The grid is being hybridized into an ac-dc network that is more flexible, accessible and reliable.
Today's electrical grid is a complex system so heavily loaded and congested it can be pushed into instability by unrelated events. The infamous 2003 Northeast blackout in North America spread across the grid at warp speed, affecting roughly 10 million people in Ontario, Canada, and 45 million people in eight U.S. states. The industry revisited this phenomenon with the 2006 European blackout. Six European countries were affected, putting an estimated 15 million customers in the dark.
The grid has grown into vast synchronous high-voltage alternating-current (ac) networks that become weak as reserve capacity fluctuates. These high-voltage ac network-based systems require extensive studies, computer modeling and enormous amounts of data exchange between the interconnected systems.
In addition to all of that, the interconnected systems must maintain a high degree of technical compatibility and operational coordination; otherwise, there will be problems — big problems. As the blackouts of 2003 and 2006 proved, a snag anywhere on the grid can be felt everywhere. Relatively small troubles can grow into major power failures with enormous impacts on load centers far removed from the location of the actual problem.
Technological Game Changer
Several postmortems of the 2003 and 2006 blackouts pointed out the cascading failures did not propagate into Québec during the North American blackout or into the U.K. during the European blackout. Both had interconnections with the affected power grids, but the blackouts were stopped at the borders.
Those interconnections were high-voltage direct-current (HVDC) interties performing like firewalls, which prevented the outage from invading their grids. Many in the industry knew HVDC facilities had the ability to block errant fault currents, but it seemed the rest of the industry needed a wake-up call. As a result, there was a new awareness not only of the firewall capability but also of the many other benefits of HVDC (for example, load flow control, voltage control and reactive power support).
In other words, HVDC offers improved stability, which is why the idea of a hybridization of high-voltage ac networks with HVDC applications is gaining traction in so much of the world. By hybridizing the grid, industry experts are talking about overlaying the ac system with a dc grid. They envision this dc grid as a combination of regional and interregional HVDC grids.
It is interesting to note this supposedly new idea of a dc grid is not all that new. Visionaries imagined a dc grid for offshore oil and gas fields more than 30 years ago. When wind farms began moving offshore, an offshore dc grid gained more interest, but it has taken time for technology to catch up.
Trends Start Somewhere
The mercury arc valve technology gave utilities the benefits of long-haul HVDC transmission and submarine links. Utilities took advantage of this technology and built the Cross-Channel project (U.K. linked to France) and the New Zealand Inter-Island project. The technology worked, but when it came to maintenance, it was complex, expensive and labor-intensive.
Then came the thyristor valve; it simplified HVDC tremendously, and utilities took advantage of this technology with a flood of HVDC systems globally. Utilities began to link their systems, crossing borders, connecting islands to the mainland and sea crossings became common — Denmark-Norway (Cross-Skagerak project), Italy-Sardinia (SAPEI project), Germany-Denmark (Kontek project) and Germany-Sweden (Baltic Cable project), to name just a few. These were but a precursor to what was ahead.
Power Transistors Complement Thyristors
As the industry was preparing to enter the 21st century, HVDC technology took a quantum leap forward when ABB introduced the voltage source converter (VSC) with pulse-width modulation. It was revolutionary, or perhaps evolutionary would be a better descriptor since technology, like all evolutionary process, builds on itself.
This was a completely new converter design unlike anything before it. It was based on valves using power transistors rather than thyristors. VSCs use fast semiconductors known as insulated-gate bipolar transistors (IGBTs) and cross-linked polyethylene (XLPE) dc cable.
This new type of valve architecture let designers break from net-commutated principles by allowing operation in all four quadrants of the P-Q plane. This permitted reactive power to be controlled independently of active power, which is an enormous advantage over line-commutated converter schemes when it comes to renewables.
VSC technology also is able to deliver power to a network without other generation sources — the so-called black-start capability. The VSC also eliminates problems from infeed to weaker networks. And if that is not enough, VSCs change power direction by switching the direction of the current, not changing voltage polarity. These abilities make VSC multiterminals easier to connect to different points in the same ac network or different ac networks, which is a stepping stone to the hybrid dc grid.
VSCs are changing offshore electrical power traditions in a big way. The traditional method to power offshore oil and gas fields was to either bring high-voltage ac power from the mainland or generate electricity by burning gas or diesel on the platform. Diesel/gas-generated electricity impacts the carbon footprint and produces a lot of greenhouse gasses. high-voltage ac brought from the mainland has distance limitations requiring reactive compensation about every 50 km (31 miles).
Then in 2005, VSC technology changed everything with the Troll A project. For the first time, a VSC system provided power from the Norwegian grid to an offshore compressor station. It also included another new technology, ABB's very high-voltage motor (VHV), which was developed with compressor platforms in mind.
What makes the VHV unique is the fact it is designed to be driven directly by the VSC without a transformer. Not having a transformer is a substantial weight savings, which is critical on an offshore platform. Of equal importance was the elimination of emissions from the combustion turbines, which were estimated at roughly 230,000 tons of carbon dioxide and 230 tons of nitrogen oxide per year.
The success of Troll A paved the way for the next step, supplying an entire oil field's ac requirements from a VSC installation. BP (formerly British Petroleum) replaced the Valhall oil field's production and compression platform and its living platform with a new VSC platform, which eliminated several gas turbines and reduced emissions significantly (about 300,000 tons of carbon dioxide and 250 tons of nitrogen oxide per year).
