A recent webinar, posted here, will assist in ensuring environmental health and safety amidst the Covid-19 pandemic are being handled properly and with the utmost attention to detail. Groome Industrial Service Group has been in the industrial and commercial cleaning business for over 50 years and most known for their expertise in specialty cleaning of HRSGs, SCR catalyst, CO catalyst, and air-cooled condensers. Listen in to Groome’s Jeff Bause, Steve Houghton, and Paul Feldner on best practices to keep your plant safe and sanitized during outages.
The best way to contact Groome for more information is through Steve Houghton, shoughton@groomeindustrial.com, 201-445-6100 x132.
St. Charles Energy Center, a 745-MW, 2 × 1 combined cycle in Waldorf, Md, is owned by Competitive Power Ventures (CPV) and operated by Consolidated Asset Management Services (CAMS). Plant manager is Nick Bohl.
Pocket guides invaluable to new employees
Challenge. Powerplants can be intimidating to new employees, and bringing a new hire’s knowledge up to an acceptable level is a priority for both the employee and the company. Today there may be only one person assigned to handle all of a plant’s outside responsibilities and he/she must be able to respond immediately to direction given over the radio by the control room operator in case of a problem. This requires knowing where every piece of equipment in the plant is located, which takes time; carrying drawings on rounds is not practical.
Solution. Personnel at St. Charles Energy Center, a 745-MW, 2 × 1 combined cycle in Waldorf, Md, created a pocket guide which provides layouts for different areas of the plant and the locations of vital equipment along with simplified drawings. Technicians do not need detailed drawings to know where they are and where to find a specific piece of equipment. The guide consists of multiple laminated cards with drawings on the front and on these drawings are numbered locations. Each number correlates to a piece of equipment and the description for each number is on the back of the card. The pieces of major equipment identified on the cards are those an outside operator may need to attend to or have been problematic.
Results. The pocket guide, developed by Chris LaBille, has greatly improved the knowledge and efficiency of the outside operators and reduced job stress. Their ability to respond quickly during recent freeze conditions proved invaluable.
Guidelines assist operators in understanding NERC standards
Challenge. To help operators maintain compliance with NERC requirements, plant management sought to improve their familiarity with certain regulatory standards. The goal was to have knowledge on specific topics easily accessible for reference if a corrective action was needed.
During plant starts after cycling, CROs sometimes noticed voltage spikes that would linger on the high side of 238 kV. For a 235-kV voltage schedule, generator output cannot exceed ±4-kV from the set point. The limited information easily accessible to operators was not in keeping with the plant’s proactive safe and efficient culture.
Solution. The “Plant Generator Voltage Schedule per NERC standard VAR-002” guideline was created so all operators would be aware of the NERC requirements regarding the plant’s specific voltage schedule. It includes the information needed by operators to deal with a regulatory exceedance or near miss.
A PowerPoint also was created to explain NERC’s voltage schedule guideline. Operations personnel were required to review this presentation and answer questions afterwards. Any questions raised were answered thoroughly to assure complete understanding.
A plant voltage graphic also was added to the operations screen so all CROs and lead operators could continuously monitor grid pricing and the dispatched generation set point (Fig 1). When the voltage changes ±3 kV, a red light flashes, bringing the voltage schedule to the operator’s attention.
Results. The enhancement, credited to Mario Longmore and Jonathan Bennett, has proven very helpful. Also, operators are less stressed knowing they have the tools to respond to a regulatory episode in the unlikely event one occurs. Finally, the work described further reflects the culture of St. Charles and the continuous efforts made by staff to make proactivity and forward thinking a priority among all employees.
Winter preparation important to successful operation
Challenge. St. Charles Energy Center discovered during the January 2018 “polar vortex” that the plant was extremely deficient when it came to winter readiness. During this period, it experienced many trips and forced outages associated with freezing transmitters, valves, and sensing lines.
Solution. In summer 2018, plant leadership met to address all the issues that had occurred during the previous winter to be sure St. Charles was ready for the cold weather ahead. They developed a multi-layered plan that would take months to perfect and implement.
First step: Plant personnel identified and prioritized critical components, systems, and other areas vulnerable to freeze-up—including transmitters, instrument air system, motor-operated valves, valve positioners, solenoid valves, and fuel supply. The locations of these critical components and the heat-trace circuits and panels associated with them were identified.
A contractor was engaged to perform a heat-trace audit. Every circuit was tested, and amperage draws were compared to design data. The amperage readings were used to create heat-trace rounds so technicians could compare the live value to the expected value and report or address any discrepancy.
Plant personnel inspected every foot of insulation, verifying thickness, quality, and proper installation. Any missing insulation, gaps, and/or damage were noted. The list of insulation repairs ended up being well over 100 items. A contractor was hired to correct them.
Using the critical components list, technicians identified locations for wind barriers to protect components in winter. Plant management decided to use scaffold-type enclosures wrapped in a fire-resistant tarp. They are sturdy, removable, and cost-effective. Electric heaters, heat lamps, and halogen lights were installed in the enclosures.
Plant personnel inventoried all supplemental equipment onsite associated with freeze protection. Needed items were ordered and added to the inventory. To ensure critical equipment did not freeze under any condition, online and offline equipment cycling lists were created. They directed operators to cycle or exercise certain valves and pumps periodically.
