7F Users Group, 2018 Conference, Atlanta, May 7 – 11. REGISTER TODAY!

The world’s largest meeting of frame gas-turbine owner/operators is hosted annually by the 7F Users Group. The organization’s conferences typically attract about 250 users and more than that number of commercial attendees representing the nearly 150 companies participating in the vendor fair over two evenings.

The group formed in November 1991, when there was only one 7F operating in the world. The first meeting attracted 14 users from four generating companies; there was no vendor involvement.

The 2017 conference in San Antonio, chaired by Clift Pompee of Duke Energy, was an unqualified success by every measure. Program improvements focused on GE Day. The steering committee worked collaboratively with the OEM to provide a more succinct general session in the morning and allow more time for the popular topical 45-min breakout sessions, which begin after the morning break on Thursday. The same format is used on Friday as well, but with a different lineup of topics. The breakout format of four topics addressed in parallel in each time slot allows users to attend half of the topical sessions available.

GE Day 2018. Positive feedback from attendees encouraged the same GE Day format for the upcoming meeting, which consists of opening remarks by OEM experts, Q&A, and open discussion. The 2018 conference chair, Luis Barrera of Calpine Corp, recently announced the lineup of breakout topics. For Thursday:

    • Fleet experience, new Enhanced Compressor options.

    • Fleet experience with the DLN 2.6+, operability best practices.

    • Fleet experience, including advanced gas path; post-repair third-stage bucket cracking.

    • Exhaust frame. Options for maximizing durability.

    • Lessons learned from flat-slot-bottom inspections, rotor life-management options.

    • Update on the most common accessories challenges, plus RCA results for the stainless-steel compressor bleed valve.

    • Controls challenges and how to deal with them, discussion of TIL 1622 (lube oil).

    • Electrical systems and generators. Maintenance best practices.

    • Parts and repairs. How to check parts status and stay informed during the repair process.

    • Outages/FieldCore. Outage preparation and execution best practices.

For Friday:

    • Overview of the technology, its applications, and how batteries could impact thermal generation.

    • Complexities of modern blade design. Airfoil design principles and why they’re relevant to an effective maintenance plant; plus, how modern design impacts plant operations.

    • Additive manufacturing. Overview of the technology, its applications, and impacts on supply chain and new product design.

    • Arming the digital worker. Interactive discussion on how new technology is enabling more effective outages from planning to execution.

    • Next generation GT technology (7FA.05 and HA). What owner/operators need to consider in running the latest gas turbines.

Training of plant O&M personnel is a top priority of many asset owners and operating companies today given the challenge in finding experienced applicants for jobs vacated by retirements of the industry’s most knowledgeable. Recognizing this need, the steering committee and GE collaborated to offer GT 101 on Monday afternoon: A four-hour deep dive on gas-turbine fundamentals spanning performance, combustion, controls, inspections and hardware considerations.

Industry newcomers—those with fewer than three to five years of deck plates experience—will benefit greatly from this concentrated program and be better prepared for the sessions to follow. For more experienced personnel, it is a very worthwhile refresher. Amazing how much one can forget in such a short time.

The user-only sessions, held in high esteem by plant personnel, begin Tuesday morning and run until the afternoon break, then pick up again on Wednesday morning. The user presentations and interactive discussions deliver unbiased O&M experience you can’t get anywhere else. Sessions on compressors, safety practices, performance and controls, auxiliaries, combustion, turbines, and generators run for one to two hours, depending on the subject. This portion of the program concludes with “7F Top Issues,” which includes discussion of best practices submitted by 7F owner/operators to CCJ’s annual program.

A dozen vendor presentations, invited and vetted by the steering committee, are on the program Tuesday and Wednesday afternoons, following the refreshment breaks. Arrangement is two sessions each day with three presentations conducted in parallel in each session. Here are the topics:

    • Big data for turbine-oil condition assessment.

    • Fire protection: Upgrades required by NFPA 12 for CO2 systems, water mist suppression systems.

    • Rejuvenation heat treatment of single-crystal GT blades.

    • Generator diagnostics for asset management.

    • 7FA compressor offerings from a third-party supplier.

    • HRSG fast-start considerations (hot and warm).

    • Auto-tuning and optimization for improving efficiency.

