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Market Competitiveness Requires Constant Control of Plant Operations and Maintenance Costs

Issue 7 and Volume 107.

By Douglas J. Smith IEng, Senior Editor

With the competitive nature of the electric generation industry, it is becoming more important to maximize the return on investment (ROI) of power plants by optimizing operations and maintenance. The key is to integrate the generation of electricity with a quality asset/maintenance management program.

A planned maintenance program can be condition based, preventive or a combination of both. Where equipment can only be off-line for a short period of time and there is a possibility of secondary damage occurring, a condition-based program is recommended. On the other hand, where equipment has backup systems, preventive maintenance carried out at fixed intervals can be utilized. Although maintaining power plant equipment can be costly, it is critical for maintaining high availability and for helping to reduce secondary damage to other equipment and components.

Power Plant Cycling

In recent years, electric utilities have changed the way they operate their older power plants. When these power plants were first constructed, they were invariably designed for baseload operation. Today, many of these plants are subjected to cycling on a daily basis to meet a utility’s peak loads. Unfortunately, cycling of the plants not only affects the heat rate and availability, it also increases maintenance costs.

According to Aptech Engineering Services, units that are subjected to regular cycling should analyze what effect cycling has on the competitive cost of operating and maintaining the plant. The cost of different types of operation – hot starts, warm starts, cold starts, load following, shutdowns and unit trips – should all be determined.

Over the years, Aptech has analyzed and surveyed more than 250 coal, oil and gas fired power plants in the U.S. These units have ranged from sub-critical drum type to supercritical once through units ranging from 15 MW to 1,300 MW. The aim is to determine a unit’s life cycle costs, thus enabling the utility to dispatch its most cost effective units.

Aptech has developed a software program (COSTCOM) for controlling the operations and maintenance costs of power plants. Aptech used the program at a 600 MW coal-fired U.S. power plant to analyze the plant’s operations and cost of maintenance. Using this information the plant has been able to reduce transients, minimize damages and reduce costs from cycling the unit. According to Aptech, the goal was to minimize the total cost of operation and not just the fuel costs.

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Figure 1 shows annual maintenance costs for a baseloaded coal-fired plant versus the maintenance costs of cycling a coal-fired plant. This graph assumes 76 equivalent hot starts and clearly shows the increase in maintenance costs from cycling the unit.

Reducing Auxiliary Power

Combined-cycle power plants that use constant speed HP feed water pumps and natural gas compressors utilize throttle control for flow modulation when the plant’s load varies. Unfortunately, when a combined-cycle plant’s load is under throttle control, the plant’s auxiliary power consumption increases. For combined-cycle plants subjected to load cycling on a continuous basis, the increase in auxiliary power can be significant and thus variable speed drives become cost effective.

According to Dr. Walter I. Serbetci, engineering manager, Raymond Professional Group LLC, Chicago, a midsize combined-cycle power plant with a GE 7FA or Siemens-Westinghouse 501F gas turbine typically requires an HP feed water flow of 700,000 lb/hr to 850,000 lb/hr for each heat recovery steam generator (HRSG). The corresponding feed water operating pressure is 2,200 to 2,400 psi. Because the designer generally incorporates a 3-5 percent performance margin into the HP feed water flow, during 100 percent load operation, some throttle control of the feed water is required

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As an example (Table 1), for a cycled plant operating for 5,000 hr/yr at 100 percent load, at 70 percent load for 2,000 hr/yr and 50 percent load for 1,000 hr/yr, the annual energy savings from using variable speed drives are:

  • 65,000 kWh at 100 percent load
  • 748,000 kWh at 70 percent load
  • 504,000 kWh at 50 percent load.

Cycling of combined-cycle plants also requires precise control of the fuel to the gas turbines as load changes. In plants where the natural gas compressors are not equipped with adjustable inlet guide vanes, Serbetci states that variable speed drives offer the most efficient and economical gas flow modulation for varying gas turbine loads.

Moss Landing Cycling Operation

In recent years, Duke Energy North America has improved the reliability and the cycling of Units 6 and 7 at their Moss Landing California plant through better asset management and improved planned maintenance. Upgrading and planned maintenance to key boiler and turbine components has helped reduce the cost of cycling the units.

After Duke Energy purchased the plant from Pacific Gas & Electric (PG&E) in 1997, most of the equipment needed repair and/or refurbishing. Prior to this, due to corrosion fatigue of the lower water walls and tube failures in the burner corners of the boiler, PG&E had replaced the lower furnace wall up to 15 ft from the first pass outlet header.

One of the first upgrades Duke Energy completed was the retrofitting of selective catalytic reduction (SCR) and low NOX burners to the units to meet the California air quality regulations. During an outage to install these environmental controls, a variety of other modifications and upgrades were carried out.

The FD and ID fans were replaced with more efficient axial flow fans and the boiler flues and ducts were modified. In addition, to improve unit control new digital controls were installed including the replacement of the old startup valve actuators with hydraulic actuators. To determine the condition of the reheat and super-heater tubing the plant used Aptech’s “TubeAlert” and “Tubelife III code” non-destructive testing equipment.

