Jesse Berst, chairman of the Smart Cities Council, offers his vision of a smart city and what it can do for its inhabitants.

We talk more and more about smart cities. How would you define a smart city?

Jesse Berst: In the broadest terms, a smart city uses computers and communications to improve livability, workability, and sustainability.

In terms of technology, a smart city collects, communicates and "crunches”. It collects information about the city's conditions (its streets, buildings, energy, water, air quality, etc.). It communicates that information where it is needed using a citywide network. Then it "crunches" (analyses) the data to improve things.

In terms of what it can do, it offers three broad capabilities. The first is situational awareness – knowing what is going on all across the city in real time. Rio de Janeiro's control center is a well-known example, since it integrates real-time information from 30 different departments into a room full of giant screens. The second is prediction. Not just knowing what is going on, but predicting what is likely in time so as to be able to do something about it. The world over, cities are beginning to send police to where they WILL be needed; repair crews to equip what WILL fail soon; and emergency services to areas that WILL experience a flood; and so on. The third is optimization. Humans could never hope to manually optimise an urban transportation system to reduce delays and congestion. But computers are doing just that in Dallas and Singapore and elsewhere. Likewise, computers can improve power grids, water networks, building energy management, travel routes for delivery companies and hundreds of other systems.

Is there more than one type of smart city (like metropoles/provincial medium and small cities)?

J.B.: I would not divide smart cities so much by size. One of the beauties of cloud computing and managed services is that solutions developed for large, pioneering cities are now available to smaller towns, too. Small cities can get world-class, enterprise-level, ultra-secure solutions for a single monthly fee. Without capital expenditure. Without setting up a big data centre. Without hiring expensive computer experts
.
Rather, cities tend to differ by what they emphasise first. Some start with transportation. Others with smart energy and smart grid. Others with smart policing. Still others with smart payments to be more inclusive of low-income families. Others with Open Data and digital government services. Eventually, of course, every aspect of a city will become smart and be connected to the other departments.

The best cities have a vision for themselves – where they want to be in 20 years. Then they can apply technology to serve those larger goals.

What could our cities look like in, let’s say, 30 years?

J.B.: Cities that choose to get smart will be far more livable in 30 years – healthier, safer, better air quality, far more convenient thanks to ubiquitous intelligence. Everything will be connected and everything will adapt to you. Even your city government will come to you on your phone, tablet or (30 years from now) the computer implant in your brain.

Smart cities will be far more workable. They will have lean, cheap, reliable, resilient electric power along with faster, less congested transit and many other functions that make a city globally competitive.

And they will be far more sustainable. They will provide all these benefits without stealing from future generations. No more guilt!

What contribution is expected from the power transmission and distribution sector to develop these smart cities?

J.B.: Electric power was the foundation of the Industrial Revolution. Along with computers and communications, it will also be the foundation for the Digital Revolution. Without clean, cheap, reliable electric power, the dream of a smart city is not possible.

What are the decisive factors that could speed up this trend?

J.B.:

• Open standards. Organizations such as IEEE, ISO, ITU, IEC and others are already at work on this.
• Interoperability, which starts with standards, but also requires vendors to "pre-integrate" and test their solutions to ensure they work together.
• Financing solutions that let us get started now to build the digital infrastructure that will be the platform for decades of future prosperity.
• Visionary leaders who see the better world we can have for ourselves and our children and are willing to lead the way.

Line-to-ground capacitors are used to alter transient recovery voltages and allow circuit breakers to interrupt fault currents. Eliminating them enables substation design to be simplified, maintenance to be reduced, and overall substation costs to be cut.

Sometimes a solution can create new problems. That’s exactly the case when dealing with short-line faults. These are faults occurring on an overhead transmission line a few hundred meters to a few kilometers away from the circuit breaker terminals. The fault condition is characterized by a very rapidly rising voltage called Transient Recovery Voltage (TRV) across the breaker contacts that occurs a very short time after current interruption.

Transient currents and voltages are generated while closing or opening the electrical contacts associated with the circuit breaker, including disconnector switches. They are short-lived (typically less than one cycle) and may be repetitive due to the relatively slower movement of the disconnector switch blade. The traditional solution to deal with TRVs is to install line-to-ground capacitors on one or both sides of the circuit breaker to modify the delay and rise times of the transient voltage.

Circuit Breaker with Free-Standing Capacitors

Circuit breakers are usually divided into two families: “Live Tank” and “Dead Tank” units. Dead-tank circuit breakers are usually grounded through jumpers connecting the terminal pads on the structure to the substation grounding grid. During closing, the equivalent capacitance of the substation behind the disconnect switch feeds the transient into the line-to-ground capacitors through the disconnect switch. During opening, the disconnect switch has to break the load current of the capacitor and can experience multiple restrikes until the distance between the jaw(s) and the blade are sufficient to withstand the voltage appearing across them. Within the circuit breaker, the path to ground normally consists of multiple trajectories including tanks, structural elements, welds and bolted connections. Victor Hermosillo, Grid Solutions R&D Manager, explains: “In a traditional design additional measures are included to control the path and prevent arcing between components, damage to components inside the circuit breaker control cabinet, coupling into control wiring, and transients transmitted into the control house.”

Condition leading to transients during the energizing of breaker-mounted line-to-ground capacitors

Eliminate the need for additional capacitors

The usual response is to mount capacitors on the circuit breaker to control the flow of the currents via separate conductors between the circuit breaker tanks and an additional conductor between one tank and the grounding pad on the structure. These grounding elements can be connected to some of the breaker elements along their path or can be entirely isolated. Both approaches have their drawbacks. Mounted parallel to the circuit breaker, the extra weight of the capacitor requires increasing the capacity of support structures and foundations. Free-standing capacitors require additional space in the substation as well as added structures, terminals and foundations.
 
For Hermosillo, the Grid Solutions DT1-145 63 dead-tank circuit breaker, jointly developed by teams in the US and France, is the way forward. The new design breaks from previous configurations by removing the need to install adjacent capacitors. “Although eliminating the need for line-to-ground capacitors, the new DT1-145 63 withstands the transient currents and voltages generated during switching operations, and minimizes their effect on substation equipment.” 

Dead-tank circuit breaker rated 145 kV, 63 kA, 60 Hz

New self-blast, double-motion interrupter technology

A spring-based FK 3-4 type mechanism and third-generation SF₆ self-blast, non-linear double-motion interrupter technology have now been applied to the DT1-145 63. Each pole includes one single-pressure, partial dual-flow design interrupter and uses a combination of SF₆ gas puffer action and self-blast/thermal action for interruption. When the current is interrupted, a transition from the conductive to the insulating state occurs within a few milliseconds.

Low-energy FK3-4 mechanism

During opening, an arc forms across the arcing contacts of the interrupter. Nozzles encapsulate the arcing contacts, which direct gas flow across the arc. The gas flow developed within the interrupter unit quenches the arc. Smaller currents, with values in the range of the continuous current rating of the circuit breaker, are interrupted by puffer action, which consists of a piston compressing an SF₆ gas volume inside a cylinder. Higher currents, up to the rated short-circuit current, are interrupted by self-blast action. Intermediate currents are interrupted by a combination of puffer and self-blast action. The operating mechanism supplies the energy for contact movement and for compression of the puffer volume. The double-motion technology of the interrupter has the advantage of decreasing the amount of energy required to operate the breaker and decreasing the kinematic energy of moving parts.

