November 2016

Lubrication management 12 • Pump bearing choices 15 • Compressor replacement 25

ENERGY-TECH A WoodwardBizMedia Publication

NOVEMBER 2016

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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

6

By Navid Goudarzi, John Rudesill, Alex Pavlak

15

Editorial Board (editorial@WoodwardBizMedia.com) Bill Moore – Director, Technical Service,

National Electric Coil Ram Madugula – Executive Vice President,

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Know what pump bearings to pick

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COLUMNS

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Printed in the U.S.A. Group Publisher Karen Ruden – kruden@WoodwardBizMedia.com General Manager Randy Rodgers – randy.rodgers@Woodwardbizmedia.com Editor Kathy Regan – editorial@WoodwardBizMedia.com

Cost performance tradeoff study of wind systems: grid-scale storage

Maintenance Matters

Lubrication Management and Technology Selection Application Guidance

By Mike Ruszkowski, Electric Power Research Institute

25

Machine Doctor

Machine Doctor: Is it time to replace a compressor?

By Patrick J. Smith

ASME FEATURE

20

Safety considerations in Biomass Torrefaction Ezra Bar-Ziv, Michigan Tech, Houghton, MI, Jordan Klinger, Treamin Energy, Atlantic Mine, MI

INDUSTRY NOTES

4 Editor’s Note and Calendar 30 Advertiser’s Index 31 Energy Showcase ON THE WEB Have you seen Energy-Tech’s weekly newsletter yet? If not, sign up at www.energy-tech.com for the latest technical articles, business news and products in the industry.

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November 2016 ENERGY-TECH.com

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EDITOR’S NOTE

Looking forward to a new year.

By the time you read this letter we will be well on our way to planning menus for Thanksgiving dinner, Christmas shopping, maybe a little snowfall and the 2016 election. While I hate the thought of snow and bitterly cold temperatures, I’ll be glad when the election is over and we can move on to new challenges and opportunities in the new year.

Our fall has been busy with webinars, enewsletters and this final print issue of 2016. This issue of EnergyTech is packed full of articles addressing maintenance issues. Patrick Smith writes about compressor problems along with the root cause analysis and ways to solve the problems. Read more in Patrick’s Machine Doctor column on page 25. The cover story shares experience and mitigation strategies in an attempt to overcome typical process safety pitfalls. Look for “Safety considerations in Biomass Torrefaction” on page 20. These are just highlights from this issue packed with helpful articles from our experienced contributors.

Hopefully, you’ve had a chance to attend one of our webinars this past year on air-cooled turbogenerators, diagnosing and correcting gas and steam turbine vibrations or critical water/steam chemistry concepts for HRSG, just to name a few. Or maybe, you took the opportunity to attend the Generator Auxiliary Systems symposium that was co-hosted

by E/one and Energy-Tech magazine, and came away with an increased awareness of critical auxiliary systems for hydrogen cooled generators.

Either way, as the year closes, you have the satisfaction of knowing that you did your best to expand your knowledge.

If you missed these educational opportunities, there’s still time to attend a webinar that was important to you by visiting the Energy-Tech website at www.energy-tech.com. Look for the webinars tab where all past webinars are still available conveniently for your download. If you didn’t take advantage of the continuing education that is offered by Energy-Tech, you’ll want to plan now to include time in the new year.

We’ll be starting off 2017 with an in depth six-session webinar on metallurgy – from the basics to failure analysis in January. Details can be found in the center of the main page on our website. Watch for details on our full webinar line-up in our weekly enewsletters and on our website.

Whatever the new year brings, look to Energy-Tech for stability in the power industry with our weekly enewsletter and our quarterly print publications. I’d love to hear from you. Email me at editorial@woodwardbizmedia.com with your ideas for topics that you’d like to see covered in articles or webinars.

Thanks for reading,

CALENDAR Dec. 13-15, 2016 Power-Gen International Orlando, Fla. www.power-gen.com January 24-26, 2017 ETU Webinar: Comprehensive Metallurgy www.energy-tech.com/metallurgy June 14-16, 2017 Vibration Institute 41st Annual Training Conference Rochester, N.Y. www.vi-institute.org June 26-30, 2017 ASME 2017 Power & Energy Conference Charlotte Convention Center Charlotte, NC www.asme.org/events/power-energy Submit your events by emailing editorial@woodwardbizmedia.com

Kathy

4 ENERGY-TECH.com

November 2016

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FEATURES

Cost performance tradeoff study of wind systems: grid-scale storage Navid Goudarzi Engineering Technology and Construction Management University of North Carolina at Charlotte Charlotte, NC USA 28223 Navid.goudarzi@uncc.edu

Navid Goudarzi Engineering Technology and Construction Management University of North Carolina at Charlotte Charlotte, NC USA 28223 Navid.goudarzi@uncc.edu

Abstract Variability and uncertainty are the primary challenges for power generation from intermittent, non-dispatchable energy sources. This stochastic behavior could significantly increase the cost of energy. An earlier work developed an interdisciplinary economic model using three-year (2011-2013) wind/load data from two different sites, Pennsylvania New Jersey Maryland Interconnection LLC (PJM) in USA and EirGrid in Ireland.

