- S&C Electric Company

The U.S. operates about 164,000 miles of highvoltage electric transmission lines. These are divided into five grids. Despite its vital role, the transmission grid has been neglected and allowed to become outdated over the past three decades. While electricity demand increased by about 25% since 1990, investment in new facilities has decreased about 30%. While investments are still being made, the growth of the transmission system hasn’t kept up with demand.

Today, 70% of the nation’s transmission lines and large power transformers are at least 30 years old. Experts agree that America’s transmission grid is in need of investment. For instance:

• The American Society of Civil Engineers gave the nation’s energy infrastructure a D in the organization’s 2009 Report Card for America’s Infrastructure.

• According to the U.S. DOE, transmission and distribution losses (never sold) grew from about 5% in 1970 to 9.5% in 2001, primarily due to heavier use and more frequent congestion.

• The North American Electric Reliability Corporation has documented that the present transmission system will require “significant transmission additions and reinforcements” to accommodate the widespread integration of renewable resources.

Congested transmission lines and an outdated infrastructure have compromised efficiency and led to brownouts and blackouts. According to the DOE, major power outages and power quality disturbances cost our economy between $25 billion and $180 billion annually.

New transmission has been a private-equity effort so far. The FERC, Federal Energy Regulatory Commission, governs the growth of wind farms and the grid but provides little guidance as to how the grid should grow despite all the talk of a smart grid. Still, wind farm owners are working to build transmission lines to load areas. For example, one recent line will extent from wind farms in East Texas to North Mississippi. Such projects create new jobs, generate investment and economic development.

Windpower Engineering & Development

Transformers serve as a hub for collection and distribution of energy changing the voltage level at different locations of the grid. They are a key component of the Smart Grid, loosely defined as an automated, widely distributed energy delivery network, characterized by a two-way flow of electricity and information, and capable of monitoring everything from power plants to customer preferences to individual appliances.

There is some ways to go before the vision of the Smart Grid is realized, but recently monitoring transformers has taken a leap forward, as energy production sites seek solutions to lower maintenance costs. Remote monitoring is seeing increasingly wider use especially remote wind farms and solar-powered production sites where having someone present to monitor transformers at fixed intervals is a costly proposition. As more renewable energy production sites come online, utilities have been investing in monitoring technology that keeps labor costs to a minimum.

Predictive maintenance gains favor over preventive

Remote monitoring and communication capabilities let utilities conduct “predictive” maintenance of transformers, which means conducting maintenance only when a parameter starts deviating from a pre-set standard. This typically does not occur at a pre-determined interval. Remote management let operators“see” how a transformer is operating and send someone to fix it only when it’s necessary.

The schematic show how Visizmax would network a wind farm for predictive maintenance.

Daniel Lambert, of Vizimax, a Montreal, Canada-based company that offers remote monitoring and control systems for public utilities and the industrial and private sectors, notes that remote management is being widely embraced, especially as operators need more profitable maintenance functions. “It is similar to today’s cars that tell you when to change your oil or conduct other maintenance based on specific driving habits,” said Lambert. “Rather than changing your oil at 6,000 mile intervals, electronic sensors can determine if you do mainly city or highway driving and signal the need for an oil change accordingly. That basic principle has been adapted for use in monitoring transformers.”

When maintenance is done purely in preventive mode, operators have no idea what is really happening inside and next to the transformer, and may tend to unnecessarily shorten intervals between each maintenance activity. With predictive monitoring, utilities can save money by having a real understanding of the key transformer parameters, which include temperature, liquid level, pressure vacuum, outgoing voltage, and ingoing voltage.

Utilities that conduct preventive maintenance programs usually use either time or quantity of energy consumed as the determining factor. Once they install remote monitoring capabilities, most switch to predictive-maintenance modes. Payback on the investment in remote monitoring equipment is estimated between 9 and 15 months.

Among those moving in the direction of this type of remote monitoring are GE, Siemens, Alstom Grid (Areva T&D), Schneider Electric, BHEL, Crompton Greaves, New York Power Authority, National Grid, Power Grid of India, and Hydro-Quebec, among others.

Building transformers that incorporate digital monitoring

Many transformer manufacturers are recognizing this growing demand for online transformer monitoring products and diagnostic services, and investing in building them, especially for step-up transmission, high-voltage transformers.

