Challenges and Unknowns

The adverse impacts on powerplant performance and economics associated with injecting large amounts of renewable energy into the grid are of great concern to many owner/operators of conventional generating assets. Many industry events have covered this topic in recent months, but the first to hit it head-on was a one-day critical-issues workshop at the CTOTF’s fall meeting in Reno, Nev, September 13.

Although the challenges of renewables integration were expected by most seasoned industry veterans, CTOTF Chair Robert G Kirn of TVA said that the speed at which intermittent renewable resources have penetrated certain markets, regions, and balancing authorities have resulted in grid security and plant operational issues that will require innovative solutions and extraordinary cooperative effort across non-traditional lines.

Speakers at “Integrating Renewables into the Generation Mix: Challenges and Unknowns” defined the principal elements of the challenge, and then proposed solutions—strategic, technological, operational, and regulatory. The challenges can be classified in broad terms this way:

• Existing generation resources must have more flexibility. Whether they can achieve that flexibility economically and without sacrificing other performance goals, such as safety, reliability, and efficiency, is another matter.
• Markets and balancing authorities must institute new measures to value, pay for, and/or reward dispatch at sub-hourly time scales—perhaps down to minutes.
• Costs of cycling generation resources must be more accurately assessed and accounted for.
• Grid issues respective of the magnitude and type of renewables connected vary dramatically across regions. Solutions may require regionally based approaches and levels of renewables based on operational characteristics versus RES goals.

The solutions, in turn, can be grouped into these broad categories:

• Modify existing plants to operate more flexibly.
• Revise market-value and reward profiles for ramping, intra-hour dispatch, turndown, and other market products reflective of increased grid security requirements.
• Seek or demand greater regional cooperation among individual balancing authorities.
• Expand bulk and distributed energy-storage installations, which could offer greater operational flexibility at lower cost than traditional options.
• Improve cost allocation and compensation to grid resources for ancillary services.
• Revise interconnection standards to recognize and assign renewable owner/operators costs for incremental system security and for ancillary services required to accommodate the operating profiles of renewables.
• Seek a legislated “sunset” to renewable energy production tax credits (PTC), especially for wind, which would slow wind penetration and create a more level playing field with respect to economic dispatch.

Setting the stage. Perhaps as simply and as eloquently as possible, Kevin Geraghty, VP power generation, NV Energy, which worked closely

with CTOTF to develop the workshop, opened the meeting by observing that electric utilities today must serve as a safety net—that is, take the “extra juice” from grid-connected distributed generation (DG) resources, including renewables, and fix problems when they occur.

The idea of utility service has changed, he said, from one where perhaps 10 outages per year at your house might be okay to one where even a blinking digital clock is not okay. NV Energy must meet a 25% Renewable Portfolio Standard (RPS) by 2025, one of the most demanding state statutes in the nation. Today the company ranks first nationally in installed solar energy capacity per person.

Jason Makansi, president, Pearl Street Inc, and executive director of the Coalition to Advance Renewable Energy through Bulk Storage (CAREBS), then framed out at the industry level the challenges that confront generation owner/operators. While many of the driving forces favoring renewable energy are well known—for example state RPSs, the “environmental gauntlet” facing coal-fired plants, and pending federal legislation that could escalate renewable energy penetration—many attendees were surprised to learn that from 60% to 90% of all generation interconnection requests in six independent system operator (ISO) and regional transmission organization (RTO) jurisdictions are renewable energy (mostly wind).

Another surprise to some: Large amounts of wind energy in certain balancing authorities and areas—including the Electric Reliability Council of Texas (Ercot), Bonneville Power Administration (BPA) in the Pacific Northwest, and the Midwest ISO—can drive market prices into negative territory because of the PTC subsidy.

