Looking ahead to WTUI 2019 in Las Vegas, March 17 – 20

Salvatore A DellaVilla Jr, CEO, Strategic Power Systems® (Sidebar 1), typically begins preparing for the annual meeting of the Western Turbine Users Inc (this year, March 17 – 20 at the South Point Hotel and Spa in Las Vegas) during holiday quiet time when he can reflect in solitude on the highlights of the year winding down and how they might impact the electric-power business in the year ahead.

“The global market that we all live and work in today, he said, is dynamic and very challenging. The global disruption is palpable, whether from the influx and growth of renewables or from the technical and policy changes that influence investment in conventional generating assets. The bottom line: We now work in an ‘uncertain market.’

“Our market also has become an industry of headlines,” he continued. “In this competitive and uncertain time we are reading and talking about the survival issues of the largest suppliers to the electric-power industry, GE and Siemens. We hear about the massive financial investment Elon Musk has made in batteries, for cars and industry, and the problems he is having.

“We hear about AEP’s proposed $4.5-billion Wind Catcher Energy Connection project incorporating 2000 wind turbines and 360-mile transmission line to move renewable energy from the Texas panhandle to Tulsa where the existing grid would be used to distribute the power to customers. Next we learn that what would have been the largest wind project in the US was canceled because utility regulators concluded the project didn’t offer sufficient benefits to ratepayers and rejected it.

“All this uncertainty begs the question, ‘What is happening in the gas-turbine market?’

“Fundamentally,” DellaVilla says, “the question we have to answer is this: ‘What role will gas turbines (both heavy-duty frame engines and aeroderivatives) play in this changing market (or set of regional markets) and what will be the fuel of choice or necessity?’

“Perhaps,” he added, “we should rephrase the question and ask, ‘What are the opportunities for gas turbines as technology and fuel challenges evolve?’”

1. Who is SPS®?

Strategic Power Systems® Inc, Charlotte, NC, is the industry’s leading analytics consultancy specializing in the collection, analysis, and dissemination of O&M data for owners and operators of generating plants—in particular those powered by gas turbines. The firm, formed by CEO Sal DellaVilla more than three decades ago, gained recognition quickly because of its work in support of the Western Turbine Users, which began in fall 1990—a few months before the group incorporated.

Recall that Western Turbine serves owner/operators of GE aeroderivative gas turbines, today focusing on the LM2500, LM5000, LM6000, and LMS100. The popularity of the LM2500 and LM5000 grew rapidly as the power block of choice for many of the cogeneration systems installed to take advantage of the Public Utility Regulatory Policies Act, enacted in 1978. Purpa opened up the generation market to non-utility entities as long as their facilities met certain size, fuel, and efficiency criteria. California was fertile territory for cogen systems.

WTUI offered users, some of whom already were meeting at various plants on an ad hoc basis, a formal structure to support the expanding base of operators. The organization’s leadership understood new users would require operating knowledge and experience, and would share their desire for continuous product improvement.

They also understood the need to establish and follow a uniform process that WTUI, as an organization, could use to track and report the availability and reliability performance of the LM5000 and LM2500 fleets.

The objective was to have unbiased and accurate data to document the performance of gas turbines and other plant equipment. Users wanted data and metrics they could share among themselves, and with GE. These goals were enabled by SPS’s Operational Reliability Analysis Program (ORAP®) and use of this data engine was supported by WTUI and GE.

DellaVilla and company went to work and issued their first ORAP report in June 1991, just three months after the incorporated user group’s first meeting. It included data from 24 operating plants representing 19 LM2500s and 14 LM5000s and provided an overview of the reliability metrics that the user desired—including component causes of downtime and engine removal rates.

SPS’s service to WTUI members and owner/operators of other engines, including today’s largest and most sophisticated frames, has grown dramatically over the years in terms of number of participants, extent of equipment coverage, depth of data analysis, and speed of information delivery.

