501F users share best practices with colleagues

The 501F fleet was recognized by peers with five Best Practices awards in the 2018 judging. The annual program, sponsored by CCJ, has as its primary objective recognition of the valuable contributions made by owner/operator personnel to improve the safety and performance of generating facilities powered by gas turbines. In this section, 501F plants share their methods and procedures for continual improvement in the areas of safety, predictive analytics, O&M, and water management.

If you’re behind in your reading, note that the 2018 best practices for aeroderivative plants were presented in earlier in the year. The Best of the Best award recipients were saluted more recently include two more 501F plants (Ontelaunee and Tuxpan):

AMP Fremont’s transparent wall and curtain protect staff from chemical hazards

Cramped quarters in the water-treatment building at this 2 × 1 501F-powered combined cycle, home to the demin plant and chemical injection skids, created an unintended safety hazard because of the caustic and acid required for regeneration of mixed-bed resin. While the high-pressure chemical injection systems were equipped with flange shields, an unsuspecting person entering that space could, in the event of a leak, be sprayed with caustic or acid.

Among the proposed solutions not recommended by the safety committee were signage and relocation of the chemical skids. The use of heavy protective curtains also was evaluated, but personnel thought they could create another hazard: In the event of a leak, the curtains might prevent operators from seeing the spray in time to avoid walking into it.

Fremont’s maintenance team proposed the solution selected: see-through chemical-safe curtains for the entryway and an enclosure of transparent Plexiglas® panels to provide an unimpeded view of the skids (photo). The best part of the plan was that personnel protection was assured for only about $2000 in labor and materials.

Fremont Energy Center, Fremont, Ohio, is owned by American Municipal Power Inc (AMP) and operated by NAES Corp. Plant manager is Craig Bonesteel.

Safety underpins Dogwood’s approach to predictive motor maintenance

A challenge facing the empowered staff at this 2 × 1 501F combined cycle was how perform predictive maintenance (PdM) on low- and medium-voltage motors while reducing—with a goal of eliminating to the degree possible—personnel exposure to electrical hazards and improving the accuracy and repeatability of data collected.

Historically, a contractor has performed the testing necessary to capture the online and offline data required. To do this, the vendor would open the motor feeder cubicle to connect test leads and then leave that cubicle open while the motor was started to permit data collection.

The contractor was required to follow NFPA 70E requirements, but even when wearing arc-flash protective clothing, he could not safely connect the leads necessary for online testing to the medium-voltage bus. The voltage was monitored at the cubicle being tested using a test cart and multiple cables strung throughout the area. Because of the electrical hazards, the contractor had to wear NFPA 70E gear while collecting data on a laptop.

To address the challenge, Dogwood implemented PdMA Corp’s MTAP technology for testing LV and MV equipment. It uses current transformers (CT) and potential (voltage) transformers (PT) to reduce hazardous currents and voltages to levels that meet OSHA and NFPA 70E requirements.

The safety system was installed on each MV motor covered by the plant’s six-month predictive maintenance plan—one MTAP to monitor current, another to monitor bus voltage. This upgrade protected contractor personnel from electrical hazards. Each MTAP was mounted to the cubicle door, allowing data collection by simply plugging the test lead into the receptacle (photo). 

Installation of the MTAPs allows the simultaneous collection of data from multiple devices at multiple locations without requiring equipment isolation. This saves money by reducing the number of contractor visits required because of plant conditions. Plus, nuisance traps have been reduced because cubicle doors remain closed during the procedure.

More benefits attributed to MTAP technology: (1) Data can be collected by one person and in only five or six hours compared to a full day previously. (2) Having specific test points with the CTs and PTs permanently mounted assures data are reliable and repeatable.

Dogwood Energy Facility, Pleasant Hill, Mo, is owned by Dogwood Power Management LLC, the City of Independence, Missouri Joint Municipal Electric Utility Commission, Kansas City Board of Public Utilities, and Kansas Power Pool. It is operated by NAES Corp. Plant manager is Steven E Hilger.

Reducing turbine lube-oil varnish potential at Hobbs

Hobbs Generating Station’s combined cycle is equipped with two M501F gas turbines and a D11 steam turbine. The GTs have 5000-gal lube-oil reservoirs, the steamer a 3600-gal tank. After eight years of service, the varnish potential of GT lube oil, based on the Membrane Patch Colorimetric Test (MPC) results, ranged from 46 to 50, the ST fluid was more than 20.

Plant’s goal was to reduce the varnish potential and safely extend the life potential of these reservoirs, thereby deferring the cost of replacement oil to coincide with a future planned outage.

Working with Hilliard Corp’s HILCO Div, plant personnel and lube-oil experts developed a plan to recover the reservoirs to acceptable varnish-potential levels as quickly as possible to prevent further oil degradation and not disrupt Hobbs operations. The solution was to treat the reservoirs by using a temporary, portable oil-conditioning unit with a remediation dosage of dry-resin ion-exchange media in a kidney-loop arrangement.