    • Lawyer’s view of key considerations for performance upgrades and rotor exchanges.

    • 7FH2 stator deficiencies.

    • Failure mitigation of non-seg phase bus.

    • Advanced thermal-spray TBC.

    • Rotor lifetime extension.


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Turbine valves: How to prevent an actuator failure from tripping your plant

The value of user groups continues to grow in the electric power industry as the number of employees on the deck plates shrinks and personnel with deep experience retire.

The plant manager for a 2 × 1 J-class combined cycle under construction told the editors he had received more than 500 resumes in the last two months for about 20 hourly positions at the facility. Two-dozen employees is the total headcount planned. Given that most candidates are not familiar with this gas turbine—only a handful of J engines are operating worldwide and the US fleet leader had less than a year of service time in February 2018—training time likely will focus on the GT because it is the revenue resource. Certainly would make sense.

What about the other equipment? Who is the subject matter expert (SME) on steam-turbine valve actuators, for example? Anyone? Not likely. The editors picked this for illustrative purposes because their Rankine Cycle experience comes from the nuclear and coal-fired plants home to large, hydraulically actuated steam valves and big staffs with SMEs for virtually every piece of equipment.  

Before the Steam Turbine Users Group was launched in 2013, the major gas-turbine users groups may have dedicated half a day to steamers. STUG enabled owner/operators to drill down on important steam-turbine (ST) topics, like actuators, that weren’t covered previously because of time constraints.

Actuator inspection and overhaul was on the agenda for STUG 2016 and then again in 2017. If you’re a neophyte and don’t understand why this subject would be discussed two years in a row, by the same company (MD&A), you ask someone on the steering committee.

Here’s what the editors were told by a committee member with decades of GE steamer experience: Back in the days of “big steam,” he said, GE, the dominant turbine supplier, made its own actuators, which might have run for 30 years with little or no maintenance. In the combined-cycle era, Bosch Rexroth AG has supplied the majority of actuators for large steam valves and those must be overhauled every five to eight years.

Some actuator designs have specific issues that require close attention. For example, Rexroth actuators for Toshiba steam turbines are very large and oriented horizontally creating wear points that might not be found in the vertically mounted actuators on GE machines.

In the mind of this committee member, at least, actuators for turbine valves may be the most important “forgotten” component in a steam plant. Many problems, he said, can be traced to water ingress and maintenance inexperience. At his company, in-service failures and numerous servo and solenoid issues that had occurred when station O&M personnel were charged with maintaining actuators in-house have been avoided by contracting the work to a specialty shop.

But, the turbine expert cautioned that there are no guarantees when it comes to actuator reliability. Inspection and soft-parts replacement, which typically are scheduled during steam-turbine minor inspections, are done at intervals of about five years—a long time given the wear and tear traced to today’s demanding cycling requirements.

Because you don’t know exactly what you’ll find when an actuator is dismantled for inspection, be sure the overhaul partner you select can assure the ready availability of parts—unless you have a back-up set of actuators, as some owners do. Scuttlebutt suggests that getting parts from Rexroth, a German company, can be challenging. However, most users are likely to agree that Rexroth has the best actuator on the market today for steam valves.

To learn more about what owner/operators can do to minimize actuator issues, the editors spoke with MD&A’s Anthony Catanese, an engineer on the front lines of the company’s Ohio overhaul shop and the SME invited to speak at STUG 2017.

Actuator performance and lifecycle are influenced most by the cleanliness of the hydraulic fluid and your ability to restrict water ingress, Catanese said. Varnish presents a double whammy: It can plug the 4- and 10-micron filters for the servos, the actuator’s “brain.” Plus, it can combine with oxidation products produced during the degradation of the hydraulic fluid to form rust and varnish that inhibits actuator operation and may reduce spring life.

Given the importance of actuators and how easy they can be to forget in the daily crush of plant activity, consider assigning responsibility for them to one person in the O&M department. There’s not that much to do except keep after the few recommended activities for relatively few valves—eight in the case of a GE D11, an integral part of the OEM’s 2 × 1 and 3 × 1 combined cycles. Those plants typically are equipped with two each stop, intercept, control, and reheat valves.