Looking for answers, DellaVilla reviewed data from a variety of sources, including that published in the “BP Statistical Review of World Energy 2018.” Summarizing, he said it shows that conventional powerplants continue to play a significant role in meeting the world’s base-capacity needs. Renewables have found a place in the market, and while there is recognition of their potential long-term benefit and value, they are intermittent power at this time—not baseload capacity.

Here are some important points DellaVilla gleaned from the BP report:

• • Worldwide generating capacity totals about 6300 GW. Nearly 60% of that capability is installed in six countries: China, the US, India, Russia, Japan, and Germany—in that order.

  • Over 86% of the primary energy consumed in these six nations comes from fossil fuels—with coal (for electric production) and oil (for transportation) continuing to play a very significant role.

    Unfamiliar with the term “primary energy”? It is defined as an energy form found in nature that has not been subjected to any human-engineered conversion process. Fossil fuels (coal, oil, and gas), biofuels, wind, solar, and nuclear fuels are all primary sources of energy.

• • China (60.4%), India (56.3%), Japan (26.4%), and Germany (21.3%) are major users of coal for power generation.

  • Russia (52.3%), the US (28.4%), Germany (23.1%), and Japan (22.1%) are major users of natural gas.

  • For the top six energy-consuming nations combined, renewables contribute only 3.8% of the electricity produced, with Germany leading at 13.4%.

  • France, No. 7 on the list of largest consumers, relies on fossil fuels for 53.5% of its primary energy—mostly oil (33.5%) and natural gas (16.2%). Interesting to note is that 37.9% of France’s electricity is produced by nuclear energy, only 4% by renewables.

Setting the BP data aside, DellaVilla focused on the interrelationship between energy and the environment. “We live in a world that values a clean environment,” he said, “and using advanced generation technologies—including gas turbines—is important to help us achieve that goal. There is almost a universal acknowledgement that carbon emissions, in the form of CO2, must be contained. This puts us in a place where we have never been before—vu jádé.

“Whether you believe in the need to curtail greenhouse emissions or not,” the SPS CEO added, “policy and regulations influence the market, and the market acts through technology selection and ‘buy decisions.’ Just follow the investment money.

“Yet there is little press or recognition that the 27% reduction in greenhouse-gas emissions in North America has satisfied the desired reduction in CO2 called for by the Paris Agreement on climate change. This positive reduction was accomplished by a shift to natural gas, a reduction in the use of coal, and the growth in renewables. No other geopolitical region can make the same claim.

“Also, it is valuable to know how gas turbines are performing. ORAP® operating data compiled by SPS offers asset reliability and availability numbers for the recent past, and the present, offering perspective for the selection of future generation resources. Plus, it shows us how the installed base (or a segment of it) is operating regionally, and what changes we have experienced over time.”

DellaVilla then walked the editors through the ORAP Simple Cycle Plant RAM metrics (Sidebar 2) for various classes of gas turbines—aeroderivatives, E-Class, F-Class, and Advanced-Class. When reviewing this information presented in Tables 1, 5, 6, and 7, keep in mind that “simple-cycle plant,” a term typically used in the reporting of reliability statistics, represents the basic gas-turbine plant arrangement, including the following equipment: GT, controls and accessories, generator, and balance-of-plant equipment to support the gas turbine and generator.

The information compiled in Table 1 comes from 621 aero units for 2018, 657 for 2017, and 834 for the 2012-2016 period. Aeros in the sample include engines from GE, MHPS (formerly P&W), and Siemens AGT (formerly Rolls-Royce), and represent units operating worldwide. A regional analysis of aeroderivative data for the US is presented in Table 2.

Table 3 is important for clarification purposes. Mergers and acquisitions and renaming of gas-turbine models in the last five years or so might allow misinterpretation of the ORAP data if you have not kept up on industry changes. To illustrate: Engines formerly associated with Alstom now appear with traditional GE and Ansaldo assets.

