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No user group serving gas turbine owner/operators covers generators, high-voltage (HV) equipment, and I&C to the degree CTOTF™ does. The day-long Gen-EI&C Roundtable conducted at the 38th annual Spring Turbine Users Conference and Trade Show, chaired by Moh Saleh, Engineering Manager at SRP’s Desert Basin Generating Station, offered four presentations with actionable content.

The opening presentation, “7FH2 Generator Noise,” by Vice Chair for Generators Craig Courter, maintenance manager at Guadalupe Power Partners LP, was the perfect segue for the second: “Generator Belly Bands,” by Bill Dollard, Manager of Contracts and Business Development for AGT Services Inc. The HV portion of the program was anchored by a presentation on “The Use of Ultrasound for Arc Flash and Electrical Failure Detection,” by VP Engineering Mark Goodman of UE Systems Inc.

The final formal presentation, “Early Warning of Stator-Vane Cracking in Combustion Turbines,” by David Sinay, Power Industry Market Manager for Mistras Group Inc, was included in the I&C portion of the proceedings, directed by Vice Chair John-Erik Nelson, Principal Mechanical Engineer for Braintree Electric Light Dept’s Potter 2 and Watson Generating Stations.

In his opening remarks, Courter noted that generators, particularly those installed during the “bubble” years, continue to report key-bar rattle events. Left uncorrected, the condition is conducive to deterioration of the generator stator. The “rattle” can be detected with the Harmonic Noise Index (HNI), a test proprietary to GE that analyses acoustic data. It is a useful tool, the vice chair said, for identifying, prior to disassembly, what may be happening inside a generator.

Unit operating data indicated a slight uptick in vibration on the collector-end bearing. Operating temperature was normal and the low-frequency noise was heard only at base load. The sound was directional and there were no visual indications. Testing proceeded this way, Courter said:

• A generator load test verified that noise attributed to high deck vibration occurred only at base load.

• Onsite vibration analysis, based on a three-point test, identified the exciter end as having higher levels than the opposite end of the unit.

• A third-party vibration analysis confirmed the plant’s findings.

• The harmonic content of the acoustic data was analyzed using HNI to determine the extent to which the 2/rev frequency and its harmonics were present in the overall noise level.

The HNI level calculated was higher than that of a normally operating hydrogen-cooled generator serving a 7FA gas turbine. It also was within an HNI range that suggested significant core/key-bar interaction (Figs 1, 2). The average sound pressure level at base load was the highest of all load points examined. Having accurate diagnostics, Courter said, allowed the plant to run until the next planned outage and to plan and obtain competitive bids for repairs with no exploration costs and no surprises.

1. Slight greasing was found on the belly band and keybar, indicating that the belly band was loose

2. No sign of greasing was in evidence on belly-band bolts, nuts

Dollard began his presentation by explaining exactly what belly bands—a/k/a core compression bands or belts—are and why they may be needed (Fig 3). Simply put, their function is to control radial vibration between the core and stator frame (key bars, building bolts, etc).  As the field rotates, he said, it applies a force to the core that makes it slightly egg-shaped (Fig 4). Depending on the OEM, stator-frame design, size (large units are most prone), the distortion may lead to key-bar vibration.

3. This belly band is comprised of six segments

4. Core is slightly egg-shaped during operation

Dollard asked attendees, “How do you know belly bands are the problem?” He answered that question by offering the following tell-tale signs:

• An increase in stator-frame vibration, usually in the radial direction.

• A step-change or gradual increase in “sound” level.

• Noisier than a sister unit.

• Acoustic survey indicates the unit is more noisy on one end than the other.

• Visual inspection of key bars or building bolts reveal greasing or dusting.

There are three types of belly-band projects, Dollard told the group. They are: (1) inspection and tightening, (2) replacement of existing belly bands, and (3) installation of new belly bands on units that didn’t have them originally, or extra belly bands on units that already have one or more.

It is relatively easy to inspect belly bands installed during frame manufacture, because access doors generally have been provided for this purpose (Fig 5). After removing doors, Dollard said, check bolt torque and verify tightness with a “ring” test of the belly band. If tightening is required, grinding of shims and/or buckles and welding inside the outer wrapper likely will be required (Fig 6) and care must be taken to prevent foreign material from entering the generator (Figs 7, 8).

