There was a time when dispatching electricity was a pretty simple process. Dispatchers tracked the supply versus the demand. Those with cheaper excess power sold it to those needing it, and marketers placed orders hourly for power transactions. The orders were executed at the top of the hour. Utilities bought and sold power among each other using the bulk transmission system for this wholesale-power trading procedure.
This worked great in the last century, but it has been challenged because of the way the grid operates today. The world is more convoluted now. Demand for electricity has grown to unimagined proportions, outpacing the grid's ability. Consumers expect cheaper electricity with unprecedented high-quality power. They also expect electricity to be environmentally friendly with little or no carbon footprint.
Renewables certainly meet the environmentally friendly expectations, but the cheaper and high-quality aspects, not to mention reliability, are challenges the industry must face. Adding to the complexity is the composition of those renewable resources. It is not unusual to find 600-MW and larger wind farms, and solar farms above 100 MW on the drawing boards, but what is catching the industry's attention is the aggregated capacity of renewables found on the distribution system.
Specialized software keeps track of the available generation, transmission resources and system load, but what about the distribution side? As higher penetrations of solar and wind generation are interconnected to the grid, distribution is no longer so simple. Distribution feeders typically are designed for unidirectional power flow (from substations to loads), but today customers with large renewable resources are pouring power into the grid through the feeders.
Operationally, there are some thornier issues, too, such as environmental concerns, interconnection policies, independent power producer contracts and curtailment as a result of congestion on the grid. The U.S. Department of Energy (DOE) and the National Renewable Energy Laboratory (NREL) recently published two studies concerning renewable generation and the transmission grid. The studies — the “Western Wind and Solar Integration Study” and the “Eastern Wind Integration and Transmission Study” — investigated the operational impact to the grid by large penetrations of wind and solar generation.
The Western study proposed 35% penetration of renewable sources (30% wind and 5% solar), whereas the Eastern study looked at 30% penetration of wind. Both studies found these high amounts of renewables were challenging but technically feasible. The studies determined that transmission capacity is the solution for accommodating these levels of renewables.
The DOE-NREL studies also pointed out expansion of the existing transmission infrastructure is critical. Without these transmission enhancements, substantial curtailments to the renewable generation would be required. This was recently brought into focus in the Pacific Northwest, one of the areas with the highest penetrations of wind in the United States. There was more green power (hydro and wind) available than load to use it. There was no way to move the power to other regions (finite transmission capacity), so the wind was curtailed.
This region has a lot of wind generation installed, but it is extremely intermittent. There also are intense environmental concerns with the Columbia River and its salmon. During the time frame this all took place, the reservoirs were full. Because of environmental concerns, it was felt the water could not be dumped despite contractual issues. Therefore, the water was run through the turbines, controlling the outlet flow of water, and wind was curtailed. Wind owners were not happy and went to the Federal Energy Regulatory Commission (FERC).
The FERC ruled in favor of the wind owners, but a ruling does not really solve the problem. As the old saying goes, “There is no substitute for wire in the air.” The real solution is adding to the transmission infrastructure, and that is what utilities are doing. For example, in North America, the Edison Electric Institute (EEI) publishes an annual report showing a cross section of its members' transmission project activities.
A Change in Thinking
A 2012 report by EEI, “Transmission Projects: At a Glance,” described more than 100 member transmission improvement projects. EEI's report noted 32 large interstate transmission projects are required for system reliability. These projects span multiple states and account for approximately 10,500 miles (16,898 km) of transmission at a cost of about US$42.5 billion. There also are 47 transmission projects supporting the integration of renewable resources. These projects represent roughly 13,000 miles (20,921 km) at a cost of approximately $49 billion.
In addition, the EEI report pointed out its members are partnering with non-EEI members to build an additional estimated $42 billion worth of transmission projects. That is a great deal of transmission building taking place, and it only represents EEI members in North America. Nonmember utilities and utilities worldwide also are adding much-needed transmission to meet demands and integrate wind and solar generation to the grid, but while transmission is hugely important, it is only part of the solution.
In Europe and Asia, high-voltage direct current (HVDC) is being used to connect remote renewables to the grid (“HVDC Transforming an Industry,”T&D World, April 2012). HVDC has the advantage of being able to move large blocks of power to the exact location on the grid where it is needed, avoiding congestion and strengthening the grid.
Renewables on Smart Feeders
It is not just the transmission system that needs renovation; the distribution system also has to change significantly to accommodate the back-feed problems brought about by the rapid proliferation of distributed wind and solar generation on the feeders. In the past, there was the assumption there was no other power source than the substation, so it was normal to design feeders radially. Alas, the customer did not get that memo. Individually, the power may be in small amounts, but grid-wise, it adds up to gigawatts.
This requires a new mindset and the deployment of improved performance monitoring schemes on the distribution system. Various monitoring systems are available to supply data for reducing system downtime, optimizing system performance and improving maintenance. They include two-way communication, detailed real-time power data, performance information and efficiency diagnostics.
To prove concepts and get real-world experience, the DOE has developed a smart grid demonstration project with Kansas City Power & Light (KCP&L). The project will study a local distributed control system based on IEC 61850 protocols, including renewable energy sources, control processors, distribution and customer technologies. KCP&L has hired Burns & McDonnell for engineering support and is partnering with Siemens Energy Inc. and Open Access Technology for the smart grid technology.
