Two water and wastewater treatment plants in California have turned to on-site solar energy generation to reduce their considerable electricity costs. But, as Ed Ritchie writes, on-site energy usage needs to be examined, and reduced if possible, to maximize benefits.


Photovoltaic panels installed at the South San Joaquin Irrigation District project
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Water districts are facing tough times across the US. The demand for water continues to rise, and so do the costs to acquire and deliver the valuable commodity. In California, recent droughts have added to the costs of pumping water from deep groundwater tables, and higher time of day peak usage rates have added yet another burden. However, two districts in Northern California found they could offset high utility rates with solar energy.

Both Las Gallinas Valley Sanitary District and South San Joaquin Irrigation District (SSJID) have been hit hard by drought conditions and high utility rates. However, there is plenty of free sunshine, so solar power offered an ideal solution for Las Gallinas’ wastewater treatment facility, and San Joaquin’s water treatment plant.

STAGGERING UTILITY BILLS

The water treatment plant at San Joaquin is a recent addition which was not needed when the district began as a service to agricultural customers in 1909. But today San Joaquin provides 40 million gallons/day (18.2 million litres/day) to local farms and 155,000 residents. The recent growth required the addition of a state-of-the-art membrane filtration water treatment plant, and along with the plant came some staggering utility bills.

‘After the water treatment plant came online in 2005 the electricity for that system was costing about $400,000 per year,’ recalls Don Battles, utility systems director at SSJID. ‘It was a good idea to integrate a solar project on property right next to the plant so we could sell excess into the Pacific Gas and Electric (PG&E) system.’

Selling the excess power made it advantageous for the district to opt for a time-of-use rate schedule with summer peak hour rates averaging about US$0.43 per kilowatt hour. ‘It’s a high rate, but actually works out better for the district because it’s also the rate that PG&E pays us for any excess power we put back on the system,’ says Battles. ‘In good weather during our peak hours we were putting more into the system than we are taking.’ The off-peak rate averages closer to $0.10 per kilowatt hour, and the district should break even on the $400,000 cost on an annual basis. Long-term payback on the capital expenditure is estimated at 15 years, and that includes incentives of $6 million from the California Solar Initiative Program.

The same California programme played a key role in the Las Gallinas Valley Sanitary District’s solar photovoltaic (PV) project. The district’s wastewater treatment facility sits on the shores of San Pablo Bay, and provides services to more than 32,000 residents of Marin County. On an average day, the district pumps roughly 3.56 million gallons (16 million litres) of wastewater through its irrigation system and settling ponds.

The environmental benefits of using solar PV looked attractive to the district’s board members, however, a persuasive financial benefit was the deciding factor. A variety of representatives from solar panel manufacturers submitted attractive proposals to satisfy the district’s financial concerns. Yet, after a review with an independent energy management consultant, district members were surprised to find putting together a PV solar generation project involved more than just buying the panels.

HOW MUCH ENERGY DOES A FACILITY NEED?

Tim Holmes, president of Kenwood Energy is the consultant, and he wasn’t surprised by the results of his analysis. ‘Typically what happens is somebody is interested in solar electricity but they don’t know much about it,’ says Holmes. ‘It’s a hot item so there are a lot of people out there selling it. Salespeople come by offering their version of the information.’

The proposals were designed to offset 100% of the facility’s energy use, but that approach would have ignored opportunities to boost efficiency and reduce the cost of the initial investment. The first step for Holmes was an energy usage audit. A process which typically takes between 30-60 days and is required to qualify for renewable energy rebates from the State of California. ‘We looked at energy efficiency opportunities and reduced the energy requirements by about 40%.’ recalls Holmes. ‘We specified the installation of variable frequency pump drives and switched the time of day that they did their pumping so they could take advantage of lower utility rates.’

On the first phase of the project, the original proposals specified a 140 kW system. Holmes’ analysis brought it down to 92 kW, for a reduction of around 38%. ‘The district was surprised by the amount of energy they were wasting, ‘says Holmes. ‘Solar is very glamorous whereas energy efficiency is viewed as almost at a level of operations and maintenance. I do a lot of energy audits and in this case we cut their use in half for a net savings of $175,000.’