Concurrently, Hobbs staff repurposed HILCO oil conditioners no longer required by a sister plant to maintain low varnish-potential levels going forward with a much smaller amount of ion-exchange media once the higher-capacity conditioning unit had removed the bulk of the varnish.

Results were immediate and impressive. After only 24 hours of operation of the bulk treatment conditioner on GT1, a substantial improvement in the appearance of the oil samples was observed. Varnish potential was reduced from 50.5 to 28.3 MPC. Similarly, after GT2 had one of the 3.5-gpm repurposed oil conditioners hooked up for 24 hours, samples showed the varnish potential had been reduced from 46.1 to 34.9 MPC.

Long-term results: During the eight-week monitoring period, the varnish potential on GT1 turbine lube oil was reduced from 50.5 to 3.7 MPC, on GT2 from 46.1 to 3.8 MPC, and on the steam turbine from 21 to 2.7 MPC (figure).

Lea Power Partners LLC, Hobbs, NM, is owned by Western Generation Partners and operated by Consolidated Asset Management Services (CAMS). Plant manager is Roger Schnabel.

How State Line’s cooling tower operates in extreme cold without freeze-up

Operating cooling towers can be problematic in extremely cold weather, when the minimum amount of cold-air cooling exceeds heat-transfer requirements and starts to affect the plant cycle. Compounding this problem, ice can form on the outside of the tower and, if left unchecked, can accumulate, possibly causing structural damage, safety hazards, and perhaps even a plant shutdown.

To prevent ice-related issues, State Line personnel came up with a simple but effective solution. Perhaps the best analogy is the cover semi drivers put on the front of their rigs in extreme cold. These “winter fronts” reduce the amount of cold air entering the engine compartment to maintain the optimum operating temperature.

This same principle was adopted for the State Line cooling tower. Pipes were installed longitudinally down both sides of the tower, along horizontal fiberglass members. When temperatures are very low, warm water is run through these lines at circulating-water pressure, to provide an additional curtain of warm water and prevent ice formation. Since implementation, the plant has not experienced an outage caused by cooling-tower icing.

State Line Power Plant, Joplin, Mo, is owned and operated by Empire District, a Liberty Utilities company; Westar Generating Inc is a co-owner. Plant manager is Brian Berkstresser.

Chlorine dioxide bests bleach for organics control at High Desert

High Desert Power Project, a 3 × 1 501F-powered combined cycle, uses a zero-liquid discharge system to process cooling-tower blowdown for recycle. The ZLD system incorporates microfiltration, softening, two stages of reverse-osmosis concentration, forced-circulation crystallization, and a centrifuge for crystallizer solids removal. The plant’s desert location dictates the use of multiple makeup water sources of varying quality, making microbiological and organics control challenging.

The facility historically used bleach to control organics in the cooling-water system, but the existing bleach feed system was unreliable. Erratic oxidant feed impacted ZLD-system performance and caused disturbances in the cooling-tower blowdown system, wasting time and money.

To achieve good results, free-chlorine concentrations often exceeded 1 ppm. Performance was mixed using bleach: Plate counts were acceptable, but sessile populations were high, indicating the presence of a highly insulating biofilm.

Extensive research convinced plant personnel to replace bleach with chlorine dioxide. The biocide supply system selected, a turnkey solution from Nalco, uses sulfuric acid and the chemical company’s Purate™ to make chlorine dioxide. Use of chlorine dioxide reduced RO membrane cleanings, improved cooling-tower appearance, improved reliability in biocide application, helped optimize manpower requirements, reduced chlorides, reduced corrosion potential in the condenser, and lowered the total cost of operation.

The new system runs reliably and the proper concentration of oxidant is applied consistently. Chloride loading on the ZLD plant was reduced by at least 15% and microbial monitoring shows good control of both planktonic and sessile bacterial populations. The tower is consistently cleaner. Plus, RO and microfilter membrane cleanings have been halved. Finally, the use of chlorine dioxide is less expensive than bleach in terms of total operating cost.

High Desert Power Project, Victorville, Calif, is owned by Avenue Capital and operated by NAES Corp. Plant manager was Claude Couvillion at the time the chlorine dioxide project was implemented. Victor Barron is the current plant manager.

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Special Report: Ovation Users Group 2018 meeting

More tools, more features, fewer connections: Ovation scope expands

There were reasons why David Farr, chairman/CEO of Emerson Corp, parent to Emerson’s Power & Water Solutions (PWS) business, delivered the opening address at the annual Ovation Users Group Conference, held in Pittsburgh, July 29 – Aug 2. At least one could speculate, reading between the lines, that it had something to do with financial issues of peer group industrial conglomerates making headlines.

First, he offered five bullet points on what it takes to sustain leadership:

    • Be secure in yourself but never become arrogant.

    • Do more listening than talking.

    • Trust your moral compass and promote truth and integrity.

    • Take calculated, well-thought out risks.

    • Continue to learn and drive for change.

