. “This high AC magnetization current demands high reactive power (VAr) from the system,” explains Ray Bardsley. “If the system is unable to supply the demanded VAr then the voltage will fall, and the system trips out as under-voltage protection activates.” Furthermore, the high amplitude AC magnetization pulses inject significant even and odd harmonics into the system, placing severe demands on the network. These harmonics are a “particular problem for shunt capacitor banks providing VAr support to the system, so just when they are needed they might trip out.”

During AC magnetization peaks, the core normally saturates, potentially leading to increased stray flux in some vulnerable items such as core clamping plates, windings and tanks.

Information from these simulations of core behavior under the influence of GIC is fed into full 3D non-linear magnetic field studies to allow the stray loss distribution in the transformer to be calculated for these new conditions. The temperatures on the transformer parts are then calculated using these stray losses as inputs.

Demand for transmission system voltage support is increasing along with growing input from renewables. At the same time, weak and aging grids, the retirement of thermal and nuclear plants, as well as little space for building new installations are limiting transmission system development. Next-generation STATCOM is the answer.

The integration of distributed generation into existing networks poses a number of challenges. The predictability of renewable energy sources is limited and the amount of power they produce fluctuates. Furthermore, wind farms require support from reactive power sources during recovery from line faults. GE Vernova helps TSOs to maintain power quality and power transfer capability using active network management based on future-proof smart technologies.

GE Vernova's utility-grade static synchronous compensator (STATCOM) solution is a custom-designed system to be installed on transmission grids to provide reactive power compensation and voltage control. Our design is based on a leading-edge modular multilevel converter (MMC) architecture with HVDC MaxSine® full-bridge power submodules. STATCOM operation characteristics differ from a classical SVC (static VAR compensator): STATCOM undervoltage performance is superior, while SVC masters overvoltages.

System Layout (shown with optional equipment)
Thyristor Switched Reactor (TSR) + Thyristor Switched Capacitors (TSC) for extended output power rating

STATCOM basics

The development of insulated gate bipolar transistor (IGBT) technology enables high power shunt compensation systems with voltage source (VSC), the next-generation STATCOM to complete GE Vernova’s FACTS offering. The shunt-connected STATCOM can generate capacitive or inductive output current independent of the AC system voltage. Jussi Pöyhönen, Grid Solutions Senior Lead Design Engineer, describes STATCOM advantages in shunt compensation. “The shunt compensation market is turning to STATCOMs thanks to their harmonic and undervoltage performance. Moreover, stringent harmonic performance requirements are more easily met, even in weak networks.”

Each phase of the VSC valve consists of a string of series-connected full-bridge valve submodules, each of them having its own DC-link capacitor. The STATCOM VSC valve current is controlled by switching valve submodules to its positive or negative DC-link voltage or zero voltage for voltage difference over the coupling impedance of a step-down transformer or a series reactor. AC voltage is controlled with capacitive reactive power, when the converter voltage is greater than the system voltage. If the converter voltage is less than the system voltage, the STATCOM produces inductive reactive power. VSC valve reactive current capability is symmetrical for inductive and capacitive operation.

The core of the STATCOM controller is a modulator in charge of valve submodule switching, applying novel algorithms including DC-link balancing and valve submodule sorting. STATCOM VSC valve submodules utilize proven HVDC design standards sharing the same design and manufacturing facilities. GE Vernova's STATCOM VSC valve has inherent transient performance thanks to the strongest DC-capacitor rating on the market.

Extensive self-diagnostic capabilities maximize reliability. Performance degradation and component faults are pinpointed in real time. High availability is ensured by a dual-lane redundancy control system configuration. A built-in event logger with automatic time stamping of 1 millisecond resolution and a synchronized transient fault recorder with up to 10 microsecond sampling allow for detailed analysis post-event.

The control system can be remotely accessed using a secure protocol. It allows remote monitoring using the built-in real-time monitor function and fault detection including diagnostics. To fulfill modern remote control interfacing requirements, the control platform supports an extensive set of industry protocols and custom protocols can be integrated as an option.