You also may be unfamiliar with Siemens’ current naming convention, particularly after the company’s purchase of Rolls-Royce aero engines. Plus, as noted above, what formerly were Pratt & Whitney aero engines are now part of Mitsubishi Hitachi Power Systems’ offerings.

Table 4 categorizes gas turbines by firing temperature and pressure ratio to differentiate among Tables 5, 6, and 7 for E-, F-, and Advanced-Class models. Of interest, too, is that SPS engineers are in the process of updating the technology characteristics presented in Table 4 as they evolve over time. Follow these developments in CCJ ONsite.

Information compiled in Table 5 comes from 427 E-Class units for 2018, 473 for 2017, and 470 for the 2012-2016 period. The gas turbines in the sample include engines identified in Table 3 from Ansaldo, GE, MHPS, and Siemens operating worldwide.

Table 6 data come from 549 F-Class units for 2018, 557 for 2017, and 646 for the 2012-2016 period. Again, refer back to Table 3 to identify the specific engines included in the global sample.

Information compiled in Table 7 comes from 25 Advanced-Class units for 2018, 27 for 2017, and 31 for the 2012-2016 period.

DellaVilla concluded the interview with the following observation, “From a review of the data presented, and the operational levels gas turbines are achieving, perhaps there is a bit of déjá vu after all. Natural gas and gas turbines have played a major role in our nation’s energy mix for more than two decades—and they will continue to do so for the foreseeable future.”

2. Definition of terms

Service hours is the number of hours equipment is in service—that is, generating either electricity or motive force. In-service is generally measured from a commercial perspective, from the time when the equipment is fulfilling its intended service until it is shut down and that service has ceased.

Start. A successful start is achieved when the breaker is closed and synchronized to the grid (power generation) or the driven equipment has reached stable operation (mechanical drive).

Service hours per start is a measure of a piece of equipment’s average mission time, or the average number of hours the equipment operates each time it is started.

Service factor is the percentage of time a unit is in service.

Capacity factor is the percentage of maximum possible generation achieved over a given period, using the stated unit capacity.

Output factor is the percentage of megawatt production over a specified time period as a function of the total megawatts that could have been produced had the unit been operated at its nameplate rating for the actual operating hours. This statistic can be calculated in either gross or net terms. Net megawatts accounts for in-plant usage of a portion of the electrical output.

Availability is the percentage of time the equipment is capable of operating.

Reliability is the percentage of time in a given period that the equipment was not forced out of service.

Western Turbine Users Inc, the world’s largest independent organization of gas-turbine owner/operators, celebrates 29 years of service to the industry at its annual Conference and Expo, March 17 – 20, at the South Point Hotel & Spa in Las Vegas. The group, which serves owner/operators of GE aeroderivative engines (LM2500, LM5000, LM6000, LMS100), was last at this popular venue in 2017.

If you haven’t already registered, don’t delay. Visit the group’s website where you can sign up for the meeting and book your hotel room.  

When making your arrangements, think seriously about coming early. WTUI’s annual golf tournament on Sunday, this year at the prestigious Rhodes Ranch only 15 minutes or so from the South Point, is a fun time and an opportunity to socialize with colleagues before Chairman Chuck Casey gavels the meeting to order at 8 am Monday. Buses depart from the South Point lobby at 6:15; format is shotgun scramble. There are many prizes to hold your interest, even if you’re having an off day. The extra fee required for this event is payable when you register.

If the golf tourney is too early for you, there’s bowling starting at 10 am. And you don’t have to leave the hotel to participate. The South Point Bowling Center has 64 state-of-the-art Brunswick lanes. You must pre-register for this event as well.

Both social events conclude in plenty of time to shower and have something to eat before the “Welcome to WTUI/Conference Familiarization” session starts at 3:30. Attendance is especially recommended for all first timers. Indoctrination ends at 5:30 when the exhibit hall opens for three hours. There will be plenty of food and prizes to keep you engaged for the entire evening.