These technologies will be critical for improving grid reliability and helping utilities avoid transformer failures and resultant blackouts. They will also reduce maintenance costs and defer capital expenditures by extending a transformer’s useful life.

In addition to monitoring vital statistics such as temperature, pressure, and vacuum levels, there has also been a burgeoning interest in conducting dissolved gas analysis (DGA) of the oil in transformers. A DGA takes samples of an oil’s exhaust gases to determine if events have occurred that might be detrimental to the transformer and reduce its life. Industrial transformer maintenance people and utilities are setting up these planned sampling programs, using online devices that can monitor oil quality.

This can greatly improve reliability, because users will know in advance when something has to be replaced, rather than risk unscheduled outages. For food-processing plants and mills, which can lose millions of dollars when power is interrupted, this type of sampling program is being undertaken to ensure reliable power.

Transformers in place now are already using various smart devices for load switching. In the 21st century, the move will be towards monitoring systems that promote transformer reliability. Ensuring reliability on the grid by replacing equipment before it fails and anticipating upcoming problems is what transformer manufacturers will be focusing on.

Remote monitoring equipment

The latest technology used for remote transformer monitoring includes a combination of a remote terminal unit, a programmable language controller, a gateway (a network node equipped for interfacing with another network that uses different protocols), and a protocol converter. The complete monitoring system is usually placed in service by a system integrator or a power manufacturer.

One type of control panel can show the essentials for each turbine. Why is #2 not producing?

An example of one such system is Vizimax’s RightWON, a secure, modular, rugged automation remote terminal unit (RTU), programmable logic controller (PLC), gateway, communication conversion protocol platform that connects circuit breakers, transformers, IEDs, meters, sensors, control and monitoring devices at the substation level or anywhere on the distribution network. In addition to energy applications, the monitoring devices are used in water and telecommunications monitoring.

The unit is for remote management applications, providing support for equipment through its data acquisition, monitoring, control and remote maintenance functions. At renewable energy sites, the system shuts down and locks circuit breakers (CBs) and inverters remotely, which avoids traveling to an energy-production site for distribution-line maintenance. The production site is still operational while maintenance is occurring on the network.

The unit is often used in substations, where it usually connects to transformers, circuit breakers, intelligent electronic devices (IEDs), protective relays, and meters through the electric utility’s private network. In some instances, in can be used strictly for monitoring transformers in substations, using wireless connectivity (through GSM, GPRS, 3G or CDMA networks). Parameters such as temperature, liquid level, pressure vacuum, outgoing voltage, and ingoing voltage will be measured and transferred to a utility’s supervisory control and data acquisition (SCADA) system. Wireless monitoring calls for specialized Web service interfaces.

The system makes it economical to conduct monitoring, because it can convert older controls and sensors already implemented to newer communication protocols without having to replice or modify them. The monitoring system connects to the SCADA using fiber optic cables or web interface through a wireless device. It offers a remote and local view on event logs charting key assets status changes and alarm signals about exceeding thresholds.

Remote access is made possible through networking, security, and telecommunication functions, and is supported by a broad range of integrated interfaces. These interfaces support a wide variety of industrial protocols (IEC 61850, DNP3, ModBus, and IEC 60870) as well as Web access and remote maintenance functions. The information collected is easily viewed on smart phones from anywhere, any time. The system supports sending notifications by email, text messages, or pager. Users who receive a message can access the system using a Web browser to view the data and operate the site remotely.

The system is IEC 61850 KEMA certified and can also be used for a variety of other Smart Grid applications, including remote default detection and automated reclose/disconnect operations within distribution networks, and alarms and operational data broadcast and commands, usually to or from the SCADA of power utilities, IPPs, integrators and equipment manufacturers’ team management applications.

Monitoring equipment also used in re-energizing transformers

In addition, new flux management monitoring technology is being deployed more at the end of transmission lines during re-energizing a transformer, a regular process that takes place every time a production site connects to the grid. The need to re-energize varies considerably, but there are always times when required maintenance requires stopping the connection between the production site and transmission lines. When maintenance is completed, the transformer must be re-energized.

The flux management units avoid network inrush that may create network outages while transformers are re-energized, something that in the past had been a frequent occurrence. This is extremely important, because several hours of lost revenue in a month can mean the difference between a profitable energy production site and an unprofitable one.