STATCOM advantages for utilities

STATCOM helps utilities in three different domains. First, to increase system stability and power quality by providing voltage control and support, reactive power control, power oscillation damping, and increased power transfer capacity. Next, it enables electro-intensive industrial processes to obtain a grid connection by controlling flicker level, harmonic voltage distortion, and voltage unbalance. Finally, it allows renewables to be connected to the grid in compliance with grid code requirements by providing fault ride through support and voltage control.

Jussi Pöyhönen sums up the advantages: “Our utility-grade STATCOM solution provides grid operators with reactive power to support grid stability in difficult network conditions and weak grids in a more compact package compared to traditional SVC solutions.”

The industry’s only model-based design control system

The advanced digital control (ADC) system from GE Vernova represents state-of-the art technology for shunt and series compensation to control and protect any connected equipment at over 10 times better performance ratings than previous designs. Thanks to hybrid processing technology (microprocessor plus field-programmable gate array, or FPGA) and high-speed serial connectivity, ADC provides top performance when running complex utility and industrial compensation algorithms. Such real-time performance allows control of modern insulated gate bipolar transistor (IGBT)-based voltage source converters, requiring sub-microsecond reaction time.

Advanced digital control (ADC) System

ADC incorporates model-based software design to provide fast, automatic and error-free code generation from control models, ensuring a greater level of confidence for the users. Software quality is greatly increased by eliminating errors during earlier stages of development using simulations of control software together with power electronics. Model-based design methodology also reduces time for control software design, testing and verification by up to 50% compared to traditional coding approaches, by automatically generating code from control models. This allows for very fast customer-specific software development and testing, which reduces project costs even for highly customized applications. The resulting control software is fully hardware-independent, giving engineers the freedom to define hardware connections.

In addition ADC introduces built-in observation and diagnostic features, such as the internal transient fault recorder, event logger, and engineering interface tools, which allow fast troubleshooting onsite and support commissioning. Ease of integration into control system software with power system modeling tools such as PSCAD provide the most accurate representation of system performance for planning and troubleshooting analysis.
ADC’s fully modular control system platform hardware is based on rugged, modern military-based VPX technology and state-of-the art commercial off-the-shelf components for better reliability and longer lifetime. VPX technology offers future-proof, higher control execution speed with higher controller-internal (backplane) data rates, and scale-up without sacrificing speed, while using established technologies from commercial and industrial markets, thus giving access to a wide knowledge community, support, and documentation

Dual-lane redundancy with hot-swap capability and no changeover unit increases the availability of the system, while a distributed signal acquisition system provides hundreds of analogue and digital channels with microsecond latency and large bandwidth.

ADC is type-tested according to IEC substation standards. It is an essential part of GE Vernova's SVC, STATCOM and hybrid (STATCOM + SVC) solutions, and is scalable to any project size and power.

Better weather prediction will be a key feature in combating the effects of climate change on grid reliability. Models based on machine-learning algorithms are a promising approach.

Key points to develop:

The combination of more powerful computers, increasingly sophisticated programming and the availability of vast quantities of data is transforming any activity involving a network, ranging from online shopping to cancer diagnosis. It is no surprise therefore that the electricity sector, whose power networks everybody depends on to function, is also exploring how the latest advances in science and technology can be used to improve reliability, efficiency, and resilience.

RWE, one of Europe’s most innovative and forward-looking utilities, has teamed up with GE Vernova to develop an outage prediction methodology that integrates data from a number of sources to predict and prevent outages and respond quickly before they occur. Manuel Weindorf, GE Vernova's Grid Solutions business' Technical Solutions Director, outlines the context. “Weather has always been a major influence on grid performance of course, causing and influencing around 70% of outages. With climate change we’re likely to see more extreme weather events and increasing threats to operations. RWE is already seeking ways to respond to the emerging challenges and maintain its high levels of customer satisfaction.”

Climate variables and variance

The GE Vernova team started by collecting asset, operational and incident-response data. The asset data contained the network topology of the substations and the distribution lines; data related to the assets; outages reported from 2006 to 2015; notifications received and actions taken regarding the notifications. RWE also provided its own data on a number of other features, for example physical asset characteristics and network topology, and nearly 30,000 outage reports.

