Best practices shared by aero users benefit frame owner/operators as well

The Western Turbine Users and CCJ are working together to expand the sharing of best practices and lessons learned among owner/operators of GE aero engines. WTUI VP Ed Jackson, plant manager of Missouri River Energy Services’ Exira Generating Station in Brayton, Iowa, says the organization’s mission is to help members better operate and maintain their plants, and a proactive best practices program supports this objective.

Jackson announced the joint program at the user organization’s annual meeting two years ago, encouraging attendees to support the initiative and explaining how they would benefit from the experience. The latest fruits of that effort are the best practices profiled here, submitted by the 12 plants identified in the figure. Last year, eight plants participated.

Recall that CCJ launched its industry-wide Best Practices Awards program in late 2004. Its primary objective, says General Manager Scott Schwieger, is recognition of the valuable contributions made by owner/operator personnel to improve the safety and performance of generating facilities powered by gas turbines.

Industry focus today on safety and performance improvement—including starting reliability, fast starts, thermal performance, emissions reduction, and forced-outage reduction—is reflected in the lineup of proven solutions profiled below.

Safety

Lawrence: Custom platforms, modified access doors permit safe entry to filter compartment

Personnel at the 258-MW Lawrence Generating Station noticed a major design flaw and safety hazard in the generator filter compartment: Access doors on both sides of the compartment were located 20 ft above ground level, with no established means of access. In addition, a support beam blocked both doors’ travel, allowing them to open only about 10 in., restricting access to air filters and critical operating transmitters.

Plant’s safety committee brainstormed the problem and came up with a plan to add custom-built platforms, supported by existing structural members, to access the compartment. In addition, the top corner of each access door would be cut off, then reattached with hinges so it would swing out of the way, allowing the doors to open fully without obstruction (left photo). When bolted, the doors would still maintain their integrity (right photo).

Key steps in the solution included the following:

    • Engaged a structural engineer to evaluate and approve the design.

    • Installed permanent, separately supported platforms with handrails and vertical ladders to allow personnel to safely access elevated compartment doors.

    • Cut off the top corner of each access door using a triangular “Nabisco cut,” and reattached the corners with stainless-steel hinges.

Today, filter changes, calibrations, and damper maintenance can be done safely, quickly, and conveniently without the need for extension ladders, scaffolding, or fall-arrest protection.

During peak operation last summer, Plant Robert VanDenburgh’s staff discovered an additional, unanticipated benefit of the access solution. When a damper actuator failed, it caused the filter-compartment temperature to rise rapidly. The unit was ready to trip offline because of the excessive heat, but operator on duty accessed the inlet door quickly and opened the Nabisco cut, which provided enough air flow to arrest the temperature increase and give personnel time to get the damper open and restore normal operations.

Lawrence, owned by Hoosier Energy and Wabash Valley Power Assn, and operated by NAES Corp, is equipped with six LM6000 simple-cycle engines.

Pinelawn: Cart built by OMTs promotes safer handling, storage of lifting devices

Chain falls and come-alongs are available in various sizes (based on load rating) with varying lengths of operating (pull) chain and load-bearing chain. Carrying these devices introduces a safety hazard since they can be heavy and their long chains make them cumbersome to handle when walking. Plus, they require periodic lubrication to maintain good working order, but drips of lubricants can present both an environmental and a slip/trip hazard.

Pinelawn’s OMTs built a wheeled transport cart constructed primarily of angle iron, tubular steel, wood decking, and eyelets to both store and transport the site’s chain falls and come-alongs in a safe and environmentally responsible manner. The lifting devices are hung from the eyelets and their chains are stowed in 5-gal buckets to allow for neat storage as well as capture of any oil drippings (photo).

Pinelawn Power, owned by J-Power USA and operated by NAES Corp, is an 80-MW, dual-fuel, 1 × 1 combined cycle managed by Kenneth Ford.

Shoreham: Filling of lube-oil reservoir made safer

The turbine lube-oil reservoir at Shoreham Energy, a two-unit, 90-MW peaking facility, offered no accommodation to add oil other than to stand on top of an adjacent motor and manually add the fluid through a fill port at the top of the reservoir using a 5-gal bucket.

Over time, multiple investments were made to provide a more stable, more secure, and safer means for adding oil to the reservoir. A wheeled cart, with a self-contained oil reservoir and pump (photo left) proved the best method, enabling staff to add oil by simply running the hose to the top reservoir, into the fill port, and starting the pump. When complete, all that was required was to stop the pump.

