Contributing to industry knowledge on ACCs, predictive analytics, use of recycled water – Combined Cycle Journal

Contributing to industry knowledge on ACCs, predictive analytics, use of recycled water

The Walter M Higgins Gener­ating Station, a 2 × 1 501FD2 combined cycle began com­mercial operation in 1Q/2004 as Bighorn Generating Station. The 530-MW facility was built and operat­ed by Reliant Energy Inc until its sale in late October 2008 to Nevada Power Co d/b/a NV Energy. FYI: The plant’s namesake, Walter Higgins, retired as president/CEO of Sierra Pacific Resources in July 2007, just 14 months before SPR became NV Energy.

In its first five years, the sta­tion has contributed significantly to industry knowledge on (1) the behav­ior, operation, and maintenance of air-cooled condensers (ACCs), (2) the value of predictive analytics in pre­venting forced outages—and possibly equipment damage—through early detection of operational anomalies, and (3) the use of recycled municipal wastewater for powerplant fire pro­tection.

Keep in mind that Bighorn was built to serve the merchant power market and, by virtue of its loca­tion (Fig 5-1), its staff had no choice but to learn how to operate the ACC reliably and efficiently and how to address the challenges associated with the use of grey water. Failure to do so would have compromised the plant’s ability to meet revenue goals.

Operations Manager Felix Fuent­es, Maintenance Manager Ron McCal­lum, and an empowered 15-person staff, are a proactive team proud of the plant’s performance record and safety program. The latter earned Higgins OSHA VPP (Voluntary Pro­tection Program) Star Site status.

Fuentes and McCallum manage the station on a day-to-day basis for Plant Director (acting) Steve Page, who also is responsible for the Clark and Sunrise facilities and works most days out of Las Vegas. Fuentes has been at Higgins since before its com­missioning.

Air-cooled condensers

Most powerplant personnel are very familiar with water-cooled condens­ers; relatively few have experience with ACCs. Most also are aware of the efficiency penalty associated with a dirty condenser, vacuum leaks, and/or plugged tubes. The first two apply to both types of condensers, the last primarily to water-cooled units.

However, the performance of ACCs can be adversely impacted in other ways—such as by recirculation of heated plume air into the inlet stream, degradation of fan performance, and reduced air flow to some cells caused by windy conditions and/or mechanical design.

When the editors met with Fuentes, McCallum, and other members of the Higgins team, the ACC discussion focused primarily on two subjects: the effects of wind on performance and some of the ideas implemented by plant personnel to facilitate maintenance and assure top efficiency and reliability.

Bighorn participated in a 2005 study conducted by consultants John S Maulbetsch (Menlo Park, Calif) and Michael N DiFilippo (Berkeley) to assess the effects of wind on ACCs. The study was comprehensive, involving a week or so of measurements and analysis at each of five western powerplants selected to represent a range of ACC and fan types, wind conditions, topographies, etc. Details of that work were presented at the 2007 conference of the Cooling Tower Institute in Corpus Christi (paper number TP07-04).

Design of the Bighorn ACC, supplied by Hamon Corp USA, is considered by plant personnel to be robust as well as maintenance-friendly. Cell arrangement is shown in Fig 5-2. Fans were supplied by Howden Buffalo Inc, Camden, SC. Note that during construction of Bighorn, SPX Cooling Technologies Inc, Overland Park, Kans, purchased the Hamon dry cooling product line. SPX also owns the Marley and Balcke Duerr dry-cooling product lines.

Recirculation. Maulbetsch and DiFilippo determined the presence of recirculation by monitoring the inlet air temperature to each cell. Readings higher than ambient indicated hot-plume recirculation. They defined recirculation as the difference between the average cell inlet temperature and the lowest temperature. Data collected at Bighorn are shown in Fig 5-3 for all times during the test periods when all fans were operating at full speed.

The researchers observed that the average recirculation almost always was less than 3 deg F, which translates to an increase in condenser pressure of less than 0.5 in. Hg. As Fig 5-3 shows, at Bighorn nearly all the points lie between 0.5 and 2.5 deg F. There were only three excursions between 3 and 4 deg F and one above 4 deg F.