The project consists of 10 circuits originating from KCP&L's Midtown Substation. This is one of KCP&L's newest smart substations, commissioned in late 2011. The project will cover approximately 2 sq miles (5.2 sq km) with about 14,000 commercial and residential customers. The goal of the project is to demonstrate a next-generation end-to-end smart grid system and monitor the effect of photovoltaic (PV) energy sources on the feeder and substation.
Julio Romero Agüero, director of distribution for Quanta Technology, has worked with utilities studying the effects of the high penetration of renewables on distribution feeders and identifying alternatives to mitigate these effects. Agüero has found the impacts can be very complex in nature, particularly for large penetration levels, and their evaluation and mitigation generally requires conducting detailed modeling and simulations.
He looks for such things as reverse power flow, voltage variations, voltage increase, interaction with capacitor banks, load-tap changers and voltage regulators, protection coordination issues, real and reactive power fluctuations, losses increase, voltage unbalance, islanding issues (for example, temporary overvoltage) and harmonics.
Common Mitigation Measures
According to the Solar Electric Power Association, solar generation supplies less than 1% of the U.S. electricity needs, but concentrated pockets of solar-power customers are streaming power into the distribution system. Pacific Gas and Electric Co. is a good example. It has more than 5 million customers, of which about 55,000 have on-site solar-power systems totaling an installed capacity approaching 500 MW.
Utilities facing such large aggregations of PV need to perform systemwide impact studies with different degrees of penetration to establish the influence of renewables. These studies would enable utilities to be proactive rather than reactive. It is best to determine the mitigation measures required to reduce or minimize the impacts of PV before it becomes an emergency.
Common mitigation measures can be as simple as modifying the reference voltage of the load-tap changers and changing the compensating current on line-drop-compensation applications, or modifying the operating mode of line voltage regulators. They also can be more complex, such as relocating capacitor banks or installing smart grid power electronic devices.
One of the most accepted technologies is the flexible alternating-current transmission system (FACTS) controllers. Common on the transmission system, these FACTS devices are moving to the distribution circuits. Static synchronous compensators (STATCOM), like S&C Electric Co.'s PureWave DSTATCOM or AMSC's D-VAR STATCOM, have been in use at wind farms for many years.
Utilities are deploying STATCOMs on their distribution systems for the same reason independent power producers used them on wind farms. These devices are based on voltage-source-converter technology. They monitor voltage and stabilize it quickly when voltage excursions occur by either supplying or consuming reactive power. S&C Electic reports it has developed a single-inverter PureWave DSTATCOM for small wind installations.
A Balancing Act
Intertwined with all those transmission and distribution issues is the need for subhourly scheduling for generation and interchanges. The intermittency of wind and solar presents integration challenges at all timescales for the power system according to Electric Power Research Institute's (EPRI's) white paper titled “Impacts of Wind Generation Integration.”
EPRI's report pointed out schedule optimization, including modifications such as more frequent operational planning and reducing the time resolution of operation (for example, 5-minute markets), is critical. The report stated, “It is expected that increasing the temporal granularity of unit scheduling from hourly to 15-minute dispatch will decrease reserve requirement.”
FERC feels strongly about this hourly status, too. It went on record saying it was discriminatory and an inefficient use of the transmission system as well as generation resources. As a result, FERC issued a notice of proposed rulemaking (NOPR) in 2010 on this and other related issues.
The NOPR includes intra-hour scheduling and forecasting, and a provision for reserve from wind. Intra-regional scheduling also will improve the use of flexible resources. The NOPR is pending. Some industry leaders who reviewed the NOPR took issue with several of its provisions, but overall, it is a step toward better use of wind and solar generation resources.
The DOE-NREL wind integration studies suggested, in addition to the subhourly scheduling, larger balancing areas (Bas) are needed along with some form of energy storage. Bas were once called control areas, but that terminology has been updated. Today, a BA refers to a metered boundary containing generators, transmission and load. The studies showed larger Bas can capitalize on geographic diversity and the aggregation of wind and solar resources. In other words, the wind has to be blowing somewhere if the region is large enough.
As an example, the DOE reported the Midwest Independent System Operator (MISO) consolidated its 26 Bas into one BA. MISO's need for regulation reserves decreased from 1,200 MW to 400 MW once the new BA was in place. The DOE observes that a larger BA can share the load and the variability of generation.
This is a significant benefit as more intermittent renewables are installed. Subhourly scheduling offers the aggregation of conventional generation and renewable resources greater flexibility. Larger Bas smooth some of the variability of wind and solar, but energy storage cannot be ignored, either.
A Sunny Outlook
It is a fact the electric industry must accept: Renewable energy sources are becoming a larger part of the energy supply. The levels of penetration of wind and solar are increasing all the time. PV is the fastest-growing segment of power generation technology, with double-digit growth each year, but the amazing thing is its deployment. Wind and solar generation are on both sides of the meter. Tremendous utility-scale wind and solar farms are all over the transmission system.
While the industry's attention has been focused on these behemoths, huge amounts of smaller-sized distributed wind and solar have been installed on the distribution side of the business, so much so that long-standing current industry practices have to be modified. The concept of bidirectional power flow on distribution feeders may have Grandpa Engineer shaking his cane, but what is the big deal? Everything changes; it is the way of life, and wouldn't it be boring if there were not challenges?