July 2014 by Energy-Tech Magazine

Contractor Training 13 • ASME: Gas Turbine Dual Injection 15 • Compressor Vibration 20

ENERGY-TECH

JULY 2014

A WoodwardBizMedia Publication

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Dedicated to the Engineering, Operations & Maintenance of Electric Power Plants In Association with the ASME Power Division

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FEAtUrEs

By Diane Closser, CLS MLT I, Energy-Tech contributor

Editorial views expressed within do not necessarily reflect those of Energy-Tech magazine or WoodwardBizMedia. Advertising Sales Executives Tim Koehler – tkoehler@WoodwardBizMedia.com Joan Gross – jgross@WoodwardBizMedia.com

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Maintenance Matters

Does your labor partner power its people? Three key questions to ask about contractor training programs By Guy Starr, DZ Atlantic

Machine Doctor

Reciprocating compressor pulsation vibration analysis By Patrick J. Smith, Energy-Tech contributor

AsME FEAtUrE

Creative/Production Manager Hobie Wood – hwood@WoodwardBizMedia.com Graphic Artist Valerie Vorwald – vvorwald@WoodwardBizMedia.com Address Correction Postmaster: Send address correction to: Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Subscription Information Energy-Tech is mailed free to all qualified requesters. To subscribe, go to www.energy-tech.com or contact Linda Flannery at circulation@WoodwardBizMedia.com Media Information For media kits, contact Energy-Tech at 800.977.0474, www.energy-tech.com or sales@WoodwardBizMedia.com. Editorial Submission Send press releases to: Editorial Dept., Energy-Tech, P.O. Box 388, Dubuque, IA 52004-0388 Ph 563.588.3857 • Fax 563.588.3848 email: editorial@WoodwardBizMedia.com. Advertising Submission Send advertising submissions to: Energy-Tech, 801 Bluff Street, Dubuque, Iowa 52001 E-mail: ETart@WoodwardBizMedia.com.

Gas by day, electricity by night: 4kV electric heater enables on-demand fuel switching, balances electric load demand By Gaurav Dhingra and Jeff McClanahan, Gaumer Process

Group Publisher Karen Ruden – kruden@WoodwardBizMedia.com General Manager Randy Rodgers – randy.rodgers@woodwardbizmedia.com Managing Editor Andrea Hauser – ahauser@WoodwardBizMedia.com Editorial Board (editorial@WoodwardBizMedia.com) Kris Brandt – Rockwell Automation Bill Moore – Director, Technical Service, National Electric Coil Ram Madugula – Executive Vice President, Power Engineers Collaborative, LLC Kuda Mutama – Engineering Manager, TS Power Plant

New alternatives for oil changes

Dual injection distributed combustion for stationary gas turbine application By Ahmed E.E. Khalil and Ashwani K. Gupta, University of Maryland

iNdUstry NotEs

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Editor’s Note and Calendar Advertisers’ Index Energy Showcase

oN tHE WEB Energy-Tech University is presenting a new webinar series, Steam and Gas Turbine Troubleshooting, with Steve Reid, P.E., president of TG Advisers Inc. The webinar will consist of two, 6-hour online courses, the first held Aug. 6-8 and the second Aug. 13-15, 2014. Go to www.energy-tech.com/turbines for more information. Cover photo contributed by Luneta.

July 2014

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Editor’s Note

Summer school for the pros Don’t think you don’t have time to learn something new If you have school-age children, or grandchildren, it’s likely you are entering the second month of summer break, characterized by Popsicle sticks stuck to the patio, s’mores supplies needing to be restocked with every grocery trip and the distinctive smell of chlorine throughout your home. The biggest challenge at my house during summer break is preventing the ‘summer slide,’ a.k.a the tendency to forget everything they learned during the school year. It’s hard to take time for another math fact sheet on multiplication when everybody else is going to the pool. I try to empathize – it’s hard to find time to learn as an adult too, even though I know it’s important to keep my skills sharp and stay relevant in my industry. Maybe you struggle with this learning hurdle too – which is why Energy-Tech has several options to help you stay schooled this summer. The first one, coming up quickly, is the ASME Power conference, which is just two weeks away as you’re reading this, July 28-31, in Baltimore, Md. There’s still time to register – just visit www.asme.org/power2014 to get started. And if you’re going, please stop and visit us in Booth #202. We love to meet Energy-Tech readers. The second is Energy-Tech University’s upcoming technical course, Steam and Gas Turbine Troubleshooting, which will be offered as an online webinar, Aug. 6-8 and Aug. 13-15. It will be presented by Steve Reid, president of TG Advisers Inc., and attendees can choose from one of the courses or both. This was one of the most popular sessions at Energy-Tech University this past March and we’re excited to offer it again in this format.Visit www.energy-tech.com/turbines to learn more. Finally, Energy-Tech University will be offering additional onehour webinars throughout the rest of the year, covering topics including predictive maintenance, pumps and condensers. These are great, short sessions packed with applicable information. If you haven’t attended one yet, you definitely should. If you would like to download a free webinar recording, visit www.energy-tech.com. The best way to learn about all of these events is to make sure you’re receiving Energy-Tech emails – so check your spam folder and approve our messages.Your inbox won’t be filled with junk, just information you can use. I hope we see you at one or more of the events listed above. In the meantime, thanks for reading.

CALENDAR July 21-25, 2014 Rotor Dynamics and Modeling Syria, Va. www.vi-institute.org July 28-31, 2014 ASME 2014 Power Conference Baltimore, Md. www.asmeconferences.org/power2014 Aug. 6-8 & 13-15, 2014 Energy-Tech University: Steam and Gas Turbine Troubleshooting Presented by Steve Reid, P.E., TG Advisers Inc. www.energy-tech.com/turbines Aug. 19-21, 2014 Power Plant Pollutant Control “MEGA” Symposium Baltimore, Md. www.megasymposium.org/wps/ Aug. 19-22, 2014 Balancing of Rotating Machinery Houston, Texas www.vi-institute.org Sept. 16-19, 2014 Machinery Vibration Analysis Salem, Mass. www.vi-institute.org Nov. 3-4, 2014 CCGT 2014: O&M and Lifecycle Management for CCGT Power Plants Houston, Texas www.tacook.com/ccgt-usa Nov. 11-14, 2014 Advanced Vibration Control Syria, Va. www.vi-institute.org

Submit your events by emailing editorial@woodwardbizmedia.com.

Andrea Hauser

ENERGY-TECH.com

July 2014

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July 28-31, 2014 Baltimore, Maryland

2014 Pre-Conference Workshops Turbines and Generators Sunday, July 27 – Monday, July 28

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Heat Rate Assessment: “Looking for the ‘Small Stuff’ to Optimize Plant Performance?”

For complete workshop descriptions, technical tracks and registration, go to:

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Monday, July 28 • 1:00pm- 5:00pm Heat rate best practices to optimize power plant efficiency and fuel cost reduction. Provide training to optimize equipment and system efficiencies. Advanced Pattern Recognition technology will be presented for integration with the thermal performance application for detecting and resolving anomalies that may result in catastrophic equipment failure and/or increased fuel costs.