During low wind conditions (from the South at 2.5 mph), Bighorn experienced virtually no recirculation. In fact, the difference in inlet temperature between the coolest cell (3E, refer again to Fig 5-2) and the hottest (1J) was only 2.3 deg F; the average recirculation for all cells was just 1.1 deg F.

With a nominal 13-mph wind out of the SSE and ambient of 92.2F, the results were different and provided more insight into the behavior of ACCs. Average recirculation was 2.8 deg F. However, five cells had inlet temperatures ranging from 98.5F to more than 100F; all were on the west edge of the north cluster (4A through E)—directly in the wake of the ACC with wind from the SSW.

Thus street 4 in the north cluster was not operating as efficiently as the remainder of the heat exchanger during this wind condition—an effect equivalent to having some tubes blocked in one portion of a water-cooled condenser.

The researchers noted that, in some cases, the recirculation number can be misleading, because of obstructions under the fan deck, temperature “inversions,” etc. Inversions here refers to conditions that cause air temperature at or near ground level to be several degrees cooler than at the fan-deck level.

One case: Time, 0100; wind at 1 mph out of the South; average inlet temperature 80.5F; minimum cell temperature of 74.9F (2I and 2H). Result is a recirculation of 5.6 deg F, which appeared anomalously high to the researchers. Further investigation suggested that the motor control center located directly under cells 2I and 2H presented a 15-ft-high obstruction to air coming in under the ACC from the South. Thus the cooler air at near ground level could have been diverted upward, bypassing the J row but becoming entrained by the fans in rows I and H.

Fan performance was significantly more difficult to determine. The approach taken by the researchers at the first site investigated was to measure inlet air velocity, static pressure rise, and fan motor current on selected cells. For other sites inlet air velocity was used as a surrogate measurement to reduce the cost of testing; only cells impacted by high cross-wind velocity were checked.

Wind can affect the velocity distribution of inlet air across one or more fans and adversely impact ACC performance. Recall that these heat exchangers are equipped with large-diameter (more than 30 ft is common for powerplant applications), low-speed (nominally 100 rpm) axial-flow fans with a modest static pressure rise (0.5 in. H2O or less). Bell-shaped inlet shrouds typically are installed to minimize inlet losses.

The work of Maulbetsch and DiFil­ippo at Bighorn—and tests by other researchers—suggests that ACC fans can expect a flow decrease of about 5% for crosswinds of 15 mph. At 25 mph, air flow may drop by as much as 15%. The physical construction of an ACC also can adversely impact flow—perhaps more than a simple crosswind would. Fig 5-4 shows the impact on fans adjacent to the cat­walk when winds at Bighorn were from the South. Extending the lip on the catwalk displaced the separation zone (Fig 5-5).

Work at Bighorn and the four other plants confirmed that “recircu­lation was not the sole cause, or even the major cause, of ACC performance degradation under windy conditions.” With winds at 20 mph, tests showed the impact on absolute exhaust pres­sure may be as much as 2 in. Hg—or four times what you might expect from recirculation.

Another conclusion: The degrada­tion in fan performance attributable to the effects of wind is difficult to quantify. Work at the five plants indicated flow reductions of as much as 50 to 60% in upwind cells depend­ing on wind speed. Downwind cells exhibited smaller losses.

Fuentes said wind has not sig­nificantly impacted operations at Higgins, which is not equipped with the wet helper tower found in many plants. The output swing caused by wind might be 5 MW at most, he guesstimated. Limiting factor for Higgins is main-steam attemperator spray capacity, not ACC capacity. For example, on a 114F day, back­pressure can reach from 7 to 8 in. Hg abs; but the trip point is 10.5 in. A 1065F main steam temperature for five minutes will initiate a runback on the duct burners.

Fogging ACCs. Fogging works well in gas-turbine inlets in dry climes, so why not try to maximize steam-turbine output using the same idea? Spraying water at the suc­tion side of the fan obviously would reduce the air inlet temperature (Fig 5-6). Tests at Bighorn revealed that 1 gpm per fan would reduce air tem­perature to the heat-transfer coils by about 0.35 deg F.