Double Motion Interrupter

Industrialization and testing

Each pole unit consists of a cylindrical aluminum tank containing one built-in, electrically insulated interrupter unit, two porcelain or composite bushings for insulating line voltage from ground, and current transformers. Pockets on the top of both ends of the tank contain doughnut-type current transformers. The mobile contacts of the interrupter unit are connected to the operating mechanism by insulating rods, shafts and levers internal to each pole, and externally via a common mechanical linkage system.

The tank is formed from a single-piece aluminum casting. This reduces potential for leaks, compared to tanks of several pieces requiring additional sealing surfaces. In addition, each circuit breaker is tested using Grid Solutions’ proprietary gas-tightness testing system, which provides quantifiable test results on the breaker in its fully assembled, as-shipped condition.

Short-line fault tests on the DT1-145 63 for ratings of 145 kV, 63 kA, 60Hz at 90% and 75% of the maximum rated short-circuit current show the benefits of the new design. The increased opening speed leads to longer gap distances in the interrupter, giving lower electric field intensity across the gap. Effective pressure rise in the thermal volume promotes mass and heat flow away from the arcing region. Optimal gas flow in the thermal volume and downstream hot gas exhaust path helps to obtain adequate conditions across the interrupter gap during the first microseconds after current zero.

Conditions across the interrupter gap prior and after current zero crossing

Safer and more cost-effective

The DT1-145 63 design integrates safety and cost-effectiveness criteria, too. All linkages and shafts are enclosed inside a cover that prevents personnel from touching any moving parts. Breaking chambers are factory assembled and may be replaced as complete assemblies. The key interrupter sub-components, consisting of the mobile contact assemblies and stationary arcing contacts, may be replaced individually.

As Hermosillo puts it, electrical and mechanical engineering is only part of the story. “We also pay attention to who is going to install and operate the equipment, where and for how long. The DT1-145 63 is factory tested and adjusted and does not require any special tools for installation. On-site installation takes only a few simple steps and it is easy to operate. Moreover, thanks to its low energy mechanism and lifetime lubricants, the DT1 series is virtually maintenance-free, even in severe environmental conditions.”

DT1-145 63 during Power Tests at CERDA in Villeurbanne, France

The ability to mitigate switching transients is becoming a key issue for today’s grids as the generated stresses lead to power quality problems and accelerated ageing. The RPH3 digital synchronous switching relay has been applied to power transformers, resulting in reductions in overvoltages, inrush current—and costs.

The increase in electrical power demand, energy market deregulation, the introduction of new operators and producers, and the variety and intermittency of new power sources (wind farms, solar farms, etc.) require high-voltage transmission grids to withstand an ever-growing number of switching operations. The transients resulting from these operations generate stresses on all substation and network equipment, leading to potential power quality problems and accelerated ageing, incorrect protection relay tripping (and, in the worst case, even flashovers). “To mitigate such stresses and improve power quality, controlled switching is a sound and cost-effective alternative to adding circuit-breaker closing resistors, over-rating electrical equipment, and installing additional protective devices,” says Farid Aït-Abdelmalek, Senior Software Build & Release Engineer at GE Vernova's Grid Solutions business in Aix-les-Bains, France. 

A microprocessor-based synchronizing relay 

Energizing of power transformers deserves particular interest not only because of electromechanical constraints generated by strong inrush currents, but also because it has a direct influence on power quality and overall electrical transmission system reliability. A thorough investigation program focusing on energizing strategies and power quality, supported by field and lab tests, led to the optimized programming of RPH3—an advanced microprocessor-based synchronizing relay already used as point-of-wave switching of shunt reactors—and capacitor banks. RPH3 is suitable for the controlled switching of power transformers, which is able to reduce overvoltages, inrush currents and, ultimately, costs.

Switching sequence: a compromise

The ideal switching sequence of most power transformers with phase coupling corresponds to a closing operation at the time of flux matching, where the prospective flux equals the magnetic core residual flux for the first winding to close. For the remaining windings to close, the prospective flux should be equal to the dynamic flux imposed by the winding already closed. “You might think that taking into account the transformer magnetic core residual flux for each energizing sequence is the best solution to control the level of inrush current and its consequences,” explains Alain Fanget, Senior Expert at GE Vernova's Grid Solutions business. “However, due to flux sharing, the above sequence is a compromise: to reduce the maximum flux error for all three phases, the winding with the highest level of flux is commonly energized first, which could impose a compromise for the two remaining ones. The straightforward situation would be to reach zero residual flux condition.”

Energizing strategies

Therefore, when performing power transformer controlled energizing operations, the main methods usually considered are: 

• energizing at fixed switching angles without considering the residual flux level, usually with assumption of zero residual flux, in order to avoid worst case (closing at maximum flux difference)
• energizing at fixed switching angles under consideration of a known residual flux level fixed by previous controlled de-energizing or by external conditions (loaded opening, presence of external impedances leading to self-demagnetization, etc.)
• energizing at variable switching angles taking into consideration the residual flux level computed with the aid of a controlled switching device such as the RPH3, regardless of the previous de-energizing condition

A combined approach

An experimental study has been performed to compare and identify the best energizing conditions for a power transformer (see tables and figure). Statistically, it appears that the most suitable strategy to energize a power transformer is to control the previous opening conditions, given that this is possible. If it is not possible (as in the case of a protection operation where the opening timing cannot be controlled), the best solution is to compute and use the residual flux level. Hence the two most probable scenarios: “controlled opening-controlled closing,” and “random opening-controlled closing with residual flux.” 
 
Aït-Abdelmalek says: “The RPH3 controlled switching device has been programmed to be able to make the distinction—it both calculates the flux and controls the opening and thus the residual flux level in the power transformer—and to adapt the closing switching angles for the circuit breaker.” This innovative approach (patent pending), which automatically shifts from one strategy to the other, stands out as the ultimate compromise for mitigating transient phenomena. 
 
To know more, read the conference paper or contact our expert, Farid Aït-Abdelmalek.

To overcome the slow commercial uptake of hybrid HVDC circuit breakers, a long-range project is reconsidering gas-discharges tubes for use in HVDC circuit breakers. Stakes are high, since it may lead to a considerable decrease in cost, complexity and footprint of HVDC breakers and, moreover, with the opportunity to mount them in easy-to-install and maintain transportable containers…

Although the first DC circuit breaker concept was proposed in the 1970’s (using gas-discharge tubes at that time), it took around 40 years before the first economical, thus acceptable concept for a commercial use in a HVDC system^[1]  was developed: the ‘hybrid’ DC circuit breaker. Laboratory tested in 2013, it offered – at last – sufficiently low losses to be economic in a commercial HVDC system. “However, the commercial uptake of such hybrid breakers has been slow, mainly because of their relatively large cost, complexity and footprint” explains Colin C. Davidson, from GE Vernova's Grid Solutions business. “New developments using optimized gas-discharge tubes could completely change this picture”.
 
^[1] Grid operators increasingly use high Voltage Direct Current (HVDC) to carry high power over long distances, as direct current (DC) is superior to alternating current (AC) because it can transmit power without capacitive or inductive losses.