While these were geared towards personal leadership, the implications for corporate leadership are obvious.

Farr also talked about winning and commitment, specifically how PWS President Robert Yeager set out a plan 20 years ago to be Number One in this business and how Emerson corporate unwaveringly committed to the power and water sectors after its acquisition of Westinghouse Process Control in 1997. “Bob knows how to win,” Farr said. And from the humorous bantering that went on between Bob and David, it was clear that losing isn’t well-tolerated in the Emerson C-suite.

Without speaking to it directly, Farr reminded the audience of hundreds of Ovation™ users, and prospects and partners, that Emerson is not having the same commitment issues as several other behemoth OEMs of the power industry. “The industry is under a lot of stress,” he noted. He went on to describe inexpensive electricity as a competitive weapon and that the industry has to be totally predictable. It wasn’t hard to think up a few big names which haven’t exactly behaved “predictably” in recent years.

The path forward

Yeager took the stage after Farr and used his time, as he often does, to assume bragging rights for the successes of the last 12 months. This year, however, there were some very notable distinctions.

“We’ve introduced more new products in the last three years than in the history of PWS,” he said. The Ovation version of the “digital twin” now includes over 200 algorithms to simulate systems using real-time data and for monitoring performance and health of equipment. Making the automation platform smarter is one way to address what Yeager identified as the Number One issue facing industry executives (according to a popular annual survey): the aging workforce.

He claimed Ovation being Number One globally. Some of the evidence:

    • Ninety-three of the 130 1000-MW supercritical boiler units in China have Ovation automation.

    • Three-hundred Ovation systems were added to the global roster in 2018.

    • The company now has completed over 400 GE gas- and steam-turbine control retrofits and 30 Ovation generator control systems.

    • There are 1.3-million MW of generation capability with Ovation automation, 450,000 MW in the US. Note that these numbers are similar to what was reported last year.

    • Twenty-nine Ovation “embedded simulation” projects have been completed and 33 are in progress.

    • The first wind turbines are being controlled by Ovation, anchored by its new Compact Controller (formerly the OCC 100, Ovation’s answer to the PLC), and the company has announced recent new-build solar project awards, its first grid-scale storage project, and a unique “grid controller” project in Hawaii.

Perhaps the most interesting announcement, given the times we live in, is that Ovation has been designated as “qualified anti-terrorism technology” by US federal government authorities, which provides significant legal protection to Ovation users whose systems were deployed beginning Jan 1, 2009.

As if to reinforce Farr’s emphasis on commitment, Yeager observed that the competitive advantage afforded by technology is short-lived and “customer service is where the edge is found.”

Building out the platform

For the hard-core Ovation geek, Steve Schilling, VP technology/R&D, rattled off some of the advancements and improvements in the platform—such as “harmonized Ethernet Link Controller protocols,” “microsecond loops with integrated I/O,” “updated hardware platform,” and many others.

The broader messages for the non-geeks included these: 

    • Ovation is “getting rid of connections” which makes the system more reliable, and native prognostic, performance monitoring.

    • Analytic applications are being built into Ovation embedded simulation and the process historian. Schilling noted, for example, that future releases will incorporate advanced pattern recognition (APR) models directly in the Ovation I/O modules, will be integrated with the PlantWeb digital ecosystem, and identify specific fault conditions and recommendations for staff.

Like string theory

Of course, with digital transformation comes digital vulnerabilities. Cybersecurity continues to suck up more and more of the oxygen in the room. In fact, Schilling likened the cybersecurity dimensions of patch testing, the matrix of supported products, chain-of-custody compliance, device control, asset inventory control reports, and domain “trust relationships” between Ovation and customer corporate IT managers to string theory in physics. “It has 28 dimensions,” he joked.

Jaime Foose, who heads PWS’s cybersecurity and customer services group, noted that the organization now has close to 40 professionals devoted to 24/7 telephone support for customers in North America and Latin America. Delivering on a promise from the 2017 Users Group, Foose announced the availability of the “Preventive Maintenance Guide,” with example checklists for system lifecycle support, segmented by workstations, controllers, network, I/O, the Power and Water Cybersecurity Suite, and others.

Foose added some gravity to Schilling’s 28 cybersecurity dimensions. A slide with dozens of cybersecurity firm “brands” for various protective functions (Fig 1) comes across like a work of modern art—each individual brand disappears into a chaotic blur. The underlying message? Leave it to Emerson’s cyber experts who understand both IT security and power generation, unlike pure IT firms. Plant managers may want to benchmark their cybersecurity activities to the broad levels and actions shown in Fig 2.

Results speak volumes

As in past years, the industry breakout sessions included user presentations illustrating the benefits of different aspects of the Ovation automation platform.

Case history 1

A 3750-MW combined-cycle facility, with three 3 × 1 units installed between 2009 and 2011, needed faster start times and implemented Ovation’s advanced startup automation features. The plant already had experienced close to 650 total GT/HRSG starts in 2018 by the time of the meeting, and the number is projected to surpass 1000 annually going forward. Automating overnight cycling of all nine GT/HRSG trains, with onsite modifications incurring no outage time, is saving close to $1-million in fuel costs alone.