However, this method proved cumbersome in that great care was needed to ensure oil would not spill from the hose once removed from the fill port. Addition of a tee, with a quick-connect fitting, at the top of the reservoir on the return line from a recently installed oil purifier was the first step in a permanent solution. A compatible fitting on the discharge hose of the oil cart’s installed pump created a “leak-free” connection, making oil transfer safer, easier, and cleaner (photo right).

NAES Corp operates Shoreham Energy for owner J-Power USA.

REO Town: How to implement a natural-gas leak detection program

Shortly after commissioning, the REO Cogeneration Plant, a 100-MW, 2 × 1 combined cycle owned and operated by the Lansing Board of Water & Light, suffered several forced outages caused by natural-gas leaks in the gas compressor building and other areas. A root cause analysis revealed gasket damage at several flanged joints in the fuel handling system because of improper tightening and torqueing procedures.

Immediately after the RCA was completed, Roberto Hodge, director of electric production, and Plant Manager Tom Dickinson ordered the replacement of all gaskets in the fuel handling system to mitigate safety and financial risks. Proper flange applications and torqueing procedures were carefully implemented.

Next, plant management, in collaboration with the maintenance mechanic group, developed the framework for implementation of an in-house natural-gas leak detection program. It uses a risk-assessment and risk-management approach by establishing gas leak levels of from 1 to 3, based on the concentration of methane and the lower explosion limit.

Grade 1 is the most severe level and requires immediate investigation, a forced outage, and repairs to protect life and property and eliminate the hazardous condition. Grades 2 and 3 are progressively lower in risk and would allow more time for maintenance planning for and/or repair.

The leak detection program requires regular testing, data tracking, and classification to determine the proper response to any evolving leak. A preventive-maintenance work order was created for mechanics to conduct a wall-to-wall plant leak test survey every other week. Test results are recorded on a worksheet, then discussed with the operations supervisor, and later scanned and saved.

All plant employees have been trained in natural-gas leak detection and response. The culture of collaboration and commitment to safety, quality, and efficiency that resulted from this effort has reduced dramatically the number of forced outages—from 19 in the first two years of plant operation to virtually zero today. Only four minor gas leaks have been detected since program implementation in May 2015. Plus, plant availability increased from 87.52% to 95.47% the year after program implementation.

Orange Grove: Water conservation makes roads safer

Orange Grove Energy (OGE), a two-unit peaking facility owned by J-Power USA and operated by NAES Corp, is required by the California Energy Commission to maintain landscaping and irrigation around the plant’s eight-acre parcel. Recycled water is trucked to the site for this purpose.

However, area residents expressed concern regarding the number of large trucks traveling through their community; the route used had seen multiple accidents, some involving fatalities, since OGE began operating in June 2010.

Data were critical to minimizing water use. The plant installed a totalizing flow meter in the irrigation system to monitor consumption, enabling staff to respond quickly to increases in irrigation flow and fix broken pipes and nozzles. 

A spreadsheet tracker was established to monitor and log flow rates and usage as they trended up or down—either in small increments or step changes. Overall, the totalizer—along with active monitoring, tracking, and trending—allowed staff to better communicate and keep the irrigation system in excellent condition.

The tracking system sharply reduced trucking requirements; the saving in labor, maintenance, and fuel amounted to over $30,000 annually. Plant Manager John Hutson says residents have expressed appreciation to OGE for reducing traffic and diesel emissions. 

Orange Grove: Relocating pigeons mitigates health, safety risks

Pigeons often are unwelcome residents at powerplants and pose a threat to the health and safety of employees. For example, pigeon droppings create slip-and-fall hazards on concrete walkways and steel deck grating. They also startle unsuspecting employees working in areas where the birds have taken refuge, sometimes causing a trip or fall.

After consulting with state regulatory agencies and a local pest control contractor, staff decided to use pretreated Avitrol corn to control and drive away pigeons from the site. Compared to other methods considered, Avitrol used in low concentrations offers a humane, environmentally friendly and cost-effective solution.

The active ingredient in Avitrol acts on the pigeons’ central and motor nervous systems, causing them to emit distress signals, alarm cries, and visual displays similar to those used when a predator is attacking the flock. These signals frighten away the rest of the flock from the site.

Program began by placing feeding stations—trays filled with untreated corn—in strategic locations around the plant to familiarize the pigeons with them. Stations were inspected weekly and refilled as needed until personnel observed significant feeding activity—which took about two months.

