by Jennifer Van Burkleo, Associate editor
An aging infrastructure and increasing demand for energy makes technology more important than ever in meeting and sustaining the power needs of the world. In its 2012 World Energy Outlook, the International Energy Agency said global energy dependency will grow by more than 30 percent between now and 2035. As the shift to more renewable sources catches on, questions are raised about how to make grids more flexible and better able to accommodate intermittent renewable generation. Alstom Grid believes high voltage, direct current (HVDC) technologies are part of the answer.
|Germany’s first offshore wind farm, Alpha Ventus 062.|
Alstom Grid recently opened its worldwide center of excellence for HVDC, as well as its large-scale transformer factory in Stafford, England, to more than a dozen journalists from around the world to talk about the future of HVDC. The company cited the benefits of HVDC and how the technology is helping connect mass amounts of renewable energy to the grid and transfer it long distances to load centers.
There are two types of HVDC technologies: Line commutated converters (LCC), which encourage energy trading and HVDC transmission; and, voltage source converters (VSC), which enables renewable energy by connecting variable energy resources and DC grids. LCC is ideal for major bulk power projects, while VSC is better suited for more compact projects, according to Alstom Grid.
“If a line is spanning a distance of more than 700 km (435 miles), it’s typically more cost efficient to go with HVDC rather than the AC solution,” said Claes Scheibe, Alstom Grid’s vice president of Power Electronics Applications.
Scheibe described other benefits of HVDC, such as increased energy efficiency to help operators meet growing electricity demand while reducing transmission losses and land use. It also is the ideal technology for connecting offshore energy sources to onshore grids, he said.
Another advantage of HVDC is that it allows operators to quickly change the direction of power flow, which makes it suitable for connecting wind, solar and other renewable sources beyond national borders, such as in Europe, or between North American Electric Reliability Regions in the U.S., Scheibe said.
HVDC also can connect AC grids to renewable sources while improving power quality, stability and reliability on those networks by reducing disturbances. The networks can be managed by control centers while operators keep the grid balanced by injecting the necessary power when there is a dip or peak in demand.
Like many countries around the world, the electricity grid in the U.S. is mostly comprised of HVAC transmission. Although HVAC has been the most commonly used form of energy transmission for over a century, the changing energy landscape has driven the need for the implementation of HVDC technology.
Utilities and companies like Alstom are looking to integrate more new HVDC networks into existing HVAC networks to create meshed grids, which would make the transmission system more efficient and flexible.
In the future, DC grids will mesh with the AC network to become more stable and more controllable. As grids evolve, direct current at high and medium voltage in transmission and distribution networks will be more commonplace, giving rise to a greater concentration of interconnected networks.
Alstom is involved in two projects in the U.S. where AC and DC technologies will be integrated. The first is the Tres Amigas Super Station, which would provide a first-ever connection between the three major U.S. transmission networks, the Eastern Interconnection, Western Interconnection (Western Electricity Coordinating Council) and Texas (Electric Reliability Council of Texas). Tres Amigas would make it possible for clean renewable electricity generated on the West Coast to power homes on the Eastern Seaboard. The second project is the New Jersey Energy Link, which would serve as a backbone for connecting offshore wind farms to the state’s power grids.
Alstom is also working on projects in South America, Asia, Europe and the Middle East. Its largest project, being constructed in Brazil, will be the world’s longest HVDC transmission line. The 2,375 km line will link 3,150 MW of power from the new hydro power plants in the Madeira River to the South-Eastern region of Brazil.
EYE ON the world
Renewable energy demand to drive European T&D markets
A rising demand for electricity coupled with environmental concerns across Europe is leading countries to look for more diverse energy sources, which will boost investment in their Transmission and Distribution (T&D) infrastructure, according to research and consulting firm GlobalData.
The report states that key European countries, including Germany, Great Britian, Norway, Italy, Ireland and France, will spend substantial sums on grid expansion and upgrade programs in order increase security of electricity supply, deploy smart grid technology and accommodate new sources of power generation – particularly renewables.