In fall 2018, training was conducted to highlight preparations and expectations for severe cold weather. It included response to freeze-protection panel alarms, troubleshooting of freeze-protection circuitry, identification of plant areas most affected by winter conditions, a review of special inspections or rounds implemented during severe weather, and lessons learned from previous experiences and the NERC Lessons Learned program.
Results included zero lost opportunity attributed to freezing in winter 2018/2019. This significantly helped the plant’s bottom line as well as employee morale. The plant has proven it can perform cold starts and remain online during single-digit ambient temperatures and wind chills below zero.
Project participants: Kelly Swann, Jennifer Renner, Mario Longmore, Jonathan Bennett, Mike Williams, James Brown, Rick King, Kenny Boone, Javier Gomez, Josh Plourde, George Sellmon, Ronald Scott, Chris LaBille, Frank Katzenberger, Sidney Potmesil, and Peter Swaby.
Labeling of chemical piping raises awareness, prevents injury
Challenge. Since COD, St. Charles has experienced several leaks in the sodium hypochlorite piping, which runs aboveground from the storage tank in the water-treatment building to the cooling-tower basin. Sodium hypochlorite and sulfuric acid piping are in the same pipe rack as lines conveying water not harmful to employees. Piping leaks are a safety concern because it might not be immediately clear if the leaking liquid is a chemical or water.
Solution. Plant staff, including Kenny Boone, labeled the chemical lines that run aboveground across the site. This makes personnel cautious and observant, and allows them to quickly determine the type of liquid discharge.
Results. Operators now respond to leaks more quickly and effectively to protect personnel.
Site safety pamphlet provides quick access to emergency information
Challenge. Project leaders were having a hard time ensuring vital emergency information was easily accessible and retained by all new personnel who came onsite. This included contact information for management staff and control-room phone numbers.
The previous method of disseminating this information was via PowerPoint. This would require visitors and contractors to take notes in order to have this information readily available or they would have to request it again from plant personnel. There was no guarantee that during an emergency, contactors would remember the information required.
Solution. A site safety pamphlet was created (Fig 2) by HSE Manager Jennifer Renner. This pamphlet is a trifold sheet of paper that contains management and control-room numbers on the front panel. Mandatory safety equipment, muster points, and smoking policy are listed on the back panel. Another panel provides the following site-specific safety points:
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- Driving and sign-in policy.
- A mandate to stay with plant contact.
- Immediate assistance if separated from plant contact.
- Personnel trained in AED, CPR, and first aid.
- Signal the plant uses to declare an emergency.
- A statement that all work must be preauthorized prior to starting work.
Inside the pamphlet is a full map of the facility with key areas labeled so a person will be able to orientate him/herself in case of an emergency. All fire extinguishers, safety showers, eyewash stations, muster locations, smoking areas, the first aid kit, and the AED are marked.
Results. The pamphlets are available next to the sign-in book in the lobby and during all outage safety briefings. The PowerPoint still has the same information, but with this pamphlet, visitors, contractors, and new employees need not take notes and can concentrate more on all the safety information delivered in this presentation.
Control-room display of boiler and pressure-vessel certificates
Challenge. The plant has over 40 state boiler and pressure-vessel inspection certificates that must be displayed in a prominent location and in plain view for review by auditors and inspectors. The licenses were being displayed in a large picture frame that hung in the control room but was in a location that did not allow someone the ability to inspect closely the information on each certificate. Plus, the display was unwieldy and licenses were prone to detaching and sliding down behind other certificates.
Solution. The need for a better organization was a must, along with minimizing space in the control room. Jennifer Renner and Kelly Swann acquired a flip and display wall organizer to have all certificates displayed neatly and in clear sight (Fig 3). It also makes it easier when certificates must be changed or reviewed.
Results. Auditors/inspectors and personnel needing to review certificate information have applauded use of this organizer. The ease of access to the information allows for quick review and reference.
The 7F Users Group and CCJ are working together to expand the sharing of best practices and lessons learned among owner/operators of large frame engines. One of the organization’s objectives is to help its members better operate and maintain their plants, and a proactive best practices program supports this goal.
The editors presented a summary of the best practices submitted by 7F users in 2019 during the organization’s annual meeting at the Renaissance Schaumburg, May 20-24. The entries judged as the Best of the Best are profiled below. They were submitted by the plants identified in color in the adjacent chart. Best practices from the remaining facilities will be shared in an upcoming issue. More detail on this year’s best practices will be available in CCJ #61 (print quarterly), publishing in late September.
Recall that CCJ launched the industry-wide Best Practices Awards program in late 2004. Its primary objective, says General Manager Scott Schwieger, is recognition of the valuable contributions made by owner/operator personnel to improve the safety and performance of generating facilities powered by gas turbines.
Industry focus today on safety and performance improvement—including starting reliability, fast starts, thermal performance, emissions reduction, and forced-outage reduction—is reflected in the lineup of proven solutions submitted this year.
Thumbnails of the five plants receiving 2019 Best of the Best awards follow (click plant name to access best practices content):
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- Lawrenceburg Power LLC, owned by Lightstone Generation and operated by Consolidated Asset Management Services (CAMS), is an 1186-MW facility in Lawrenceburg, Ind, equipped with two 2 × 1 combined cycles. Plant manager is Mark Johnson.
