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HRW-Hydro Review Worldwide

Converting to Variable Speed at a Pumped-Storage Plant

Converting to Variable Speed at a Pumped-Storage Plant

As French utility Electricite de France is learning, replacing a traditional pump-turbine unit with a variable speed unit at an existing pumped-storage plant can increase capacity, provide better energy storage and offer faster grid support.

By Jean Marc Henry, Frederic Maurer, Jean-Louis Drommi, and Thierry Sautereau

Variable speed technology offers additional network flexibility to conventional pumped-storage plants by enabling power regulation in pumping mode as well as in generation mode. A variable speed pumped-storage plant is one for which the speed can be varied through a frequency converter. This speed variation allows a change in the discharge/power in pump mode, as with a fixed speed there is only one operating point for a given head. While already used for several years, particularly in Japan, the variable speed finds a new source of development with the fast growth of variable power sources, such as wind and solar. There is a need for better adaptation by storage capacity to compensate for fluctuations.

This case study discusses the benefits associated with retrofitting an existing pumped-storage plant with a variable speed unit, based on turbine manufacturer Alstom Hydro's experience with hydro projects under construction and the experience of French utility Electricite de France (EDF) in the installation and operation of pumped-storage plants.

Why variable speed?

Developing and constructing a new pumped-storage plant requires an adequate site, significant investment and eight to 10 years. A more expedient and cost-effective approach to increasing hydroelectric capacity is to convert existing synchronous units into variable speed machines.

EDF operates an electricity generation fleet with capacity of about 100 GW in France and a total capacity of more than 135 GW worldwide. Among this fleet, 5 GW of capacity comes from pumped-storage plants equipped with synchronous generators. Pumped-storage plants provide storage capacity while keeping the advantage of fast peaking response provided by all hydroelectric facilities. This technology developed significantly with the expansion of nuclear development programs from the 1970s through the 1990s. A key enabler of this development was reversible Francis pump-turbines that allowed large outputs per unit (>200 MW). The nuclear expansion required a storage compensation of large output, mainly on a day/night basis, as the nuclear was not flexible at all, particularly in its early stages. Storage compensation of large output is possible with reversible pump-turbines.

Today, intermittent renewable power generation (such as that provided by wind and solar plants) represents an ever-larger share of the world's power output, but it requires a means of storing the surplus energy so that it can be used during periods of peak demand. Moreover, intermittent renewable energy is not predictable, thus representing a major challenge for grid stability.

Refurbishment of conventional synchronous pump-turbine units, as EDF and Alstom are doing at the 800-MW Revin plant, can increase balancing reserve and improve performance.

Variable speed pumped-storage schemes combine the needs for better energy storage and faster grid support. Variable speed technology can offer additional network flexibility to conventional pumped-storage plants by allowing power/frequency regulation in pumping mode, as well.

For example, converting 50% of the 20 GW of pumped storage installed in the USA would provide additional power balance flexibility, as well as up to 3 GW of frequency regulation capability on the grid during off peak periods. Furthermore, greenhouse gas emissions are reduced because fossil fuel-fired plants are not needed for balancing purposes.

Converting an existing plant to variable speed

Although it is a prime option for providing better energy storage and faster grid support, converting a synchronous unit into a variable speed unit requires special considerations and design studies.

First, a turbine upgrade has to be considered because the power variation in pump mode and the potential speed variation depend on the hydraulic design. Consequently, setting a new hydraulic profile within an existing machine structure requires requalification of the mechanical structure, as well as verification of the hydraulic transients. These constraints must take into account the expected speed variation range as well as the new way of operating the units.

Second, the choice between a synchronous generator with full convertor and a double-fed induction generator with converter in the rotor circuit must be evaluated. The constraints of upgrading the motor-generator into a variable speed induction machine within an existing powerhouse and its effect on the plant must be taken into account. The ability of the civil structure to accommodate the resulting higher stresses must also be dealt with.

Variable speed units lead to higher loads on civil structures. However, modifying the civil works in the plant is not cost-effective. Thus, all existing concrete structures must be checked to ensure they can bear the foundation loads of the stator (loads and torques, under static and dynamic conditions) and thrust bearing load transfer. Ultimately, local reinforcement may be necessary or variable speed machine size must be limited to match civil structure bearable loads.

