The best way to operate small hydro plants economically may be to operate them remotely. Janet Wood heard some experiences of remote operation, and some thoughts on the economics of automation

Small hydro plants are often installed in remote sites, meeting the needs of a discrete community far from grid-based electricity supplies. In such cases there are good arguments for offering members of the community a stake in operating or maintaining the plant.

In other regions, however, many small hydro stations exist as part of the capacity of a large electricity generating company. Those stations have to offer power that is not only reliable but also — and often most important from a utility’s point of view — power that competes on economic grounds with fossil fuelled, large hydro and other alternative forms of generation. For those stations, reducing costs and increasing reliability and availability are of paramount importance.

North American legacy

In North America some utilities operate large tranches of small hydro stations — partly a legacy of legislation intended to introduce alternative, and privately operated, power generators to the industry. In the US, for example, CHI Energy operates some 30 small hydro stations, while in Canada the small hydro division of Ontario Hydro has 26 units.

The question under discussion when representatives of these companies and others met at July’s Hydrovision conference (28-31 July, Reno, US) was how to operate small hydro stations profitably. One solution very often implemented was to reduce the personnel used to operate the plants.

Gordon Brown of Ontario Hydro Small Hydro Division explained that the company aimed to use a single central operator for all 26 of its units — totalling 115MW. The initiative was a result of analysis performed in 1997 to assess how best to prepare this group of plants to operate in a deregulated market. Equally, the units would not retain dedicated maintenance staff.

Instead, maintenance would be carried out by mobile maintenance crews who would visit each plant on a weekly basis to carry out basic tasks. More extensive work would be carried out on a regular basis: the maintenance crews would schedule full maintenance outages on a two-year basis. Along with the new approach to maintenance scheduling there would also be a new emphasis on addressing the root causes of problems, rather than applying an immediate but short-lived ‘band aid’.

Operating units remotely is not a recent innovation: speakers from Niagara Mohawk pointed out that that company’s 72 small hydro units had been operated remotely since 1981. The idea was not universally approved, however: Ron Fernandez of BC Hydro noted that none of BC’s extensive small hydro facilities were operated remotely and suggested that the company was not in a hurry to change its policy. Nevertheless, for delegates remote operation was of obvious interest. Questions from the floor centred on aspects of emergency management. Although time was required to reach the plant in the event of an emergency, the remedy lay in increasing the knowledge of field operators, who should be given information about the type of alarm, so that on arrival they could act quickly.

Getting the basics right

While the potential of remote operation was discussed in one Hydrovision session, in another delegates looked in more detail at the automation that made such new operating strategies possible. Questioners in this session were initially interested in the cost of introducing automatic systems into existing plant, and in the benefits that would accrue from doing so.

In answer Daniel Purzycki, vice president of engineering at North american-hydro, pointed out that automation was a broad term, and while it could encompass complete upgrades, and the possibility of remote operation, it could also mean simply introducing automation on single systems such as water level monitors. The cost benefit analysis would depend not only on the plant but the automation system employed.

John Bogert, vice president, northeast operations at CHI Energy, was more bullish about the possibilities of introducing even simple automation. Consider a plant that had suffered flow violations, he said: introducing automatic water level monitoring would not only remove the possibility of such violations, but would also allow documentation to be produced to demonstrate that the plant complied with regulatory requirements.

New technology

The practicalities of automation were also questioned in this session. For example, how quickly would automation systems become obsolete? Speakers agreed that with such systems the engineer’s traditional aim of producing a system for a lifetime of 15-20 years was no longer viable. Bogert estimated that systems should be considered to be up-to-date for around 7-8 years. However, in a well-designed system much of the auxiliaries should be configured in such a way that the processing unit could be simply replaced, and similarly the programme should be written to allow for upgrades. One problem identified by Bogert was that spare parts became more expensive. He offered a practical solution: obtain parts from another operator who had upgraded to use a newer version.

Despite the questions raised by delegates about automation, the battle for new technology appeared to have been won: a straw poll of delegates revealed that 80- 90% were working at plants that had already introduced automation. The question of remote operation was not so clear cut, as the differing experience of BC Hydro and Ontario Hydro showed. One delegate estimated, however, that his own plant required more than 80 man-hours of operator time per week. In an industry where operating costs are being driven down relentlessly, the on-site small hydro operator may become a rare sight.