Natural ester uses 11 • Efﬂuent limits 15 • ASME: CO2 bottoming cycles 22
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Determine tube integrity with hydro testing
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By Mike Catapano and Eric Svensson, Powerfect Inc.
Editorial Board (editorial@WoodwardBizMedia.com) Bill Moore – Director, Technical Service, National Electric Coil Ram Madugula – Executive Vice President, Power Engineers Collaborative, LLC Kuda Mutama – Engineering Manager, TS Power Plant Tina Toburen – T2ES Inc.
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Effluent limitation guidelines: Expect the unexpected
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Natural ester fluids: A good fit for GSU transformers By Gene DelFiacco, Cargill Industrial Specialties, Dielectric Fluids Group
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Individual tube hydro testing verifies heat exchanger tube integrity
Flexible combined heat and power systems for offshore oil and gas facilities with CO2 bottoming cycles By Marit J. Mazzetti, Yves Ladam, Harald T. Walnum, Brede L. Hagen, Petter Nekså and Geir Skaugen, SINTEF Energy Research
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ON THE WEB Energy-Tech takes training online this month with three webinar options for our readers – from one-hour technical sessions to two-day courses. Topics include: Communicating across generations in the workplace, cooling water solutions and new boiler technology. Learn more at www.energy-tech.com and see page 33 for more about our upcoming online course, Cooling Water Solutions for Power Plant Professionals. Cover image courtesy of Powerfect.
It’s not an energy policy, but … Clean Power Plan lays out potential path There’s been quite a bit of discussion in the news recently about the EPA’s proposed Clean Power Plan, which sets new carbon limits for states for the first time and is expected to go into effect this summer. Sen. Mitch McConnell (R-Ky.) doesn’t like it, and wrote that states should hold out against the EPA plan.While I’m not surprised by his opinion, it does remind me of similar arguments I heard in the publishing industry when I began my career more than a decade ago. At that time, the Internet was still a relatively new creation. Google wasn’t yet a noun and a verb and alternative news blogs were just beginning to appear. Many publishing executives were skeptical of the online option - thinking it was just a fad - and didn’t invest in it. A few years later, it turned the industry’s entire profit model on its ear and everyone has been playing catch-up since. I see a similar process happening in the utility industry regarding environmental regulations and renewable energy.While power plants will always play the crucial role of providing baseload power to consumers, the appeal of being able to generate your own electricity and off-set your utility bill with some solar panels on your roof is only growing and becoming more affordable. And while new regulations might increase consumer’s bills, I feel confident saying that my electric bill would continue to go up without them. Companies need to make money and electricity is a necessity of modern life. Consumers will pay the bill, and take their own steps to become more efficient in their usage. Arguments against these realities are short-sighted, failing to see the benefit of planning for where the industry is already headed, toward more renewable sources, increased efficiency and cleaner power-gen production. At the end of the day, this is just business sense.This is where the money is going and states who don’t get onboard will be missing a growth opportunity. Read Ken Silverstein’s excellent March 15 column in Forbes for more on this – you can find it on Energy-Tech’s Facebook page too. Change is hard, but you can either grow with it or watch it go by without you. Growth is generally considered the better option. And speaking of growth, Energy-Tech has several opportunities to grow in your professional knowledge and workplace expertise this month. Check out our calendar for our three online courses this month, particularly the April 23 one-hour webinar with Hurst Boiler and the two-day course, April 28-29, on cooling water solutions with Brad Buecker and Ray Post. And, as always, thanks for reading Energy-Tech.
CALENDAR April 9, 2015 The Perfect Storm: Making the Most of a Cross-Generational Workforce webinar www.energy-tech.com April 19-21, 2015 2015 IEEE Rural Electric Power Conference Asheville, N.C. www.ieee.org/conferences_events April 21-23, 2015 Electric Power Conference & Exhibition Rosemont, IL www.electricpowerexpo.com April 23, 2015 Too Good to be True: Economic and Environmental Benefits of Biomass CHP System webinar www.energy-tech.com April 28-29, 2015 Cooling Water Solutions for Power Plant Professionals webinar www.etu-coolingwater.eventbrite.com May 11-15, 2015 Advanced Vibration Analysis (AVA) Houston, Texas www.vi-institute.org June 15-19, 2015 Rotor Dynamics and Modeling (RDM) Syria, Va. www.vi-institute.org June 28-July 2, 2015 ASME Power & Energy 2015 San Diego, Calif. www.asmeconferences.org/powerenergy2015 Sept. 21-25, 2015 Machinery Vibration Analysis (MVA) Salem, Mass. www.vi-institute.org Oct. 12-16, 2015 Balancing of Rotating Machinery (BRM) Knoxville, Tenn. www.vi-institute.org
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Individual tube hydro testing verifies heat exchanger tube integrity By Mike Catapano and Eric Svensson, Powerfect Inc.
Introduction In some of our past articles, we have stressed the need for a comprehensive programmatic approach to optimize heat exchanger life-cycle management. We have previously identified the integral elements of these programs relative to various inspection and testing methods that should be employed periodically in order to obtain a true picture of the overall health of utility plant feedwater heaters, condensers and balance of plant (BOP) shell and tube heat exchange equipment. With time, all types of heat exchangers will degrade – none are immune to failure. Therefore, a proactive maintenance approach of periodic condition assessment techniques and the trending of results over time is the most important thing that can be done to optimize the exchanger’s remaining useful life and overall reliability. The results of all evaluation methods will aid in understanding the root cause(s) of why damage is occurring and can provide a basis for establishing remedial actions when possible. The best life cycle management programs are ones that use a variety of complementary techniques since, in most cases, none are adequate by themselves to properly quantify and validate failure mechanisms. They include, but are not limited to: • Visual inspections • Leak testing • Individual tube hydrotesting (ITHT)
Figure 1. Individual tube hydrostatic test plug.
• Non-destructive examination/Eddy current testing (NDE/ECT) • Tube leak location detection • Failed tube sampling The main intent of this article is to stress that the most successful maintenance programs do not rely on only one method for assessment. All too often, responsible heat exchanger component engineers put too much emphasis on subjective NDE/ ECT results when formulating decisions regarding details of how and when to repair, refurbish and/or replace the equipment. Our experience has shown that the often omitted method of ITHT affords the only practical method of establishing remaining tube integrity. Backing up the NDE results with follow-up ITHT can help make the important decisions of what to plug more practical and less subjective.
Background history ITHT was developed back in the mid-1970s to eliminate insurance plugging and offer a more practical approach to establishing feedwater heater (FWH) plugging criteria in the days when ECT technology was not very reliable and its user’s capabilities were still developing. Alternative to insurance plugging For many years, insurance plugging was common practice in the utility industry. The purpose of plugging unfailed tubes was to prevent subsequent forced outages from secondary failures of the tubes adjacent to the original tube failure. Such failures were expected because the high velocity streams from the original leaking tube often degraded the surrounding tubes. Lacking further information regarding the condition of the surrounding tubes, the station guessed which tubes were suspect and plugged them for “insurance.” This approach seemed expedient at the time, but led to other problems. Under normal circumstances it is no longer considered good maintenance practice. In addition to the wasted time and cost of plugging good tubes, insurance plugging accelerated the demise of the heaters for two reasons. First, it greatly increased the plugging rate. This not only affected heaters because of thermal penalties and higher tube velocities/pressure drops, but also led to premature decisions to replace affected heaters because these decisions were based on the large number of tubes plugged (although many were still good tubes). Second, the weld repairs (the prevalent plugging method of that day) used to plug the tubes surrounding a leak often produced clusters of weld areas at the face of the tube sheet. Large differential temperatures were created in these areas;
Figure 2. Portable individual tube hydrostatic tester.
Figure 3. Testing a FWH with ITHT.
Figure 4. Dented tube in U-bend identified via video-probe.
particularly in fossil plant 3-zone high-pressure (HP) FWHs, because the plugged tubes no longer removed the heat imparted by the superheated steam. The end result in many cases was severe cracking of both the brittle weld repair material and the adjoining tube sheet ligaments, and was the direct cause of many heater replacement decisions. The development of an individual tube hydrotesting system used with test plugs that gripped and sealed the tubes from the internal diameter became a preferred alternative to insurance plugging. ITHT of the surrounding tubes can prevent the need for insurance plugging by testing each tube to a much higher pressure than the feedwater tube side operating pressure. Any weakened tubes on the verge of failure will not pass this go/ no-go integrity test and will be plugged. Tubes that pass the test can be returned to operation with a high level of confidence.
Principals of individual tube hydrostatic testing Tubes might be individually tested in order to provide a go/ no-go test to determine whether the tube is failed or weakened and on the verge of failure. By treating each tube as an individual pressure vessel, the tube can be tested to pressure higher than the tubeside operating and design pressures, as per UG-27 of the ASME Boiler and Pressure Vessel Code, Section VIII, Division 1, which gives equations for calculating the maximum allowable working pressure (MAWP). UG -99 of the current Code prescribes the 1.3 multiplier times the MAWP for the allowable hydrotest pressure.
Integrity test of suspect tubes complements ECT/ NDE Users found ITHT to be equally applicable to testing tubes found suspect via ECT and other non-destructive examinations. ECT of heat exchanger tubing is a very useful tool in establishing an overall picture of areas within the exchanger that are degrading and/or experiencing damage, but it does have its limitations. ECT data can be questionable if there is not a good correlation between the tubes being tested and the standard used for calibration. Additionally, the accuracy of the results is often dependent on the skill of the interpreter. Standard ECT methods cannot be used on ferromagnetic tubing such as carbon steel, Monel or Type 439 tubing. Specialized ECT methods such as Remote Field, Magnetic Saturation and Flux Leakage, as well as UT testing using IRIS, have been developed as the state of the art has improved dramatically during the past 40 years; but limitations with ECT still remain. Despite its limitations, ECT is still recognized as a useful source of information with regard to heat exchanger tube condition assessment; however other test methods are needed to help thoroughly evaluate remaining tube integrity. ITHT can provide a complementary test in support of any suspicious damage called by the ECT surveillance, the results of which offer a more practical criteria in determining the suitability of the individual tube for continued operating service.