GE Vernova acquired data from six weather stations associated with the RWE regions as well as historical weather data from the weather station nearest to distribution substations and other related grid assets. Weindorf stresses the complicated relationship with weather and climate change in Germany. “Integration of renewable energy sources is a key part of the strategy to combat climate change, and hopefully in the long run they will help to mitigate the negative impacts. But in the meantime, they can also cause some variation in power generation because of their intermittent nature and unpredictable generation profiles, which puts additional stress on related grid assets.” This is especially true for the low voltage side of the distribution grid where most of the DSOs today do not have a huge amount of visibility on the actual grid condition, as automation and monitoring capabilities are not yet deployed at full scale.

A walk in the random forest

Once the data had been acquired and the influencing factors identified, the next step was to select a modeling approach. A random decision trees model was chosen. This is an ensemble method, meaning that it uses multiple algorithms to give better predictions than would be obtained by any of the individual algorithms. It also minimizes “overfitting”—errors that occur when highly complex models fail to spot the underlying relationship and return random errors or noise instead. Other advantages of this approach include its lower computational requirement for large volumes of data compared to other models; its ability to handle both categorical and numerical variables; and the fact that it can deal with unbalanced and missing data.

The model was applied to both weather and non-weather features and evaluated with different metrics. These included a Receiver Operating Characteristic curve explaining the expected prediction quality in terms of ratio between right versus wrong predictions (true positive vs. false positive), derived from the training data provided. Indirect weather impacts had to be accounted for too, such as impacts on construction work leading to accidents that damage cables and equipment. Those kind of activities are influenced by given weather conditions (e.g., good weather could mean more road works while bad weather could mean bad working conditions and therefore more accidents/faults and slower progress.

The average true positive of outage prediction varies from 75% to 88%. The results show that historical weather data is an important predictor and variable in predicting a power outage, such as thunderstorms, rain, ice, fog, maximum temperature over the past three hours, and wind direction. Asset and geography-related features such as service area and voltage type are also important.

Teach your models well

Future iterations could test predictors other than on weather and incorporate features related to the outages themselves. The data set could also be enriched by incorporating social media feeds, for instance by identifying and analyzing outage-related keywords across a wide geographical area.

Weindorf is optimistic about the possibilities of machine-learning algorithms to improve network management and enable RWE to maintain high levels of customer satisfaction. “But,” he points out, “to learn, the machine has to be taught well. In the next stages, we’d like to use more and better data, data in its original form where possible, because aggregated and anonymized data can mask critical relationships. We may also need more geographical data to scale the models beyond two regions.”

GE Vernova’s outage restoration solutions

Damage and losses from increasingly severe weather events are costing our global economy more than $200 billion per year. From hurricanes to ice storms to wide-scale flooding, these severe weather conditions cause havoc on our power systems.

During these events, networks and substation assets can be damaged. Crews must battle storm conditions to find and assess every fault. Operators and dispatchers must navigate through a sea of disconnected data collected from various sources, leaving communities without power for extended periods of time.

To identify, assess, visualize, plan, mobilize and report all the network damage, utilities need interoperable systems and tools that are capable of sharing data between their back-office systems and their in-field teams. GE Vernova’s comprehensive suite of outage restoration solutions provide utilities with the interoperable tools they need to react and even anticipate outages, offering smart devices, geospatial visualization tools, outage and distribution management systems and mobile workforce applications. Utilities can ensure a faster and more efficient recovery.

Our smart controls, smart sensors, and substation automation devices allow utilities to implement automated switching plans that re-route and restore power, while line sensors wirelessly communicate with control sensors to identify the exact fault location.

Providing a single, accurate enterprise-wide view of the utility’s network and its assets, GE Vernova’s Smallworld Electric Office GIS enables utilities to visualize, collect, and assess each outage.
With integrated damage assessment tools and pre-configured workflows, utilizing solutions such as our advanced distribution management system (ADMS), standalone outage management systems (OMS) or integrated storm management systems, operators can make more informed decisions, mobilize field personnel, and communicate more accurate restoration times.