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FEATURES

New alternatives for oil changes By Diane Closser, CLS MLT I, Energy-Tech contributor

In a perfect world, lubricants would not degrade. There would be no ingress of contaminants, excellent storage and handling procedures would be common, and every employee who came in contact with oil or grease would be trained and certified to do their jobs. Unfortunately, I often find the opposite to be true. With a high number of knowledgeable employees retiring, new replacements are often at a disadvantage due to lack of training and lack of a history with the equipment that is now their responsibility. Some plants know how old their turbine oil is and what is actually in Figure 1. Flushing rig set up to clean the system. the reservoir, others do not. Some have excellent sampling and testing programs in place, others do not. Because of this, a market has opened up for products to help eliminate the consequences of an undereducated workforce. I recently attended one of the best lubrication conferences of the year. The presenters were forward thinkers, leaders in their field. Many new products were introduced, and one in particular was a more cost-effective alternative for flushing turbine oil systems. It eliminated approximately 92 hours and $100,000 in flushing a 3,000 gallon boiler feedwater pump that contained old and highly degraded turbine oil. With everyone being focused on getting the units up and running in the shortest amount of time, this is a valuable new product. The following case study was written and presented at the conference by Greg Livingstone of Fluitec. Again, this is a new solution when a plant decides their oil needs to be changed. A coal-fired power plant had two 3,000-gallon boiler feedwater pumps with very old and highly degraded turbine oil. They elected to try two different services to clean up their systems. Below is an overview of both services.

Flushing of Boiler Feedwater Pump 1 The services were outsourced to a professional flushing company, which performed the services during a planned outage. The following procedures were followed: 6

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1. At the beginning of the outage, the lube system was drained and disposed. 2. Restrictive flow areas and critical components were isolated from the flush with the creation of specialized jumper hoses. 3. Confined space tank cleaning was done on the reservoir. 4. A water solution with a citrus cleaner was added to the system. 5. An external pump and bag filters were used to generate very high flow rates. 6. At the conclusion of the chemical flush, the water was removed from the system and from draining and evaporation. 7. The oil system was charged with new oil. 8. A high velocity, high temperature oil flush was performed to remove any other contaminants from the system. • Total time for the flush: 2.5 weeks • Estimated hours required to support the flush during the outage: 100 hours • Total cost for the flush: $150,000 • Effectiveness of the flush: All varnish and contaminants were removed from the system. The flush was considered a success.

July 2014

FEATURES

Figures 2a and 2b: The filters cleaned up significantly along with other system components during the flush.

Flushing of Boiler Feedwater Pump 2 For the second system, the plant performed a Solubility Enhancement System Cleaning by following these procedures: 1. A 5 percent Solubility Enhancing Agent was added to the system three months prior to the outage. 2. A suitable chemical filtration system (ESP technology) was set up to continually clean the fluid and restore its ability to dissolve contaminants. 3. During the outage, the used oil was drained from the reservoir and from all low points in the system. 4. The system was then recharged with new oil.

• Total time for the system cleaning: 3 months • Estimated hours required to support the flush: 8 hours • Total cost for the flush: $50,000 • Effectiveness of the flush: All varnish and deposits were removed from the system. The flush was considered a success.

Feedwater pump case study summary The plant was equally satisfied with the outcome of both flushes. Other concerns about residual cleaning agent leftover in the turbine oil also were eliminated.

July 2014 ENERGY-TECH.com

FEATURES cleanliness levels are defined, and time, money, manpower, etc., are spent to achieve these levels of in-service lubricant cleanliness. The last thing you want to do is contaminate it with “dirty” new oils. Quality control of lubricants delivered from lube suppliers must be verified to ensure the correct product is being delivered and that the cleanliness of the delivered lubricant are up to current target particle and moisture cleanliness levels. To help ensure your lubricants are meeting their standards, the use of oil analysis is a powerful tool and will reveal the following: • Quality of base stocks • Additive quality and concentration • Lubricant performance properties • Thickener performance properties (grease)

Figure 3. Condition monitoring pod

Early detection of machine faults and abnormal wear is key for machine reliability. Another new product was introduced at this conference called the CMP, which stands for the Condition Monitoring Pod (Figure 3) by Luneta. The CMP enables daily inspections across numerous critical parameters and delivers a huge benefit compared to less frequent condition monitoring activities. Imagine the power of having immediate feedback on the health of critical assets whenever you want. Once the CMP is installed, the plant can quickly view oil levels, oil color (wrong oil, oil oxidation, etc.), detect surface foam and entrained air, inspect for wear debris, sediment and sludge, test for water contamination, detect corrosion and varnish, and much more. The CMP features a built-in sample port (with a pilot tube) and offers quick access to a variety of field lubricant tests. The condition monitoring pod (CMP) does not simply act like a level gauge, but also contains a magnetic plug, corrosion gauge and other functionalities all in one. A basic three-day lubrication course will help new employees understand how critical proper lubrication practices are. The students can learn why it is important to keep contaminants out of the reservoirs and what proper testing means to keep the machines running. Once a team has been educated, the next step is to look at receipt inspection and storage and handling. What can we do to ensure we received the lubricant we ordered? Is it clean and dry? Improper receiving techniques do nothing but promote higher risks of contamination ingression, mixing of lubricants, etc. Proper written receiving procedures should be in place to ensure the highest level of consistency and cleanliness is maintained. Proper receiving techniques should include filtration of incoming oils. Many times new oils might be dirtier than the defined particle target cleanliness level. If particle target 8

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Once we are sure we have the lubricants we ordered, we need to store them in the proper way. Lubricant storage is an area where many plants struggle. They fail to see the real value added in developing a proper lube room to store all new and in-use lubricants, as well as lubrication-related tools like filter carts and grease guns. Proper storage techniques always should start by designing a proper storage facility. Among other things, the facility should include: proper air handling to regulate temperature and moisture, adequate fire-proof cabinets for accessory storage, work space for filling top-up containers or grease guns, designated filter cart storage areas for each oil type, new and in-use storage space for all lubricants, and a small desk and filing cabinet to track lubricant usages and inventories. Ideally, the lube room is the nucleus of reliability in the plant. This is where the reliability of a rotating component can be strengthened, or the life of a component reduced. Most people don’t realize, or conveniently overlook, the importance of a well-designed and well-maintained lubrication storage room. Once the storage and handling has been successful, true lubrication engineering can begin to take place. This might involve direct or indirect participation in mechanical design, lubrication economics, lubricant formulation or application recommendations of all forms of lubricant in all types of equipment, machines, tools or products with the objectives of obtaining optimum conditions with regard to wear, friction, power, corrosion, leakage, vibration or other operating characteristics influenced by the lubricant. ~ Diane Closser is an independent solutions provider with more than 20 years of experience solving industrial lubricant and polymer related issues. She has developed and implemented lubrication and commercial grade dedication programs, established and managed fluids analysis laboratories, and written and instructed numerous lubrication and FT-IR courses for a multitude of industries. Closser is a polymer chemist and STLE Certified Lubrication Specialist. She is owner of Closser Lubrication Services Inc. You may contact her by e-mailing editorial@woodwardbizmedia.com.

