Throwback to Plans for Hydro in the Pacific Northwest

Bonneville Lock and Dam, owned by the Portland District of the U.S. Army Corps of Engineers, is on the Columbia River about 40 miles east of Portland, Ore.

The Pacific Northwest of the U.S. is unique in that it contains a high concentration of hydroelectric power projects, more than many other regions of the country. This article features a compilation of some of the information previously published on this region, which can provide valuable insight for owners of hydro projects throughout North America.

By Gregory B. Poindexter

The following compilation is a brief review containing some of the stories that came out of a U.S. region in which hydroelectric generation and related issues are paramount to both social and economic life. The full and complete text of each of these stories is available on, at the link provided.

Unique solutions allow for successful rehabilitation at Bonneville

Rehabilitation of the 10 turbine-generating units in Powerhouse 1 at the 1,076-MW Bonneville Dam project involved unique constraints and challenges. The U.S. Army Corps of Engineers partnered with contractor Voith Hydro to design solutions to these challenges that allowed for successful, cost-effective completion of the rehabilitation.

The collaboration between the Corps and Voith Hydro proved to be the most effective tool in overcoming many difficult challenges during rehab of the Bonneville Dam project. The rehabilitation was completed in July 2010. Total cost was US$155 million over a 14-year period.

Bonneville Lock and Dam features a 10-unit hydro powerhouse, a deep-draft navigation lock, two adult fish ladders, a juvenile fish bypass system, and a spillway. In the fall of 1937, President Franklin D. Roosevelt dedicated the first two generating units, each with a capacity of 54 MW. The Corps installed eight additional units by 1943.

Today, Bonneville Lock and Dam features:

  • Two powerhouses containing 20 Kaplan turbines with a total capacity of 1,076 MW;
  • Four adult fish ladders rising 60 feet;
  • Two independent juvenile fish bypass systems;
  • An 18-bay concrete gravity spillway that can discharge 1.8 million cubic feet per second;
  • A shallow-draft lock; and
  • A significant recreation and visitors program.

In 1992, Congress, through the National Energy Policy Act, authorized the secretaries of the Army and Interior to accept funding provided directly from power marketing agency Bonneville Power Administration, in lieu of annual Congressional appropriations. As a result, funding received from BPA was directly applied toward the operations, maintenance, and capital programs at the federal facilities within the Federal Columbia River Power System (FCRPS).

More than 70 years have passed since Bonneville Lock and Dam was dedicated in 1937. During this time, the power-train infrastructure underwent numerous additions and modifications. In 1994, Voith Hydro began a comprehensive rehabilitation and modernization of the aging 518-MW Powerhouse 1. The rehabilitation task — including minimizing electrical and mechanical anomalies created by past construction efforts — proved daunting, especially considering the added constraints of a facility steeped with environmental concerns.

Voith Hydro offered the Corps a comprehensive project solution, with worldwide resources. This — coupled with Voith Hydro’s skill in optimized project planning and execution — assured the Corps a high level of quality.

Voith Hydro also offered performance-based total solutions to ensure technical and financial success. By single-sourcing with Voith Hydro, the Corps eliminated the time-consuming and typically inefficient management of multiple suppliers and shortened the project schedule.

Together, Voith Hydro and the Corps’ quality assurance and construction representatives completed a major rehabilitation and modernization of the Bonneville Lock and Dam First Powerhouse. In July 2010, rehabilitation of the last of the 10 units was complete.

While the rehabilitation assured the continued dependability of the power-train equipment, the modernization effort optimized the use of water and helped to meet emerging reliability compliance regulations. The scope of work included the design, manufacture, installation, testing, and commissioning of the following components of the 10 main generating units:

  • Fish-friendly 280-inch-diameter adjustable Kaplan runner;
  • New fish-friendly (minimal gap design) bottom ring and discharge ring;
  • Completely restacked and rewound stators;
  • Refurbished wicket gate and blade operating mechanisms;
  • Refurbished main shaft bearing systems;
  • Addition of environmentally friendly self-lubricated wicket gate mechanism bearings; and
  • Refurbishment and testing of the existing generator rotor.