GE Vernova’s Mobile Enterprise and Damage Assessment systems allow crews to visualize and capture network data using multiple platforms and devices, providing up-to-the minute information back to the central control. Our unique set of outage restoration solutions empowers utilities to maximize grid reliability and minimize network downtime.

In line with the so-called fourth industrial revolution, traditional energy network substations are evolving into digital substations, with major breakthroughs that may provide enormous gains for T&D utilities. Asset digitization, situational awareness and decentralized automation are examples of new valued features being incorporated.

A combination of technology and macroeconomic factors is driving an in-depth transformation of the energy industry. To name a few: the transition toward a new mix of energy sources with greater content from renewable sources; the need to improve power delivery reliability and quality; and pressure to reduce operating expenditures on network assets. The resulting challenges for the electrical grid include integrating distributed energy resources, adjusting supply and demand in real-time, enhancing overall equipment performance while minimizing service downtime and blackouts, and so on. In consequence, next-generation electrical grids are becoming more complex and, thus, need to be more and more intelligent to cope with bi-directional flows of energy and information. This can be achieved by adding monitoring and diagnostics devices and smart software tools.

Electrical substations are at the core of this evolution. Being the critical nodes of the energy highways, “it is clear that, in order to make the grid more digital and intelligent, we need to start with making substations not only digital but intelligent, too,” says Javier Lopez, Senior Product Marketing Leader at Grid Solutions. “And this is what Grid Solutions has been doing in recent years.”

GE Vernova's digital substation journey: first steps

The first stage in the quest for intelligent substations consisted in “digitizing” the equipment. This means being able to interconnect these devices and to exchange data (measurements, binary I/Os, signals) among them by using a common communicating architecture. This was made possible by the arrival, at the beginning of this century, of the IEC 61850 standard dedicated to interoperable communication and data modeling for substation automation systems, based on Ethernet networks. A second development stage brought increasing integration of monitoring systems to provide substation operators and maintenance teams with clearer, more comprehensive and real-time understanding of everything that is happening in the substation: full “situational awareness.” Last-generation user interfaces, such as DS Agile aView, provide the necessary graphical support to react adequately to any electrical, safety or security issues.

Figure 1. Substation situational awareness on DS Agile aView

Modeling the substation for superior efficiency and performance

Digitizing the substation elements and dashboarding monitoring data was just the beginning of the journey toward truly intelligent digital substations. As Lopez points out, “the value chain starts with collecting and aggregating data with sensors and merging units, and sharing them across Ethernet architectures. But,” he continues, “the greater value resides in our capacity to make intelligent use of those data: applying analytics and modeling techniques, providing diagnostics and taking new operating actions.” Today, GE Vernova’s DS Agile digital control system is able to combine the insights from comprehensive situational awareness with statistics and modeling techniques, and to build a faithful replica of the substation. This is close to the GE Vernova’s “digital twin” concept, already used in the fields of power turbines and locomotives. A digital twin is a computerized model of a physical asset that can be used for obtaining state estimations, predictions and optimizations by making simulations applying the conditions and challenges the real equipment may face. Below are some of the applications that can be implemented, based on the substation’s digital modeling.

Predictive maintenance of assets

“Moving from reactive to predictive actions is a key benefit of GE Vernova’s digital twins,” says Lopez. “Similarly, by continuously tracking data from sensors embedded in the substation equipment, historical performance databases can be maintained for each individual device as well as for the whole substation, and digital models can be built for predicting how they will perform over time.” The predictive capabilities of the digital models combined with asset performance management (APM) software tools can help increase asset availability, ease lifecycle management and reduce spare parts inventory levels, costly downtime and operational risks for the users. The benefits for the substation owner can be very significant.