“Renewable energy accounted for around 70 percent of the total power generation capacity additions made in the EU in 2012, and further additions are being introduced as a result of EU targets aimed at reducing greenhouse gas emissions and increasing the share of renewables total energy consumption by 2020,” Shivanshu Agnihotri, senior analyst at GlobalData, said.
According to the report, European T&D grids are characterized by issues related to network congestion and the integration of distributed energy resources.
“The aging nature of the T&D networks in Europe has raised concerns regarding the stability of the electricity supply and has prompted a number of nations to frame policies for the incorporation of efficient technologies into the grid,” Agnihotri said.
The need to increase cross-border grid interconnections will be another boost to the European T&D market, as it could lead to competition in the power market and the potential reduction of power prices. By providing a broader generation base, interconnections can improve energy supply security and reduce the need for the additional construction of power generation capacity.
Opinion: Are we trying to be too smart about smart metering in the UK?
by Craig Edge, Wheatley Associates
With yet another delay to the U.K. Government’s proposed Smart Meter Implementation Plan, the time has probably come to take stock of the situation, reflect on how the roll-out strategy is being implemented, and ask the question: Are we trying to be too smart about smart metering in the U.K.?
On May 10, the U.K.’s Department of Energy & Climate Change (DECC) announced that it was pushing back the start of the full-scale U.K. smart meter roll-out program by one year to the fall of 2015 with targeted completion of the installation of at least 50 million smart meters in no less than 30 million homes and businesses by the end of 2020. DECC stated the main reason for the delay is to give suppliers more time to create the data communications network that will underpin the roll-out.
There is no denying that the smart metering program has the potential to transform energy management and consumption in the U.K., if all goes to plan. Considerable cost savings are potentially available to suppliers and consumers alike. But are we really being over-ambitious and biting off more than we can chew? It is a colossal undertaking. Although there is nothing wrong with grand plans, the U.K.’s track record on IT projects of this scope and scale is not good. Maybe this further slippage is just symptomatic of trying to implement a program that is both over-complicated and over-controlled. When it comes to technology-based projects, how realistic is it to expect the network infrastructure to have an extended life-span of 20 years, as mandated? Is a one-time solution really feasible?
In the U.K., with smart metering intended to cover gas and electricity supplies, we have arguably embarked upon one of the most ambitious implementation programs yet conceived. Other countries, in contrast, are focusing solely on strategies for electricity. It also seems something of a paradox that, given the U.K. energy market’s recent history of deregulation and competition, smart metering in the U.K. has indirectly led us to seek to develop a highly regulated, centralized communications infrastructure to manage the data and energy management requirements. Communication of data to and from smart meters in the domestic sector will be managed centrally by a new, country-wide function covering both the electricity and gas sectors, known as the central data and communications company (DCC).
As the program generalities give way to the detail of the high level deliverables, a small but significant number of the technical requirements still do not have a proven solution on the table. The mechanism to make smart metering accessible to almost all customers, in a non-discriminatory manner, is still searching for a capable and reliable technology. Rather than criticize the delay, Dr Martyn Thomas, Chairman of the IT policy panel at the Institution of Engineering and Technology, called for the Government to take advantage of the time to formalize specifications for the system which are currently only expressed informally, leading to a danger of inconsistency, ambiguity and contradiction. But once specified what chance is there that it will still be fit for purpose in 20 years, as required? Surely flexibility and openness to technology advances will be essential for ongoing success? Just look at the development of the mobile telecommunications industry as a comparative example.
The wireless nature of the proposed communications network needed to underpin the smart metering program also opens up a potential strategic vulnerability to the utility system as a whole. Industry commentators are increasingly expressing concern that this is not being properly addressed. Little consideration has apparently been given to how the proposed wireless network might be hacked and the suggestion is that it will be with ease. With the energy supply system until now largely protected by its invisibility, suddenly there will be a proliferation of potential access and consequently hacking points. The system compliant smart meters that are currently available are also coming in for criticism for their apparent lack of security.
