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HydroVision 2008 Preview

The HydroVision 2008 Conference and Exhibition convenes in Sacramento, Calif., July 14-18. This event features multiple opportunities to anticipate change, capitalize on opportunity, and shape the future. Here is a sampling of the innovations that await attendees.

The HydroVision 2008 conference and exhibition is the year’s most significant gathering of hydro professionals and practitioners from around the world. Held July 14-18 in Sacramento, Calif., the conference and exhibition offer opportunities to share experiences and discuss potential solutions to today’s most important issues.

The conference program for HydroVision includes ten concurrent tracks where you can learn about the latest innovations from every segment of the industry. The exhibit hall will be an exiting place to learn about the latest technical developments and familiarize yourself with hydro’s newest equipment and services.

HydroVision also features several pre- and post-conference activities, including plant tours, seminars, and professional meetings, as well as networking opportunities such as receptions and a golf tournament.

For a sampling of the kinds of innovations you’ll see at the HydroVision conference, this article features applications of eight of the many products and services that will be on display in the HydroVision exhibit hall:

By using these products and services, project owners saved time and/or money or solved a problem in a new way.

For more detailed information about all conference events and registration, visit the website, www.hcipub.com, or call (1) 816-931-1311 to request a brochure.

Cleaning generators with CO2 blast technology

To clean generator components at two hydro plants in Colorado, Xcel Energy recently used a carbon dioxide (CO2) blast technology offered by Bob Fidler Services, Inc., headquartered in Apple Valley, Calif. Alfred J. Hughes, hydro plant supervisor for Xcel, says he found the technology to be cost effective and provide better cleaning of stators, rotors, slip rings, and brush holders and easier cleanup in a shorter amount of time compared to alternative cleaning methods.

Bob Fidler Services is exhibiting at the HydroVision conference, and can provide details about the technology.

Buildup of oil and debris in the components of generators can restrict the flow of air through the machine, which can lead to overheating problems. Periodically, these components need to be cleaned to remove the buildup.

“Years ago, we used steam to clean the oil and debris out of the generators,” Hughes says, “but getting the generators dry enough to operate sometimes took weeks.” The utility also has used dry cleaning with brushes and rags, as well as solvents. These methods created challenges of time and safety, and never really cleaned completely enough for insulating paint adhesion. The solvents often were toxic, creating hazardous waste and potential safety concerns for workers.

Hughes heard about the technology from another conference attendee at a past HydroVision conference. Soon after, he and Fidler talked about it. In 2007, Public Service Co. of Colorado, an Xcel Energy company, used the technology for cleaning three units at its 8-MW Tacoma hydro plant on the Animas River, 20 miles north of Durango. And, in 2008, the utility used it on the generator at the 3.9-MW Ames plant on the south fork of the San Miguel River, 80 miles south of Montrose. It took one week for the four units at the Tacoma and Ames plants to be cleaned. This compares to four weeks using four or five workers for alternative cleaning methods.

“The results from using the CO2 blast technology are excellent,” Hughes says. “We get a much cleaner generator and the process takes fewer man-hours and is much safer than the methods we’ve previously used.”

CO2 blast technology, also known as dry ice cleaning, is an environmentally friendly process that cuts hazardous waste by 95 percent, Fidler says. “It’s non-abrasive and does not affect the shape of the equipment being cleaned. Dry ice blasting is similar to pressure washing or sandblasting, but adds no waste to what is being blasted.

In preparing to conduct the cleaning, Bob Fidler staff prepares the work site. This involves covering large areas immediately around the equipment to be cleaned with plastic and laying resin paper on the floor to prevent oil being tracked around the plant. The staff then connects hoses and safety straps to the compressor to prevent the hoses from causing an accident if they were to become loose or break. Workers then roll in the dry ice and air compressor to fill air lines with air and begin cleaning.

“CO2 cleaning is a great value when you consider the downtime necessary for other types of cleaning and drying of the generator,” Hughes says. “When you factor in the downtime and the repeated testing to make sure the unit is dry, CO2 cleaning is probably half the cost of other methods.”

Hughes says the cost in one budget year was approximately 10 percent of the annual operations and maintenance budget for the plants, but he anticipates only needing to do the CO2 blast once every five to ten years.


Xcel Energy recently used CO2 blast technology to clean the hydro generator at its 3.9-MW Ames hydro plant in Colorado. This method requires shorter outages and provides easier cleanup than alternative cleaning methods.
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“It’s an excellent cost-benefit,” Hughes says. “Insulation fails much sooner through overheating, so a clean unit with excellent air flow through the generator should last years longer.”