The basics of hybrid DC breakers

The first HVDC schemes indeed used mercury-arc valves, a type of gas-discharge tube for the conversion between AC and DC; these mercury-arc valves allowed to construct single switches offering voltage ratings of hundreds of kilovolts, a long operating life and a high robustness to faults. Afterwards, due to their high maintenance requirements, these mercury-arc valves were replaced by semi-conductor devices such as thyristors (for Line-Commutated Converter HVDC) and, later, IGBTs (for Voltage-Sourced Converter HVDC). Semiconductor devices were also proposed for all published variants of the ‘hybrid’ DC breaker concept until 2017.  Hybrid DC circuit breakers are built (see figure 1) with a mechanical switch (ultra-fast disconnector), low- and high-voltage semiconductor switches (PE1 and PE2) and a surge arrester which provides the reverse electro-magnetic force (EMF) needed to drive the fault current to zero, absorbing the inductive stored energy in doing so^[2].

Figure 1: Basic concept of a hybrid HVDC breaker

However, the component count in these hybrid concepts is very high (and expensive), due to the hundreds of semiconductor devices needed to withstand such high voltages. So “the advent of a single high-voltage switch capable of withstanding the entire terminal-to-terminal voltage of the DC breaker could be transformative” points out Davidson. Rather than searching for 100% innovative concepts, why not look back for the future?

^[2] The difficulty of the complete operation can be illustrated by comparing it to the successful catching, in a ‘blink of an eye’, of a 1-ton mass falling from a 450 m height.

A new generation of gas-discharge tubes

As a matter of fact, GE Vernova was one of the pioneers of HVDC starting with mercury arc valves, a type of gas-discharge tube, more than 50 years ago. The advantage of this technology was that the mercury cathode, being liquid, was self-restoring. This gave the valve a longer operating life than any gas discharge tubes using solid cathodes (such as thyratrons), and a robustness to faults that cannot be emulated by semiconductor-based switches. The company and its predecessors built both the first commercial thyristor-based HVDC scheme (Eel River, in 1972) and the last commercial mercury arc scheme rated at 150 kV dc and 1800 A, the largest such valves ever, both in Canada. So, what if there would be a chance to obtain the same advantage without the inconvenience?
 
They were in brief:

• the toxicity of the mercury cathode material,
• the long anode column needed to provide stable high-voltage operation
• the occurrence of “arc-backs” during which the valve temporarily and incorrectly conducted current in the reverse direction
• the high maintenance requirements arising from the vacuum pumps and other mechanical apparatus needed to maintain a vacuum on the – relatively large – tube assembly

“Experts of GE Vernova’s Global Research Center (GRC) thought that some old electrical concepts sometimes judged obsolete, could be given new life by steady improvements over the years in materials, components, processing, controls, and software, as it occurred in high power RF applications (microwave ovens, radio and TV transmission, radars) as well as in X-ray medical imaging” Davidson explains. This is all the truer since a new generation of gas-discharge tubes appeared, offering a much more compact solution than thyristor or mercury-arc based valves and – crucially – the ability to turn on but also to turn off current. An ideal first application for such a gas-discharge tube could be HVDC, to replace the complex and bulky high-voltage semiconductor system of the hybrid DC circuit breaker by a single gas-discharge tube.

Potential advantages are obvious. Single tubes can stand off and switch high voltages and for example, x-ray tubes operating at 600 kV can be purchased off-the-shelf. Tubes can carry potentially large currents, essentially in proportion to their active cross-sectional area, and they can switch quickly (the order of a microsecond), similar to thyristors.

Gas-plasma tubes

GRC selected gas-plasma tubes over vacuum tubes based on their lower forward voltage drop during operation. While HVDC converters were identified as a particular application for such tubes, they could particularly well function in frame of the DC breaker topology. With this in mind, GRC recently decided to launch a long-range project to investigate such tubes.

Several objectives have already been accomplished. Tube prototypes constructed at 40, 100, and 300 kV, provided knowledge of the necessary materials, engineering, and construction methods.  And unlike their mercury-arc predecessors, which required a long anode column with sophisticated grading electrodes to withstand high voltages, this new generation of tubes (Figure 2) is “remarkably compact, much smaller than traditional mercury arc or present-day thyristor valves”.

Figure 2: New generation gas-discharge tubes – cross section and principle of operation

Gas-discharge tubes in DC Circuit-Breakers

Various tests and a close examination of the plasma within the tubes during operation has revealed new, unexpected operational plasma states, some of which have lower forward voltage drops than previously expected, which can pay benefits in various applications. In HVDC hybrid breakers, Figure 1, the idea would be to substitute the auxiliary branch components (PE2) for a gas-discharge tube, keeping the main branch components (PE1 and the ultra-fast disconnector) essentially unchanged. “Moreover, since the DC circuit breaker operates infrequently, the operating life of the cathode material is not a concern, and the resulting DC circuit breaker could be much more compact than today’s solution, in a way that an outdoor, containerized, factory-tested solution could become feasible” reveals Davidson.

Splitting the dc breaker

Let’s take a ±320 kV VSC HVDC scheme with one breaker at each pole as an example. As the Transient Interruption Voltage (TIV) for a DC breaker—i.e. the peak voltage that the DC breaker should produce in order to force the current down to zero— is typically 150 percent of the nominal DC voltage, the breaker would require a TIV of 480 kV. This is fully achievable with a single gas discharge tube resulting in a very compact system. However, it is possible to divide the circuit breaker in smaller stages and to use it as current limiter. By using smaller stages as necessary for current interruption, the DC breaker can prevent the further rise of current due to remote (out of zone) faults, leaving the duty of interrupting the fault current to another DC breaker, further upstream.
 
Splitting the breaker presents two additional advantages:

• redundancy: if one modular DC breaker unit is unavailable, although the DC breaker may be unavailable for fault clearing, it can still be used for current limiting if required; and,
• simplification of mechanical configuration: the modular construction could simplify the mechanical configuration of the DC breaker and its housing.

Coming back to our example, the base of the 320-kV breaker’s structure are four identical modular sub-breakers, each of them with a nominal DC voltage of 80 kV and a Transient Interruption Voltage of 120 kV.

Outdoor mounting

One major limit of the commercial uptake of classic hybrid CBs is the (perceived) need for them to be located inside a large climate-controlled building similar to a valve hall, which precludes the possibility for DC breakers to be added as a retrofit on existing point-to-point HVDC schemes due to the lack of space.

Normally, HVDC converters are housed in special climate-controlled buildings because the high DC operating voltages cause particulate pollution to adhere to the insulating surfaces of the converter. In the case of a DC breaker, all components are normally operating at the same electrical potential – that of the DC line in which the breaker is inserted. It is therefore appropriate to enclose the DC breaker components in a conductive housing that is at DC line potential. The DC breaker components are therefore inside an equi-potential housing (in normal operation), and there is no tendency for these components to attract any atmospheric pollution. The enclosure therefore does not need onerous requirements for filtration or air-tightness.

As a result, a two sub-breaker scheme is obtained, each breaker rated at 80 kV nominal voltage (120 kV TIV) installed inside a midpoint-connected typical ISO 668 shipping container. The DC breaker components only see a transient voltage of up to 120 kV with respect to the container. As the air clearances at such a voltage are modest, it leaves enough room inside the container for the DC breaker equipment itself.

To make a complete 320 kV DC breaker, two such units are connected in series, each unit being mounted on an insulated pedestal (Figure 4). The DC breaker components are factory-assembled, tested and shipped to site inside the containers, with only the wall bushings, corona rings and support insulators being added on site.

Figure 3: A modular DC breaker unit consisting of two sub-breakers, each rated at 80 kV nominal voltage (120 kV TIV) inside a midpoint-connected container.

