COMBINED CYCLE CONVERSIONS

AS WELL AS UPGRADING EXISTING COMBINED CYCLE ASSETS, OWNERS AND OPERATORS ARE LOOKING AT CONVERTING COAL AND NUCLEAR PLANTS TO COMBINED CYCLE OPERATION

With so much pressure from the U.S. Environmental Protection Agency (EPA) reigning down on aging coal plants, one option for power plant operators is transforming the facility into a combined cycle (CC) plant, harnessing both steam and natural gas. By doing so, they can make use of all the steam turbines as well as a large portion of the balance of plant.

The same applies to nuclear facilities, which already have the bulk of infrastructure in place for natural gas CC operation. Faced with the prospect of being edged out of the U.S., European and Japanese markets, some utilities and independent power providers may decide to switch from coal and nuclear to natural gas as the best route ahead.

And the economics are favorable. Many anticipate a boost in combined cycle construction in the U.S. and other regions of the world (Figure 1).

“Upcoming EPA rulings on greenhouse gases (GHG) and maximumachievable control technology (MACT), as well as the uncertainty around renewables have created an expectation of many new future natural gas units in the U.S.,” said Tim Xie, Lead Power Plant Performance Evaluation Group at WorleyParsons.

He laid out the math in favor of CC. It has the lowest construction costs among all types of generation technologies, on top of a relatively short construction duration, lower emissions, and low water consumption compared with other fossils. Financing, too, he said, is easier on CC compared to others. “In March 2012, a combined cycle gas turbine power plant had lower $/MWh fuel costs compared to coal-fueled power plants for the first time in history,” said Xie.

However, low gas prices pose a dilemma for CC plant design as fuel savings over the plant’s lifecycle may struggle to offset the increased capital costs. Therefore, GT selection is the key to success. Those specifying power plants are advised by Xie to investigate fuel costs and capital costs for the various GTs being considered to find the best option, which varies from site to site (Figure 2).

He cited the trend in Asia and Europe for increased orders for H- and J-class GTs, where high natural gas costs make it easier to justify higher upfront costs. Those types of turbines, though, have far fewer U.S. installs because of cheaper natural gas. As a result, there appears to be more of a focus on up-rating the more proven F-class gas turbine models.

New reality

As operators retire coal-fired plants, they will be faced with the challenge of cycling, according to Bill Siegfriedt, project manager at Sargent & Lundy*. Most of the recent combined cycle plants were originally built for base load operation, he said. Yet they find themselves tasked with cycling duty to fit the needs of a grid holding an abundance of variable renewable resources. Unfortunately, many of the design techniques to equip CC plants for cycling duty are not suited for retrofit.

The original intent of most CC plants assumed full load operation and infrequent starts, no quick starts and low capital costs for a short-term payback, said Siegfriedt. Cycling plants, on the other hand, run only on higher demand days, times or seasons, and typically at part load. “For plants not designed for this kind of duty, it can lead to premature wear, excessive maintenance and equipment failure,” said Siegfriedt. “You have to take a close look at the existing plant to find the potential for modifications. However, some features are not suitable for retrofit.”

He explained that it is possible to retrofit many older CC sites for reduced load operation, rapid and frequent starts, and high availability. Procedures and control systems can be adapted to assure that a CC plant with multiple GTs will turn down while avoiding inefficient GT part-load modes. Also, conversion to sliding pressure operation can improve efficiency of the steam cycle in part-load situations.

The need for rapid starting should also be addressed. Large heat transfer tubing requires a heavy wall and contains a great deal of water, which requires gradual warm up. A Heat Recovery Steam Generator (HRSG) retrofit, to a faster-heating design, would be financially unattractive. That said it is important to keep the steam cycle warm to speed up starting as much as possible.

This can be done by adding: a stack isolation damper; steam sparging to the HRSG mud drum; and LP condensate recirculation between the evaporator and the economizer. Of course, the ramping of the GTs can be uncoupled from the HRSG warm up requirement by using Inlet Guide Vanes (IGV). These can help match the temperature of the flue gas entering the HRSG to allowable levels.

The steam turbine also should be addressed. Installing attemperation for the main steam and reheat steam will uncouple the steam turbine’s warm up rate from those of the GTs and the HRSGs. Adding a steam bypass to the condenser will reduce the venting of excess steam and cut down on demineralized water make-up requirements. Some steam will still be vented, so it may also be desirable to increase makeup water treatment capacity. “Keeping the combustion turbine and steam turbine warm is a good strategy to be able to better deal with faster or more frequent starts,” said Siegfriedt.