Now there’s “one button for a pre-start, and one button for a GT start,” according to the owner representatives making the presentation, and “we’ve gone from hundreds of clicks per start to 11 clicks!” They reported that operator acceptance was the most difficult challenge, but now operators use it every day.

The plant has reduced hot-cycle startup fuel consumption by 18%. In addition, each start is “more consistent” and involves much less overall financial risk (Fig 4). Even with six-sigma training for plant personnel to improve cycling performance, too much variability was exhibited across the different plant operations teams.

Other benefits from the upgraded controls include $300,000 per combined-cycle unit from model-predictive control of superheater and reheater temperatures, $600,000 across the units from model-predictive NOx control and reduced ammonia consumption, 47-MW/min load ramping through model-predictive unit load control, tighter control over the automatic duct-burner system, and efficient comparisons of operator start signatures.

The new techniques were installed, tested, and proven out on one train, then replicated across the other trains. The project took 30 months from conception to completion, noted the owner reps, but an Emerson manager clarified that a “standard scope would be six to nine months” for a project of this type today.

Case history 2

Another utility with an ageing 685-MW steam unit upgraded its station excitation controls with Ovation-based capability. “You don’t think much about excitation systems until they don’t work,” the presenter said. Indeed, one of the project drivers was four unit trips attributed to excitation in one year. The other driver was obsolescence—replacement parts for the original Brown Boveri generator excitation controls were unavailable.

“Emerson not only had a reasonable delivery schedule (less than 12 months), it was the most ‘open’ of the systems on the market,” said the presenter. He also noted that Emerson was good about working through issues such as lack of adequate cooling capacity in some of the cabinets, an overheated transformer phase which had to be replaced, and failure of the excitation transformer. During the last event, oscillography built into the Ovation system protected the generator.

Case history 3

A utility with a 1230-MW plant acquired from investors and equipped with four 1 × 1 combined cycles had as its objective “consolidating to as few control systems as possible.” However, it left the GT controls to the OEM because of the long-term services agreement (LTSA). The following were part of the project:

    • Replaced the Bently Nevada vibration monitoring system with an Ovation Machinery Health Monitor.

    • Replaced Alstom P320 controls on the steam turbine/generator.

    • Replaced the Alstom exciter cabinet with Ovation.

    • Unified alarms to one 40-in. monitor in the control room.

    • Added Ovation supervisory M&D for the gas turbines.

    • Upgraded the Mark Ve GT controls to Mark VI, with the graphics replicated in the Ovation platform.

Some of the physical plant modifications which came with the project included new gland seal steam valves, instrumentation, and pressure control scheme; instrument calibrations; valve rebuilds; new attemperator valve installed with new automation logic; 6000 I/O points looped and functionally checked; addition of an 800,000-gal fire water tank; and 480-V bus feed rebuilt.

Overall, troubleshooting hours have been reduced, 25-35 minutes have been shaved off of a cold start, and the spares inventory has been lowered. Two “lessons learned” offered to the audience were being more realistic about the project duration and the need for training (no prior Ovation experience at this site), and having a third-party review for the Alstom steam-turbine logic conversion.

Case history 4

A Midwest utility accomplished an Ovation retrofit for a 938-MW Toshiba steam turbine/generator. What makes this project notable is that the unit is only eight years old. The main project driver was that OEM support was “non-existent.” The plant was also able to take advantage of a planned long outage involving boiler retuning, and a ST/G major outage.

Scope included complete logic conversion from the OEM-supplied controls to Ovation, supervisory I&C, overspeed protection, main turbine and boiler-feed-pump turbine drives, fully automated turbine startup, rotor stress calculator, and other “integrated enhancements.” A similar retrofit project was conducted for a large utility in the Southeast. The presenter noted that they still “have a few issues to work out.”

Case history 5

A peaking gas-turbine facility with four simple-cycle units in Wisconsin added diesel engine/generators, black-start capability, and replaced an “obsolete vibration monitoring system.” The Bently Nevada racks were replaced, but the existing GE/Bently sensors were re-used. A new set of controllers for each unit was added, along with the Emerson PeakVue product integrated into the Ovation system. According to the presenter, there are “no longer any data links to maintain.”

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HRSG Tip of the Month: November 2018

How best to replace an HP evaporator: Tubes only or entire harp?

Editor’s note: Online forums hosted by independent users groups are an invaluable communications medium for sharing experiences among industry colleagues. Power Users, which sponsors user-only discussion forums for the groups it manages—7F, Combined Cycle, Generator, and Steam Turbine—most recently launched an online HRSG forum.

It is moderated by former plant manager Bob Anderson. Today a consultant, Anderson is well respected industry-wide for his deep knowledge of heat-recovery steam generators. The HRSG Forum with Bob Anderson,  which he chairs, is the leading meeting for boiler users serving at combined-cycle and cogeneration plants powered by gas turbines.