Overcoming machining challenges at Wells project

Machining work performed in this region has universal appeal. IPS Portland worked on an extended project with Toshiba, which involved machining brake rings and hydro shafts for a 75-MW generator at Douglas County Public Utility District’s Wells project on the Columbia River in Washington.

Dick Bloomquist, IPS Portland’s machine shop manager, said the original equipment manufacturer (OEM) was looking for qualified, experienced machining services. Bloomquist said the work requested is the kind the machine shop performs on a daily basis.

“The turbine shafts weigh 76,000 pounds and have an overall length of 167 inches with a 42-inch seal fit,” he said. “The shafts have 71-inch flanges at both ends, so we had to include splitting the rings in our job scope.”

IPS Portland technicians machined the old sleeves off the shafts, manufactured new sleeves, then split and welded them into place. Tolerances, according to Bloomquist, were less than 0.002 (two one-thousandths) of an inch.

IPS started with brake rings and shafts. In short order, it was machining the flange runners and removing old pins and bolts. Technicians built a blast booth in the shop to sandblast the flange faces before painting. They also machined and polished bearing fits and cleaned, detailed, and re-cut flange faces.

“By the time we finished, we had restored the shafts and rings to OEM spec, with everything documented and validated,” Bloomquist said.


Reintroducing anadromous fish in Oregon’s North Umpqua River

Reflecting the important regional focus on fish passage, as reported in 2010, PacifiCorp Energy was reintroducing chinook salmon and steelhead to a 6-mile stretch of the North Umpqua River above Soda Springs Dam by 2012.

Anadromous fish were cut off from this reach of the river when the dam was built in the 1950s to impound water for a hydroelectric project.

PacifiCorp was building upstream and downstream fish passage facilities at the dam, enhancing fish habitat in the river, and monitoring predation levels to document the long-term effectiveness of this effort. Construction of the $60 million project began in June 2010. Todd Construction was awarded the construction services contract and Mackay & Sposito Inc. received the construction management contract.

PacifiCorp’s North Umpqua Hydroelectric Project consists of eight diversion dams and associated hydroelectric facilities with a total capacity of 185 MW. These dams and power plants were built between 1948 and 1956, about 60 miles upstream of Roseburg, Ore., on land owned by the U.S. Department of Agriculture’s Forest Service.

PacifiCorp operates the project in a “peaking” mode, storing and releasing water for generation at strategic times during the day to meet peak energy demands. Soda Springs Dam, the project’s lowermost development on the North Umpqua, serves as a re-regulating facility, smoothing out bulges of water and providing a more natural hydrograph downstream, including the 34 miles immediately below the project designated in 1988 as a Wild and Scenic River.

This re-regulating function of Soda Springs Dam also ensures consistent habitat and dependable spawning conditions for fish species highly valued by anglers.

The North Umpqua project’s original 50-year operating license, issued by the Federal Power Commission, expired in 1997. Five years prior to this expiration date, PacifiCorp began the process of applying for a new operating license, as required under the Federal Power Act.


Snoqualmie Falls Plant No. 2: Restoring a renewable resource

Puget Sound Energy’s (PSE) 44.4-MW Snoqualmie Falls Hydroelectric Project, about 30 miles east of Seattle in the foothills of the Cascade Range, features two powerhouses. Plant 1 began operating in 1898 and was inducted into the Hydro Hall of Fame in 1998. Plant 2, about a quarter-mile downstream from Plant 1, began operating in 1910.

Both Snoqualmie Falls plants have undergone major upgrades to their aged infrastructure.

In the 1890s, civil engineer Charles Baker contemplated harnessing the energy at Snoqualmie Falls to provide electricity to nearby uses. But as transmission technology advanced, he refined his plan to include markets in the growing Puget Sound cities of Seattle and Tacoma.

Baker convinced his father, Chicago businessman William T. Baker, to bankroll the venture. The son’s plan, never before accomplished, was to build the plant completely underground so as to protect its equipment from the wet winters and the near-constant spray of the falls.

