Best practices among technical highlights of 7F Users’ upcoming meeting, May 7 – 11

Only a few weeks from now, owner/operators from around the world will gather in Atlanta for the 7F Users Group’s annual Conference and Vendor Fair—the largest event of its type for frame engines. Don’t miss the opportunity to meet with user colleagues, the OEM, and third-party products/services providers under one roof. Register today! 

Last year, for the first time, discussion of fleet-wide best practices was incorporated into the Top Issues session on Wednesday afternoon. This addition to the program, a collaboration between the 7F Users Group and CCJ ONsite, was received positively and will return with fresh material in 2018. If you didn’t attend last year, a review of the best practices discussed—they rarely go out of date—is a way to catch up with your colleagues. Brief summaries follow. One or more might find application in your plant.

Purge air keeps moisture from entering isophase bus duct, Vandolah Power.

Moisture intrusion into isophase bus duct caused the PT and some electrical connections to fail after rain events. Water leaking into the GSU bushing enclosure would travel down the bus duct into the generator breaker enclosure. Short-term solution was to repair the leaks on the GSU and fix the modification flaw on the A-phase bushing enclosure introduced during plant construction.

Long-term solution options were (1) installation of a positive-pressure system for the bus duct and (2) a purge-air system using instrument air to lower the overall dew point in the bus system and absorb moisture. The latter, much less expensive than the former, was selected. Purge air is supplied to the bus duct, the secondary side of the plant’s four GSUs, and the primary side of the two auxiliary transformers at 2.5 psig. All work was done by plant personnel.

Acoustic monitoring provides early leak detection, T A Smith Energy Facility

Acoustic monitoring was shown to identify and monitor both HRSG tube leaks and attemperator leakage/leak-by more effectively than such alternatives as flow-measuring devices and valve-position indicators. A collaborative program among the plant, Mistras Group, and EPRI, confirmed the technology’s capabilities. Benefits include the following:

    • Allows owner/operators to manage HRSG tube leaks until planned outages by minimizing the number of thermal cycles on the unit.

    • Enables staff to better understand potential economic impacts from specific operating profiles.

    • Detects leak-by in spray and/or block valves believed “closed,” thereby minimizing the possibility of tube cracking attributed to quenching by water.

Training for this generation and beyond, T A Smith Energy Facility

A partnership between the plant and Technical Training Solutions in the development of in-house computer-based training programs for both Mark VI GT controls and advanced D-11 steam-turbine controls promotes operational excellence at affordable cost. The total solution incorporated two full weeks of instructor-led training onsite for more than 15 students, plus access to upwards of 75 existing training modules for one year for the staff of 33. Plant management believes this program saved more than $250,000 over a comparable offsite training initiative.

Ultrasonic detector pinpoints small gas-turbine leaks offline, Plant Rowan

Small leaks are a near certainty in any fluid system with gasketed joints subjected to numerous thermal cycles. Most leaks outside the gas-turbine compartment generally are easy to identify on site walk-downs when the plant is operating. Not so inside the compartment because entry with the engine in service usually is prohibited or restricted.

The latest hydrocarbon imaging cameras can be useful for identifying natural-gas leaks, but when the GT is operating, excessive turbulence inside the compartment from ventilation fans makes finding them difficult—if not impossible.

Personnel at Plant Rowan check their gasketed joints using an ultrasonic detector (UE Ultraprobe® 3000) with the engine in “crank” mode. There is ample compressor discharge pressure, back-fed from gas nozzles and diffusion-air and atomizing-air connections, to verify the integrity of all gas pigtails, flanges, and tubing—even gas-control-valve flanges and packing. Plus, the ninth- and 13th-stage extractions, second- and third-stage nozzle cooling, and pipe flanges for the inlet-bleed-heat system as well.

Concrete wall facilitates cleanout of cooling-tower basin, Rathdrum Power Plant

A downside of Rathdrum’s zero-discharge system is that the plant is not permitted to discharge the large volume of cooling-tower water during outages, challenging staff in the removal of soda-ash solids that accumulate in the basin and would plug the facility’s plate-and-frame heat exchangers if allowed to remain there.