One of the first posts to the new site was from an owner/operator seeking the experiences of colleagues who have replaced the HP evaporators in their HRSGs. What to do? Remove/replace tubes keeping the headers in place, or remove/replace the entire harp. The user said engineers assigned to this project were struggling to decide where the best location might be to draw a line in the HRSG between what should be replaced and what should be retained.

“As we dig deeper,” he said, “we continue to find parts and pieces which could allow advantages to the OEM if we were to just cut the tubes and leave in the existing headers at the top and bottom of the HRSG.”

Another approach, the engineer continued, is to expand the scope of replacement to allow for new headers with connection points defined as the bottom of the steam drum and the feedwater entry. The team’s thinking was that this might provide a more apples-to-apples comparison as opposed to leaving potential proprietary design elements within the HRSG that other companies might not have rights to.

Anderson contributed to the dialog, sharing that he was aware of one module replacement in which the tubes were replaced while the original headers were retained in place. This was not an economic decision, but required because there was no access for cranes to remove/replace the modules. The logistics of the tube replacement were complex and challenging because of limited access and the need to support and maintain alignment of the lower headers.

Anderson figures the total job cost was higher than for a module exchange and certainly required a longer outage. If you replace tubes only, he added, you must either grind off the tube-to-header weld at each end to replace the entire tube (a very time consuming process with risk of damaging the header), or cut the tubes and make a butt weld to the retained portion of the old tube. The $64 question: Can you know that there is no corrosion damage in the retained tube stubs?

Some HRSGs similar to the owner’s Alstom unit, Anderson said, have a primary HP superheater section upstream of the HP evaporator (relative to gas flow). If so, welding in the new tubes only can be accomplished with the welder on the downstream side of the tube. This likely would require mirror welding—a skill becoming harder and harder to find. An alternative might be an orbital welder.

If there’s no HPSH attached to the upstream side of the HP evaporator, a pair of welders could install the first (center) row of new tubes from both sides, but all other rows would require a welder on one side of the tube only. This “welding your way out” technique means that any leaks deeper than the row accessible from the maintenance bay will require removal/replacement of some good tubes—perhaps many—to access and repair the failure. Anderson estimated the HRSG under discussion has more than 1150 HP evaporator tubes. That’s 2300 welds made from one side that must be perfect.

All other HP evaporator replacements Anderson is aware of relied on replacement harps or entire modules. They were removed/replaced during a much shorter outage than required for the tube-only replacement. Minimizing the number of field welds reduces outage duration and facilitates control over component fit-up, weld quality, NDE inspection, and hydro/repair—if needed. Plus all of these tasks remain outside the outage critical path.

Modules have been removed/replaced by lifting upward out of the HRSG the way they were originally installed (often requiring removal of the HP drum for access), or removal through the side of the HRSG to avoid disturbing the drum. The location of the HRSG side support columns will dictate if the new module can be removed/replaced in one piece or not.

Anderson continued, “If your unit has the two large-diameter fore and aft collection manifolds between the headers and the drum like other HRSGs from this OEM, you have a couple of choices on where to make the upper transition. The tradeoff will be the cost of material replaced versus the number of field welds required. The location of the HRSG’s side support columns may dictate that the second option is possible only if the column permits removing the entire evaporator module intact.

Finally, Anderson recommended against the tube-only replacement option on this project. He suggested asking the bidders to identify and quote their preferred cut points top and bottom (save the collection manifolds and have more internal field welds, or replace the fore-aft manifolds and have no internal field welds and only a few external field welds), plus insist the bidders quote an option for the alternative cut-points they do not prefer.

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Reflecting on the presentations at the Distributed Energy Conference

From central to distributed: The inflection point still not clear

At the Distributed Energy Conference in Denver, Oct 15-17, 2018, one of the electric-power industry’s top analysts came away with the sense that the “inflection,” marking the point at which investment in distributed assets grows faster than that in centralized assets, hasn’t yet arrived. And the timing of its arrival still is not clear.

What is clear is that, like acrimonious separations with high-priced lawyers, the debate is far less about technology and engineering challenges and far more about who is going to make money and how—and how much. (Conference details can be accessed at www.distributedenergyconference.com.)

To explain this requires some recent history. In the early 1980s, after the Public Utility Regulatory Policies Act (Purpa) was passed, along with the Fuel Use Act (already in place to prevent utilities from building new gas-fired power stations), many cogeneration facilities and “Purpa plants” were built. Some were large gas-turbine-powered cogen units serving major industrial complexes; some small ones used alternative fuels like biomass, tires, and manure; some were tiny turbine and engine units (micro-cogen), and some were innovative ways to provide thermal and electric energy at industrial, commercial, and institutional facilities.