Sealing system reduces leakage around turbine shaft

To reduce water leakage within the turbine-generating unit of its 5-MW Foyers Falls hydro plant, Scottish & Southern Energy PLC in Scotland retrofitted the 12-inch-diameter main shaft with a split-type HydroSele® cartridge seal from James Walker & Co. The seal, which features two elastomer-based rotary sealing elements working back-to-back with flush water introduced between them instead of a face sealing arrangement typically used by mechanical seals, solved the leakage problem.

James Walker & Co. will be in the HydroVision 2008 exhibit hall to share details about its HydroSele® cartridge seal system for use on either Francis or Kaplan units with shaft diameters between 9.8 inches and 29.5 inches.

When the Foyers unit was constructed in 1968, the shaft was outfitted with a pair of internally mounted mechanical seals of the spring-retained segmented carbon ring type, plus an outboard labyrinth system. Over time, sand and peat in the Foyers River caused excessive wear to the seals. In addition, the shaft was becoming eroded and scored around the labyrinth system. Water was spraying out of the seal housing toward the generator. The utility was replacing the carbon seals every 12 months.

By 1996, the utility decided to replace the mechanical seals with the HydroSele system. The innovative feature of the HydroSele® system is the way its two sealing elements operate within their housings in a cartridge. The two elements work back-to-back, with filtered water flushed between them at 30 pounds per square inch above the water pressure at the sealing gland. This ensures that river water, with its abrasive content, does not enter the area between the sealing elements and the shaft.


Seal Reduces Leakage
This split-type HydroSele® cartridge seal from James Walker & Co. was installed on the turbine shaft in Scottish & Southern Energy’s 5-MW Foyers Falls hydro plant to reduce water leakage. The seal features two elastomer-based rotary sealing elements working back-to-back with flush water introduced between them instead of a face sealing arrangement typically used by mechanical seals.
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The cartridge is a bolt-on unit that incorporates the housings for the two sealing elements and the flush area between them. Because the system is modular, each component can be designed and precision manufactured to fit together perfectly around a specific turbine shaft. For example, the complete split-type assembly of outer housing ring, flush ring, inner housing ring, and two sealing elements can be installed without stripping down the housing. This can reduce the amount of time needed for the turbine to be off line during both initial installation and refurbishment. Another benefit is that, once installed, the seal is totally adjustment free. Some systems have operated for ten years without a need for maintenance.

Scottish & Southern chose the HydroSele system, in part, because its modular concept and custom design minimizes installation time. In addition, by installing the seal system, the utility could reduce seal maintenance requirements to intervals greater than five years.

Two James Walker engineers installed the sealing system at Foyers in less than two days without mechanical lifting gear.

The new sealing system reduced leakage to three-quarters of a gallon per hour, thus eliminating the problem of water spraying toward the generator.

In 2004, during an annual maintenance shutdown at the plant, Scottish & Southern replaced two worn sealing elements in the cartridge.

Scottish & Southern’s Douglas Smillie, hydro engineer at Foyers, says the sealing system continues to work satisfactorily, with the plant running constantly 48 weeks a year at at full load speed of 756 revolutions per minute.

Stopping debris in rivers from building up behind dams

Lake Cachuma, the 190,000-acre-foot reservoir formed by Bradbury Dam, sits 25 miles northwest of Santa Barbara, Calif. The lake is one of four reservoirs included in the Cachuma Project, built in 1953 by the U.S. Department of the Interior’s Bureau of Reclamation, which also owns and operates the project. The purpose of the project is to regulate water flow in the Santa Ynez River and its tributaries, especially during the rainy season (typically October to April). In addition, Lake Cachuma is the chief source of water for the area’s historically water-deficient South Coast communities, including Santa Barbara and 38,000 acres of agricultural land.

When wildfires broke out in southern California in September 2007, staff at the Santa Barbara County Public Works Department and Flood Control District began planning ahead. The staff knew that when the rains started in about a month, the scorched debris from the fire would be washed into tributaries that feed the Santa Ynez. Eventually, the debris would wash into the heavy flows in the river.