Dynamic power rating

Digital technologies can be applied to assess the expected performance characteristics of a system, given internal and external parameters and conditions. These are a combination of a digital evaluation of its “state of readiness” (based on sensor readings) and temperature, humidity, and other environmental data that can impact its performance. A use case of this is the DS Agile’s smart cooling system for power transformers, which dynamically manages the cooling system of a transformer, taking into account the instantaneous power load, internal status and ambient conditions in order to enhance its overall performance.

Figure 2. Real-time monitoring of a power transformer with smart cooling system

Another application is dynamic line rating (DLR), which consists of a real-time weather-based dynamic line and transformer rating software tool to adapt loading capacities to the prevailing environmental conditions (wind, rain), based on transmission line models. By calculating the lines’ effective power transmission capacity (known as ampacity) under peaks of wind and enabling their ratings to be adjusted in real time, the DLR solution allows utility operators to increase the production of wind power without additional investment in new transmission lines.

Figure 3. Prototype of DLR graphical dashboard for RTE’s Smart Substation project in France

Wide-area automation

Digital control systems of modeled neighboring substations can be interconnected to perform automation actions at grid level too. Through inter-substation control and protection data exchange and automation functions, wide-area control units such as the DS Agile WACU offer the possibility of exchanging fast IEC 61850-based GOOSE messages (control signals) between neighboring substations without the need to transit commands via a centralized grid control room. GE Vernova’s WACU can be programmed to provide smart grid solutions such as:

• fast network self-healing and power restoration from line faults
• load-shedding and islanding of critical grid areas or microgrids following grid instabilities to guarantee security of supply
• management of distributed renewable power source inter-connection
• voltage regulation and power flow optimization at a wide-area level.

Delivering high-value digital applications and services

As Lopez points out, “digital technologies are bound to transform the entire power sector value chain. At the present stage, the focus is progressively shifting from the hardware into more software applications and high-value digital services. With equipment tending to rapid commoditization, physical assets cannot provide long-lasting differentiation.” He concludes: “What will really give the edge for end users will be the ability to provide higher efficiency and productivity solutions and services by accessing, analyzing, and capitalizing on the valuable data from those assets.”

BIBLIOGRAPHY
[1] Klaus Schab: The Fourth Industrial Revolution (Jan. 2016)
[2] Hermann, Pentek, Otto: Design Principles for Industrie 4.0 Scenarios (IEEE paper, 2016)
[3] Marco Annunziata, Ganesh Bell (GE Vernova): Powering the future: Leading the digital transformation of the power industry (GE whitepaper, Sept. 2015)
[4] D. Chatrefou, A. Procopiou, S. Richards (GE Vernova): Substations Go Fully Digital but Stay Compatible (ThinkGrid article, Spring-Summer 2013)
[5] T. Buhagiar (RTE), JP Cayuela, A. Procopiou & S. Richards (GE Vernova): Poste Intelligent – the Next Generation Smart Substation for the French Power Grid (March. 2016)

To meet the tough duties of 420 kV/63 kA gas-insulated substations (GIS), GE Vernova (previously Alstom) teams have developed a new single-chamber, double-motion circuit breaker. It demonstrates major improvements in size, cost, and environmental impact.

High-voltage circuit breaker (CB) technology has advanced greatly since its introduction. Several interrupting principles have been developed to enhance performance and reduce operating energy. Among the various CB technologies Alstom has in its portfolio, gas-insulated substations (GIS) offer several advantages compared with air-, oil- or vacuum-insulated approaches. One is compactness, which explains why GIS are often chosen when space is limited and land is costly. As this becomes more significant with population growth and the trend of urbanisation, equipment compactness has become a key factor. “When dealing with high voltages such as 245 kV, the solution was originally to use two breaking chambers in series, each chamber taking half of the voltage. Then we developed a single chamber, but with high operating energy,” explains Jean-Baptiste Jourjon, Grid Solutions' GIS R&D group manager. “Advances in design then made possible the use of a single SF₆chamber or ‘single break’, but with a low energy operating mechanism.” Subsequently, the same principles were extended to even higher voltages such as 420 kV, i.e. beginning with two chambers in series and then, to improve compactness, moving to a single chamber via the ingenious “double-motion” technology. This permits a drastic reduction in the operating energy of the opening mechanism (see sidebar - box 4), allowing the adoption of a commonly used spring mechanism.