To cool ACC inlet air by 5 deg F during the hottest part of the day (when power prices are highest) translates to 15 gpm for each of the 40 fans. Spraying for seven hours would consume a nominal 250,000 gal of water, which was not feasible for Bighorn.

ACC lessons learned, best practices

Ron McCallum led the discussion on ACC lessons learned and best prac­tices. He began by reviewing the oper­ating history of the fan drivers and associated gearboxes. The short list of main events: Five years, 40 fans, and only one motor failure and one gearbox failure. McCallum also remembered a problem on a fan with a leaking high-speed gearbox shaft seal. The action taken was to reduce oil pressure from the shaft-driven pump.

But you quickly got the sense he was just warming up when the edi­tors asked a question about the gear­box. Eyes wide open, he said with a grin, “The ACC fan system presents unusual challenges because of the location of the gear reducer, which is mounted under the walkway grating and boxed-in with supporting frame­work. Plus, the gear reducer doesn’t lend itself to easy rigging because of its location and weight distribution.”

The Higgins staff is a proud group and they struggled with their first gear-reducer change-out. Rigging and clearance were the biggest issues, McCallum recalled. “Experience in hand,” he continued, “we were deter­mined to develop a procedure that would allow safe and efficient remov­al and replacement of gear reducers. With 40 fans, we knew we would be doing this again.”

With McCallum taking a breath while revving up into high gear, Fuentes saw an opening. “As issues come up at Higgins, we as a team search for ways and means to address them economically while maintaining the safe work environment we have worked so hard to achieve,” he said. “We never quit thinking and doing and have never let any problem gain the upper hand. Just any solution is not the solution we’re looking for. We view issues from all angles to be sure our fix meets all objectives and is not a hindrance to someone else.”

Fuentes took a sip of water and McCallum jumped back in. “It’s pretty easy to remove the 200-hp fan motors and transport them north or south [refer again to Fig 5-2] via a monorail to facilitate gearbox access,” he said (Figs 5-7, -8, -9). “One of our goals was to rig the reducer for removal so that it didn’t have to be handled more than absolutely necessary to get it to ground level safely.” Some of the challenges the Higgins team faced:

Principal equipment, Walter M Higgins Generating Station

Commercial operation: February 2004
EPC contractor: Bighorn Constructors
Owner’s engineer: Sargent & Lundy
Type of plant: Combined cycle
Key personnel
Regional director: Steve Page (acting)
Operations manager: Felix Fuentes
Maintenance manger: Ron McCallum
EHS manager: Christine Hinshaw
CROs: Jason Canillo, Randal Cooper, Tony Guadarrama, Chris Jackson, Tom Millett, Joe Otero, Greg Reitz, Sean Schmitt, and Jimmy Seymour
Technicians: David Cairns, John Eliason, Marty Gillespie, Kevin Newcomb, and David Rettke
Coordinator: Patricia Comella
Gas turbines
Manufacturer: Siemens Energy Inc
Number of machines: 2
Model: 501FD2
Control system: TXP (Siemens AG)
Combustion system: DLN
Fuel: Gas only
Water injection for NOx control? No
Water injection for power augmentation? No
Air inlet house: Donaldson Company Inc
Air filters: Donaldson Company Inc
Inlet-air cooling system, type: Evap cooler
Generator, type: Air-cooled
Manufacturer: Siemens AG
GSUs: Hawker Siddeley Power Transformers Ltd
Manufacturer: Alstom Power
Control-system, type: P320
Attemperator(s): Copes Vulcan, an SPX brand
Duct-burner: Forney Corp
SCR: Englehard Corp (now BASF Catalysts LLC)
Catalyst supplier: Englehard Corp (now BASF Catalysts LLC)
CO catalyst: Englehard Corp (now BASF Catalysts LLC)
Steam-turbine bypass valves: BTG Specialty Valves (now CCI-Control Components Inc)
Steam-turbine bypass desuperheaters: Copes Vulcan, an SPX brand
Water treatment
HRSG internal treatment, type: Amine
Chemical supplier: Univar USA
Reverse osmosis system: Aquatech International Corp
Demineralizer installed? Yes
Wastewater treatment system, type: ZLD
Supplier: Aquatech International Corp
Steam turbine
Manufacturer: Alstom Power
Generator, type: Hydrogen-cooled
Manufacturer: Alstom Power
GSU: Hawker Siddeley Power Transformers Ltd
Balance of plant
DCS: Bailey Infi 90 (ABB Bailey Controls)
Condenser, type: Air-cooled
Manufacturer: Hamon Dry Cooling (now SPX Cooling Technologies Inc)
Boiler-feed pumps: Flowserve Corp
Condensate pumps: Flowserve Corp
Circulating-water pumps: Flowserve Corp