5. Access doors are removed to inspect belly bands

6. Grinding shims and welding usually are necessary to tighten belly bands. Band shown is snug against round key bar; key bars also may be rectangular in cross section

7. Tent prevents rain and airborne debris from getting into outdoor units open for belly-band inspection, installation, etc

8. Plastic sheeting prevents metal filings, dropped bolts, weld spatter, etc, from escaping into the generator

A user asked, “Why might you replace or add belly bands?” Replacement usually is motivated by improper design, the AGTServices expert said. For example, the band might be of the wrong diameter relative to core OD, or the material might not be quite right for the application. Poor installation or broken bands are other reasons for replacement.

When belly bands must be installed in an operational unit to reduce vibration, it often is necessary to provide one or more access doors. Blisters, where used to facilitate the flow of cooling air, must be removed first (Fig 9). Then doors are cut in the wrapper with grinders (Fig 10), until about 1/32nd of an inch of steel remains. Chisels are used from this point on to help keep debris from getting inside the unit. FME (foreign material exclusion) considerations contribute to the time-consuming process. It normally takes a couple of weeks to add belly bands on a GE 324 generator (Fig 11). Final welding after installation of belly bands is shown in Fig 12.

9. Blisters are removed to access the wrapper

10. Access doors are cut into the wrapper

11. Belly-band installation on a GE 324 generator takes about two weeks

12. Wrapper and blisters are welded back in place and the generator is repainted

Testing after completion of work should include standard outage electrical testing and an EL CID test if the field was removed. You might want to check core torqueing as well, if accessible—in particular if data indicate the possibility of core looseness. Validate your efforts with an acoustical survey on restart and a visual check during the next major outage. Finally, does the generator sound quieter? Does the floor not shake as much?

Dollard’s presentation focused on GE generators. Regarding Westinghouse units, he mentioned that they generally should be core-torqued every 10 years or so and that requires removal/replacement of belly bands where installed.

Goodman began by asking the group to consider ultrasound an integrating technology because it can be used with infrared and vibration inspections, or alone, to detect impending failures in a wide variety of mechanical equipment—from gears and bearings, to pumps, to steam traps—as well as to locate leaks and to warn of potential failures of electrical equipment. The technology has the capability to sense high-frequency sounds transmitted either through air or solids and to translate those sounds into lower frequencies, within the range of human hearing.

Airborne ultrasound is effective, Goodman said, because all operating equipment and most leakage issues produce a broad range of sounds; plus, the high-frequency ultrasonic components of these sounds are extremely short wave in nature. Because these short wave signals are fairly directional, Goodman continued, it is relatively easy to detect their exact locations by separating them from other noises. Warnings of degradation in mechanical equipment can be detected early—well before failure—and often before vibration or infrared methods can be of help.

Goodman stressed the value of ultrasound for electrical inspection of closed cabinets, such as motor control centers, and suggested that it be used in conjunction with infrared technology. One “hears,” he said, the other “sees.” Airborne ultrasound can identify the ionization characteristics of corona and arcing, while infrared thermal imaging identifies the heat generated at loose connections and by bad fuse clips, overloaded wiring, bad or worn breakers, and load imbalances.

Goodman focused for a while on the hazards of arc flash, what it is, and how it occurs. Most, if not all attendees, were at least familiar with arc flash from plant safety training. Ultrasound, he said, enables operators to scan cabinets housing energized electrical equipment to be sure no arcing or tracking is present before an access door is opened.

Sound analysis, the next topic in Goodman’s “short course,” may have been the most valuable part of his presentation. Recordings of sounds created by corona, loose components, arcing, tracking, etc, enabled attendees to experience first-hand the capabilities of the technology. Goodman stressed that it always is necessary to examine both the noise-spectra and time-domain images to evaluate the severity of the condition being examined.

Fig 13 illustrates the spectrum for corona with sound in decibels on the vertical axis and frequency on the horizontal axis. The peaks occur at 1x, 2x, . . . nx, where x is 60 Hz. Note that the amplitudes of sounds between the peaks are about half those of the peak amplitudes. The time series in Fig 14 reveals a uniform band of signals in both spacing over time (horizontal axis) and amplitude (vertical axis), with very few peaks extending much above the average “band.”