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Figure 5. Tubes dented due to Weir Plate being pushed against U-bend supports.
Figure 7. Condenser tubes following refurbishment. Tubes that passed hydrotest remained unplugged and were returned to service.
The MAWP is defined by the code as the lesser of two equations:
Where: P = Internal design pressure S = Maximum allowable stress values (per ASME Code, Section II, Part D) E = Joint efficiency (1 for seamless tubes, 0.8 for welded tubes) R = Inside radius of tube in inches t = Minimum thickness of tube
In addition to the details of the tubing and the material characteristics, the selection of the optimum test pressure is application specific and should also take into account the objective of the testing, the age of the exchanger, any known failure mechanisms, as well as the specifics of the operating parameters. Test pressure judgments for HP FWHs are different than those for condensers or BOP exchangers.
Advantages of ITHT Individual tube hydrostatic testing has the following advantages: • Go/No-Go test for remaining tube integrity – offers practical plugging criteria. 8 ENERGY-TECH.com
Figure 6. Condenser tube plugs prior to testing.
• More stringent test than overall system tube-side hydro – individual tube test pressure is often higher than operating pressure, or even vessel design test pressure. • Precludes insurance plugging – only tubes that are failed or weakened are plugged. The tubes surrounding a known leak that were traditionally insurance-plugged are tested to ensure that they can handle the higher hydrostatic test pressure. • Prevents future forced outages – any tubes that are weakened from leak impingement and on the verge of failure will be failed during the hydrostatic test and plugged. • Portable systems available – testing can be performed anywhere. • Complements other NDE inspections – provides indication of stress concentration factors.
Understanding stress concentration factors Test trials conducted on tubes with known machined defects of various configurations confirmed that the nature and characteristics of the defect had a significant effect on remaining integrity, and the yield point and burst pressure at which the tube failed. Tubes with longitudinal defects tended to fail at lower than predicted pressures as the tube was axially pulled apart by amplification of the internal pressure. Tubes with circumferential defects of about the same percentage wall loss tended to fail at higher pressures than empirically calculated. Tubes with simulated pits of the same wall loss held even higher pressures. Since the characteristic of a pit is a localized point of severe wall loss with significant reinforcement surrounding it, often times these tubes would not fail when subjected to full hydrostatic test pressure. This indicates that the equations in UG-27 are not suitable alone as the basis for plugging criteria. This is mainly due to the fact that the minimum wall thicknesses required as calculated by UG-27 assumes a uniform thickness for the entire tube wall. That is not usually the case. Prior experience has shown that the sizing of defects as reported in ECT results sometimes do not directly correlate with hydrotest results. Some tubes that failed the test were reported in the 50 percent wall loss range or even less, while others that were reported as 91-100 percent wall loss withstood a 7,000 psig ITHT without failure. These test results support APRIL 2015
FEATURES the need for multiple test and inspection condition assessment to operating pressure, each dented tube was individually hydro methods. If the ECT results are valid and true, then they contested to the heater design pressure of 1,800 psig, well above firm that there are stress concentration factors related to certain the operating pressure of 1,200 psig. Of the 340 tubes tested, types and configurations of defects and that their effects play a only one tube failed the test. significant part in remaining tube integrity. Therefore, simply Although a dent is a deformity due to a force strong enough using a criterion of 50, 60 or even 70 percent wall loss based to plastically deform the tube, it might not have appreciable on an ECT report might remove a significant number of good effect on the tube burst pressure in the absence of other damtubes from service. A better approach would be to individually age mechanisms. Therefore, the dent itself should not always be hydrotest tubes when they exhibit wall loss above 50 percent considered a damage mechanism that significantly affects the or other specified value, and let the results of the ITHT dictate integrity of the tube, though there have been instances where which tubes should be plugged. If percent wall loss has been the dent is large enough to prohibit passage of an eddy-curtrended for some time and the rate of wall loss increases significantly, then the station Y O U R C O M P L E T E S O U R C E F O R P R O C E S S B A L L V A LV E S should investigate the root cause; try to eliminate the factors that have caused the increase in rate and individually hydrotest ™ questionable tubes.
Case histories The usefulness of ITHT as a method to confirm remaining tube integrity can be illustrated in two case histories.
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Case History #1: High pressure feedwater heater During a recent outage, a station was conducting ECT of its HP FWHs, which had been in service for more than 30 years. This FWH has a drain inlet nozzle near the back of the heater with an associated integral flash chamber and a weir plate in order to protect the U-bends. In the past, only the straight lengths of the tubes had been tested, however, in this outage, it was decided that the U-bends also would be tested. It was discovered in the U-bends that there were approximately 340 restricted tubes, located primarily in the outer 13 rows on the east side of the heater. A tube-side videoprobe inspection revealed that the tubes had been dented at a location near the centerline of the U-bend. It was suspected that the U-bend supports might have moved and crimped the tubes. A shell-side videoprobe inspection was conducted via the relief valve flange and pressure taps in the drain’s inlet nozzle in order to inspect the U-bend supports and the weir plate. This inspection revealed that the weir plate attachment welds had failed and that the plate had become dislodged on the east side and was pushed against the bundle. It was unknown how long this condition had existed within the FWH. In order to confirm that the tubes had not become weakened and would fail while subjected
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FEATURES rent probe. Since it was unknown how long the weir plate had been dislodged, if the plate was wedged into place or could still vibrate in operation, and whether there was potential for further damage, the station plugged some of the tubes closest to the weir plate in order to minimize the chances of an in-service tube leak. However, this was a fraction of the tubes that would have been plugged solely on the ECT indications. Case History #2: Main surface condenser Over the course of many years, a station plugged a significant number of condenser tubes during short duration outages. Typically, when a forced outage was taken to resolve an apparent condenser leak, the shell side was flooded overnight and the waterboxes were opened. The following morning, station mechanics were sent in to find and plug the leak(s). In most cases, water leakage was found cascading down the face of the tube sheet and the actual leak locations were difficult to identify. Many times the tubes that they thought were leaking were plugged, along with several other tubes in the surrounding area just to ensure that the leak was stopped. They simply plugged everything they thought might be leaking. Although this allowed the unit to be returned to service as quickly as possible, this practice resulted in many unfailed tubes being plugged. Additionally, the plugs they were using were unreliable and tended to loosen with time. A refurbishment program was developed that included removal of older, unreliable tube plugs • and individually • • • • hydrotesting the • SELL • RENT• LEASE • plugged tubes to • - 24 / 7 • 500 psig. Tubes that • EMERGENCY SERVICE • failed the ITHT • • • • were re-plugged • • with more reli• • able mechanical • • IMMEDIATE DELIVERY • seal plugs, whereas • tubes that passed • • • • the ITHT were • 10HP TO 250,000#/hr 250,000#/hr Nebraska 750 psig 750 TTF • • 150,000#/hr able to be returned Nebraska 1025 psig 900 TTF • 150,000#/hr Nebraska 750 psig 750 TTF • to service based on Nebraska 350 psig • the high amount of • 150,000#/hr 115,000#/hr Nebraska 350 psig Nebraska 750 psig • • 80,000#/hr Nebraska 350 psig 60,000#/hr Nebraska 350 psig • confidence that the • 75,000#/hr 40,000#/hr Nebraska 350 psig • tube would not fail • 10-1000HP 20,000#/hr Erie City 200 psig Firetube 15-600 psig • in operation. • ALL PRESSURE AND TEMPERATURE COMBINATIONS SUPERHEATED AND SATURATED • • Overall, the proRENTAL FLEET OF MOBILE • • TRAILER-MOUNTED BOILERS gram was deemed • 75,000#/hr 75,000#/hr Optimus 750 psig 750 TTF • 350 psig to be successful. • • 60,000#/hr Nebraska Nebraska 350 psig Nebraska 500 psig • • 50,000#/hr The improved tube Nebraska 350 psig 30,000#/hr Nebraska 350 psig • plugs prevented any • 40,000#/hr 75-300HP Firetube 15-600 psig • • ALL BOILERS ARE COMBINATION GAS/OIL • ENGINEERING • START-UP • FULL LINE OF BOILER • re-initiation of tube
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leaks due to loose or dislodged plugs during the course of operations between outages, thereby increasing condenser reliability. In total, 812 tubes out of 1,571 previously plugged (just over 50 percent) were able to be returned to service, thereby restoring additional surface area in the condenser that was unnecessarily plugged and improving condenser efficiency.