Construction of Plant 1 at Snoqualmie Falls began in April 1898. This plant contained four Pelton turbines and generated electricity in late 1898. Commercial power production began on July 31, 1899. The plant’s capacity was 6 MW, transmitted at 32,000 volts to Seattle, Tacoma, Everett, and small towns in between.

Baker always anticipated adding a second plant at the site but lost ownership of the Snoqualmie Falls facility in 1903.

The chief rival of Baker’s Snoqualmie Falls Power Co. was Seattle Electric Co., formed in 1900 by engineering consultants Charles A. Stone and Edwin S. Webster. Before long, Stone and Webster would own the Snoqualmie Falls project.

But first, in 1905, the newly formed Seattle-Tacoma Power Co. (which evolved out of Baker’s holdings after his departure) added a fifth Plant 1 unit, with a Francis turbine. This addition increased capacity of the plant by 5 MW.

A few years later, the company sought the most practical and efficient way to further increase power output at Snoqualmie Falls. The preferred recommendation out of four options called for a new plant down river from the falls, providing the following advantages:

  • Ability to use the total available head;
  • No risk of damaging existing machinery (from expanding the subterranean powerhouse);
  • No construction delay waiting for completion of a new penstock shaft; and
  • Ability to accommodate future enlargement.

This expansion also included installation of a second penstock with a larger capacity than the original 1910 penstock.With its added turbine, the expanded Plant 2 had a capacity that doubled that of the five older Plant 1 units. At this point, the combined total capacity of both plants was 44.4 MW.


The Dalles Dam, a safer place for salmon

A new spillwall at The Dalles Dam on the Columbia River is expected to improve survival rates for juvenile salmon by 4%. The project, completed in March 2010, may help the owner of the 1,800-MW hydro project meet or exceed federal standards for salmon survival.

It is a hulking mass of concrete, built to perform a delicate task. It took 17 months and more than $45 million to build. It is 830 feet long and more than 40 feet tall.

More than 1,000 truckloads of high-quality concrete were used to build the large spillwall, the latest improvement at The Dalles Dam on the Columbia River.

The spillwall is designed to steer young salmon to a safer part of the river, away from ambushing predatory fish and birds.

“The wall appears to be doing what we anticipated it would do,” said Gary Fredricks, a fisheries biologist with the National Oceanic and Atmospheric Administration. “The flow is doing what we expected.”

The structure could help The Dalles Dam, overseen by the U.S. Army Corps of Engineers, meet or exceed salmon survival goals established by a federal plan, known as a Biological Opinion, for protecting salmon and steelhead listed under the Endangered Species Act.

Shaped like a giant hockey stick, the spillwall creates an escape route for endangered juvenile salmon by guiding them to the deepest, fastest, and safest part of the river downstream from the dam.

About 80% of migrating juvenile salmon pass through the dam’s spillway. The rest go through the turbines or trash sluiceway.

Before the new spillwall was built, the spillway’s fast-flowing waters would propel young salmon toward the shallows, where they were easy prey for smallmouth bass and other predatory fish. Still, the survival rate was above 90%, just shy of the targets set by the Biological Opinion. The new spillwall is expected help the dam reach those standards.

“Every percentage of survival improvement is very difficult to get when you’re already over 90%,” Fredricks said. “We’ve been working on these mitigation issues for decades now, and we’re getting down to the bottom of the barrel in terms of easy things to do.”

Several studies on salmon survival at The Dalles Dam will be performed to measure the project’s success, Fredricks said. Fish with acoustic tags have been released upstream above John Day Dam and are being tracked by biologists.

“We are monitoring the survival of those fish all the way down to the lower part of the Columbia River,” Fredricks said.

The spillwall project was federally funded under the Columbia River Fish Mitigation Program. A $45 million construction contract was awarded to General Construction Co., a subsidiary of Kiewit Corp.

