Quantifying Component Degradation due to Flexible Operations

With more hydropower plants being required to operate flexibly, there is concern regarding effects on the equipment. EPRI shares findings from a recent whitepaper on the adverse effects of flexible operations.

For more than 20 years, a variety of influences have combined to require power plants, including hydroelectric units in North America and worldwide, to operate with increasing flexibility.

Flexible operation often involves varying the power output in response to market signals and regional electric grid demands. Some of the adverse effects of flexible operation include increased starting and stopping of the units, operating the units at reduced or maximum power levels, and operating the units in regions of increased cavitation or increased hydraulic instability.

In recent years, the Electric Power Research Institute (EPRI) has conducted research on the challenges of increased operating flexibility for plants across the electric power industry, including studies of the technical issues associated with this trend and the best practices and new technologies to mitigate damage and increase flexibility. A key part of this research has focused on the flexible operation of hydropower plants.

A recently published EPRI report summarizes the current knowledge related to flexible operation of hydroelectric units, including accelerated degradation of components and associated infrastructure. The report summarizes previous research conducted on increased flexible operation in hydroelectric units.

This article highlights the findings of previous research, including the trends and causes for increases in flexible operation and the potential adverse effects on hydro components and systems. It also describes several case studies of industry experiences with flexible operation and discusses potential future research investigations to improve the hydro industry’s adaptation to increases in flexible operation.

The 240-MW Osage hydro project in Missouri is one of several case studies in the report.

Trends and causes of increased flexible operation

A number of factors have created the need for more flexible hydropower systems. Initially, the primary drivers were the rise of electricity markets and the emergence of new products and ancillary services (regulation and frequency response, reactive supply and voltage control, spinning reserve, and supplemental reserve).

Another factor has been the role of hydro units in providing support for fossil and nuclear generating units within non-market power systems with a mix of generators, such as Duke Energy and the Tennessee Valley Authority. New license conditions, environmental operations, and updated optimization and control systems can also change or limit the flexible operation of hydro facilities.

A key driver for increases in flexible power system operation is the rapid and widespread rise in variable energy resources, primarily wind and solar generation, as a result of federal production tax credits, state renewable portfolio standards and state greenhouse gas reduction goals. Figure 1 summarizes some of the factors that affect the flexible operation of hydro plants.

Figure 1 — Complexity of Operational Factors for Hydro Plants

The operational factors that affect the flexible operation of hydro plants are categorized by association with water, the overall facility and the power system.

Adverse effects from flexible operation

The off-design conditions that occur during flexible operating modes can cause adverse effects to the systems and components of hydroelectric units. EPRI has compiled industry experience in a number of areas, including turbines and related components; generators and related components; gates and valves; circuit breakers, switchgear, and transformers; instrumentation and controls; and other components and systems.

For each of these plant areas, the consequences were summarized for six operating zones or transient events, including: start/stop, speed-no-load, low load and intermediate load, near-best efficiency (traditional baseload operation), high load, and load rejection.

A few examples of the likely consequences of these operational modes are:

  • Turbines and related components: More frequent starts/stops increase vibrations and dynamic stresses, reducing the fatigue life of turbines, turbine shafts, wicket gates, headcovers and headcover bolts and increasing the wear of turbine guide bearings, thrust bearings, shear pins, brakes and wicket gate bushings. Figure 2 shows the broad spectrum of loading on a turbine produced by operation in the speed-no-load, lower load, and intermediate load operating zones.
  • Generators and related components: Increased cycling leads to increased vibrations, dynamic stresses and thermal stresses, reducing the fatigue life of rotors, stators, end windings, spider arms and support brackets, increasing wear of generator guide bearings, thrust bearings and generator cooling systems, and increasing the probability of insulation failure.
  • Gates and valves: Low-load and intermediate-load operation increases pressure pulsations, vibrations, and dynamic stresses, potentially reducing the fatigue life of gates and valves, associated studs, bolts, shafts, actuators, penstocks and penstock rivets and increasing wear of gates and valves.
  • Circuit breakers, switchgear and transformers: More frequent starts/stops increase vibrations, dynamic stresses and thermal stresses, reducing the life of circuit breakers, switchgear and transformers. Typically, this equipment is rated for a specified number of starts/stops.
  • Instrumentation and controls: Low-load and intermediate-load operation increases vibrations, potentially reducing the life of instrumentation and controls.

Figure 2 — Strain Gauge Amplitude Spectrum

These strain gauge amplitude spectrum test results show the broad spectrum of loading on a turbine produced by operation in the speed-no-load, lower load, and intermediate load operating zones.

Technical approaches for evaluating adverse effects

A number of approaches have been developed for evaluating the accelerated degradation associated with flexible operation of hydroelectric units. These approaches include deterioration and maintenance modeling, cumulative damage analysis, finite element analysis (FEA) modeling, computational fluid dynamics (CFD) modeling, and fatigue analysis. An aerospace concept, called Design Reference Missions (DRM), allows comparisons of effects at different operating profiles.

Case studies of flexible operation

EPRI compiled four case studies that provide specific experience with flexible operation.

Flexible operation for environmental and market purposes

Ameren Missouri’s eight-unit, 240-MW Osage Hydroelectric Project is located on the Osage River near Lake Ozark, Mo. Because of concerns about downstream water quality, Osage Units 1 through 8 were upgraded in 2002 with aerating turbines using central aeration. In 2008, several units were upgraded with aerating turbines using distributed aeration. These installations resulted in less flexible operation for the plant.