“Avoiding the need of a large climate-controlled building to house the breaker, just using a typical ISO 668 outdoor container could pave the way to the construction of DC grids,” concludes Davidson.

DC circuit breakers will be essential for the development of DC grids; however, the technology is in an intermediate state where the concepts have been proven up to mid TRLs but remain relatively large and potentially uneconomical. There is possible effective engineering, but full-scale product development is difficult to justify because of the limited commercial outputs. A gas-discharge tube-based hybrid DC breaker could potentially result in step-change as a more economically viable proposition with significant footprint and volume reduction compared what has been proposed so far.

The continued commitment to develop and evolve its products has enabled GE Vernova to maintain a strong position in a competitive HVDC market and provide an enhanced and flexible solution for new and replacement HVDC projects. The H450 HVDC thyristor-based valve is the latest such development, providing the ideal platform for future HVDC projects such as the Jeju Bipole 1 valve replacement in Korea.

HVDC converter station for Kepco's Jeju project installed on mainland

In Q1 2017, GE Vernova were successfully awarded an LCC HVDC Refurbishment Project in Korea. The project scope was for the replacement of the valves and controls of an existing 300 MW +/-180 kVdc Bi-Pole scheme. The scheme linked the mainland of Korea in Haenam to the island of Jeju. The key for GE Vernova to be able to undertake such a refurbishment project was having an LCC product portfolio flexible enough to provide an improved solution. Mark Donoghue, Principal Engineer at Grid Solutions, explains “This was critical for this type of scheme where there was a significant physical size and positioning constraint placed on the replacement valves due to the existing converter building which could not be modified”.

Haenam' HVDC converter substation building

H-Series valves evolving through the age

The solution was to use the latest development and evolution of the H400 series valves called the H450. This is the culmination of a number of major developments over the last fifty years. In order to understand where the H450 sits in the evolution of thyristor based HVDC valves, let’s look at the history of the GE Vernova valve family.  The first-generation oil-cooled outdoor thyristor valve was developed in the late 1960s with a pilot installation commissioned in 1971 using three parallel connected stacks of 37 mm 4 kV thyristors. This was followed in the early 1980s by the H200 series valves which were forced air-cooled, air-insulated indoor valves using 2 parallel 56 mm 4 kV thyristors per level. In the late 1980s, this was followed by the H300 series valves, the first water-cooled indoor floor mounted valve utilizing single 5.2 kV 100 mm thyristors per level. Finally, the latest H400 series suspended water-cooled indoor valve using single 8.5 kV thyristors with options for 100 mm or 125 mm thyristors per level was introduced in 2003.  This was developed further into the H420 in 2010, allowing for higher transmission voltages and the possibility to use 150 mm thyristors, and the latest evolution is the H450 introduced in 2017. This improvement of the LCC valve allows GE Vernova to be more competitive on the HVDC LCC market, by deploying the H450’s reduced physical size valve, without affecting electrical performance.

H400 valve module

H-series provides the core power converter technology in the Jeju Bipole 1 HVDC scheme

The key purpose of the Jeju Bipole 1 refurbishment project is to provide stable and economical power supply by a main equipment replacement and performance upgrade in order to meet an increase in continuous power demand. The existing equipment was originally installed by GE Vernova in 1994 and therefore around 25 years old. The original valves were based upon the 3^rd generation H300 thyristor valve.

“This valve is the core power converter technology for the traditional, and mature, LCC HVDC market. The present H400/H420 valve technology has been in use for about 15 years and was Grid Solutions’ first suspended valve design. The technology has been used for a variety of HVDC projects, including back–to–back and point–to–point projects, the latter including submarine cable and overhead lines (OHL) projects.  The valve has operated at DC voltages up to ± 800 kV on the Champa-Kurukshetra project in India and is able to accommodate 100 mm, 125 mm and 150 mm thyristor devices”, says Donoghue. 

Zoom on the H450 series valve

In common with all valves from the H300 series onwards, GE Vernova’s latest H450 valves use direct liquid cooling which enables a single-circuit system with either pure deionized water or a water/glycol mix, depending on ambient temperature conditions at site. The valves are air-insulated and suspended within a controlled environment. By suspension mounting the valves, the mechanical stresses are reduced, which is of particular importance for applications in seismic areas. However, in some cases, such as pre-existing structures with inadequate suspension facilities, the valve may be floor mounted by using ceramic or composite support insulators. The valves employ high power thyristors, together with associated gating, damping and grading circuits, arranged in 6- or 12-pulse converter groups. According to the application type, thyristors with different voltage ratings and diameters can be easily accommodated.

New H450 series, the need for a new valve module with same performance

In recent years, GE Vernova further evolved the H400 series valve with a "re-packaging" design of the existing H400 module and H400 valve arrangement. “The main scope of this development was the re-design of the module without affecting the electrical performance of the existing H400 design”, states Donoghue.  He adds, “Hence the same thyristor options, the same di/dt reactor and the same damping resistors have been reused on the new H450 module”.

The H450 development project followed the same New Product Introduction process as usual, with different technical gates from the conceptual designs to the industrialized product for the first H450 contract project in South Korea with KEPCO BP1 refurbishment scheme.

H450 valve hall used for Jeju HVDC Bipole 1 renovation project

But so much lighter and smaller! The new thyristor clamped assembly is key

The key part of the H450 development centered around what is called the Thyristor Clamped Assembly (TCA), an assembly that houses the thyristors and water cooled heatsinks. In the existing H400 series valves there were two separate but identical TCAs; however, as part of the H450 development these were combined into a single clamped assembly containing twice as many thyristor levels. The key components that make this possible are the filament wound glass reinforced plastic (GRP) banded straps used to provide the large clamping forces required by the modern-day power thyristors used in HVDC. Depending upon the size of the thyristors (diameter) the maximum clamping force can range from 90 kN for the 100 mm diameter devices up to 200 kN for the largest 150 mm diameter devices. A notable feature of the band design that was developed for the H450 was that only one design was needed, irrespective of the size of thyristor used, which was not the case for the original H400 series valves. Another key change within the TCA was the reduction of overall thickness of the thyristor heatsinks, enabling space saving compared to the original design. To ensure electrical continuity through the valve/TCA when we do not require a full complement of thyristors fitted into some of the modules, dummy thyristors are used. In a matter of fact, the total number of thyristors required for the project valve is not a multiple of 12 (the maximum that can be fitted in a TCA). That’s where an actual thyristor is replaced with a copper block, also called  dummy thyristor.

Thyristor clamped assembly (TCA) with thyristors (THY), dummy thyristors (Dummy THY) and heatsink (HSK)

The development of the single thyristor clamped assembly was the enabler to make significant reductions in the overall dimensions of the valve module; a key building block of an HVDC valve. A reduction in dimensions of some 38% and a reduction of weight of 20% were achieved, giving a significant flexibility in the valve arrangements and size of valve building. This size reduction was also key in the layout of the valves for the KEPCO valve replacement project.
 
On the valve structure stand-point, two significant improvements have been achieved.

1. The reduction of the electrical clearance around the valve thanks to the new shape of the corona shields (see sidebar article).
2. The addition of a second valve arrangement known as “in-line” where the modules are positioned end-to-end (see cover picture). By comparison, the traditional H400 series use a “square” arrangement where the modules are side-by-side.

