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Repairing Wind Blades in the Field

Issue 5 and Volume 113.

By Drew Robb

In late 2006, the first Liberty wind turbines rolled off the assembly line at Clipper Windpower’s Cedar Rapids manufacturing plant. By 2008, Clipper had ramped up production to about 300 turbines, with production capability at close to 400 on an annual basis, but the company’s first challenges came just after installing its first turbines in 2007.

During inspection, one of Clipper’s fleet service personnel heard an unusual noise coming from one of the rotor blades at a project site in upstate New York. The machine was stopped for a closer look. Fleet Services found that an internal structural reinforcement panel in the root area of the blade had come loose due to a design flaw. Known as the aft shear web, it is a longitudinal spar that connects the high-pressure and low-pressure skins to each other in the widest area of the blade.


Clipper’s manufacturing plant in Iowa.
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“The connection of the spar to the blade skin was found critical to withstanding the loading experienced during turbine operation,” said Jeff Maurer, vice president of fleet services at Clipper Windpower. Although a fleet-wide inspection revealed this defect to affect about 20 out of 250 blades, Clipper decided to conduct a rotor blade reinforcement of the entire fleet by adding a shear clip that strengthens the connection of the spar to the blade skin.

Clipper’s efforts encompassed six wind farms in the U.S. as well as a blade factory in Brazil and the Port of Houston where the blades arrive in the U.S. One of the affected projects was already online and a retrofit had to be undertaken. The others were in the construction stage and blades had been shipped to the sites.

The company began the process of blade repair in the depths of winter at a site in Minnesota. Clipper engineered a control system to warm the blades to a certain constant temperature to be able to cure them properly. During extreme conditions, heating elements were used as well as blankets around the blades to produce the required temperature for curing. A lighting system and generators were rigged up and hot air units were used to warm the inside of the blade.

“Temperatures as low as 20 F to 30 F below zero were experienced and it was a real effort to develop an effective post-curing process and to get it to work consistently,” said Maurer.

Despite some of the most extreme winter temperatures on record, gale force winds and other challenges, all of the blades—hundreds in fact—were successfully repaired.

New Blade Issue Crops Up

Then in late August 2008, Clipper noticed some superficial cracking or imperfections in the skin of some blades. This was traced to a manufacturing problem with a vendor, Maurer said.

The company used a Six Sigma quality process to better understand the situation. A root cause analysis (RCA) isolated a flaw in the manufacturing process that caused small folds or wrinkles in the laminate used to form the blades. Under continual loads, small, superficial cracks were forming in the vicinity of the wrinkles within the blade skin, six meters from the root, on the trailing edge of some blades.

“When the laminate is laid into the molds, the positioning is critical to ensure the required properties,” said Maurer. “By dissecting the affected blades, we could clearly see these defects.”

Clipper sent a team to the Brazilian manufacturer to coordinate remedial actions and rolled out repairs in freezing temperatures in the field to all of the blades requiring repair.

Maurer said that approximately 10 blades suffered severe cracking that required complete replacement. Working with its vendor, Clipper developed a process that repairs and reinforces the affected areas. Since the slight laminate folds are not visible on the blade surface and are not able to be detected until loads result in superficial cracking, the Clipper team again made a decision to address all blades fleetwide.

Because the defects appear at the same blade location each time, this simplified the process of standardizing the repair procedure. Clipper’s blade reinforcement returns a 20-year life to the blade.

“Heat blankets are used to bring the temperature of the blade up to around 60 C so that fiberglass reinforcements can set properly,” said Maurer. “We have been bringing blades down to the ground at various sites concurrently, fixing and then remounting them. The entire job will be wrapped up by the end of the summer.”

As the repair and reinforcement process is conducted to the outside of the blade, Clipper is evolving special technology to carry out these repairs. This includes developing a prototype lifting system designed to eliminate the use of cranes for further blade remediation. The alternate structure is like a small shed built around the outside of the blade, erected on scaffolding. However, this technology can’t be used during severe weather.