What proved difficult, though, was a scalable design and business model. In other words, there were many interesting “one-offs” but few repeatable projects. By the mid-1990s, all that changed with the convergence of (1) the lifting of regulatory restrictions on gas, (2) advanced gas-turbine technology, (3) IPP and merchant investment, and (4) growing electricity demand. Sales of gas turbines, in simple- and combined-cycle arrangements, took off, culminating in the famous installation wave of 1997-2002. Approximately two-hundred-thousand megawatts of gas-fired capacity were added to the grid during that period.

At the Distributed Energy (DE) conference, speakers presented on a variety of challenges and trends, most of which have been aired ad nausea over the last 10 or 15 years. But the range and scope of DE projects highlighted (and discussed during the breaks) were instructive.

Clearly, there’s no shortage of imagination when it comes to DE. Projects ranged from wind + solar + battery facilities; subscription 20-year wind energy purchases from a non-utility wind developer; utility-owned solar, wind, and storage; 11 MW of solar across 18 sites for a county governmental entity; a campus CHP facility recently expanded with a microgrid (and soon to add storage); a campus fuel-cell CHP unit; and others.

What was not clear was whether any of these DE schemes could be scaled and replicated in the region, state, or nationally. One presenter lauded a project with a 2.5-MW wind turbine/generator, 1.3 MW of solar PV, and a 1-MW/4-MWh storage unit, dubbed a “mid-grid solar wind hybrid.” He said there were thousands of attractive locations for this concept. However, he did not mention follow-on projects.

Perhaps it’s folly to even think in terms of the earlier advanced GT boom. After all, those were still largely centralized facilities, many with long-term power purchase agreements with a utility or electricity marketing partner. They fit into the historical capacity expansion patterns of the industry and the tendency of regulated utilities (and the banks that cater to them) to prefer a cookie-cutter, least-risk approach to investment.

When you start with each customer’s individual needs, criteria, and aspirations, however, can a cookie-cutter approach ever work? Perhaps, if the regulated distribution-oriented utility is controlling expansion. If each customer is truly in control, however, all bets on that horse are off. Consider this analogy: How a colleague has downloaded, arranged, and set the apps on his or her mobile devices are probably very different from how you’ve done it.

Several of the conference speakers insisted “the customer is in control.” Really? The industry has been hearing that for two decades. If you have a large load the utility doesn’t want to lose, it’s probably true. If you have a 12-unit rental property, a small commercial building, or a residence, perhaps not. The truth is that the utility industry and emerging DE component still considers the “customer” in the collective sense, not as an individual.

An old saying goes, “never let anyone get between you and your customer.” One speaker noted that the assumptions of the last 100 years no longer hold when it comes to the answer to the question, “Who owns my electric load?” He used the five stages of grief to explain where utilities in the aggregate are today regarding this question. On the scale of denial, anger, bargaining, depression, and acceptance, he thinks utilities are between anger and bargaining.

One of the weapons utilities used to block or stall projects in the Purpa days, and continue to use, is the interconnection (IC) request and analysis. Apparently, it is still a potent weapon. One analyst speaker noted that utilities can block projects by assuming the worst case in the IC evaluation. Even if the worst case is only two hours in the course of a year, the utility can still decline the IC request, at least for projects this speaker is involved with.

We tend to think about California when it comes to DE, mostly because it is said to be the fifth largest economy on the planet (if considered as a country). Whatever works there will, as has been shown in the past, likely be a model for the rest of the nation. But Hawaii is where the pace of the centralized-to-DE transformation is truly ground-breaking, and where the concept at scale likely will be proven first.

According to a speaker from the 50th state, one in three Hawaiian homes has rooftop solar PV. Public facilities there have to be energy net zero by 2030. The state has a mandate of 100% clean energy by 2040, despite the fact that its “grid” is actually six islanded power systems. Almost incredibly, 80% renewable by 2030 has penciled out as the “least cost” path. Keep in mind that renewables are replacing a large component of diesel-based capacity and access to natural gas isn’t a matter of collecting, pipelining, and distributing as it is on the mainland.

The one roadblock, he said, is aligning utility incentives with the DE strategy, and noted that the state is considering a new regulatory model that “breaks the links between traditional system expansion and capital investment.” “That is the key,” he said, “to making the transformation to distributed energy resource management (DERM) move faster.” Alaska is another state moving more quickly than the rest of the nation to a DE future, for many of the same reasons, based on other presentations at the conference.

For the other states benefitting from a more interconnected grid and lower-cost primary energy resources, the degree to which the utility is embracing or resisting DE will be key to the rate of transformation, and what is left of the customer base once they enter the “acceptance” phase.

It seems most of what is being debated at these conferences is not whether the technology is ready, whether the grid can “handle” massive DERM, or what customers really want, but rather who is going to “control the ball” and make the most money scaling and customizing DE resources to respond to real customer needs and desires.

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Factor European experience into O&M practices at US combined cycles, Part II: Aberrant P91 life predictions

At European Technology Development Ltd’s International Conference on Power Plant Operation and Flexibility, held in London in July 2018, ETD’s Dr Ahmed Shibli, the conference organizer, and David Robertson tag-teamed an in-depth presentation on life-prediction concerns for aberrant P91 components often found in electric generating stations worldwide. They are usually the product of not understanding the precise heat-treatment requirements, by the component producers and fabricators, for high-Cr martensitic steels.