Further tips: invest in redundancy so that if one system fails, you can maintain high availability; review trips and start failures to determine what systems or components are causing repeated events; upgrade control algorithms to provide intelligence to operators so they can more reliably follow load patterns; and automate control of the steam bypass to assure accurate dumping from HRSGs to minimize steam pressure swings.

Coal-to-gas switch

An even more adventurous strategy for aging coal plants is eliminating coal altogether. Brian Reinhart, Study Manager at Black & Veatch Energy in Overland Park, Kansas, examined a variety of options including a switch from coal to natural gas.

He framed the discussion around a 250 MW subcritical pulverized coal-fired unit built in the late 70S — the type of site that is firmly in the EPA’s crosshairs. This particular facility was challenged by the fact that the closest gas line with sufficient capacity was 60 miles away.

Reinhart covered several options such as conversion to natural gas only, natural gas and coal co-firing, a full emissions control retrofit to bring the unit into compliance, repowering the steam turbine to make it run as part of a combined cycle plant or replacing the entire plant with a new CC. Co-firing was dismissed rapidly as it is still regarded as a coal unit by the EPA, so regulatory issues remain.

Reinhart said that a more feasible long-term approach is either emissionscontrol retrofits or a combined cyclebased solution. A CC could entail retaining the steam turbine, condenser, control room and water treatment facilities and replacing the boiler.

“The steam turbine would need to be repowered,” said Reinhart. “Although you would experience a derate of about 10% to 20% in steam output due to flow limitations in the steam turbine, by adding two F-class gas turbines you would boost net power by nearly three times.”

On the downside, you would need about eight acres or more for these two GTs and heat recovery steam generator trains. But the end result would be a gain in efficiency, a drop in O & M and no need to perform heavy maintenance on pulverizers and other coal equipment. Further, by changing from 250 MW to 600 MW, the area would have to possess sufficient transmission margin.

Nick Zervos of the Thermal Engineering Group at Shaw’s Power Group was another pointing out the potential advantages of steam turbine repowering as an option for converting a coal site to a combined cycle plant. “As it could cost hundreds of millions in regulatory compliance to keep an old coal boiler going, the owner may choose instead to retire the existing coal-fired boiler and put in one or more combustion turbines and HRSGs to repower the existing steam turbine,” said Zervos.

He detailed the differences in steam systems in repowered plants, compared to compact Greenfield combined cycle plants. When a GT is added to run in CC mode, for instance, that can lead to long steam piping due to where the gas turbine is sited.

Zervos said that longer lines mean greater pressure and temperature losses. A mere 1°F drop in steam temperature can mean a big loss in revenue. So for long steam piping lengths, he advised plant managers to choose pipe insulation thicknesses carefully. And if at all possible, site the gas and steam turbines close together. One of the other consequences of long steam lines is more complicated warm ups for cold starts.

If there is no way around having the GT sited far away from the steam turbine, the plant will need adequate drain lines to avoid the accumulation of condensate, which can lead to water slug damage of the pipe. It is especially important to minimize the length of steam turbine bypass lines downstream of the bypass valves.

When a cold bypass pipe is suddenly filled with hot steam during a steam turbine trip event, condensate will form and be propelled along the pipe. The longer the line is downstream of the bypass valve, the greater will be the condensate accumulation and consequent transient loads applied at all changes in direction.

“Ideally the gas turbine and HRSG will be selected to make as much steam as the steam turbine can swallow,” said Zervos. “Very often supplemental duct firing in the HRSG is appropriate for a good match with the existing steam turbine. You can also make modifications to the steam turbine to be able to handle more or less steam.”

In addition to bringing in GTs and HRSGs, required modifications include condensate pumps, boiler feed pumps, a steam turbine bypass system with condenser spargers, steam drain tanks, and retiring feedwdater heaters.

For the steam path itself, modifications are needed on high pressure inlet blading and low pressure back-end blading. Alternatively, perform a complete steam path replacement.

“It is often economical to reblade the whole steam turbine to keep it from acting as a bottleneck to the system,” said Zervos. “You also need a steam bypass system so that when the steam turbine trips, you don’t need to trip the GT, too. This is especially important for multi- HRSG plants.”

* Siegfriedt’s experience includes lead engineer on the project that took a canceled nuclear project and transformed it into a 1,400 MW CC facility (Turbomachinery International, p.11 September/October 1988).