July 2014

FEATURES

Gas by day, electricity by night: 4kV electric heater enables on-demand fuel switching, balances electric load demand By Gaurav Dhingra and Jeff McClanahan, Gaumer Process

For generations, U.S. manufacturing has been powered, quite literally, by fossil fuel. Natural gas, oil and coal have historically run the workhorses of American industry – the heaters and boilers that process raw materials into usable products for a range of businesses, including oil and gas companies, chemical manufacturers, food processors, pulp and paper manufacturers, and petroleum refiners. Not surprisingly, these powerhouses have big appetites: 83 percent of all industrial boilers are fueled by natural gas and they eat up an astonishing amount of energy. In fact, when researchers at the Massachusetts Institute of Technology (MIT) calculated how much natural gas industrial boilers in the U.S. consumed each year, the figure came in at about 2.1 trillion cubic feet (Tcf). And that study was done in 2006, before surging domestic shale gas production triggered an American manufacturing renaissance that has undoubtedly increased the use of natural gas for industrial activities. As energy-intensive as gas-fired boilers are, they’re often equally emission-intensive. In particular, they produce carbon dioxide and nitrogen oxide, two pollutants that are coming under increasingly stringent regulation by the Environmental Protection Agency (EPA) as part of the White House’s ambitious climate change agenda. Natural gas boilers also waste energy – the U.S. Department of Energy (DOE) estimates that up to 50 percent of industrial energy input is lost in the form of exhaust gases, cooling water and heat loss from product heating. But now, with the successful introduction of the world’s first 4kV heater, industry has the power to change its energy source on demand.

The 4kV process heater: an emission-free, efficient alternative Like its natural gas counterparts, electric heaters are used for a variety of industrial and commercial processes, including producing hot water or steam and vaporizing liquid to gas. But that’s where many of the similarities end. Electric heaters are emission-free at the point of use and boast nearly 100 percent thermal efficiency. They are more efficient in converting process fluid to vapor compared to conventional fossil fuel fired equipment, and there’s no stack loss – no wasted heat, unburned fuel or excess air escaping up the flue stack.

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There’s a financial incentive to using electric heaters, as well, particularly during utilities’ off-peak hours, when lower energy demand means electricity rates can drop to as low as one-third of the day-time pricing. For industrial customers, switching from natural gas during the day to an electric heating application during those highly discounted evening and nighttime periods can generate significant operational savings – not only over peak electricity rates, but even compared to natural gas prices. And by increasing demand for off-peak power, electric utilities win too: When more large customers are using electric heaters during shoulder and nighttime periods, power companies can better balance the electric load, sell surplus energy that would otherwise be wasted, and – by running at higher capacity – keep their equipment working more efficiently. “The benefits of dual-fuel heating capabilities, that is, using one fuel during the day and switching to an alternative source when prices go down, are evident for anyone who uses a lot of power,” said Jeff McClanahan, president of Houston’s Gaumer Process, a leading designer and manufacturer of electric process heaters and engineered systems. Until recently, however, the large current requirements of electric resistance heaters – which usually operate at normal building distribution voltage (480V) – meant that they were not commercially practical for very large loads. However, because many large process industries have medium- to high-voltage connections accessible at their service entrances, the possibility existed for operating larger MW process heating equipment at higher voltages. This advance would enable on-demand fuel switching from natural gas to electricity-based on fuel cost. The introduction of the world’s first 4kV heater has made that possibility a reality. Industry now has the power to automatically dispatch equipment based on energy prices. In addition, utility companies have a new customer source to help keep their daily load profile stable.

Material improvement at a textile mill With two natural gas boilers and a fuel oil boiler for back up, a textile mill in the southeastern U.S. faced concerns about process energy costs, the risk of natural gas curtailments cutting off its supply and the emissions and safety of its back-up boiler. In other words, it was considered the perfect field demonstration site for the world’s first fully commercialized 4kV heat-

July 2014

FEATURES er by the team that conceptualized and manufactured the equipment, including Atlanta-based Southern Company, an electricity producer with 4.4 million customers; the Electric Power Research Institute (EPRI); boiler manufacturer CleaverBrooks; and Gaumer Process, which patented the 4kV and has operated a 4kV heater since 2007. Installation of the 4kV heaters was completed in December 2010. They have proven to be nearly 100 percent efficient at converting fuel to steam, compared to 80 percent efficiency of the Figure 1. natural gas boilers. In addition, the 4kV has enabled cost-effective fuel switching and allowed the company to scrap its higher emissions fuel oil boiler and associated fuel storage costs. The mill’s owners can negotiate for lower gas prices, eliminate any contracted “firm” gas needs, and are now less concerned about the reliability of their natural gas supply. The 4kV heaters can be equipped with Energy Decision Management System (EDMS) automation which was designed by Georgia Power (a Southern Company subsidiary) and Stonewater Control Systems Inc. EDMS allows for the automatic dispatch of equipment based on hourly price and usage forecast, and helps facility planners tie energy usage back to environmental goals. The 4kV’s success at the textile manufacturer validated the approach from the both the customer and utility’s standpoint, said Ed Harmon of Georgia Power. “By allowing the manufacturer to automatically dispatch their boilers 24 hours a day based on fuel pricing, electric heaters provide a clear advantage,” Harmon said.

In addition to enabling on-demand fuel switching, EPRI said that the benefits of 4kV technology also include: • High efficiency: Efficiency of converting electricity to heat utilizing resistance heating approaches 100 percent.

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High-voltage benefits Now readily available to industrial and commercial customers, the 4kV fills the gap in the industry for a 1-20 MW range medium voltage electric heater with resistance elements up to 4160V.

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FEATURES • No emissions or pollution: This is particularly important in a non-attainment area. • Better working conditions: This is due to electric heating that is inherently noiseless and clean. • More precise temperature control: The 4kV’s new control system allows temperature uniformity with +/- 1°F. • Greater operational flexibility: Electric boilers are a more efficient standby source with very fast startup. Alternative fuel storage and associated costs can be eliminated. Figure 2.

• Reduced infrastructure and cleaner design: A 1 MW 4kV heater has three wires, compared to dozens of wires and a transformer for a 600V electric heater. Reduced energy losses due to lower current flow are significant during the life cycle of the equipment.