  • How to transport the reducer outside the cell. The doorways all have “headers” that require hoist­ing the reducer above them to pass through each cell. Unconventional rigging angles would be required to avoid having to remove each header down a row to gain crane access to ground. Also, reducers would have to be rigged-up as short as possible to the lift hook to clear the headers.
  • How to remove support beams under the deck to facilitate gear­box extraction.
  • How to safely transfer the reducer from the chain hoist to the mobile crane.

Plant staff engineered the fixture shown in Fig 5-10 to address clear­ance issues, lift- height restrictions, and the need to transfer the load from hoist to crane safely. Figs 5-11, -12 show the lifting procedure in more detail.

McCallum stressed that more work remains regarding the ACC reducer. For example, plant staff sees a need for a fixture or devices to control the fan hub during reducer removal and replacement. The ability to control hub position is very important, he continued, to allow proper alignment with the reducer. Also on the plant’s “to do” list is the design and fabrica­tion of a hybrid mechanical/Inpro seal for the input shaft that extends the mean time between repairs.

McCallum then ran though several more things the Higgins staff did to improve ACC operations and facilitate maintenance (bullet points below). He said he looked forward to sharing the details of these enhance­ments with colleagues—and learning from them—at the inaugural meeting of the ACC Users Group, Nov 12-13, at NV Energy’s headquarters in Las Vegas (see advertisement, left).

  • Preventive maintenance is impor­tant to reliability and perfor­mance. A special portable filter cart was purchased to clean-up semiannually the synthetic oil used at Higgins.
  • New oil-pressure and vibra­tion monitoring equipment was installed to support the mainte­nance culture at the plant. The vibration and oil switches supplied with the ACC were ineffective: By the time they were activated it was too late. Also, they couldn’t be read locally (the new instruments can) and were of no value to O&M personnel on rounds.
  • One PM is to inspect the cou­pling between the Flender gear­box and motor. Inspection of the rubber grommets required lifting the motor to visually check their condition. You don’t have to talk to the Higgins staff for very long to realize they were not going to buy into this time-consuming procedure with its inherent safe­ty risks. Flender engineers were responsive to the plant’s needs and supplied a vernier tape for the top and bottom coupling flanges to measure backlash—an alternative method for determining grommet health. FYI: Siemens Energy & Automation Inc acquired Flender in Spring 2005.
  • Conduit was repositioned and split spacers were inserted between the motor and gearbox allowing mechanics to lift a motor off its coupling and run the required periodic two-hour vibration check without having to break the cou­pling.
  • ACC tube bundles are cleaned annually with service water (no detergent). After washing, person­nel enter the cells and wash off the deck plates.
  • Two spare gearboxes are available onsite. These are stored verti­cally to prevent grease migration.
  • This is important, McCallum said. Spare motors also must be stored vertically and with shafts unload­ed.
  • Proper cleaning of the steam path during commissioning is espe­cially important to operational reliability. One problem that had been encountered at some plants was plugging of condensate-pump filters with debris, thereby inter­rupting the steam blow. The Hig­gins system was arranged as shown in Fig 5-13 to assure a con­tinuous steam blow.

A trap similar to that under your sink was installed to allow diversion of mill scale before it reached the condensate tank. Also, the height of the condensate-receiver standpipe was extended to increase the amount of debris the tank could hold without com­promising pump operation.

