Asset Management: Determining an Optimal Plan for an Upgrade at Ludington

To determine the work required to rehabilitate and upgrade the pump-turbines at their 1,872-MW Ludington plant, Consumers Energy Company and Detroit Edison Company undertook a comprehensive condition assessment and life extension study. Using information from this assessment allowed the companies to develop an optimal upgrade plan.

By James L. Topper, William J. Axdorff, David J. Sonntag, and Robert A. Rittase

The 1,872-MW Ludington pumped-storage plant uses Lake Michigan as its lower reservoir. The plant, which began operating in 1973, contains six 312-MW pump-turbine units that provide a valuable resource, as they are able to adapt to large swings in electricity demand.

In the late 1980s through the mid-1990s, owners Consumers Energy and Detroit Edison performed major unit overhauls to repair cavitation, reduce gate leakage and replace wicket gate bushings. The owners knew a second round of major overhauls would be required for the plant to continue operating reliably. They planned to begin these overhauls in 2013. However, Consumers Energy and Detroit Edison needed to determine the scope of work required.

In 2006, the owners hired Devine Tarbell and Associates to perform a condition assessment and life extension study of the plant. The purpose of this study was to develop a scope of activities for the major unit overhauls. In recognition of the technology improvements made since the units were commissioned, the study examined options for increasing the availability, capacity, efficiency, reliability and overall operation of the plant.

The process used for Ludington provides a good template for the testing and analysis necessary to evaluate overhaul opportunities at a pumped-storage facility. Studies such as this develop useful information that can be used to provide valuable assessments of plant condition. These assessments can then be considered when planning for major unit overhauls. This same information can be a starting point for an even more involved evaluation of the potential to upgrade facility performance. Either effort requires a commitment on the owner’s part to make the facility available for a detailed evaluation.

FIGURE 1 Ludington Pump-Turbines

The pump-turbine units at the 1,872-MW Ludington plant have been operating since 1973 and will be overhauled beginning in 2013. The goal of this overhaul and upgrade is to maintain reliable operation of the facility and potentially increase availability, capacity, efficiency, and reliability of the units.

Condition of the plant

The Ludington units have numerous issues that require systematic maintenance and a scheduled outage every two years. This maintenance system is effective, resulting in a random outage rate of less than 0.8 percent in 2005. Cavitation repair on the pump-turbine runners represents the bulk of the maintenance activity during the scheduled outages. This repair is supplemented by an extensive non-destructive examination (NDE) of the runners to check for cracks.

Other major problem areas that have caused forced outages are: cracking of the runner crown cover plates and various problems with the thrust bearings. In fact, at the time of the study in 2006, Unit 5 was not operated as a pump due to concerns with possible thrust bearing failure.

Typical observations at the plant included:

  • Electrical and controls equipment obsolescence, including load break switches, motor-driven exciters, and protective relaying;
  • Stator core waviness and deterioration;
  • Shaft seal wear and leakage;
  • Wicket gate leakage;
  • Generator air cooler problems;
  • Bearing and bushing wear;
  • Coating deterioration or loss; and
  • Stator winding corona.

Deciding to perform the study

By the time the second round of major overhauls begins, the plant will have been operating for 40 years. Also, technology has improved since the units were commissioned, providing the possibility to improve plant availability, capacity, efficiency, reliability, and operation.

DTA investigated two potential scopes for this study. The first was a base scope, consisting of investigating just the work necessary to enable the units to operate with at least the same availability, efficiency and reliability as was achieved after the first round of overhauls. The second was an upgrade scope, investigating the work necessary to enable the plant to achieve the maximum net benefits in improved efficiency, capacity and performance.

For either scope, the guiding premise was to identify all work that would need to be completed to operate the plant efficiently and reliably during the next operating license period. This operating period will begin in 2019 and is assumed to last 30 to 50 years, and the owners assume that the plant will undergo one set of major overhaul outages, planned for the middle of the period.

DTA used several methods to gather data. This included interviewing plant personnel; reviewing plant drawings and other documents; inspecting the pump-turbines, generator-motors, and auxiliary equipment; performing NDE of high-stress areas; performing index and vibration testing of the units; doing heat run testing on the generator-motors, bus, and transformers and performing thrust bearing testing. Figure 1 shows the structure of the units.

FIGURE 2 Turbine Alternatives

An evaluation of five hydraulic options for turbine mode at the 1,872-MW Ludington pumped-storage plant indicates that installation of new high-capacity runners and modification of the stay vanes would provide the highest long-term benefit.