“Our new skyclimber will be usable in the spring and will enable the process to move much more quickly,” said Maurer. “At the sites where we will be deploying the skyclimber, the turbines will continue to operate uninterrupted in the interim.”

To address the issue in the long term, Clipper sent a group to its supplier in Brazil, which adjusted its manufacturing process to detect these defects.

Author: Drew Robb is a Los Angeles-based freelance writer specializing in engineering and technology issues.


Hydroelectric Station Upgrades High-Current Switchgear

 

By Ben McKelway, freelance writer

With a hydroelectric generating capacity of 1,100 MW, the eight-generator Muddy Run Pumped Storage Facility in southeastern Pennsylvania helps the mid-Atlantic power grid meet peak demands. Built in 1966, the plant is undergoing a major generator switchgear upgrade that is phased over several years to minimize the impact on output capacity.

The Muddy Run plant boosts its output by drawing down its reservoir in peak periods and replenishing the reservoir off-peak. Four earthen dams form an 887-acre lake that holds up to 1.5 billion cubic feet (11.4 billion gallons) of water by containing the waters of the Muddy Run and other small tributaries.


Inside the Muddy Run Pumped Storage Facility in southeastern Pennsylvania, a technician checks newly installed Phoenix Electric switchgear prior to commissioning.
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On the downstream side of the dams at the river’s edge sits the power plant. In the daytime, water from the reservoir falls 343 feet through four intake shafts, each 25 feet in diameter, and is shunted through eight tunnels to the turbines. Late at night and on weekends, when electricity demand is low, the turbines are reversed to pump water up to the reservoir from the river 400 feet below. Twenty hours of full-load operation causes the surface of the reservoir to drop 50 feet.

The facility owner, Exelon Power, is a division of Exelon Generation Co., which is a unit of Exelon Corp., a Chicago-based energy company with more than $19 billion in annual revenues. Exelon’s ability to boost its output as needed—especially on hot summer days in the late afternoon and early evening when people typically get home from work and turn up their air conditioners—is critical to meeting the region’s dynamic peak electricity demands.

“The reservoir is like a giant battery,” said Charles Tuttle Jr., the plant’s senior electrical engineer who is supervising the upgrade.

By design, Muddy Run is not far (upstream and across the river) from the Peach Bottom Atomic Power Station—two nuclear reactors operated and partly owned by Exelon Generation. The nuclear plant runs all the time, so Muddy Run makes use of the excess power generated by the reactors at night to double its output the next day as needed.

In service for about 40 years, the Muddy Run generator units, each of which includes a generator circuit breaker and a set of switchgear, require two days of maintenance after every 500 operations (on/off cycles). Since the number of operations depends on the demand for electricity, there are days in the spring and fall when demand is low and some of the units are idle. But demand is higher in the winter and higher still in the summer, when it is not unusual for every unit to run at least twice a day. The facility’s eight 140 MW generators have already been replaced, but the aging switchgear is becoming expensive to maintain.

“The old switchgear is at the end of its life,” said Tuttle. “It is obsolete and has become very labor-intensive for us.”

The first of the eight replacement high-current switchgear units was commissioned in April 2007. Two more units were commissioned in the spring of 2008 and all three of the new units are performing well. The upgrade plan calls for three more units to be installed this spring and the last two in the spring of 2010.

Exelon’s multi-year contract for the eight sets of generator switchgear is with ABB Inc. At the heart of each replacement unit is ABB’s SF6 high-current generator circuit breaker, manufactured in Switzerland. For the rest of the gear—a veritable 3-D maze of high-voltage switches, control systems, and hundreds of feet of copper cable and buswork—ABB turns to its Boston-based supplier, Phoenix Electric Corp.

Phoenix Electric designed and is building the stacked switchgear cubicles (six per generator) that house ABB’s circuit breakers as well as the new Phoenix gear. Each of the eight six-cubicle units is approximately 18.5 feet high x 20 feet x 7.5 feet and weighs about 15 tons. Each is rated for 6,000 amps continuous duty at 15,000 volts and is capable of interrupting 100,000 amps short-circuit—among the highest-rated equipment of its kind in the world. When each unit is completed, it is shipped from the assembly plant in three sections strapped to semitrailer flatbed trucks.