When scheduling D11 overhauls, Catanese notes that some customers have opted to inspect and refurbish two valves every year to level both cost and outage time on an annual basis. Most often only about a week or two of scheduled shop time is required for the basic “open/clean/close” process and replacement of soft parts for a full set of eight actuators. An incoming inspection report with shop recommendations is generated shortly after actuator receipt. Plant personnel are invited to verify the report’s findings, discuss the recommendations, and witness testing after work is complete.

Of course, the technician assigned responsibility for actuators should be looking at them periodically when out in the plant. One of the first signs of concern often is leakage out of the packing-gland telltale weep hole. If borescope examination of the spring reveals moisture or rust, maintenance should be scheduled soon.

Moisture causes rust which can cause broken springs which, in turn, score the shaft and promote increased leakage. Plus, moisture can accumulate and contribute to the failure of springs on vertically mounted actuators. As a stop-gap measure, consider removing a breather vent and using dry shop air to pressurize the actuator, thereby preventing water/steam accumulation in the spring can.

Given the problems with varnish and moisture ingress that can arise over an actuator’s lifetime, it makes sense to spend time at the design stage to select the optimal hydraulic fluid for the service. If problems arise in service, give thought to replacing the fluid with one better suited to your application.

Finally, when your actuators leave the shop, be sure they are properly crated for shipment and possible long-term storage and secured in an upright position.

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Vegetation challenge? Consider goats

Sharing ideas, and solutions to problems encountered in operating and maintaining powerplants, is why users groups were formed by owner/operators. Talen Energy is a big supporter of these self-help all-volunteer organizations, its personnel actively participating in several—including the Combined Cycle and 501G Users Groups.

An idea sure to generate discussion at upcoming meetings comes from Colleen Dolan and Regina Chan and their colleagues at Talen’s Athens Generating Plant, operated by NAES Corp. The three-unit, 1080-MW, 501G-powered facility is located 30 miles south of Albany, NY, a stone’s throw from the Hudson River.

Plant facilities include two storm-water basins designed to safely capture and release natural and facility discharge into federally protected wetlands. The man-made ponds are monitored by the New York State Pollutant Discharge Elimination System Permit Program.

Since commissioning in 2004, the ponds, located in opposite corners of the site and designated the northeast and southeast ponds, have become overrun with vegetation, mainly cattails and sumacs. Such vegetation is often found at power-generation facilities, especially those surrounded by woods and wetlands.

Storm-water ponds become inefficient when overcome with vegetation. And when pond berms attract vegetation (other than grass), root systems can undermine the berms causing leaks. At Athens, the cattails also attracted muskrats, which began making holes in the berms. Plus, obstructed visibility of the site’s perimeter was a security concern. Thus, vegetation control became a critical part of facility maintenance.

Proper pond maintenance is critical for both operation and environmental conservation. Generally, storm water refers to runoff that does not soak into the ground, and can travel into waterways. In the case of Athens, that eventually leads to the Hudson River. Storm-water runoff collects pollutants and debris as it travels, enabling concentrations of materials that can cause damage to lakes, rivers, wetlands, and other water bodies. Thus it can have negative impacts on animal and plant life, plus sources of potable water, and other things as well.

Because containment and controlled discharge are part of Athens’ state permit program, vegetation must be controlled.

Cattails, aquatic perennial plants, overwhelmed the Athens ponds. Three species of sumacs (Staghorn, Smooth and Poison) also appeared in and around the ponds. These shrubs and small trees produce flowers with dense pinnacles and fruit. Sumacs can reach a height of 30 ft.

The northeast pond is designed to collect and release water from natural sources and from the Athens facility. When vegetation became an apparent problem, the pond’s discharge pipe was closed for long periods in an attempt to raise the water level where cattail growth would not be induced. The area also was brush-hogged. These two actions significantly reduced the need for vegetation removal and maintenance. But the pond berm and surrounding area soon became an alternative growth area, and uncontrolled sprouting became a new concern. Extensive mowing is the current viable solution.

The southeast pond (map) also is designed to carry, collect, and release, but the facility has not yet been required to open its discharge pipe. Water collected in this pond is from rain and occasional release from transformer containments. Therefore, the level normally is low, providing an ideal environment for vegetation growth within the pond. Both cattails and sumac have flourished and have invaded the berms and surrounding areas. Brush hogging, extensive mowing and manual labor have not decreased the problems. Some cleanup activities actually have increased the progression of these plants.

