Perspective: State of the Industry, 2019

by Jason Makansi, Pearl Street Inc.

In these days of heightened uncertainty in the power industry, it’s easy to have amnesia about long-term prospects in the electricity business. The opportunities may be shifting, for a few perhaps like the ground underneath you during an earthquake, but the long-term opportunities remain excellent.

The short version of the state of the industry (SOI) is that electricity demand continues to grow, along with population; the sources for supplying that electricity are “decarbonizing”; electric transportation represents a significant source of new demand; and future activity is shifting towards the customer end of the supply and delivery value chain.

The only sub sectors of the power industry that face an existential threat are nuclear- and coal-fired generation, and even that is tempered somewhat by activity in Asia.

According to the “Exxon Mobil 2018 Energy Outlook,” world population will grow from 7.4-billion to 9.2-billion in 2040, but 1-billion people don’t have access to electricity today. The International Energy Agency (IEA)’s World Energy Outlook notes that 40% of world energy is consumed by Europe and North America and 20% by Asia. By 2040, these percentages are expected to reverse.

Asia also represents 50% of global natural-gas growth, 60% of renewables growth, 80% of petroleum growth, and 100% of coal and nuclear growth.

The run of historically low natural-gas prices in the US still has a way to go, according to experts, although it now appears that LNG exports and displacement of petroleum by natural gas for hydrocarbons processing and heavy manufacturing are poised to chip away at the supply glut. At some point, this trend will have to impact prices.

Because electricity demand growth is still anemic in most parts of the country, new generation capacity will be driven by decarbonization policies at the state level, a gauntlet of other environmental laws choking coal, resiliency, and operational flexibility. You can sum that up in a meme: “must run renewables, must follow gas.”

Ironically, the deregulatory and competition programs of the last 30 years have resulted in regulated utilities with protected distribution functions. As impressive as technical and economic progress have been with solar PV, battery storage, micro grids, so-called “smart” homes, and the like, distribution utilities seeking their traditional regulated rate of return on invested capital are likely to drive the distributed energy sector.

Unless electricity demand growth roars back, this likely will be where utilities focus their efforts.

Large-scale storage remains the wild card for the future. If gas prices escalate and battery costs decline, the peakers of the future may not be simple-cycle gas turbines. If home-battery storage prices decline rapidly, then large swaths of ratepayers may opt for rooftop solar PV + storage to supply the bulk of their electricity, whether it’s the local utility offering the system or a company like Tesla.

Storage is such a wild card because it can “play” across the electricity supply and delivery chain, including inside an electric vehicle (EV). With continued battery cost declines and effective management of safety aspects (for example, the catastrophic fire hazards often associated with lithium-ion batteries), one can envision a multi-year period during which tens of thousands of megawatt-hours of storage are added to the US grid, in much the same way as 1997-2002, when 200,000 MW of gas-fired capacity was added.

The death spiral, articulated in a 2013 EEI report, “Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail Electric Business,” of customers leaving the grid appears to be coming to pass. That is, as more and more industrial, commercial, and residential electricity customers opt for some form of onsite generation, utilities must spread the costs of maintaining the grid across a shrinking customer and kilowatt-hour demand base. That increases prices, which forces more customers off the grid, a destructive feedback loop.

For this reason, some believe it inevitable that regulated utilities must “control” the distributed-energy rollout and the retail space, or face an existential threat of their own.

However, it’s critical to realize that everyone still needs electricity. What is in question is which entities will be providing it. The opportunity isn’t going away, it’s just shifting.

A good example is a university in New Jersey.  It replaced and expanded an old combined heat and power facility in 2011 and then added a microgrid that started up last year. Two main project drivers: (1) enhanced resiliency, avoiding reliability issues on the utility side of the meter; and (2) avoiding escalating rates from the local utility resulting from fee adders for bringing more renewable energy to the service territory.

“Must-follow” gas plants present their own slate of opportunities, especially for service firms. Harsher and less predictable operating tempos, combined with shrinking O&M budgets, mean that owner/operators have an appetite for lower-cost solutions for repair and upkeep. And the new H and J machines coming into the supply side will inevitably proceed through their own teething and O&M issues in the early years of the model lifecycle. They are designed for faster and even more frequent cycling than their F-class predecessors.

While those in the fossil-fuel side of the business tend to shudder at the renewables + storage paradigm, adding the third parameter to the equation may be even scarier. Digital technology is transforming society in much the same way as electrification did one hundred years ago. Consider that 60% of adults under 30 don’t even have a driver’s license! They are content, apparently, using digital sharing platforms like Lyft and Uber, or mass transit.

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Factor European experience into O&M practices at US combined cycles, Part V: Drones and robots

Capitalizing on work presented by Xcel Energy at meetings of the HRSG Forum with Bob Anderson, ETD’s Dr Ahmed Shibli and William Moore produced an extensive report for the consultancy’s Group Sponsored Project on drones and robots for powerplant inspection. The highlights of this work were discussed at European Technology Development Ltd’s International Conference on Power Plant Operation and Flexibility, London, July 2018.