Some of the water could be transferred to onsite holding areas and tankage but they could not hold all of the huge volume required. Baker tanks were an option, but many would be required and they are expensive to rent. Engineered solution: build a gated wall across the basin, pump water from one side to the other, clean the side pumped out, transfer the water to the clean side, and clean the other side. Success!

Leak-testing gas-turbine systems with helium, Nuevo Pemex Cogeneration

Nuevo Pemex relies on helium tracer gas and a sensitive helium detector to find air leaks in the gas-turbine inlet ductwork, expansion joints, manhole seals, defective welds, etc. Even small leaks are of concern in this refinery environment to prevent compressor fouling, erosion effects of entrained particulates, etc.

Staff modified a ninth-stage compressor water drain pipe to accommodate a sampling port and instrumentation to detect the presence of helium sprayed in leak-prone areas, to pinpoint where repairs are necessary. Feedback is virtually instantaneous: It takes only about two seconds for the helium to get from the area being inspected to the instrumentation.

Using HRSG water to heat GT fuel gas, Nuevo Pemex Cogeneration

Nuevo Pemex initially operated as a simple-cycle facility with an auxiliary boiler to supply hot water to the heat exchanger for preheating fuel gas. After single-pressure HRSGs were installed behind the plant’s two 7FAs, a hot-water extraction system was installed on each of the heat-recovery boilers and the fired unit was shut down. A drain in the bottom header of an economizer section where the water temperature is appropriate for heating the fuel gas is the source of supply. The bottom line: A heat-rate improvement of 1.6%.

Air attemperation system assures superheated steam on startup, Faribault Energy Park

During the early phases of plant startups, gas-turbine exhaust heats up HP superheater tubes in the HRSG faster than steam can transfer heat away from them. Control room operators sometimes address the problem by increasing attemperator sprays to near-maximum rates during startup, just prior to ramping the GT—this to prevent a runback caused by high metal temperature. However, excess sprays often create saturated steam conditions, which in combination with thermal cycling, contributes to downstream pipe, tube, and weld failures.

Faribault installed HRST Inc’s QuenchMaster™ air attemperation system to cool the GT exhaust before it contacts HRSG piping and tubes. A review of plant data had revealed steam conditions reached saturation dozens of time during each startup with engineers predicting HRSG parts with a normal expected life of 30 years would likely fail in about five under the plant’s proposed fast-start profile.

QuenchMaster guarantees 35 deg F superheat when in use, with actual results about 50 deg F or more for the starting profile analyzed. After nearly five years of service engineers are confident HRSG components will achieve near-original expected lifespans.

Cardox-tank double relief valves facilitate testing, maintenance, Calhoun Power

Relief valves for the plant’s Cardox tank were piped directly into the tank. Were there a sticking issue with either of the two relief valves, the tank would have to be emptied prior to doing any work. The tank also had to be emptied to test the relief valves.

Staff worked with a local vendor to make a “T” piping rig with a go/no-go switching valve so relief valves can be tested without removing the CO2 (photo). Testing is accomplished by swapping the valve and removing the offline valve. Money is saved because no CO2 is lost and a vendor does not have to be hired to remove CO2 from the tanks for testing.

Finally, several more best practices shared by 7FA-powered combined-cycle plants at last year’s meeting were profiled previously by the editors. If you missed them, just follow the links below:

    • Woodbridge Energy Center: Comprehensive plant heat-trace guide; Logic changes reduce blowdown quench-water, save $30,000 per month; Safety program minimizes the potential for arc-flash injuries; Trifold for contractors keeps critical site information readily available.

    • Green Country Energy: Recovering “non-recoverable” megawatts.

    • Nueces Bay and Barney M Davis Energy Centers: Healthy condenser makes for an efficient plant.

    • Effingham County Power:  Safe grounding of a generator step-up transformer; Relocation of flow transmitter eliminates freeze-up, fouling; Empowered technicians, inexpensive mod boost reliability; Lay up chillers dry in winter to protect equipment, save money.

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