Conclusion There are many instances where Individual Tube Hydrotesting can help to determine the actual condition of heat exchanger tubes. As a part of a comprehensive life cycle management program, complementary techniques of testing tubes can be used to help find root causes for failure mechanisms, while also maintaining heat exchanger performance by only plugging the number of tubes that is necessary for continued reliable operation. ITHT should be considered in cases where ECT results are suspected of having too high a margin of error, or are ambiguous or unclear, or if a large number of tubes exceed the station’s “plugging criteria” based on called wall loss. In these cases, ITHT can help determine which tubes should actually be plugged and which are suitable to remain in service. Some of the best maintenance programs screen the tubes with ECT, then employ follow-up ITHT as the criteria for plugging repairs on all tubes found to be damaged and/or suspect via the ECT results. Utilizing these two complementary inspection and test techniques makes heat exchanger repair/replace decisions much more practical than the results of either of them used alone. Together, they add much needed credence to determining actual remaining tube integrity. ~ Michael C. Catapano has more than 35 years of experience in the operation, design, procurement and maintenance of feedwater heaters, condensers and other shell and tube heat exchangers, including 7 years with PSE&G and 28 years as president of Powerfect Inc. His current work at Powerfect is primarily devoted to consulting, troubleshooting problems and assisting utilities with feedwater heater replacement and operating and maintenance activities. Catapano is an ASME fellow and has assisted ASME and EPRI in numerous feedwater heater projects, seminars and publications. He also holds three patents pertaining to feedwater heater testing and repair. Catapano has a bachelor’s degree in Mechanical Engineering from Newark College of Engineering. You may contact him by emailing firstname.lastname@example.org. Eric Svensson graduated from the Georgia Institute of Technology in 1993 with a bachelor’s degree in Chemical Engineering. He joined the Naval Nuclear Propulsion program shortly after graduation, where he received training in Nuclear Power Theory and Operations. In 2000, he received a master’s degree in Operations Management from University of Arkansas. His current role as vice president of Engineering at Powerfect is devoted to consulting, troubleshooting problems, as well as operations and maintenance activities. Since joining Powerfect, he has been involved in writing the specifications and conducting quality control checks for more than 20 replacement feedwater heaters. He also is a member of the ASME Heat Exchanger Committee and has co-authored several technical papers. You may contact him by emailing email@example.com.
Natural ester fluids: A good fit for GSU transformers By Gene DelFiacco, Cargill Industrial Specialties, Dielectric Fluids Group
Originally designed as a less-flammable, fire-resistant alternative to mineral oil, natural ester fluids were first used commercially as a transformer coolant and insulator in 1998. These fluids have more than twice the flash and fire points of mineral oil. They are self-extinguishing, which significantly reduces the risk of pool fires, as well as the risk of collateral damage to adjacent equipment that might otherwise occur. Natural ester fluids also offer a broad spectrum of environmentally friendly characteristics. During the late 1990s and early 2000s, natural ester fluids were used on a limited basis, often in environmentally sensitive applications. Recently, however, changing market forces have helped natural ester fluids successfully transition from a niche product to a mainstream tool that outperforms mineral oil in many applications. More than 600,000 transformers worldwide (including 15,000 substation installations and more than 500 medium and large power transformers) are cooled and insulated by natural ester fluids like Envirotemp® FR3® fluid, which is the most widely used natural ester fluid in transformers today. The vast majority of these transformers, however, have been installed at the distribution end of the grid. Many utilities have converted exclusively to natural ester filled transformers for their distribution fleets. On the power side, several power generation companies worldwide have committed to using natural ester fluids. Transnet BW, a transmission network operator in Germany, recently commissioned a 420kV power transformer filled with natural ester fluid, demonstrating the viability of these fluids in this high-voltage category. Only about 25-30 transformers on the generation side of the grid are using natural ester fluids — with most of those being retro fills. And yet, the same operational efficiencies and characteristics of these fluids that make a strong business case for their use in distribution transformers apply to transformers in the generator step up (GSU) category. Here’s why more power generation companies could benefit from following in the footsteps of their counterparts on the distribution side of the grid.
New life for aging equipment The average large power transformer in the U.S. is approximately 38-40 years old, according to a 2014 report from the Department of Energy (DOE). Seventy percent of those transformers are more than 25 years old. As the report indicates, “the life expectancy of a power transformer varies depending on how it is used. Aging power transformers are potentially subject to an increased risk of failure.”
Figure 1. An aging comparison.
The majority of power generation plants were built with a planned life cycle of 30-40 years. Simple failure of GSU transformers can be extremely problematic for power generation companies because of their size, weight and the amount of copper and other metals needed for their manufacture,
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FEATURES replacing a transformer is a costly and time-consuming process for power generation companies. Natural ester fluids have been proven to extend asset life — both in the laboratory and in the field. During normal operation, all transformers produce water, which can negatively impact the functional life of a transformer. Natural ester fluids are essentially self-drying; they can absorb approximately 10x as much water as mineral oil. This protects the cellulose insulation in the transformer from the level of degradation that typically occurs in transformers
Figure 2. Fire and flash point comparison.
cooled by mineral oil and, for new transformers, has been proven to extend the life of the insulation by 5x-8x — which in turn can extend the asset life. The high-temperature capabilities of natural ester fluids (which can typically operate at 130°C hot spot vs. 110°C for mineral oil) also can help extend asset life. Cargill first began providing natural ester fluid for retro fills of GSU transformers in 2002 when a customer asked for a natural ester fluid to be used to retro fill a 1957-era, 150 MVA GSU transformer at one of their substations. Twelve years later, the GSU is still operating at full capacity. There also is substantial risk with aging transformers suffering a catastrophic failure, involving fire and/or explosion. Because the majority of existing GSU transformers were installed in the 1960s and 1970s, before current spatial and fire mitigation requirements were in place, the risk for substantial collateral damage is significantly higher than for installations meeting current requirements. In many cases, the GSU transformers are as little as 3´ to 5´ from the wall of the generating station and the generators just 3´ to 5´ on the other side of the wall. So if a transformer suffers a catastrophic failure, it could knock out a substantial portion of the power company’s generation capacity, which can take as much as two years to replace. Even a non-catastrophic transformer failure can be costly. Recently, a mid-sized U.S. company experienced a failure resulting in fire damage to the GSU transformer and the wall next to it. Although the failure did not completely knock out the generators, it still took several weeks and cost more than $5 million to return to full generation capacity. In the meantime, they also lost the revenue associated with the lost generation capacity. The increased fire-safety characteristics of natural ester fluids can greatly reduce the likelihood of such shutdowns. Underwriters Laboratory and FM Global classify FR3 fluid as a less flammable fluid. Perhaps more impressive than the classification is the fact that since the first natural ester fluid-filled transformer was installed in 1998, not a single transformer using natural ester has had a fire-related failure reported.
Figure 3. High temperature example.
Figure 4. The Conrad Substation.
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As a result, natural ester fluids are ideal for retro fills of GSU transformers in power generation stations that were built in the ’60s and ’70s and don’t meet current spatial and fire mitigation requirements. Underwriters like FM Global emphasize the risk that these installations represent to the power generation companies, and retro filling with natural esters is considered to be a risk mitigation option.
Per the Environmental Protection Agency guidelines, natural ester fluids are deemed to be ultimately biodegradable (meaning they will completely biodegrade in 28 days). Testing by the Organization for Economic Cooperation (OECD) confirms that natural ester fluids are non-toxic and non-hazardous in soil and water (OECD test #203). Changing regulatory environment Recent regulatory changes also help make the business case for using natural ester fluids in GSU transformers — much the same as they did for distribution transformers. For starters, because the use of natural ester fluid has been proven to extend the insulation life of assets, both in original equipment and when used as a fluid for retro fills, the Federal Energy Regulatory Commission has ruled that all costs associated with the conversion to natural ester fluids — fluid, labor and equipment — can be capitalized (February 17, 2011; Docket No. AC11-2-000). Per the Environmental Protection Agency guidelines, natural ester fluids are deemed to be ultimately biodegradable (meaning they will completely biodegrade in 28 days). Testing by the Organization for Economic Cooperation (OECD) confirms that natural ester fluids are non-toxic and non-hazardous in soil and water (OECD test #203). According to the BEES 4.0 lifecycle analysis, natural ester fluids have been classified as essentially carbon neutral, resulting in 56x less carbon emissions than mineral oil.
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Figure 7. Fire clearance example.
The Bureau of Land Reclamation has established a higher level of environmental safety for transformers at hydroelectric dams in some parts of the U.S. They now recommend use of a transformer coolant and insulator that will cause no significant environmental damage, even if it spills directly into the waterway, which is tantamount to requiring the use of natural ester fluids. In a move to be proactive, one Pacific
Northwest company has decided to use natural ester fluids to retro fill all of its GSU transformers. Current U.S. energy policy is dictating a relicensing of some existing generators during the next three to five years. The expectation is that much of our existing generation capacity is going to be recertified without requiring any sort of equipment upgrade. Natural ester fluid retro fills could improve the safety profile of these facilities, and extend the GSU transformer life. Additionally, U.S. energy policy calls for retiring the oldest fossil fuel power generation stations. This means roughly 30-40 percent of our current generation capacity is due to be retired during the next three to five years. As new generators and GSU transformers are brought online, the enhanced fire-safety profile of natural ester-filled transformers (relative to mineral oil-filled transformers) could save millions of dollars. These saving could potentially come in several ways: through the elimination of fires and the associated losses during the expected life of the transformer; per FM Global guidelines, through the potential elimination of fire walls and expensive deluge systems; and, through more cost-effective installations, due to the fact the natural esterfluid-filled transformers might be placed closer to each other and to buildings in space-constrained installations. Whatâ€™s more, the high temperature capabilities of natural ester fluids will allow the manufacture of GSU transformers with a smaller footprint. Going forward, it looks as if use of natural ester fluids in GSU transformers could expand rapidly, much as it has on the distribution side of the grid. ~ Gene DelFiacco is a North America Business Development leader for Cargill Industrial Specialties, Dielectric Fluids Group, and has a diverse professional background, including 25 years of marketing, sales, technical and product management experience within the electrical power industry. DelFiacco received his bachelorâ€™s degree from the University of Illinois and an MBA from Marquette University. You may contact him by emailing email@example.com.