The exploratory phase (just completed) of this project was directed at determining suitability of drones and robots for visual and UT inspection, as well as a review of R&D activities. The upcoming phase is the design and development of the most suitable and economic automated devices in three types:

1. Drones for visual inspection and data analysis of remote, out-of-view and at-height components.

2. Robots for polishing and UT inspection of components including crack sizing.

3. Small or mini-robotic devices for polishing and UT inspection requiring access through narrow spaces—such as between HRSG tubes.

Various organizations and experts are involved and more are invited to participate.

Drones. One development point is the oil and gas industry, currently using drones for UT inspection by attaching them to pipes (Fig 1). However, drones are not yet stable enough for complete UT inspection.

1. Drones attached to pipes are being used in the oil and gas industry for UT inspections but stability is an issue that must be resolved before the technique can gain widespread acceptance

Some significant points were made:

1. Photos taken by modern commercial surveillance drones can be enlarged on a computer screen by factors greater than 20× before pixilation creeps in.

2. Such detail can help diagnose the cause of failures. In the case of a burst evaporator tube, for example, a thick edge can indicate impure feed or boiler water; a thin edge can indicate overheating, fireside wastage, etc.

3. This valuable information is available as soon as the boiler has cooled sufficiently for access.

In emergency shutdowns, a drone is a frontrunner for immediate access to the failure location. Quick access is especially beneficial if there is a need to procure materials or services. It also enhances the placing of scaffolding in the correct, precise location. Plus, drones can check surrounding areas before a chain of failures occurs and capture a permanent record.

For thermal surveys, drones are particularly adept at carrying thermal imaging cameras and reaching correct positions. This can identify the areas of heat leak or damage to insulation.

Powering the drones carries two options: internal combustion engines, or electrical power. Electric became the choice with lithium batteries, but carrying loads for long time periods is difficult. The group sponsored project is investigating this further.

Robots. For this project, a robot is defined as “a surface crawler that carries out visual/NDE inspection and sends inspection data to a remote-control unit.”

Robots can reach inaccessible areas, or those where scaffolding is required. There is a range of proven technologies for robots, robotic machines, and intelligent flexible arms, but further development is needed for the powerplant environment—for example, polishing heads and UT probes for wall-thickness measurements.

Current development recognizes the challenges. Robots are not suitable for climbing tubes with thick deposits. Closely-spaced wall tubes can limit access, and plants have wide variations in tube diameters and tube-to-tube gaps.

A look ahead. Robotic arm development, especially for access through narrow spaces, shows promise. Stated Shibli, “a highly flexible and long robotic arm of about 0.4 in. diameter is needed that can pass between tubes in an HRSG, has multiple axes of rotation, and can carry out visual examination, surface polishing, initial inspection, and assessment.”

The next phase of this ongoing group sponsored project is development of “a novel drone-robot hybrid device.”

2. Portable scanning force microscope alerts on early-stage creep and fatigue damage, contributing to better forecasting of life assessment

Other inspection techniques discussed at the meeting included Obikou, a pipe strengthening mechanism for creep damage and/or steam welded pipes (ETD); a portable scanning force microscope (Fig 2) for early-stage creep and fatigue damage detection and life assessment (ETD); electrical discharge sampling equipment for removal of samples from pressure vessels and turbine rotors for quality checks and life/crack assessment (ETD/SGS, UK); portable magnetic measurement equipment for onsite creep damage detection (Univ of Manchester, UK); and shop welding interruptions of P91 components (PPC, Greece).

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Air in-leakage: ACC performance thief

Part 2 of CCJ ONsite’s coverage (access part 1 here) of the Air-Cooled Condenser Users Group’s 10th annual meeting (October 2018, Colorado Springs) by Consulting Editor Steve Stultz focuses on air in-leakage, which increases vacuum and contributes to a loss in thermal performance. Ingress of oxygen and carbon dioxide also can cause problems in the steam/water cycle and make it more difficult to achieve the degree of chemistry control required for optimal performance.

Bear in mind that a typical ACC may have 20,000 tubes, 40,000 welds, numerous valves, large ductwork, and plate walls—many locations for air leaks to occur and propagate.

Conco Services Corp’s Andrew Leavitt provided valuable perspective and contributed to the forum by describing practical methods and applications for tracer-gas leak detection.

“Sometimes,” he said, “you are looking for a leak less than the size of a dime in a surface area equivalent to three or four football fields.”

“Often you should just start at the ground and move up, eliminating areas,” he suggested. Leavitt showed examples of leakage at steam-jet air ejectors, jet isolation valves, hoggers, and other locations—including some under insulation. Also common are tube and duct weld leaks.