Getting up to 420kVA/63 kA

A “single-break” product rated up to 420 kV had been developed previously, but it was limited to 50 kA short-circuit current. It was a very large “puffer”-type circuit breaker with a high-energy hydraulic mechanism, so it was too large and too costly for today’s markets. Building on the self-blast double-motion technology that already existed for the 245 kV/50 kA range, Grid Solutions' engineers rose to the challenge of designing and constructing a new class of interrupter that could accommodate the most demanding mechanical and dielectric constraints of the 420 kV/63 kA GIS duty cycle, yet be compact, cost-effective, reliable, safer and more environmentally friendly.

Designing and constructing a new class of interrupter that could accommodate the most demanding constraints.

However, pushing the technology to increase both the rated voltage and the short-circuit current up to these targets seemed a very serious challenge, especially in the context of size limitations. “We had to establish new criteria, first to optimise the sizing of the interrupter (dielectrics, mechanics, pressure and thermal withstand, etc.), and also because the known rules for lower voltages did not work when applied to 420 kV,” says Jourjon.

40% footprint reduction

After some years of simulations, model improvements and tests on full-scale prototypes, the teams came up with a solution: the T155-CB3 single-break (or single chamber) interrupter, which is much smaller than the existing single-motion, double-break technology (two interrupters in series) and which provides significant advantages:

• a 40% reduction in opening energy;- lower environmental impact with 40% less SF₆ mass;
• a 38% mass reduction for one full pole with mechanism;
• phase width reduced from 900 to 700 mm;
• a 34% height and 40% footprint reduction; 
• and the possibility of a full three-phase bay integration with common points and disconnectors in a single package.

“With this single-chamber approach, the cost is dramatically reduced, as well as the environmental impacts,” says Jourjon. These include reduction of mass, meaning less use of material (aluminium), and SF₆ reduction, which is important for global warming. In addition, complete bay shipment reduces the carbon footprint of transport to site.

Great interaction between product lines

Throughout the five years of development, the Grid Solutions R&D departments working in both gas- and air-insulated switchgear product lines, in collaboration with the Research Center in Villeurbanne, all worked closely together on this ambitious technical project.

It also achieves a breaking time below two cycles at 60 Hz.

The aim was to maximise the knowledge-sharing of the experts, conceive and compare various technical options, and to benefit from standardized solutions whenever possible. “It also allowed us to incorporate industrial aspects early in the development process, to avoid the issue of a sophisticated technical solution that works but would not be cost-effective and would be difficult to manufacture in volume,” points out Jourjon.

A complete redesign of the whole GIS

The T155-CB3 “single-break” interrupter manages to reach 420 kV/63 kA switching and breaking performance with only one interrupting unit per phase and with low-energy spring mechanism for both energy storage and actuation. It also achieves a breaking time below two cycles
at 60 Hz, which means a higher level of protection for the equipment in case of fault currents. Breaking performance covers 420 kV systems globally, including 60 Hz networks. The compactness of this new circuit breaker led to a complete redesign of the whole GIS, with a new arrangement of the components (disconnectors, etc.) enabling complete bay assembly at the factory and full bay shipment to site. This means that all major components are tested (including optional embedded low voltage control cabinet) and sealed at factory, a further guarantee for a high level of quality and customer satisfaction.

It has a premium performance.

In addition, full bay shipment reduces erection time by 30%. Jourjon stresses: “The T155-CB3 is designed for easy accessibility with integrated gangways, and the specific gas partitioning ensures maximum availability in case of maintenance. So despite its lower cost (and size), it has very much a premium performance. It also offers comprehensive monitoring solutions and is ready for the full digital substation.”

Single-break, double-motion principle 
AC short-circuit current interruption involves blowing insulating gas through the electrical arc.

