Rehabilitation and Repair

Rehab reports: Case studies of major hydro rehabilitation worldwide

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Rehab reports: Case studies of major hydro rehabilitation worldwide

In North America, as well as many other parts of the world, hydroelectric plant rehabilitation is a major and important business. The long-lasting legacy of hydropower naturally means facilities will need significant operations and maintenance work and periodic repair or replacement of components. For all who are planning such work, learning lessons from others who are “in the trenches” is invaluable. This article provides some insights into work being performed, along with lessons learned and best practices to employ.

In the first part of this article, two major hydroelectric owners in North America discuss the “big business” of hydroelectric plant rehabilitation. These excerpts are taken from the transcript of the September 2022 HYDRO+ free virtual training session: Learning from Rehabilitation Case Studies. It is available to watch on demand at any time for more information and a more thorough discussion of the subject.

David Rowland, senior project manager, hydro generation projects with the Tennessee Valley Authority in the U.S., plays a key role in developing TVA’s Hydro Life Extension program, or HLE. TVA has completed 75 projects, ranging from $100,000 to $40 million. Rowland is managing seven major HLE projects, with a portfolio of more than $225 million.

TVA has 109 conventional hydro units and four large pump-turbines with total installed capacity of 5,600 MW. The fleet produces $1 billion to $1.1 billion a year in revenue. TVA has a rich history in turbine and generator rehab on its fleet, dating to around 1990. TVA started a program called the H mod, and from 1990 until today, has completed 70 hydro unit rehabs.

TVA is now starting to go back to some of those Kaplan units that were completed in the early 1990s. From 1990 to about the 2010 timeframe, TVA had pretty decent investment in the program, but there was a lull in investments from 2010 to 2017. Since 2017, TVA has been trying to ramp back up.

Along that timeframe, availability of the fleet was continuing to decline, by about 1% a year. So personnel made a strong push to management over the past two to three years to ramp up the investment level.

Starting in the fall of 2021, TVA began the new, focused HLE program. It’s still the same work TVA has always done, as far as turbine and generator and power train replacement, but there is a renewed focus and investment levels are going back up. TVA is targeting about a 10% per year re-investment rate, which is over $100 million. Rowland said in his opinion, 10% re-investment rate is what utilities should be doing on average yearly in perpetuity.

Over the past five or six years, the setup was diced into many different, smaller projects to prioritize the funding. It’s a very inefficient approach to do an entire unit at a time.

In the new HLE program, TVA is focusing on selecting projects. The priority of units is a really big deal. Where do you invest in the most efficient way? TVA has a hybrid approach of looking at the value of the unit on megawatt-hour and revenue bases, and any ancillary services it provides or flood control factor in a little bit. Then TVA looked at the age of the turbines and generators and factored in their asset health scores.

In general, TVA’s generators are lasting 30 to 35 years. A general rule of thumb is Kaplan turbines are lasting 30 years and Francis around 50 years.

The hydro replacement projects are diced into three phases that personnel get approval for. Phase one is scoping and preliminary engineering. This goes into great detail, studying every component on the power train of the unit: turbine, shafts, bearings, bridges, headcovers, the generator and the electrical going out to the transformer.

TVA tries to get the best bang for the buck on power improvements without spending too much money. And they strive for efficiency, usually getting 3% to 4% efficiency improvements on each overhaul.

Phase two is the long lead material purchase or detailed engineering design and all construction planning.

Phase three is the implementation or outage work for the project. TVA’s project managers serve pretty much like a general contractor. Projects are performed with a lot of in-house resources and labor. Typically, the mechanical contractor is the in-house field folks. For tearing down the units, TVA usually will contract out some of the major work, the discharge ring work, rehabbing the unit, and the generator work. Whatever parts TVA is buying new on the mechanical side is contracted out. When it comes to rehabbing the major components — such as shafts, bearings and head covers — it’s a hybrid mix. TVA does some of those components in house in its machine shop, so they are able to do the shafts and bearings typically. The larger head covers and shift rings, TVA sends out to an external vendor. In some cases, depending on what is found in phase one, TVA will purchase a new head cover with shift ring.

TVA has developed an extremely detailed scope index where every component on a hydro unit is listed out, starting in the draft tube and out to the transformer. TVA then has a division or responsibility tied to that piece of scope.

TVA then builds very detailed project budgets based on more of an organizational breakdown structure. And then that scope indexed document ties those two together.

After all that, the team is assembled. TVA has a lot of ancillary support when it comes to the small things in an outage: asbestos support, lead abatement, scaffolding, etc. TVA uses a partner contractor for that and manages the field outages in house, with a construction management team running the project.