Leavitt then presented some troubling examples from new installations. In one case, installers “simply forgot a gasket” on a jet isolation valve.

An odyssey. Don Wright of Exelon Corp led participants through “A Vacuum Leak Odyssey,” focusing on the difficulties of accurate leak detection. His example was an 1100-MW 2 × 1 combined cycle commissioned in 2017. The ACC has 11 streets with 55 cells, four hoggers, two steam-jet air ejectors, and one air eductor to protect the vacuum pumps.

Problems occurred soon after commissioning, he said, with vacuum from 1 to 1.5 in. Hg above the backpressure design curve, dissolved oxygen running 60 to more than 100 ppb, hoggers operating continuously to maintain vacuum, more than 50 fans turning 24/7, and thermography clearly showing cold areas (entrained air) in many streets.

Following a walkdown and valve configuration checks, helium leak testing began.

There were no valve alignment issues. Minor leaks were found at a duct rupture disk and a drain pot. Significant leaks were found at hogger shaft seals. These issues were addressed, but again with no improved vacuum performance.

Then Hurricane Harvey hit the area, and the plant was shut down temporarily. After restart, vacuum and dissolved oxygen improved significantly, and ACC thermography showed good temperature distribution. There was a significant reduction in the number of fans running. Hogger use was still required to maintain vacuum, and the steam-jet air ejector still had no visible discharge.

By November, vacuum and oxygen returned to pre-Harvey levels. The steam-jet air ejector OEM identified stuck check valves. Vacuum improved but remained above design. Helium leak testing was scheduled for spring.

In April, major leaks were found in steam-ejector flanged joints, drain tank valve, and the bonnets of four drain valves off the condensate line to the deaerator. Minor leaks also were identified in the defleg section of two streets, LP-turbine rupture disk and gland seal, and exhaust-duct flange.

Operations have since improved, but leak detection will remain active. In Wright’s words, “Even after the fix, there can be room for improvement.” Some minor leaks remain, and dissolved oxygen (15-30 ppb) remains slightly elevated.

This odyssey continues with helium testing scheduled for 2019.

Not all plants are created equal. As-built errors can challenge an operating staff. Experience at

Doga Enerji’s 180-MW combined-cycle cogeneration plant on the outskirts of Istanbul, Turkey, illustrates the point. The plant features three GE-designed and Thomassen-built Frame 6 gas turbines, three HRSGs of European design, one GE/Thomassen steam turbine, air-cooled condensers, and related equipment. The site was commissioned in 2010 to supply both electricity and district heating.

A plant rep shared lessons learned that attendees could benefit from. The ACC at this plant today has three streets with five fans each. Air removal is by hogging (startup) and two main ejectors.

The speaker described the following ACC shortcomings:

    • Original design had only two streets. A third was added after two years of operation to improve summer operations.

    • The ACC intake area was blocked by containers which were removed in 2013.

    • A neutralization pit under the ACC led to blade corrosion on one fan. However, the pit cannot be relocated and must remain open to cool plant waste water.

    • The urban environment dictated conversion to low-noise fans.

    • Safety guard material under the fans is weak wire mesh, making maintenance both difficult and dangerous.

    • Dissolved-oxygen measurement is incorrect, influenced by oxygen in the makeup water. A separate sampling line is needed.

    • The original ACC tube-cleaning systems were not properly designed by the plant’s maintenance team and are not safety-compliant.

Other issues faced in the first few years of operation included the following:

    • Motor coupling abrasion.

    • Oil leakage from seals.

    • Foiling of strainer filters.

    • Particles in the oil pumps under the gearboxes.

    • Motor bearing breakage.

    • Gear abrasion.

A panel discussion on air in-leakage followed. It encompassed measurement data points and testing locations and methods. Helium versus SF6 was reviewed, noting that the latter is both difficult to transport and prohibited in many locations.

During the exchange, Structural Integrity’s Barry Dooley, a member of the steering committee noted that the ACC Users Group is planning to publish guidelines on air in-leakage; its starting point will be a new IAPWS Technical Guidance Document currently in technical review. Dooley is the executive secretary of that global organization.

The goal of both documents will be specific guidance for detecting and addressing air in-leakage at the plant level. Ultimately, this information should make its way into project specifications and offer specific best practices for detection.

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Gas-turbine operating metrics in an uncertain energy market

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.

DellaVilla called CCJ ONsite’s offices afterwards to tell the editors that the déjá vu he normally experiences when reflecting on the industry he has served for more than two-score years was replaced this year with a feeling of what the organizational theorist Karl Weick calls vu jádé—the feeling or sense this is something that has never been experienced before.

“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.

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Western Turbine 2019 kicks off in Las Vegas only eight weeks from now. Register today!

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.

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Resiliency, demand charges drive Montclair State to add microgrid to CHP

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.

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Factor European experience into O&M practices at US combined cycles, Part IV: HEP inspection checklist

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.

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