Actions and alternatives. Biocides and herbicides were never an option for vegetation control. Alternatives were discussed with the New York State Department of Environmental Conservation, concluding that mechanical removal would be the most appropriate. But New Athens had attempted mechanical means since 2011 and these had proven neither economic nor efficient. The vegetation would return.

Sometimes the best solutions are relatively simple and, in this case, local.

Athens personnel contacted a local farmer who raises goats. They are herbivores, naturally clearing land with their insatiable appetites, and capability to ingest a wide variety of plants. Their natural craving includes cattails and sumac. For the more tree-like sumac species, goats will eat the bark or use it to clean their horns, in addition to eating the leaves. This prevents new shoots from growing.

After surveying the southeast pond area, the farmer was willing to locate a small herd of 10 goats in a fenced area for eight weeks. He would visit daily to bring water, check animal health, and oversee progress. This became a trial run to determine whether or not the goats would be comfortable and willing to feed on the overgrowing vegetation. Goats were placed in four different areas of the pond throughout the eight weeks to test their appetites and adjustment to the environment. The results:

Area 1. The southern area of the southeast pond is a steep hill that meets the Conrail Railroad tracks east of the Athens facility. This zone is filled with sumac and had grown into a miniature forest. The view of the tracks (and security perimeter) was obscured by the dense canopy of leaves and thick branches. This area was chosen the first test because of its abundance of sumac.

Within 48 hours, the goats had made significant progress, eating away at the sumac leaves and cleaning their horns on the bark. Within 10 days, and view of the railway was significantly improved. Approximately half of the trees were stripped bare as the goats targeted the staghorn and smooth sumac. They also ate the grass, flowers, and weeds.

The goats concentrated on the steep hill. The untouched vegetation was either plants that they could not ingest, were too high to eat, were poison sumac, or were staghorn containing white flowers (young sumac getting ready to bloom).

Area 2. The goats were moved to the second zone after 10 days. This was the pond area containing cattails and surrounded by sumacs and other vegetation, and was the area of most concern to the facility (pond discharge pipe).

However, because of poor weather and standing water in the pond, the goats did not venture into the base but instead only grazed on the sides, eating the sumac trees.  Their sensitivity to water overruled their preference for cattails, reducing their overall impact. They ate approximately 35% of the area, consuming leaves and breaking down barks, impeding future growth.

Area 3. After 14 days in Area 2, the goats were moved to a zone densely populated with shrubs and weeds on the hill and with staghorn and smooth sumac at the base. This was the smallest test area, bordering a larger natural habitat. Thick vegetation made it difficult to monitor progress. The goats cleaned approximately 25% of the vegetation, primarily on the hill. Rain accumulated on the ground floor where other sumac resided, and the goats were soon moved to the next area.

Area 4. The final test zone was the north region of the southeast pond. This area is also a hill that meets with an adjacent fuel oil tank. It is not filled with cattails but instead consists of tall sumacs, shrubs, bushes, and common weeds. The goats could graze and then rest under the tall trees during hot days.  

Approximately 40% of the area was cleared by the feeding. Another 10% was eliminated through sun exposure as the goats stripped the bark and ate the roots. Their preference for sumac reduced any significant impact on other shrubs; they would break the shrub leaves and pull on branches but would not consume them. The farmer became concerned for their nutrition and they only remained for one week.

Results. This trial seemed to benefit the facility, the goats, and the farmer. For the plant, approximately 40% of the overall vegetation in the test pond area was cleared. It was environmentally sound; the vegetation was reduced and nutrients were restored back to the ground. It was also economical, providing a sensible program with positive results. For the farmer, the goats were well fed and grew quickly.

Roadblocks were identifiable. Water in Areas 2 and 3 limited the goat herd’s potential to clear away cattails. Dislike for young, tall staghorn sumac in Areas 1 and 4 limited overall clearing of sumac. But the trial provided first-hand experience and useful data for future trials and programs. Many roadblocks (water accumulation, for example) can be reduced with early planning.

Goat trials will resume in summer 2018 at other plant areas.