During the third month, Plant Manager John Hutson’s staff at Orange Grove Energy began filling the stations with the Avitrol-treated corn, inspecting and refilling them as needed. After about two months, there was less activity at the stations. Inspections were reduced to biweekly, then monthly. After about nine months, the pigeons had disappeared and have not returned. Today the feeding stations are inspected quarterly to monitor for signs of pigeon activity. As of January 2018, the site had been pigeon-free for about 18 months.

Worthington: Lighter, hinged manhole covers benefit safety

Worthington Generating Station has three vaults with manholes that provide access to valves. The existing manhole covers (photo, left) at the four-unit peaking facility operated by NAES Corp for Hoosier Energy, required two operators to remove them, and they still posed a safety hazard because of their weight and design.

Plant Manager Robert VanDenburgh’s safety committee worked with a local welding company to design a lighter-weight cover (photo, right) that eliminates the need for two-person removal and replacement. Plus, the hinged design eliminates the hazards associated with moving and storing the cover during vault access. And the new cover requires no tools for removal. It causes zero back strain and presents few if any pinch points.

Performance improvement

Bundy: Steam-turbine rotor/case upgrades and heating system extend outage intervals

Lincoln Electric System’s Terry Bundy Generating Station is dispatched primarily to address peaks in the SPP market, resulting in daily on/off cycling. In 2016, the steam-turbine OEM significantly increased the equivalent operating-hour (EOH) factor for cold starts on the plant’s 2 × 1 combined cycle. The new cold-start EOH factor would have required major inspection/maintenance cycles for the steamer every seven years, costing more than $7.6 million over the next 25 years.

Staff evaluated the benefits of reducing the number of “cold” starts and associated maintenance cycles by upgrading turbine components and installing a turbine case/rotor heating system. 

Project scope covered the evaluation of mechanical modifications to the turbine rotor and installing a turbine rotor/case heating system to allow the unit to remain in hot standby mode for multiple days after coming offline. The overall goal was to improve unit operating economics and reduce the equivalent operating hours associated with cold starts, thereby cutting maintenance costs by extending the interval between major inspections. Rotor mods reduced the original cold-start EOH penalty from 530 to 235 EOH.

The turbine modifications included machining the rotor ends to increase case clearance, modifying the blade root configuration, changing the geometry of the thermal relief groove, and installing upgraded blades. The heating system maintains the steam-chest temperature at 650F, further reducing the EOH penalty for a start to 36 EOH.

A key requirement of the project was designing a monitoring system to estimate rotor temperature. The main challenge here was that the dual-case design of the turbine made it difficult to accurately measure turbine temperature. Working with the turbine OEM, seven additional thermocouples were installed in the turbine-case HP and IP sections, including one which extended into an HP inner-case structure.

This allowed the system to assign the correct EOH factor for hot (644F and above), warm (266F to 644F), and cold starts (less than 266F) based on actual rotor condition. The original EOH factor system used the amount of time since shutdown to determine which factor to apply to the next start.

The heating system, designed to bring the turbine from a cold condition to 260F using approximately 2067 kWh of energy, consists of 19 heating-blanket zones that are sequenced on and off depending on measured case/rotor temperature and time since the unit was taken offline.

The zones are sequenced to maintain the turbine at 675F from the time the steam turbine is taken offline until 96 hours have passed. It then lowers the maintenance temperature to 575F for the next 72 hours. Finally, the system holds the turbine at 375F for 48 hours before allowing the temperature to decay to ambient.

In addition to extending the interval between maintenance periods, the heating system reduced the steam-turbine dispatch time by 45 minutes. The shorter dispatch time improved unit economics and will potentially lead to better market utilization of the generating resource.

Economic analysis of the benefits of this system indicate over $5.5 million in total savings from extending the maintenance intervals. The economic benefits of the shorter dispatch time have not yet been quantified. Plant Manager Jim Dutton and his team are still evaluating the amount of energy, and associated cost, for heating-system operation.

Project cost breakdown

    • Heating system design, installation and commissioning: $1,263,764

    • Estimated net present value of maintenance-cost reduction: $5,538,000

    • Peak heating electrical demand: 150 kW

First hold temperature, trip to 96 hours.

    • HP end section, 650F.

    • Steam chest, 675F.

    • IP end section, 375F.

Second hold temperature, 97 to 168 hours.

    • HP End section, 550F.

    • Steam chest, 575F.

    • IP end section, 275F.

Third hold temperature, 169 to 216 hours.

    • HP end section, 375F.