The system calculates the residual flux while a transformer is reenergized at the last operation, and ensures that the next transformer operation is performed at the exact millisecond such that residual flux is identical to the previous operation, which minimizes current inrush and stress on both the high voltage transformer and circuit breaker.

The unit measures relevant parameters from the transformer and sends a command to the circuit breaker of the transformer to achieve this operation. Using this equipment increases the quality of the network, decreases network outages, and decreases the frequency and the cost of maintenance operations.

Last thoughts

Remote monitoring makes it possible to manage maintenance of remote power equipment in the field in a predictive mode instead of the more traditional and more expensive preemptive or preventive mode. By remotely monitoring power equipment in remote locations, electric utilities now only must execute maintenance operations on their equipment when it is required. This is going a long way to cutting costs for the many renewable energy production sites that are coming online.

Pacific Crest Transformers
http://www.pacificcoasttransformers.com

Windpower Engineering & Development

For more information on MISO's value-added planning process, MTEP11 and the Multi-Value Projects portfolio, see MISO's MTEP11 and MVP One-Pagers posted on MISO's website.

MISO’s Board of Directors has unanimously approved MISO’s Transmission Expansion Plan 2011 (MTEP11), a comprehensive long-term regional plan for the electric grid that will bring more than $2 billion in annual benefits for decades to come for energy consumers throughout the Midwest. The plan was developed during 18 months that included dozens of meetings with stakeholders to ensure the reliable and low-cost delivery of energy.

When combined with the existing power transmission network, the projects approved in MTEP11 will improve system reliability, connect 2,700 MW of queued generation and lower the cost of delivered energy while enabling energy policy mandates. Board approval requires that MISO’s transmission owners use due diligence to construct the facilities approved in the plan.

MTEP11 recommends 215 new transmission infrastructure projects, including 16 industry-leading Multi-Value Projects (MVPs). Together with the previously approved MVP, the 17 MVPs alone will create $15.5 to $49.2 billion in net present-value benefits over a 20 to 40-years. The MVP portfolio provides broad regional benefits commensurate with costs and it supports state and federal energy policy mandates in the MISO region. In total, the portfolio will deliver benefits in excess of 1.8 to 3.0 times its costs. For retail customers, that translates to $23 in benefits from lowered delivered energy costs for about $11 a year in investment — a 109% return.

“The portfolio of Multi-Value Projects will not only improve regional reliability, but it also will create up to 39,800 construction and 74,000 total annual jobs and generate up to $49.2 billion in benefits from the use of lower-cost generation and reductions in energy wasted through transmission losses,” says MISO CEO John Bear. “In addition, all of MTEP11 projects are essential to helping the region manage the severe drop in planning reserve margins that is likely to occur in the next several years if pending environmental regulations proceed as planned,” he said.

Through use of a low-cost generation siting system developed in collaboration with MISO’s stakeholders, state regulatory officials and transmission owners, MVPs optimize portability for wind generation while minimizing distances from planned transmission to other fuel sources, assisting the region’s transition to new generation facilities. This in turn lets states within the MISO footprint meet their renewable energy goals and ensure lower-cost generation is utilized in the wake of pending environmental regulations that could cause the simultaneous outage of 61,000 MW of coal-fired generation in the region.

For more information on MISO’s value-added planning process, MTEP11 and the Multi-Value Projects portfolio, see MISO’s MTEP11 and MVP One-Pagers posted on MISO’s website. There you will find information on the following topics:

• MTEP 11 Overview
• Benefits from Multi-Value Projects
• How MVPs Create Jobs, Benefits for States
• MVP Map by Zone

MISO
https://www.midwestiso.org/Pages/Home.aspx

Windpower Engineering & Development

Generation technologies such as wind and solar are gaining market share, while at the same time they are introducing an uncertain wrinkle into the old reliable power grid — variability.

This article comes from NREL
With the simple flick of a light switch, you connect to “the machine,” the North American electric grid. It’s the world’s most complex transmission and distribution system — also is referred to as the world’s largest machine. That same machine has run reliably on coal, natural gas, and nuclear energy for decades.

Now, it’s time for a tune up. Newer power-generation technologies, such as wind and solar are gaining market share, while at the same time, they introduce an uncertainty into the power grid in the form of variability.

The new Energy Systems Integration Facility (ESIF) at U.S. Department of Energy’s (DOE) National Renewable Energy Laboratory (NREL) is tackling the challenge of keeping the power grid running reliability while at the same time introducing a host of new equipment into an already complex system.