Phoenix Electric has no “off-the-shelf” products; all of the company’s work is custom. The design/development phase, in which Exelon, ABB, and Phoenix engineers worked together, took thousands of hours of design, calculations and testing to ensure the new equipment would interface properly with the ABB breakers as well as the generators.


Designed and built by Phoenix Electric Corp. for one of the Muddy Run Storage Facility’s eight generators, this six-cubicle switchgear/circuit-breaker unit stands approximately 18½ feet high and weighs about 15 tons.
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“These are the largest units we have ever built and they are rated 20 percent higher than the units they replace,” said Stephen Simo, Vice President of Phoenix Electric. “The complexity of what Exelon needed, combined with the challenge of fitting more powerful switchgear into the limited available space, was a true engineering challenge.”

To speed and simplify the design of the units, Phoenix engineers made use of 3D software. The software made it easier for the engineers to visualize not only the components, but the spacing between them.

Positioning the components precisely within each cubicle was key to fitting them all in. Pertinent codes specified clearances or flame-retardant dielectric insulation between certain components.

The design for each cubicle also had to ensure that its bus connections would line up with those of adjacent cubicles. After the assembly and individual testing of each cubicle, Phoenix tested and measured each bus connection between each individual cubicle section to verify proper alignments.

Phoenix also had to design the packaging for the cubicles, which had to withstand the vibrations of a 10-hour truck ride to Pennsylvania.

All of the original Muddy Run circuit breakers are General Electric air-blast models. But because the new ABB SF6 breakers make use of a newer, more reliable gas-insulation technology, they are rated for 40,000 on/off cycles with minimal maintenance—more than 54 years of service at two cycles per day.


New Static Exciters Aid in Reliability-Related Equipment Testing

 

By John R. Hunter, Salt River Project (Originally published in Hydro Review, April 2009)

Arizona utility Salt River Project recently installed new static exciters in seven hydro units. The enhanced exciter capability enables utility personnel to conduct reliability-related equipment tests required by the Western Electricity Coordinating Council, rather than outsourcing the testing.

From 2005 to 2008, Salt River Project (SRP) in Arizona replaced the static exciters for seven turbine-generator units at three of its seven hydro plants. SRP chose these units, which ranged in size from a 10 MW conventional unit to a 115 MW pumped-storage unit, because they were the largest units at its peaking facilities. The remaining SRP units are smaller, at run-of-river projects.

As utility personnel completed work on the first unit, they realized that the new static exciter offered the capability for utility personnel to perform all reliability tests required by the Western Electricity Coordinating Council (WECC), rather than outsourcing the testing as had been done previously. Now, SRP performs all tests required by WECC — including static, generator saturation curve, generator dynamic model and exciter dynamic model testing, as well as unit inertial model verification and governor model validation. This saves the utility the time and money involved in hiring an outside company to perform reliability testing and allows SRP to perform select tests during commissioning of new equipment.

Installing New Static Exciters

Before selecting the static exciters to be installed at the plants, SRP polled others in the hydro industry for vendor recommendations. The utility then submitted requests for proposals to the identified vendors. In 2005, the utility selected the EX2100 excitation control system from GE Energy. SRP installed this system in all seven units over three years under three separate contracts. Installation was completed on the first unit in 2006. Based on the success with this installation, SRP contracted to have two more systems installed in 2007 and the remaining four in 2008.

For the two pumped-storage units and one of the larger (40 MW) conventional units, the utility installed EX2100 models that came with a redundant bridge. This provides a backup should one bridge fail. Because of the cost associated with this feature, SRP chose a model with a single bridge for the single 10 MW and three 11 MW units.