  • Daily walk-arounds are conduct­ed to verify proper operation of all fans, gearboxes, and motors. Maintenance is on a weekly cycle.
  • Wind curtains installed under the fan deck as described in Fig 5-2 shield the plant from debris and act as a visual screen. They also help direct air flow to fans.
  • Gearbox oil temperature con­cerned McCallum. He would have preferred an oil cooler above the fan in the air stream like he had at some other plants. But Flender engineers assured him that run­ning the synthetic oil provided at 200F was not a problem.

Predictive analytics

By now you may be thinking that Higgins personnel will not be fully satisfied until they are able to elimi­nate all but the thought of equipment failure. Since driving the forced-out­age rate to zero is roughly equivalent to eliminating lost-time accidents, which they have accomplished, you probably are correct. This organiza­tion-wide “can do” culture has pre­vailed since plant commissioning.

Critical to the goal of zero forced outages is intelligence. You have to know what is on the verge of failing to prevent failure. No crystal balls allowed here; they’re too unreliable. Three months after Bighorn went into service, owner Reliant support­ed a three-month study to determine the value of predictive analytics for identifying issues before they became major problems. SmartSig­nal® was selected for evaluation. Bighorn was the pilot plant for the Reliant fleet.

Background. Simply put, Smart­Signal imports PI data into a robust empirical model that compares a mathematical representation of healthy equipment behavior against actual operating data. In actual­ity, many discrete models, each built around a different type of failure mechanism, are used. Significant deviations generate alerts.

Early warning of equipment issues reduces forced outages and O&M costs, and improves availability. Fuentes said gas and steam turbines and balance-of-plant equipment all are tracked by SmartSignal. “It’s like driving with a radar detector,” he added. “It keeps you alert and provides an extra measure of protec­tion.” Higgins’ experience is that the early-warning system works well. To illustrate: During the pilot study, here’s what SmartSignal caught:

  • pH excursion in the HP steam drum of one HRSG caused by a bad sensor.
  • A disk-cavity cooling-air control valve on one of the gas turbines was showing “closed” even though it was 10% open, identifying a positioner problem.
  • A problem with the pilot fuel-gas control valve on one GT also was caused by a positioner issue.
  • A temperature excursion in one combustor was traced to a washer in that combustor.
  • The biggest catch: Identification of a flashback temperature problem on one gas turbine.

As the last bullet point suggests, some findings are more significant than others. Low-priority “finds” are identified in weekly reports that are reviewed in 15-min conference calls after their publication. Medium-pri­ority alerts are e-mailed to the plant as “advisories.” The plant is called immediately on high-priority alerts. Note that small residual deviations (difference between actual and esti­mated values) are expected because of normal system variations. Large residual deviations are considered abnormal and generate an alert.

SmartSignal has a technical staff of experienced engineers and former senior-level plant operations per­sonnel that monitor the operation of scores of plants. Some custom­ers—particularly those with many assets—have set up their own M&D (monitoring and diagnostic) centers

and handle supervisory monitoring internally.

Regarding the flashback tem­perature problem noted above, it was identified by the deviation between the blue (PI data) and green curves (predicted SmartSignal value) in Fig 5-14. For the DCS to alarm in such a situation, the temperature would have to be “off the charts.” By that time, damage most likely would have occurred.

In this case, inspection revealed debris in the fuel-gas witch-hat strainer in one of combustor No. 6’s burner stages. Debris was removed and the residual deviation returned to normal. The anomaly was not detected by traditional condition-monitoring devices and prompt attention by plant personnel avoided a possible machine trip.

In sum, predictive analytics allowed Bighorn to shift what would likely have been an unplanned maintenance event to planned maintenance; plus, early action avoided damage that might have required significant out­age time to address. Over the long term, predictive analytics permits use of a condition-based maintenance program, thereby extending overhaul intervals and boosting availability. And it also allows tighter control of heat rate, reducing fuel cost and total emissions.

SmartSignal told the editors that payback of the annual fees for both the software license and the moni­toring service virtually are assured by the O&M saving. The company offered its 98% renewal rate as evi­dence. Bighorn’s license went with Reliant after the plant was sold. However, Higgins recently rejoined the program and results are being monitored by NV Energy to gauge its fleet-wide value.