In 2004, the Corps built a 100-foot spillwall between bays 6 and 7 to disrupt a lateral flow that seemed to steer the salmon toward waiting predators. Fish mortality and injury decreased, but salmon survival rates were still low due to predatory fish and birds in shallow waters.

A study of fish survival at the dam showed that more direct conveyance from the spillway to a deep, swift-running channel known as a thalweg would likely improve survival rates for juvenile salmon.

The modeling, design, and construction of the new spillwall between bays 8 and 9 were performed by a team of fisheries biologists and engineers who worked closely with state and federal agencies and tribal representatives at the Corps’ Engineering Research and Development Center (ERDC) in Vicksburg, Miss.

“All the right people worked together right there at ERDC on the biological, technical, and structural elements of the wall’s design,” said Bob Wertheimer, the Corps’ lead fisheries biologist on the project. “All options or ideas to increase fish survival were considered.”

The team considered an extension of the 100-foot spillwall to the thalweg. But modeling showed the extension would likely cause an unacceptable increase in total dissolved gas, which can be harmful to fish. The new spillwall is not expected to cause significant changes in total dissolved gas.

The new spillwall runs straight downriver from the middle of the 20-bay spillway and bends near the end to ensure salmon reach the thalweg.


In-place replacement of a wicket gate

A hydropower unit’s two major assemblies are the turbine assembly and the generator. Of the turbine assembly’s key parts, the method of controlling the flow of water to the turbine is provided by a set of overlapping vanes, called wicket gates. The wicket gates usually turn less than a quarter of a circle to control the power output of the generator or power consumption of a pump.

When a wicket gate shaft on Unit 2 at the 456-MW Noxon Rapids hydro plant twisted to the point of failure, plant personnel devised a way to quickly repair the unit and get it back online. To accomplish this, they had the leaves cut from the spare wicket gate, installed the shaft in the unit, then welded the leaves back in place. The repair was completed in just three weeks, and the wicket gate has operated normally ever since.

Noxon Rapids, on the Clark Fork River in Montana, began operating in 1960. The project is part of the two-powerhouse, 742-MW Clark Fork project. The Noxon Rapids powerhouse contains five turbine-generator units.

The first problem with wicket gate No. 1 in Unit 2 at Noxon Rapids occurred on June 19, 2006. A high-temperature alarm came on in the turbine guide bearing, and personnel took the unit off-line. It was visually apparent that a shear pin had failed on gate No. 1 and the stop pin had suffered a violent impact, causing it to partially shear. In addition, the wicket gate shaft was twisted and bent slightly upward. Because June is a peak generating month for Avista, it was imperative to get the unit operating quickly. Thus, plant personnel simply installed a new shear and stop pin and returned the unit to service on June 24.

Then, in mid-May 2007, the shear pin on gate No. 1 failed again. This failure was discovered during a routine daily inspection; again, the cause was unknown. During this inspection, personnel noticed the upper part of the wicket gate shaft had yielded and was twisted beyond repair.

Unit 4 at Noxon Rapids was off-line for generator repair work, so an extended outage was not an option for Unit 2. Therefore, plant personnel decided to replace the gate with a spare, with minimal disassembly of the unit.

Avista asked its generation and production engineers to find a solution to the failure in Unit 2. Therefore, plant personnel decided to replace the gate with a spare, with minimal disassembly of the unit.

Options considered involved:

  • Maintaining the No. 1 wicket gate in place, locking it in the open position;
  • Welding the wicket gate in the closed position;
  • Cutting the existing wicket gate out of its position, installing a newly machined shaft, and welding the original gate leaves onto this shaft; and
  • Quickly cutting apart the existing wicket gate in pieces and removing it, then installing a spare wicket gate. A machine shop would cut off the leaves on the spare gate and machine the shaft outer diameter to fit through the intermediate bushing. Then the leaves would be welded to the shaft inside the unit.

Time was of the essence because spring runoff was just a few weeks away and Avista personnel chose the fourth option because it appeared to require the shortest amount of repair time.


Gregory Poindexter is associate editor of Hydro Review.



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