Arizona operates under reliability requirements governed by the WECC. As the utility completed the commissioning process for the first unit, personnel recognized that the EX2100’s processing power and interface provided the capability to perform all WECC testing in-house. Before the new static exciters were installed, SRP hired technical support people from outside the company to perform all reliability testing required by WECC. For this, the company had to bring all the hardware necessary to complete testing to the site, figure out where to wire into the old analog exciters, complete all testing and provide the reports to be submitted to WECC. For each unit tested, the company required at least a day to mobilize to the site and complete setup and another day to complete testing and de-mobilize. In addition, this work had to be coordinated with the operating group and dispatching. The reports would arrive several weeks later.

SRP concluded that using the installed capability of the static exciters to complete all data gathering in-house would save the utility quite a bit of money. It also would allow SRP to more easily schedule the testing around its needs, rather than the schedule limitations of the outside testing company.

Almost all the hardware needed to perform the testing was already in place. All seven units featured 4-20 milliamp (mA) loops for wicket gate position and speed. The only equipment SRP needed to order was an additional analog input card for the EX2100, to allow the utility to record the variables generated during the testing. Installing this card only involved wiring it in and configuring the GE interface software called Toolbox.

How SRP Performs Tests

In 1996, WECC experienced a severe system disturbance. To validate its computerized models of the system, in 1997 WECC required all generator operators connected to its system to complete unit testing. WECC wanted tests to be performed on all units rated 10 MW or greater and required that the tests be performed every five years. In 2006, the North American Electric Reliability Corp. (NERC) passed new regulations that formalized these testing requirements. Tests that must be performed every five years include static testing, generator saturation curve testing, exciter dynamic model testing, generator dynamic model testing, unit inertial model verification and governor model validation.

The following sections describe how SRP now performs these tests in-house, using the new static exciters.

Static testing. For static testing, each unit is loaded to various points on the megavolt ampere reactive (MVAR) capability curve. Operations personnel perform this test and record the data manually. SRP developed a recording form for personnel to use to ensure that all required data is obtained. On the form we use to record the static test data, we also record wicket gate position throughout the load range because one test requires wicket gate position versus unit load.

For the first couple of static tests, SRP had a relay engineer on site to assist with the process. This engineer developed a spreadsheet to indicate where we were in relation to the generator protection impedance circle for the under-excited tests. Additionally, it was helpful to provide the operators with a laptop computer hooked into the EX2100 system that showed, in real time, where they were in relation to the underexciter limit and overexciter limit functions. By comparing the data on the spreadsheet with the data on the underexciter limit and overexciter limit functions, we were able to confirm that the exciter protection comes into service before the unit is tripped by the protection system.

Depending on additional unit operations and system demands, the static test probably will take two to four hours to complete.

Generator open circuit saturation curve testing. This test is performed with the unit off line and at speed with an applied field. NERC requires that the voltage applied to the unit be adjusted from 105 percent of rated down to 50 percent of rated in 5 percent increments, to validate the generator saturation curve. To avoid disrupting the test, it may be necessary to defeat the field flashing circuit. Information SRP records includes the required voltage to be applied, the actual voltage achieved and the exciter field volts and amps. Again, operations personnel perform this test and record the data manually on standard SRP-developed forms. Table 1 shows a sample of data obtained during a generator saturation test.

Click here to enlarge image

The saturation curve test should take less than one hour to complete.

Exciter dynamic model testing. With the unit on line at low load and underexcited (or bucking) MVAR and the automatic voltage regulator in service, the generator breaker is tripped open. Information recorded includes generator volts and field volts and amps.

SRP performs this test, as well as the generator dynamic model testing, unit inertial model verification, and governor model validation, using the EX2100 Toolbox software to record the data.

Collected data is exported to a .csv file, which can be opened to chart the data using Microsoft Excel. It is best to use either an Excel or .csv file because most modeling software can read these file formats. SRP sends all the resulting Excel files to GE, where personnel plug the data into modeling software and generate reports that illustrate the results of the testing.