Fuentes concluded this portion of the editorial roundtable by saying one of the things he learned during the first SmartSignal experience was that predictive analytics is only as good as the models used. This time around plant personnel spent more time working with the vendor to develop more robust plant-specific models. The new and improved ver­sion of SmartSignal is in use today. Stay tuned for a progress report.

Grey-water for fire mains: Lessons learned

The first lesson you learn in the power-generation business is that if you’re not learning new lessons you’re probably not doing enough. This is an industry where virtually nothing can be taken for granted—no matter how many times it’s been done previously.

Consider the use of treated waste­water for plant makeup. The experi­ence base covers scores of plants—at least. A guess at the overall success rating: Very successful. But every plant’s situation is unique and grem­lins can make for a high level of frus­tration.

At Bighorn, the gremlin was coli­form bacteria. In the early going, the station exceeded its NPDES (Nation­al Pollutant Discharge Elimination System) permit level for coliform bacteria a few times—no exceedances after 2005, however. Primm Waste­water Treatment Plant effluent is the plant’s primary water source. The original plan to achieve permit­ted coliform levels simply by adding chlorine (5 ppm excess, at the power­plant’s expense) to the treated waste­water did not meet expectations.

For example, the high-efficiency reverse-osmosis system (HERO®, Aquatech International Corp, Can­onsburg, Pa) installed as part of the original Bighorn water treatment system (Fig 5-15) suffered a 20% der­ate from 100 to 80 gpm because of bio­fouling. This required more demin-trailer capacity to meet summer peak demand. Cost impact: About $25,000 per month.

Fuentes said the plant staff also was concerned that the high level of chlorine in the evap-cooler makeup might contribute to chloride stress corrosion cracking of gas-turbine components—this despite constant vigilance to assure excess chlorine in plant water remained between 2 and 4 ppm.

There are health issues associated with use of water high in coliform bacteria and the local fire depart­ment would not respond to a Higgins emergency if it did not meet NPDES specs. There was no “wiggle” room; the problem had to be corrected.

Three solutions were proposed and evaluated:

  • Microfiltration of all Primm Wastewater Treatment Plant effluent before pumping it into the fire/service water tank (A in Fig 5-15).
  • Install a dedicated firewater tank and fill it with potable water from an onsite well (C in the figure).
  • Replace the existing 10,000-gal permeate tank (B) with a 500,000-gal firewater/permeate tank and fill it with HERO effluent.

Cost of the microfiltration option was estimated at more than $1 million. Biggest concern of engineers was that reject flow would be too high for the onsite evaporation pond. On the plus side, the evaluation team believed that chlorine injection into the fire/service water tank and daily flushing of the firewater loop (D in the diagram) would prevent future exceedances of coliform bacteria.

The team also believed HERO bio­fouling would stop once suspended solids were removed by the microfil­tration unit, which would include a downstream activated carbon filter followed by injection of a non-oxidiz­ing biocide.

The dedicated firewater tank option was less expensive ($600,000); plus, it was isolated from the coliform bacteria source. Yet chlorination, weekly sampling, and daily flush­ing of the firewater loop would con­tinue as a permit requirement. Three negatives: (1) Potential for coliform bacteria limits above those specified in the permit; (2) chlorine use and the possibility of it attacking system components would prevail; (3) the HERO biofouling problem would not be resolved.

HERO biofouling also would continue with the proposed $750,000 firewater/permeate tank option. But HERO would remove coliform bacteria—in much the same way as the microfiltration unit. In addi­tion, the additional permeate stor­age would reduce the need for rental demineralizers in peak months, but only after the biofouling issue was resolved.

Pall Corp’s (East Hills, NY) AriaSM membrane filtration sys­tem was selected and installed at A in the diagram. Its Microza hol­low-fiber membranes (Fig 5-16) are designed to remove suspended con­taminants from surface and ground water sources and from secondary waste. And they are made of PVDF(polyvinylidene fluoride), which is highly resistant to oxidizers.

Fuentes said the system works this way: Treated and chlorinated municipal wastewater is pumped to Higgins. Instrumentation moni­tors turbidity, total dissolved solids, etc. If water doesn’t meet specs, it is diverted to a rapid infiltration basin which allows water to percolate down into the aquifer.