Monday morning you’ll hear from the authorized service providers (ASPs, formerly called “depots”) serving the GE aero fleets—Air New Zealand Gas Turbines, IHI, MTU, and TransCanada Turbines—as well as the OEM’s service team. Time limit on each of the presentations is 15 minutes, so there’s a lot to hear in a short period of time. You can get the details in the exhibition hall later in the day or on Tuesday. The booths of the ASPs and OEM are well staffed.

A Monday morning highlight is Consultant Mark Axford’s “Worldwide Gas Turbine Business Update.” Axford is well-known and -respected by, the Western Turbine community. His rapid-fire, fact-filled presentation on energy matters will review the headlines that made industry history in the past year; bring you up to date on fuel and electricity pricing and what might impact those numbers in the year ahead, such as subsidies for renewables; chart progress, or the lack thereof,  in energy-related technology development, batteries included; weigh the possible impacts of changes in OEM organizations; review the gas-turbine order book for 2018 and what the industry expects this year, etc.

Axford is best known for his market assessments, his predictions highly accurate over the years—uncanny might be a better descriptor. However, last year the consultant was way off his game. For 2017 he predicted US gas-turbine orders (units larger than 10 MW) would be up 10%, down 10% worldwide. The actual numbers were US down 36%, worldwide down 28%. Safe to say no one was predicting a market correction of this magnitude in 2017—at least publicly.

At last year’s meeting in Palm Springs, Axford predicted US orders would be down 10% in 2018 and down 10% (or more) worldwide. The Houston-based consultant carefully guards his predictions so you’ll have to attend his presentation at 10:45 in the South Coast Hotel’s Grand Ballroom to see how close he came to the actual numbers for 2018. Plus, you’ll get to hear his 2019 market predictions firsthand.

While Axford focuses on the aero market, Sal DellaVilla and his team at Strategic Power Systems® track the performance of engines in service, allowing owner/operators to benchmark their operations against the industry. The SPS® engineers and analysts will discuss the company’s findings during the breakout sessions. For a sneak peek at the results, read the companion article in this issue.

Engine breakout sessions begin Monday afternoon. Over the three days of the meeting, nine classroom hours are devoted to the operation and maintenance of each aero engine served by WTUI. Hands down this is the biggest bargain for the training of technicians responsible for LM2500, LM5000, LM6000, and LMS turbines. It’s where owner/operators get the nitty gritty on what might bite them next and how to avoid paying again for problems others have experienced and solved.

But everyone needs a break from the engine detail. That’s provided by Tuesday’s special technical presentations, where you’ll get an overview of other technologies vital to plant operation—generators and control systems, for example. This portion of the program consists of three one-hour sessions with each session providing a choice among three presentations conducted simultaneously in the Napa, Sonoma A/B, and Sonoma C/D meeting rooms.

Here’s the lineup of presentations in the first session from 2:30 to 3:30:

• Installation and removal of Ameriflex couplings.
• Ageing HRSG inspection and maintenance priorities.
• Aero Best Practices.

Second session from 3:30 to 4:30:

• Boro-blending technology and its capabilities.
• Generator maintenance and rotor pull.
• Reliability and maintainability of aero engines.

Third session from 4:30 to 5:30:

• Tunable diode laser for NH3 measurement.
• Online monitoring of stator endwinding vibrarion.
• Excel for daily reports and calculating simple KPIs.

Nominate your plant for a TICA award

The Turbine Inlet Cooling Assn will recognize, at the 2019 WTUI meeting in Las Vegas, turbine users/owners/operators that have demonstrated the successful implementation and use of at least one inlet cooling technology on a GE aero engine. One award will be given for each TIC technology, says Executive Director Dharam (Don) Punwani.

Enter your plant for consideration before February 4. Nominations will be evaluated using the following equally weighted criteria:

• Total number of turbines using TIC.
• Total increase in power (kilowatts) attributed to the TIC system.
• Percent increase in capacity provided by the TIC system.
• Year of installation, to gauge total benefit.
• Noteworthy/innovative details of the TIC system or in its use.