13. Corona spectrum. Sound amplitude in decibels is on the vertical axis, frequency in Hz on the horizontal axis

14. Corona time series. Amplitude is on the vertical axis, time on the horizontal axis

Sinay introduced users to acoustic-emission monitoring technology capable of detecting cracking of compressor stator blades while the unit is operating. Mistras Group Inc’s Acoustic Combustion Turbine Monitoring System (ACTMS™) has been installed on forty gas turbines to date and is credited with at least one documented “save,” having detected and located an S1 vane crack in an F-class gas turbine at a combined-cycle plant owned and operated by Florida Power & Light Co (Fig 15).

15. ACTMS™ locates a crack in a 7FA S1 vane

He reminded attendees that vane cracking in some engine models is a recognized industry concern. ACTMS’s non-intrusive sensors, mounted on the turbine case by magnets or waveguides that transfer the cracking energy to the sensor while dissipating heat. A typical installation on a GE 7FA has 12 sensors arranged in a conical array to detect cracking in rows S0 through S5, an area of concern.

The sensors are wired to a monitoring system located outside the turbine enclosure that evaluates sensor signals in real time. Use of multiple sensors enables ACTMS to locate the position of a crack in three dimensions for follow-up verification during a borescope examination. Details on how ACTMS works are in Sinay’s presentation, available through CTOTF’s Presentations Library along with the other presentations summarized here. Access is available to all registered (a process that takes just a few minutes) employees of gas turbine owner/operators.

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President Rod Shidler and Field Service Manager Mike Hoogsteden of Advanced Turbine Support LLC had no sooner finished presenting on the results of recent inspections of Siemens 501FD2s and GE aeros at CTOTF’s™ 38th annual Spring Turbine Users Conference when one of the company’s technicians forwarded photos of significant damage to the trailing edges of 41 third-stage buckets on a GE7FA (Fig 1). It looks as if something took a bite out of the buckets.

What apparently had happened was that a repair weld holding a section of flex-seal ring pipe in place cracked allowing the pipe section to liberate and damage the buckets, located only an inch or two away from the flex seal. Two of the lessons learned: (1) Be sure this part of the engine is on your inspection check list. (2) Repair welds in the exhaust section have an element of risk given the high temperature (nominal 1000F) and very turbulent nature of the gas stream—especially so when the work is done on engines subject to daily thermal cycles.

To understand exactly what happened, please read on. A necessary first step is a review of the arrangement and general design of the components involved. For this information, the editors reached out to David Clarida of Integrity Power Solutions LLC. The exhaust system expert, licensed by the OEM to make repairs downstream of the turbine section, had just participated in CTOTF’s GE E-class and Legacy Roundtable on the same subject. The exhaust systems on most GE E- and F-class units are nearly identical.

Clarida began by pointing out that the same components often are referred to by different names in industry discussions so it’s important to look at the diagrams as you read further. Fig 2 shows the arrangement of 7FA components from the R3 bucket row to a point about 6 ft beyond the turbine exhaust flange. Note, in particular, the locations of the flex seal, flex-seal ring pipe, and exhaust-frame outer diffuser, and the proximity of the flex-seal ring pipe to the shroud blocks and the rotating R3 buckets.

The flex seal essentially is formed by a couple of layers of thin-gauge metal sheet that slide into a slit in the flex-seal ring pipe on one side and a slit in the exhaust-frame casing on the other side (Fig 3). Its purpose: Provide a barrier between the hot exhaust gas and cooling air for the bearing housing while allowing the exhaust-frame casing and outer diffuser to expand and contract independently of each other.

By their nature, function, and environment, flex seals are subject to wear and tear conducive to failure. When the barrier between the exhaust and cooling air is breeched, one of two things is likely to happen: Air from the exhaust-frame blowers escapes into the exhaust stream, thereby starving the bearing housing of cooling, or if the backpressure is high enough, exhaust gas would flow into the cooling circuit and possibly overheat the bearing housing. Thus regular inspection by a trained professional is important.

Clarida said that the flex-seal ring pipe is in two sections—one for the upper half of the unit, one for the lower half. They meet at the horizontal joint. The flex seal is divided into several sections. When a flex-seal segment fails, one possible solution (not recommended) is to cut out a section of ring pipe in the affected area, replace the damaged seal segment, and reweld the section of ring pipe in place. The alternative is to remove the upper half of the casing and replace the entire ring pipe and flex seal in the affected half of the unit.

This obviously is the more expensive and time-consuming option, but Clarida said it is the only way to ensure against the weld cracking and ring-pipe segment liberation shown in the photos provided by Advanced Turbine Support (Fig 4-6). It is very difficult to make quality weld repairs of the type required, he continued, because of the tight spacing between the shroud blocks and the ring pipe. The circumferential welds at the ends of the pipe segment being replaced are particularly challenging.