With Europe's commitment to the environment, VSC schemes also are making inroads with offshore wind farms. In 2009, the BARD Offshore 1 wind farm became the first wind farm to be connected to shore with a VSC scheme.
Offshore DC Grid Hub Concept
Today, dozens of VSC offshore wind projects are in service, under construction or in the planning stages. Offshore wind generation has grown at a fantastic pace in Europe. The European Wind Energy Association (EWEA) released its 2011 offshore wind statistics recently.
The EWEA reported a total of 1,371 offshore wind turbines have been connected to the grid. This figure represents 3,813 MW from 54 wind farms connected to 10 European countries. EWEA estimates roughly 40 GW of wind will be installed offshore by 2020 and expects it to increase another 110 GW by 2030, for a total of 150 GW.
That is a lot of wind generation to connect with individual connections, which is not an efficient method. This has triggered a slew of proposals to connect wind farms and oil fields to an offshore dc grid that is international by nature. One plan for the European Union is called the Offshore Grid project.
This offshore grid would connect the North and Baltic Sea wind farms to the continent through hub connections at sea. These hub connections would then form a dc grid, allowing the aggregation and dispatch of all the offshore wind farms to be sent to any country connected to the dc grid.
This would meet two huge needs of the industry. The wind farms would be located in totally different regions, which could solve the intermittent nature of wind; in an area this size, the wind is blowing somewhere all the time. The other issue just starting to gain attention is the submarine cable congestion problem. Each offshore facility requires submarine cable connections to shore using today's designs. The dc grid hub configuration would avoid a large number of parallel submarine cables by consolidating the wind farm feeds.
Recently, the 10 nations bordering the North Sea showed how serious they are about offshore grids and congestion by signing an agreement called the North Sea Countries Offshore Grid Initiative. This initiative has been heralded as the first step in the European super grid. It will coordinate the deployment of new HVDC cables with the goal of linking renewable energy across the North Sea.
Part of the initiative is the BritNed cable between the U.K. and the Netherlands, which is the first HVDC link between the U.K. and another country in 25 years. The BritNed auctions the cable's transmission capacity on the open market. Interestingly, the cable's 1,000-MW capacity has been fully purchased since going into service. The next HVDC link for this strategic plan is the 2012 East-West Interconnector (Ireland-Wales) project.
A DC Grid in the Future
Combine this offshore dc grid hub concept with the onshore proposals being considered, and an overall hybrid ac-dc grid emerges. Onshore, Deutsche Energie-Agentur (DENA) has some interesting plans that propose to take advantage of existing ac and dc facilities, as well as new facilities. DENA is proposing an extension of its existing integrated grid as a transmission network by upgrading overhead transmission lines, constructing new transmission lines and overlaying a meshed dc grid (overhead and underground HVDC transmission).
A dc grid would consist of dc hubs connected to synchronized and unsynchronized ac systems, onshore and offshore, connected as regional dc grids and interregional dc grids. Its principle value would be as a facilitator for power exchange, power trading between power systems and reinforcing the ac grid.
The regional dc grid is defined as a system that comprises a single protection zone. Such a system can be built with today's HVDC technology. It really does not need a dc circuit breaker to isolate the faulty part of the grid, but regulatory issues do need to be addressed and solved.
The interregional dc grid is a different matter. It is a system that needs several protection zones. It needs dc circuit breakers, fast protection, power flow controllers, automatic network restoration and a dc-dc converter for connecting different regional systems. Of course, there are more regulatory issues complicated by the number and size of the interregional dc grid.
These are interesting challenges, but they are not showstoppers. Multiterminals have given utilities some experience with several of these issues. Power balance is maintained when the power input is equal to the power output (including losses). The dc voltage is the indicator of power balance. When there is a surplus of power, the dc voltage goes up; when there is a power deficit, the dc voltage goes down — simple.
Control systems are available that have a proven track record maintaining energy balance with voltage and power control. Several professional groups are working on ac and dc grid-simulation models as well as advanced power flow programs to develop new operating strategies for large HVDC systems, such as an overlaying backbone system and its effects on the existing ac networks.
Perhaps the most significant barrier to the interregional dc grid has been the lack of a suitable HVDC circuit breaker. This is due to the fact a dc grid has very low impedance, and a short-circuit fault is much harder to deal with than that found in an ac grid. An HVDC circuit breaker must be able to clear a fault in a few milliseconds to avoid a collapse of the common dc voltage.
The existing mechanical dc breaker designs are too slow. Semiconductor designs are fast, but they generate large transfer losses. To overcome these shortcomings, ABB is developing an HVDC breaker concept that combines mechanical and semiconductor designs into a hybrid breaker.
No Shortage of Challenges
Today, the situation is rather simple. The need for connectivity between countries and power market regions is the major motivator for developing hybrid grids (ac with dc overlay). Renewable energy and environmental concerns for reducing greenhouse gasses and the carbon footprint are key policy drivers. HVDC technology is proving to be a most important tool in the industry's toolbox for addressing these forces. In many ways, this situation is very similar to the early days when people thought they had to decide between ac or dc. But, now dc is not competing with ac; it is improving the network.
ABB | www.abb.com
BP | www.bp.com
Deutsche Energie-Agentur GmbH | www.dena.de/en
European Wind Energy Association | www.ewea.org