Details and entry form are available on the TICA website.

Superstorm Sandy was one of those events which changed most everyone’s thinking on infrastructure reliability, especially in the NYC metropolitan area. But Sandy is only one element in the “perfect storm” which led Montclair (NJ) State Univ (MSU) to add a microgrid to its relatively modern combined heat and power (CHP) system.

Other elements include a unique state-level public/private partnership created in 2009 in the wake of the “Great Recession,” recurring utility-side events responsible for several campus-wide outages annually, and ratcheting utility demand and T&D charges.

Today, MSU can operate 100% divorced from the grid and export up to 3 MW of power to it, thanks to an engine-based 5.2-MW microgrid commissioned in May 2018 that works in tandem with a 5.6-MW gas-turbine/HRSG-based combined heat and power facility commissioned in 2013 to replace and upgrade an antiquated CHP system installed in the 1950s. The gas-fired engines can also burn LNG, for yet another level of backup.

The two 2.6-MW Jenbacher engine/gen sets anchoring the microgrid have three functions, according to Plant Manager Andrew Morrissey: peak-demand shaving, backup capacity when the gas turbine is in an outage, and supplemental generation when utility power supply is lost. On a normal day outside of the peak season, however, MSU “sells a little power to the utility during nighttime, and buys a little power during the day,” adds Morrissey.

The CHP plant can deliver 100% of the campus steam and cooling needs and up to 86% of its electric demand. But recurring issues with utility-supplied power caused MSU to invest in further relief, the microgrid.

In a presentation to the Distributed Energy Conference, Denver, October 2018, Frank DiCola, CEO of DCO Energy LLC, noted that, over its first summer, the new microgrid netted close to $400,000 in savings by shaving electric demand peaks. “Utility capacity charges were the main economic driver for the microgrid project,” he said. Electricity costs to MSU are now 40% lower than before the new CHP.

Jonathan Wohl, DCO’s senior VP of project development, noted during CCJ’s visit to the facility, that the T&D cost component of MSU’s utility bill is also rising significantly, as the utility adds T&D infrastructure to bring in more renewable energy. Of course, what will also happen is that as more customers like MSU divorce from the grid to the extent possible, costs for maintaining the “grid” have to be spread among fewer customers and/or customers buying fewer kilowatt-hours.

Another project driver was the reliability of grid-supplied electricity. MSU could experience as many as three blackouts a year, even though there are two 26-kV utility lines feeding the campus. Disturbances on the utility lines could also trip the turbine in the old CHP plant. Outages typically were from 30 minutes to several hours in duration. Superstorm Sandy in 2012 added to the concern about resiliency of campus utilities.

Risk mitigation and resiliency run deep in the psyche of the facility staff. DCO, which develops, designs, builds, operates, and maintains CHP systems across the country, has engine, turbine, and chiller expertise groups within the firm. The process performance group identifies cross-facility issues and addresses them. At MSU, spares are carried for any component with over a 10-week delivery time.

“We evaluate the N+1 risk for all major components across our fleet,” said Fred Eckert, DCO’s executive VP of facility operations. Morrissey referred to a fuel splitter valve for the gas turbine with a 52-week lead time. “I keep one of these in my office,” he said, pointing to it on the floor in the corner.

Since the gas turbine doesn’t run without it, the HRSG is a major risk component because it can take down the turbine. All of the campus steam normally is provided by the 28,000-lb/hr HRSG (at baseload), equipped with a duct burner capable of producing an additional 22,000 lb/hr. Two backup fired boilers, each rated 42,000 lb/hr of steam, also are available; one is kept in hot standby at all times.