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Payback in one year Although the cost breakeven point for a 4kV electric heater is both site- and application-specific, it can be less than one year, McClanahan said. But additional savings also accrue because of the emission-free characteristics of electric heater technology. McClanahan cited the American Council for an EnergyEfficient Economy (ACEEE), which highlighted the 4kV installation at the textile mill as a case study for its 2013 Summer Study on Energy Efficiency in Industry. The ACEEE noted that because electric heaters are emission-free by design, users don’t have to install the expensive CO2, NOX, or SOX scrubbing equipment required for natural gas heating applications. McClanahan sees the market for the 4kV as robust and growing. Electricity providers are spreading the word, and more and more industrial customers are coming on board. In fact, Gaumer Process recently completed a power plant 4kV installation and will deliver 10 MW of 4kV heaters for a U.S. LNG export terminal later in 2014. With cost and emissions savings for industry and a way for utilities to sell more off-peak electricity, it should be full steam ahead for the 4kV. ~ Gaurav Dhingra is the vice president of Engineered Systems at Gaumer Process, www.gaumer.com. He has a bachelor’s degree from the Thapar Institute of Engineering & Technology. You may contact him by emailing editorial@woodwardbizmedia.com. Jeff McClanahan is the president of Gaumer Process, www.gaumer.com. He has a bachelor’s degree from The University of Texas at Austin. You may contact him by emailing editorial@woodwardbizmedia.com.

Dedicated to the Engineering, Operations & Maintenance of Electric Power Plants

July 2014

MAINTENANCE MATTERS

Does your labor partner power its people? Three key questions to ask about contractor training programs By Guy Starr, DZ Atlantic

The looming mass retirement of thousands of baby boomers has been a critical concern for the power industry for most of the past decade. In that time, industry groups and associations have tracked and published workforce trends in hopes of raising awareness to prevent what could become a full-blown crisis if left unaddressed. Recently, there have been signs of progress. Studies from 2013 from the Nuclear Energy Institute (NEI) and the Center for Energy Workforce Development show the number of energy industry workers under age 37 has steadily increased during the past five years. Even with modest improvements, the competition for talent, specifically skilled labor, will be fierce during the next few years. The NEI estimates that as soon as 2015, the energy industry will have to replace 100,000 skilled workers, 25,000 in nuclear power. That means the best and most highly-skilled workers will have their choice of projects and employers. Power plants have always relied on outside partners and contractors to fill talent gaps. These partners have long been judged on their deep networks and experience in effectively and efficiently staffing projects. But as the labor pool continues to shrink and worker options grow, past performance will not be the only thing that leads to future results. Contractors must prove that in addition to relying on established pipelines, they are capable of effectively training and retaining new workers. To put it another way, they must prove that they are helping build careers for craft people, not just finding them isolated jobs. There are three key training questions that energy producers must begin to ask those partners to ensure they are embracing this new mindset.

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MAINTENANCE MATTERS Is their training transferrable? Nuclear plants in particular have always struggled to verify the abilities of supplemental skilled workers. In many cases, the only way for plants to have confidence in their performance was to train them on-site using their own qualification programs. While this approach led to positive final outcomes, it also frequently resulted in repetitive training for workers that moved from plant to plant. Workers knew that regardless of experience, they would be re-trained on each new site. This system was frustrating for the worker and inefficient for the plant. During the past few years, the industry has pushed for standardized tests and certifications that will ensure quality supplemental workers. Leading partners and contractors will have training programs that meet certain standards, such as the Electric Power Research Institute’s Applied Portable Practical Protocol (AP3), and receive training accreditation from organizations such as the National Center for Construction Education and Research. Still others will go a step further by establishing their own qualification programs. Standards such as these give workers portable skills. While some level of on-site training might still be needed, these certifications should reduce the cost and time burden. In the fight to attract and retain skilled labor, portable training also is a key competitive advantage. It incentivizes individuals to seek out contractors that offer this training and keeps them at the top of mind for supplemental workers. In the end, it provides more value to utilities as they increase efficiency and performance. Is their training mobile? Mobile supplemental workforces have long been the norm for work on plant outages. But as the current market continues to drive up wages, the savings realized by using local skilled workers is significant. Plants must find partners that have a proven track record of working with utilities to identify, train and mobilize local talent. Many within the industry are working to establish partnerships and programs with colleges, universities and technical schools. Previous experience establishing and building these types of programs will set leading contractors apart. Hands-on programs that provide certifications will feed into local projects. By developing a direct line from schools to working opportunities, contractors using these strategies will build loyalty and familiarity with workers growing their network for work on other sites. In the absence of education partnerships, the ability to test and evaluate existing local talent via web-based training modules also is critical. Just as workers move from plant to plant, training programs should be able to move as well. Hiring local workers with transferable skills cuts down on

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per diem costs for utilities and builds them a labor pool for future projects.

Is their training accelerated? In a wide range of surveys, “opportunity for career advancement” ranks high on the list of concerns for millennial employees. This is advantageous for the power industry since it is particularly well-equipped to cater to those desires. But to be successful in doing so, contractors must be able to identify and accelerate the growth of young top performers. Successful programs combine formal classroom training with field work. Exposing young workers to a variety of different job sites and projects accelerates the learning process and facilitates innovation and creative problem-solving. In addition to the formal structure of an accelerated program, contractors should also demonstrate a commitment to a mentorship culture. Having established workers that can pass on knowledge to a younger generation of workers is the best way to ensure long-term sustainability. For utilities, the value comes from knowing that long-term alliance partnerships will be just as valuable three years from now as they are today. Conclusion As Dave Delong, author of the forthcoming book, “Closing the Skills Gap: Innovative Talent Management Solutions for a Changing Workforce,” recently wrote in the Harvard Business Review, industries dealing with a skills gap find themselves in one of four scenarios: those who know they will be affected and understand the critical skills that need to be replaced; those who know they will be affected by an aging workforce but don’t know which skills will be affected; those who face skill gaps unrelated to the aging workforce and those who aren’t sure if an aging workforce is a problem, or if they face any looming skills gaps. Fortunately, the energy industry is firmly in the first category and has already taken significant steps to address the issue. But as the reality of time works against the best efforts to find new workers, there will likely be more pronounced differences between contractors that have industry leading talent and those that simply have warm bodies. Asking these pointed questions of potential partners will ensure that plants and utilities work with those that are truly powering and empowering their people for the future. ~ Guy Starr is president of the DZ Atlantic business unit, part of the company’s Engineering, Construction and Maintenance (ECM) group. Starr has more than 30 years of management and operations experience in the engineering and field services business, with a career spanning multiple service lines and industries. You may contact him by emailing editorial@woodwardbizmedia.com.

