Retrofitting Air Handling Equipment at W.H. Sammis

Issue 4 and Volume 115.

FirstEnergy Corp. completed a $1.8 billion project to retrofit environmental controls at the W.H. Sammis station. Photo courtesy of Bechtel.

By Brian Wheeler, Associate Editor

As U.S. Environmental Protection Agency rules covering power plant emissions come into effect, many plants are beginning retrofit projects to comply with the mandates or as part of settlement agreements. When completing an emission control project, existing air handling equipment must be addressed.

“It is an integral part of the retrofit project,” said Mark Voorhis, project manager at Bechtel.

When retrofitting an existing plant, if the air handling system does not deliver the right flow and take into account the added pressure drop from the new components, then the boiler may not operate at peak efficiency. For balance draft systems, when more components are added to the back end of the plant, the system may face an increase in pressure drop due to the new equipment in the gas path. Analyses must be completed to evaluate the existing draft systems and the state of existing induced draft (ID) fans capability. The ID fans may not be working to the same specifications as when they were originally installed. Understanding how the new increase in pressure drop matches up with the capability of the existing draft system can determine whether a retrofit or a total replacement of existing fans is needed.

“A retrofit to the existing fans could be as simple as tipping the blades, or as extensive as entire rotor and motor replacement, with the added complications that come with it,” said Voorhis.

And if modifying existing fans cannot produce the needed draft system improvements, then booster fans sometimes must be added to supplement the existing draft system. Or the plant can have a combination of both a rotor replacement retrofit and installation of new draft fans, which is what was done at the W.H. Sammis plant in Ohio.

In 2005, FirstEnergy Corp. began a $1.8 billion project to retrofit the W.H. Sammis coal-fired plant for air emission controls. The Sammis plant has a generating capacity of more than 2,200 MW with its seven coal-fired boiler units. To meet the goal of reducing sulfur dioxide (SO2) and nitrous oxide (NOx), Babcock and Wilcox Power Generation Group installed scrubbers and selective catalytic reduction equipment. For this project to be successful, the EPC contractor, Bechtel, also had to make a number of balance of plant modifications, including upgrading existing air handling equipment.

“Sammis was an extensive and complex retrofit for emissions control, including substantial air handling and ductwork modifications,” said Voorhis.

Voorhis had worked on two previous emissions retrofit projects and said he has not yet been on a site in which some modification or addition to the air handling capability and related infrastructure was not needed.

In Sammis’s case the plan was to route the flue gas from the seven boilers through three common wet flue gas desulphurization (WFGD) scrubbers. For boiler units 1 through 4, new ductwork was engineered to route flue gas through one of the common scrubbers. To achieve this, the gas flow path had to be changed within the existing four baghouses to get the proper tie-in points for the new flue duct. As part of this design approach, Voorhis said the project had to bypass and remove from service eight existing ID fans (two for each unit). Four new flue gas control dampers were installed in the ductwork to replace the existing ID fans. Three new common 12,100 horsepower Howden axial ID fans were introduced to the project to feed the one common scrubber for the four boiler units.

With one scrubber supporting four independent boiler units (all four of whose draft systems are controlled by dampers) the rest of the pressure through the scrubber and out through the new 850-foot-tall chimney is now controlled by the new common axial fans.

For the other three boiler units at Sammis—Units 5, 6 and 7—new ductwork had to be completed to route the units through two new common scrubbers. Babcock and Wilcox installed two SCR systems on Units 6 and 7, as well. To modify the draft system to support the SCR equipment, Bechtel performed a rotor replacement on the four existing fans associated with units 6 and 7.

“The project’s goal was to avoid having to replace the existing ID fan motors,” said Voorhis. “We maximized the amount of head we could get out of new rotors with the same motors, and FirstEnergy rewound and maintained the existing motors to ensure maximum capacity in accordance with the original motor specifications.” He said this type of construction effort, which needs to be accomplished during a plant outage, is never a simple thing on retrofit projects.

Typically, ID fan rotors are originally installed to allow future access, if needed. But over time plant modifications may take place which increases the complexity of rotor access and removal. In the case of Sammis, the plant had gone through an emissions modification project in the late 1980s in which new precipitators and baghouses were installed. When that project was complete, it left access to the ID fans very challenging. Nine months of planning took place to find the most efficient method for removing the existing components and installing the new rotors and rewound motors. When planning was finished, the project completed as much pre-work as possible by relocating commodities to decrease the amount of time the plant would need to be offline. The outage-related retrofit activities were planned on an hourly basis.

“On these retrofits, the goal is to get as much done before the outage to minimize outage time. The goal is to never be on the boiler outage critical path,” said Voorhis. “We complete construction right to the tie–in point; that is, up to the point that further activities require some type of plant or component outage.”

Replacing the rotors made up for the pressure for the SCRs. However, for boiler units 5 through 7, to account for the added pressure drop across the two new common scrubbers and the new 850-foot chimney, three common 14,700 horsepower Howden axial ID booster fans with a flow rate of 2.3 million actual cubic feet per minute (AFCM) were added downstream of the three boiler units.

Another technical issue associated with major plant modifications affecting the draft system is the guidance provided in the National Fire Protection Association’s (NFPA) code, NFPA 85, associated with implosion protection as it is then interpreted by the appropriate underwriting authority. In part, these NFPA guidelines discuss the need for a compliant control system to be in place to protect the boiler and duct work from transient pressures, as well as providing guidance on the options related to structural strengthening of draft system infrastructure and control system trade-offs. At Sammis, precipitator frames and ductwork in certain areas were strengthened. Also, vacuum relief dampers were installed in the duct to help relieve negative transients should they occur.

By project’s end, over 9,000 tons of duct was erected at Sammis. Three hundred thirty-seven duct modules were constructed off-site and delivered on a “just-in-time” basis to the construction site. To help plan this “logistically challenging exercise,” 24 separate duct routing, construction method and material studies were completed by a joint team comprised of Bechtel, FirstEnergy, B&W and Dynasteel Corp. personnel to develop the overall constructability plan.

The completed absorber vessels at Sammis. Photo courtesy of Bechtel.

To put all pieces together, Bechtel, along with FirstEnergy, B&W and other contractors, had six to eight weeks to tie-in all duct and wet flue gas desulfurization associated work on each unit. The duration for the ID fan rotor replacement was eight to 10 weeks, accomplished within the existing boiler maintenance outage windows. There were seven separate tie-in outages for the seven separate boilers.

“Not only was the project complex in its own right, but the team had to integrate it with existing boiler outages whose point in time was fixed and not easy to be adjusted,” said Voorhis.

The retrofit project helped FirstEnergy’s largest power plant in Ohio reach its mandated emission goals of reducing SO2 by more than 95 percent and NOx by more than 90 percent. 

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