Effluent limitation guidelines: Expect the unexpected By Brad Buecker and Michael McMenus, Kiewit Engineering and Design Co.
Recently there has been much focus on air emissions regulations, as the EPA continues to clamp down on industries that burn fossil fuels, and in particular coal-fired power plants. But effluent limitation guidelines (ELG) are becoming more stringent for wastewater discharge at other facilities, including combined-cycle power plants. In many cases, the tightening regulations are being promulgated by states rather than the federal government, and so much uncertainty exists from state to state. This article examines these issues and techniques for wastewater treatment. The answers can at times be quite complex.
First, a look at coal plants Rather than deal with the expense and effort of complying with new air emissions regulations, owners of many older coal plants have elected to shut down the units. However, a significant number of large plants around the country are still in operation. Many were designed or retrofitted with wet scrubbers for sulfur dioxide (SO2) removal. Liquid purge streams
from wet flue gas desulfurization (WFGD) systems contain a complex mixture of chemical species, including impurities introduced from the coal. The EPA has focused on several, and Table 1 outlines these impurities and the projected discharge limit for each. Mercury, as would be expected, has the tightest limit. Given that the concentration in the purge stream is very slight to begin with, how can it be reduced even further? The answer lies in chemistry. Mercury very strongly and almost completely reacts with sulfide ions (S2-) to form an insoluble precipitate. Mercury can be â€œdropped outâ€? of solution in a clarifier if a sulfide chemical is added to the treatment process. Original chemistry was based on inorganic sulfides, but this chemistry offered two major difficulties. First, some inorganic sulfides are quite hazardous, and thus safety issues with regard to handling are of concern. Secondly, mercury reacts so quickly with sulfide that the precipitates from inorganic sulfide treatment might be so fine that they carry over from a clarifier and cannot be cap-
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REGULATIONS COMPLIANCE These polymers will participate in typical clarifier flocculation reactions, but where they have captured mercury. Selenium presents an entirely different problem. During combustion, selenium reacts to primarily form the selenite ion (SeO32-). If one examines the periodic table, selenite is analogous to the sulfite ion (SO32-). Selenite is actually an ion that can be rather straightforwardly removed from solution, but in wet scrubbers, most of which are forced-oxidized to produce a gypsum byproduct, selenite is converted to selenate (SeO42-) and this ion cannot be readily extracted from solution. Selenium ions can be removed in wetlands via uptake by vegetation, but obviously this process is very land intensive, with a potential host of issues that make it difficult or impossible at most facilities. An alternative that has been successfully demonstrated is GE’s Abmet® process, in which WFGD wastewater passes through media containing microbiological organisms that capture oxidized selenium species, metabolically convert the ions to elemental selenium and retain the selenium. Beds will reach exhaustion and must be replaced. Exhausted material is disposed in a properly certified landfill.Veolia’s SeleniumZero® Figure 1. Schematic of polymer chains with sulfide groups attached. is another technology that is gaining interest. The idea stems from the chemistry of metals co-precipitation with iron. It tured by conventional filtration media. This problem has been has been well-known for years that a number of metals can addressed by development of flocculating polymers with active be precipitated from solutions by reaction with iron oxides. In sulfide groups. SeleniumZero, the iron oxide is attached to a substrate and the selenium adsorbs to the oxide. Iron oxide co-precipitation also is a technique to remove arsenic, Table 1 – Proposed ELG for FGD Wastewater Best Technology Available  although another method is selecAverage of daily values for a tive ion exchange. Many readers Pollutant Maximum for any 1 day 30 consecutive days shall not exceed are no doubt familiar with ion Arsenic, total (µg/L) 8 6 exchange as part of the process to produce high-purity makeup Mercury, total (ng/L) 242 119 water for steam generators. For Selenium, total (µg/L) 16 10 wastewater and other industrial Nitrite/nitrate (mg/L) 0.17 0.13 water treatment purposes, resin beads can be designed with active sites to remove specific ions. Such resins have been developed for Table 2 – Proposed ELG for Nonchemical Metal Cleaning Wastes Best arsenic. Technology Available  Even though these technologies Average of daily values for a have been successfully demonstratPollutant Maximum for any 1 day 30 consecutive days shall not exceed ed, treatment of wet FGD purge Copper, total (mg/L) 1.0 1.0 streams is still a very complicated process. The discharge also contains Iron, total (mg/L) 1.0 1.0 significant quantities of calcium, magnesium, chloride and sulfate. Zero liquid discharge (ZLD) treatTable 3 – Proposed ELG for Chemical Metal Cleaning Wastes NSPS  ment has not proven to be very successful for these streams. This Average of daily values for a Pollutant Maximum for any 1 day issue is a major reason why dry 30 consecutive days shall not exceed scrubbers have become most popTSS (mg/L) 100.0 30.0 ular for new installations. Oil and grease (mg/L)
Copper, total (mg/L)
REGULATIONS COMPLIANCE Metal cleaning waste streams Table 4 – Proposed ELG for Bottom Ash Transport Water NSPS  The proposed ELG outlines Average of daily values for a new guidelines for metal cleaning Pollutant Maximum for any 1 day 30 consecutive days shall not exceed wastes. The guidelines have been separated into two categories, TSS (mg/L) 100.0 30.0 “nonchemical metal cleaning Oil and grease (mg/L) 20.0 15.0 wastes” and “chemical cleaning metal wastes.” The former is discharge water from plain washing Table 5 – A Once-Common NPDES Example of steam generator components, while the latter obviously refers to Average of daily values for a Pollutant Maximum for any 1 day waste discharge from actual chem30 consecutive days shall not exceed ical cleaning processes. TSS (mg/L) 100.0 30.0 The BAT effluent limitations Oil and grease (mg/L) 20.0 15.0 for nonchemical metal cleaning wastes are shown in Table 2. Free available chlorine (mg/L) 0.5 0.2 The NSPS guidelines for pH (range) 6.0 – 9.0 6.0 – 9.0 chemical cleaning wastes are a bit more detailed, as outlined in Table • Total dissolved solids (TDS) 3. • Sulfate (SO42-) The document goes on to give the following guidelines, • Copper (Cu) detailed in Table 4, for bottom ash transport water. • Phosphorus (primarily as phosphate, PO4) And, the following text includes, “There shall be no dis• Ammonia (NH3) charge of wastewater pollutants from fly ash transport water.” • Quantity of discharge The highly publicized failures of ash storage ponds in recent years, along with increasingly stringent regulations, are moving the remaining coal plants toward dry handling systems.
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Wastewater treatment at combined-cycle plants What about combined-cycle power plants, which obviously burn a much cleaner fuel and do not exhibit the environmental complexity of coal plants? Apart from those plants equipped with air-cooled condensers, the primary constituents of a wastewater stream might consist of some or all of the following. • Cooling tower blowdown (typically represents the largest wastewater stream) • RO reject • Evaporative cooler blowdown • Quenched boiler blowdown • Plant drains In the past, a discharge permit might have looked like the data in Table 5. With regard to new guidelines, on a national level the EPA has proposed limits of 0.2 ppm for chromium and 1.0 ppm for zinc in cooling tower blowdown. However, other parameters are appearing in new state discharge permits, including the following:
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REGULATIONS COMPLIANCE Many of these elements or compounds may be introduced by process conditions. For example, on an increasing basis, treated municipal wastewater is the choice for industrial plant makeup. This water often contains elevated concentrations of ammonia and phosphorus. Copper might be released from copper-alloy heat exchangers. Copper also has been used as a preservative in the wood of cooling towers constructed from that material. Sulfate poses a conundrum because a common method to mitigate calcium carbonate scaling in cooling towers is feed of sulfuric acid (H2SO4) to eliminate bicarbonate alkalinity. Depending on the method of wastewater treatment allowed or available, this issue can range from straightforward to exceedingly complex. Some plants are permitted to discharge spent water to a local municipal wastewater treatment plant, provided the industrial water does not contain excessive concentrations of harmful impurities such as heavy metals. At plants in arid regions of the country, evaporation ponds might serve the purpose. However, these ponds must be permitted and installed in a proper manner. Lined ponds are de rigueur in today’s strident environmental climate. If none of the above options are available, mechanical-thermal evaporation of the waste stream might be the only choice. Accurate determination of influent water chemistry is vital for design and selection of evaporator/crystallizers, as hardness, alkalinity and silica can cause severe scaling. Crystal seeding is often necessary to mitigate scaling. A common seed crystal is
gypsum, which provides a more thermodynamically stable site for precipitation of such minerals as calcium sulfate and silicates. For ammonia and phosphorus removal, a biological process might be the best option. Both chemicals are primary nutrients for microbiological growth, and these properties are used to obvious advantage in a bioreactor or membrane bioreactor. Alternatively with regard to phosphorus, which has been noted exists as phosphate in wastewaters, precipitation in clarifiers or reactors may be a good alternative. Phosphate reacts readily with iron or aluminum and can be reduced to low concentration in a reactor. A problem we encounter with increasing frequency is a limit on the quantity of discharge. In arid locations, but sometimes in other areas also, a limit might be placed on discharge volume, or even at times the minimum cooling tower cycles of concentration (COC) might be mandated. However, as many readers will plainly see, increasing COC to reduce discharge volume increases the concentration of impurities in the water. This has impacts on cooling tower operation and might make wastewater treatment much more complicated. ~
References 1. Federal Register, Vol. 78, No. 110, June 7, 2013, Environmental Protection Agency, 40 CFR Part 423 Effluent Limitations Guidelines and Standards for the Steam Electric Generating Point Source Category; Proposed Rule.