Hydraulic design

Power regulation in pumping mode mainly relies on the ability of the hydraulic design to adapt to the power/flow variations. Because the older designs are not set to these conditions, an upgrade is recommended to get the most benefit. Upgrading the hydraulic design affects:

— Hydraulic transients considering the existing waterway;

— Integration of the new hydraulic components within existing contours; and

— Cavitation-free operation with the available runner setting. This is one of the main parameters that could affect the pump power range.

As discussed above, to benefit from the upgrade, a new hydraulic design is generally required to provide increased pump-turbine efficiency (up to several percent) due to improved and state-of-the-art design capabilities and to the speed adjustment in turbine mode at partial load.

It is also needed to provide increased power regulation in pumping mode. Such regulation is provided by increased performance in cavitation and turbine/pump power ratio, as highlighted by variable speed hydraulic designs with a large head range (see Table 1)

.Alstom Variable Speed Hydraulic Designs

Electrical design

The excitation frequencies, for example on the head cover, are related to the rotation speed. The requalification of existing parts of the distributor (such as wicket gates and head cover) requires, therefore, consideration of the speed variation, to avoid resonance.

Fully Fed Single Line Diagram

There are two technologies for varying the speed (see Figure 1 and Figure 2). One option is keeping a synchronous motor-generator connected to a full power supply frequency converter (fully-fed motor-generator); the other option is replacing the synchronous motor-generator by a double-fed induction machine (DFIM) connected to a reduced power supply frequency converter on the rotor. In this case, keeping the existing stator may also be considered.

DFIM Fed Single Line Diagram

The first option is most suitable for low outputs (<100 MW per unit), but it also requires an excitation system. For higher outputs, the cost of the frequency converter becomes prohibitive. It is possible to keep the synchronous motor-generator from the original equipment manufacturer, but it is not recommended to re-use the existing motor-generator winding because the frequency distortions and harmonics become more demanding for electrical insulation (fast aging of insulating material).

A DFIM is generally the preferred solution for large unit outputs (>100 MW). Its main advantage is that it requires low-power converters that use only a small fraction of the total output. This means less power loss in the converters, lower global price and a much smaller footprint for the power electronics while delivering the most benefit variable speed can offer.

A fully-fed machine cannot deliver additional power regulation in pumping mode because of the limitations of current pump-turbine technology. Pump power variations are limited by the stability and cavitation characteristics of the pump and not by the frequency range of the power converter. For example, a pump operating range generally has about a 30% power variation, which means a +10% frequency range variation.

The voltage source inverter using IGBT (Insulated-gate bipolar transistor) or IGCT (integrated-gate commutated thyristor) is preferred to a cyclo-converter because it enables rapid response to the grid. Using a voltage source inverter also leads to a smaller machine because there is no need to supply reactive power to a cyclo-converter. In addition, there are no sub-harmonics injections that could generate sub-synchronous resonances.

Alstom uses DFIM technology in all its variable speed pumped-storage projects. DFIM uses the exchange between the wound rotor and frequency converter to provide the speed variation. As a consequence, the stator needs to be oversized in sub-synchronous mode, due to the additional power transiting the rotor.

Keeping the existing stator may, however, be considered if reactive power supply can be reduced. The reactive power is partially provided by the frequency converter. In such a case, the stator winding needs to be compatible with the rotor winding. Alternatively, the stator could be replaced.

In both cases, the main constraint on the DFIM design is to fit the stator and rotor within the motor-generator pit. The pit dimension is a limiting factor to the DFIM maximum output.

The DFIM wound rotor is about 30% heavier than a salient pole synchronous rotor, which impacts the shaft line behavior.

The frequency converter

The frequency converter will lead to additional losses (roughly 3% of the converter power) but much less than a full power frequency converter. This is because the power involved is proportional to the ratio of shifted frequency.

While an additional static frequency converter is often used to raise the speed up to the synchronous speed with fixed speed PSP in pump mode, this speed raising function is achieved by the frequency converter itself on variable speed PSP. While the static frequency converter feeds the stator within a fixed speed PSP, the frequency converter feeds the rotor on DFIM variable speed.

The connection to the rotor will be made through large slip rings housed in a separate cubicle. Given the high current involved, air-cooling and filtration are needed. The environment of the slip rings is air-conditioned to maximize the lifetime of the brushes and to capture all the carbon dust. Special attention is given to the carbon dust vacuuming system to avoid the spread of carbon particles over the unit, which could result in a rotor insulation drop.