The duo issued a stark warning: “Traditional NDE techniques do not show damage in P91/P92 until late in life (70% or later), making current detection and component integrity management difficult.” New techniques are needed.

“A problem with 9Cr martensitic steels,” they said, “is that the creep cavity size for the first 70% of life can be on the nanometer or few-microns level only. Thus, cavity detection and quantification by traditional means, such as replication or UT inspection, can be difficult.”

At the same time, “for aberrant microstructures, powerplants often assume the safe life is equal to P22 or P91. But the industry could be underestimating life, thus condemning these components too early and thereby losing revenue. We currently do not have long-term rupture strength data for such abnormal microstructures to predict their safe operating life accurately.”

The two presenters gave examples of potentially abnormal materials:

    • Material over-tempered or tempered high in the ASME range.

    • Material under-tempered at the bottom of the new ASME range (730C) or old range (704C).

    • Cooling too slowly from austenitizing.

    • Soft spots and soft bands found in some piping materials.

Welding issues include:

    • Various repairs and weld-repair configurations/geometries.

    • Repeat weld repairs.

Type IV failure in seam-welded P91

Next, Shibli outlined a six-year joint industry project that began in 2014 “aimed at producing 15 aberrant microstructures in P91 (both base and weld metals) and conducting stress rupture tests to 30,000 hours, which can then be extrapolated to 100,000 hours and beyond to estimate the safe operating life.”

Initial industry sponsors, coordinated by ETD, are various European and Japanese utilities, although new partners/sponsors are welcome at any stage to contribute towards the testing of one more of these aberrant microstructures. This project also involves detailed metallography, including use of transmission electron microscopes (TEM), to categorize the microstructures and their behaviors.

“To make matters worse and life assessment more difficult,” Shibli continued, “it is now fairly well established that the creep failure stages for high-Cr martensitic steels (P91/P92) are reduced to creep cavity initiation, cavity growth, and failure with little warning.”

Specific visual examples were given for all points made in the presentation. Featured in the examples was Type IV damage in seam-welded components (photo).

“The 9Cr martensitic steels have been very useful in raising powerplant temperatures and pressures (and making HRSGs more compact), improving plant output and efficiency,” Shibli stated. “However, more and more of these components are now showing cracking at the Type IV position associated with the weldments.”

And their conclusion: “Even components that can be identified to be at risk are creating issues for the plant owners and integrity assessors in view of the unknown long-term rupture strength of the aberrant steels, hence the need for the long-term stress rupture data to ensure their safe operation.”

Posted in 501 F&G Users Group | Comments Off on Factor European experience into O&M practices at US combined cycles, Part II: Aberrant P91 life predictions

INDUSTRY NOTES, November 2018

Registration opens for three 2019 user meetings; sign up now and make good use of your 2018 budget surplus

In the last couple of weeks, registration opened for three high-profile 2019 conferences dedicated to the information needs of owner/operators: 501F Users Group, Western Turbine Users Inc, and HRSG Forum with Bob Anderson. The details provided below are intended to encourage your participation.

501F Users Group

Dates: February 17 – 22
Location: Paradise Valley (Scottsdale), Ariz
Venue: DoubleTree Resort by Hilton

The compelling program for this meeting will be posted online shortly. It will have many of the same elements as the information-rich 2018 conference, which ran four days and included the following:

    • User presentations on issues identified in the fleet and solutions implemented, as well as on experience with upgrades to improve unit performance.

    • User-only sessions promoting open discussions and short presentations by owner/operators on safety; compressor, combustion, hot-gas, inlet, and exhaust sections; rotors; auxiliaries; and generator.

    • Special closed sessions, ranging from two to four hours each, by the major products/services providers serving this frame: Siemens, Mitsubishi, Ansaldo Energia’s PSM, and GE.

    • Vendorama progam. At the meeting last February, 33 companies made 35 half-hour technical presentations to bring attendees up to date on products/services of interest to the 501F community.

    • Vendor fair, following the Vendorama program on the first day of the meeting, gives users the opportunity to peruse the offerings of nearly a hundred manufacturers and services firms.

If you have never attended a 501F Users Group meeting, make the 2019 conference your first. You will learn things vital to your plant’s future success that’s not available in one place anywhere else.

Western Turbine Users Inc

Dates: March 17 – 20
Location: Las Vegas, Nev
Venue: South Point Hotel & Spa

GE aero (LM2500, LM5000, LM6000, and LMS100) owner/operators from around the world will share experiences, both good and bad, at the 29th annual meeting of the Western Turbine Users. Get all the details at the group’s well organized, easy-to-navigate website—social events, agenda, special tours, exhibit hall, breakout sessions, etc. Then register and book your hotel room at the same website for the electric-power industry’s largest independent user group meeting. 