According to NREL’s director for Electricity Resources and Buildings Integration, David Mooney, the grid has operated essentially the same for more than 50 years. Utilities know how to predict energy demand by looking at the day of the week and the weather forecast. Then, utilities dispatch generating sources (usually from coal or natural gas) to meet expected demand.

An artist with the Smith Group, rendered the Energy Systems Integration Facility. The view is from west to east.

“It was a pretty orderly way to operate a system,” says Mooney. “Today, there are a lot of technologies coming online — including wind and solar — that are going to require a transformation in the way this orderly system operates. Now instead of only having variability in the electric demand, we are also introducing technologies that make the generating supply variable as well.”

Renewable Energy Already is Connected — Or Is It?

For homeowners with photovoltaics (PV) on their roofs, or the technician working a wind farm in Texas, this may seem moot. Their technologies already are connected to the grid and the electrons seem to be flowing seamlessly.

However, this type of renewable energy still make up a small fraction of the America’s overall energy generation. According to the latest data from the U.S. Energy Information Administration, power generation from renewables such as biomass, geothermal, solar, and wind have so far accounted for less than 5% of the total U.S. power generation in 2011.

Connecting that small amount of renewable energy into the power grid is not a big deal. “If you have 1,000 homes and five to 10% of those add solar, the variation and the output of the PV is in the noise of the grid,” says Mooney. “Right now, utilities view PV systems in small numbers as a demand reduction technology — no different than people switching to compact florescent bulbs. But, if 50% of those 1,000 homes have a PV system, then the output could start to look more like a generating technology to the utility. Once it reaches those kinds of numbers, the utility has to start worrying about things like variation in cloud cover that cause PV output to vary.”

“As all of these new technologies become cost effective, they are starting to get used a lot more and utilities ask, what’s the best way to integrate these variable technologies while maintaining a safe and reliable electric power system?” says NREL’s Director of Energy Systems Integration Ben Kroposki.

ESIF is the first significant DOE laboratory designed specifically to deal with the integration issue. NREL’s researchers will be able to configure electric systems the way they would appear in the field and operate them at the same level of power as the utility uses.

“We all know how we react when the power goes out. The local utility usually bears the brunt of the PR problems associated with an outage,” says Mooney. “So it is understandable that they are conservative in how they go about adopting new technology. That is why the ESIF is so important for reducing that risk. The utilities will be able to operate new technologies in an environment that mimics the real system so they can work out the bugs of introducing new technologies beforehand and maintain the high reliability standards that we have all come to expect.”

ESIF also will be a plug-and-play environment for industry. “ESIF is set up so that partners can bring in technologies — such as a PV inverter or battery system — and we will have on hand the other equipment that the technology being tested would connect to. They don’t have to go and try to find these complete systems,” Kroposki said.

ESIF also will loop the utilities’ hardware into a simulation environment so they can look at new technologies operating in a combination of real world, real power and simulated or virtual environments to see the impact that these new systems are going to have on the reliability and quality of the power. “Once they try it all out in the ESIF, we believe the utilities will be much more inclined to adopt the technology,” says Mooney.

Fun facts to know and tell about ESIF:

• Cost: $135 million
• Area: 182,500 ft²
• Office space: about  200 ft²
• State-of-the-art electric systems simulation and visualization
• Component and systems testing and at MW-scale power
• Combine functioning systems with utility simulations for real-time, real-power evaluation of high penetrations of renewable energy
• 15 laboratories
• Four outdoor test areas
• Construction complete: fall 2012

Other key service and support features:

• Research Electrical Distribution Bus (REDB)
• High Performance Computing Data Center (HPCDC)
• Hardware-in-the-Loop Prototyping at Megawatt-scale Power
• Collaboration and Visualization Rooms
• High bay control room

Another challenge for NREL researchers will include looking for ways to improve the grid. “For mostly economic reasons, we can’t build up a new grid and then switch over to it,” Mooney said. “ESIF will let us look at how we can make the grid ‘smarter’ and more flexible to receive technologies in a way that can maintain or even enhance the existing grid.”

Many technologies on the grid are antiquated, and can be up to 50 years old. A “smart grid” has three components that the current grid doesn’t have:

• Sensors as part of the grid so that power quality is measured in real time
• Communications to relay data coming from sensors to utility operators to assist with decision making
• Controls that allow system operation changes from a central location.