- Effingham County Power, owned by The Carlyle Group and operated by Cogentrix Energy Power Management, is a 525-MW plant in Rincon, Ga, equipped with a 2 × 1 combined cycle. General manager is Bob Kulbacki.
- Woodbridge Energy Center, owned by Competitive Power Ventures and operated by CAMS, is a 725-MW outdoor facility in Keasbey, NJ, with two 7FA.05 engines powering its combined cycle. Plant manager is Chip Bergeron.
- Elwood Energy, owned by J-Power USA and operated by NAES Corp, is a 1350-MW, nine-unit peaking facility in Elwood, Ill. Plant manager is Joseph Wood.
- Plant Rowan, owned by Southern Company and operated by Southern Power, is a 985-MW generating complex in Salisbury, NC, that has a 2 × 1 combined cycle and three simple-cycle units. Plant manager is Chris Lane.
Effingham and Woodbridge have received several Best of the Best awards between them in previous years. You can access those articles at www.ccj-online.com by simply typing the plant names into the search function box on the home page (top right).
With the 29th annual conference of the 7F Users Group at the Fairmont Dallas (Tex) Hotel, May 18-22, only a few months away, this might be a good time to register for the world’s largest meeting of frame gas-turbine owner/operators, assuming you haven’t already done so. About 250 users and 150 exhibitors are expected to attend, so the conference hotel could fill up quickly. Check out the meeting agenda, then register online. You can book your room through the website as well.
What follows are 16 best practices for improving safety and performance, and for reducing emissions, shared by seven plants powered by 7F gas turbines. These facilities were recognized for their contributions at the user organization’s 2019 meeting. Recipients of Best of the Best awards were profiled earlier.
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- Pocket guides invaluable to new employees
- Guidelines assist operators in understanding NERC standards
- Winter preparation important to successful operation
- Labeling of chemical piping raises awareness, prevents injury
- Site safety pamphlet provides quick access to emergency information
- Control-room display of boiler and pressure-vessel certificates
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- Unit axial vibration monitoring
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- Complex underground water leak repairs
- Eliminating chemical-tote handling hazards
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- Multiple benefits accrue from gas-chromatograph install
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- Lockwire prevents water-injection and fuel-oil purge-valve actuators from coming loose
- Sounding-cap addition on oil-tank lid
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- LOTO upgrade facilitates maintenance of chemical feed pumps
- LOTO test points
- Do your machine guards meet current standards?
Many combined cycle (CC) turbines working in more and more aggressive operating regimes face the added challenge of shrinking O&M budgets. From an accountant’s view, fewer operating hours for older machines equates to less need for O&M funds, however wrong-headed that may be from the deck-plates view. Thus, the hunt for less expensive but reliable, and potentially even superior, component repair services and providers continues unabated.
Focus here is on low plasticity burnishing (LPB), a patented shop technique to repair a variety of fixed and rotating gas- and steam-turbine parts suffering from foreign particle damage, stress corrosion cracking, fatigue, fretting, many forms of erosion, pitting, and surface defects generally (Fig 1).
LPB may be unfamiliar to many CC facility staff because it traditionally has been applied private-label, so to speak, through OEMs and other non-OEM services firms. Now, Lambda/Surface Enhancement Technologies (SET), Cincinnati, Ohio, which possesses the patents, intellectual property, machines, and tooling, and two decades of shop experience, is offering LPB-based repairs directly to owners/operators. The company traditionally had been focused on the aviation and defense industries.
LPB has been specifically proven in the field as an effective repair technique for CC plant applications including, but not limited to:
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- Erosion damage on R0 compressor blades of the 7FA and 9FA gas turbines.
- Foreign particle object damage (FOD) of seventh-stage compressor blades in 501F gas turbines.
- Stress concentration damage of first-stage compressor blades in Taurus 70 gas turbines.
- Moisture-induced erosion and high-cycle fatigue damage of low-pressure steam-turbine blades (Fig 2).
- Fretting damage on rotor through bolts in 501G-class gas turbines.
A representative of one 7F owner/operator told the editors that they tested several LPB-repaired R0 blades. . .“ran the hell out of the units” and the blades performed well.
In aviation, LPB has been applied repeatedly for similar damage mechanisms to at least a dozen major components of aero gas turbines—including blades, vanes, and discs at multiple stage locations. Many aeroderivative gas turbines in power applications are based on stationary versions of these same machines.
EPRI conducted a study several years ago with LPB and a competing technique, laser shock peening (LSP), applied to gas-turbine compressor blades subject to erosion, corrosion, and impact damage—especially in machines with evaporative coolers and direct water injection and fogging for boosting turbine output. Lambda/SET did the LPB work for this program.
According to the summary of the EPRI report, issued in December 2015, “LPB was used to apply an equivalent compressive patch to the leading edge of retired blades. The burnished blades’ residual-stress measurements met or exceeded the compressive layer depth and magnitude of the originally laser-shot-peened compressive patch.” Further, the report notes, “the plant owner could readily implement this enhancement on spare components. Typically, components would be shipped to a specialized shop to implement the compressive patch.”