Haenam HVDC LCC converter station In Korea: Valve hall

The new arrangement provides an opportunity for GE Vernova to improve the width of the valve hall using the in-line valve arrangement when other equipment, such as the converter transformer and busbars, dictate the length of the valve hall. By adding the choice of using an “in-line” arrangement or the existing “square” arrangement for either suspended or floor mounted options with two, four or eight valves per Multiple-Valve Unit, GE Vernova’s HVDC LCC product provides flexibility for the transmission operators.

Intensive type testing process according to IEC 60700-1

The design of a thyristor valve is a complex, multi-disciplinary process involving a range of engineering disciplines including power engineering, power electronics, analog electronics, semiconductor physics, heat transfer, fluid mechanics and mechanical and structural engineering. As there are no standards to follow for designing the HVDC value, GE Vernova relies on the vast experience and solid design practices gained through over 50 years in the HVDC industry.  Modern thyristor valves are relatively standardized, that is to say that the bulk of the real design work is carried out during the product development phase, such that applying the valves to a particular project is a relatively straightforward matter.  At its simplest, the work involved for a particular project may just involve adapting the number of series-connected thyristors according to the voltage rating requirements imposed by the overall system design. For the introduction of a new product and first project implementation this may not be so straightforward. We therefore sought to minimize manufacturing and testing risk by producing a batch of valve modules ahead of type testing.
 
While there are no specific standards for the design of HVDC valves, this is not the case for the testing of HVDC valves. IEC 60700-1: ‘Thyristor valves for high-voltage direct current (HVDC) power transmission – Part 1: Electrical testing’ defines the test program for the valve and covers two broad categories: dielectric tests and operational tests. The type tests form an important part of the design verification process as well as customer project requirements. In addition, the standard covers both production routine testing and sample testing.
 
When a new thyristor valve design has been produced or a previously tested valve design is modified, a program of type tests must be performed. Type testing of thyristor valves is complex, specialized and time-consuming. Some parts of it require extremely specific and expensive test circuits for which only a few serious players in HVDC can justify investment in. All thyristor valves are subjected to comprehensive routine testing in the factory. The purpose of this test program is to prove that the thyristor valves have been correctly assembled. It aims to identify wiring connections that have been incorrectly made, grading components that are out of tolerance, gate electronics that are malfunctioning, blockages in the cooling circuit, joints between the thyristor and heatsinks, etc.
 
For the KEPCO valve replacement project the valves needed to be floor mounted and sited within the converter building, essentially as in the original installation. The reduction in size, weight and increased flexibility of the H450 design made this possible. The figure below shows the valve arrangement. Each of the three structures are known as a quadri-valve (i.e. a structure comprises four valves) and forms the overall 12-pulse converter bridge and represents one pole end of the scheme.

H450 series valve arrangement

Highlights

• GE Vernova’s new H450 design is 38% smaller, and 20% lighter than the H400 product, despite using the same main components (thyristors, di/dt reactor, damping resistors.)
• The number of parts per module has been reduced by 25%. This allows the manufacturing line to be more efficient, quicker and more controlled.
• The maintainability at site is simplified, with easier access to the main components to replace during a planned maintenance outage.

Zoom on the corona shields

Design enhancement of the corona shields
 
Since the late 1970s, all commercial HVDC valves have been air-insulated; that is to say, the insulation between the valves and earth is achieved by using air instead of a higher-performance dielectric medium such as oil or SF₆. This is mainly because of the large physical size of the valves and the need to access the valve components at regular intervals to replace failed components.
 
As HVDC transmission voltages have increased sharply in the last decade (from 500 kV to 800 kV or even higher), the size of air clearances needed around the valves has also needed to increase, and since air clearances increase non-linearly with voltage, the air clearances around the valve are now having a dramatic effect on the size of the valve hall. The valve hall is a very large building with stringent requirements on air quality and there is therefore a considerable economic incentive to reduce its size.
 
An external profile as smooth as possible
 
For high voltages and large air clearances, the design of the corona shields at the top, bottom and sides of the valve is of paramount importance.  The aim of these corona shields is to make the external profile of the valve as “smooth” as possible, avoiding regions of high curvature which will lead to localized areas of high electric field and an increased risk of flashover.

The design of the predecessor H420 valve module was carried over from the earlier H400 valve and only the external corona shields were changed, leading to relatively limited shielding, and the need for long clearance distances.

Colin C. Davidson, Consulting Engineer at GE Vernova's Grid Solutions business, explains, “the H450 valve is a mechanical “re-packaging” of the H420 valve, using the same electrical components but in a better and more compact mechanical layout, considering the external corona shielding from the outset. The performance of the H450 valve has been verified by undertaking a series of “50% flashover voltage” tests (U₅₀ tests) which involve repeatedly applying switching impulses to the valve structure at gradually increasing voltages and for a range of different clearance distances”.  The H450 valve has been demonstrated to achieve dramatically smaller electrical clearance requirements than its predecessor, more than a 50% reduction for the so-called “inline” configuration at the highest voltages (pictured).

U₅₀ Test campaign

Source: Getty/Think Stock

The energy transition now underway will see a growing share of electricity coming from distributed energy resources (DERs), largely connected to the distribution grid. Under the lead of ERDF, France’s distribution network operator, SyDEV, Vendée’s distribution network owner, and together with six other partners, the Smart Grid Vendée project shows how different players in the energy chain can work together to support the energy transition with cost-effective solutions.

The Vendée area is located on France’s Atlantic coast. It covers a population of over 600,000 people across the whole 6,700 square kilometer département (one of the country’s administrative subdivisions). We asked Said Kayal, GE Vernova's Smart Grid Innovation Director, to outline the project’s ambitions and why they chose the Vendée. “Distributed renewable generation will be a feature of tomorrow’s electricity supply, and it is important to study the implications all along the supply chain. Already 9.5% of the electricity generated in the Vendée comes from wind and solar photovoltaic (PV) – more than twice the French national average – and is totally fed into the distribution grid. So the Vendée presents an ideal test bed to study the impact of significant input from renewables on distribution network operations.”

Look-ahead grid management opens smart perspectives

Generation from multiple, renewable sources that may only operate intermittently, as well as new electrical uses such as electric vehicles, are leading to growing constraints on the distribution grid. Look-ahead power system analysis, based on accurate generation and load forecasts, becomes critical in order to anticipate, detect and resolve these constraints on a timely basis on the distribution network.

“In the past, the distribution network operators mainly used internal levers to alleviate local network constraints. This includes voltage regulation in the substations, reactive power management, or optimised network topology switching. In Smart Grid Vendée, the objective is to go further and explore new external levers based on the use of the DER flexibilities, which are available in the electrical loads and storage, as well as generation.”

Flexibility, a new lever

Flexible use or network upgrade become choices to be made on a case-by-case basis, in the context of growing penetration of DERs on the distribution network. New strategies based on DER flexibility in long-term network planning, day-ahead or real-time operations may unveil sustainable and viable technical/economical options for the electrical system.

In order to develop the use of DER flexibility on the distribution network, a new market mechanism is being tested in Smart Grid Vendée. The distribution network operator is evolving into a new role, that of “market facilitator”. Here, GE Vernova's DERHub for DSO will help ERDF take advantage of and manage DER flexibility transactions with the flexibility aggregators.