“People are surprised to learn that most utilities still don’t know about a power outage until they get a call from a customer,” Mooney said. “If we had a smarter grid, we would have sensors on transformers and power lines that would let utilities act preemptively if problems in power quality were arising so they could keep the power on. However, if the power did go out, utilities would be able to see it immediately and dispatch crews to minimize down time.”

As utilities put smarter technologies onto the grid, another avenue for energy savings is to have the grid communicate with a home energy-management devices so the home can work with a utility to manage power needs.

“The smart grid will offer the possibility of frequent, likely automated communication between a utility and a customer,” Mooney said. “As a consumer, you will likely be able to know when the power is cheapest, for example, and have a plan with the utility that tailors your power consumption accordingly.”

The foundations for a smarter grid are being laid today. In June 2011, Secretary of Energy Steven Chu announced that more than 5 million smart meters had been deployed thanks to Recovery Act-funded efforts to accelerate modernization of the nation’s electric grid.

“To compete in the global economy, we need a modern electricity grid,” he said. “An upgraded electricity grid will give consumers choices and promote energy savings, increase energy efficiency, and foster the growth of renewable-energy resources.”

NREL
www.NREL.gov

Windpower Engineering & Development

IBM, once known for main frame computers, now wants to be known for building smarter cities. That will start with a smarter power grid.

Software that lets a utility in Washington cut power consumption by up to 50% will soon get a big test. This demonstration is part of a project that will attempt to knit together aging and fragmented grid infrastructure across five states and 11 utilities. The project will involve 95 smaller efforts to integrate wind power, store power from the grid, accommodate electric-vehicle charging, and establish “microgrids” that can survive on their own in the event of a power outage.

The software for the $178-million project is nearly complete (as of Nov 2011) and the system is predicted to be up and running by Nov 2012, says Ron Ambrosio, team research leader for the energy and utilities industry at IBM, one of several organizations involved. The project is one of 16 smart grid demonstrations funded in part by the 2009 Recovery Act.

Some of the technology got a trial run on Washington state’s Olympic Peninsula in 2005 to 2007. The technology let utilities communicate with smart thermostats and other equipment at residences, reducing peak electricity demand and responding to fluctuations in supply from intermittent resources such as wind turbines.

Ordinarily, such a system would depend on changes in regulations to let utilities charge residential customers different prices for electricity depending on demand. But the devices developed by IBM, the Pacific Northwest National Lab, and others, makes such real-time pricing unnecessary.

The approach keeps electricity rates flat and gives customers rebates on their power bills in exchange for having thermostats and other smart devices hooked up to communicate with the utility. The utility signals smart thermostats and appliances regarding how much it costs the utility to provide it electricity. Then, based on consumer

preferences, the smart systems signals back to the utility regarding how much power they will use. For instance, when Summer power costs are high, the thermostat might signal that it will let the internal how temperature rise to reduce air conditioning costs.

When the system was tested on the Olympic Peninsula, it reduced electricity demand during peak times by an average of 15%. During one period of particularly tight power supply, consumption dropped 50%. Consumers trimmed electric bill by about 10%.

One concern the demonstration will address, says Ambrosio, is the potential development of feedback loops that can make the system unstable. The concern is that such interactive devices in 60,000 homes over five large western states could cause unexpected fluctuations in demand that power generators can’t keep up with.

IBM
www.ibm.com

Windpower Engineering & Development

The HySTAT uses pressurized alkaline electrolysis to generate high purity hydrogen at pressures to 25 bar (363 psi) directly from the electrolyser module. Hydrogen and oxygen are channeled through efficient inorganic membranes resulting in high-quality hydrogen.

A manufacturer of hydrogen generation and fuel cell products says it has been selected by the City of Herten, Germany to store hydrogen generated from wind power. Herten is a major German hydrogen cluster for electro-mobility as well as renewable energy projects.

Renewable wind energy is a good source of power for communities to offset the demand traditionally served by electricity from fossil fuels. Wind energy also has significant potential as part of Germany’s commitment to phase out nuclear power by 2020. By incorporating hydrogen energy storage, excess wind power can be stored and redeployed when the wind is not blowing, ultimately supplying a greater percentage of the community’s overall power requirements with improved stability and reliability.