CCJ ONsite covered early results with a rotor through-bolt LPB repair in “Siemens meeting focuses on issues, solutions, technology developments for large frames.” As noted in that article, “Because the most recent bolt fracture occurred on a rotor that had some mitigations applied, robust discussion ensued regarding the effectiveness of those mitigations as well as on the latest recommendation of low-plasticity burnishing. LPB is a surface treatment intended to greatly improve a through-bolt’s margin against both fretting and HCF crack initiation and propagation by adding a deep compressive residual stress field to the bolt surface.”
A review of LPB testing was provided at Siemens Energy’s first customer conference for F/G/H owner/operators in September 2015. It reported favorable results on fatigue resistance tests and open actions for additional ongoing tests—such as material debit and thermal mechanical exposure.
In some cases, owner/operators can reduce the number of times a set of parts (blades, vanes, etc) needs to be overhauled, and correspondingly the amount of time the unit has to be shut down for the work. For example, test results presented at PowerGen 2019 show that R0 blades nominally exhibiting only 0.008 in. erosion damage tolerance without any surface treatment can be LPB-treated to increase the damage tolerance to a 0.040 in. depth and be reused instead of being replaced. This could lead to the huge cost benefit of reducing the total number of shutdowns for this repair from five to two over the service life of the compressor blades.
Simply, in the LPB technique, a ball or rounded wheel is pressed into the component surface to deform the surface layer in tension, so that the material is left in residual compression after the tool passes (Fig 3). The required magnitude and form of the residual stress field are achieved by controlling the force and tool position. It is purely a mechanical repair.
LPB was honored as a NASA Spinoff technology for 2010 and earned recognition as one of the “R&D 100,” a list of the top 100 inventions of the year. An article on NASA Spinoff’s website with the unlikely title, “Burnishing Techniques Strengthen Hip Implants,” notes some of the important product outcomes of LPB:
“Capable of being applied to all types of carbon and alloy steel, stainless steel, cast iron, aluminum, titanium, and nickel-based super alloys, and many components with odd shapes or forms, LPB can be performed in a machine shop environment, in the field, and by using robotic tools. One important feature of the LPB application method is that it is highly controllable and can be validated to ensure that the process is applied to every part.”
Other attributes of LPB, compared to other options, are:
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- Depth, magnitude, and distribution of the compression are designed specifically for the geometry and stresses applied to each component.
- Compression ranging from a few thousandths of an inch (comparable to shot peening) to over a full centimeter.
- FOD- and erosion-prone blade edges can be put in through-thickness high compression.
- Minimal cold work, which keeps the compressive layer more stable at high temperatures and not prone to mechanical relaxation under momentary tensile overload.
- No residual surface damage, and therefore no finish machining or grinding; LPB leaves a mirror-like finish on all processed parts, and metallographic examination reveals no damage to the grain structure following treatment.
- Closed-loop control process with minimal operator intervention is continuously monitored with typical six-sigma statistical process control, ensuring a uniform repeatable production process.
- Only one processing cycle is necessary to achieve full depth of compression, which reduces costs and shop time.
Finally, to introduce LPB and its applications to CC facility staff, Lambda/SET plans to participate in the following user groups in 2020: 501F, Western Turbine Users Inc, 7F, Combined Cycle, and CTOTF.
Guest Commentary by Salvatore A DellaVilla Jr, managing director, Gas Turbine Association
“Too much change in too short a period of time,” the definition of ‘Future Shock,’ was conceptualized, defined, and shared in a book by Alvin and Heidi Toffler, published with the same name in the 1970s. If we look at today’s energy market, and we consider the messages that we hear almost every day, change has been too slow. But the global message is pretty strong: Change has to come fast and furious to mitigate the social and global impacts of using fossil fuels in power generating plants—no fossil fuels by 2040 or 2050.
Not many people would disagree that there is a need to reduce greenhouse gas (GHG) emissions to attenuate the rate of climate change. The goal of implementing a carbon-neutral economy demands will, policy, and technology; all three are required over a sustained period to effect positive change. Promoting clean energy solutions that include renewables, battery storage, and carbon sequestration cannot overlook the value and real benefit of natural-gas-driven gas-turbine technologies that already result in environmental improvement by transitioning the market to a cleaner energy future.
One has to wonder if where we are now is a result of not enough change over too long a period of our past, or simply a reflection of social confusion with the breakdown of normal decision-making that the Tofflers suggest is a consequence of “accelerated change.”
No fossil fuels by 2040 or 2050? That’s 20 to 30 years from now. That is fast! Is anybody worried about where baseload generation will come from? What about reserve margins? What will provide the base and load-following requirements, how will it be delivered? Who will provide the needed ancillary services, or black-start capability when power has been interrupted and must be restored quickly? Has anyone considered what will happen to energy costs in a 100% fossil-fuel-free energy economy? Balancing the grid, power and voltage, demands energy stability and resilience—a necessity.
The “Future Shock” is that heavy-duty and aeroderivative gas turbines will have a continued role with considerable sustainable investment value; they are part of the “Clean Energy Solution.” Replacing retirement-ready older coal-fired stations with more efficient gas-turbine-driven combined-cycle technologies has had a sustainable impact on reducing GHG emissions. Research from the Electric Power Research Institute (EPRI) indicates that “The US is responsible for 44% of global CO2 emission reductions since 2005, and 80% of that was from the electricity sector. Energy efficiency and cleaner generation have been the reason for these gains. Fuel blending can also help lower CO2 further.