HRSG Forum with Bob Anderson

Dates: July 22 – July 25
Location: Orlando, Fla
Venue: Hilton Orlando

With two solid events under its belt, the HRSG Forum with Bob Anderson introduces an expanded program for the organization’s third annual conference and exhibition (diagram), making it the undisputed king of content in the world of heat-recovery steam generators. HRSG Week 2019 begins with a Make-up Water Workshop (July 22) the day before the traditional two-day HRSG Forum and concludes with the morning session of EPRI Technology Transfer Day (July 25).

You can register for the entire program now for only $650; or $475 for the two-day forum plus the EPRI session on Thursday morning. The user-driven program features technical presentations by HRSG experts, with significant time for group discussions and networking with peers. Plus, registrants will receive complete meeting minutes, copies of presentation slides, and up to 24 hours of continuing education units (forum + workshop + technology day).

Visit the website periodically for program details as they become available.

Ring eight bells for Frank Berté, 77

News of Dr Frank Berté’s passing on July 4, 2018 reached us only recently. He was the co-founder of Tetra Engineering Group Inc, perhaps known best by readers of CCJ for its solutions to problems associated with heat-recovery steam generators and high-energy piping systems.

Berté was a frequent participant at user group vendor fairs and an occasional presenter. He was easily distinguishable among the many exhibitors because of his calm, quiet nature in a sea of salespeople. Plus, he never arranged his table display without his funky air-powered simulated flame. You could spot him “a mile away.”

Peter S Jackson, PE, who succeeded Berté as president of Tetra, remembers Frank as an excellent engineer, inspiring leader, and genuinely friendly man. Everyone who knew Frank or worked with him, Jackson said, enjoyed his enthusiasm for work and love of life.

Berté’s career in the electric power industry spanned nearly five decades; it began in the mechanical engineering group at Commonwealth Edison Co’s Dresden Generating Station. Next step was a management position in the reactor design department at Combustion Engineering Inc. Berté founded Tetra with two other engineers in 1989.

Later he started Innovative Marine Technology to pursue, in his spare time, the design of sailboats and other things related to the sea. Accomplishments included the first ever Tridactyl sailboat, which he patented. Also, TankerProa, a modular sailing vessel using Tridactyl technology to help power transoceanic tankers.

Berté was a restless doer who kept his hands and mind moving non-stop—always receptive to professional challenges and to sharing his knowledge with industry colleagues. One example of the latter was an article he penned for the first issue of CCJ, “Assessing the true cost of cycling operation is a challenging assignment.” Things haven’t changed much on this in the 15 years since its publication.

Born in Brooklyn, Frank moved to the Bronx with his family before continuing his migration north to West Hartford, Conn, and later to Westford, Mass. He earned a Master’s Degree in Mechanical Engineering from The City College of New York and a PhD in Nuclear Engineering from the Massachusetts Institute of Technology.

IAPWS working group reports progress on four new documents

The Power Cycle Chemistry (PCC) working group of the International Association for the Properties of Water and Steam gathered at the parent organization’s annual meeting in Prague, Czech Republic, Sept 2-7, 2018, to advance the development of several new Technical Guidance Documents (TGDs).

The annual IAPWS (pronounced eye-apps) conference was conducted concurrently with the International Conference on the Properties of Water and Steam (ICPWS), which is held every four or five years. The 2018 edition of the ICPWS was the seventeenth; the first was held in London in 1929.

The joint meeting attracted more than 100 papers from 140 scientists and engineers representing 27 countries. Purpose of the conference is to connect scientists with the engineers who use their information. Both groups of professionals benefit: The researchers/scientists learn about problems seeking resolution while the engineers gain access to the latest research results. The information exchange included experience with film-forming substances (FFS), which are of increasing interest to combined-cycle owner/operators.

IAPWS Executive Secretary Dr R Barry Dooley of Structural Integrity Associates Inc, well known to the global power-generation community, contacted CCJ’s editorial offices to say that four TGDs are in final draft form with planned release dates in 2019:

    • Guidance on air in-leakage.

    • Guidance on the use of FFS in industrial plants.

    • Guidance on generator-cooling-system chemistry.

    • Guidance for ensuring the integrity and reliability of demineralized makeup water supply.

Additionally, the PCC working group is preparing several white papers likely to be developed into TGDs at a later time. These include “Corrosion Products in Flexible (cycling, two-shifting) Plants” and “Guidance for HRSG Condensate Polishing Plants.”

Dooley reminded that there are eight TGDs currently available free-of-charge on the organization’s website at www.iapws.org. They offer a wealth of practical information on topics such as steam purity for turbine operation, phosphate and sodium hydroxide treatments for steam/water circuits of drum-type boilers, instrumentation for monitoring cycle chemistry, how to measure carryover of boiler water into steam, etc.

The next IAPWS meeting will be held in Banff, Canada, Sept 29-October 4, 2019.

Posted in 501 F&G Users Group | Comments Off on INDUSTRY NOTES, November 2018