Weaving local threads

The decentralization of energy production means that local authorities will have increased responsibilities regarding the energy chain. Aware of this step change, and strongly committed to energy efficiency measures, the SyDEV is deploying new technical aggregation and automation platforms to better monitor and dispatch the DER flexibilities they have on their own public assets (buildings, street lighting, distributed generation). GE Vernova's DERHub for aggregators will allow territories and cities to intelligently aggregate and weave the individual flexibilities – smart homes, smart buildings, energy storage, solar panels – into an aggregated flexibilities potential. Such potential is then translated by a commercial aggregator into market mechanisms, including the new one managed by ERDF.

Kayal is pleased at the way Smart Grid Vendée has integrated all the players into a complete smart grid on such a wide scale. But he and his partners in the project are impatient too. “This is only the pre-industrial phase. We are looking forward to scaling up to regional level.”

New ICT tools for DSO and territories to take advantage of and manage DER flexibilities

Three questions to Regis Le-Drezen, ERDF Vendée Director

Does the energy transition need new technologies?
Traditional, centralized systems designed to efficiently distribute energy have difficulty coping with new electricity uses. For example, the electricity is now flowing both ways and customers expect the same flexibility for charging their cars as for charging their phones! To operate more efficiently we need new technical and organisational solutions. That is why we are investing in smart grids.

Do the key technologies exist?
Yes, to some extent. For example, following an incident on our medium-voltage network, automatic control systems can reconnect 70% of the customers who were cut off in less than two minutes without any human intervention thanks to advanced management software and self-healing systems. The challenge is to extend this type of solution to low voltage distributed generation from wind and solar energy and to electric vehicle load management.

 How do new technologies and processes work together in Smart Grid Vendée?
Take demand response for example: the DSO wants to predict short-term needs for a given infrastructure and incorporate a degree of flexibility into long-term planning. The local constraint management mechanism we are developing with GE Vernova will enable us to make good use of local flexibility to avoid constraints as well as to reduce the grid operating costs.

Dialogue with Yann Dandeville, SyDEV – Smart Grid Vendée Development and Innovation Director

What is SyDEV?
It stands for Syndicat Départemental d’Energie et d’Equipement de la Vendée – the Vendée Departmental Authority for Energy and Infrastructure. SyDEV represents the 282 municipalities that make up the department. It owns the low and medium voltage electric distribution network (22,000 km) as well as the gas network (2,400 km). Like its sister organisations in other parts of France, it is in charge of public services regarding energy supply. But SyDEV stands out for its expertise in public lighting and assistance in energy audits for municipalities. SyDEV is also known for its commitment to renewable energy production, electronic communications and charging infrastructure for electric vehicles.

Why did SyDEV join Smart Grid Vendée?
We react to our users’ needs, but we also want to anticipate changes that will affect them. That is why we’re focusing on clean energy and other environmental aspects. We’re a renewable energy producer, with six wind farms totalling 51 MW, and 36 solar-powered generators of 2.9 MW in all, located in buildings. We see the Smart Grid Vendée project as a way of providing our members with cost-effective, environmentally sustainable solutions.

What are you hoping to get from the project?
We want to evaluate the cost savings from new technologies, given the need to reinforce and upgrade our network. We would also like to test the technical and economic feasibility of managing the grid and public lighting on the Vendée scale. And we would like to discover innovative solutions to cut energy costs for public buildings. The expertise of partners like GE Vernova help us do all that.

Today’s unusual weather phenomena tell us that the climate is changing. While mitigation is important, experts agree that adaptation is necessary to adjust to the various effects of the planet’s evolution. That includes adapting power grids.

[Source: GETTY/ThinkStock]

Severe, atypical weather events are on the increase. Flooding, hurricanes, heat waves and extreme cold spells are becoming more frequent. According to the World Bank, global mean warming is 0.8°C above pre-industrial levels, oceans are acidifying, sea levels are rising at 3.2 cm per decade and an exceptional number of extreme heat waves occurred in the last 10 years. The US National Oceanic and Atmospheric Administration adds: “We have entered uncharted climate territory. We must accelerate the pace of adaptation to achieve a more sustainable planet.”

Dr. Lawrence Jones, who leads GE Vernova's Grid Solutions' Utility Innovations & Infrastructure Resilience activities in North America, explains the potential impacts of a changing global climate on the power grid infrastructure: “The grid as we know it today was not designed for big temperature swings. So the electric network is affected by increasingly extreme temperatures that may degrade the equipment’s thermal and physical properties and reduce its lifespan. As the Earth heats up, the resistivity of the soil can change and some underground devices could malfunction, leading to problems in the grid’s protection systems. Equally, an excess of moisture in some regions could have a serious impact on the dielectric properties of underground equipment."

“The increase in severe weather events will affect major portions of the electricity networks in different ways. For example, we are already beginning to see an impact on load patterns. Peak loads might change or multiple peaks could occur within a day, resulting in erratic utilisation of energy resources. We saw the occurrences of multiple peaks in parts of the US during the polar vortex earlier this year.”

The solution? A smarter and resilient grid

A smarter, resilient grid can play a major role in adapting to climate change. It can do so in two fundamental ways – the physical approach and the cyber approach. The physical side involves the introduction of new technologies and materials into the grid infrastructure. “For example, the application of nanotechnology can create new materials through the manipulation of their atomic structure with better physical properties, making them more robust and more efficient,” notes Dr. Jones, who also serves on Grid Solutions' global business development team for smart grid and smart cities consulting. “And equipment made with graphene, a revolutionary and extremely hard material, can make it less vulnerable to extreme weather conditions. In this way, material science can make a significant contribution to grid resilience. So, too, can superconductors, which can not only push more electrons down the wires, but can be used to design better power electronics for HVDC. The grid’s adaptation to climate change may also be enhanced by wireless sensor networks, enabling the real-time collection of data in the grid as well as its surroundings.”

It’s the information that counts

The second key element in a smarter grid is the leveraging of the huge volumes of data collected – the cyber approach. “We’re talking here about exabytes* of data,” says Dr. Jones. “The largest producers and consumers of power grid data are the hundreds of millions of sensors and controls embedded in smart devices installed in buildings, substations, generators, transformers, and other equipment in the transmission and distribution networks.”
 
“Then there are the expanding data from the increasing amount of variable renewable generation resources, demand response programmes, and distributed energy resources such as electric cars and energy storage. Grid operators today and more so in the future will have more access to external data sources such as weather agencies, etc. Extracting actionable information from this avalanche of data will help to identify and predict physical phenomena.”

*one exabyte = 1 million terabytes, or 10¹⁸ bytes.

From reactive to predictive operation

This interdependence of the physical and cyber domains is undoubtedly one of the industry’s salient challenges. But this coupling could also present opportunities for different ways to operate the grid when faced with severe weather events. “Instead of the conventional reactive mode of operation, we are at the beginning of the new age of applying more predictive techniques. Operators will have to keep the lights on while coping with the uncertainty due to climate change.”
 
Dr. Jones gives examples: “In the case of the tornado that struck Oklahoma in May 2013, it is reported to have rapidly intensified to an EF-5 level tornado in less than half an hour. Grid operators need to be able to simulate such climate-related anomalies and run ‘what-if’ scenarios to better anticipate how the grid reacts and what actions to take. Similarly, in wind farms across Denmark, the wind speed can go from 0 to maximum in 10 minutes. With integrated forecasting technology and ultra-fast computation, the control centre can calculate what will happen in the next five minutes. This capability enables a predictive mode of grid operation – and is indeed a requisite for what has become known as a self-healing grid – that anticipates events and responds to them to mitigate their negative impact on the network. This can help to make the system more resilient.”

Grid operators need to be able to simulate such climate-related anomalies.