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Getting top performance from your air-cooled condenser

Air-cooled condensers (ACCs), like their water-cooled (WCC) cousins, get little respect from plant personnel. These heat exchangers typically are viewed as being of secondary importance compared to the steam turbine/generators they serve. They certainly are not eye candy. The most popular version of the former looks like a huge elevated stage with spindly legs, the latter may be described best as a steel box filled with thousands of small-diameter tubes. Both are just kind of “there.” A pet rock comes to mind.

And what could go wrong with either? Not much, compared to the steam turbine/generators and most other plant equipment. But remember that a healthy condenser is critical to achieving top Rankine cycle efficiency and maximum profit. This puts condensers under the watchful eye of the financial folks.

Powerplant O&M staffs are most familiar with WCCs and much has been written about how to keep them at peak performance. For a short refresher, look back at the work done by your colleagues at Talen Energy’s Nueces Bay and Barney M Davis Energy Centers to earn one of CCJ’s 2017 Best of the Best (Practices) Awards.

Much less has been published on how to squeeze more performance from ACCs. One reason: There are far fewer ACCs than there are WCCs, hence the funds available to support product improvement have been somewhat limited to date. NV Energy believed dry cooling technology could be advanced at an affordable cost by fostering collaboration among owner/operators of ACC-equipped powerplants and it launched the ACC Users Group nine years ago with assistance from the editors of CCJ and CCJ ONsite.

The library of presentations from the organization’s meetings available on its website may be the most comprehensive collection of technical material on ACCs available publicly.

The ninth annual meeting of the ACC UG, held Oct 3 – 5, 2017 in Las Vegas, featured specifics of performance issues and measurements, equipment challenges and solutions, system chemistry, and design details that could be discussed and shared among users, engineering firms, equipment suppliers, and academics, and taken home for the benefit of operating plant personnel, owner/operators, and researchers. CCJ ONsite’s Consulting Editor Steve Stultz filed the following report; his coverage continues in the next issue of this letter.

Looking back over the years to the first meeting in 2009, the editors opined about what they viewed as a quantum leap in technology from then to now. Also, that because of water’s generally much higher value in areas outside the US, technology improvements—such as those to improve fan performance, mitigate gearbox issues, etc—are coming from places like South Africa, Morocco, Italy, Germany, Netherlands, and Spain.

Performance improvement. Huub Hubregtse of Netherlands’ ACC Team talked about the need for good operational data on heat transfer, fans, leak rate, etc, to decide what modifications or adjustments might be required to achieve top performance of the heat rejection system. He stressed the value of engineering expertise to for interpreting the data.

The plant DCS records turbine backpressure, steam temperature at the turbine exhaust, condensate temperature, extraction temperature, steam flow, and ambient temperature at the weather station. With this information, Hubregtse continued, the performance calculation method (a thermal design model) can calculate turbine backpressure as it should be. When compared with actual or historical backpressure, differences indicate either performance loss or performance improvement.

He went on to say that fan-performance determination requires the following data:

    • Actual air flow from the fan.

    • Static pressure in the plenum.

    • Static pressure at the suction side of the fan.

    • Fan power.

Air-side performance is evaluated based on the temperature rise of the coolant across the finned heat-exchanger tubes. The hot air temperature is commonly measured at the outlet of the bundles (50 positions). Air flow should be measured from the fan bridge in at least four directions.

Hubregtse also discussed the adverse impact of air in-leakage on ACC performance and stressed the need to inspect for leaks and eliminate them. He said performance losses of up to 10% have been attributed to in-leakage.

ACC fouling has two effects, he added. First, air flow is restricted, resulting in a higher static pressure than the original design. Second, the heat-transfer coefficient of the finned tubes is reduced by insulation layers (fouling) on the surface. Thus, ACC performance tests should be made after tube cleaning.

Details on air in-leakage at three ACCs in Mexico and two in the UK were provided by InterGen’s Oscar Hernandez, a member of the user group’s steering committee. At one plant in Mexico, instrumentation detected a change in the dissolved-oxygen concentration leading to repair of a spray nozzle. In another, dissolved oxygen again triggered an investigation leading to the finding of a steam-turbine gland seal out of position. For both, credit was given to accurate online instrumentation and continuous chemistry monitoring.