SAN JOAQUIN HITS CALIFORNIA’S 1 MW WALL

The San Joaquin project also went through a process of reduction after analysis, but for different reasons than Las Gallinas. It began with the idea of a 2 MW project, but ended as 1.6 MW, and ultimately designed as two projects. ‘The first is 1176 kW of crystalline PV panels on single axis trackers,’ Battles explains. ‘And we knew that wasn’t going to meet all of our needs.’

Actually, the demand at San Joaquin was large enough to justify a 2 MW project, but according to David Vincent, project developer at Conergy Projects Group, California regulations would not allow it, and the district had to improvise. Based in Denver, Colorado, Conergy designs, manufactures, installs and finances solar PV solutions for commercial and residential customers. ‘Typically, the first thing to look at is the number of large power users and their water treatment facility was pulling 3.5-4 GWh per year so they had a large demand for energy, says Vincent.’

Vincent’s engineers had to split the load between two meters, so the project became a two-phase process with the first phase using 6720 Conergy 175 W modules at 1176 kW, and the second phase using 5760 First Solar 75.5 W modules at 417 kW. The second phase required a whole new set of switchgear, and Conergy had to modify the interconnection. ‘We couldn’t do just a straight interconnection to their main meter box,’ says Vincent. ‘And we had to install quite a bit of different equipment just to get the interconnection approvals. That was both a physical challenge as far as the interconnection was concerned and also a legal challenge to make sure that everything was done right for the net metering rules that apply.’

Both phases are mounted on single axis tracking systems. Conergy estimates a 25-35% performance boost by having the panels follow the sun rather than remain stationary. Vincent notes that it was a challenge to minimize the number of drive motors for the tracking system, in order to reduce long-term maintenance demands. Each of the system’s 2-hp motors drives over 60,000 lb (27 000 kg) of modules and steel to follow the trajectory of the sun. The solution uses a 30-ton (27-tonne) screw jack and counter balance mechanism.

FIXED MOUNT ON A SHIFTING BASE

The system at Las Gallinas doesn’t use tracking, but the location needed for the 2940 Sharp ND-200UI PV panels proved to be difficult. The only choice was near the shores of San Pablo Bay, on a base of man-made bay-fill. Engineers had to address issues involving the distance from the pumping facility, plus muddy unstable ground composition, and environmental impact considerations. At this point, San Rafael, California-based EI Solutions was chosen to supply the panels and coordinate the state’s rebate programme as administered by the area’s utility, PG&E. Linscott Engineering Contractors, also based in San Rafael, handled construction of the panel array and the special foundation to support it.

The shoreline of San Pablo Bay is composed of ‘bay mud’ with a history of residual runoff from the days when gold was mined from the area’s mountains, so it is still settling and unstable. EI Solutions had a civil engineer study the area and instead of using conventional concrete piers planted vertically down to bedrock, the system sits on a concrete foundation. Essentially, it floats on the ground while supporting the array. If there is uneven settling the array remains stable.

The array’s layout accommodates some open space as dictated by an environmental impact report requiring the retention of a wetlands area for wildlife. The district took environmental concerns a step further by burying the new transmission lines from the array to the pumping facility, and removing old towers and lines installed by PG&E.

LONG DISTANCE HIGH VOLTAGE STEP-UP

The buried lines had to cover a mile in distance between the array and the actual plant, and required a unique solution for transmitting the power. Designers employed a step-up transformer that raises the voltage from 482 V to 12,000 V from the source. The power travels at the higher voltage until it reaches the pump site where another transformer returns it to 482 V. ‘The benefit is that higher voltages can be transported with fewer losses,’ explains Holmes. ‘It’s an efficiency solution and there are some losses associated with stepping up and down, but when comparing them to the loss in transmitting the power over a mile we found it had the highest efficiency. And that included factoring in the cost of the transformer equipment.’

After construction of the second phase, the total output was 588 kW, enough to offset 90% of the district’s energy use according to historical data. Holmes considers 90% to be an aggressive ratio because such systems typically peak at 70-80% when designed for wastewater treatment plants. But in this case a number of factors influenced the decision, starting with future expansion plans and ending with California’s net metering rules.