In distribution systems, Volt VAr Optimization (VVO) improves power flow using real-time information and online system modeling. “Probably one of the most valuable applications of predictive tools is in asset management. We are now entering what I call the age of ‘hybridity’. For at least the next 30 years, power grids, especially in OECD countries, will consist of both old and new devices and equipment. While utilities will have to replace old assets, there are many assets with more than a decade left in their operational lifespan. Smart condition monitoring devices can be integrated into the grid and asset control rooms for analysis and improved grid operation. Interoperability of the old and new devices is a priority.” Dr. Jones is also one of Grid Solutions' experts on the subject of interoperability across the grid and between different infrastructure systems. He is currently serving as a member of the Smart Grid Advisory Committee at the US National Institute of Standards and Technology (NIST) of the US Department of Commerce.

An on-going investment in IT solutions

All this will require a major investment in Information and Communications Technology (ICT) solutions. “A particular emphasis will be on advanced grid and asset analytics as well as decision-support systems to harness all the data. The new emerging operational paradigm will require the creation of information flows that allow operators to take appropriate action in real-time – or perhaps rather ahead of time. Some applications already exist, but the effort will continue for five to 10 years to come.” To corroborate Dr. Jones’ prediction, Navigant Research, a market research and consulting company with special expertise in the energy sector, forecasts that worldwide spending by utilities for smart grid IT systems will more than double in the next 10 years.

As the climate changes, the electricity grid will adapt and become more resilient.
 
 
[Source: GETTY/ThinkStock/Stocktrek Images]

In a grid topology using HVDC circuit breakers able to provide fast clearance of a DC fault, two main contrasting, yet complementary, solutions appear possible. One would be to apply the same protection philosophy and principles used in AC systems. The second could be the “Open Grid” concept.

Adapting the AC grid protection philosophy

The principle, philosophy, and scheme for protection of HVDC systems can be inherited from AC systems. The greatest challenge is the need for a very short tripping time without losing selectivity, security and sensitivity.

Although HVDC grid protection is still in a development phase (to date no DC circuit breaker is in commercial use in the field), the protection principles of an AC system are still one option for application to an HVDC network. As Sankara Subramanian, head of the Innovation & Technology department at GE Vernova, explains: “A DC breaker that can provide fast clearance of the DC fault will play the key role for isolating the faulty line and devices in the HVDC system. In this context,” he adds, “the philosophy, principle and scheme for protection of HVDC grids may still follow those for AC systems.” However, as with AC system protection, the four requirements of a secure and reliable HVDC system (selectivity, speed, sensitivity and security), “are somewhat in contradiction with each other, and need to be balanced technologically and economically”.

Unit versus non-unit protection

Protection can be based on the information and measured voltage and/or current at one end (where the protection is installed) or at both ends. In the first case (one end), it is called a “non-unit protection”; in the second case (both ends), it is a “unit protection”.

In an AC system, the over-current protection and distance protection belong to the non-unit protection category, while the current differential/phase as well as directional comparison belongs to the unit protection category. “The advantage of the non-unit protection is that the communication links and devices are not required,” explains Subramanian. “This not only minimises costs but also means that the speed of the protection is not limited by the communication time delays. Meanwhile the reliability and security are not restrained by communication errors or failure.” On the other hand, non-unit protection has the disadvantage that it cannot provide absolute selectivity.  

Another important point is that transmission lines in an HVDC grid are normally longer than those in an AC system: the communication time delay is therefore longer, due to the distance involved. If the line length is longer than the limitation of direct communication, then inter-connection relaying to forward the information is required, which can cause an extra time delay (up to 100 ms for lines over 500 km). “Therefore, in future HVDC grids, the non-unit type is likely to play the dominant role of protection,” says Subramanian.

Protection algorithm: transient or steady-based?

Protection algorithms are generally formulated by the characteristic difference between internal and external faults. Algorithms based on the characteristic difference of transient voltage or current signals are called “transient-based protection”. Those based on the character of steady-state voltage and current signals are called “steady-state-based protection”.

Whereas in AC power grids most of the protection systems installed are steady-state based, in HVDC grids the steady-state signal is DC, so the Fourier-based protection does not work; the transient period is also much longer then in an AC system. Therefore, the preferred way of formulating an algorithm for HVDC grid protection of the conventional approach is by employing “transient-based protection”.

Sampling rate and time window

A very important element for transient-based protection is the time window, which will directly impact the speed of the protection algorithm. It determines the sampling rate such that, within the time window, there should be sufficient samples to detect the faults and determine whether they are internal or external faults. As per IEC 61869-9, the sampling rate for DC grid protection is 96 kHz (96 samples/ms). If we assume that the required time of the total fault clearance should be less than 5 ms, the window length should be less than 0.5 ms. Using the above sampling rate, the decision for an internal or external fault could be made by an algorithm in less than 0.5 ms, which could therefore meet the requirement of HVDC fault clearance.

New algorithms for HVDC grid protection

Based on the above analysis, the only difference between HVDC and AC grid protection schemes would be that non-unit protection would be the primary protection function. However, as for AC, there could be several protection schemes for HVDC grids: the primary protection may be a transient-based direction-over-current relay or a transient-based distance relay plus transient-based high-speed remote trip detection without relying on communications between the ends. The backup protection could be a transient current differential relay or a transient-based directional comparison unit protection or a transient-based distance unit protection plus an aided scheme (a scheme relying on communication between the ends). “All these protection philosophies are presently in the development stage, and there are already several patent applications in this field,” Subramanian concludes.

Open Grid: an alternative approach to HVDC grid protection

A major hurdle to overcome in the creation of a true HVDC grid, even when the HVDC circuit breaker technology is available, is the protection of the grid. “If the DC grid protection philosophy were to be based on that currently employed in AC grids, then the protection system would need to have the ability to detect the fault, to discriminate that the event is an HVDC grid fault and not an external disturbance, to locate where the fault is on the HVDC grid, and then to send a trip signal to the appropriate HVDC breakers,” explains Carl Barker, Chief Engineer at GE Vernova. “In the event that the fault is real, then this must take place while the DC current is rising towards a steady-state maximum value but before it has reached a level that is beyond the capability of the HVDC breakers to interrupt.

Fault interruption in a DC grid

Applying the same protection strategy as that used in AC systems – 20 ms detection and discrimination followed by tripping only the DC circuit breakers associated with the fault – results in the line voltages and currents displayed in the figure below (it is assumed that the DC circuit breaker operating time is 5 ms). “These results show that allowing the fault current to rise over a period of 20 ms and then only using the HVDC circuit breakers associated with the faulted line to clear, imposes a very high current interruption duty on those circuit breakers,” says Barker. “On the other hand, reducing the time for detection and discrimination before the HVDC circuit breakers are tripped reduces the time available for fault location.”

AC Methodology applied to DC grid protection

Reversing the protection sequence order

An alternative approach, referred to as “Open Grid”, is to reverse the protection sequence order. “This means allowing each HVDC circuit breaker to autonomously trip on detection of a fault without any delays associated with communications or discrimination logic, and then re-closing healthy circuits,” explains Barker. This strategy may offer practical advantages in terms of building a robust DC/AC grid: the HVDC circuit breaker opens at a much lower fault current, and the fault, as it propagates rapidly through the network, is “seen” by several breakers that will all open (except those more remote from the fault; they will not have time to “see” it and will therefore remain closed). “The energy requirements of the HVDC circuit breakers could thus be much lower – initial results indicate a reduction of some 95%.” This approach significantly reduces the duty on individual circuit breakers, facilitates their rapid opening and is complementary to ongoing HVDC circuit breaker development. Fault location would also be facilitated by this method.