A lengthy list of key indicators beyond chemical parameters was reviewed, highlighting such items as increase in backpressure, decrease in condensate temperature, and loss of ACC vacuum. This was followed by a list of common air in-leakage sources including missing hardware, penetrations, welds, turbine shaft seals, expansion joints, pump seals, manways, and valves. Thermal imaging was recommended, looking for black spots

Structural Integrity’s Barry Dooley, a member of the ACC UG steering committee mentioned that IAPWS is reviewing the subject of air in-leakage for one of the organization’s Technical Guidance Documents planned for 2018. Dooley is executive secretary of the international body of experts.

Tube cleaning technology has advanced significantly over the last decade. AX Systems’ Romain Pennel presented on an automated cleaning system developed by the French company. His case study for a small waste-to-energy plant in the UK equipped with two A-frame ACCs illustrated the value of cleaning. Output had decreased by 3 MW before cleaning reclaimed most of that loss.

Pennel began with an overview of fouling mechanisms, showing how they create an isolation film and limit air flow through the fins, thereby reducing heat transfer. This includes fouling from the natural environment (such as pollen or sand) and from industrial sources (fiber, dust, and oil). The result: Reductions in vacuum, turbine steam flow, and power generation.

ACC configurations and challenges covered by the presenter included flat, A-frame, and V-frame. Examples of what not to do with regard to external cleaning of heat-transfer surfaces included the following:

    • Don’t use manual high-pressure spray equipment: It’s easy to bend fins when the spray head is not perpendicular to the tube surface.

    • Avoid sandblasting. Risks include fin damage and removal of any tube coating—aluminum, for example.

    • Say “no” to use of a bicarbonate solution for cleaning. Risk is the electrolysis effect between aluminum and NaHCO

EPRI’s Andy Howell, chairman of the user group’s steering committee, followed Pennel with a status report on the users group’s tube-cleaning guidance document, “Finned-tube heat exchanger tube cleaning.” The chemist reviewed an outline of ACC.02, which covers operational factors limiting ACC efficiency (such as ambient temperature and degree of external tube fouling), cleaning frequency, foulant removal using water, air, and dry ice, and much more.

He urged all attendees to participate in the development of the document with suggestions, reviews, and comments.

Of fans and wind. Failure to meet performance expectations often can be traced to wind effects and fan issues—such as marginal design, in both cases. Ockert Augustyn of Eskom, South Africa’s largest utility (produces about 95% of the country’s electricity), discussed operating performance of the world’s largest ACC at Medupi Power Station. It will be home to six 794-MW steam units; three were operating at the time of the meeting.

Eskom operates large ACCs at four multi-unit installations. Fans measuring 30 ft in diameter number between 48 and 64 per condenser; platform heights range from 145 to 195 ft. Water restrictions dictate use of ACCs.

Augustyn stressed that all ACC performance requirements are specified by the purchaser; the supplier is responsible for compliance and design. However, he pointed out that the supplier can be at an advantage because performance testing is not conducted at high-wind conditions.

Augustyn noted these risks for the purchaser: A supplier might be reluctant to add safety margins or other features that would make its offering less competitive, and the purchaser may not be able to disqualify offers or justify higher costs if all suppliers meet the specification. More important, performance characteristics in windy conditions are essentially unknown until after commissioning—too late for design changes.

Because most suppliers are in compliance with specifications, the advantage is theirs, and the purchaser needs to be knowledgeable of all potential risks and limitations.

Operational experience at Eskom shows there can be significant capacity loss during adverse weather conditions (high temperature and high wind speed, in particular). At the utility’s older Matimba site, CODs of its six 665-MW units extended from 1988 to 1993. A dozen vacuum-related unit trips attributed to wind occurred during the first seven years of operation. In 2016 alone, there were multiple cases of load losses exceeding 1000 MW.

Planning for Medupi drew upon Eskom’s experience at Matimba and its other plants:

    • Atmospheric conditions were based on 130-ft elevation above grade.

    • Design wind speed was 20 mph in any direction.

    • Wind-wall height was extended to the top of the steam duct.

    • An 8-ft-wide solid walkway was placed around the entire platform perimeter (for maintenance work, but also to reduce hot air recirculation).

    • Wind cross on ground level was 33% of fan inlet height.