Electrical balance of plant

Beyond the motor-generator described, the entire unit's electrical equipment has to be re-engineered. Some equipment may be re-used, while other parts must be replaced, and new equipment must fit within the space limitations of the powerhouse. For example, synchronous rotor excitation devices must be dismantled while stator medium voltage gears could be re-used.

Most of the new equipment that must be installed in the powerhouse is for the DFIM rotor feed. Equipment includes:

— Heavy-duty power tapping on the MV side of the unit's power transformer;

— Short circuit current-limiting reactors;

— MV breaker;

— Harmonic filters;

— Voltage source inverter and transformer;

— Segregated phase bus ducts from voltage source inverter to rotor ring cubicle;

— Rotor over-current and over-voltage protection cubicle; and

— Non-conventional current transformers and voltage transformers for rotor current and voltage measurement at very low frequency.

The largest pieces of equipment required for rotor excitation (voltage source inverter and transformer) require roughly 1,615 square feet of ground space for a unit with pumping capacity of about 30 MW, which might be difficult to find in some underground powerhouses.

On the stator side, additional pieces of equipment need to be installed:

— Isolated phase bus ducts (part of which may be re-used from the existing sync unit);

— Starting/braking short circuit breaker used for the DFIM launching in motor mode and for the re-generative braking sequence;

— Generator circuit breaker: depending upon its condition and rating, a new breaker might be considered; and

— Phase reversal disconnectors, which may be re-used or replaced depending upon condition, ageing and rating.

Last but not least, the unit power transformer has to be checked for replacement, depending on the rating of the new unit and/or special requirements due to the harmonics produced by the DFIM and voltage source inverter. On the unit control side, the unit voltage and speed controls are very closely linked in order to optimize the DFIM and turbine operating point. Hence, from an operator point of view, active and reactive power setpoints are the sole information to be sent to the variable speed generating set control.

Variable speed units must have some of the same important operating features as the synchronous units, such as black start operation, isolated network feeding or line charging capacity. Black start operation without tapping energy for rotor excitation is obtained from a low power feeder that energizes the voltage source inverter enough to build up stator voltage. Isolated network and line charging capacity are no more challenging than with a synchronous machine. Indeed, the power electronic control improves, stabilizing the unit output when operating in an islanded network condition.

Mechanical design

The thrust bearing will be impacted by the new hydraulic design, which may transfer different hydraulic thrust, and by the rotor, which may increase weight. As a result, the existing thrust bearing needs to be rechecked against updated loads.

Several parameters need to be considered in the shaft line calculation: possible increase in the bearing's span, increase of the rotor weight, runaway speed modification and operating speed variation. The most critical feature for shaft line safety is the bending natural frequency. Fulfilling usual margin criteria may impact the overall machine layout.

Increase in thrust load, converter losses and the slip ring filtration system need to be reconsidered — both for the sizing and the routing of the water-cooling system. Special attention must be paid to the water velocity in the existing embedded pipes in order to avoid ageing of the pipes.

Converting a motor-generator to variable speed, either complete or the rotor only, takes time. Specifically, the new wound rotor would need to be assembled on-site. Nevertheless, the rotor and stator will be assembled prior to unit shutdown. Furthermore, given the work to be done to upgrade the hydraulics, the motor-generator replacement is unlikely to have a significant impact on time, taking no longer than it would for standard hydraulic refurbishment.


Converting existing synchronous units into variable speed is an expedient and cost-effective solution to increase power regulation capabilities for plant operators. It also facilitates the integration of intermittent renewable energy generation into the electrical grid. However, some constraints and limitations must be fully assessed before such a conversion may be undertaken. Constraints coming from civil structures or the hydraulic circuit would be the most difficult and most costly to overcome.

EDF and Alstom, based on their respective experience in pumped-storage plant design and operation, have made such an assessment in order to upgrade a 270 MVA existing unit into a 300 MVA variable speed machine.

Jean Marc Henry is a technical integrator and Frederic Maurer is an electrical engineer with Alstom Hydro. Jean-Louis Drommi is an electrical expert and Thierry Sautereau is a mechanical engineer with Electricite de France.

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