Index testing

Index tests were performed on two units to establish a baseline for the unit performance characteristics. DTA and plant personnel performed a series of these tests to measure power consumed during pumping mode and produced during generating mode. Pressure and water level also were measured to allow calculation of net head and head loss. To determine a relative unit flow rate, differential pressure was measured in both operating modes, at various gate openings. Because the units are not equipped with instrumentation for flow measurement, absolute performance testing was not possible.

These data were used to determine relative unit efficiency in both modes. These efficiencies then were used as input to an analysis intended to estimate the actual operating performance of the units.

An immediate benefit to the plant was readjustment of the pump cycle cam curve. Changes to the head versus gate opening curve in the pump control system resulted in performance improvements of up to 1 percent at low head.

Vibration testing

Vibration measurements of three units were carried out in parallel with the index testing to develop an overall “signature” of the units. In addition to providing information about unit status as input to the base and upgrade scopes, this testing was intended to determine areas of immediate concern that should be addressed during normal maintenance.

Instrumentation used included:

  • Proximity probes and accelerometers on all bearing housings and brackets;
  • Pressure transducers in the spiral case and draft tube cone;
  • Pressure transducers for measurement of servomotor oil pressure; and
  • Instrumentation used as part of the index testing.

Vibration testing showed the generator-motors had good mechanical and magnetic balancing of the rotors and that they were well-centered in the stator magnetic field. However, the generator-motors had higher vibrations at pole passing frequency (120 Hertz) than what is usually observed in units of this type, possibly indicating loose stator wedges. The presence of loose wedges was confirmed during an inspection, and the owners have rewedged the Unit 1 stator.

Start up in pumping mode proceeded well. In the steady-state pumping mode, the units operated smoothly, with the exception of operation with a high water level in the upper reservoir, when the unit became unstable at high gate opening. Pressure pulsations of up to 85 feet were observed in the spiral case during unstable pumping, confirming the inability to restart this unit as a pump at this high head.

Heat run testing

Electrical, magnetic, mechanical and thermal testing and analyses of the generator, buswork and transformer were conducted to determine the condition of the electrical systems. Data were collected to determine if cooling system improvements would be required for both the expected remaining life of the equipment and potential increased generation. Test data were used to develop saturation curves, generator segregated losses and generator efficiency. This was the first heat run test performed on these units.

Instrumentation needed included:

  • Resistance temperature detectors and thermocouples to measure temperature rise of air, water, and equipment;
  • Flow meters for water and oil; and
  • Electrical meters to measure electrical operating characteristics.

Testing and an insulation remaining life analysis showed that the stator winding would have a remaining life of less than the desired time period between major unit overhauls, regardless of performance upgrades.

FIGURE 3 Pump Rehab Alternatives

An evaluation of five hydraulic options for pump mode at the 1,872-MW Ludington pumped-storage plant indicates that installation of a new runner with no capacity increase but with modification of the stay vanes would provide the highest efficiency level.

Thrust bearing testing

There were several reasons for this testing: to assess the conditions under which the thrust bearing system operates, to understand the causes of the reduced thrust bearing life and frequent thrust bearing failures and to provide input for modification of the thrust bearing system or recommendations for design of a new system. Empirical data from three different investigations were analyzed:

  • Laser mapping of the thrust runner and thrust shoes of Unit 1. The metrology of the thrust runner and thrust bearing shoes allowed for a better understanding of the wearing faces of the thrust bearing system;
  • Hydraulic thrust analysis of Unit 1. Direct hydraulic thrust measurements provided information about the loads the thrust bearing system experiences. A proximity probe was mounted on a beam beneath the lower bridge, and the hydraulic jack system was used to remove the weight of all the rotating components from the lower bridge. By measuring the deflection as the load was removed, the spring constant of the lower bridge was calculated. Knowing this constant, the hydraulic thrust during different modes of operation was determined by measuring the downward deflection of the lower bridge during operation; and
  • Thermodynamic analysis of the oil. This analysis provides an evaluation of the thrust bearing system by measuring the temperatures of the thrust bearing oil and cooling water during generating and pumping operation.

There were two results of this testing. First, the thrust bearing is overloaded. During pumping, the measured value exceeded the OEM-expected value by 134 percent, indicating a severe overload from the original design conditions. A review of the hydraulic design indicates that the primary cause of the high hydraulic thrust is the inadequacy of the head cover thrust relief system.

Second, laser mapping of the thrust runner found the bearing surface to have a slight concavity, indicating a reduced load-carrying ability for the bearing.