Two large chillers are used for cooling; one (2300 tons) is steam-turbine driven, which also adds a large “sink” for productive use of steam when electric demand is high and campus steam demand is low. This is important because the system does not include an HRSG bypass stack. The other chiller is a 2000-ton motor-driven unit. Both chillers were supplied by York®, a unit of Johnson Controls.

A big challenge for the CHP construction team was trenching through solid rock to add 8500 ft of condensate return lines. That caused a hit on the budget, although the overall project remained within anticipated costs. The antiquated CHP system was only returning 20% of the condensate. “It returned more rainwater than condensate,” quipped Eckert. As the campus grew, chilled-water demand kept growing. MSU had resorted to renting chillers for individual buildings. Today, 90% of the condensate is returned; DCO has a contract guarantee at 80%.

A lesser challenge on the O&M side proved to be raw-water quality for the boilers. The campus buys water from the city, but it often has to be supplemented with well water. When that happens, “the hardness goes through the roof,” said Morrissey. Adding deionizer resin bottles brought the issue under control.

Like most powerplants these days, the CHP + microgrid is controlled with a sophisticated SCADA system. MSU’s includes a Rockwell Automation system with Schweitzer Engineering Laboratories’ relays and load-management system (LMS), the last incorporating model-predictive control. The controller adjusts actual electrical, steam, and chilled-water loads versus what is expected based on ambient conditions (temperature and humidity) and historical demand data.

A dispatch model crunches real-time LMP pricing data from PJM (figure) and electricity costs to MSU to determine whether to sell or buy and how much. Recall that LMP is the acronym for “locational marginal pricing.” To establish the predictive model, DCO reviewed historical 15-min demand intervals to “predict” when and how much peak-shave electricity would be needed from the microgrid engines. The engines are only permitted to run 2000 hours per year.

There can be significant and unanticipated electric demand from the campus. For example, electric demand tends to spike during rainy days. Although classes are typically not in session during the summer, there are many special events and the CHP + microgrid facility operators may not get much notice about when they are occurring.

The LMS controls every major electrical breaker on the campus, and also is tied into a load-shedding strategy when necessary. Overriding objective is to avoid ratchets on the utility demand charges, which are calculated based on the five single hours of highest demand in the current year setting the rates for the following year. According to DiCola, historical data showed that the highest demand hours occur during the third weekday of heat waves characterized by 90F+ temperatures and high humidity. Black-start capability also is built into the LMS.

No money down. The state public/private partnership program allowed MSU to add the CHP facility with no capital investment. A 2009 Economic Stimulus Program encouraged universities and others to take advantage of public private/partnerships combining taxable and tax-exempt bonds to finance facilities over 30 years. DCO was awarded both the EPC contract and a 30-yr O&M contract.

As part of that, the major equipment, primarily the gas turbine/generator, engine/generators, and motor- and steam-turbine-driven chillers, had to be protected by long-term service agreements.

MSU decided to take advantage of the program and modernized the existing CHP—consisting of two legacy boilers, a 1950s-vintage steam-distribution and condensate-return piping network, a 1990s-vintage Solar Turbines’ Centaur 40 gas turbine/generator coupled to an HRSG from the same time period, a small black-start engine/gen set, and backup generators “past their prime” in several buildings.

The central plant was operating at an efficiency of less than 50%, reported DiCola. There was no chilled-water distribution network, only local rental chillers. The entire steam distribution system had to be replaced. These and other deficiencies were delineated in a 2009 Energy Master Plan issued by MSU.

MSU’s facility was the first powerplant under the stimulus program. The CHP + microgrid is expected to save $2-million annually, including debt service. The facility also received a clean energy grant from the state EPA. The GT emits only 9 ppm of NOx, thanks to Solar’s SoLoNOx emissions reduction technology, which requires no reagent and no water or steam injection. The plant was not required to include continuous emissions monitors.

CHP plant availability reported by DiCola in his presentation was 97.4%. “Most of our issues are with the utility, not the onsite equipment,” Morrissey said during the site visit.