Water that meets quality stan­dards flows through a sand filter and the Pall system, as shown in Fig 5-15. Another chlorination step at the fire­water/service water tank maintains the chlorine residual between 2 and 4 ppm, which is sufficient to dispatch coliform bacteria and other “bugs.”

To verify the effectiveness of the chlorination program, weekly total coliform samples are taken at the storage tank discharge and at least five different deadleg points—that is, hydrants/sprinklers—on the loop to verify total system disinfection. Results (in bacteria count per speci­fied volume of water) are received in about a week. If high (false positives are possible), water is retested imme­diately and super-chlorinated if nec­essary; then deadlegs are flushed.

A safety program second to none

Fuentes stressed several times dur­ing the editorial roundtable his belief that Higgins’ very talented and flex­ible staff had developed into a “world-class outfit, a unit capable of achiev­ing more than the team members could achieve individually [whole is greater than the sum of its parts]. The employees hold each other—and contractors as well—to a high level of responsibility and quality,” he said.

“In operations,” he added, “every­one has collateral duty. For example, one operator is the lead on water treatment, others on lockout/tagout, management of change, operating pro­cedures, etc. Everyone also tracks, to the extent possible, what other plants are doing; the team decides what best practices Higgins should adopt. Our employees take ownership.

“In maintenance, each of our tech­nicians has ‘champion’ status in at least one technology—such as root cause analysis, vibration analysis, oil analysis, thermography, etc. Proof that we’re a world-class outfit is in the numbers,” he said: “Equipment forced-outage rate is less than 1%, starting reliability is above 99%.

“Safety is an area where this group shines,” Fuentes continued. “We’ve been an OSHA VPP Star Site since July 2007. The employees applied for and prepared for this certification on their own. There was no ‘manage­ment initiative.’ They did it because of their inherent belief that safety is everyone’s first priority—always. Safe­ty is an integral part of our success in every area of our business.”

The cornerstone of Higgins’ safety culture is employee involvement and empowerment. For example, employ­ees (1) take personal responsibility for their own safety and health, as well as for others working with them; (2) respond in a positive manner to every safety initiative and exchange ideas for continuous improvement; (3) identify workplace hazards and use the hazard reporting/suggestion process; and (4) participate in and lead pre-job briefings, safety training, and safety meetings. Fuentes added, “Everyone has the authority—rather the responsibility—to stop any job at anytime without fear of reprisal if they see an unsafe practice.”

These are not just words on paper. During the winter 2008 out­age, which was a major effort with dozens of contractor personnel onsite, several incidents prompted a com­plete full-day safety stand-down. Near-misses and injuries by contract labor prompted Higgins management to secure the facility for 24 hours.

During that time, safety meetings reinforced the plant and company safety programs (rules, policies, and compliance with federal, state, and local regulations). Emphasis was that Higgins will not compromise safety. Also, that discipline—including ter­mination when warranted—will be imposed if rules are disregarded. There were no further incidents dur­ing the outage.

Fuentes presented an outline of Higgins’s safety program to the editors. To say the program is com­prehensive would be an understate­ment. The plant’s six-person safety committee—two maintenance per­sonnel, two operators, one man­ager, and one safety advisor—meets monthly. Meetings are announced in e-mails and prominently noted on the station’s bulletin board, com­plete with agenda. All employees are encouraged to attend. A typical meeting reviews old business, new safety concerns/suggestions, etc. The open forum solicits input from all attendees. Minutes are posted on the bulletin board and sent to all personnel.

The plant relies on a mixture of in-house experts and qualified outside trainers to prepare and conduct the necessary training. For example, a 30-hr general industry OSHA course is taught by an authorized trainer. So are courses on forklift safety, arc flash hazards, and a few others.

Emergency response is high on the safety-training agenda. The plant’s extensive “Emergency Response Guidebook” recently was revised to incorporate NV Energy directives. It has chapters on fire, personnel injuries, bomb threats, hazardous materials spills/releases, intrusion, etc. Plus contact information for fire, police, EMS, key company person­nel, etc.