It is convenient to run the tests from the control room with a communication cable to the exciter where test personnel are located. The first step is to put the exciter on line. To perform an exciter dynamic model test, SRP’s procedure is to:

1) Start and load the unit to about 10 percent load and bucking MVAR.
2) Set up the Toolbox to record generator volts, exciter volts and exciter amps.
3) Remove any voltage setpoint control system from service.
4) Start recording.
5) Trip the generator breaker.
6) Record the values for 20 to 30 seconds.
7) Stop recording.
8) Return unit operation to normal.

It does not take very long to complete all of the trip tests. SRP has performed all the required tests, including the static tests, in a single morning.

Generator dynamic model testing. With the unit on line at low load and bucking MVAR and the automatic voltage regulator out of service, the generator breaker is tripped open. Information recorded includes generator volts and field volts and amps.

Unit inertial model verification. With the unit running at moderate output, the rotor speed and wicket gate position are recorded as the generator breaker is forced open.

Governor model validation. This test is also called the on-line speed reference step test. With the unit at 80 percent load, a frequency step change is induced into the control system to validate governor response. Information recorded includes unit load and wicket gate/blade position.

Regular WECC testing

For WECC, SRP must complete some of this testing every five years. If initial model validation was completed and no major maintenance has been performed (for example, replaced a turbine or governor, replaced an exciter or rewound a generator), required tests may be limited to:

  • Static tests
  • Exciter dynamic model verification or a step injection test (unless there is a recorded system voltage excursion event that proves the automatic voltage regulator response was appropriate); and
  • Governor model validation (unless there is a recorded system frequency event of sufficient magnitude to prove governor response was appropriate).

The static tests are designed to confirm that the unit can achieve the MVAR indicated in the model and ensure that the overexcitation or underexcitation limiters do not interfere with the capability.

For the exciter and governor tests, sample rates vary with use of a voltage or frequency excursion recording to validate the model. For a voltage excursion, WECC requires a sampling rate of 20 per second or faster. Although it may be possible to set the exciter up to record an event automatically, this can be problematic. It is almost simpler to just perform the test. For the governor test, a sampling rate of one every three to five seconds is sufficient. This sampling rate is within the range of most of SRP’s local energy management system/supervisory control and data acquisition (SCADA) historians, making them useful in validation.

Because the exciter step injection test is required during commissioning of a new exciter, it is provided for in the GE software. To perform this test, SRP simply sets the software for the size of the voltage step (about 2 percent to 3 percent), the time to wait before returning to normal, and the values to record. The unit should be at 80 percent load. Users must make sure to take any voltage setpoint controllers out of service and have the unit loaded such that the overexcitation or underexcitation limiters will not come into service.

Once the test is complete, the user opens the Toolbox and selects Edit, then Configure, then “Block Collected.” The user browses to the AVR/PSS_Test capture buffer, a feature of EX2100 that is designed specifically for this test. He or she then will select the quantities to trend when downloading the file.

SRP actually performs two tests at the same time. SRP has power system stabilizers on all exciters and a bit of local mode oscillation. SRP does one exciter step injection test with the power system stabilizer out of service and one with it in service. This confirms graphically that both the automatic voltage regulator and power system stabilizer are healthy.

As a backup to the capture buffer, the above tests can be recorded with the Toolbox trend recorder.

The ability to periodically test exciter performance can be extremely useful, saving time and money spent troubleshooting problems with old analog exciters. Many hydro plants are undergoing similar exciter upgrades, and most exciter manufacturers likely have similar interfaces and capabilities. Learning to use and maximize the capability of this new equipment can result in time and cost savings.

Author: John Hunter is operations and maintenance supervisor, instrumentation controls and electrical, for the hydro generation division at Salt River Project.


New Oil and Water Separation Technology

 

By John Scambos, President, Aqueous Recovery Resources Inc.

It all looks so simple on the surface; separating oil from water. Yet any engineer working with oil will readily confess that there is no easy way to separate water from product. However, an original application of basic fluid-dynamic principals has just recently spawned technology that, at last, thoroughly separates the two.