The objectives of reducing carbon output, improving competitiveness in the energy sector and increasing energy security are as laudable as when the government first mandated the installation of smart meters in October 2008. But, nearly five years on, it is hard to argue that anything has changed for U.K. households or that the future holds an abundance of promise. There continues to be a distinct lack of public understanding about the smart metering proposals. Skepticism, disinterest and a simple lack of knowledge abound and rather than seeking to affect a substantial shift in attitudes, many of the key benefits messages are seemingly being diluted. Many of the benefits expounded on government and quasi-government websites seem alarmingly unambitious for the estimated programs cost of £11.7 billion, a cost that is bound to rise. To be critical, many of the benefits that smart metering will deliver could be achieved at a fraction of the cost through the installation of simple pre-payment meters.
Nevertheless, smart metering is undoubtedly the way forward. Constantly reviewing the project and slipping the timetable is no bad thing if it ensures that we get it right. But there remains an open question for us all: should there be a broader and deeper review of the current approach? Having flirted with revolution, and probably rightly so, perhaps it is time to contemplate switching to a more evolutionary approach.
MISO uses real-time synchrophasor technologies to enhance reliability
Midcontinent Independent System Operator Inc. (MISO), formerly Midwest Independent Transmission System Operator, recently became one of the first grid operators across the country to utilize new synchrophasor technology in its real-time system operations for grid monitoring and analysis, a major milestone in furthering the U.S. Department of Energy’s goal of revitalizing the nation’s electric grid.
Synchrophasor technologies use phasor measurement units (PMUs) to collect data from more than 344 installed devices, 30 times per second. Traditional technology records measurements every four seconds. The data is GPS time-stamped, enabling measurements from different locations to be time-synchronized and combined to create a detailed, comprehensive wide-area assessment of system conditions. With this data MISO can better detect, diagnose and prevent system disruptions.
“Incorporating these new technologies into real-time operations greatly increases our situational awareness of grid activity, and is essential to our effort to modernize the grid. Synchrophasor technologies provide us with unprecedented data on situations that could radically affect reliability,” said Richard Doying, MISO’s executive vice president of Operations and Corporate Services. “With these devices, we’ve extended our ability to see ongoing system conditions, providing additional assurance that consumers are benefiting from improved reliability and predictability.”
Synchrophasors provide immediate value by enhancing MISO’s ability to simulate and troubleshoot the bulk power system, bringing a new level of situational awareness to grid operators. With synchrophasors, MISO’s system operators now view vital voltage and current measurements at any one of hundreds of strategic points along the interconnected transmission network at a level that was previously impossible to reach.
Regulatory frameworks that support utility electric efficiency programs grow
A new report, “State Electric Efficiency Regulatory Frameworks,” released by Innovation Electricity Efficiency (IEE), an institute of the Edison Foundation, shows that regulatory frameworks supporting utility electric efficiency (EE) programs continue to grow.
“Supportive regulatory frameworks are the key to expanding the electric power industry’s already large commitment to electric efficiency even further,” said Lisa Wood, IEE’s executive director. “Through them, the power industry provides integrated programs to help customers manage energy use, more fully utilize flexible demand resources on the power grid making it more efficient, and serve as a consistent and comprehensive point of contact to support all customer energy needs.”
Spending and budgets for utility EE programs continue to grow, in large part because state policies that allow utilities to pursue efficiency as a sustainable business are evolving. Utility company EE budgets in 2012 totaled $6.9 billion—a 27 percent increase above 2010 levels. By 2025, IEE predicts that EE budgets will exceed $14 billion.
“For utilities to treat EE programs as equivalent to supply-side investments from a financial perspective, three types of regulatory mechanisms are critical: direct cost recovery, fixed-cost recovery, and performance incentives,” said Wood.
The report finds that all states with ratepayer-funded EE programs have direct cost recovery of program expenditures. Since its last update in July 2012, IEE found that 31 states have some type of fixed-cost recovery mechanism to align utility fixed costs with investments in energy efficiency programs, up from 27 states in 2012. Regarding performance incentives, 28 states currently have them in place, up from 23 states in 2012.More PowerGrid International Issue Articles
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