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Brad Buecker serves as a process specialist in the Process Engineering and Permitting group of Kiewit Engineering and Design Company, Lenexa, Kan. The group provides water and wastewater engineering and consulting to the power and chemical industries. Buecker has more than 34 years of experience in, or affiliated with, the power industry, much of it in chemistry, water treatment, air quality control and results engineering positions with City Water, Light & Power in Springfield, Ill., and Kansas City Power & Light Company’s La Cygne, Kan., station. He has a bachelor’s degree in chemistry from Iowa State University, with additional course work in fluid mechanics, energy and materials balances, and advanced inorganic chemistry. You may contact him by emailing email@example.com. Michael McMenus graduated from Missouri University of Science and Technology (Rolla) with a bachelor’s degree in Life Science in 1981. He obtained his master’s degree in Environmental Management from University of Maryland University College in 2010 and has more than 30 years of experience in the environmental management field as a regulator, consultant and industrial facility environmental compliance manager. He is currently the manager of Process Engineering and Permitting for Kiewit Engineering Design Co. You may contact him by emailing firstname.lastname@example.org.
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Sleeping with the fishes By Frank Todd, True North Consulting
Lately, Mrs. Megawatt has been mentioning a faint, highpitched sound coming from somewhere around our shower. I confidently informed her that it is no problem and that she should not worry about it. However that did not stop me from looking under the house and putting my stethoscope to the pipes and wall hunting for telltale signs of something sinister. Sometimes we think everything is O.K. because the real problem is hidden from view. This story is about a power plant that was going along without a care in the world, until some evidence came up that indicated there was a problem no one realized was there. Sitting out on the bluff, Savannah, my faithful golden retriever, and I were enjoying a spectacular sunset over the San Juan range when we were interrupted by a faint jingle from the office indicating an opportunity to provide for our sustenance. It was a well-known entity that always brings a slight uneasiness to my reverie, the Jersey Jungle Power Station. As anticipated, next came those now so familiar words: “Mr. Gangone sends his respects and requests your presence at your earliest convenience.” My fountain pen fell to the table – I was a little surprised since we had recently helped them with a turbine replacement and I hadn’t expected to hear from them again. Apparently once the relationship was established it was difficult to stay under the radar. Jersey Jungle had been humming along nicely since its turbine replacement, until the staff received a call from the syndicate indicating they were coming up short on their end of the Megawatt stick. As I got off the plane, I noticed Brian the Btu Buster sitting in his Miata waiting for me with the requisite black suit and dark glasses. Triple B had been around this roulette table before and he knew how to play the part. As we approached the power station, Brian noticed a big truck pulling up to the river with placard on the side stating “Jersey Jungle Hatchery,” as a young man with a definite tilt to his head greeted us with some amount of fear and trepidation. Giuseppe Varverdi was a new engineer up from the ranks, and the nephew of the Don himself. Giuseppe indicated that Mr. Gangone had very high expectations for our visit and proceeded to describe the problem. Two times a year the syndicate would send Guido out to the power station to determine if they were meeting their quota for supplying the Grid. For the last two visits, Guido was not pleased and Giuseppe’s predecessor had somehow ended up as the chief Waterbox monkey in charge of the fishes for the foreseeable future. Brian and I could feel the tension as Giuseppe spoke. Giuseppe provided the chart in Figure 1 to show us the problem. Gross load had been decreasing during the time period in question. Since this plant operated at a constant thermal input, this was not expected. We asked Giuseppe to plot the condenser inlet temperature along with the Gross Load to see
APRIL 2015 ENERGY-TECH.com
if it was the cause for the change, as shown in Figure 2. Even though the condenser inlet temperature was increasing, it did not look like all the pasta was in the right pot. Brian and I asked for some Historical Plant Data and started working. The process we chose to use was to start with our thermodynamic box around the whole cycle and move the box 20 ENERGY-TECH.com
in around the components. Therefore, the starting point was the condenser cooling water inlet. First we wanted to characterize the relationship between the circulating water inlet temperature and the condenser pressure. This would tell us what condenser pressure was to be expected at a given load over the range of inlet temperatures. Once we had established the condenser expected performance, we would examine the relationship between the condenser pressure and plant output at a constant thermal input. Having all this information would be a first step in diagnosing the problem. Figure 3 shows the curve we developed to characterize the condenser performance. We also could have used vendor curves, but often the as-built performance is different than the theoretical performance provided by the vendor. Figure 4 shows the curve we developed to characterize the turbine performance with respect to condenser pressure. We also could have used the vendor curves here, but they do not always accurately represent actual plant performance with respect to condenser pressure. Using these two relationships, we could then take a look at how the condenser was performing. Figure 5 shows the expected condenser pressure (orange line) and the actual condenser pressure (blue line). It is clear that that the actual condenser pressure started increasing with respect to the expected condenser APRIL 2015
MR. MEGAWATT pressure. This points to some problem with condenser efficiency. her face and water all around her feet. I realized I might end up Based on this graph we thought we were on the right path. But sleeping with the fishes after all. ~ before we did our victory dance, we wanted to know if this discrepancy could explain all the difference in generation and Mr. Megawatt is Frank Todd, manager of Thermal Performance the cause of the problem. Figure 6 shows the plant generation for True North Consulting. True North serves the power industry corrected for the influence of the expected condenser pressure, in the areas of testing, training and plant analysis. Todd’s career, and for the actual condenser pressure. The green line is the difspanning more than 30 years in the power generation industry, has been centered on optimization, efficiency and overall Thermal ference between the two, which is the loss due to the condenser Performance of power generation facilities. You may email him at efficiency problem. email@example.com. Giuseppe was impressed, but we noticed the big guy outside the conference room door was not budging. “So,” Giuseppe said, “yuz told us the ® tomato is bad, but not why the tomato is bad or how we make sauce with the bad tomato. Mr. Gangone, my uncle, would be pleased to know how we fix dis’ problem.” Looking at Brian, I noticed little beads of sweat running down his forehead and knew we had to come up with something TRY quickly. Then I remembered that when I BEFORE was looking at the data I had noticed the YOU BUY! temperature rise across the condenser was a little fishy and I said, “mackerels in the waterbox! 800.536.0790 “Look at this graph (Figure 7),” I continued. “You see the temperature rise across 90° Prism & the condenser is increasing. At a constant • Sharp, Clear Photos & Video Close-Focus thermal input, the condenser temperature • Large 5-inch LCD Monitor tips available! rise should be constant if cooling water flow is not changing. Q = flow x tem• Easy-to-Use Controls perature rise. Since temperature rise is • Annotation Feature increasing and Q is constant, flow must be changing (Figure 8).You told me that your • Rugged Tungsten Sheathing circulating water pumps were just replaced • Quality Construction and are working fine, but something is • Precise 4-Way Articulation changing the flow through the condenser. If it is not the pumps it must be the system • Starting at only $8,995 or the flow area in the tube side condenser. You also told me that the syndicate lost their man on the inside of the EPA and In stock, ready for overnight delivery! they are making you reintroduce mackerels Hawkeye® V2 Video Borescopes are fully portable, to the river.You have waterbox fouling.” finely constructed, and deliver clear, bright high resolution photos and video! The 5” LCD monitor That evening they took a down power, allows comfortable viewing, and intuitive, easy-to-use popped open the water box and started controls provide photo and video capture at the touch CPR on a boat load of mackerels. We sugQuickly inspect cooling tubes of a button! V2’s have a wide, 4-way articulation range, gested that they change the location where inside heat exchangers, turbine and are small, lightweight, and priced starting at only blades, and much more! they were adding the fish to the river and $8995. V2’s are available in both 4 and 6 mm diameters. we set up a monitoring system to identify Optional 90° Prism and Close-Focus adapter tips. future flow problems with the condenser. Made in USA Once again, Brian and I had dodged Visit us at: the cement overshoes and came away with bellies full of pasta and wine. As I pulled into the garage, Mrs. Megawatt was standing there with a decidedly sour look on Booth # 3033 • Orlando, FL May 18 - 21, 2015 gradientlens.com/V2 VIDEO BORESCOPES
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Flexible combined heat and power systems for offshore oil and gas facilities with CO2 bottoming cycles By Marit J. Mazzetti, Yves Ladam, Harald T. Walnum, Brede L. Hagen, Petter Nekså and Geir Skaugen, SINTEF Energy Research, Trondheim, Norway
Improved energy efficiency is the only “fuel” that simultaneously meets economic, energy security and environmental objectives, according to the 2013 IEA report “World Energy Outlook.”  This also is the case for oil and gas production, where it is gaining importance. Particularly as offshore fields are aging, the energy needed to produce a barrel of oil and gas increases significantly. Offshore facilities are normally designed for maximum production (or “plateau”) rates. In many cases, declining production results in increased power demand. One example is water injection in order to maintain reservoir pressure. This is a common energy intensive process, which is often necessary as the platform goes into tail production. Improved energy efficiency will lead to reduced fuel consumption and resulting CO2 emissions and help meet the world’s climate goals, as well as improving offshore process economics by reducing fuel cost and CO2 taxes where applicable. This is the case for Norway, where the government introduced an offshore CO2 tax to accelerate the implementation of CO2 reduction measures. Offshore oil and gas platforms are in most cases generated by gas turbines operating in a simple cycle. However, on three offshore installations on the Norwegian continental shelf (NCS) a steam bottoming cycle has been installed that recovers the heat from the hot exhaust of the gas turbine, increasing the efficiency of the electricity production on the platform . Alternative concepts for more compact bottoming cycles saving weight and footprint on the platform have been discussed by Walnum et al. . Those cycles are based on the use of CO2 as working fluid. Lately, supercritical CO2 cycles have received
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attention, especially for nuclear applications. [2,3,5] The main reason is the potential for weight, size and cost reduction. These characteristics also are transferable to bottoming cycles for gas turbines . For most oil and gas production platforms, part of the heat from the gas turbines is recovered for use in the energy intensive onboard oil/water separation process, among others. Depending on the plant layout, compressor driver concepts and power production strategy, a waste heat recovery unit (WHRU) might be Figure 1. Layout of the two concepts for combined needed on multiple gas heat and power (CHP) production. Upper: Dual waste heat recovery unit (DWHRU). Lower: The turbines. The ratio of heat to power demand internal heat recovery unit (IHRU). will typically vary and heat recovery systems are needed that can combine heat integration and power production (CHP) across a wide range of operating conditions. For steam systems this is typically performed with steam extraction or backpressure turbines, where steam is extracted at an intermediate pressure and utilized for process heat. For CO2 systems this is not an option, since the CO2 is typically expanded in a single-stage turbine and far away from the two-phase boundary. In this work, several concepts for CHP will be evaluated at different operating conditions. The concepts are modeled using in-house tools, enabling the use of detailed component models taking real off-design effects into account. This is necessary due to the large load
ASME Power Division Special Section | APRIL 2015
ASME FEATURE changes, enabling operation of the cycles with power production only and all the way to pure heat production. The work will extend the investigation presented previously, and present alternative system layouts to combine power production from a CO2 bottoming cycle with heat generation.