The Industrial Internet of Things (IIoT) will generate huge volumes of data in the coming years. But harnessing that data to generate meaningful insights is a challenge. Leveraging the power of a specially designed platform can help industrial companies obtain the information they need to enhance assets and gain competitiveness.

"GE Vernova's Grid Solutions business has developed its Predix operating system to help customers exploit the data emanating from the IIoT,” says Greg Petroff, GE Vernova's Chief Experience Officer, Digital Predix Products & Technology. “Predix is a software platform as a service that runs in the cloud and at the device edge so that customers can tap into it, collect their data and run analytics on them at machine, plant and cloud level. It is designed for industrial and infrastructure companies to handle their very large volumes of data—much of which was not even saved in a consistent way in the past—and run intense analytics computing on them to generate insights into asset life cycles, performance, service improvement, maintenance and upgrading/replacement, investments, CAPEX and other needs.”

The platform offers a standardized vehicle to enable enterprises to quickly take advantage of operational and business data. By tapping into a platform designed around a set of re-usable building blocks, developers can rapidly build and deploy applications, reduce the sources of error, lower costs and be sure that their investment is durable over the long haul. The cloud offers the economics of a centrally managed and shared infrastructure with an adjustable scale to meet expanding needs. It also offers connectivity for all the assets of industrial companies and, in particular, analytics that provide insights and diagnostics to ensure that the assets operate at optimum levels.

Predix overview
https://www.predix.com/overview

“These are major benefits for utilities,” adds Phil Robinson of GE Vernova's Grid Solutions business, Software Solutions. “They can spend much less time on deploying and configuring their applications and more on developing solutions to drive business outcomes, enhancing their productivity. They have access to a full-function environment that is always up and running.” “Furthermore,” notes Petroff, “Predix is made up of a broad palette of building bricks called microservices, so customers can subscribe just to the services they need. And these microservices are provided not only by GE Vernova, but also by its several partners, startups, and even other customers. In other words, a whole ecosystem built by industrial stakeholders who are familiar with the equipment, devices and data that industry uses and who are focused on solving industry’s problems.”

Challenge and opportunity

Perhaps the biggest challenge for Predix is convincing customers of its benefits. Says Petroff, “This is a new model for them for building their software and managing their assets with groundbreaking new capabilities unavailable in legacy software systems. They have to feed their data into the cloud, and many have not realized the value unlocked by doing this yet. And, although GE Vernova has been using Predix internally for years—to great advantage—general availability is still quite recent, so there is not as much evidence of ROI yet than we would like to present to customers. The evidence we do have, however, is compelling.” Then there is their concern for data security and anonymity. Robinson points out that “Predix takes care of the multi-tenant issue. Data is physically segmented based on identity, and authorization and authentication are always needed to access the databases.” Petroff adds, “Predix respects all legal data privacy and security frameworks and operates with two-key encryption. And remember, Predix is not a control system—there is a firewall between the SCADA data and the analytics in Predix, so if there were to be a security breach, the data cannot be tampered with.”

Of course, there are other cloud platforms on the market. However, existing platforms are aimed at consumer or enterprise uses. Predix, on the other hand, is designed specifically for industrial clients with industrial problems to solve. “The assets are the critical element,” Robinson states, “and GE Vernova is a manufacturer of many of those assets.” Petroff continues, “For example, GE Vernova's Grid Solutions business has more than 120 years of experience with rotating machines and with power conversion, transmission, and distribution equipment. We know how material behaves in operation and we know the devices. That considerable industry expertise means that we can deliver better insights for customers.”

In addition, Predix is built on Cloud Foundry, an open-source Platform-as-a-Service from Pivotal, with its support for existing languages and programming tools, its expanding library of services, and its cutting-edge development and operations (DevOps) environment. It allows application developers to quickly build, test, deploy, and scale applications.

Application development made easy

A key advantage of Predix is its ease of getting started. “Customers can actually start playing with Predix in a ‘sandbox’ environment for free,” Robinson points out, “so there’s no big up-front investment required to get going. The technology is open and mainstream, not proprietary, with sample applications and components that anyone can take a look at. The development ecosystem offers numerous tools, videos, blogs, training, tutorials and a collaboration environment that caters to all levels of expertise. With a starter application, for example, a customer can spend 15 minutes on a tutorial and then begin.”

GE Vernova's Grid Solutions runs a number of applications on Predix that are crucial to utilities. The intelligent mapping service, for example, that records the different asset locations in the network and presents them visually for field engineers, providing them with status information on the network, equipment and devices. Robinson also points to the Asset Performance Management System. “This is a service optimization solution gathering real-time monitoring and diagnostics information on assets in the field. It runs analytics and makes near- to long-term predictions so that a reliable life cycle strategic plan can be established. Of course, the output of such analysis may be work, so Predix also has a mobile element so that work orders can be sent to field engineers on their laptops, tablets or phones.”

These are just some of the applications already available on Predix. Others will follow, making Predix an essential tool for forward-looking utilities.

Germany wants to be climate-neutral by 2045, a good 20 years from now. The development of a climate-neutral electricity system in the next decade is crucial to achieving this goal. We therefore expressly welcome the German government’s efforts to increase the share of renewable energies in electricity generation to 80 percent by 2030, which have been further intensified by the Russia/Ukraine conflict.

Halving planning and permitting times

Despite rising approval and expansion figures, we are not yet where we want or need to be to achieve the 2030 renewables target, particularly in the key technology of onshore wind. As promised, the federal and state governments must stay on the ball, make the necessary areas available, and significantly reduce the duration of planning and approval procedures – ideally by half.

Secure grid extension

This also applies to electricity grids. In recent years, a lot of energy and money has been invested in accelerating the expansion of the transmission networks. This has been important, and we must not let up. But we also need to apply the same vigor to making the distribution grids fit for a climate-neutral future. We need to expand and modernize them and enhance their operation so that they can integrate the many decentralized generation and consumption systems that will be added across the country in the coming years.

Ensuring system stability through flexible generation

Alongside renewables and modern grids, flexible and highly efficient gas-fired power plants will be the third pillar of the electricity system of the future. With a clear transition path to hydrogen combustion, they will not only ensure Germany’s and Europe’s energy security in the medium term but will also be partners to renewables in the long term. They supply electricity during dark periods, provide important network services and thus ensure the stability of the overall system.

Ensuring the transformation of the power system through reliable decisions

The energy system has already changed significantly over the past two decades. What we have set ourselves for the next two decades goes far beyond that. Decisive action and reliable decisions are now essential to give all stakeholders the certainty they need to make the investment decisions that are now required in the short term.

From GE Vernova’s point of view, three points are crucial:

• A future electricity market design that also rewards the provision of generation capacity and grid services;
• The rapid development of hydrogen import, and transport infrastructure to decarbonize flexible generation; and
• Certainty about financing and tendering conditions following the Climate and Transformation Fund (KTF) ruling by the Federal Constitutional Court.

The ruling has further delayed the final consultation on the power plant strategy within the German government. In our view, quick decisions are needed to ensure long-term security of supply and to prevent CO2-intensive coal-fired power plants from operating longer than necessary.

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This article is by Stefan Hartge, General Manager, GE Vernova's Electrification business