Results showed a wind plus natural gas system can reduce emission as much as 50% below that of an all-natural gas system, with only a slight increase in system cost. Energy storage can be a key element in obtaining energy and cost savings, together with providing availability, reliability, and security of energy supply to consumers. In this paper, grid-scale storage parameter variations (storage capacity, cost, and efficiency) are explored to obtain levelized cost trends for wind systems with storage.

Introduction Over the past ten years wind energy due to its cost-effectiveness and abundancy over other renewable energy sources, has shown the most prominent growth. The average annual growth of installed wind power capacity has been 25% per year in the past ten years [1, 2]. It is projected that wind power will supply 25-30% (compared to current 2.6%) of global electricity demand and 35% (compared to current approximately 5%) of the US electricity demand by 2050 [2, 3].

The stochastic nature of wind raises variability and reliability concerns. The impact of wind power integration on the system stability and reliability is dependent on the penetration level.

Different penetration levels require different technologies, grid operating models, and market analysis. While there is considerable research on technical and economic issues associated with storage integration with renewable energies, there is a lack of consistency in the final conclusions [4-6]. This discrepancy comes mainly from the variability of renewable energy sources and the market and regulatory structures that determine storage economics. The technology maturity, storage system efficiency, as well as capital and operation and maintenance costs are among other technical and economic considerations in evaluating the storage systems.

6 ENERGY-TECH.com

Alex Pavlak Future of Energy Initiative Severna Park, MD USA alex@pavlak.net

The objective of this paper is to study the cost and emission performance of wind with grid-scale storage, and to compare the wind system with all-natural gas systems [7, 8]. Cost is derived from published data from the Energy Information Administration (EIA) measured in dollars per megawatt hour ($/MWh) at the system level. Emission performance is measured as % CO2 emissions relative to an all-natural gas system. The results illustrate the impact of storage capacity and efficiency on the cost of wind for achieving any carbon emission ranging from a maximum 100% to a minimum 0% emission rate.

EIA cost components This study adapts levelized cost estimates developed and published by the energy information administration (EIA) as shown in Table 1 for natural gas advanced combined cycle (NG) and onshore wind [9]. The numbers are calculated in 2015 $/ Megawatt hour, and it is assumed that these systems would be brought online in 2020.

The system modeling methodology is to include the gridscale storage and transmission parameters in calculating the proportional contribution for each of different generator types, and then add them up. The EIA levelized fixed and variable costs from Table 1 are directly applied to each proportional component [7]. Note that the CF assumed by EIA is modified and replaced by its real value using the PJM data [10]. To make sure that the system has enough reserve capacity to reliably operate during peak load, an installed reserve margin of about 15% is used in calculating the total required capacity [11].

Table 1 - Levelized cost components estimated by EIA ($/MWh) Plant type

CF %

Fixed cost

Variable cost

Levelized cost

NG Wind-onshore

87

19

53.6

72.6

36

73.6

0.0

73.6

Studied site The three year (2011-2013) actual wind/load data from Pennsylvania New Jersey Maryland Interconnection LLC (PJM) in USA is used to perform the cost-performance study. Table 2 November 2016

FEATURES presents the average load data, peak load (annual maximum), and total capacity (peak load + 15% reserves) for the PJM region [10]. While the lowest average load was observed in 2011, the peak load has been the highest in this year. However, averaging multiple years would be useful due to small standard deviation values of 3%, 1%, and 1% of the average load, peak load, and total capacity, respectively. The cost numbers are normalized relative to the average load. Note that due to small standard deviation of three year load/wind patterns in the PJM, the sensitivity analysis on the storage capacity and efficiency is performed on wind/load data of 2012.

Table 2 - PJM load data (2011-2013) Year

Average load (MW)

Peak load (MW)

Total capacity (MW)

2011

84.44

158.04

181.75

2012

88.95

154.34

177.49

2013

90.30

157.51

181.13

Average

87.90

156.63

180.12

All-natural gas system scenario An all NG system has the lowest cost and highest CO2 emission and is the reference scenario in this study. For such a system,

which is summarized in Table 3. The NG system, 100% emissions, in PJM has an average three year cost of 87.90 $/MW. Less than 1% deviation of this average cost for PJM and other sites [7] offers employing multiple years’ data for system cost analysis. Figure 1 illustrates the average three year time series for the PJM region. By storing the excess energy from the electricity generated by a wind farm and using it for peak-load time windows, a more efficient wind farm can be more cost effective than expanding it to a larger capacity.