Alternative layout and boundary conditions Two options were investigated for heat production integrated with a CO2 bottoming cycle, as shown in Figure 1. The first layout simply uses a secondary WHRU after the bottoming cycle WHRU. The mass flow of CO2 is controlled to make sure that the necessary heat is available for the secondary WHRU. It will be referred to as the dual waste heat recovery unit (DWHRU). The second layout exploits the large amount of super-heat available at the CO2 turbine outlet to produce process heat. It will be referred to as the internal heat recovery unit (IHRU). Two locations are considered: 1. Northern climate: For this location, cold cooling water (10°C is available) and the CO2 bottoming cycle is able to condense at sub-critical temperature (31°C). This is the standard Rankine cycle layout. A pump (at point “g” in) is used to compress the liquid CO2 before waste heat recovery. 2. Southern climate: The cooling water temperature is higher (25°C) and the CO2 remains in the gas phase all along the cycle. The CO2 is compressed (at point “g”
Figure 2. Produced power vs. produced heat
ASME Power Division: Combined-Cycle Committee
A Message from the Chair The ASME Power Division Committee for CombinedCycles is a group of industry professionals who meet to discuss technology improvements, performance enhancements, design, operation and maintenance of power plants operating in a combined-cycle mode. In most cases, this refers to a gas turbine connected to a heat recovery steam generator and steam turbine for additional power generation, but not always – as can be seen in the ASME feature article in this issue. The use of CO2 as a bottoming cycle fluid is just one example of some of the new concepts being discussed within the Combined-Cycle Committee and at the ASME Power Conference every year. In addition to new combined-cycle concepts, the conference sessions supervised by the combined-cycle committee include presentations on new gas turbine technologies, performance considerations and O&M issues. Each year our committee brings together a panel of experts to discuss pertinent issues for combined-cycle power plants. In recent years, there has been significant interest on facility start cycles – both from a reliability standpoint and a schedule optimization standpoint. This year we are still researching the topic and searching for members to be on our panel of experts. If you’d like to be involved, we would welcome your input. Our committee generally meets twice a year, with the main meeting held at the ASME Power Conference (www.asmeconferences.org/powerenergy2015). Attendance at the meeting is not required; we typically have dial-in and internet connections for members who aren’t able to join us. But if you do attend the ASME Power Conference, be sure to join our track – which this year includes a tutorial on Combined-Cycle Plant Performance Monitoring. We look forward to seeing you there! Tina L. Toburen, P.E. Chair – ASME Power Division; Combined Cycle Committee President - T2E3 Inc. Phone: 425-821-6036 Email: firstname.lastname@example.org
Figure 3. CO2 mass flow rate vs. produced heat APRIL 2015 | ASME Power Division Special Section
ASME FEATURE Runge Kutta routine) and iteration on the wall temperature profile (with DNSQE from SLATEC). Relevant heat transfer and pressure drop correlations are obtained from the literature, see Table 1. More details on the heat exchanger framework can be found in Skaugen et al.
Waste heat recovery unit (WHRU) The WHRU is modeled as a cross-flow finned tube heat exchanger with serrated fins. The tube passes are arranged in horizontal serpentines inside a rectangular vertical gas duct, approaching a counter flow configuration. The WHRU is designed for a 3 kPa pressure drop on the exhaust side. Figure 4. Pressure ratio vs. produced heat
Figure 5. Expander efficiency vs. produced heat
in) before the waste heat recovery unit. This is called the Brayton cycle.
Models and methodology The main purpose of this study is to investigate how the two proposed layouts for a combined heat and power bottoming cycle manage varying load ratio between process heat production and power production. Realistic off-design evaluation is needed, which imposes advanced geometry-based component models (as opposed to performance-based models that cannot provide off design information). Gas turbine model The gas turbine performance was calculated separately with GT Master from Thermoflow Inc. The chosen model is a GE LM2500+G4 with the dry low emission (DLE) setup. Compressor and turbine maps relating corrected inlet air mass flow to compressor pressure ratio and efficiency were utilized. The gas turbine is supposed to run at 100 percent load for all power/heat ratios for the bottoming cycles. Heat exchanger models An in-house framework is used to model the heat exchangers. The models use geometrical input data to calculate parameters such as hydraulic diameters, perimeters and cross sectional areas for each fluid pass. Based on the geometry specification and the fluid inlet conditions, the outlet conditions are found through integration of the fluid passes (with a 4th order 24 ENERGY-TECH.com
Condenser The condenser is modeled as a plate heat exchanger. The high condensing pressure of CO2 (55–60 bar) makes it unsuitable for standard plate-and-frame configurations. However plate-and-shell configurations could be an option. In this work, the performance characteristics of the heat exchanger at off-design conditions are of the most interest, and this will be relatively independent of the type of heat exchanger. The condenser is assumed to be cooled with sea water. At the design point, the cooling water flow rate is set to give a 10°C increase in cooling water temperature, and this flow rate is kept constant also at off-design conditions. Recuperators and process heat generator (d in) for the IHRU The recuperator model is based on stacked layers of multiport tubes with counter-current flow, and is meant to represent a generic compact heat exchanger. Due to the high operating pressure (200 bar), diffusion bonded printed circuit heat exchangers might be the most relevant solution currently available. Pump and turbine for the bottoming cycle The pump is modeled with constant isentropic efficiencies defined as follows:
The efficiencies are set to 80 percent throughout the load range studied. It is assumed that the pump is equipped with variable frequency drive (VFD). The turbines are calculated using the inlet guide vanes (VIGV) model. An efficiency ηDP of 85 percent was assumed at design. Off design performance was evaluated using manufacturer efficiency charts. The efficiency factor as function of volume flow ratio R (to design volume flow) is obtained from Atlas Copco: Equation 2
ASME Power Division Special Section | APRIL 2015
ASME FEATURE The efficiency factor as a function of tip velocity ratio (to design tip velocity) is obtained from:
The turbine efficiency was then calculated as product of the design point efficiency and the two efficiency coefficients and is used in the iterative cycle calculations:
rate and high pressure are therefore considered free variables and are optimized during simulation.