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These are tough times for electric utilities. Many people seem to believe they know more about the business of producing and delivering electricity than company executives, who are challenged daily by demanding questions and opinions from regulators, politicians, customers, special-interest groups, and others about everything from species displaced by new infrastructure to the unfair price of electricity produced “free” from solar and wind resources.

Having both viable and politically correct answers to questions yet not thought of is part of the job. For the generation side of the business, this requires a living plan for producing power five, 10, and 15 or more years from now at competitive prices and consistent with unspecified regulatory requirements. Variables and unknowns should be evaluated independently and often to provide the most accurate and current information to executives on the front lines and for inclusion into integrated resource plans required by state authorities.

One ongoing study at NV Energy, and probably many other generators as well, involves identifying possible upgrades for existing assets capable of satisfying near-term increases in demand and delaying the need for new resources. Staff Engineer Susan Hill provided users attending the Regulatory and Compliance Roundtable at CTOTF’s™ 38th annual Spring Turbine Users Conference a valuable methodology for doing this. Generation strategy is one of Hill’s responsibilities at NV Energy. The Georgia Tech Chemical Engineer has more than 15 years of experience in power-generation operations and process optimization in the utility, pulp-and-paper, and pharmaceutical industries.

Upgrade options now being considered by NV Energy include these:

• Cooling of compressor inlet air using absorption or mechanical chillers, or inlet fogging. Each of these enhancements boosts compressor mass flow, which increases power production. Adding thermal-storage capability to a chiller package can further improve performance by reducing chiller size and shifting power consumption to off-peak hours. The latter provides more power for sale during peak periods.

• Engine performance improvements offered by OEMs and third-party providers. Examples include:

1. A Siemens FD3 upgrade for the utility’s four 501FD2 gas turbines.

2. Replacing hot-gas-path (HGP) parts in NV Energy’s eight 7FAs to those provided in GE’s Dot-04 package.

3. Upgrading HGP parts on all F-class frames with a third-party supplier’s latest offerings.

4. Adding GE’s OpFlex to improve the operating flexibility and performance of the company’s 7FAs.

• Using TurboPHASE™ to boost peak output and respond quickly to grid requirements.

• Power augmentation by injection of steam or water to increase compressor mass flow.

• Addition of PV capability where switchyard capacity is available.

• Replacement of seals and hardware on steam turbines to return the machines to as-new condition.

• Addition of wet cooling capability to plants served exclusively by air-cooled condensers, to reduce backpressure and increase generation when ambient temperatures are highest.

• Installation of a packaged boiler to take advantage of unused steam-turbine capacity.

Key steps in the process outlined by Hill and co-presenter Jonathon Bader, PE, of Sega Inc, an engineering firm, were the following:

• Identify possible upgrades.

• Identify any plant limitations.

• Perform high-level design of upgrades for applicable units.

• Determine potential capacity increase for each upgrade.

• Assess upgrades for complexity.

• Estimate lead times for projects.

• Evaluate environmental/permitting limitations.

• Determine controls upgrades required, if any.

The next level of investigation involved these tasks, among others:

• Evaluate the candidate facility’s balance-of-plant infrastructure for supporting the proposed upgrade.

• Use thermal engineering software to gauge performance.

• Estimate capital cost and the incremental increase in plant variable costs.

• Conduct an environmental assessment that evaluates the possible impacts of the following environmental statutes: PSD (Prevention of Significant Deterioration)/BACT (Best Available Control Technology), NSR (New Source Review), NSPS (New Source Performance Standards).

The environmental assessment portion of Hill’s presentation was of particular interest to attendees who had never participated in PSD, NSR, and/or NSPS evaluations. What quickly became apparent was that no particular upgrade could be applied across the utility’s fleet with equal success. One reason for this is the many locations of the company’s generation assets and the different rules that can apply to each. To illustrate: About three-quarters of NV Energy’s capacity is in southern Nevada, specifically Clark County; most of the remainder is in northern Nevada, relatively close to Reno. Some Clark County assets are in PM10 non-attainment areas; plus, ozone rules are not well defined for the county going forward. Northern plants are in an attainment area.