A Tuffboom barrier installed about 1 mile upstream of Bradbury Dam in southern California trapped debris that had been washed into the Santa Ynez River during heavy rains in the fall of 2007. The barrier prevented the debris from building up behind the dam and blocking water flow through its outlets.
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This debris – ranging from leaves, twigs, and tree trunks to paper, plastic, construction materials, washing machines, and even dead cows – eventually would gather behind Bradbury Dam. District staff were concerned the debris would back up behind the gates of the dam’s spillway. When the gates were lowered, this debris essentially would act as a beaver dam and prevent passage of water through the gates. If water could flow through the gates, the dam operators would not be able to regulate or control flows from the dam. Alternately, if heavy debris was against the gates, when the gates were lowered, this debris could get caught up on the top of the gates so that operators could not close the gates when needed.

The district staff contacted Worthington Products, which supplies Tuffboom barriers for use in managing debris, ensuring watercraft safety, or restricting access to a dam for security reasons. Worthington will display its barrier and boom products in the HydroVision exhibit hall.

“The district contacted us to say the rainy season was coming, and it needed a debris barrier installed upstream of Bradbury Dam within five weeks,” says Paul Meeks, president of Worthington. In response, we supplied nearly 2,000 linear feet of barrier in the form of a boom. The boom, consisting of several sections of galvanized steel logs, was supplied in 10-foot-long sections. Each log section is 16 inches in diameter and weighs 141 pounds. Log sections are connected using high-strength shackle and link hardware. The entire boom line is connected to shoreline anchor points via either cable or chain sized to withstand the operating conditions. The shoreline anchors are large engineered concrete blocks called “deadman anchors.”

The boom traps floating debris, which collects upstream of the boom. The cost for the boom, $145,000, considered an emergency procurement, was paid for with funds from Santa Barbara County and the water district that uses water from Lake Cachuma.

Although most installations like these are placed 300 to 1,000 feet from the dam, this boom was located approximately 1 to 1.5 miles upstream of Bradbury Dam. This location – where a tributary enters the lake – forms a natural choke point where debris gathers. The boom is able to stop floating debris, yet let water continue to flow into the lake.

The boom was installed within 30 days. Shortly thereafter, a massive weather system dumped record rainfall on the area, recalls Rick Tomasini, maintenance superintendent for the district. The rain, as anticipated, washed debris into an estimated 20 percent of the storage area behind the booms. Tomasini says the boom kept virtually all the debris from the fire away from the dam, which prevented the potential blocking of the spillway. This permitted dam operators to continue to safely operate the dam during these storm events. It also allows the debris removal to occur in a remote location away from the dam. In this case, there was not enough debris to warrant cost of removal, and the debris booms will be left in place year round.

Adding digital electronics to an analog static excitation system

The 104.5-MW Carmen plant, on the McKenzie River in Oregon, featured an analog static excitation system. Project owners and operator Eugene Water and Electric Board (EWEB) installed the system in 1992. The system, supplied by Basler Electric, included three cabinets containing the potential power transformer, control section, and half-wave silicon-controlled rectifier (SCR)-diode bridge. The system offered three modes, which were controlled via a series of relays and set points established using a motor-operated controller.

With the analog system, EWEB was unable to sustain the operation of the plant’s two units at their near nameplate ratings without severely affecting the performance of the system’s voltage regulator. After investigating solutions to this problem, EWEB determined that a change to the excitation system, which would include the addition of a power system stabilizer, was needed.

However, not all parts of the excitation system needed to be replaced. Both the existing bridge and the potential power transformer were very reliable. With proper care, the utility believed they could operate effectively for many more years. Thus, EWEB decided to retain these components and replace only the analog control section.

EWEB contracted with Basler to replace the analog electronics. New devices to be installed included Basler’s DECS-400 digital controller, a firing circuit to control the bridge, a sequence chassis for auxiliary relays, and new doors for the three cabinets. The DECS-400 comprises a voltage regulator, manual control, power system stabilizer, excitation limiter, and autotracking capability to provide “bumpless” transfer between operating modes.

The alternating current (AC) field breaker, field flash contactor and resistor, half-wave bridge, and potential power transformer would be retained. In addition, most of the terminal blocks that interface to external cabinets would remain, saving rewiring costs.


Cost-Effective Excitation Upgrade
By adding new doors containing digital equipment to an existing analog excitation system cabinet, the Eugene Water and Electric Board in Oregon reduced the cost of an excitation system upgrade at its 104-MW Carmen plant by 40 percent.
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The cost of refitting just the controls and cabinet door for each unit was about 60 percent of the cost to completely replace the cabinet and bridge. The installation effort involved in retrofitting the existing cabinet versus completely replacing the cabinet was about equal. Demolition of the first cabinet required less than two days. Interwiring of the new panels on the cabinet doors took about three days.