The US has met the terms of the Paris Climate Change accord, at least in spirit and execution.
Gas-turbine combined-cycle systems integrate cost effectively with wind, solar, and existing battery storage applications. These hybrid systems can fill the cyclic, load-following, or peaking-power requirements that intermittent generators are not designed to fill alone. With new realistic “cleaner fuel” opportunity and availability, such as an appropriate hydrogen mix or blend, gas turbines will continue to meet the needs of baseload generation.
New-cycles development and associated R&D investment will ensure that gas turbines evolve in performance and capability to meet changing market demands. Gas turbines will add value as a clean energy technology that supports the needs of other market segments, like transportation charging stations. A vital component to the nation’s generating mix and the global installed base, gas turbines represent an investment-grade opportunity with a real return on investment that includes cost-effectiveness, reliability, efficiency, and resiliency.
The Tofflers were concerned with taking control over what they called “the accelerative thrust.” The “accelerated thrust” is always triggered by man, and it’s where we are right now. The Tofflers’ message: Control the waves of change or be overtaken by them. We need to heed this message. Climate change is real. Addressing this major global challenge means embracing the best mix of energy technologies. Gas-turbine technology, now and in our future, is a major part of the “Clean Energy Solution.”
Salvatore A DellaVilla Jr, managing director of the Gas Turbine Association, is the CEO and founder of Strategic Power Systems Inc. GTA is a membership organization established in 1995 with a goal of communicating the message that gas turbines are, and will continue to be, a vital component of power generation in the US.
Gas turbines now produce approximately one-third of our nation’s electricity. They are a cornerstone energy-conversion technology, providing electricity and heat for industries and communities. Today’s dynamic, innovative, and competitive energy market depends on clean and efficient gas-turbine products coupled with growing renewable generation capabilities.
In what GE claims to be the largest gas turbine black-started by a modern battery, Entergy Louisiana has added a 7.4 MWh lithium-ion (nickel-magnesium-cobalt chemistry) unit at its Perryville power station to restart a 2001-vintage, 150-MW 7F.03 peaking gas turbine/generator should grid power be lost.
To re-energize the grid, black starts typically require separate gas or diesel generators to first start the larger generator. When you avoid a diesel generator, you also avoid other complications, especially the liquid fuel storage and delivery system. Also, black start assets typically are tested more than they are called upon to operate.
The 11-month project reflects several current trends. First is the growing and diverse grid-scale applications for large batteries, primarily lithium-ion. Second is the “hybrid” concept of pairing them with traditional generation and T&D assets. Many storage system engineers consider black start to be the most difficult grid-scale battery application.
According to GE specialists, the storage unit includes a grid-forming inverter, whereas most storage (and solar) assets employ grid-following inverters. The grid-forming inverter essentially creates a voltage source reference point the turbine can synchronize to. In other words, the inverter can operate in stand-alone mode, as its own grid.
“The voltage source inverter control is specifically designed to coordinate with the GT controls, in this case the familiar Mark VIe,” said Troy Miller, head of sales for GE Energy Storage, a subset of GE Renewable Energy Hybrids.
The battery system consists of three 40-ft shipping containers with 21,400 battery cells connected to a series of controls to convert DC power to AC.
GE expects interest in its hybrid storage solutions to grow, including solar, wind, and thermal plants, and even for competitor gas turbines. Earlier, GE pioneered the first commercial application of battery storage to LM6000 machines to convert a non-spin peaking unit into spinning reserve at Southern California Edison’s Center Peaking facility.
Entergy Louisiana declined to comment for this article, but was quoted in the GE press release on the project as follows: “This is an innovative use of battery technology that provides another tool to buttress the overall reliability and resiliency of our system.”
The utility’s 2019 Integrated Resource Plan noted that energy storage, particularly in the case of battery-enabled storage, provides a range of attributes including: The ability to store energy for later commitment and dispatch, ability to discharge in milliseconds and fast ramping capability, rapid construction (on the order of months), modular deployment, portability and capability to be redeployed in different areas, small footprint (allowing for flexible siting), and low round-trip losses compared to other storage technologies (such as compressed air). The IRP made no mention of the Perryville project.
The turnkey digital front end (DFE) solution for aging, unreliable, or obsolete gas turbine load-commutated inverter (LCI) starting systems, described last year in CCJ ONsite, now has a user testimonial and operating experience supporting it.
John Chaya, operations manager at Cogentrix’ Rock Springs (Maryland), reports that the installation by Turbine Controls & Excitation Group Inc (TC&E), Denver, Colo, went “as expected,” testing proceeded with only the normal number of “bugs” to sort out, and all machine starts since Nov 8, 2019 have been successful. All acceleration and ramp rates were matched to the original OEM specifications.
All four 7F peakers at Rock Springs (commercial in 2003) will soon be served by two DFE LCIs, with the second unit install to occur this year.
Chaya notes that the motivation for the retrofit was that the majority of unit unavailability was attributed to the LCI. The precipitating event occurred in October 2017 when two units were out of service for 12 hours. Obtaining spare parts was becoming an issue as well. The units experienced 120 starts in 2019, mostly in the summer.