PSD analysis needed? One of the first questions you should ask when evaluating upgrade options is, “Will it trigger PSD analysis?” PSD rules, Hill pointed out, apply to both attainment and non-attainment areas and analysis is required if your project results in a significant increase in emissions. The next question likely is, “What is significant?” To determine that, compare the potential increases in emissions of criteria pollutants attributed to the upgrade with the “significant emission rate” (SER) in tons per year for each pollutant as specified in the PSD rules. These numbers are as follows: PM10, 15 tons/yr; PM2.5, 10; NOx, 40; VOC, 40; CO, 100; CO2e, 75,000. 

In case you read through the list quickly, take note of the last entry. Greenhouse gases (GHG)—including CO2, CH4, N2O, SF6, and certain fluorocarbons—became regulated under the federal Clean Air Act in 2011. The CO2e designation stands for carbon-dioxide equivalency or the amount of CO2 that has the same global warming potential as the mixture of greenhouse gases.

The bottom line: If the emissions after the upgrade exceed the pre-upgrade emissions by more than the SER, PSD analysis is necessary, Hill said. The next question probably is, “What does PSD analysis involve?” According to Hill, it means (1) air dispersion modeling for NAAQS (National Ambient Air Quality Standards) and PSD, and possibly ambient-air modeling as well, and (2) BACT review and possibly installation. Even if the upgraded facility satisfies BACT, she said, the process adds time and expense to the project. 

In sum, Hill stressed that if PSD analysis is required for upgrading a relatively new unit the best outcome is a longer permitting process, later project implementation, and higher cost; the worst, modification of existing controls. For older units, expect that you’ll have to install BACT, which probably means a sizeable investment.

NSR is another hurdle that must be cleared. It is applicable to construction or modification of a major stationary source. The obvious question from anyone considering an upgrade is, “What is meant by modification?” Colin Campbell of RTP Environmental Associates Inc, who presented on the challenges of NSR during the same session as Hill, said that “modification” as defined by Congress was, “Any physical change in, or change in the method of operation of, a stationary source which increases the amount of any air pollutant emitted by such source or which results in the emission of any air pollutant not previously.”

EPA’s “major modification” definition in NSR rules is narrower and more specific, he continued. Specifically, (1) It allows for exclusions for some types of changes—for example, routine maintenance/repair/replacement, (2) It establishes de minimis exemption levels for emissions, and (3) It clarifies that emissions increases are determined based on actual annual emissions.

But that’s not all. Campbell said that after much litigation, the current status is that (1) exclusions must be interpreted narrowly, consistent with Congressional intent, and (2) whether maintenance/repair/replacement is routine or not may be based on the nature, extent, purpose, frequency, and cost of the project. Apparently, upgraded replacement components—such as HGP parts—could be considered a “major modification,” in at least some cases. However, the deal breaker for many upgrade projects might well be GHG.

Next steps. Hill began wrapping up by asking, “Now we know the ‘triggers’ for additional permitting and possibly capital, how do we estimate without a full detailed emission analysis?” The answer, she said, it to make some simplifying assumptions and calculations, such as these:

• Assume emissions in pounds per million Btu of heat input will not change.

• Calculate the fuel increase required by upgrade under consideration.

• Assume a number of operating hours at the higher rate of fuel input.

• Calculate the increase in pollutant emissions and compare them with the SER and other “triggers.”

• Highlight those projects that come within 50% and 100% of SER.

Then rank projects based on cost and risk and decide which ones to take to the next level of evaluation, which involves the following:

• Detailed engineering.

• Detailed review of permitting implications—including potential changes in SCR performance.

• Develop performance curves for use in production cost modeling to quantify the benefit of each proposed project in the dispatch model.

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NERC/FERC compliance matters dominated the afternoon session of CTOTF’s™ Regulatory and Compliance Roundtable with Vice Chair Alan Bull of NAES Corp making formal presentations on the latest version of PRC-005, “Transmission and Generation Protection System Maintenance and Testing,” and the key elements of a strong internal compliance program. Bull, an electrical engineer with more than a decade of industry experience, has NERC compliance responsibility for all of NAES’s facilities in North America. Roundtable Chair Scott Takinen, director of executive projects for fossil generation at Arizona Public Service Co, chipped in with a case history on his company’s audit experience in the WECC (Western Electric Coordinating Council) region.