After the Midwest Independent Transmission System Operator (MISO) introduced regional energy markets in 2005, generation from Osage was traded in the MISO market. In January 2009, MISO introduced an ancillary services market. Detailed analyses of Osage’s operation were conducted using unit load data at one-minute time intervals to evaluate the overall plant efficiencies operating in the new market environment. Performance results under the MISO ancillary services market fell short of the optimized performance by an average of 3%, primarily as a result of the practical necessity of maintaining additional units on-line at lower loads to meet anticipated system demand and to avoid excessive unit cycling.

The primary observed impacts from Osage’s aggressive participation in the MISO ancillary services market have been increased repair and replacement of circuit breakers as a result of more frequent starts/stops. In 2013, an agreement between Ameren Missouri and the Missouri Public Service Commission on the fuel adjustment clause reduced the value of the ancillary services revenue to the Osage Project as a cost center. Subsequent Osage operations have included a moderate participation in the ancillary services market in an effort to optimize energy and ancillary services revenues and to reduce O&M expenses for the circuit breakers.

Replacement runner design for flexible operation

The U.S. Bureau of Reclamation’s 2,080-MW Hoover Power Plant includes 17 units. In 2010, Reclamation awarded a contract to upgrade Hoover Unit N8. The design requirements included flexible operation over a head range from 396 ft (120.7 m) to 511 ft (155.7 m) and an operating range from 5% to 100% of full load without cavitation and excessive pressure pulsations. Design requirements also included power and efficiency guarantees at heads of 396 ft (120.7 m), 445 ft (135.6 m) and 511 ft (155.7 m).

To achieve the requirements set out by Reclamation, the equipment manufacturer redesigned the wicket gate and stay vane hydraulic profile and utilized an extended runner band. The extended runner band was particularly important for controlling cavitation over the wide operating range. CFD modeling and finite element models were implemented for stress and fatigue analyses.

By perfecting the blade profile design, engineers were able to increase efficiency, flatten the efficiency curve, and reduce pressure fluctuations from draft tube vortices. The new unit began commercial operation in May 2012.

Extended operation for integration of solar and wind energy

Energias de Portugal (EDP), Portugal’s major electric utility, needs storage capacity, flexibility and a faster response because of the integration of increasing solar and wind generation. To extend the operating range for EDP’s two-unit, 260-MW Alqueva II Pumped Storage Plant, EDP and a hydropower equipment supplier analyzed the plant’s equipment using CFD and FEA modeling, strain measurements on an operating pump-turbine unit, strain measurements on a physical model of the unit, and fatigue analyses.

By limiting the number of hours of operation in the high dynamic stress zone at intermediate loads and by extending the operating range into the relatively low dynamic stress zones below the intermediate load zone and at high loads, a significantly wider operating range was established. The wider operating range increased the power band for the secondary reserve market, providing EDF with additional revenue from the Alqueva II plant.

Assessment of potential adverse effects from more flexible operation

Ontario Power Generation’s Pine Portage generating station is on the Nipigon River east of Thunder Bay, Ontario, Canada. The plant includes four Francis-type generating units with a total capacity of 144 MW.

OPG’s hydropower assets have traditionally been used to generate baseload power. When OPG stopped burning coal in its thermal plants in 2014 to reduce CO2 emissions, nuclear power became a much larger component of the utility’s baseload generating capacity, and hydropower’s traditional role began to change.

The Pine Portage station has shifted from predominantly baseload to load-following or part-load operation because of increased generation from wind and solar sources and because of decreased industrial demand for electricity in Northwest Ontario after the 2008 recession. As a result, Pine Portage has significantly increased the flexibility of its operation, including a wider operational range, more starts and stops, and increased diversion, or spilling, of water through the sluice gates during times of low demand for electricity.

OPG and EPRI developed a pilot project to focus on the changing mission profile for the Pine Portage generating station. The process uses a technical workshop to identify, discuss, and prioritize key technical issues and to define uncertainties, gaps in knowledge and understanding, and potential solutions. Components of particular concern were the turbine runners, shafts, head covers, bearings and generator components.

Additional research

Recommendations for additional EPRI research on this topic include:

  • Work with turbine manufacturers and utilities to define standardized DRMs for flexible operation and to develop appropriate technical specifications of new turbines and pump-turbines for more flexible operation when it is required.
  • Work with turbine manufacturers and utilities to define and use standardized DRMs, condition assessment techniques, and fatigue analyses for existing turbines and pump-turbines that are re-tasked for more flexible operation.
  • Review condition assessment technologies for fossil and nuclear power plants for application to hydroelectric plants.
  • Work with utilities to conduct a comprehensive review of the usefulness and cost-effectiveness of condition monitoring techniques for predicting potential failures of hydropower turbines.
  • Work with manufacturers, utilities and universities to develop advanced condition monitors that incorporate system models, statistical wear data and operational history data.

References

Flexible Operation of Hydropower Plants, EPRI Document No. 3002011185, Electric Power Research Institute (EPRI), Palo Alto, Calif., 2017.

Monette, C., et al, “Cost of Enlarged Operating Zone for an Existing Francis Runner,” Proceedings of 28th IAHR Symposium on Hydraulic Machinery and Systems, International Association for Hydro-Environment Engineering and Research, Beijing, China, 2016.

Megan Nesbitt is senior technical leader of EPRI’s hydropower program.

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