July 2014

ASME FEATURE

Dual injection distributed combustion for stationary gas turbine application By Ahmed E.E. Khalil and Ashwani K. Gupta, University of Maryland, College Park

The quest for clean and sustainable energy, along with energy security and independence, has motivated researchers to develop advanced energy conversion systems that can furnish the current and future energy needs with minimal impact on the environment using local energy sources. Natural gas appears to be one of the most viable options due to its abundance in its natural form, or as shale gas. Novel combustion techniques for achieving near zero emission of NOX, CO, unburned hydrocarbons and soot from gas-fired combustion turbines remain of great importance due to even more stringent emission regulations. The thermal field uniformity in gas turbine combustors is important since it causes local burn Figures 1a and 1b. Photograph of the high intensity CDC combustor (Left: Combustor with optical access, out of combustors and turbines, creating more Right: axial product gas exit). downtimes and increased pollutants emission. Colorless distributed combustion (CDC), which shares some of the principles of high temperature air combustion (HiTAC) [1], has demonstrated ultra-low emission of NO and CO, and improved pattern factor (enhanced thermal field uniformity in the entire combustor volume) [2-6]. Reduced noise and stable combustion also have been shown under CDC conditions for gas turbine combustion. The flames in distributed combustion do not show any visible flame signature, and so are termed colorless due to negligible visible emission from the flames. Among the critical requirements for seeking distributed reactions are controlled and rapid mixing between fresh reactants and hot recirculated reactive species from within the combustor. Proper mixture preparation and input operational condition can allow one to look for distributed reaction across the entire volume of the combustor. Conventional combustors have a thin reaction zone, characterized by high reaction rates with local hot spots. Distributed combustion mitigates the formation of a thin reaction zone and hot-spot regions in the flame to Figure 2. Colorless combustion with dual air/fuel injection. mitigate thermal (Zeldovich) NOX emission [1,7]. Different mixing schemes and recirculation zone generation The amounts of entrainment must be controlled to increase methods explored to enhance flame characteristics include the temperature of the reactant mixture to a level high enough swirlers and bluff body [8-10], and tangential air [11]. The role of for auto-ignition of the fuel. The uniformly mixed fuel/air/hot swirling air injection into the combustor on distributed comactive gases then spontaneously ignite, resulting in a distributed bustion reactions was explored, with simultaneous jet entrainreaction regime instead of a thin reaction zone [4-6]. Ultra-low [4] ment of product gases from within the combustor . NO and CO emission has been demonstrated from a swirling

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ASME Power Division Special Section | July 2014

ASME FEATURE

Figure 3. NO and CO emissions for single injection case.

Figure 4. OH* Chemiluminescence intensity for single injection case.

CDC combustor [4,5]. Swirling CDC has been investigated using different fuel introduction scenarios [6] and fuels [12-14], with ultra-low emissions for each case. Previous investigations examined single injection in the form of an air/fuel premixed injector or separate air and fuel injectors for non-premixed combustion. A lab scale test combustor was used at a heat load of 6.25 kW. A contemporary stationary gas turbine combustor can release 48,000 kW of energy, which indicates a scaling factor of thousands. Different approaches for scaling are discussed in the literature [15]. The scaling techniques include constant velocity injection (CV), residence time (CRT), thermal intensity [16] or use of Coleâ&#x20AC;&#x2122;s approach [17]. The choice is dictated by the importance of desired output parameters. The CV approach leads to an increase in mixing time and significant decrease in thermal intensity, whereas the CRT approach results in high pressure drop across the combustor from high velocity [18,19].

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Multiple air and fuel injection into a combustor requires further examination for distributed reaction combustion. Fuel and air staging has been used to control pollutants emission. The stages are generally located close to or farther from each other, to produce or eliminate flameto-flame interaction, since reaction zone is known to be affected by the following or preceding reaction zone. Evaluating the behavior of multiple air and fuel injectors, and whether they form one large reaction zone or multiple small reaction zones, is critical. Multiple injection behavior is investigated using a lab scale combustor modified to allow for multiple injectors (one or more). The two injector configuration (herein called dual injection) is expected to reveal the key attributes of using such an injection scheme compared to single air and fuel injection. The air/fuel injection velocity was kept constant in all the experiments. NO and CO emissions are recorded, along with OH* chemiluminescence intensity to seek the reaction distribution behavior in the combustor under different operational conditions. Figure 1 shows a photograph of the experimental test facility. Further description of the combustor also is available [5]. Inlet air temperature to the combustor was preheated to 600K to simulate gas turbine operational conditions. Air preheats affect combustion kinetics and pollutants emission. Generally, high air preheats increase the flame temperature, increase NOX emission and decrease CO emission [5]. Figure 2 shows the combustor operating under dual-injection mode, where colorless (no visible emission) combustion is obtained. Direct comparison of the results for single- and dual-injection, including the case of varied fuel distribution between injectors in the dual-injection case is now presented. In the figures, ATP indicates single-injection mode and ATP-D indicates dual-injection. Emissions of NO and CO for the single-injection case are presented in Figure 3. NO emissions decreased with the

ASME Power Division Special Section | July 2014

ASME FEATURE decrease in equivalence ratio (Φ), while CO decreased to a minimum and then increased again. Emissions of 5 PPM NO and 10 PPM CO at Φ=0.6 are demonstrated. The OH* chemiluminescence intensity distribution showed that the reaction zone is in the shape of a crescent, see Figure 4. The reaction intensity decreased and moved farther downstream with a decrease in Φ. This can be attributed to the lower flame speed at the lean conditions, making it hard for the flame to stabilize and move the reaction zone farther downstream. Experiments also were Figure 5. NO emissions for single and dual injection cases. conducted using two air/ fuel injectors at opposite sides of the combustors. Dual injection is expected to result in lower NO emissions from more distribution of the reaction across the combustor. Results showed higher NO emissions with dual injection (see Figure 5), which might be initially counter-intuitive. This is due Figure 6. OH* chemiluminescence intensity for dual injection case. to the flame-to-flame interaction. If the air/fuel mixThe fuel distribution between the two injectors also was ture from the first injection does not completely burn before examined. The change in fuel distribution changes the local Φ the second injection location, the colder fresh reactants might of each jet (while maintaining constant global Φ), leading to interrupt the reaction to result in higher local Φ and to create a change in the local flame characteristics. Figure 7 shows the local hot spots. It is therefore important to distribute the reacNO emissions at Φ=0.6 with defined fuel distribution. The tion (for distributed reaction combustion) instead of creating results reveal that careful distribution of fuel between injectors a localized area with a higher reaction rate that contributes to can decrease emissions to levels lower than those achieved with higher thermal NO emission. single injection. This is important for scaling-up the combustor, The cause of high NO emissions was identified using OH* since single injection can pose difficulties in large size combuschemiluminescence from identification of reaction zone behavtors. ior. The OH* chemiluminescence intensity results shown in The OH* chemiluminescence intensity distribution with Figure 7 showed that the reaction zones created from each different fuel distributions is shown in Figure 8. Also, 45 perinjector are not equal. The second reaction zone (on the right cent of the overall fuel introduced at the first injector resulted of the combustor) has higher intensity than the first reaction in higher intensity at the second reaction zone (at the right of zone. This indicates that air and fuel injected from the first jet the combustor) compared to the first reaction zone (on the (on the left) reacts, and with the introduction of fresh reactants left of the combustor). Increased fuel injection from the first from the second jet (to the right), the reaction rate dramatically injector caused an increase in first reaction zone intensity and a decreases. Now as the mixture starts to react again, Φ does not decrease in the second reaction zone intensity. At about 55 perstay uniform, leading to a somewhat concentrated reaction and cent of the fuel through the first injector, the reaction zones are higher reaction rate, as seen from the higher OH* chemilumialmost identical. An additional increase in the fuel injected from nescence, shown in Figure 6 (second reaction zone). injector one resulted in an increase in the first reaction zone

July 2014 | ASME Power Division Special Section

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ASME FEATURE

Figure 7. NO emissions for fuel distribution variation dual-injection cases.