Determining upgrade potential

Once data gathering was complete, DTA used the results to perform various analyses. These analyses, intended to help DTA determine the upgrade scopes for the overhaul of the units, included:

  • Remaining life analysis of the pump-turbine runners;
  • Hydraulic performance and upgrade analysis;
  • Transient hydraulic analysis to determine possible water conveyance system limitations;
  • Generator-motor electrical and mechanical analyses; and
  • Economic analysis of various upgrade options.

Remaining life analysis of the pump-turbine runner 

During the unit inspections, NDE of high-stress areas was performed on the generator-motor rotor and pump-turbine runner. NDE of the runner included dye penetrant and ultrasonic examination at the junction of the blade with the crown and band. Numerous crack indications were discovered. Eight of these indications were used in a fatigue and remaining life analysis.

The analysis used static and dynamic stress levels from finite element analysis results and field strain gage testing results from a similar pump-turbine runner, as well as the material mechanical properties of the Ludington pump-turbine runner.

NDE established the existence of several crack indications at the pump-turbine runner blade-to-crown and blade-to-band joints, which are the typical high static and dynamic stress areas for pump-turbine runners. A fatigue and fracture analysis was performed to study eight of the indications and to determine the remaining life of the pump-turbine runner based on the calculated growth propagation of the indication. “Remaining life” was defined as the time required for the indications to propagate through the entire thickness of the runner blade.

Remaining life depends on the size, type, and depth of the indication. It was not possible to evaluate the indication’s depth due to the presence of stainless steel strips that were a part of the OEM-provided cavitation protection system.

The analysis indicated that the shortest life expectancy for these pump-turbine runners was 42 years (from 2006). A sensitivity analysis was performed to determine the effect on remaining life of varying the depth of each of the selected indications. An indication depth of 0.2 inch was used for the basis of the remaining life analysis.

Another sensitivity analysis was performed to determine the effect of a change in the number of expected future start/stop cycles on remaining life. Increasing the number of start/stop cycles by 20 percent reduced the estimated remaining life to 29 years.

Hydraulic upgrade analysis

The results of the hydraulic analysis were used in the electrical and mechanical scoping, transient hydraulic and economic analyses to determine the optimum plant upgrade. Index test data and historical generation data were used together with the empirical analysis to define the absolute efficiency of the pump-turbines. Alternatives that were considered in the analysis included:

  • Overhaul of the pump-turbines without hydraulic modification;
  • Overhaul of the pump-turbines with modifications to the stay vanes to improve efficiency;
  • Replacement of the pump-turbine runners with new runners having about the same capacity, but optimized for maximum efficiency in both the pumping and generating modes and with modifications to the stay vanes;
  • Replacement of the pump-turbine runners with new runners having an intermediate increase in capacity and with stay vane modifications; and
  • Replacement of the pump-turbine runners with new runners having the maximum obtainable capacity and with modifications to the stay vanes.

An empirical method (as opposed to a numerical technique) was used to estimate the performance of modifications to the water passageway geometry and/or replacement of major components of the pump-turbines. This method was selected based on DTA’s experience with similar pump-turbine upgrade cases. The hydraulic performance of modifications and/or replacement of major components of the pump-turbines at Ludington were derived from the performance of a similar, recently model-tested machine.

A systematic approach was used to analyze components, consisting of:

  • Determining hydraulic conditions and performance of the existing unit;
  • Estimating the point of peak efficiency or design point of the upgraded unit: speed, net head, and discharge;
  • Selecting a similar, recently tested baseline model machine;
  • Sizing the baseline machine to achieve the design point parameters;
  • Evaluating the geometries of the upgraded and baseline machines for hydraulic losses; and
  • Estimating the expected performance of the upgraded machine.

Performance of the pump-turbines differed from the OEM’s performance curves due to changes in model-to-prototype step-up procedures and deterioration of surface finish and geometry since the units were installed. Using this information and the method described above, estimates of the expected performance of each upgrade option were developed (see Figures 2 and 3).

FIGURE 4 Load Rejection Simulation

Results from a transient hydraulic analysis of the units at the 1,872-MW Ludington pumped-storage plant indicated it should be possible to increase flow capacity by 15 percent.

Electrical upgrade analysis

Analysis of the data developed during electrical testing indicated several limitations in the electrical system upgrade. Actions required to correct these limitations included reinsulation of the generator-motor stator leads and rotor pole coils with Class F insulation, replacement of the rotating exciter with a static exciter, replacement of the stator air coolers with higher-capacity coolers and increasing transformer cooling with higher-capacity fans.