Before commissioning the new excitation electronics, Basler performed a series of tests to verify the equipment performed properly using the existing bridge. The tests showed improved operating performance. Since the system was commissioned, the two generators have operated at peak capacity without exhibiting power system instability. For EWEB, this means reliable performance and the ability to operate at the unit’s highest output capacity.

Based on this experience, EWEB plans to retrofit additional units in 2008. Basler will be on hand in the HydroVision exhibit hall, displaying, among other products, digital excitation systems.

Modernizing annunciation systems

In 2004, as part of an ongoing modernization, design and operation staff at the U.S. Army Corps of Engineers’ 43-MW hydro plant at the Albeni Falls Dam decided to upgrade the existing annunciation system. The system alerts operators and maintenance staff to changes in plant operating conditions.

The hydro plant on the Pend Oreille River, about 60 miles northeast of Spokane, Wash., in the Idaho panhandle, generates enough electricity for 15,000 homes. The Bonneville Power Administration markets this electricity to customers primarily in the Pacific Northwest.


The U.S. Army Corps of Engineers’ 43-MW Albeni Falls hydro plant on the Pend Oreille River in Idaho features a new annunciation system for alerting operators and maintenance staff to changes in plant operating conditions.
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For the modernization, design and operation staff identified requirements for the new system. It had to be flexible and expandable to allow easy addition of new points and allow for intelligent grouping of alarm points by function (e.g., bearing temperatures) and by generating unit. The approach to install, as well as modify and add to the system, should be quick and easy. The components should be low cost and commercially available now and in the future. And the system should allow remote viewing.

Particularly because of its expandability and compatibility with other systems in the Albeni Falls plant, the staff chose an annunciation system consisting of three commercial, off-the-shelf components: a real-time controller and embedded Web server from SoftPLC, a SNAP IO from Opto-22, and SoftPanel Annunciator software from ACSI.

The real-time controller and Web server is one of hundreds of SoftPLC programmable logic controllers (PLCs) the Corps uses to control hydro operations and power production in the Pacific Northwest. The Corps began installing equipment manufactured by SoftPLC, headquartered in Spicewood, Texas, in the late 1990s and continues with new installations today. SoftPLC products are “open architecture,” which means they can be easily adapted to work with products from other vendors. SoftPLC is exhibiting at the HydroVision 2008 conference.

The Opto-22 SNAP IO component includes analog, digital, and serial communication modules.

The SoftPanel Annunciator software turns a personal computer into an annunciation viewer. Multiple computers can be added at any time to increase usability. The computers can be located anywhere, including remote sites. Each viewer has the ability to acknowledge and clear system alarms. Albeni Falls currently has more than 200 points wired into eight Opto-22 SNAP racks with three SoftPanel viewers.

“Our maintenance personnel are very comfortable with the SoftPLC platform and Snap Opto,” says Joseph L. Summers, operations project manager. “We benefit from reduced maintenance costs, and we have spares available from other systems.”

The system also offers a fast, easy, Windows-based configuration tool. Web-based technologies in the SoftPLC controller enable SoftPanel annunciation software to be used at any location. SoftPanel software distribution is enabled from the SoftPLC controller via a Web browser to any SoftPanel viewer. Its built-in firewall capability allows secure communication.

The system is easy to maintain, because all configuration is done via the software that automatically updates all SoftPanel viewers. In addition, the system is scalable from small to large applications, and the same user interface and training can be used for all control needs in the facility. Hundreds of points can be configured and IO can be located at the remote site to lower installation costs. Each SoftPanel window can have multiple inputs associated with it. The tabbed viewing for annunciation points allows for hundreds of annunciation points per viewer while still allowing for readable text on each of the windows.


Along the Sava River in Slovenia, Holding Slovenske Elektrarne (HSE) is developing five run-of-river hydro plants. The company is using biodegradable oil at these facilities. Accidental discharge of biodegradable lubricants into the river would result in a far less consequential loss than a discharge of mineral-based lubricants.
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The Corps can add redundant viewers at any time, a feature that works well for displaying annunciation system data from a remote site. And, traditional annunciation outputs can still be wired to other systems or connected to existing annunciation displays.