    • Steam chest, 375F.

    • IP end section, 200F.

Equus: LM6000 remote start/stop alert notification system

Equus Power I entered the New York merchant power market in late 2017. An important revenue stream for the facility is the NY ISO 10-min-start market. Plant is operated remotely from another peaking unit, Pinelawn Power LLC, about 20 miles away. Both Equus and Pinelawn are owned by J-Power USA, operated by NAES Corp, and managed by Kenneth Ford.

It was necessary to assure that real-time start and stop signals were received and acted upon immediately by the Pineland operators. Prior to implementing the alert notification system, one of Pinelawn’s two O&M techs had to remain in the control room to fulfill this function, limiting the OMTs’ ability to perform their regular inspection and maintenance activities. The challenge: Install a system that allowed OMTs to leave the control room to perform their Pinelawn duties yet still receive immediate notice of remote start/stop requests for the Equus turbine.

The Equus site already was equipped with hand-held radios that linked the Equus and Pinelawn plants via an electronic network. Their primary purpose was to enable a “Man-Down” alert system to provide a safety net when staff was tasked with working alone at Equus.

Site management pursued expanded capabilities for the radio system—including interfacing it with the Equus control system so start/stop signals could be transmitted to all radios on the Equus-Pinelawn network.

Today, upon receipt of an Equus start/stop signal, all radios on the network will both display a text message and annunciate an alarm tone. Plus, hardware installed to support the new radio system was modified to activate a contact closure that sounds mechanical alarm bells strategically placed in high noise areas of the Pinelawn plant, thereby providing further assurance that an Equus start/stop signal will be heard and acted upon immediately.

The remote alert notification system provided immediate results. Specifically, a Pinelawn OMT is no longer required to remain in the control room to monitor for an Equus start/stop signal. This allows Pinelawn staff more time to complete equipment inspections and perform required maintenance. Also, the robust start/stop notification system helps ensure Equus can continue to successfully compete in the New York ISO 10-min-start market.

EVM I: Condensate recovery from inlet-air chiller cuts costs, benefits community

Challenge: How to increase output/maximize revenue when electricity demand and prices peak during the warm months.

EVM I, owned by EVM Energia SAPI de CV (Mexico) and operated by NAES Corp, was designed with a chiller-type power-augmentation system. When inlet air approaches saturation, moisture begins to condense. The condensate formed—as much as 16,500 gal/day—dropped to a collector in the filter house and was piped to plant drains. Disposing of this much water was expensive given the fee structure specified in the plant’s wastewater permit.

Staff wanted to recover the condensate for use as makeup for the small boiler onsite, for filling of the service-water tank, and for providing demineralized water for chiller makeup and for gas-turbine compressor water washing.

After considering several possible solutions, personnel came up with the design for a system that could direct the condensate formed either to the plant’s sumps or to a collector tank. Once filled, these tanks would be pumped to the service water tank and/or the demineralized-water tank, as required.

During a planned outage, staff modified the condensate drain pipe for each gas turbine, installing two valves: one to direct the condensate to the drain, the other to a 290-gal collector tank added alongside the auxiliary skid serving each engine. Next, a pump was installed in each circuit to pump water to the service-water and/or demin tank.

A simple level-control device keeps the system working in automatic, or in manual mode, as required. It relies on an electrical float to start and stop the pump. When the collector tank is full, the water is pumped to the service tank; the float stops the pump when the tank is empty. The 220-V system is powered by the gas-turbine lighting boards.

The system described allows recovery of up to 16,500 gal/day of water. Given the variation in relative humidity and ambient temperature, condensate production also is variable. Plant Manager Javier Badillo’s staff calculated a monthly baseline using actual daily production from July 2016 through June 2017 (table).

Table: Condensate Production

Because the state of Mexico has imposed a ban on obtaining fresh water from new wells, the plant would have to buy water for services and for making demineralized water. It made a considerable difference to its operating budget that the plant was able to recover approximately 159,000 gallons from the commissioning period (October 10-16) through the end of the month.

At about $0.06/gal, plant saved about $9500 in October alone. This means that the condensate recovery system, which cost roughly $10,500 in materials and labor, more than paid for itself in its first month of operation. Management does not expect to buy fresh water for the remainder of the plant’s service life.

In fact, because EVM I recovers substantially more water than it uses, the plant supplies the local community with badly needed water for crop irrigation and other uses, allowing it to reduce its wastewater disposal cost to practically zero, while improving relations with neighboring communities. 