Drills are conducted regu­larly and include local emergency responders—examples: ammonia leak response, multiple personnel injuries, major natural gas leak (with helicopter evacuation), and high-reach rescue. Plant personnel per­form audits/inspections of safety poli­cies and procedures, LOTO practices, work permits, confined-space per­mits, fall protection (twice annually), fire-system equipment (monthly), first-aid kits (monthly), protective gear (monthly), emergency lighting, confined-space monitors (monthly/quarterly), etc.

A recent audit motivated person­nel (1) to review and upgrade plant labeling, thereby assuring quick iden­tification of all systems and processes (Fig 5-17), and (2) to seek out and eliminate potential safety hazards throughout the facility. An example of the latter: A small bleach leak caught without causing injury prompted the installation of splash guarding designed in-house using the manage­ment of change process (Fig 5-18).

Another example: Plant staff saw need for a more robust scaffold monitoring program (Fig 5-19). This upgrade included additional training for many personnel up to the scaf­fold erector/inspector level and a new inspection program—including new inspection tags. Inspection efficiency greatly improved, eliminating the potential for less than quality scaf­folding at the station.

Confined spaces. A program to eliminate the dangers associated with confined spaces is an ongoing effort. The way Higgins does this is through “reclassification.” The details: Plant personnel do not enter “permit-required confined spaces.” Policy is to reclassify confined spac­es, when possible, as “non-permit required” through pre-entry evalua­tions, atmospheric testing, job haz­ard assessments, and eliminating or controlling the hazard.

Higgins’ comprehensive reclas­sification program took a big leap forward last year with the purchase of several sophisticated instruments for continuous monitoring of reclassi­fied spaces (Fig 5-20)—confirmation of management’s commitment to the employee-driven safety program.

“Controlling the hazard” is illus­trated by the plant’s reclaim-water sump project. Higgins has a couple of sumps in the reclaim water system to temporarily hold out-of-spec water until it can be pumped to one of the onsite evaporation ponds. They were designed with fixed-in-place sub­mersible pumps, accessible only by a straight ladder into the sump.

That had “hazard” written all over it. How do you get tools and parts safely into and out of the sump? How do you get the pump out if in-situ maintenance is not possible? Why would you want personnel going up and down ladders if it’s not absolute­ly necessary?

The Higgins team used a multi-disciplinary team approach to rede­sign the entire system. Goals includ­ed: Eliminate the need to enter a confined space, eliminate use of a ladder to do normal maintenance, move equipment out of the sump to facilitate inspection and mainte­nance. Fig 5-21 shows the “eleva­tor” personnel designed to move the pump into the sump, and out of it, from ground level. The sump cover in Fig 5-22 allows sump accessibility if necessary, but otherwise discourages personnel entry.

Several other recent safety initia­tives included:

  • Installation of maintenance plat­forms to eliminate hazards asso­ciated with climbing on pipes and other infrastructure to reach equipment requiring inspection and/or maintenance.
  • A re-evaluation of potential trip/slip hazards and elimination of new hazards identified.
  • New safety bulletin board to raise the visibility of the plant EHS pro­gram.
  • A complete audit/update of the plant’s MSDS (Material Safety Data Sheets) library.
  • Relocation of overhead system/equipment vents to ground level.

Safety never sleeps at Higgins. One new initiative, scheduled for completion this summer, is a Safety Dashboard, which will be available on all plant PCs to provide personnel instant access to procedures, stan­dards, documentation, forms, statis­tics, etc.

Another initiative is that several plant personnel will apply for federal OSHA certification, supported by NV Energy, to participate in audits of facilities nationwide that have applied for the OSHA VPP program.

Lastly, other initiatives in prog­ress include: (1) 100% participation and 100% completion of all plant process-specific and safety training assigned by management using the GPiLearn® Web-based system (Gen­eral Physics Corp, Columbia, Md), (2) implementation of the NV Energy corporate safety ergonomics pro­cedure/standard to identify proper posture, lifting techniques, etc, (3) effluent water handling procedure to identify potential handling hazards, hygiene, protective gear, etc. ccj

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