A piston moved by the operating mechanism increases gas density and generates an overpressure between the arcing contacts. As a consequence, gas flows through the arcing area, which cools down the arc and prevents its re-ignition after a current zero. The new Grid Solutions T155-CB3 circuit breaker uses SF₆ self-blast technology, where the arc energy contributes to overpressure generation without affecting the mechanism’s operating energy. At 63 kA, overpressure can reach up to 120 bar, which a spring mechanism could not withstand if the pressure were applied directly to the moving piston. For the 420 kV rating, very fast moving contacts are needed to withstand the recovery voltage between terminals following current interruption. To reduce operating energy and allow the use of its standard spring-driven FK3-6 mechanism, Grid Solutions developed a double-motion technique that consists of displacing the two arcing contacts in opposite directions using a linkage lever system (see figure), instead of displacing one contact as in traditional designs. The speed requirement from the operating mechanism is therefore halved. This means that the energy necessary for the opening spring is reduced by around 40%.

T155-CB3 single chamber 420 kV / 63 kA Interrupter: efficient, compact and easily accessible 

Today’s offshore wind farms use medium-voltage systems. However, a higher voltage design is more attractive at every stage, from layout to operation through to long-term costs – provided a number of challenges are overcome.

Governments worldwide are promoting renewable energies. But if they really want to achieve sustainable development, then solutions to environmental problems have to make economic and social sense, too. Wind farms are part of strategies for renewables, but expanding their contribution significantly will mean reconciling the often conflicting interests of policy makers, investors, clients, citizens, and the energy industry itself.

Offshore wind farms can meet many of the objections to onshore projects, especially new offshore designs that exploit the advantages of moving from today’s favoured solution using medium voltage 33 kV technologies to high voltage 66 kV designs. 

Double the voltage, half the current

Doubling the voltage to 66 kV means the current is halved. Robert Lüscher, Manager of Gas-Insulated Substation (GIS) Development at GE Vernova's Grid Solutions business, outlines the advantages of the new approach in terms of design, cost, and reliability. For a start, more strings of wind turbines can be linked to the substation busbar. Energy from a larger area can be handled by a single platform for a given 'power density' - the generation capacity installed in a given area. This advantage will grow as platforms move farther offshore and if their cost increases.

The 33 kV voltage level generally used offshore was determined by the availability of switchgear and transformers that could fit into the wind turbine. However, equipment that already exists for the onshore market can now be adapted for integration into the latest generation of 5 MW offshore installations, allowing the use of 66 kV AC designs.

We could even dream of a single centralized 66 kV/245 kV AC to ±320 kV/DC platform 

Lüscher explains that a future increase of wind farms rating above 500 MW can be technically and economically achieved by applying 66 kV. The increase in power of the wind turbine generators will reinforce these benefits. The main advantage can be seen in the central AC collector platform, where the 66 kV equipment would have a major advantage in comparison to traditional 33 kV equipment in terms of maximum transmitted power and size. "We could even dream of a single centralised 66 kV/245 kV AC to ±320 kV/DC platform - converter station, collecting the power of multiple wind clusters."

Moreover, the technology does not have to be designed from scratch; several practical solutions exist. Lüscher, whose role is to help integrate and customize GIS in offshore platforms and turbines, points out that GIS switchgear has already been integrated into offshore platforms for some years now, and higher voltage equipment could be integrated into offshore installations in a number of ways – in the tower itself, on top of the monopile, or in the jacket substructure. Some significant resizing may be needed to allow the tight integration into a wind turbine tower, since 33 kV cubicles are smaller than 66 kV GIS bays. Grid Solutions' enhanced type F35-72.5 kV gas-insulated substation was considered as a perfect candidate for this project. However, close cooperation with the skilled people of GE Vernova was needed to make the GIS fit. At least 15 different layouts of the GIS were intensively studied to find a solution that matches all the technical requirements and also accommodates all possible wind farm collector system configurations. On the other hand, a 66 kV switchyard requires fewer bays overall on a central 500 MW-rated collector platform, so the 66 kV equipment in fact needs less space than the commonly used solution in 33 kV.

Future 66 kV-rated GIS equipment could be designed completely SF₆-free and therefore contribute a major step to GE Vernova's commitment to sustainability.