Characteristics of this renewable resource important to any economic evaluation include the following: Wind-energy strength curves are opposite of electricity demand curves; availability of wind energy can shift dramatically in a few minutes; wind capacity factors rarely average more than 30%. Thus plants powered by gas turbines and coal are penalized by having to undergo deeper and more frequent cycling to “fill in” around intermittent wind.

Also of interest: Less than 10% of Ercot’s total wind capacity is considered “available” during summer-day peaks. Plus, wind energy in PJM Interconnection is credited with only 13% of its capacity value during peak periods. And MISO representatives report that swings of up to nearly 2000 MW are common.

Makansi suggested four broad solutions options, adding that all ultimately would be deployed in some combination in regions affected by large-scale renewable energy penetration. The options:

• Smart grid. Enhanced wind monitoring, forecasting, and communications with grid operators, combined with demand side management (DSM).
• Gas + wind. Deeper and more frequent cycling and dispatching of existing fossil assets, and the addition of more flexible gas-turbine-based assets.
• Energy storage. Build a new layer of bulk and distributed storage options, which offer greater flexibility than alternatives for meeting sub-hourly dispatch requirements.
• Business as usual. Run old fossil units into the ground.

Ultimately, all of these solution sets will be deployed in some combination for all regions affected by large-scale renewable energy penetration.

The advantages bulk energy storage offers are considerable, Makansi went on. Pumped hydroelectric storage (PHS) and compressed air energy storage (CAES) are both commercially available, investible options long on operating experience. They can move from idle to full load in less than 10 minutes; comfortably charge and discharge for two, six and even 12 hours; have no emissions (PHS) or a minimal emissions profile (CAES); and suffer less deterioration in cycle efficiency and emissions degradation than simple-cycle gas turbines or combined-cycle systems.

Most importantly, perhaps, PHS and CAES can function both as load and generation, making them ideal for ancillary services. Dozens of new PHS and CAES plants are being developed nationwide and regulations and policies at the state and federal levels are being shaped so that storage can be included as a viable asset class for grid operations.

Generating companies speak. Michael Roberts, managing director of power asset management and operations for Iberdrola Renewables

Inc, Portland, Ore, the leading wind-energy producer worldwide, noted that his company designed a combined-cycle plant, Klamath Falls, specifically for daily cycling. Grid flexibility in the West is “being used up,” he cautioned.

Although some point to the flexibility of hydroelectric plants for integrating wind energy, Roberts noted that, at least in the Pacific Northwest, they are usually under ecological restrictions to manage fish life.  He also noted that no formal market exists for flexibility, although BPA is headed that way.

While Roberts urged the development of flexible energy products, he conceded that the contractual obligations to meet such products would be “a mess,” the maintenance component of the costs of cycling units is difficult to quantify, and complex computer modeling is necessary that is at once user-friendly to traders, operators, and forecasters. He asked the audience, what is the “surcharge” for the necessary flexibility? Growth in wind power makes life difficult for grid managers, he stressed.

Iberdrola’s observations as an independent generator were contrasted somewhat by those of Stephen Beuning, director of market operations for Xcel Energy, the top wind provider in the nation. He believes that renewable energy to date hasn’t

been required to dispatch, but future systems will be, and that fast intra-hour dispatch will mitigate the balancing-area challenge and provide market signals as well. To do this most effectively, Beuning suggested to utilities with their own balancing authorities in the West to work more on a regional basis. Today, gas turbines and other powerplants must be committed to accommodating wind energy.

As chair of the Western Electric Coordinating Committee’s (WECC) Seams Issues Subcommittee, Beuning was able to offer insights into regional activities. WECC, he noted, has only limited congestion management procedures and only six transmission paths available to manage congestion.

WECC’s “efficient dispatch toolkit” includes an enhanced curtailment calculator for the entire footprint and an energy imbalance market. The RTO is currently evaluating a process called “virtual consolidation” and is expected to complete a benefit/cost analysis by the middle of next year. With wind resources projected to increase beyond 50,000 MW by 2019 in the Western Interconnection, variability impacts must be addressed now.