To meet the project requirements, Hydrogenics will provide one HySTAT 30 hydrogen generation unit and a HyPM 50 kW fuel cell power system to Herten in 2012. This combination will demonstrate the advantage of hydrogen with its ability to scale and store significant amounts of energy for long periods with negligible loss. From storage, the energy will be redeployed through fuel cells as electricity to the grid, or as fuel for zero emission vehicles and other devices, such as industrial equipment.

Electrolyzing water into hydrogen using excess intermittent renewable energy is the optimal clean pathway to smart-grid stabilization and energy storage. It has real advantages over alternative energy storage solutions,” said Hydrogenics CEO Daryl Wilson.

Hydrogenics Corp.
http://www.hydrogenics.com/

Windpower Engineering & Development

The Smart Grid Storage Management System provides an interface between a stored power source and a utility grid. The equipment consists of a master control system and a 2-MW, 2.5-MVA power conversion system.

The Smart Grid SMS Storage Management System is said to provide an interface between a stored power source and the utility grid. It consists of a master control system and a 2-MW, 2.5-MVA power conversion system (PCS). The PCS has two inverters, each rated 1 MW and 1.25 MVA. When coupled with stored energy, the SMS can charge the storage device from a utility source, or discharge the storage device to the utility. When connected to a feeder, the SMS can supply VARs in response to an external command, or hold feeder voltage at a preset level. The SMS can also operate independently, supplying power to a load not connected to a utility. Individual SMS units can be operated in parallel up to 10.0 MW or 12.5 MVA, with unit outputs connected to a common bus at medium voltage. Two or four SMSs are housed in a single ISO container for outdoor installation. Each 2-MW block contains two dc-circuit breakers, two ac-circuit breakers, two PCSs and controls. The output of the PCS is a 480-V delta connection that can be connected to a delta or wye transformer. If it is necessary to supply single-phase loads when the utility source is not present, a delta connection must be used. A few applications include:

UPS for data centers. The SMS is the largest-capacity static-inverter pack available in the UPS industry. Its high capacity and medium voltage capability, gives data-center designers greater flexibility than previously possible. The SMS’s design is capable of powering complete data center loads, including air-conditioning chillers. Single bus systems up to 24,000 kW are possible with the SMS.

SMS for renewable energy. Solar and wind energy are intermittent power sources that the grid must accept whenever available. During absences of sun or wind— when these sources are not generating—replacement power must be provided. The SMS can store the power when it’s produced, and then use that energy for generation ramp-rate control, output-smoothing, or time-shifting.

Grid-scale energy storage. The SMS can deliver up to 2 MW of stored energy to a grid from any type of battery storage.

Islanding. When applied with S&C’s IntelliTeam SG Automatic Restoration System, the SMS can be used in remote areas, as an energy source during power outages. Upon loss of utility power, IntelliTEAM SG re-configures the distribution system and uses the stored energy to serve local customers—now isolated from the utility—for as long as 7 hours.

Peak shaving. During high-demand periods, the SMS can provide full output for up to seven hours. This reduces the system peak, deferring the need for capacity additions on the distribution or transmission system.

The company lists these product features:

• Megawatt-hours of energy storage for Smart Grid applications.

• High efficiency.

• Fully digital control system.

• Better use of renewable energy.

• With S&C’s IntelliTEAM SG Automatic Restoration System, provides dynamic islanding capability.

• Automatic or remote SCADA control.

• Turnkey installation and project management for smooth integration into utility system.

S&C Electric Co.

www.sandc.com

Windpower Engineering & Development

The report analyzes energy harvesting to power the charging station. Solar is not the only option here.

The report analyzes energy harvesting to power the charging station. Solar is not the only option here. The lack of standards is holding things up to a lesser or greater extent across the world. Timelines and the issues involved are examined. Forecasts of charging station numbers, unit value and total value are given, detailed by charging speed and territory.

Analysis is the essence of this report say authors, with many figures and tables comparing pros and cons and giving detailed new forecasts for 2011 to 2021. The report appraises work from New Zealand to Canada and Japan. The charging issues and equipment employed with electric land, water, and air vehicles are considered, both hybrid and pure electric, and the solutions now and in future. The report quotes recent opinions of many interested parties. The impact of alternatives is also considered, such as gas turbine and fuel cell charging of on-road vehicle batteries, with no roadside charging, and the declining percentage of hybrids that do not plug in.