The SoftPanel systems were installed in 2006. “The system is functioning as anticipated with no failures to date,” Summers says. “We would purchase the system again.”

Using biodegradable lubricants

The 33-MW Boötanj plant, which began operation in May 2006, is the first hydro facility in Slovenia to use environmentally compatible hydraulic oil. The plant, in southeastern Slovenia about 100 kilometers east from the capital Ljubljana, uses a biodegradable lubricant supplied by Panolin AG in the hydraulic system of five radial gates.

Panolin, headquartered in Switzerland, is exhibiting at the HydroVision 2008 conference.

Once part of Yugoslavia in Central Europe, the Republic of Slovenia became an independent state in 1991 and joined the European Union (EU) in 2004. Hydroelectric resources play an important role in providing power to the country. Holding Slovenske Elektrarne (HSE), headquartered in Ljubljana, Slovenia, is Slovenia`s leading power provider.

HSE subsidiary HSE Invest, an engineering company, is constructing the five-powerhouse, 187-MW Lower Sava River Hydro Power Project. The project, with an expected annual production of 720,000 megawatt-hours, will meet about 6 percent of Slovenia’s annual power needs. The Boötanj plant is the first plant in the Lower Sava group to be developed.

At Boötanj, HSE personnel considered the possibility of using biodegradable oil in the turbines in addition to the biodegradable oil for the radial gates’ hydraulic system, but the timing was wrong. Work on the plant was too advanced to use the biodegradable oil in all three turbines. ‘’We decided the use of only one type of oil for all three turbines would mean fewer problems for maintenance,’’ says Sandi Ritlop, HSE project manager. ‘’That way, you can have only one package of tools and less oil in spare quantity.’’

However, HSE is incorporating the use of biodegradable oil in both the hydraulic systems and the turbines at the next two plants in the Lower Sava River Hydro Power Project: 42.5-MW Blanca, scheduled to begin operation in November 2008; and 39.5-MW Kröko, due for completion in 2012.

“Because of ecological reasons, we prescribe use of biodegradable oil in tender demands. We strongly believe that the environmental awareness of the hydropower industry is fundamental to mankind, and we build hydropower plants to operate for 50, and more, years,” Ritlop says.

“There are many experiences with using this kind of oil, and we checked on some reference facilities, including Tiwag’s 31.5-MW Langkampfen hydro plant in Austria, which was one of the first hydro plants in Europe to use biodegradable lubricants, “ Ritlop continues. “We also shared experience with operating and maintenance staff at Austria’s 16-MW Bischofshofen and 18-MW Kreuzbergmaut plants before we decided to use biodegradable oils.”

The choice of biodegradable oil is in keeping with HSE’s environmental commitment. According to its Internet site, HSE is committed to upholding international quality standards and the principles of sustainable stewardship of natural resources and environmental management. “HSE endorses safe and environment-friendly power generation in all its facilities,” according to the site.

Accidental discharge of biodegradable lubricants into a river would result in a far less consequential loss than a discharge of mineral-based lubricants. Unlike other biodegradable oils that are based on vegetable oil, the oil HSE uses at Boötanj, and plans to use at the other Lower Sava plants, is a saturated synthetic-ester based product supplied by Panolin AG, of Zurich, Switzerland. Synthetic esters are organic compounds made from the reaction of acids and alcohols and can also come from renewable resources. They have a high vaporization point, provide a strong lubricating film, disperse oil deposits, and are highly biodegradable.

Ritlop appreciates the relationship of the cost to the benefits. “The cost of biodegradable oils is rather high, compared to mineral oils,” Ritlop says, “but we believe that, in new construction and during the bid period, these costs are much lower than changing the complete system anytime later.”

Adding hydro to a water delivery system

When the San Diego County Water Authority began a capital improvement program in 1989 to improve its water delivery system, officials decided to add a 4.5-MW hydro plant. The decision was based on a feasibility study by Black & Veatch, a Kansas City, Mo.,-based engineering, consulting, and construction company, which showed that a small hydro plant could be installed to recover available head in the water transmission system and to act as a redundant control device. The plant, named Rancho Peñ asquitos, began operation in 2007. Development of the plant cost $21 million.