A considerable amount of equipment is aggregated into “protection system” as defined by PRC-005: protective relays, communications systems, voltage and current sensing devices, station DC supply, and control circuitry. NERC has spent five years updating the standard, which includes specific maintenance and testing guidelines. PRC-005-2 was adopted by the NERC Board of Trustees on Nov 7, 2012 and is now awaiting regulatory approval by FERC. This is expected in June, Bull told attendees.

Judging from the large number of PRC-005-1 violations self-reported, or identified during audits, over the last several years, many owner/operators could use a primer on how to avoid citations. And that’s what Bull prepared for attendees. The presentation was robust, encompassing nearly 100 slides, the vast majority content-rich.

The failure of users to maintain proper documentation and to do all the maintenance required by the standard accounted for most of the violations, as the summary list below suggests. The violations generally indicate a lack of procedural rigor and/or unfamiliarity with the tasks required. 

• No summary of protection-systems maintenance and testing procedures.

• Maintenance and testing intervals not defined.

• Basis for maintenance and testing intervals not documented.

• Protection-system maintenance and testing program did not include all the component types as defined by NERC.

• Missing documents. More specifically, an inability to document implementation of maintenance and testing procedures.

• Failure to complete maintenance and testing procedures within prescribed intervals.

The first part of Bull’s presentation helped attendees refresh their knowledge of the types of protection systems used in electric generating facilities. It included a list of more than a dozen generation protection relays you’re likely to find in most plants. Bull noted at this point that the existing definition of “protection system” does not include auxiliary relays; therefore, maintenance and testing of such devices is not explicitly required at this time.

Bull’s review of the proposed changes to PRC-005-1 was comprehensive and especially valuable to those in the group who had difficulty complying with the first version. Details were well organized. There were individual slides for each of the components/systems identified in the second paragraph above. They identified the component of concern, the maximum maintenance interval, and the maintenance activities required.

For example, in Table 1-2 for communications systems, one entry is for “any communications system with continuous monitoring on periodic automated testing for the presence of the channel function, and alarming for loss of function.” The maximum maintenance interval is every 12 calendar years (second major for a base-load combined cycle). One of the maintenance activities specified is to “verify that the communications system meets performance criteria pertinent to the communications technology applied—for example, signal level, reflected power, or data error rate.”

Bull then reviewed the proposed time lines for implementation of the various requirements of PRC-005-2, which ranged from 12 months to the 12 years. This was the perfect segue to well over a dozen slides detailing “appropriate evidence” to assure that you have the required paperwork to verify the results and prove you conducted the necessary maintenance and tests properly. A series of slides answering frequently asked questions closed out the presentation. Bull’s slides are available at www.ctotf.org in the Presentations Library.

Compliance culture. Bull opened this presentation on the culture of compliance with a FERC policy statement: A company should act “aggressively to adopt, foster, and maintain” an effective culture of compliance, and have in place “rigorous procedures and processes that provide effective accountability for compliance.” Interestingly, while there are no FERC requirements for having an Internal Compliance Program (ICP), it is important that your facility’s/company’s compliance culture be viewed positively by regional auditors. Having a highly rated compliance program could reduce, possibly eliminate, the civil penalty that otherwise would be imposed if a violation were to occur.

Regional auditors, the vice chairman continued, are required to assess and document your company’s compliance culture as part of the audit process. Such assessments involve completion of a compliance-culture survey, plus ICP review. Among the variables that auditors factor into their assessments are these:

• Compliance history and repetitive violations.

• Failure to comply with compliance directives.

• Self-disclosure and voluntary corrective action.

• Degree and quality of cooperation during the audit process.

• Concealment of violations.

Thirteen assessment areas are used by the audit team to evaluate your plant’s/company’s ICP. Here are questions the auditors ask themselves:

• Was the ICP well documented and widely disseminated throughout the entity?

• Has the plant/company named and staffed an ICP oversight position and is that position supervised at a high level? Does the oversight position have independent access to the CEO and/or board of directors?

• Is the ICP operated and managed independently of those responsible for compliance with reliability standards?

• Does the plant/company have sufficient resources for its ICP?

• Is the ICP a living document?

• Does the ICP:

1. Have the support and participation of officer-level management?

2. Provide for appropriate and sufficient staff training?

3. Include formal, internal self-auditing for compliance with all applicable reliability standards on an established periodic basis?

4. Include disciplinary action for employees involved in violations of the reliability standards, if appropriate?

5. Have internal controls—including self-assessment and self-enforcement to prevent recurrence of reliability-standard violations?

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