The report appraises a surprisingly large number of companies providing, or about to provide, solar powered roadside charging and inductive contactless charging, resonant and conventional, is appraised. The  different standards situations are examined for North America, Europe and East Asia, for both charging stations and their interfaces, and the battle for the global standards.

ASDReports
www.Asdreports.com

Windpower Engineering & Development

Grid Information Manager allows making smarter business decisions that improve operational reliability and efficiency through a single view of all of a utility’s grid information management.

GE engineers say, yes, and they have done so with the company’s Intelligent Platforms software. Proficy Grid Manager, a range of tested grid optimization software for local utilities, delivers real-time information and analytics to help utilities improve operational reliability and efficiency, and manage a more intelligent, cost-effective grid.

Offering an approach that’s customizable to align to a utility’s required smart grid vision, the grid manager encompasses four modular capabilities including operations management, lifecycle management, load management, and knowledge management. It uses the latest ideas to help utilities reduce system outages, enhance equipment lifecycles, manage customer loads, and digitize standard operating procedures.

“Proficy Grid Manager is an open and layered architecture that connects with a utility’s current systems and applications while providing the flexibility to implement value-added capabilities right on top,” said Bill Pezalla, Global Energy Industry Manager for GE Intelligent Platforms. “It’s also Microsoft-based for easier support and training, cost-effectiveness, and integrated security.”

The company says key portions of Proficy Grid Manager include the:

• Operations Management Dashboard to provide a remote-monitoring capability that lets utilities respond to outages, analyze, and prioritize alarms, and leverage advanced and causal analysis. It delivers actionable information that increases system reliability and decreases restoration time.
• Lifecycle Management delivers alarms and quick diagnosis to events on transmission and distribution equipment, providing information that can reduce downtime caused by equipment failures.
• Load Management provides analytics that leverage next-generation technologies to more effectively predict and balance customer loads—minimizing the impact of peak loads on customer productivity and costs, and limiting utility spending on wholesale supply or new generation resources.
• Knowledge Management improves consistency and ensures that best practices become standard operating procedures. This is an industry-unique offering that electronically manages a utility’s work processes and provides an audit trail for compliance.

To help utilities get started, the developer works with each utility to develop a complimentary customized “Smart Grid Roadmap” — a unique list from other solution providers. The roadmap provides a step-by-step strategy, tailoring the grid manager to meet business needs and achieve each utility’s own vision for its distribution system.

“A key advantage is that a utility can jump straight in at any step and progress from that point,” said Pezalla. “Depending on what smart grid technologies are already in place, the roadmap lets users focus on the areas that provide the best operational performance and cost effectiveness for its utility today while providing a strategic, forward-looking path for the future.”

GE Wind Energy
http://www.ge-ip.com/electric_utilities

Windpower Engineering & Development

FERC’s recent Sky River decision highlights issues for owners of generator lead lines regarding the use of such lines by unaffiliated third parties. Sky River LLC owns a wind project and an interest in an associated lead line to connect to the transmission grid. Other qualifying facilities also use the nine-mile, 320-kV generator lead line. Sky River negotiated a common facilities agreement to allow a third party, WindStar Energy LLC, to use the line to transmit power from WindStar’s proposed wind project to its point of interconnection on the transmission grid.

With Sky River as owner and WindStar as licensee, the parties filed the common facilities agreement for FERC approval under Section 205 of the Federal Power Act. The parties requested waiver of Sky River’s requirement to post an open access transmission tariff (OATT), which, pursuant to Order No. 888, is required for the provision of jurisdictional transmission service. FERC has often granted waivers to entities that only own discrete and limited interconnection facilities, such as generator lead lines.

In this instance, however, FERC rejected the common facilities agreement. FERC stated that Sky River cannot provide transmission service to an unaffiliated third party outside the context of an OATT. In the circumstances involving WindStar, an unaffiliated third party, FERC determined that Sky River was required to publish an OATT and process a transmission service request pursuant to that OATT, as outlined in Order No. 888.

The Sky River decision affects numerous generators with lead lines. It would require them to publish an OATT when an unaffiliated third party requests service on the line. The Sky River decision rejects common facilities agreements with unaffiliated third parties that involve generator lead lines because they have been determined to result in the provision of jurisdictional services outside of FERC’s open access requirements.

Foley & Lardner LLC
http://www.foley.com/

Windpower Engineering & Development