Adding Hydro to Water Delivery System
A single 4.5-MW Francis turbine at the Rancho Peñ asquitos Pressure Control and Hydroelectric Facility in San Diego, Calif., uses available hydraulic pressure from a water supply system to generate enough electricity to meet the annual power demands of approximately 5,000 homes. (Photo by Mike Wallace, used with permission of the San Diego County Water Authority)
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In designing the plant, Black & Veatch engineers faced a number of challenges, including preparing accurate estimates of generator output for a variable flow situation and identifying and complying with operational and environmental permit requirements. The Black & Veatch team also worked with the community to maximize acceptance of the facility, which aesthetically blends into the surrounding residential and commercial area.

The Water Authority is a public agency – working through 24 member agencies – that serves the San Diego region as a wholesale supplier of water from the Colorado River and from northern California. The authority’s water delivery system consists of approximately 270 miles of large diameter pipelines in two aqueducts located between major seismic faults. The Water Authority uses the pipeline to import 320,000 acre-feet of untreated water annually, storing it in reservoirs throughout San Diego County including the Olivenhain and San Vicente reservoirs.

The Rancho Peñ asquitos hydro facility pressurizes a 22-mile-long section of the 108-inch-diameter Pipeline 5 between San Marcos, Calif., and Mira Mesa, Calif. Pipeline 5 is one of three large diameter pipelines within the Second San Diego Aqueduct. The Rancho Peñ asquitos facility controls water pressure and flow within the pipeline based on demand for water and the water level in the upstream reservoir. Its operating requirements cover an anticipated flow range of between 60 cubic feet per second (cfs) and 620 cfs under both normal and emergency scenarios.

Designers specified a single horizontal Francis turbine to take advantage of the 306-pound-per-square-inch hydraulic pressure. This specification allows for power generation under most operating conditions. A state-of-the-art control system permits a smooth and coordinated operation of the turbine-generator and the turbine bypass control valves. The bulk of the generating equipment was provided by VA Tech as a subcontractor to general contractor Archer Western. VA Tech also provided installation, start-up, and testing guidance to the general contractor.

Officials expect the plant to generate enough electricity to meet the annual needs of approximately 5,000 homes. The Water Authority sells the electricity to the San Diego Gas and Electric Company under a ten-year power purchase agreement, helping the local utility meet a mandate of providing 20 percent of its retail electricity sales from renewable resources. “The estimated $1.3 million to $1.6 million in energy sales will pay off the hydro plant in about seven to eight years and will help offset the Authority’s operating expenses,” said Mike Wallace, who managed construction of the project for the Water Authority. “The success of this project has us looking at similar hydroelectric generation opportunities as we expand and upgrade our aqueduct system.”

The San Diego Water Authority and Black & Veatch received recognition for their work in designing, engineering, and constructing the Rancho Peñ asquitos Pressure Control and Hydroelectric Facility. The American Public Works Association’s San Diego Section gave the project its Outstanding Project Award for 2006, the American Society of Civil Engineers’ San Diego section and region 9 named the project the 2007 Outstanding Water Project of the Year, and the National Hydropower Association named San Diego County Water Authority an Outstanding Steward of America’s Waters in 2008 in recognition of development of the project. These awards not only recognize how the Rancho Peñ asquitos facility improves aqueduct system operations and reliability, but embraces the Water Authority’s adopted energy strategy to provide both cost-effective and environmentally friendly renewable energy projects, Wallace says.

Black & Veatch will be in the HydroVision exhibit hall to share details about designing and engineering hydro plants to be added to water supply systems.

Quantifying fish passage

The community of South Indian Lake depends in a large part on the commercial fishery in Southern Indian Lake, 500 miles north of Winnepeg, Manitoba, Canada. At the outlet of the lake, on the Churchill River, is an unmanned river control structure. The structure, named Missi Falls, is owned and operated by Manitoba Hydro. The Missi Falls structure is part of the Churchill River Diversion, built in the 1970s to divert water from theChurchill Riversystem into the lower Nelson River system. Along the Nelson River, Manitoba Hydro owns and operates hydro generation facilities with a total capacity of more than 3,500 MW.

Missi Falls has no provision for upstream fish passage. “Commercial fishers in the South Indian Lake community were concerned about how many fish, particularly whitefish, move downstream through the Missi Fallsandare unable to return to the lake,” says Shelley Matkowski, senior environmental specialist for Manitoba Hydro.

Consequently, says Matkowski, the South Indian Lake EnvironmentalSteering Committee, which addresses local environmental concerns and consists of representatives from the community of South Indian Lake, Manitoba Hydro, Manitoba Water Stewardship Department, and Fisheries and Oceans Canada, sought to answer the question: “How many fish are leaving the lake through the structure?”