“The TC&E/TMEIC team was very professional and did the work in the time frame promised,” The timeline was three days for component changeout, two days for testing and commissioning during the 2019 fall outage.
Other benefits attributed to the project by Chaya: startup procedures remained the same and the electronics and interface screens are much larger and easier to read (Figs 1 and 2). One piece of advice he offers the next users: Be sure to request training for troubleshooting, even though “it’s pretty intuitive to get through the manuals.”
TC&E/TMEIC completed three DFE LCI upgrades last year.
With a little luck, you’ll never experience significant rub damage to your rotors. By design, OEMs usually provide generous clearance between the rotor and non-rotating parts except where it’s unavoidable: bearings and seals. OEMs mitigate the rubbing risks associated for those close clearance components with smart material selection—such as Babbitt, brass, and nylon. Those features work well enough when everything operates according to design, but that doesn’t always happen.
When significant rub damage does occur, say Calpine Corp’s Craig Spencer and GenMet LLC’s Neil Kilpatrick, repair options can be limited based on location and severity, but ideally the remedy requires only removal of the heat-affected material, which can be tricky if not done with the proper process.
Shaft rub basics. When your rotor is turning, any solid material that comes into contact with the rotor surfaces has the ability to cause rub damage. The severity of that damage depends on the total amount of energy and rate of energy transfer which occurs during the rub.
The most common rub occurs when some hard substance (grit) gets caught between the rotor and the bearing or the seals and that grit exceeds the given clearance, causing the grit to machine the surface of the rotor, making a groove with no evidence of heat, metal adhesion, or bulging.
Normally, a few small grooves pose no appreciable risk, and can simply be polished out (Fig 1; A, B, D).
If there are more than a few grooves, and/or if they are relatively deep grooves—such as from a hydrogen seal (Fig 1; C), bearing oil seal (E), or labyrinth seal (F), you may need to perform a step machining of the shaft surface, and replace the seals, and possibly the bearing, to fit to the new diameter.
Another common rub occurs when seal strips are set to an inadequate clearance during a maintenance outage. Generally speaking, these seal strips will wear in the necessary clearance in time, sometimes yielding deposits from the seal strips adhered to the shaft. Usually there’s no appreciable damage to the shaft substrate, and only shaft polishing is needed to remove the deposits. However, severe cases should be metallically evaluated after polishing, as noted with friction rubbing described below.
Less common, but potentially much more severe, is a friction rub created by contact between the turning rotor and a non-rotating member of the unit assembly as a result of an abnormal operating condition—such as a loss of lubrication or an abrupt lateral event like an L-0 blade liberation. Because of the relatively high energy transmission in a relatively short amount of time, these friction rubs often do show evidence of heat, metal adhesion, or bulging at the rub site. Fig 2 shows an example of shaft bluing from heat and metal adhesion attributed a friction rub.
Possible remedial options for friction rubs include, in order of severity:
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- Machining out the damage to a smooth bottom groove.
- Machining the damaged zone smooth and locally heat treating to temper back the heat-affected material.
- Machining out the damage and replacing the removed material using TIG welding.
- Replacing the shaft in whole or in part.
To better understand the need for these repairs, we should better define the physics of this type of damage.
Friction rub physics. The profile of a friction rub is depicted in Fig 3, where the rotor (in gray) rotates against a stationary object.
Because of the great momentum in the rotating shaft, it usually will continue to rotate no matter how hard it makes contact with the stationary object, at least for some time. High-energy friction contact can result in highly localized extreme temperatures within the shaft in proximity to the rub, often exceeding 1300F. Given that shafts normally are made of high-strength, low-alloy steel, this heating is often enough to locally transform the structure to soft austenite.
While the rub is active, heat flows into the rotor as depicted in Figs 4 and 5. As temperature builds in the hot zone (B-B), the hot metal tries to expand, but the cold surrounding metal is much stronger and more stable and compressional yielding occurs. As temperature increases, compressional yielding increases and locally reduces the strength.
During this intense rubbing, it’s common to form adhesive metal-smearing deposits on the surface.
When rubbing stops, the hot zone effectively is quenched down to the temperature of the surrounding metal. In typical rotor magnetic-steel components, this means that a local hardening transformation to martensite can occur. At the same time, a significant contraction of the former hot zone occurs, and the stress state of transformed metal zone will change to what can be a very high tensile stress.
Martensite is very hard and brittle, and so it is not uncommon for cracks to develop at this point because of the residual tensile stress. Rub severity is somewhat proportional to the likelihood for cracking to occur.
With this type of damage, crack initiation and propagation from normal operating stresses cannot be predicted, but, clearly, the probability of cracking is likely significant. This condition also means that the part (rotor forging, blower hub, blower blade, etc) is now capable of erratic and unpredictable behavior. This makes it imperative to treat or otherwise remove the damaged material, collectively known as the heat-affected zone (HAZ) from the shaft if it is to remain in service.
HAZ removal. As noted above, there are several repair options, depending on the location and severity of a shaft rub.