A laboratory analysis showed the condensate to be of high quality. Conductivity measures less than 5 µS and pH averages 6.5-7. With reclaimed-water specs close to those for demin water, plant can use it directly for offline and online compressor water washing. Given the plant typically was paying $5600 annually for demin water, this reduces operating costs further.

Orange Grove: Improved oil-pump breather reduces maintenance

The NOx water pump for OGE’s gas turbines is equipped with bearings that rely on a self-enclosed sump for lubrication. The pump was supplied with a simple air breather that became saturated with oil and leaked externally soon after its cleaning or replacement. Oil was being added every other week and operators were wiping up oil in the pump house daily.

Solution was to upgrade the existing filter (photo left) with a breather that allows air to pass through the filter but drains the oil back to the sump. Plant Manager John Hutson’s team also added a 6-in. extension and two 90-deg elbows to give a change of direction and further decrease the likelihood of oil reaching the filter (photo right).

Oil leakage stopped immediately and produced an economic benefit. The cost of removing the old filters and installing the new breather/filters totaled $125, saving an estimated $2600 annually in replacement parts and labor.

J-Power’s Long Island fleet: One way to avoid air-permit violations

Four LM6000s owned by J-Power USA and operated by NAES Corp at multiple Long Island sites have strict NOx limits (2.5 ppm one-hour average on gas, 9 ppm on oil). Thus, a hiccup in NOx-water or ammonia injection might cause a significant spike in stack NOx, likely resulting in a reportable air-permit exceedance.

The challenge was to establish a method to automatically detect an abnormality in the emissions control system and immediately start a GT shutdown. The goal was to eliminate the time needed for an operator to detect, analyze, and act on system abnormalities thus reducing the chances of the CEMS Data Acquisition and Handling System recording a steady state, one-hour-average, air-permit exceedance.

Plant managers identified the following conditions at which an automatic GT shutdown should be initiated:

    • GT load greater than 25 MW and NOx water flow rate drops below 5 gpm.

    • GT load greater than 25 MW and 25 minutes have elapsed since startup (assures SCR is warmed up and ammonia is being injected) and ammonia flow drops to less than 10 lb/hr for more than 10 seconds.

Once the above thresholds were identified, an outside vendor specializing in GT and BOP control-system architecture was contracted to develop and implement logic to support the desired actions.

Following implementation of automatic shutdown logic, none of the four engines has experienced a reportable air-permit exceedance as a result of water- or ammonia-injection anomalies. Best estimate: Eight reportable events were prevented in the last two years.

West Valley: Upgrading lube-oil hoses reduces forced outages

For the first couple of years after COD, generator lube-oil discharge hoses on each of the five LM6000s at Utah Municipal Power Agency’s West Valley Power facility ruptured annually or more frequently. Each incident resulted in an unscheduled outage of at least four hours and the loss of 50 to 100 gallons of lube oil. The OEM equipment consisted of two stainless-steel flanges connected by a rubber hose—a design apparently not up to the task.

Even after Plant Manager Jerame Blevins’ staff (NAES Corp) had replaced the ruptured hoses numerous times with OEM approved parts—and upgraded the hose material—the issue persisted (photo left). Personnel considered several solutions, settling on having a braided stainless-steel-reinforced hose manufactured for each unit (photo, right). Careful measurements were taken on each unit before having the five new hoses fabricated by a local shop.

Since West Valley installed the new hoses four years ago, it has not had a single rupture, saving about 500 gal/yr of lube oil valued at $8100. It has also reduced the call-in hours for two extra operators to clean up five spills and replace five hoses, which totaled more than $2200 annually. Overall, it has reduced the number of forced outages by an average of five per year (at four hours per outage).

Worthington: Isolation and bypass valve set-up helps protect chiller from extreme cold

During summer peaks, Hoosier Energy’s Worthington Generating Station uses four 1800-ton chillers to produce the 40F water required to maximize GT performance with 43F compressor inlet air. For winter operation, the NAES O&M staff, directed by Plant Manager Robert VanDenburgh adds 40% glycol to the chilled-water loop and a small boiler operates to heat and maintain loop temperature at 54F. The glycol/water mixture circulates through the air inlet house to maintain compressor inlet air at the desired temperature.

Chiller issues developed when the ambient temperature was extremely low. The glycol/water loop temperature dropped below 30F, causing unusually cold fluid to flow through the system, including the chiller evaporators.

