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Plant Upgrades: Plant Upgrades Add Capacity at Less Cost

Issue 4 and Volume 105.

By Douglas J. Smith
IEng, Senior Editor

The U.S. has approximately 1,300 electric power plants in commercial operation more than 30 years of age. Although some of these plants will be replaced with new greenfield plants, a large percentage will continue operating for years to come.

Rather than constructing new power plants a less costly option is to upgrade and/or repower older plants. These plants typically have low efficiencies and low reliability. They also tend to have higher emissions of NOx, SOx and particulates.

In general, upgrading and repowering older plants reduces emissions and improves efficiency and availability. At a fraction of the cost for constructing a new greenfield power plant, an older plant can increase its capacity and have its life extended for at least 20 years through upgrading. The upgrade also provides much quicker returns since delays due to siting and permitting greenfield plants can extend their development and construction schedules to five years or more.

In recent years, many older power plants have been repowered with fluidized beds and/or modified to combined-cycle operation. However, depending upon the circumstances, it is not always necessary to carry out major modifications. Upgrading individual systems such as coal pulverizers, coal handling systems, gas and steam turbines, boilers, ash handling systems and/or valves can reduce the cost of upgrading.

Pulverizer Upgrades

In today’s competitive power industry, pulverizers must be capable of handling a variety of coals with varying grindabilities, moisture levels and ash content. Not only must pulverizers be capable of responding to changes in coal quality quickly, they must also respond to load changes.

Faced with more stringent environmental regulations, many coal-fired power plants are switching to low sulfur coals. Unfortunately, these coals tend to have lower grindabilities, higher moisture content and lower heating values. In addition, switching to low sulfur coals generally causes unit derating.

In recent years, coal pulverizer manufacturers have responded to the changing operating environment by upgrading and redesigning the pulverizers. One company, ALSTOM Power Inc., has increased the capacity of their pulverizers by redesigning the primary and secondary classification zones and by increasing the capacity of the exhauster fans.

The increased airflow (capacity) of the exhauster fans comes from the use of larger diameter double shrouded high efficiency fan rotors and higher speed drive motors. In addition to increasing the capacity of the pulverizers, the manufacturers have also reduced the downstream system resistance.

Babcock & Wilcox, ALSTOM and Foster Wheeler have all developed variable speed rotating classifiers that operate with lower pressure drops. The lower the pressure drop the finer the coal. According to the manufacturers, besides improving coal classification, the variable speed classifiers have also reduced pulverizer wear.

Boiler Life Extension

Boilers are the major cause of unscheduled outages. However, with the development and use of new materials for boiler upgrades, a boiler’s life can be extended in many older power plants. Nonetheless, before deciding on the scope of boiler upgrades, it is essential to conduct an in-depth inspection of the boiler. According to Babcock & Wilcox, the inspection should include:

  • Steam drums.
  • Headers.
  • Superheater, generating, waterwall and economizer tubes.
  • Steam and feedwater piping.
  • Deaerator.
  • Attemperators.

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High temperature headers, located at the outlets of the superheaters and reheaters, are subjected to extreme steam temperatures. Consequently, they are exposed to high thermal and mechanical stresses, Figure 1. Externally, the most significant damage to tubes is erosion from sootblowing and ash particle impingement.

Superheater Upgrade Increases Capacity

A Midwest power plant has recently upgraded the superheaters on three pulverized coal units. Over the years, the units had progressively lost capacity and by the early 1990s, each unit had lost 10 MW. All three units burn low sulfur eastern bituminous coal.

A B&W study of the single reheat radiant boilers revealed that an increase in throttle pressure of 70 psig would restore the 10 MW to each unit. This could be accomplished by upgrading the superheaters.

Except for the economizer, all of the components in the convective pass of the boilers were replaced. These included:

  • Seven banks of primary, secondary and reheat tube surfaces.
  • Six superheater headers.
  • Associated tube bank and header supports.
  • Rear wall casing, header vestibules and refractory.
  • Tube leg rear wall penetration seals.

According to B&W, the T91 (SA213T91) materials used in the secondary and reheat outlet banks will provide longer component life and reduce steam side pressure drop. Likewise, the reduced diameter reheat outlet tube legs and header stubs will improve flexibility and thus reduce stress in the area where tube failures had previously occurred.

To reduce costs and downtime, the B&W project team constantly reviewed the design, fabrication and delivery sequence of the components to the site. Some of the cost savings came from locating the field welds for easier welder access and shop assembly of the sootblower shielding and support attachment assemblies. In addition, the primary superheater (PSH) outlet bank sections were modularized and manufactured in six sections.

Because of limited lay-down area at the plant, the PSH outlet bank sections were delivered to the site in reverse order of their installation. Extensive pre-planning resulted in only 16 weeks of downtime required for each unit. However, the time for design, fabrication and installation took a total of 35 months.