Figure 8. OH* chemiluminescence intensity for dual-injection fuel distribution variation cases.

intensity, and a decrease in the second reaction zone intensity. Relating this behavior to Figure 7 reveals similar behavior between NO emission and reaction zone intensity. Minimum emission of NO corresponds to the case where OH* intensity in both reaction zones were similar.

Conclusions Results obtained with single injection of air and fuel demonstrated ultra-low emissions. Dual injection showed higher emissions than single injection. For the same Φ, NO emission increased by 20 percent, with minimal change in CO emission.

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The OH* chemiluminescence showed the presence of unequal reaction intensity distribution, with one reaction region stronger than the other. This results in a local increase in temperature (hot spots) to contribute to local thermal NOX formation. Slightly increasing the fuel amount in the first jet (about 55 percent of total fuel) provided decreased NO emission compared to even fuel distribution between the two injectors. At this condition, the emissions were lower than NO emission with single injection at the same equivalence ratio. OH* Chemiluminescence intensity distribution showed that 55 percent of the fuel injected from the first injector resulted in equal intensity of the two reaction zones. The importance of reaction distribution and the need to eliminate any concentrated reaction zone forming local hot spots has a direct impact on pollutants emission. Fuel distribution and mixture preparation can be used to control flame characteristics to produce favorable performance and lower emissions. ~

References 1. Tsuji, H., Gupta, A.K., Hasegawa, T., Katsuki, M., Kishimoto, K., and Morita, M., 2003, High temperature air combustion: from energy conservation to pollution reduction, CRC Press, Bocaraton, Florida. 2. Arghode, V.K., and Gupta, A.K., 2010, “Effect of Flowfield for Colorless Distributed Combustion (CDC) for Gas Turbine Combustion”, Applied Energy, 78, pp.1631-1640. 3. Arghode, V.K., and Gupta, A.K., 2010, “Investigation of Forward Flow Distributed Combustion for Gas Turbine application”, Applied Energy, 88, pp.29-40. 4. Khalil, A.E.E., and Gupta, A.K., 2011, “Swirling Distributed Combustion For Clean Energy Conversion In

ASME Power Division Special Section | July 2014

ASME FEATURE Gas Turbine Applications”, Applied Energy, 88, pp.36853693. 5. Khalil, A.E.E., and Gupta, A.K., 2011, “Distributed Swirl Combustion For Gas Turbine Application”, Applied Energy, 88, pp.4898-4907. 6. Khalil, A.E.E., Gupta, A.K., Bryden, K.M., and Lee, S.C., 2012, “Mixture Preparation Effects on Distributed Combustion for Gas Turbine Applications”, J. Energy Resour. Technol., 134(3), 032201. 7. Correa, S.M., 1992, “A Review of NOX Formation Under Gas-Turbine Combustion Conditions”, Combustion Science and Technology, 87, pp.329-362. 8. Gupta, A.K., Lilley, D., and Syred, N., 1984, Swirl Flows, Abacus Press, Tunbridge Wells, England. 9. Archer, S., and Gupta, A.K., 2004, “Effect of Swirl on Flow Dynamics in Unconfined and Confined Gaseous Fuel Flames”, 42nd AIAA Aerospace Sciences Meeting and Exhibit 5 - 8 January 2004, Reno, Nevada 10. Leuckel, I.W., and Fricker, N., 1976, “The Characteristics of Swirl-Stabilized Natural Gas Flames”, J. Inst. Fuel, 49, pp.103-112. 11. Yetter, R.A., Glassman, I., and Gabler, H.C., 2000, “Asymmetric Whirl Combustion: A New Low NOX Approach”, Proceedings of the Combustion Institute, 28, pp.1265–1272. 12. Khalil, A.E.E., Arghode, V.K., Gupta, A.K., and Lee, S.C., 2012, “Low calorific value fuelled distributed combustion with swirl for gas turbine applications”, Applied Energy, 98, pp.69-78. 13. Khalil, A.E.E., and Gupta, A.K., 2013, “Hydrogen Addition Effects On High Intensity Distributed Combustion”, Applied Energy, 104, pp.71-78. 14. Khalil, A.E.E., and Gupta, A.K., 2012, “Fuel Flexible Distributed Combustion for Gas Turbine Engines”, Proc. 48th AIAA/ASME/SAE/ASEE Joint Propulsion Conference & Exhibit, 30th July-1st August, Atlanta, Georgia, USA, DOI:10.2514/6.2012-4033. 15. Arghode, V.K., 2011, “Development of Colorless Distributed Combustion For Gas Turbine Application”, Ph.D. thesis, University of Maryland, College Park, MD. 16. Kumar, S., Paul, P.J., and Mukunda, H.S., 2005, “Investigations of the scaling criteria for a mild combustion burner”, Proc. of the Combust. Inst., 30, pp.2613-2621. 17. Cole, J.A., Parr, T.P., Widmer, N.C., Wilson, K.J., Schadow, K.C., and Seeker, W.R., 2000, “Scaling Criteria For The Development Of An Acoustically Stabilized Dump Combustor”, Proc. of the Combust. Inst., 28, pp.12971304. 18. Bobba, M.K., 2007, “Flame Stabilization and Mixing Characteristics in a Stagnation Point reverse Flow Combustor”, PhD Dissertation, Georgia Institute of Technology.

19. Khalil, A.E.E., Gupta, A.K., 2013, “Flowfield Effects on Distributed Combustion for Clean Gas Turbines”, Proc. 51st Aerospace Sciences Meeting (ASM), January 7-10, Grapevine, Texas, USA, DOI:10.2514/6.2013-874. Dr. Ahmed Khalil is a research associate at the Combustion Laboratory, University of Maryland, College Park. He received his bachelor’s degree and master’s degree from the Faculty of Engineering, Cairo University in 2007 and 2009. In 2009, he joined the combustion laboratory at the University of Maryland, where he received his Ph.D. in 2013. At Maryland, Khalil concentrated his research on developing new combustion concepts for gas turbines that deliver ultra-low emissions while maintaining high efficiency. He has authored 14 journal papers and 19 peer reviewed conference papers. Khalil was awarded the ASME Melville medal in 2013 for one of his publications. He is an active member of the ASME and AIAA. His research interests include combustion, turbulence, power generation, emissions, renewable fuels and energy sustainability. You may contact him by emailing editorial@woodwardbizmedia.com. Ashwani Gupta is Distinguished University Professor at the University of Maryland College Park. He obtained his Ph.D. from the University of Sheffield, UK. He was awarded Higher doctorate (D.Sc.) from the University of Sheffield and also from the University of Southampton, UK, and honorary doctorate from the University of Wisconsin Milwaukee. His research interests include: combustion in furnaces, gas turbines and micro-engines, advanced diagnostics, air pollution, high speed propulsion, sprays, gasification, waste to energy and high temperature air combustion. You may contact him by emailing editorial@woodwardbizmedia.com.