A similar analysis of the generator-motor was performed to determine mechanical constraints that could limit the electrical upgrade. Mechanical components and systems that were determined to be below standard factors of safety for a unit upgrade were:

  • Wedge pressure for radial restraint of the windings would be inadequate;
  • End plates would not properly support the amortisseur bars or the winding in the event of turbine runaway;
  • The main shaft would be below standard factors of safety with an upgrade in unit power; and
  • Insufficient information was available regarding the spider shaft torque keys. Further study would be required after disassembly of the first unit.

A detailed study of these critical mechanical components will be undertaken when the overhauls are performed.

Transient hydraulic analysis

A transient hydraulic analysis of the existing units and water conveyance system was conducted. The purpose was to determine the feasibility of increasing plant output through replacement of the pump-turbine runners with more efficient and/or higher capacity runners that could operate at flows of up to 15 percent greater than the original design flow.

DTA developed a numerical model for simulation of hydraulic transients and calibrated it with load rejection testing and original plant commissioning test results. The model was used for checking the hydraulic transients (i.e., maximum unit speed rise and pressure rise in the water conveyance system) in the event of an increase in unit capacity. Each unit at Ludington has its own penstock.

The transient hydraulic analysis indicated that it should be possible to increase unit flow capacity by 15 percent with respect to the pressure and speed rise resulting from hydraulic transients (see Figure 4).

The analysis results also showed that by modifying the wicket gate closure timing, reduced speed rise and reduced pressure rise could be obtained. These results were the same with either the original design or the upgraded flow capacity.

The design of a replacement pump-turbine runner will affect the transient hydraulic behavior. Because of this, an updated transient hydraulic analysis should be performed if a replacement runner is selected.

Economic analysis of upgrade options

An economic analysis of the upgrade options was conducted. The results from the economic analysis were used, along with the estimated costs associated with each of the upgrade options, to provide an overall cost/benefit evaluation.

Each potential upgrade option was simulated in an economic model using an energy and capacity forecast from the owners. In addition to the upgrade options, the economic model simulated the value of other options, including:

  • Conducting the outages required for the overhaul/upgrade work in the winter instead of the summer;
  • Restoring Unit 5 as a pump before the next round of major overhauls; and
  • Performing case studies to determine the value of pumping and generating capacity and efficiency.

To calibrate the model, an hourly benchmark analysis of Ludington operations from Jan. 1, 2006, through Dec. 31, 2006, was simulated. The analysis investigated four historical price data series — day-ahead and real-time prices for the Michigan Hub and the Ludington locational marginal price. It became apparent that, without adjustment, the model would over-optimize the plant dispatch and produce more generation than history indicated.

There were two explanations for the differences between the model and historical data. First, the model has perfect foresight of forecasted prices and will optimize operations to maximize gross marginal revenue. Second, personnel at Ludington hold back generation to provide ancillary services and to meet other secondary grid operations.

To match forecasted and actual generation, DTA used historical generation to develop a monthly generation holdback profile for the 2006 benchmarking period. This profile was assumed to apply for the entire simulation period. When combined with cost estimates, the economic analysis reached these conclusions:

  • The additional cost of a winter outage is offset by the benefits of increased revenue during the peak summer periods;
  • A separate outage for restoration of Unit 5 as a pump is economically viable;
  • Stay vane modifications are cost-effective whether or not the runners are upgraded; and
  • Upgrading for maximum capacity provides the greatest overall benefit.

Based on the condition assessment and life extension study, the plant owners have decided to proceed with overhaul and upgrade of the Ludington facility. New components are now being manufactured, and the first outage is expected in 2013.

James Topper, P.E., a member of Consumers Energy Company’s Engineering Services Department, was the company’s engineering lead for the assessment. Bill Axdorff, P.E., is a senior engineer with Consumers Energy and was project manager for the assessment at the 1,872-MW Ludington pumped-storage plant. Dave Sonntag, P.E., a member of Detroit Edison’s Integrated Resource Planning Group, was the company’s liaison for the assessment. Bob Rittase, P.E., is a senior consultant for HDR|DTA and manager of the York, Pa., office. He was HDR|DTA’s project manager for the assessment work.

This article has been evaluated and edited in accordance with reviews conducted by two or more professionals who have relevant expertise. These peer reviewers judge manuscripts for technical accuracy, usefulness, and overall importance within the hydroelectric industry.

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