Capital, always scarcer than one wishes, could now be put to work towards MSU’s primary mission, educating students and expanding campus facilities. The college campus is New Jersey’s second largest, with 27,000 students, 8000 in the dormitories. Indeed, the campus continues to grow, adding buildings and refurbishing older ones.

As importantly, MSU is relieved of the responsibility for day-to-day deliveries of critical energy streams, and can focus on monitoring consumption to identify and address inefficiencies. DCO also manages fuel supply for the university, which can be dicey in the Northeast given harsh winters and bottlenecks in regional natural gas supply.

Certainly not a household name in the CCJ community, DCO Energy, headquartered in Mays Landing, NJ, employs close to 500 people and designs, builds, and operates CHP, cogeneration, small power, and non-utility powerplants across North America. According to DiCola, the firm is now in the process of evaluating the economics of battery storage at many of its facilities, which could be the final piece of the puzzle for sites wishing to divorce completely from the local utility.

Rob Wang of Engineering Analysis Services Ltd (UK), presented on outage planning and life extension of cycling plants at European Technology Development Ltd’s International Conference on Power Plant Operation and Flexibility, London, July 2018. He highlighted both piping system health management and analytical techniques for component life assessment.

Piping system details are, perhaps, too often overlooked. Wang reminded participants of cyclic thermal movements, large stresses at nozzles, and incremental plastic collapse damage to constant-load hangers.

For system health issues, stated Wang, “long piping systems are subject to cyclic thermal movements that generate peak stress/strain at the nozzles and hangers.” Constant-load hangers (and variable-load spring supports) are used for balanced piping systems, allowing movement within clearly specified limits and maintaining stresses within code.

But operators must be aware of cycling’s impact, as well as the more common degradation forces of corrosion, loosening of bolted connections, and misalignments (among others). He therefore encouraged piping stress analysis and assessments, and periodic hanger surveys and full piping system reviews.

For the latter, he offered clear specifics:

1. Set up a live database from the design and installation records to include:

      • Hanger ID and setting positions in both cold and hot conditions.

      • Hanger travel limits.

      • Movement between cold and hot conditions.

      • Dates for installation, effort adjustment/reset and replacement/ resetting.

2. Conduct the following three surveys for every maintenance period:

      • Pre-outage survey in hot condition.

      • Survey during outage in cold condition.

      • Post-outage survey in hot condition.

3. For each survey, generate a technical report on findings, system health, and maintenance recommendations. He then gave details for each survey:

Pre-outage hot survey

• Survey hangers/supports to obtain hanger position readings.

• Review current readings against as-built benchmark and historical data.

• Identify out-of-range hot positions and predict possible out-of-range cold positions.

• Make outage-team maintenance recommendations for hanger effort adjustments or hanger replacement.

Outage cold survey

• Survey hangers/supports to obtain position readings.

• Review current readings against as-built and historical data.

• Confirm/verify out-of-range cold positions predicted during the pre-outage hot survey.

• Make hanger support effort adjustments based on pre-outage hot recommendations and the current out-of-range findings.

• Record adjustment details and revised hanger readings.

• Predict out-of-range hot hanger positions.

Post-outage hot survey

• Survey hangers/supports to obtain position readings.

• Review current readings against as-built and historical data.

• Check that adjusted hangers are within range.

• Record adjustment details and revised hanger readings.

• Note any potential out-of-range indications.

Wang stressed his recommendation to repeat these surveys for every maintenance cycle. He reminded participants to also inspect for any degradation by rust, lost or loose nuts, obstruction, misalignment, unintended deformation or configuration change, and to finish each survey process by informing outage planning of all findings.

Such information assists the entire plant in life-extension work, and provides early warnings on risk issues.

The Air-Cooled Condenser Users Group’s 10^th annual meeting (October 2018, Colorado Springs) hosted over 100 participants—more than half users, with first-timers in the majority.