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MACHINE DOCTOR

Reciprocating compressor pulsation vibration analysis By Patrick J. Smith, Energy-Tech contributor

Pressure pulsations, mechanical resonance and cylinder stretch are some of the common causes of high vibration in reciprocating compressors. If something in the compressor system is changed that affects these dynamic forces, a vibration problem can arise where there wasnâ&#x20AC;&#x2122;t a problem before. When a compressor system is designed, a pulsation analysis is typically done in order to incorporate the appropriate pulsation suppression devices. Changes in operating conditions, gas composition, capacity control, compressor speed, etc., can impact this. Higher pressure pulsations can cause increased vibration levels on the compressor or in the piping system, and can lead to mechan- Figure 1 ical failures, instrument failures and other problems. All components or assembly of components in the reciprocation compressor system â&#x20AC;&#x201C; including the compressor cylinders, pulsation bottles, piping and coolers â&#x20AC;&#x201C; have natural frequencies that can be excited by various shaking forces. These dynamic forces can be caused by mass unbalance, misalignment, pulsations, cylinder stretch and other mechanisms. A natural frequency is the frequency at which the component or group of components want to vibrate. A resonance condition exists if the frequency of the shaking force corresponds to a natural frequency of a component or assembly of components. If a resonant condition exists, a small force can cause high vibrations. Cylinder stretch is the elongation of a cylinder assembly due to the dynamic internal gas pressure forces acting on the cylinder. These differential forces vary as a function of crank angle, operating conditions, cylinder loading and other factors. So something that changes the cylinder pressure profile will affect the dynamic cylinder stretch, which can change the frequency and magnitude of the applied forces, which can again cause higher vibrations.

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When mechanical failures occur in the field, it is sometimes necessary to measure pressure pulsations and vibrations in order to determine the cause and corrective action. The purpose of this article is to present a case study of a pulsation/vibration field test that was done to address a problem with high vibrations that was identified after the capacity control system was modified.

Compressor configuration This case study pertains to a 6-throw, balanced-opposed reciprocating compressor. The drive train consists of a 12,000 HP, 360 RPM synchronous motor directly coupled to the compressor. The compressor crankcase and motor are mounted on a concrete foundation. The compressor cylinders are all double-acting. This is a multi-service compressor which includes a single feed gas compressor stage consisting of two cylinders, a single medium pressure hydrogen compressor (MP H2) stage consisting of two cylinders and a single high pressure hydrogen compressor (HP H2) stage consisting of two cylinders. A picture of the compressor is shown in Figure 1.

July 2014

MACHINE DOCTOR

Figure 2

Capacity control system Reciprocating compressors are fixed capacity machines. In these compressors a fixed volume of gas is drawn into a cylinder through suction valves. A piston is used to reduce the volume in the cylinder, which increases the pressure to line pressure. Gas is then discharged through discharge valves. In most applications, the compressor flow must be controlled to match the required process flow. If the compressor capacity is greater than the available process flow, the suction pressure will decrease. At the same time, if the compressor capacity is greater than the required process flow, the discharge pressure will increase. To control these pressures, it is necessary to incorporate some type of capacity control system. The compressor that is the subject of this article was originally fitted with step capacity unloading and recycle valves for each service. The step unloading system consisted of suction valve unloaders which could unload the head end of each cylinder and reduce the capacity of the cylinder by 50 percent. The cylinders also were fitted with fixed head end clearance pocket unloaders, which added clearance volume and could reduce the cylinder capacity of each cylinder by something between 50 percent and 100 percent. Therefore, this system could be used to reduce the compressor capacity in fixed steps. Discharge to suction recycle valves were used to control the compressor capacity in-between these fixed steps for each service. Each service (feed gas, MP H2 and HP H2) also could be controlled separately. History The compressor was commissioned and put into continuous service. Even though the step capacity unloading system

reduced compressor power when operating at reduced process flows, there was still some gas that was recycled, and this resulted in some wasted compressor power. Two years after the compressor was • commissioned, the step capacity control • • SELL • RENT• LEASE system was replaced • - 24 / 7 with an infinite step • EMERGENCY SERVICE • unloading system. With this system, just • • the required amount • of gas is compressed • and there is no wast- • • IMMEDIATE DELIVERY ed power. This sys• tem utilizes suction • 10HP TO 250,000#/hr valve unloaders that 250,000#/hr Nebraska 750 psig 750 TTF • 150,000#/hr Nebraska 1025 psig 900 TTF delay the closing of • 150,000#/hr Nebraska 750 psig 750 TTF 150,000#/hr Nebraska 350 psig the suction valves on • 115,000#/hr Nebraska 350 psig 80,000#/hr Nebraska 750 psig • 75,000#/hr Nebraska 350 psig each stroke so that 60,000#/hr Nebraska 350 psig • 40,000#/hr Nebraska 350 psig only the required • 10-1000HP 20,000#/hr Erie City 200 psig Firetube 15-600 psig amount of gas is • ALL PRESSURE AND TEMPERATURE COMBINATIONS SUPERHEATED AND SATURATED • compressed. RENTAL FLEET OF MOBILE • The infinite step TRAILER-MOUNTED BOILERS • 75,000#/hr Nebraska Optimus 750 psig 750 TTF unloading system was • 75,000#/hr 350 psig 60,000#/hr Nebraska 350 psig Nebraska 500 psig successfully commis- • 50,000#/hr Nebraska 350 psig 30,000#/hr Nebraska 350 psig • 40,000#/hr sioned and put into 75-300HP Firetube 15-600 psig • operation. However, ALL BOILERS ARE COMBINATION GAS/OIL • START-UP • FULL LINE OF BOILER • ENGINEERING several months later AUXILIARY SUPPORT EQUIPMENT. • Electric Generators: 50KW-30,000KW two pipe supports • WEB SITE: www.wabashpower.com upstream of the HP • 847-541-5600 • FAX: 847-541-1279 E-mail: info@wabashpower.com H2 suction pulsation • • bottle failed. A close POWER EQUIPMENT CO.

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Figure 3A

Figure 3B

examination of the failed supports revealed some possible manufacturing issues. After the piping supports were repaired, the piping vibration was measured using a simple hand held device. The measured piping vibration level of 0.8Ë?/second was a little high, but was not excessive. So the failures were attributed to poor quality pipe supports. During the next several months, a couple of feed gas cylinder jacket water pipes failed. Again, the measured vibrations in these areas were a little high, but not considered excessive. However, a broader review of the piping system vibrations revealed several other areas of high vibration. A summary is shown in Figure 2. Although there hadnâ&#x20AC;&#x2122;t been any failures in these areas, there were concerns that the higher vibration levels could lead to failures or other problems. It wasnâ&#x20AC;&#x2122;t known if the infinite step unloading system was contributing to the high vibrations because pulsations and piping vibrations were not measured before this system was

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installed. The original pulsation study included a turndown case at the 50 percent load condition and, as shown in Figure 2, the infinite step unloading system was being run at loads less than 50 percent. Lower flows could reduce the damping efficiency of the installed pulsation suppression devices and cause higher pressure pulsations, resulting in higher piping vibrations. In addition, an infinite step unloading system creates different Pressure-Volume (PV) curves than a step unloading system, and this can cause different pressure pulsations and cylinder stretch frequencies and forces. In order to understand this better, it was decided to perform a pulsation/vibration field test.