The fact that systems harnessing this technology employ dynamic construction that requires no maintenance, electronic control, energy or consumables, accounts for their cost effectiveness and rapid return on investment.

“With tightening regulations in most states to control hydrocarbon emissions in air or water, we sought out a novel approach to oil water separation,” said Michael Enos president and CEO of Monument-Colorado-based Auxsol, Inc. “Our senior engineer studied a half-dozen technologies, and we decided this new technology was the way to go. We’re real happy with the results.”

“The oil and water issue is a long standing problem in our industry,” said Enos, whose company, Auxsol, builds and operates mobile treatment units to clean oilfield-produced waters at the source. “We have customers ask us all the time, ‘What do you guys do for primary separation?’”

So pervasive the issue that other industries even peripherally dealing with oil and water have long sought solutions, with only mixed results.

“One of the toughest problems we face is getting the oil and water separated; in particular, trying to eliminate the oil sheen on top of the water that drains from our plant,” said Rolando Gonzales, an engineer with Consolidated Edison Co. of New York.

“The energy commission, Environmental Protection Agency and the State of New York are all very strict about discharging oil into the river. Anything higher than 15 parts per million is a violation and subject to fine.” As it turns out, commercial water users are doubly responsible in that concentrations may be well below the 15PPM threshold, but the discharged water can still have a visible sheen and that is a problem.

Unfortunately, traditional attempts at separating entrained oil from produced water have met with less-than-satisfactory results.

Unable to achieve primary separation, some companies have attempted to solve the problem by tacking on expensive “polishing” technologies at the back end of the separation “train”. Yet ultra filters, core wrapped membranes and reverse osmosis systems can cost hundreds of thousands of dollars, while still not effectively handling the oil.

Pioneered by Aqueous Recovery Resources, Inc. (ARR) of Bedford Hill, N.Y., the Suparator system utilizes new technology that incorporates a three-step separation mechanism involving no moving parts or media.

  • Collection: Water and oil enter the first compartment, where only water gets sucked out through an opening at the bottom. The design ensures that any amount of oil gets collected.
  • Concentration: The oil, still containing some water and chemicals, gets concentrated into a floating layer of considerable thickness, while water and chemicals migrate toward the interface and re-enter the water flow. The oil is then further concentrated to force water and chemicals out..
  • Separation: The upper fraction of the accumulated floating layer gets skimmed off, isolating pure oil. This “dry” oil is separated and ready for downstream refining or storage.

Such results stem from taking advantage of the Bernoulli Effect; the phenomenon whereby increased stream velocity in a fluid results in internal pressure reduction. Best known as the principle that creates lift in aircraft wings, it can also dynamically separate liquids of differing specific gravities. A number of valves are mounted across the fluid channel such that the major part of the flow passes underneath and a smaller portion passes overhead. Several “wings” are used to progressively shear off more oil and reduce water content. Since the interface layer does not have the same specific gravity as oil, dirt and other unwanted foreign objects get removed before they settle into the water tank and require detergents or maintenance.

Field Success

Auxsol’s customers ultimately gain the benefits of lower operating costs through: reduced water supply and disposal volumes, reduced dependence on external water sources by up to 50 percent and reduced environmental and health, safety and environmental exposure.

As this technology also enables desired chemicals to stay in the aqueous medium and not get separated with the oil, such achievements get duplicated in peripheral industries that face the challenge of removing thin oil films from valuable mixtures and solutions.

While some industries may not directly profit from the selling of oil product, they still stand to gain through the effective oil/water separation this new technology allows.

“We collect all the drains from our plant, and sometimes some oil sheen escapes through the other separators we have upstream,” said ConEdison’s Gonzales. “But the Suparator technology does the final cleaning, and so far it’s been working beautifully with very minimal maintenance. The water is pristine.”

As investments in these new-technology, oil/water separation systems offer a very short pay-back time through increased saleable product, reduced operational cost and minimal maintenance, while reducing associated environmental costs.