Extending the economic operating life of aging steam plants remains a priority at many utilities, given the challenge of obtaining permits for new generation and the lower cost of life-extension projects. More than half of U.S. coal-fired plants are over 30 years of age, and 10% are more than 50 years old. These veterans still have a lot of fight left in them, given an overhaul or two. But such work can uncover unexpected ailments, as operators at the aging Cromby Generating Station (Figure 1) learned.
Exelon’s Cromby Generating Station, located in Phoenixville, Penn., consists of two units: Unit 1 is a coal-fired 144-MW plant; Unit 2 is a 202-MW unit that burns gas or No. 6 fuel oil, depending on market conditions. Unit 1 has accumulated more than 330,000 fired hours since it began commercial service in 1954. Unit 2, commissioned in 1955, remains a favorite dispatch unit in the Exelon fleet and dispels the myth that “it’s the miles and not the age” that determine when a unit should be retired.
Rotor transplant
Unit 2, the focus of this case study, is a conventional steam plant with a three-casing, single-driveline steam turbine (one HP, one IPâsingle-flow LP [IP-SFLP], and one double-flow LP [DFLP]) originally built by Westinghouse (Figure 2). Mitsubishi Power Systems Inc. (MPS) was awarded a contract to retrofit and upgrade the steam turbine to extend its service life. Generating 4% more power with the more-efficient turbine was a welcome side benefit of the project.
Figure 2 also illustrates the unit’s rotor bearing arrangement. In this configuration, bearing No. 4, between the IP-SFLP and the DFLP (bearing No. 5), is shared by the two cylinders. Figure 3 compares cross sections of the old and replacement HP steam turbines.
The retrofit project replaced the HP rotor and diaphragms but reused the existing outer casing. The original Curtis control stages were replaced with a single, higher-efficiency Rateau stage, and the reaction blades were redesigned with the latest 3-D design tools. The HP turbine’s inner casing, blade, and dummy rings were replaced; the HP rotor bearings were rebabbitted; and thermocouples for bearing metal temperature were installed. Farther down the driveline, one row of LP L-0 blades and three rows of LP L-1 blades were replaced. The addition of orthogonal vibration measurement instrumentation completed the scope of work. Plant engineers showed excellent foresight in adding this new vibration instrumentation—as you’ll appreciate in a moment.
The upgrades were completed without incident, and the unit was started on November 17, 2003, for testing. Loading of the unit and overspeed tests were also performed without any major problems. However, vibration instability, or oil whirl vibration, in the HP bearings at low-load operating conditions was soon observed. In the following days, several field balancing runs were performed to reduce the vibration levels of bearings 3, 4, and 5. On November 20, after sustaining low-load operation for several minutes, a rather sudden synchronous vibration increase was recorded in bearing 2 (and in bearing 1 to a lesser extent) that prompted a trip of the unit.
During the coast-down, a sudden subsynchronous vibration spike was recorded at approximately 3,500 rpm with a filtered 0.5X value in excess of 15 mils (with direct readings of almost 20 mils).
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