There are some major things TVA has seen in the past with old units. First, personnel almost always find additional discharge ring damage around the turbine area for cavitation. So, that’s usually fairly extensive repair. Sometimes TVA will do a partial or full replacement on the discharge rings.

Second, the stator core iron typically needs replaced. Back when the program started in the nineties, it was almost never necessary to replace stator core iron. But now the stators are aging out, and TVA has made that standard scope now, which adds money and time to outages.

An issue that’s been popping up recently is trouble with rotor poles. TVA typically rehabs the rotor poles, but personnel are finding several sets that need a full replacement of the pole itself for various reasons. So, rotor poles are high on the list for discovery and issues lately.

Dave Bonell, senior manager in Ontario Power Generation’s renewable generation major projects group, is leading several large hydroelectric redevelopment projects. Dave is a certified project management professional with over 24 years of experience in IT and the construction industry. He has extensive experience as a project manager, management consultant, organizational change management consultant and organizational process analyst.

In Ontario, OPG has four nuclear plants, two wood pellet plants, a solar facility, 66 hydro stations and four combined cycle gas plants. The company also has 87 small run-of-river hydro plants in the U.S.

The overhaul program of Ontario assets started in 2021 and runs to about 2042. Those 66 stations contain 233 units. The average age of these stations is 82 years, and several are over 120 years old. OPG is looking at 174 unit overhauls required. There was a time when OPG was getting behind on the project, with some stations hitting the 50-year mark between overhauls, which is why this program was developed.

OPG will average about eight overhauls per year. About 40 of the unit overhauls will include turbine runner replacements, to improve efficiency or boost capacity. The investment was $2.5 billion, in 2021 preinflation numbers. It will be significantly higher now.

There are some key risks for the overhaul program.

The first is lack of OPG resources and staff from union halls. All work is done by OPG staff or staff from union halls and vendors. It is getting harder to source a welder or boilermaker from the union hall because other groups are doing large overhaul programs as well.

The second is availability of key vendors and original equipment manufacturers, as OPG has more overlapping projects. When OPG started getting to eight or nine projects annually, even maxing at about 15 projects one year, the vendors are drawn pretty tight, in terms of having good-quality staff.

The third is machine shop availability. OPG has a couple of internal machine shops, but for some of the larger components the company goes external. And there are limited machine shops in the northeast for these kinds of components.

The fourth is nonstandard engineering. All of OPG’s sites are different. Even within plants, there are different units. So the company has to start each one from scratch, which is taking more time.

The fifth is the repair versus replace decision timeline. The more the company looks at things, the more it becomes clear that, in some cases, it makes more sense to completely replace a unit, water to wire.

OPG has about 250 maintenance projects in play annually, about $300 million of work. This overhaul program is supplemental, and the current company setup wouldn’t suffice. OPG is split into four regions, each with a director of assets and projects and dedicated staff, from engineering and supply chain, and a dedicated overhaul crew. Instead of borrowing from the base crew, they’re moved into a dedicated group.

An example of the work OPG is doing is the Sir Adam Beck generating station. The complex consists of a 130 MW pump generating station, 550 MW Sir Adam Beck 1 that began operating in 1922, and 1,580 MW Sir Adam Beck 2 that was completed in 1954. The station was built on the 25 Hz grid, and starting in the 1950s they were converted to 60 Hz. G1 and G2 remained 25 Hz because they were providing power to steel mills that needed 25 Hz for some of their large motors. In 2009, that was discontinued, and those units were mothballed.

OPG spent the next three or four years trying to figure out whether to just overhaul the units or if they would be complete replacements. At the end of the day, the decision was made to completely replace them.

The G5 overhaul was happening at the same station during the same two-and-a-half-year period. That overhaul included a new runner but basically left the generator untouched. There was only about a $2 million difference between replacing G1 versus overhauling G5. That led OPG to look more closely at replacing versus just overhauls, especially given the age of the equipment. When equipment starts hitting 100 years, it’s already been overhauled two or three times.

The Sir Adam Beck scope was complete replacement, along with head gate refurbishment. OPG planned to reuse the penstock scroll cases and draft tubes to keep the cost down and minimize civil works on the project.

One constraint is that the new units are limited to the conditions of the existing plant, such as overhead door size. OPG came up with some jigs that were use multiple times on the project to save costs.

OPG was able to go from a 44 MW unit up to 57.5 MW, a significant generation increase.