PNM Resources, according to Jonathan Hawkins, manager of advanced technology and strategy,  plans to solve integration problems at the distribution level, providing a firm, dispatchable renewable resource by adding large scale batteries and smart-grid technology. Beyond 20% renewable energy penetration, community energy storage systems—neighborhood units with the look and feel of those “green” transformer boxes—may be investigated.

The view from grid-side. Echoing a comment made by several presenters, Clyde Loutan, a senior advisor in the California ISO’s Market and Infrastructure Div, said that the West does not have much inertia in its grid, unlike the eastern part of the country. He also mentioned hydro resources, but “what about a bad hydro year?” It bears remembering that a very poor hydro year helped precipitate California’s electricity crisis a decade ago, and that ultimately forced the governor out of office.

Astonishingly, 18,000 MW of thermal generation will be retired or repowered in the next 10 years in California, while 20,000 MW of wind and solar is expected to be added. Currently, the state faces separate challenges balancing wind energy and solar resources. Almost all of the generating resources in the state are only capable of 20-MW/min ramp rates, or less.

In addition to the day-ahead and hour-ahead schedules, the system may need the capability to dispatch units on a five-minute basis, a significant departure from current practice. However, Loutan suggested that, up to a certain point, deviations in supply and load can be “picked up” and managed in frequency regulation—one of several so-called ancillary services. To manage the impacts of the state’s demanding RPS by 2020, CalISO and others are looking at integrating storage into supply scenarios.

Although employed by NRG Texas LLC, Adrian Pieniazak, director of market policy for Ercot, gave an Ercot/IPP perspective on wind

integration. In Texas, upwards of 41,000 MW of wind could be interconnected in the coming years. One of his eye-opening stats: Last August 16,

peak-hour load was 64,805 MW; wind output averaged only 650 MW, from a resource base totaling more than10,000 MW.

Pieniazak started by reminding the audience that FERC has no jurisdiction in Texas. Wind energy is suffering in Texas not only because of curtailments, but because curtailed wind resources are then limited in how fast they are allowed back onto the grid. Ercot now requires new wind turbine facilities to provide their own voltage support; some machines must be retrofitted as well.

Ercot also modified regulation and added more “non-spin” at 30-min intervals but may have to go to a 15-min non-spin regulation product. He noted that Ercot as a whole “hasn’t done well on ancillary services cost allocation.” Pieniazak focused attention on Texas’ Competitive Renewable Energy Zone (CREZ) transmission line build-out. CREZ will help with integration long term, but the first lines won’t be in operation until after 2012.

On the solutions side, Pieniazak believes that newer-model wind turbine/generators can provide frequency control and be placed on AGC just like gas turbines. Nevertheless, the high-wind-week projections for year 2013 look “really scary,” he said.

A trio of speakers from NV Energy—Richard Salgo, director of electric systems control operations; Gary Smith, director of smart technologies; and Dariusz Rekowski, director of generation O&M, gave a “grid operator” perspective on integration issues. Most of the presentation was a well-needed refresher on balancing areas.

A recurring theme was the quality of spinning reserves versus the quantity. Nighttime minimum load in northern Nevada can be as low as 750 MW, which poses operational challenges for conventional generation assets because half that demand, possibly more, is under contract as “must-take” renewable power. This obviously limits the “range of motion” of generating units that can’t be taken offline.

Part of the solution will come from the utility’s Advanced Service Delivery (ASD) program, demand response management anchored by smart meters, and customer “ownership” of their energy usage. But NV Energy’s generating assets still will have to make sacrifices in terms of increased cycling, faster ramp rates, and lower-load operation, which negatively affect performance. Lower efficiency and higher fuel consumption and CO2 emissions are among the impacts. Consequences for NV Energy and its customers will be incrementally higher fossil-plant O&M costs and increased investment in units that will generate fewer megawatt-hours.