    • Performance guarantees were verified by CFD before construction.

Also required was an increased gap between the ACC and turbine building. At Matimba, the two structures kissed, at Medupi they were 165 ft apart. Plus, the at-grade wind walls at Medupi were extended from Matimba’s 33 ft to 47 ft. Augustyn explained: “We went with what we knew, then made things stronger and bigger.”

The first unit at Medupi entered commercial operation in October 2015 and has experienced no vacuum-related load losses. ACC performance comparisons of Medupi and Matimba benefit from the close proximity of the two plants.

Wind screen design. Cosimo Bianchini, of Italy’s Ergon Research, shared his knowledge on the use of CFD analysis for optimal wind-screen positioning. He captured the attention of attendees with this factoid: Wind’s impact on the ACC is significant, reducing net power by 10% or more for each 22 mph of wind speed. Two common sources of wind-induced ACC losses, he continued, are fan performance degradation and recirculation of hot air into downwind fan inlets.

Bianchini went on to describe his overall modeling strategy with detail befitting a CFD specialist. He pointed out one of the advantages of modeling: The ability to test variations. In this case, 11 mitigation devices (screen plans) were tested by combining various suspended and ground-up designs. The optimal configuration, a compromise between performance and cost, was the cruciform fabric screen (30% open area) and suspended vertical screens around the ACC walls.

The conclusions: Wind screens can mitigate wind losses, showing a gain of up to 14% at 22 mph. This recovery factor starts decreasing at intermediate wind speeds. Actual flow rate depends on wind-screen configuration, wind speed, and wind direction.

Efficient fan design. Augustyn returned to the podium to discuss the “learning experience” for Eskom at Matimba. The plant had suffered historic losses in windy months but the utility’s engineering team concluded it was not economically feasible to reduce them entirely. Typical annual production from the plant is 24,000 GWh. Vacuum-related losses in 2016 totaled 350,000 MWh, or less than 1.5% of total production.  

Eskom initiated its loss-mitigation efforts with a thorough review of previous CFD work, including placement of wind screens. This led to a detailed look at fan performance.

Aerodynamic design was reviewed with CFD, keeping the same duty point. Static efficiency was set at 60%, and a steep curve was established to protect against wind.

South Africa’s Stellenbosch Univ was invited to participate in the study and a consortium was established to design, manufacture, install, and commission a high-efficiency 30-ft-diam fan. Consortium members included Kelvion (Germany),  Enexio (Germany), ECILIMP Termosolar (Spain), Soltigua™ (Italy), IRESEN (Morocco), Waterleau Group NV (Netherlands), and Notus Fan Engineering (South Africa). Funding was provided by the European Union through its Horizon 2020 Research and Innovation Program.

A unique manufacturing process offered consistent weight distribution. When eight blades were weight-tested, there was only a 500-g difference (less than 1%) between the heaviest and lightest airfoils in the group. There also was a 50% weight reduction with the new design. Blade angle settings achieved increased volume flow and reduced fan power consumption.

Aerodynamic improvements included the following:

    • The new fan consumes 15% to 20% less power than the existing fan for similar flow displacement.

    • Volume flow rates can be increased by 10% to 20%.

    • Cells have greater protection against wind effects.

Structural improvements:

    • Blades are not resonating, thereby greatly reducing vibrational loads on the gearboxes.

    • Blade shape and structure are consistent, making blades interchangeable without negative effects.

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COMMENTARY: Utilities embrace digital technology within the same old business models

Spending two full days at the DistribuTECH® 2018 Conference & Exposition in San Antonio, Tex, in January, was an opportunity for the editors of GRiDToday and CCJ ONsite to assess progress as the electricity industry “transforms” from centralized to distributed assets with customer service at the core of the enterprise. Or so all the executives were saying.

The concept of a “smart city” was certainly a prevalent theme, an evolution in buzzy phrases from smart meter followed by smart grid, as was the notion of a “digital utility.” During the keynote talks, a utility executive for a large municipal noted that the company is uniquely suited to be a smart city. An executive from the largest state-owned public utility in the country told the audience it is working to become the first “all-digital utility.” Both have built and are managing significant technology development centers to achieve these goals.

Of course, no one defined what exactly is a smart city or a digital utility, nor did anyone broach what the term smart city might imply about rural areas.

