Best practices are the foundation of continual-improvement programs implemented by generating plants to help ensure top performance on a predictable and repeatable basis. In 2016, plants powered by gas turbines (GTs) were recognized by the COMBINED CYCLE Journal’s Best Practices Awards program for their achievements in water management, O&M, performance improvement, fast-start procedures, monitoring and diagnostics, outage management, and safety.
Most of the 50 or so best practices submitted to the editors last year were profiled in the first three 2016 issues of the CCJ. If you missed them and your back copies aren’t within reach, you can access these valuable ideas online using the search function provided towards the top of every page. The final group of 2016 best practices appears in the fourth-quarter issue now in the mail and full versions will be available online in the coming weeks. They are summarized below.
Fast starts/performance improvement: Colusa, Chaves
Financial success for many conventional generating plants today depends on their ability to start quickly and operate flexibility to accommodate the unpredictability of must-take renewables. To achieve its goal of staying on the leading edge of renewables integration, PG&E’s Colusa Generating Station implemented a so-called agility controls package and installed a heating blanket on the steam turbine.
The former features improved startup automation and software that enables fast, reliable, and repeatable ST hot, warm, and cold starts. The heating blanket cut ST hot/warm start times from 81 minutes to less than an hour, and allowed faster loading of the steamer—reducing the ramp time by approximately half. The improvements saved an average of 66 million Btu in fuel per start and reduced CO and NOx emissions by an average of 52.5 and 75 lb per start, respectively.
The Aureliano Chaves Power Plant, owned by Ibiritermo SA and operated by Petrobras, was challenged to improve its starting reliability and reduce the time to breaker close. The Brazilian plant’s technical staff saw an opportunity for conserving resources (fuel, cooling water, personnel time, etc) and starting faster and more reliably by reducing the time to pull vacuum. Addition of a vacuum pump to supplement the capability of the hogging ejector reduced by two hours the time to start the plant.
Water management: Faribault, Rokeby, Amman East
Minnesota Municipal Power Agency’s Faribault Energy Park constructed a system of clay-lined ponds to reduce the plant’s burden on the local aquifer, collect and reclaim storm-water runoff for plant use, and provide a place where the community can fish, picnic, and walk trails. The conservation of groundwater can be significant: The 6 million gal collected during one unusually high-rainfall month was sufficient to support plant operation for about 100 hours.
In addition, the plant O&M team implemented several methods for reducing cycle water consumption. An example is a simple but effective program for monitoring makeup flow to the condenser. An increase in flow is indicative of steam or water leaking from the facility. Ultrasonic probes and an infrared camera then can be used to pinpoint leak location.
Plant management at Lincoln Electric System’s Rokeby Generating Station shared its experience on plant infrastructure improvements and expansions that affected more than just generation assets. Case in point: The facility’s original sanitary lagoon could not meet the needs of the growing plant. This triggered periodic material removal by an outside contractor, the cost of which continued to increase as additional non-sanitary discharge points were directed to the system.
Plus, regulations covering lagoon design had been updated since the original lagoon was installed and it no longer met county permitting requirements.
Plant personnel conducted an audit of plant wastewater and rain-event flows and determined the sanitary and site drain flows should be separated. The treatment system designed to accommodate all existing plant waste streams relies on a standard sanitary lagoon, and a bio-retention “rain garden” for storm-water and oily-water-separator discharges. Some permit modifications were required. A side benefit of the project was updated underground utility drawings and a beneficial reconfiguration of the oily water separator system.
AES Jordan PSC’s Amman East Power Plant is located in an area with minimal water resources. The plant’s “Put Safety and Environment First” program identified the following five areas with an opportunity for reducing water consumption:
1. Water supply network for the fire protection system was divided into zones and monitored for leakage, valves were upgraded, fire-system relief valves were modified to discharge to the raw-water storage tank rather than to drains, etc.
2. Evap-pond water is recycled for HRSG-blowdown cooling instead of using raw water.
3. Water-saving devices were installed in service rooms and restrooms.
4. Plant startup procedures were modified to minimize water use. Examples: a reduction in steam venting and faster ramp.
5. A treatment system was installed to allow use of evap-pond water for site irrigation.
Success! Water consumption was reduced by more than 25,000 gal/day; annual financial benefit was $25,000.
O&M: Faribault, Ferndale, MPC Generating, AL Sandersville
Faribault Energy Park’s HRSG experienced several reheater tube failures, all located at the end of a tube bundle. The lower header had only one drain line in the center, inadequate to handle the flow required. Result was an accumulation of water at the far end of the header causing those tubes to remain cooler and subjected to stretching as the hotter tubes in the bundle expanded.
The fix: A second drain line was tapped into the header where water accumulated, the original manual drain valve was replaced with an automated one and a thermocouple installed in the drain line, and a level transmitter and condensate pot were installed for moisture detection. No tubes have cracked since the modifications were made.
When Puget Sound Energy’s Ferndale Generating Station was commissioned in 1994, the operator interface in the control room consisted for four Bailey OIS 20 proprietary consoles with 19-in. 640 × 480-resolution CRT displays and an alarm printer tied to the DCS. Next step in controls evolution, in 2003, was a Wonderware upgrade with four InTouch operator stations (21 in., 1024 × 768 CTRs). Market changes, etc, dictated automatic generation control in 2015, requiring an operator-interface solution to allow more effective information exchange.