Phase one array at Las Gallinas Valley
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The district had planned to add more treatment capacity to the facility, so the ratio would eventually fall closer to the 70-80% range. Additionally, it was in the district’s best interests to avoid generating more energy than it consumed because the excess would be free energy for the utility. ‘You don’t want to create that scenario because it’s a lost investment where you create value for the utility at your expense,’ says Holmes.

COMPARING CRYSTALlINE TO THIN FILM

Excess energy is an asset at San Joaquin, and the second phase was an opportunity to find the best rate of return between crystalline PV and new thin film products. ‘We were sold on the idea of using thin film as we have some cloudy days during winter and we were told thin film takes advantage of the ultraviolet rays that make it through the atmosphere,’ says Battles. ‘We also have a lot of summer days when temperatures exceed 100°F (38°C) and thin film can utilize heat better than crystalline.’

The district will track performance differences thanks to a monitoring system installed within the DC to AC inverters.

Performance for June 2009 showed about 2-3% more energy from the crystalline panels. But Vincent expects the thin film to catch up as the temperatures go up, and also on hazy or foggy days. ‘We also have issues with dust,’ he adds. ‘When you put a fine layer of dust over a PV panel you’re decreasing the amount of light. This thin film product can deal with what we call ‘soiling’ in the industry, much better than its crystalline counterpart.’

Aside from output, one point was evident without much comparison. Although the thin film modules had a lower price per watt than the crystalline units, the modules have a power capacity of 72.5 W per panel, so they required nearly double the number of modules as compared to the higher capacity 175 W modules in Phase One. The result was more labour costs for installation, and that may ultimately eliminate any savings over the crystalline option. The comparison between the two technologies is an added bonus, but both Vincent and Battles say the project can stand on its own based upon the success on its financial merits.

LAS GALLINAS CONTRACTS FOR PERFORMANCE

For Las Gallinas, the financial merits became a key issue in the vendor’s contracts, according to Al Petrie, the former district manager. Petri notes that beyond the construction complications, much of his concern was focused on the role of EI Solutions.

‘70% of the total cost of the project is in the panels,’ says Petrie. ‘The district went through a selection process with six or seven companies bidding and making presentations. The board wanted to be sure that we had a very good panel since it was the dominant part of the project.’ Petrie defines quality as a good service life with strict performance criteria. In this case, the district’s contract specified that the panels could not degrade more than one quarter of 1 per cent per year in terms of their generation efficiency.’

Further specifications included having all panels tested in advance, and EI Solutions had to put up a $250,000 bond to guarantee performance. Over the course of the first five years EI Solutions must demonstrate the efficiency of the system has not degraded more than than 0.25%. If it does they will have to pay the district for the lost performance and erect additional panels to bring the performance back up to the contract’s levels.

From an annual perspective, that performance is meeting and exceeding the contract’s levels. The installation produces over 1 GWh annually, with cash savings of more than $156,000 in its first year of operation. In fact, Mark Williams, the water district’s current manager, reports the system was producing 100% of the facility’s power in November 2008.

The area’s weather was a contributing factor. Energy use at wastewater treatment plants typically peaks with rainfall, while dry weather and drought have the opposite effect. Usage at Las Gallinas has dropped as much as 30% during dry seasons. Not surprisingly, with below average rainfall, the pumps at Las Gallinas have consumed about 30% less power.

Less rainfall also means more sunshine, another factor that pushed the electricity production from the panels to exceed 100% of the plant’s usage. ‘The situation created more energy than needed but of course next year everything could change,’ says Holmes. ‘In hindsight we would not have done anything different because we could have had a wet year. However, if the facility did not have to expand we would have created a smaller system.’

Ultimately, designing the smallest system with the largest rate of return was the target for each of these projects. Both took advantage of expert energy usage analysis to size their PV systems, and both developed successful strategies to counter the impact of high, peak rate utility charges.


Ed Ritchie writes on energy matters in the US. Email: cospp@pennwell.com

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