The chillers are laid up during the winter off-cycle, so the evaporator and condenser normally stay at the same pressure and temperature. However, the extremely low evaporator temperatures allowed low refrigerant temperatures to transfer from the evaporator to the condenser, causing trapped residual water from annual tube cleaning to freeze in the condenser tubes. Eventually cracks developed, damaging the chiller.

To sum up the challenge:

    • Prevent flow through the chiller evaporators when the loop temperature drops below 40F.

    • Maintain proper operating pressure and flow rates without using the chiller evaporator as a pass-through.

    • Change procedures to prevent water from settling in the condenser tubes while the chiller is laid up for the winter.

The NAES staff’s root cause analysis concluded that the chiller evaporators must not be used as a pass-through during winter operations. An alternative plan was to allow the glycol/water mixture to bypass the chiller evaporators while maintaining the integrity of the loop. Isolation valves were installed in the chiller inlet and outlet piping that completely disconnected the chiller from the loop to prevent any refrigerant transfer to the condenser.

Plant also added a bypass valve upstream of the isolation valves to maintain the flow path. To address the standing water in the condenser tubes, low-point drains were installed. The winter lay-up procedure was revised to ensure that the condenser tubes could dry thoroughly following annual cleaning.

By completely isolating the chiller from the glycol/water mixture loop, the plant increased chiller reliability and has experienced no further downtime caused by cold evaporator temperatures. While it’s too early to assess long-term results, staff expects the freezing/cracking problem in the condenser tubes has been eliminated.

Orange Cogen: Backup diesel air compressor for black-plant situations

Northern Star Generation’s 2 × 1 LM6000-powered combined cycle at Orange Cogen is connected to the grid via the local utility’s 69-kV system. Historically, inclement weather events cause this section of the system to disconnect, blacking out Orange Cogen, which is operated and maintained by Consolidated Asset Management Services LLC.

The plant was designed with a station battery system, but the air compressors were not connected to it. Not having instrument air for more than two hours during a black-plant event presents the following challenges, among others:

    • Control of air-operated valves is lost with possible financial impact. Example: Losing control of boiler feedwater flow causes excessive wear and tear and thermal stress on expensive HRSG components and support equipment.

    • Dry-pipe deluge systems for fire protection require instrument air for proper operation. Deluge valves were arranged to open after air-receiver capacity was exceeded and pressure dropped below 45 psig, requiring technicians to disassemble and reset the valves.

Plant Manager Allen Czerkiewicz’s staff investigated solutions for maintaining instrument air pressure when the plant lost power—including adding a receiver or replacing the existing one with a larger receiver. However, the storage capacity required to supply air for two hours was considerable.

A backup generator also was considered, but the cost of a unit to run a 100-hp air compressor, plus associated switchgear, was prohibitive. Adding the compressors to the station battery system had its drawbacks, too: Additional cells would have been required and the battery room was too small to accommodate them.

A diesel-powered air compressor was the optimal choice. A trailer-mounted unit was selected so personnel could use it for maintenance purposes when the plant was not in operation. A successful result hinged on integrating the portable air compressor into the existing air system and allowing for the exhaust gasses to safely vent to atmosphere. This was doable.

The local supplier added a controls package, enabling the new compressor to start at 95-psig system pressure and unload at 105 psig; plus shut down after running unloaded for five minutes. The permanently installed electric compressors are arranged in a lead/lag scheme with the lead unloading at 120 psig and loading at 110, the standby loading at 105 psig and unloading at 115.

The diesel compressor was located outside the water treatment building under a protective roof (photo). Piping and conduit for the new machine was run in-house after trenching to avoid a trip hazard. The conduit was to provide a 120-V ac circuit for a charger/battery tender to keep the compressor starting battery in top condition.

The diesel compressor has one drawback: It is not an instant-on machine like a motor-driven compressor. The diesel requires 30 seconds to heat up intake air before it will fire and there is a short warmup period before it will load. Starting time may vary depending on ambient temperature.

After two actual events, staff learned that system pressure dropped to 65 psig before the diesel compressor picked up load and raised system pressure. However, this was adequate serve control valves plant-wide, plus maintain pressure to the fire-system deluge valves.

The diesel compressor was tested by turning off the electric compressors when the plant was offline and it performed as expected. Operators were able to bring the plant to a safe condition with the deluge valves remaining shut.

One event revealed additional protection provided by the new equipment: With an electric compressor down for quarterly maintenance, a close lightning strike took out the running air compressor along with several other motors while the plant was operating. The diesel compressor started and allowed operators to maintain normal operation, preventing a forced outage.

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