The benefits of dispensing with a platform

Removing the extra platform needed for the 33 kV design has a number of advantages, not least avoiding the cost and difficulty of accessing remote platforms in rough conditions. The two platforms may be up to 50 km apart, and a range of factors can affect the performance of the cable linking them, apart from the purely mechanical stresses and accidents that any equipment on the sea bed is exposed to. For example, the cables need to compensate reactive power, the power that exists in an AC circuit when the current and voltage are not in phase.

Operating at 66 kV means making extra efforts to ensure the equipment can withstand various over-voltages, notably the temporary over-voltages (TOV) that can occur when operating conditions suddenly change, and the switching over-voltages that happen within the first 20 ms after switching events, such as energising the cables.

With some studies suggesting that switching to 66 kV could double transmittable power, Lüscher argues that as well as needing fewer substations, the technology has other significant advantages. “We should be able to work with larger arrays, with more turbines in each array. In any case energy transport is more efficient at 66 kV, so system losses are cut.”

The concept is now being commercially offered with the Haliade™ 150-6 MW wind turbine developed by GE Vernova's Grid Solutions business. The integration of the GIS into the wind turbine is based on pretested modules on a single frame with up to three cable feeders plus protection to the main transformer, ready to be installed in the wind turbine tower.

Remote power to vital systems of the wind turbine is provided via reverse injection through a power voltage transformer.

Environmental and standards challenges

Lüscher describes the multiple challenges the various teams had to overcome in adapting and inventing solutions. “Exposure to the highly saline marine environment is one problem, of course. Then there are the high shocks and accelerations the equipment has to resist at every stage from construction, transport, installation and commissioning on site, and last but not least some of the most violent weather in the world.” 

One difficulty was the lack of specific standards for such a pioneering application in offshore conditions. The team used similarities in the earthquake-withstand capability for the design and obtained good correlation of test results with the simulation.
 
Lüscher points out that there is a high chance that the new higher voltage concept becomes a major contribution to making energy systems greener. “It’s helping provide energy more reliably, at lower cost and with a lower environmental footprint.” In other words, it makes economic, environmental, and social sense. There are multiple conventions covering the aspect of raising the system voltage and their potential impacts; the trend is going that way.

Higher, bigger, farther

Ramon Piñana: Head of Electrical Systems in the GE Vernova R&D department

Integrating such high-voltage level equipment into an existing wind turbine design means facing several challenges. When voltage increases, equipment size does as well. And this is not limited to switchgear – the wind turbine power transformer and cables also get bigger. Space inside the tower or transition piece is very tight; moreover, its circular shape does not facilitate easy integration of a square-shaped GIS. The tower door was another limiting factor and as such a design driver of this HV equipment. To overcome this problem, two activities were needed; first, reduce the GIS footprint as much as possible by removing any accessory or feature no longer needed in wind turbines. Efforts to shorten length, reduce width and cutting corners were made to find a suitable size.

Other requirements considered during the adaptation work were linked to operation and maintenance needs. As size increases, so does the weight. This means finding new methods and tools to deal with such large systems in the event of on-site reparation or complete system replacement, such as bigger beams and special cranes to deal with the new weight.

Stringent vibration requirements were also a must-have feature to incorporate into the design. Vibrations may come not only from normal operation of the wind turbine or constant splashing of sea waves against the tower foundations, but can also occur during transport between the tower assembly plant and the site, when the equipment can experience severe accelerations. The people at GE Vernova were able to come up with an optimal solution thanks to their expertise and know-how acquired during years of similar demands such as those of seismic-sensitive sites.

The new offshore wind solution adapting the Haliade™ 150-6 MW offshore turbine to a voltage level of 72.5 kV will help cut electrical losses, simplify wind farm collector system layouts, reduce the cost of cable layout during execution and potentially also allow the use of smaller cable sections – and therefore reduce the cost of energy.

Although further design details will be needed since this component is usually tailor-made for a specific site or project, we can now already say that GE Vernova is ready to offer this solution to the market.