Usually, the most cost-effective and expedient manner to deal with a HAZ on a shaft involves machining it off. Because you want to preserve as much of the shaft substrate as possible to endure operational stresses, this machining is an iterative process, where usually skim cuts of the surface on the order of a radial depth of 5 to 25 mils are taken, and the remaining surface is evaluated for a need for additional skim cuts.
Depending on method of evaluation, there are challenges to accurately determining the remaining HAZ after a skim cut. If you look at Fig 2 of the as-found rotor, the damaged area is obvious. However, as you can see in Fig 6, the HAZ is much more difficult, if not impossible, to identify visually after a skim cut. The entire surface looks the same.
Within the HAZ, changes have occurred in the microstructure of the rotor steel. As a result, the steel in the HAZ is harder. Given that it’s not practical to cut up the shaft to examine the microstructure under a microscope to check for HAZ, it is common practice to check the hardness of the shaft as a proxy for determining if HAZ remains.
Typical hardness testers use a pen-like device to shoot a diamond-tipped projectile into the shaft surface and measure its response. It tests one location at a time with each impact. The reading is a highly localized average of the hardness at the test location.
And there’s the figurative rub: How can you be certain that you’re testing the correct location with this highly localized test on a rotor surface which looks like Fig 6? After a skim cut, it’s too easy to lose your references for locating the potential remaining HAZ, meaning you may get a false negative report showing no remaining HAZ simply because it was tested in the wrong location. This opens the door to possible crack initiation in service due to the remaining hard material.
A better alternative to evaluating remaining HAZ is a process called macroetching. It involves first polishing the surface with about a 600 grit or finer sander, and then applying an acid solution to the surface (10% Nital in this case). The changes in the steel microstructure cause variations in the grain structure and precipitates around the grain boundaries. The macroetching solution helps to accentuate these grain boundaries in a way which can be visually discerned with the naked eye in localized regions on the shaft.
In Fig 7, you can see the results of macroetching after the first skim cut, as well as measurements of Brinell hardness (HB). The hardness in the primary macroetching indication measured 457 HB, while measurements outside of the HAZ measure a nominal 271 HB. If you’ve got really sharp eyes, you may be able to discern in Fig 7 how there is a center whitish island of material surrounded by a material which is darker than the balance of the rotor surface. Such an appearance is typical of significantly hardened material.
Unfortunately, the rotor surface in Fig 7 is somewhat mottled by contact after the etch was performed. For a better perspective of what a rotor surface looks like shortly after macroetching, refer to Fig 8, which was captured after the second skim cut. There’s no need to do a hardness check because it’s obvious that there’s still a HAZ in the rotor.
Conclusion. Rather than hardness testing, you should insist on macroetching to evaluate remaining HAZ when dealing with magnetic steel. Don’t assume that the shop uses macroetching as a standard practice. Even if the shop isn’t familiar with macroetching, they should have a metallurgist/NDE contact who is. But in every case, the work must be done by qualified personnel.
Stainless steels are more difficult to examine with macroetching, so if your rub involves a stainless component, like a generator rotor endwinding retaining ring, it is even more important to consult with an expert metallurgist for options.
Large-scale battery energy storage systems (BESS) continue to demonstrate their ability to meet specific functional requirements of grid operations and management under a variety of business models and ambient conditions. Los Angeles Department of Water and Power (Ladwp) is the latest to add a BESS, primarily for transmission-line stability. It follows several recent projects with distinctly different primary functions.
Two years ago, Southern California Edison added a large BESS to its Center Peaker Facility. Its primary function is to capitalize on pricing for spinning-reserve capacity in the CAISO market. While the gas turbine/generator proceeds through its start sequence, the BESS delivers power immediately. The BESS also takes load swings while the turbine operates at maximum output, its most efficient and lowest emissions operating point.
SCE is credited with pioneering the first application of a fully integrated, hybrid BESS/LM6000 peaking facility. Just before that project began operating, the Village of Minster (Ohio) brought a 4.2-MW solar PV facility online paired with a 7-MW/3-MHh BESS primarily for power-factor control, peak-load management, and Reg D frequency regulation in the PJM market. Minster purchases all of these “services” and owns none of the equipment.
T-line stability. Last October, Ladwp brought a 20 MW/10 MWh BESS online down the road from a substation which takes 34.5 kV power, collected from 570 MW of solar PV in the area, and converts it to 230 kV for a long transmission line that takes the power to LA (Fig 1). The Beacon Solar + BESS earned recognition from the American Society of Civil Engineers (ASCE) as an Outstanding Energy Project.
Unlike Center and Minster, the primary function of the Beacon BESS is T-line frequency control and voltage regulation, with a secondary purpose of load following during the daily transition late in the day from sunlight to dusk as the utility’s afternoon peak demand begins to ramp up.
According to Ladwp’s Tom Honles, power engineering manager, in its first six months of operation, the BESS has successfully demonstrated its daily load-following function from 6 pm to 8 pm, discharging from a full state of charge to minimum state of charge at a programmed ramp rate of 5 MWh per hour. If necessary, the utility’s control center can dispatch the full 10 MWh of energy in a half hour or less.
Perhaps as importantly, the BESS has been shown to accommodate the extreme weather variations in the area, having operated through both sub-freezing and 120F ambient temperatures. The Mojave is among the harshest climates, in terms of extremes, in the continental US.