Pulsation/vibration field test Beta Machinery Analysis (Beta) was contacted to perform the pulsation/vibration field test. Beta specializes in rotating and reciprocating machine pulsation and mechanical analyses and pulsation/mechanical field testing. The test plan was a collaborative effort and it was decided not to do any analyses prior to the field test. Any analyses would be defined after the field testing if it was deemed necessary. The test plan included the different operating load cases, specific areas of focus in the piping system, the test setup, methods for collecting the data, etc. For the pulsation testing, a number of valves had to be added to measure the pulsations at the appropriate locations. The vibration testing included piping system vibration measurements, and mechanical natural frequency testing. API-618 3rd Edition was used to evaluate pulsations (Note: API-618 has been revised since the time of this testing). For pulsation testing, the following criteria were used as a guideline: Upstream and downstream piping pulsation limits % Pulsation = 300/(SQRT(P * ID *f)

July 2014

MACHINE DOCTOR Where: % Pulsation = % allowable peak to peak pulsation referred to absolute line pressure at frequency f P = average line pressure (psia) ID = inside pipe diameter (inches) f =pulsation harmonic frequency (cycles per second) Compressor side pulsation limits CPL = 3R with 7% Maximum

these piping resonances is to add stiffness to the piping system at areas of high vibration. This will increase the piping system natural frequency in these areas. In this case, temporary wooden braces were installed at some locations, temporary wedges were added under pipe sections at other locations, and more robust temporary clamps were installed at other locations. See Figure 4 for an example of where temporary wedges were added under a piping section. These measures were successful in reducing the process piping vibration levels to acceptable levels. These temporary measures were left in place until permanent pipe braces, clamps and shims were installed.

Where: CPL = % allowable unfiltered peak to peak pulsation referenced to absolute line pressure R = stage pressure ratio For vibration testing, it was decided to use a piping vibration limit of 1Ë?/second as a guideline.

Results of field testing Although the operating conditions did not exactly match the original design conditions, the measured pressure pulsation amplitudes were all within the guidelines and were actually lower than the levels predicted by the original pulsation study. The vibration levels were above the guideline in a few areas. The spectrum analyses showed that the dominant vibration frequencies were at higher harmonics of running speed, predominantly 3X, 5X and 7X. The mechanical resonance testing showed some natural frequencies close to these running speed harmonics. See Figure 3. This provided evidence that some of the vibrations could be due to excitation of these piping system natural frequencies. Reciprocating compressors generate vibrations at harmonics of running speed. BETA has done some engineering analyses and performed some case studies that show infinite step unloaders can generate higher energy pulsation and cylinder gas forces at higher frequencies than other traditional types of unloaders (pocket or valve unloaders). Therefore, in the case of the compressor that is the subject of this article, it is possible that higher piping vibrations resulted from higher order piping resonances being excited after the infinite stepless unloader system was retrofitted. As previously mentioned, if a resonant condition exists, a small force can cause high vibrations. One way to address

July 2014 ENERGY-TECH.com

MACHINE DOCTOR some additional elbows. When the jacket water piping was repaired after the initial failures, it replaced heavier wall piping and fittings. It was decided to monitor the jacket water piping and only modify the piping if failures occurred in the future. Since making the piping support and jacket water piping changes, there have been no chronic problems or issues with excessive vibration.

Figure 4

The feed gas jacket water piping vibrations were marginally above the guideline. The jacket water piping was configured with very short, straight sections of pipe, which made the piping system very stiff and meant that the forces imposed on the piping from cylinder thermal growth, cylinder stretch and vibration could create higher stresses than if the piping system had more flexibility. Flexibility could be attained by adding

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Conclusions The causes of excessive reciprocating compressor piping vibrations are not always obvious. Any time a significant change is made to something in the reciprocating compressor system, mechanical and performance data should be taken before and after the change to evaluate the implications of the change. In the case of the compressor in this article, if piping system vibrations were taken before the infinite step unloading system was installed, the effect of this change on the piping system vibrations could have been better evaluated and corrections in the piping system could have been made before there were support and piping failures. In the absence of this information, industry standards can provide a good reference for guideline limits. When a problem with piping system vibrations is identified and there are no obvious problems with supports, foundation, anchor bolts, etc., it might be necessary to consider a pulsation/ mechanical field test. If this field test is performed, it is key to have this performed by someone skilled in taking and analyzing the data and it is important the test scope and procedures are developed collaboratively with the operating company. ~ References 1. API-618, “Reciprocating Compressors for Petroleum, Chemical, and Gas Industry Services”,Third Edition, API, Washington, DC. 2. Eberle, Kelly and Howes, Brain C., “Acoustical Modeling of Reciprocating Compressors With Stepless Valve Unloaders”, Beta Machinery Analysis Ltd., Calgary, AB, Canada,T3C 0J7 Patrick J. Smith is lead machinery engineer at Air Products & Chemicals in Allentown, Pa., where he provides technical machinery support to the company’s operating air separation, hydrogen processing and cogeneration plants. You may contact him by e-mailing editorial@woodwardbizmedia.com.

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Advance Turbine-Generator Troubleshooting and Failure Prevention

Stephen Reid, PE This intensive, 6-hour course describes major failure modes that turbines experience. The fundamentals of steam and gas turbine design will be covered in detail. In addition, predictive maintenance technologies and associated performance issues will be discussed along with case studies that demonstrate turbine fundamentals.

Stephen Reid, PE This intensive, 6-hour course describes methods for prevention of turbine failures. An understanding of failure modes, and how to prevent them, will help plant personnel avoid costly forced outages. New issues on increased unit cycling and turndown also will be discussed along with the pitfalls of associated equipment issues. The most current industry problems and failure modes are presented, along with many recent case histories.

August 6, 7 & 8, 2014 • 6 PDHs

Highlights and Major Topics • Turbine failure statistics - analyzing industry data • Detailed design of turbines • Performance improvements • High temperature failure mechanisms • Effects of chemistry and environment on failure modes and operations • Steam and gas turbine blade vibration • Participant case studies

All webinar class sessions begin promptly at 10 a.m. Paciﬁc, 11 a.m. Mountain, Noon Central and 1 p.m. Eastern. Each course will consist of three 2-hour webinar class sessions scheduled three days in a row. Each session will be recorded on video and can be viewed the following day.

August 13, 14 & 15, 2014 • 6 PDHs

Highlights and Major Topics • The basics of root cause analysis • Turbine casing cracking • Turbine rotor and disc cracking • Correcting steam and gas turbine vibration issues • Turbine lateral vibration • Turbine torsional vibration • Predictive maintenance programs • Participant case studies

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