Sonar Detects Fish Movement
To collect data about fish passage at Manitoba Hydro’s Missi Falls river control structure on the Churchill River in Canada, researchers installed transducers. These transducers, supplied by BioSonics, Inc., send sonar signals through the water to detect fish movements.
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The committee needed a way to sample and record fish movements in the approach channel on a continuous basis to document day/night and day-to-day variation at the Missi Falls facility. The goal was to estimate numbers of fish moving out of the lake and to get an idea of which species were moving out. Because the facility is in a remote location – two hours by air from the nearest float plane base with communications limited to satellite links for telephone and Internet access – monitoring fish movement there over an extended period of time presented some challenges. In addition, the data collected would be restricted to specific sampling periods and disallow the desired continuous observation.

Traditional methods of data collection like video sampling and net sampling would not yield the desired information. Because of the need for lights, video sampling could influence fish behavior. In addition, with either method, continuous sampling would be impossible. Furthermore, net sampling can be size biased, and it provides no behavior information.

Another sampling method could have been to tag a sub-sample of fish and monitor movement or passage using those tags. “The tagging method would have been very expensive and time consuming, requiring much more manpower for equipment setup, tagging the fish, and on-site monitoring,” says Bob McClure, director of marketing and sales for BioSonics, Inc., of Seattle, Wash., a consulting, engineering, and manufacturing firm that specializes in applying hydroacoustics to monitor and assess aquatic biological resources. BioSonics is exhibiting at HydroVision.

The committee hired aquatic environment specialists North/South Consultants, Inc. of Winnipeg, Manitoba, Canada, who subcontracted the hydroacoustic monitoring from BioSonics to assist in data collection.

“We chose the acoustic monitoring system for its ability toestimate how many fishmoved downstream in the channel and how many movedback upstream before reaching the control structure,” Matkowski says.“The difference would tell us iffish were moving out of the channelvia the control structure.”

The hydroacoustic method offered several advantages, according to McClure:

The only shortcoming is the inability of acoustics to differentiate species, which must be established by net-captured samples. (At Missi Falls, North/ South Consultants conducted net studies.)

“The cost of deploying and retrieving an automated hydroacoustic system and the analysis of the resultant data is dramatically less than deploying a field team, supporting them in the field for a month, tagging and tracking fish, netting fish, and analyzing the resulting data – if that would have been possible at all,” McClure says. “The important consideration here was: could these questions have been answered any other way?”

McClure adds that traditional fish sampling methods will always be an essential component of understanding abundance, distribution, size, species, and behavior. However, he says, “traditional sampling techniques make instantaneous measures of habitat components and provide only a brief glimpse of the highly dynamic biological variables. Fish are always moving into and out of an area. Different sizes interact and behave differently and respond differently to changes (such as flow). These changes can best be measured and analyzed from continuous data, such as that available using hydroacoustics.”

BioSonics personnel assembled a SONAR-based autonomous hydroacoustic system, which included one BioSonics DT-X Digital Scientific Echosounder and two 200-kiloHertz split beam digital transducers. BioSonics staff worked with Manitoba Hydro and North/ South Consultants staff to install the system. After arriving by float plane, they installed the equipment along the sidewalls of the approach channel, set the transducers to monitor the passage of individual fish, and configured the system to operate autonomously and collect data over several weeks without human intervention. They also tested and calibrated the installation. They mounted the equipment on a long pole that was thenplaced in the water and anchored to the shore.These transducers were connected by wires to a computer system at the control structurewhere the data was recorded.

“The original plan was to begin sampling in June,” McClure says. “However, during the initial installation, a lightning strike severely damaged the equipment.” This delayed the start of data collection until mid-August. Unattended data collection continued until the first week of October for a total of 695 hours of acoustic data collected over 29 days.

The study documented 70,000 fish movements of a variety of species, including lake whitefish, northern pike,cisco, burbot, white sucker, and longnose sucker,in theapproach channeltothe control structure.North/South Consultants investigated the species composition using concurrent periodic gill nettingnear the hydroacoustics monitoring site.

“Since the 2007study recorded fish movements for such a short time, which is not long enough to come to any conclusions, we arecontinuing the study in spring 2008,” Matkowski says.“Ideally we would like to conduct the study duringlow, medium, and highflow years to see if there are any differences in fish movements at different flows.The technology looks promising and may be useful in studying fish movements at some of our generating stations.&rdquo.


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