Enter storage. Bob Kraft, CEO and president, Energy Storage & Power LLC (ES&P), Bridgewater, NJ, told the audience that his firm is evaluating

CAES systems up to 460 MW in size for greenfield sites, as well as the retrofit of existing F-class turbine plants for this service.

Other features of a modern CAES plant, compared to the pioneering version demonstrated at the McIntosh facility in Andalusia, Ala, include these: three-minute bottoming cycle startup from a warm condition; use of commercially available components, not custom equipment; state-of-the-art combustor technology; and split system with multiple compressors and expanders to add flexibility.

According to Kraft, a “CAES 2” plant can ramp at rates up to 28 MW/sec. Another interesting offering from ES&P is a humid-air turbine, which regains cold-day performance on a hot day and promises a 13% power boost for today’s standard combined-cycle plant at less than $350/kW.

Flex machines. The new capabilities being built into today’s gas turbines was amplified by Bruce Rising, strategic business manager, Siemens Energy. Rising claimed that a Siemens simple-cycle Flex-Plant™ 10 can reach 150 MW in 10 minutes, the 150-MW combined-cycle Flex-Plant™ 30 in 30 minutes. Advanced power diagnostics and an integrated fuel-gas characterization system are features that will enable such plants to better handle deep cycling and dispatch. Rising reiterated the unintended consequence of fast ramping: Reduced efficiency of environmental controls.

A planner’s perspective. Victor Niemeyer, technical executive for EPRI’s Climate Program, connected wind integration to global climate

change issues. He began by saying in the low-carbon future, coal “is toast,” which made even this natural-gas-oriented audience wince. Of course, what he meant was that, long-term, carbon is a factor even without an imminent federal policy goal for carbon. At $100/MWh, he said, wind could displace all of the nation’s coal.

While that may make wind enthusiasts cheer, another observation was more sobering: The idea that wind from one region will compensate for wind in another is not true. Sometimes there is no wind over a broad area. Niemeyer pointed to some modeling and analysis work conducted over a seven-state region (the Dakotas, Minnesota, Iowa, Missouri, Kansas, and Nebraska) which showed that low wind output can persist for extended periods.

Niemeyer concluded with these three points: Adding transmission enables greater utilization of wind (although “lots of line-miles are necessary”), cost of wind delivered to load is much higher than the simple cost of generation, and the “anti-correlation” of wind with load and the need for new interregional transmission “greatly limits” the fraction of coal generation displaced by wind in a de-carbonized future.

Presentations by Thomas Mastronarde, Gemma Power Systems LLC, Glastonbury, Ct, on integrating combined-cycle heat-recovery steam generators with solar thermal, and by Steve Gressler, Structural Integrity Associates Inc, San Jose, Calif, on material considerations for equipment under increased cyclic duress, rounded out the day.

Panel discussion. Some of the more salient points gleaned from the workshop’s two panel discussions:

• In Ercot, municipal utilities with a rate base are the only ones that can build and finance peakers and “flexible resources.”
• Ercot rules forcing wind turbine plants to retrofit reactive power and voltage control are under appeal by the Texas Public Utility Commission.
• Interconnection standards for wind machines were proposed by the CalISO for all non-synchronous units, but were rejected by FERC.
• CAES-based storage has natural reactive-power capabilities.
• ISOs/RTOs have learned a great deal about committing resources to manage wind penetration, but industry participants must get beyond long-term averages because forecasted operations and actual operations can be vastly different.
• Owner/operators need to rethink maintenance strategies when a nominal 650-MW fossil unit is being replaced by, say, a half-dozen generators at smaller facilities, not to mention hundreds of wind generators hanging hundreds of feet in the air.
• The $6-billion cost for CREZ in Texas is being socialized across the Ercot load, but industrial and consumer groups are fighting the policy. California is also considering CREZ-type approaches to add transmission infrastructure that enables wind.