Later in one of the mega-sessions, a representative from one of the country’s largest investor-owned utilities said they were “looking to replace existing assets with new, smarter, and better ones.” This utility is, by the way, one of the largest coal-based utilities, too, which tells you something. The traditional utility business model is to earn a regulated rate-of-return investing in assets over a long time horizon. Smart cities and an “all digital utility” are grand central planning strategies which utilities are comfortable with, even if they are designed for “decentralized” infrastructure.

The muni executive gave an insightful company factoid: Last year the utility had 8470 MW of capacity in operation; in 2020 they expect to reduce that to 7880 MW, while adding 650 jobs. Clearly, those workers are not destined for the powerplants or transmission network. The executive said the company considers the community it serves “energy advisors.” That’s an advisory committee meeting one would probably make any excuse to avoid.

Not your father’s utility bill. The customer-services technology platforms being implemented are nothing like a paper utility billing statement delivered monthly. The hardware model, according to presentations and what was being exhibited on the floor, is the smart phone; the customer experience model is Amazon, and the engagement is intended to be 24/7/365.

Descriptions and demonstrations of these customer/utility interfaces were truly dazzling, with systems controlling a two-way transactional electricity flow interface with the utility, rooftop solar, smart thermostat and HVAC, behind-the-meter storage, electric-vehicle charging station, and more. Customers can chart and alter (or not) behavior, costs, and revenue (if they are selling power back) patterns through data visibility.

Demand side management (DSM), in other words, has come a long way from the utility subsidizing the replacement of an old refrigerator with an efficient one, while the ratepayer plugs in the old one in the basement to keep the beer cold. That was DSM circa 1970s.

Still early days. Despite the promise and potential, the smart-digital transformation is still in its infancy. Utility representatives generally talked more about their “initiatives” and future plans, their technology development programs, and results from initial demo facilities than they did of replicable commercial projects. As one example, the muni utility mentioned above has only one microgrid currently in operation. Meanwhile, the engineers and technocrats grappled with the nuts and bolts of making this stuff work.

Across several sessions addressing microgrid challenges and lessons learned, what was clear is that the one function that essentially distinguishes a microgrid from a conventional power and electrical system serving an industrial facility, for example—the capability to “island” (or safely disconnect) from the utility or larger grid in responding to a disturbance, keep operating, and then automatically reconnecting when the disturbance is cleared—is still the greatest challenge.

In one presentation, the microgrid manager noted that “it was a challenge going from island” operation back to the grid-connected operating state. Further, that seamless transitions work but you may need to shed some load.” That actually doesn’t sound like a seamless transition. Another microgrid operator “was not able to demonstrate transitioning from islanded to grid-connected operation. In this project, one problem was that the battery-storage communication system couldn’t react fast enough to synchronize the battery to utility frequency.

Other challenges mentioned by several with demo-project experience included:

    • Accommodating cloud-induced variability with solar PV systems.

    • Contracting for, and integrating, state-of-the-art components from multiple suppliers into a coherent system design.

    • Understanding and complying with building codes and standards and new standards for microgrid components and grid interfaces, which are still evolving.

    • Control and communications protocols and cybersecurity issues among different subsystems (storage, PV, microturbine/generator, etc).

    • Loop testing hardware with real-time digital simulation (described by one presenter as critical).

    • Handling reactive load profiles and providing reactive power support (one presenter mentioning the application of “smart” inverters).

Finally several C-suite challenges were noted, perhaps unintentionally. For example, a representative of a large nuclear-based utility with a national footprint said they were “pursuing a customer and energy services business model” while also noting that “the customer experience [stuff] is only 5% of the utility’s annual expenditures.” Protecting current revenue sources while pursuing hot new growth areas is always a fundamental challenge for executives of large companies.

One executive noted that “the future is in energy storage.” However, it’s also true that reliable, affordable storage is what could decouple customers from the utility grid, reduce the need for purchased utility power to the emergency backup category, and allow new market entrants to manage a customer’s residential or commercial energy infrastructure. Thus, the real race may be to pay off existing “dumb” assets and retain ratepayers with dazzling new services delivered through an Amazon-like interface before Amazon and others like it dis-intermediate the utility altogether.

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