Results and discussion The produced power is shown as a function of produced heat for the different cases in Figure 2. As expected, the power output is in general higher for the Northern case compared to the Southern. This is due to the lower cooling water temperature and the higher exhaust mass flow. For the dual WHRU system, the power output is not affected by the heat production up to 5 MW, since this heat
Calculation procedure The design of the bottoming cycle model was performed in Aspen HYSYS  to enable simple modifications and tuning of the processes. The design case is based on 10 MW heat production. The design point parameters shown in Table 2 were used to define the HYSYS model. Then advanced geometry-based models were designed for individual components using the in-house code to match the HYSYS model. The advanced model will allow for realistic off-design calculations. Stationary solutions for the whole bottoming cycle are solved using a sequential quadratic programming (SQP) method (NLPQL). More details about the calculation procedure can be found in reference . For off-design simulation, a control strategy must be chosen for the bottoming cycle. The condensation pressure could, to some degree, be controlled by the flow of cooling water, but in these simulations it was decided to keep the cooling water flow constant for the DWHRU system. For the northern conditions, where the system operates in trans-critical mode, the condensation pressure will be controlled by the heat rejected in the condenser. For the IHRU system the cooling water flow rate is variable in order to obtain necessary control flexibility. For the southern conditions, when the system is operating fully in supercritical mode, pressures are controlled by mass repartition between the low- and high-pressure sides. The mass flow and pump outlet pressure is controlled by the turbine and pump operation. The VFD of the CO2 pump/compressor enables a high efficiency in a wide range of flow rates and pressure ratios. The VIGV allows the turbine to operate with constant pressure ratios across a broad flow range. The mass flow APRIL 2015 | ASME Power Division Special Section
ASME FEATURE Table 1 – Heat Transfer and Pressure Drop Correlations WHRU
Fin side heat transfer
Fin side pressure drop
Tube side heat transfer
Tube side pressure drop
Condenser Single phase heat transfer
Condensing heat transfer
Single phase pressure drop
Condensing pressure drop
Recuperator and IHRU Single phase heat transfer
Single phase pressure drop
Table 2 – Bottoming Cycle Process and Component Design Point Parameters Component
WHRU (exhaust/CO2) UA [kW/K]
WHRU (exhaust/hot fluid) UA [kw/K]
Recuperator UA [kw/K]
Process heat generator (CO2/hot fluid) UA [kw/K]
Max pump/compressor outlet pressure [bar] Pump/compressor efficiency [%] Expander efficiency [%] Motor/generator efficiency [%]
Nomenclature P R T h s v η
Pressure (Pa) Volume flow ratio (-) Temperature (K) Specific enthalpy (J/ kg) Specific entrophy (J/kg K) Tip speed velocity ratio (-) Efficiency (-)
DP Design point in Inlet out Outlet
is available anyway. If the heat demand is increased further, the power output drops relatively steadily. For the IHRU system, there is a significant power drop from 0-5 MW heat production. This is mainly due to the control strategy applied. The mass flow and pressure levels are controlled to heat the hot fluid to 170°C. For moderate process heat production, the mass flow of CO2 is not optimized for power production. The mass flow is increased to lower the CO2 temperature at the turbine inlet such that hot fluid is produced at 170°C. It would be beneficial to produce the hot fluid at a higher temperature so that the CO2 mass flow is optimized for power production. The hot fluid could then be reduced to the desired temperature by mixing. For heat production between 15 and 20-25 MW, the IHRU system performs equally or better than the dual WHRU system. For the Northern case, the power from the IHRU system drops quite drastically for heat production above 20 MW. To make more heat available for the hot water, the work extracted from the expander must be reduced. This is done by reducing the pressure ratio. The pressure ratio was decreased by reducing the heat uptake pressure (as condensing pressure is controlled by heat exchange with the cooling water). The high pressure is an important parameter for cycle efficiency. For the Southern case, operating as a Brayton cycle, the power production reduction is less drastic. Here the low pressure is free to increase, resulting in a reduced pressure ratio without decreasing the high pressure as much. The 10 MW heat production case is used as the design case. The resulting expander efficiency is shown in Figure 5. The expander efficiency is relatively constant for all cases, except for the IHRU system at the highest heat production case. The low efficiencies experienced here indicate that the operating conditions are outside the range of the expander.
Conclusions Compact CO2 cycles could be an interesting alternative for additional power generation on platforms equipped with gas f 80 turbines . c 85 On many installations, both power and process heat has to be 95 provided from the fuel burned in the gas turbines. A bottoming cycle added to increase power production would have to be controlled such that the heat demand also is satisfied. The ratio of power to heat demand is expected to vary during operation, which adds complexity to the operation of the bottoming cycle. Advanced models able to provide realistic off design calculations for two bottoming cycles have been implemented. The calculations have shown that both proposed CO2 processes are able to produce both heat and power, both in Northern and Southern climates in a wide range of power to heat demand ratios. Initial evaluations indicate that the expanders are able to operate in a large range of conditions and are able to handle large variations in the ratio of power to process heat demand. f
Acknowledgments This publication forms a part of the EFFORT project, performed under the strategic Norwegian research program PETROMAKS. The authors acknowledge the partners
ASME Power Division Special Section | APRIL 2015
ASME FEATURE Statoil, Total E&P Norway, Shell Technology Norway, Petrobras and the Research Council of Norway (203310/S60) for its support. ~
14. Selander, W. N., 1978, “Explicit Formulas for the Computation of Friction Factors in Turbulent Pipe Flow,” No. AECL-6354, Chalk River Nuclear Laboratories, Chalk River, Ontario CANADA. 15. Martin, H., 1996, “A theoretical approach to predict the performance of chevron-type plate heat exchangers,” Chemical Engineering and Processing, 35(4), pp. 301-310. 16. Han, D.-H., Lee, K.-J., and Kim,Y.-H., 2003, “The Characteristics of Condensation in Brazed Plate Heat Exchangers with Different Chevron Angles,” J. Korean Phys. Soc, 43(1), pp. 66-73.
References 3. International Energy Agency, 2013, “World Energy Outlook 2013.” 4. Vanner, R., 2005, “Energy Use in Offshore Oil and Gas Production: Trends and Drivers from 1975 to 2025,” Policy Studies Institute (PSI), London, United Kingdom. 5. Kloster, P., “Energy Optimization on Offshore Installations with Emphasis on Offshore Combined Cycle Plants,” Proc. Offshore Europe Oil and Gas Exhibition and Conference. 6. Walnum, H. T., Nekså, P., Nord, L. O., and Andresen, T., 2013, “Modelling and simulation of CO2 (carbon dioxide) bottoming cycles for offshore oil and gas installations at design and off design conditions,” Energy 59, pp. 513-520. Zeeco’s 35-year history of combustion and 7. Johnson, G. A., McDowell, M. W., environmental successes makes us the O’Connor, G. M., Sonwane, C. breath of fresh air you need to convert G., and Subbaraman, G., 2012, power plants from coal-fired to natural “Supercritical CO2 cycle development at gas, or add low or ultra-low NOx gas-fired Pratt & Whitney Rocketdyne,” ASME capability to meet the latest emissions and Turbo Expo, ASME, Copenhagen, efficiency targets. In a combined cycle facility, Denmark. ZEECO® low-NOx duct burners also assist in 8. Kimball, K. J., and Clementoni, E. meeting clean-air standards. M., 2012, “Supercritical carbon dioxide brayton power cycle development It’s time for a fresh look at the company and overview,” ASME Turbo Expo, ASME, technology that will keep power and steam Copenhagen, Denmark. generating clean energy for years to come. 9. Thermoflow, 2011, “GT MASTER 21.0.” Global experience. 10. 1993, “SLATEC - Common Local expertise. Mathematical Library,” Netlib Repository, U. T. Computer Science Dept, ZEECO Low NOx Duct Burner and O. R. N. Laboratory, eds. 11. Skaugen, G., Kolsaker, K., Walnum, H. T., and Wilhelmsen, Ø., 2013, “A Flexible and Robust Modelling Framework for Multi-Stream Heat ® Exchangers,” Computers & Chemical Engineering, 49, pp. 95-104. 12. Næss, E., 2007, “An Experimental Study of Heat Transfer and Pressure Drop in Serrated-Fin Tube Bundles and The ZEECO GB Low NOx power burner fires a variety of gas or Experience the Power of Zeeco. Investigation of Particulate Fouling in liquid fuels and supports multi-fuel applications without major combustion control or burner management system modifications. Waste Heat Recovery Heat Exchangers,” Dr.Ing, NTNU, Trondheim, Norway. 13. Gnielinski, V., 1976, “New Equations Zeeco, Inc. Boiler Burners • Duct Burners 22151 E 91st St. for Heat and Mass Transfer in Turbulent Broken Arrow, OK 74014 USA Burner Management • Combustion Control Pipe and Channel Flow,” 16(April), pp. +1 918 258 8551 Ignition Systems • Turnkey Solutions email@example.com 359-368.
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ASME FEATURE 17. Marcuccilli, F., 2006, “Kalina & Organic Rankine Cycles: How to Choose the Best Expansion Turbine?,” ENGINE Workshop 5: Electricity generation from Enhanced Geothermal Systems. Strasbourg (France). 18. Atlas Copco, 2012, “Driving Expander Technology,” Atlas Copco Gas and Process Solutions(B03/004/24/0512). 19. GE, 2012, “Turboexpander-Generators. Company catalogue. http://site.ge-energy.com/businesses/ge_oilandgas/en/ literature/en/downloads/turbo_generators.pdf.” 20. Aspen Technology Inc., 2010, “Aspen HYSYS v7.2.” 21. Schittkowski, K., 1986, “NLPQL: A fortran subroutine solving constrained nonlinear programming problems,” Annals of Operations Research, 5(1), pp. 485-500. 22. Meitner, P. L., and Glassman, A. J., 1980, “Off-Design Performance Loss Model for Radial Turbines With Pivoting, Variable-Area Stators,” Cleveland, Ohio. Editor’s Note: This paper, PWR2014-32169, was printed with permission from ASME and was edited from its original format. To purchase this paper in its original format or find more information, visit the ASME Digital Store at www.asme.org. Dr. Marit Jagtøyen Mazzetti is a research scientist and project manager with SINTEF Energy Research, Dept. of Energy Efficiency Education. She has a Ph.D. in Materials Science and Engineering from the University of Kentucky and a M.Sc. (Siv.ing) in Chemical Engineering,
Norwegian Institute of Technology (NTH). You may contact her by emailing firstname.lastname@example.org. Dr. Petter Nekså is Chief Research Scientist at SINTEF Energy Research and an adjunct professor at NTNU, Dep. of Energy and Process Engineering He received his Ph.D. in Mechanical Engineering from the Norwegian Institute of Technology (NTH) and an MS degree in Refrigeration Engineering/ Mechanical Engineering also from the Norwegian Institute of Technology (NTH). You may contact him by emailing email@example.com. Brede A. L. Hagen is a research scientist with SINTEF Energy Research. She received her MS degree in Applied Physics and Mathematics with specialization in Applied Physics at the Norwegian University of Science and Technology. You may contact her by emailing firstname.lastname@example.org. Geir Skaugen is a research scientist at SINTEF Energy Research. He received his MS degree from the Norwegian University of Science of Technology and holds a Ph.D from the same university. You may contact him by emailing email@example.com. Yves Ladam is a scientist at SINTEF Energy Research and received his Ph.D. and MS degree in Physics from the University of Grenoble, France. You may contact him by emailing firstname.lastname@example.org. Harald Taxt Walnum is an M.Sc. HVAC at Sweco Norge AS and received his MS degree in Mechanical engineering at the Norwegian University of Science and Technology. You may contact him by emailing email@example.com.