Utility grade. Experienced utility engineers will recognize a “utility mentality” in the design of this BESS. For example, there are redundant battery stacks to allow for scheduled maintenance outages and lifecycle cell degradation. While the plant requires 12 containerized battery units to meet rated load, a thirteenth was added for reliability and redundancy. Each container also includes redundant air conditioning systems; two HVAC fans are visible on each end (Fig 2). Each cooling system is “alarmed” as well.
Battery thermal management is always critical for a BESS but in the desert, even more so. To ensure that those a/c systems operate in the event of a complete loss of grid power in the area, a Cummins 180-kW (200-kW standby) turbocharged diesel/generator was incorporated into facility design. Seven days of fuel onsite is available to keep the containers cool (Fig 3). The engine was sized based on the a/c load, which gives you an idea of the parasitic load taken for thermal management.
The battery control system is integrated into the complex of battery enclosures, with redundant failover intelligent controllers, while the operator console and system protection reside at the substation control house about a half mile down the road. The ac substation also has seven-day backup engine/generator capability to support both the solar array and energy storage.
On top of the physical design margin, Ladwp has a contractual performance guarantee with Doosan Gridtech and KTY Engineering, the BESS supplier and facility engineer, respectively. The utility performed site acquisition and development, grading, electrical interconnection, structural foundations, site security, and control integration into the Scada network and Ladwp’s Energy Control Center (ECC).
Samsung SDI supplied the lithium-ion batteries/inverters. Fire protection is integrated into each box. The inverters are designed to meet PRC24 code for low-voltage ride-through.
Temperature has such a huge impact on batteries that, according to Honles, the components had to be sequenced and shipped to the site to minimize ground storage time. Otherwise, it could affect lifecycle performance.
As another precaution, the entire site is electrically grounded, since Li-ion batteries are “always hot,” says Honles.
A thousand words. A picture of the area offers a glimpse into what Ladwp has to manage but a visit puts it in stark terms. One sees on the drive up to the facility endless wind turbine/generators as you get within 10-15 miles of Beacon. Then when you take the turn off the main highway into the Ladwp grounds, it’s nothing but endless solar PV arrays. Honles notes that in a few years, more than a gigawatt of solar PV will be operating in the vicinity of the BESS.
Clearly, it is a remote location, but the BESS isn’t expected to need much attention. O&M procedures include maintenance of the critical cooling systems for the containers; replacement of a/c filters, something most homeowners can relate to; and semi-annual battery inspections.
Startup issues focused mostly on the power converter systems (PCS) and the battery controllers, but were of the typical mean-time-between-failures (MTBF) bathtub curve variety, notes Honles, and were experienced in the first three weeks of contractually stipulated performance testing, prior to declaring acceptance into commercial operation.
The BESS went through extensive testing in all three performance modes (frequency control, voltage control, peak-power delivery) prior to acceptance. Each battery rack had to do one full charge/discharge cycle each day for 90 days and do this 95% of the time (95% reliability guarantee, 99% availability).
Software allows three selectable operating modes. Frequency control has priority most of the day. At 6 pm, the software automatically switches into discharge cycle, and empties 100% each day from maximum state of charge (SOC) to minimum SOC. The final mode is to soften the solar ramp out at the end of the day as the sun goes down. The BESS was exercised in all of these modes during the performance tests.
The controls and communications architecture is often the greatest challenge with a large-scale BESS. Each battery cell has to be monitored and managed with tens of thousands of others, a task relegated to the battery supplier and its optimized battery controller electronics.
Then the battery system has to be integrated with the dc/ac PCS and inverters. The PCS’s ac connection is matched with corresponding harmonic-rated ac step-up transformers to match the medium voltage of the plant. The BESS may be integrated with a solar PV plant, such as that at Beacon, and through a utility substation, stepped up to a high voltage and interconnected to the transmission system. Entire facility requires control and communication with the utility Scada system.
To handle all this, Ladwp specified an open standard, and accepted in the system integrator’s proposal, the Modular Energy Storage Architecture (MESA), a communications protocol which, says Honles, includes a wide set of available data points, and flexibility with other storage configurations. While MESA was developed primarily for distributed energy resources, Ladwp adapted it to its needs by adopting a reduced set of data points necessary for the utility-type operations of their ECC.
Commercial terms. The BESS and balance of plant cost $17.5-million, almost $2-million less than the not-to-exceed authorization from the Ladwp Board. Total cost, including site development and interconnection, was around $23-million. However, it is important to note that the project was driven by the state’s AB2514 storage mandate, not an investment-grade payback, and to demonstrate the ability to serve as a reliability-enhancement asset.
Regarding the latter, Honles notes, the other options would have been (1) a static VAR compensator or (2) load shedding and curtailment of solar capacity on the transmission line. Neither would have provided a peak demand solution, however.
Storage in context. Finally, while this facility is large in the scheme of evolving grid-scale storage, it is worth noting that it is minuscule compared to the “big daddy” of storage in Ladwp’s system, the nominal 1300-MW Castaic pumped-storage hydroelectric plant. In this context, BESS has a ways to go. In fact, some power-system engineers estimate that 250 MW of variable generation ultimately needs to be coupled to 100 MW of 4-hr-capable storage to truly provide grid stability.