According to B&W, the superheater upgrade has resulted in a throttle pressure increase of about 70 psig and an 8-10 MW increase in output per unit. Moreover, the units now have improved reliability, lower maintenance costs and their life as been extended.

Northside Repowering Project

Jacksonville Electric Authority (JEA), Florida, is repowering Units 1 and 2 at its Northside Generating Station. Unit 2 is being repowered under the U.S. Department of Energy’s (DOE) Clean Coal Technology Program. DOE is contributing $74.7 million with JEA paying the remainder of the costs. However, Unit 1 repowering is being financed completely by JEA. Repowering of Units 1 and 2 started in mid 1999 and both are expected to be back in commercial operation by 2002.

Boilers on Units 1 and 2 are being replaced with 300 MW circulating fluidized-bed (CFB) boilers fueled by coal and petroleum coke. The existing steam turbines are also being upgraded to increase their capacity by approximately 25 MW.

Unit 2’s oil/gas fired unit has been out of service since the early 1980s due to boiler reliability problems. However, Unit 1 remained in operation until it was taken out of service for repowering. There are currently no plans to upgrade the third 518 MW oil-fired unit. JEA will continue to operate the unit without any upgrading.

Although NOx emissions from the CFBs are inherently low, JEA is installing a selective non-catalytic reduction (SNCR) de-NOx system to lower emissions further. A new baghouse will reduce particulate emissions by more than 99.8 percent. The plant’s limit for SO2 emissions is 0.15 lb/mmBtu. Because of this, the plant is required to capture over 98 percent of the SO2 when firing petcoke with a sulfur content of 8 percent. According to Foster Wheeler Energy Corporation, the 300 MW units of the Northside Generating Station will be the world’s largest CFB boilers in operation.

The Forgotten Valve

Upgrading and resolving valve problems tends to be given low priority. However, eliminating problems in severe service valves offers one of the quickest and most effective ways for improving plant efficiency, says Dr. Sanjay V. Sherikar, Manager Plant Betterment, Control Components Inc.

Although severe service valves are a small percentage of the total valves in a fossil power plant, they experience the most problems. Examples of severe service applications include those for controlling boiler feed pumps, minimum flow control, feedwater control, spraywater control, main drainage, heater emergency drainage, turbine bypass and startup valves.

Power plants that overlook valve problems experience poor reliability, more frequent plant trips, a loss in capacity, higher heat rates and increases in operating and maintenance costs, says Sherikar.

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In many instances valve problems are caused when high fluid velocities occur with a high p. Controlling the velocity of the fluid, therefore, is critical, placing more emphasis on proper valve selection.

Ireland is currently experiencing an economic boom and the Electricity Supply Board (ESB) is hard pressed to meet rising electricity demands, says Tom Canning, Thermal Performance Manager, ESB. For this reason, ESB was seeking efficiency improvements that would involve minimal downtime requirements at the company’s Moneypoint power station. After evaluating various options Canning concluded that upgrading the plant’s severe service valves was the most cost effective way to increase efficiency and subsequently capacity.

The program undertaken at the 915 MW coal-fired Moneypoint power station showed that a 37 MW increase could be achieved by improving the performance of the severe service valves at the plant. The first phase of this program focused on identifying the efficiency losses from poor performing control valves and diagnosing the root cause of the valve problems.

Results of the first phase revealed that Unit 2 and 3 each had a loss equivalent of 14.2 MW and Unit 1 of 8.4 MW. Table 1 is a summary of the MW losses for individual valves at Moneypoint.

During the Unit 2 outage in May 2000, the following valves were replaced with fluid velocity control technology valves:

  • The 12-inch startup valve.
  • Three 6-inch emergency heater drain valves.
  • Three 2-inch main steam drain valves.

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To evaluate the success of the upgrade, the temperatures near the valves were recorded before and after valve replacement. Table 2 clearly shows that after installation of the new valves, the temperatures upstream and downstream of the valves dropped dramatically. This is a good indication that the valves were not leaking. After six months of operation, there were still no significant temperature changes.

According to Mick Roche, Outage Manager for Moneypoint Unit 2, the gain in Unit 2 performance attributable to valve changes was estimated at 7.4 MW. Plans are now underway to upgrade the severe service valves on the other two units.

Not only have the new valves replaced the lost MW, they have also reduced startup problems. Before the installation of new drain valves, damage sometimes occurred to the drain line elbows during unit startup, which then required the startup to be aborted. When this happened, it typically took a minimum of one day to repair the damage and get the unit back on-line. Now, with reduced fluid velocity within the drain lines from the installation of the new valves, this problem has been eliminated.