Duke Energy replaced all reheat tubing with life expectancy of less than 80,000 hours, tubes with significant thinning and all of the super-heater tubing. Although the outlet header did not require replacing, some creep damage was found on the header tube studs and welds.

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A major modification at the Moss Landing plant was an improved startup bypass system, (Figure 2). Modifications to the bypass system included removing the resister tubes and 202 valve, and adding a 207 valve, reheat attemperation and variable speed controls. After the upgrades were completed, the net result is the unit can be ramped up 50 MW/min from the previous ramp rate of five MW/min. As a result, Duke Power is now able to respond quickly to the capacity needs of the California energy market.

Operations and Maintenance Management

Although electric generating plants are facing more pressure to reduce operating and maintenance costs, they are still expected to maintain high availability and low heat rates. Additionally, plant managers are being asked to reduce personnel. The end result is that plants are left with less experienced staff and managers are now being forced to become more innovative in how they operate and maintain their plants.

According to a paper presented by Stone and Webster Consultants at Power-Gen International 2002, power plants are now incorporating neural networks, distributed control systems with advanced graphics, outsourcing services and performance monitoring software. Some smaller California cogeneration plants and new combined-cycle power plants are cross training personnel to do mechanical, electric and instrument repairs. Combined-cycle power plants frequently have job descriptions that allow the staff to perform both operations and maintenance tasks.

Similarly, the plants are utilizing predictive maintenance techniques, on-line stress calculators, reducing spare part inventories and extending the intervals between scheduled outages to reduce costs. Typical operating and maintenance costs, in 2002, for a 500-1,000 MW coal-fired plant are $30-$35/kW/yr while the costs for coal-fired plants larger than 1,000 MW are $25-$30/kW/yr.

According to Richard M. Grieve, senior consultant, Stone and Webster Consultants, the 2002 costs are lower than previous years. The major reason for the reduction is that competition is forcing electric utilities to squeeze more production out of their plants by extending the intervals between outages and also by reducing on-site personnel. The costs of non-fuel operations are primarily due to the cost of labor. As a result, the efficient use of personnel is a fundamental requirement if power plants are to be competitive.

Although large electric utilities in the U.S. have some form of centralized planning, maintenance and engineering, many of them, particularly in the Midwest and Eastern U.S., are outsourcing the engineering and maintenance functions to reduce costs. As a result the plants have less onsite maintenance staff. The onsite staff is responsible for carrying out minor repairs and routine maintenance. In almost all cases contractors generally do the scheduled and unscheduled maintenance.

Recovering Lost Steam Turbine Capacity

Cinergy’s Walter C. Beckjord Unit 5 has a 255 MW General Electric tandem compound, combined reheat steam turbine. Over a period of eight years, 1992-2000, the HP steam turbine’s efficiency dropped from 82.2 percent to 78.7 percent. This also caused a loss in capacity of 18.3 MW.

Plant personnel determined that copper deposits within the HP steam turbine contributed to the reduced efficiency. During plant operations, dissolved copper oxides from the corrosion of copper tubing in the condensers and feed water heaters carry over into the boiler cycle and HP steam turbines.

The Beckjord plant had experienced similar problems with the HP steam turbine on Unit 6. The copper deposits were removed in the HP turbine by chemical foam cleaning of the turbine. After cleaning, the HP turbine’s efficiency was significantly improved.

Cinergy awarded the contract to HydroChem to chemically clean Unit 5’s HP turbine. The first task before cleaning could start was to develop a procedure to provide adequate isolation of the HP turbine. Isolating the turbine prevents the chemical cleaning solution from migrating to other areas of the steam turbine and associated equipment. To isolate the HP turbine required cutting and modifying the steam piping systems (Figure 3).

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Prior to chemically cleaning the turbine, with the turning gear in operation and the first stage inner metal temperature at 170 F, condensate water with a non-chemical foaming agent was pumped through the turbine. After determining that the HP turbine was isolated and no leaks were visible, the HP turbine was cleaned using a chemical foam.

During the cleaning process, the foam was injected into the turbine through an injection valve that replaced one of the four turbine control valves. As the chemical foam passed through the rotating and stationary blades of the HP turbine, any copper deposits in the system were dissolved by the foam solution.

After leaving the HP turbine, the copper laden solution was passed through the cold reheat piping where an anti-foam solution was injected to change the foam to a liquid. The waste liquid was transported to a waste tank, prior to it being disposed off-site.

After completing the chemical cleaning, the HP turbine was rinsed using the same solution as that used for initial system testing. Final cleaning of the system, which took approximately 15 hours, was achieved by injecting saturated steam through the HP turbine. Figure 4 shows the reduction of copper from start to completion of chemical foam cleaning.

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The total time for the chemical cleaning, not including unit startup, was 136 hours. A sample of the waste liquid indicated that 30 lbs of copper deposits were removed from the HP turbine. Without chemical cleaning the plant would have had to schedule at least a five-week outage for the disassembly, cleaning and reassembly of the turbine.

As the electric generating industry continues to evolve, electric generating plants must continue to change the way they operate and maintain their plants. To survive, utilities must respond quickly to changing market conditions.