The overriding takeaway this year was new information, supported by informative looks into the fundamentals. Such balance expands the benefits of meetings, concludes CCJ Consulting Editor Steve Stultz, who attended the conference for CCJ ONsite. Agenda items covered three categories: equipment design and performance, system operation and maintenance, and the effects of system chemistry.

Chemistry launched the sessions, with Barry Dooley of Structural Integrity Associates Inc, a member of the group’s steering committee chaired by EPRI’s Andy Howell, at the front of the room. He moved quickly into the emerging concerns of air in-leakage and film-forming substances, reminding participants that last year’s event featured a workshop on ACC corrosion mechanisms and detection. This year’s would begin with an overview.

But his synopsis included compelling reminders of chemistry’s impact. “ACCs now are installed at many combined-cycle, conventional, supercritical, and industrial installations,” he stated. “Regardless of system or location,” Dooley stressed, “damage and appearance are almost always the same if system chemistry is not correct.” If anyone should know, it’s Dooley. He has inspected and evaluated the O&M of ACCs in more than 20 countries.

Selected photographic examples of flow-accelerated corrosion, iron, and the strong influence of component geometry confirmed that “material damage and system consequences can be enormous. One example: “If we operate below pH 9.0,” the chemist/metallurgist said, “we will have large amounts of iron coming out of the ACC, leading to critical system failures—including condensate polishers and steam turbines.”

He then reviewed the Dooley Howell ACC Corrosion Index (DHACI), now in widespread use by owner/operators to detect damage and make inter-unit and time-based damage assessments. “There is a one-to-one relationship between equipment damage and the amount of iron in the cycle,” Dooley stated, “and the goal should be to get total iron to less than 10 ppb.”

This led to a discussion on the difficulty of measuring total iron. The best strategy, he pointed out, is contained in Technical Guidance Documents (TGD) issued by the International Association for the Properties of Water and Steam (IAPWS). One in particular is TGD 6-13, “Corrosion-Product Sampling and Analysis for Fossil and Combined-Cycle plants,” which has been endorsed by leading powerplant chemists in more than two-dozen countries. Access www.iapws.org to review and download at no cost all of the organization’s TGDs.

In addition, a valuable guideline for internal inspection of ACCs, he reminded, is ACC.01, available for download at www.acc-usersgroup.org/reports/, also at no cost.

The discussion then turned to film-forming substances (FFS), a topic reportedly triggering some confusion (and misuse) within the industry. Dooley offered the latest definitions from IAPWS: “Film-forming amines ad products (FFA/FFAP) are amine-based. Film-forming products (FFP) are non-amine and the specifics are proprietary—unfortunately for users. All are now called FFS by IAPWS and others.”

“There can be many problems when these substances are not applied properly,” Dooley warned. “Owner/operators must investigate equipment carefully before application to make direct post-application comparison, and must then be monitored carefully.”

The premier standard for these substances is TGD 8-16, “Application of Film-Forming Amines in Fossil, Combined-Cycle, and Biomass Power Plants.” Section 8 of this TGD begins as follows: “This section provides guidance for operators when applying FFA/FFAP to generating plants as a supplement to, or as a replacement for, the current chemistry regime. This is the base case for this IAPWS TGD, and it is applicable to all-ferrous, fossil, combined-cycle/HRSG, and biomass plants.

Discussions followed, with one participant explaining what is perhaps the first use of FSS in a US ACC. Many others are currently investigating uses. Dooley issued a stern warning: “If these substances are not applied properly, deposits can simply go elsewhere and cause extreme damage.”

Chemical suppliers may not know the details. And there are no universal answers. “Each system must be viewed as unique,” he emphasized.

Dooley concluded his portion of the program with an introduction to air in-leakage and common sources of leakage at plants with ACCs—including cracked welds, open valves, leaking flanges, LP-turbine/condenser expansion joints, loose instrument fittings and/or connections, condensate receiver tank joints, and inter-condenser drain-system connections. There are many other sources of leakage as well.