ASME Power Division Special Section | APRIL 2015
Call For Presentation-Only Abstracts! Deadline: May 12, 2015
JUNE 28-JULY 2, 2015 SAN DIEGO CONVENTION CENTER | SAN DIEGO, CALIFORNIA | GO.ASME.ORG/POWERENERGY
ENERGY SOLUTIONS FOR A SUSTAINABLE FUTURE In 2015, four of ASME's major conferences come together to create an event of major impact for the Power and Energy sectors: ASME Power & Energy 2015. Fossil and nuclear power generation, solar, wind, fuel cell applications and much more will be discussed in each of the four concurrent conferences within this larger event.
The ASME Power Conference delivers the very latest power engineering solutions in plant operations, maintenance and construction with cuttingedge technology.
The ASME Conference on Energy Sustainability is the world class exchange of innovative technology and R&D efforts that offer a path to renewable solutions.
The ASME Fuel Cell Conference offers the very latest technology research and solutions for fuel cells.
The ASME Nuclear Forum presents the most recent developments in the Nuclear Power industry.
Call For Presentation-Only Abstracts!
Demonstrate your involvement in this critical industry by submitting your presentation-only abstract (for oral or poster presentation) to a track within the events above. In addition, we welcome case studies and real world applications/ best practices. ASME’s Power & Energy event is the can’t miss event in 2015.
Visit go.asme.org/powerenergy for full track listings and submission details. Presentation-only abstracts are due May 12, 2015!
SPONSORSHIP & EXHIBITION OPPORTUNITIES ARE LIMITED, SO ACT NOW! GO.ASME.ORG/POWERENERGY About ASME For more than 100 years, ASME has successfully enhanced performance and safety for the energy and piping industries worldwide through its renowned codes and standards, conformity-assessment programs, training courses, journals, and conferences – including the Offshore Technology Conference (OTC), the International Conference on Ocean, Offshore and Arctic Engineering (OMAE), the International Pipeline Conference (IPC), and Turbo Expo.
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Guidelines to achieve successful gas turbine part refurbishment By Stephen R. Reid, P.E., TG Advisers Inc.
Gas turbine hot-section hardware requires part refurbishment after a specified number of operating hours, unit stop-start cycles, or a combination of the two. The repair processes required to achieve an additional interval of service present significant challenges. The variability in incoming part condition, process variation and the human element are key factors to understand and monitor in order to achieve successful part refurbishment.
Key gas turbine repair processes: • Inspection • Coating removal • Joining • Machining • Coating application Failure mechanisms for hot-section hardware include oxidation, creep, cracking and dimensional distortion. It is vital that incoming inspections be robust to properly define repair scope and identify unrepairable hardware from the onset. For most hardware, it is expected that coatings will be depleted or spalled after a service interval. Traditionally, ceramic coatings are removed through an abrasive grit blast and metallic bond coats are removed through acid stripping. Common issues encountered are excessive base metal removal, inter-granular acid attack and incomplete removal. Cracking from thermal mechanical fatigue is often present during refurbishment. This repair has become increasingly challenging with the widespread use of nickel-based superalloys across the industry. The joining processes most commonly performed for crack repair are welding and brazing. Some factors impacting the quality are joining material selection, surface cleanliness, proper process
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Figure 1. Sample gas turbine Stage 1 blade prior to repair; photo courtesy of “Gas Turbine Journal”
inputs and part pre-heat, and pre- and post-process heat treatments. Material build-up and machining, such as tip or hardface repair on rotating blades, is often required during part refurbishment. With part creep and distortion it becomes increasingly difficult to achieve desired dimensional results. It is important that fixturing and machining processes are robust and have the ability to adapt to the often significant variation in part condition. Thermal spray processes are utilized to reapply coating systems to hardware. Most hardware receives coating prior to final machining during initial manufacturing. The presence of such features as cooling holes and seal slots makes recoating more challenging than the initial application. Part geometry, pre-heat temperature, surface cleanliness and roughness, gas and powder properties, and coating gun condition are some of the factors that influence coating quality.
Recommended guidelines to improve repair quality The following steps are recommended to improve the quality of part refurbishment.
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TURBINE TECH Get engaged • Develop comprehensive repair specification • Review non-conformances • Define hold points • Review part progress Steps to achieving the desired repair results start well before the hardware arrives at the shop. Develop a comprehensive repair specification for your hardware that captures lessons learned Figure 2. Sample gas turbine tip repair; photo courFigure 3. Gas turbine coating process; photo courtesy of tesy of Industrial Laser Solutions Sulzer from previous repair experiences and available industry knowledge. As part of Post repair documentation review and visual the specification, agree to review points inspection at key steps of the repair. This provides an opportunity • Work scope completed for the hardware owner and shop personnel to discuss • Dimensional inspection non-conformances or deviations from the specification. If • Blade moment weights possible, visit the shop and audit the part repair process. • Flow area and harmonics • Visual inspection Integrate important quality checks in repair • Non-destructive testing After repairs are complete, review the hardware and • Destructive testing material samples quality documentation for discrepancies. Understand the • Coating strip – acid scope of work completed and verify key dimensions are • Coating application within tolerance. Audit measurement results and look for • Flow checks and pressure checks outliers in the data. Examples of important measurements • Coating thickness checks • Cooling hole blockage checks Inspection is a vital component of repair. Integrating in-process inspections into repair helps ensure the desired end results are achieved. On high risk or high variability Gaumer has industry leading knowledge in processes, such as coating removal and fuel gas conditioning including electric heater, reapplication, material samples can be processed along with the hardware. This filter/coalescer and control panel design. allows for destructive analysis of the proGaumer engineers will work with your cess without sacrificing a piece of valuunique operating conditions to provide able hardware. If additional verification a complete, successful solution. is warranted, a part can be destructively evaluated. Call today for: Ensure cooling air and fuel flow sys• Fuel Gas Conditioning tems have not been compromised. Flow, • Fuel Gas Heaters pressure and blockage checks are critical • Fuel Gas Filters at this stage of the repair. Request and review documentation of the results of these important checks.
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TURBINE TECH and visually inspect each part before use. This step is often omitted with significant consequences. Investing the appropriate time in the repair of your parts can go a long way in ensuring successful part refurbishment and the ability to achieve the maintenance intervals you desire. ~ Stephen R. Reid, P.E., is president of TG Advisers Inc. and has more than 30 years of turbine and rotating machinery Figure 4. Stage 1 stationary nozzle, post repair; photo courtesy of “Gas Turbine Journal” experience. Reid and his team provide turbine troubleshooting, health assessments and are area, harmonics and the moment weight of blades. expert witness services to major energy companies in the U.S. Always perform a final visual inspection of the hardware. and have provided condition assessment evaluations on more than 100 turbine generators in the U.S. Reid also is a short course instructor for EPRI, ASME, Electric Power and POWERGEN, has Going forward numerous patent disclosures and awards, and published more Get engaged in the refurbishment of your hardware! than 20 technical papers and articles. Reid was the recipient of the 1993 ASME George Westinghouse Silver Medal Award for his This begins with development of the repair specification. contributions to the power industry and is past chairman of the Clearly define your quality requirements and agree to ASME Power Generation Operations Committee. He is a registered review points during the repair. Review and audit post-re- professional engineer in the state of Delaware. You may contact pair documents for non-conformances. Finally and most him by emailing email@example.com.
importantly, carefully remove the parts from the crates
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Online Training: Cooling Water Solutions for Power Plant Professionals By Brad Buecker, Kiewit Power Engineers and Raymond M. Post, P.E., ChemTreat Inc.
Brad Buecker, Kiewit Power Engineers
This webinar course is designed for power plant and other industry professionals responsible for new cooling water technology, including use of gray water, high-efficiency cooling towers and zero-liquid discharge. Each session will be recorded on video, so if you have to miss a live session, you’ll have access to the recording on the following day. Register by April 14 to take advantage of all discounts. (Call 563-5883853 for group rates.)
Course Description During the heyday of large power plant construction in the last century, once-through cooling was the choice at many plants. However, concerns about the impact of oncethrough cooling on the health of aquatic creatures have virtually eliminated this technique for new plants. Raymond M. Post, P.E., The choice becomes a cooling ChemTreat Inc. tower or air-cooled condenser. Many project developers and owners are selecting cooling towers, which exposes plant personnel to new chemistries and technologies that are significantly more complex than once-through cooling. This two-part webinar course will examine cooling tower fundamentals, including basic design details and heat transfer, followed by discussion of chemistry and water treatment issues. Many water-related factors are influencing cooling tower design and operation. Dates and Tuition Two 2-hour sessions will be held per day Tuesday and Wednesday, April 28 and 29. Each 2-hour sessions will begin promptly at 10 a.m. Pacific Time, which is 11 a.m. Mountain Time, noon Central Time and 1 p.m. Eastern Time. Early Bird Price: $299 when purchased by April 14 ($359 value). Call Randy at 563-588-3853 for group rates. Class Format This two-part webinar series consists of two 2-hour sessions that take place on Tuesday and Wednesday, April 28 and 29. Each registrant will be provided with electronic copies of course materials prior to the online course. APRIL 2015
Each class will include lecture and Q & A utilizing the GoToWebinar.com platform. A quiet room and a reliable Internet connection are required to take this course. See GoToWebinar.com for technical requirements. Certificates of completion will be provided to all attendees after the last class session. The class will be recorded so if you have to miss the live session you’ll have easy access to the information.
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