In terms of challenges, OPG couldn’t do a full evaluation of all components until the units were removed. The penstocks were 1919 riveted steel encased in concrete. Surprisingly, they were in really good shape, with less than 20 rivets repaired per unit.

However, personnel did find large cracks and voids in the cast steel scroll cases. OPG attempted a repair, but the company spent about $5 million and the cracks just got bigger and bigger. Deciding this approach was too costly and was going to never offer the desired safety factor, OPG pivoted to a full replacement. This appears to be the first of its kind in Canada and maybe in the U.S. for a scroll case replacement in an operating plant.

OPG personnel cut up and removed the scroll case. All pieces had to come up through the turbine pit, which is only 18 feet across at the top, and this had to be done within 20 feet of G3, which was operating. Personnel we had to use small equipment to keep the vibrations to a minimum to avoid tripping out the other unit.

To rebuild it to the same spec as what was installed initially, multiple pieces were required. OPG put in five segments, with only about 1 in of space to spare for unit components going down into the turbine pit.

One important lesson learned relates to the upstream projects, which were not completed as planned before the major projects group took over. For example, the powerhouse cranes hadn’t been upgraded for about 20 years at the time. OPG had to add that work to the project scope, which caused delays.

The price to replace these units with a six-year warranty was comparable to the overhaul cost.

Some recent rehab case studies

Recently we have reported on several rehabilitation projects planned or ongoing at hydroelectric facilities worldwide. In total, the five projects referenced below account for 4,388 MW of total capacity. Below are some recaps of this work, with links to more information.

Clover, Australia

AGL Energy Limited has begun a five-year rehabilitation of the 29 MW Clover hydro station in Victoria. This work involves replacing turbines, generators and inlet valves to boost throughput and thus increase output capacity by 14 MW.

This station provides peaking power, as well as backup power when other generating stations are offline. It is part of the 395 MW Kiewa Hydro Scheme, which together with the McKay Creek, Bogong and West Kiewa stations provides average annual generation of 404 GWh. It is the oldest of the four stations and was commissioned in 1945.

The project will cost $27.84 million.

Folgefonn, Norway

Statkraft plans a major modernization of the Folgefonn hydropower scheme in Hardanger to meet increasing demand for renewable energy due to electrification and new industry development.

The Folgefonn development comprises the Jukla and Mauranger power plants, which began producing power in 1974 to supply the local aluminum industry. Jukla Power Plant is a combined power plant and pumping station, enabling it to use different head levels. Water from the Jukla plant is reused in the Mauranger Power Plant. Combined, the two produce 1,204 GWh of electricity annually.

Statkraft anticipates increasing installed capacity at the Mauranger power plant from 250 MW to 880 MW, providing 70 GWh to 80 GWh of new clean energy for the power system.

It will take about three years before detailed planning can begin. Construction could start in 2026. The overall cost of this work was not disclosed.

Haditha, Iraq

Iraq’s Ministry of Electricity has commissioned a rehabilitation of the 660 MW Haditha hydropower project on the Haditha River in the western part of the country.

The plant was built in the 1980s and contains six 128 MVA units. Haditha Dam is an earthfill dam that is just over 9 km (5.6 mi) long and 57 m (187 ft) high. In addition to hydropower generation and flood control, the dam provides water for irrigation.

The revitalization will be spearheaded by KONČAR – Engineering (KET), with a contract awarded in June 2022 worth $68.7 million. The company will carry out a partial revitalization of generation units; replace part of the equipment, the entire plant management system, the excitation system and electric protection system; and upgrade mechanical subsystems and hydromechanical equipment.

The timeline for completing the project was not released.

Niagara Power Project, U.S.

The New York Power Authority is in the midst of its Next Generation Niagara project, a 15-year modernization and digitization program for the 2,675 MW Niagara Power Project. The Niagara plant is the largest source of clean electricity in New York State and began producing power in 1961.

Launched in 2019, this program will extend the operating life of the project and involve replacing the gantry crane, inspecting the Robert Moses plant penstocks, upgrading and digitizing control systems and overhauling and/or replacing end-of-life mechanical components.

Sultartangi, Iceland

Landsvirkjun, the National Power Company of Iceland, is uprating the second generator stator at the 130 MW Sultartangi hydroelectric station from 75 MVA to 80 MVA.

The Sultartangi Power Station was put into commercial operation in 1999 and uses water from the River Tungnaá and the River Thjórsás, as the two rivers are joined in the Sultartangalón Reservoir above the station. Average annual electricity production at the station is 1,020 GWh.

The uprate of the first generator stator was completed in September 2021.