Project cost was a management concern. The four Wonderware computers were reconfigured to support two monitors each (total of eight 40-in. flat-panel LED displays). Another four 40-in. monitors were installed to display alarms, weather, and feeds from security cameras. Additionally, three 24-in. monitors were installed to accommodate the turbine controls at this 2 × 1 combined cycle.
Plant personnel designed and installed, during normal work hours, a custom structure to support the monitors using standard steel pipe joined by aluminum fittings of the type typically specified for handrail systems. The 15 high-definition monitors reduce eye strain and are arranged in a horseshoe configuration to minimize operator fatigue. Total out-of-pocket cost to the plant: About $7500.
MPC Generating LLC, operated by Cogentrix for Southeast PowerGen LLC, has, among its assets, a simple-cycle gas turbine with a hydrogen-cooled generator. The coolant is supplied from a bank of 12 bottles which are replaced when gas pressure drops to about 300 psig. During an abnormal weekend weather event an excessive amount of hydrogen was consumed, pressure dropped dramatically, the unit tripped, and the generator vented. The peaker was unavailable for several hours while the generator was purged with carbon dioxide and recharged with hydrogen.
Determined to prevent a repeat of this scenario, plant staff designed and installed an independent emergency hydrogen supply line with a separate and dedicated redundant bank of bottles. The redundant line, arranged in parallel to the normal supply, has a dedicated pressure regulator set 10 psi less than the normal hydrogen supply pressure of 70 psig. If the pressure drops to 60, the emergency bank provides the hydrogen without operator intervention—thereby avoiding a unit trip.
AL Sandersville, another Southeast Power Gen facility operated by Cogentrix, relies on 13.8-kV cables in elevated trays for delivering the output from its eight simple-cycle generators to the step-up transformers. An inspection revealed the wood cable spacers in various stages of deterioration and cables sagging. Decision was to replace the wooden spacers with HDPE plastic spacers.
Challenge: Swap out the spacers safely and without the use of a crane, because of space constraints. Bids indicated a one-month effort and cost of nearly $70,000 (labor only). Unacceptable. Plant personnel designed and built a cable lifting rig that mounted directly on the bus tray to lift the cables safely and without damage. They also self-performed the work during scheduled spring and fall outages.
Safety: Rathdrum, Amman East
Rathdrum Power Plant, managed by NAES Corp for Tyr Energy, is an OSHA VPP facility. Management’s ongoing challenge to the facility’s team members: Be vigilant for identifiable safety-related improvements. An identified hazard was submitted detailing the inherent risks of allowing continued vehicular traffic flow during chemical and hydrogen-gas offloading.
Without a manned security gate, plant personnel determined a method for effectively restricting traffic flow to one direction or the other during transfer evolutions was necessary. The solution both simple and practical: Safety-yellow plastic chains can be deployed across the road at four locations, as necessary, to restrict traffic to the two identified areas. Plastic was selected over metal because of the maintenance associated with the latter in an industrial environment influenced by cooling-tower drift. The chains are retained in garden-hose-type reels mounted roadside.
Amman East’s two dual-fuel gas turbines have been forced to operate on oil since 2011 because of a “political situation.” Typically, 30 to 36 tanker trucks are received daily at the plant’s six-vehicle unloading bay. A safety concern was the need for a contractor to climb up on each truck to open its top hatch, thereby creating a fall hazard from a significant height. A full-body harness with static lifeline was the original safety solution. However, the concrete bases anchoring the cumbersome static lifelines were damaged frequently by truck movement.
Plant personnel first thought to redesign the lifelines and modify their concrete bases consistent with the latest safety standards. An alternative idea was to design and build a mobile platform capable of serving two trucks simultaneously to make unloading more efficient, more reliable, and safer. A study supported this thinking, but bids were higher than the plant could afford.
So the work was brought in-house. Plant personnel designed the system and contracted out its fabrication. Three platforms ultimately would be required but the second and third would not be ordered until the first confirmed functionality, safety, etc. Success confirmed, the remaining two platforms were fabricated and installed as well.
Monitoring and diagnostics: Bayside
Tampa Electric Co’s H L Culbreath Bayside Power Station has seven 7FA.03 gas turbines equipped with DLN 2.6 combustion systems. The OEM has supported the plant under a contractual services agreement since the first unit began commercial operation in 2003. In 2015 the utility began participating in a remote M&D pilot project spearheaded by GE’s Power Services business and its Intelligent Platform’s Smart signal predictive diagnostics software and services team.
Prior to the existence of the M&D Center, many combustion and other issues might not have been detected by station personnel until they caused hardware damage or a unit trip. Plus, before the development of remote combustion tuning capability via the M&D Center, field specialists had to travel to the plant for this purpose.
Bayside’s Best Practices submission describes a couple of alert conditions fielded by the M&D Center and how they were handled—in particular a remote tuning solution that improved flame stability and reduced dynamics, thereby reducing the risk of unit trips from lean blow-out. Quick response to the issues affecting two GTs were said to have enabled Tampa Electric to be proactive in keeping the plant operating during a challenging summer that required record generation to meet demand.