Figure 1 - Three year average load-time series in PJM

A combined system that includes wind and an ideal storage identifies the system limits. It is assumed that the storage system has a zero cost, with 100% efficiency, and has a large (but finite) capacity. Also, the transmission lines, storage devices, and demand responses are assumed to have no loss in the power. This scenario with such assumptions would identify constraints in calculating the required storage capacity to level the region load. However, it should be noted that the system costs would exceed these limits due to actual curtailment, storage and transmission efficiencies and costs. Here, the NG system is required to fulfill the peak load with reserves.

Table 4 presents the 100% wind with ideal storage cost in the PJM region from 2011 to 2013, with an average three year total system cost of 127.25 $/kWh. Similar to the all-NG scenario, the assumed 0.34 CF from EIA is corrected to the actual values of 0.20, 0.30, and 0.35 in 2011, 2012, and, 2013, respectively, for the PJM region. The significant differences in the total system cost at different years in the PJM region come from different CF values at each year. Increasing the CF value will result in lowering the total system cost. Increasing the CF value will result in lowering the total system cost.

Wind + NG system scenario

Table 4 - PJM System cost for wind + ideal storage

Table 3 - System cost for all natural gas in PJM Parameters

2011

2012

2013

Average load (GW)

84.44

88.95

90.30

NG capacity (GW)

181.75

177.49

181.13

Avg. NG production (GW)

84.44

88.95

90.30

NG fixed cost ($/MWh)

35.58

32.98

33.16

NG variable cost ($/MWh)

53.60

53.60

53.60

Total system cost ($/MWh)

89.18

86.58

86.76

Wind + ideal storage scenario

Parameters

2011

2012

2013

Average load (GW)

84.44

88.95

90.30

NG capacity (GW)

181.75

177.49

181.13

Avg. NG production (GW)

0.00

0.00

0.00

Avg. wind production (GW)

88.44

88.95

90.30

NG fixed cost ($/MWh)

35.58

32.98

33.16

NG variable cost ($/MWh)

0.00

0.00

0.00

Wind fixed cost ($/MWh)

125.12

83.41

71.50

Total system cost ($/MWh)

160.70

116.39

104.66

A wind + NG system scenario follows the ideal storage scenario out to the point where curtailment begins. PJM 2011,

November 2016 ENERGY-TECH.com

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FEATURES 2012, and 2013 wind contributed 1.50%, 1.61%, and 1.87%, respectively to the total load. The wind-time series is scaled up (assuming the same footprint of deployed wind farms) until wind just begins to overlap the load curve. The curtailment begins when average wind equals to approximately 26% of average load.

The three-year average cost-performance chart for the wind + NG system scenario is presented in Fig.2. The red square is the three-year average system cost for all natural gas calculated in Table 3. The blue dashed-line is the three-year average system cost as a function of system emissions as reduced by wind assuming ideal storage in the PJM region. The curtailment begins at 26% wind penetration (74% emissions, the dotted red line). The curtailment does not have a noticeable effect on system cost until about 50% penetration.

in Fig. 4. The overall impact of the one day grid-scale storage is marginal. It is apparent from Fig. 4 that the one day bulk storage increases energy costs at low penetration; reduces energy costs only beyond 80% penetration.

Table 5 - Bath County basis for levelized storage cost for PJM Bath County Rated power MW

3003

Bath County Duration at rated power (hr.)

10.30

Capacity kWh (10 hours @ nameplate)

3.12E+7

Capex $

1.60E+9

1977 2014

3.85 (PPI* inflation factor)

Z - Capacity cost $/kWh

6.16E+9 197.00

A - 30 year annuity @ EIA discount factor of 6.6%, $/kWh/yr. 15.27 B - PJM one day capacity kWh

2.16E+9

C - Annual cost of one day capacity $ (A*B)

3.31E+10

D - Annual load 2013 MWh

7.91E+8

Levelized cost $/MWh (C/D)

41.80

Two way efficiency for Markov modeling

0.80

Figure 2 - Wind + NG with curtailment for PJM region

Wind + NG + bulk storage scenario This scenario considers the impact of grid scale storage on system cost-performance tradeoff 1. The size of the storage is assumed to be one day of average load. This real (as opposed to ideal) storage scenario considers the impact of grid scale storage (size, cost, efficiency) on system cost versus emission performance.

Cost-performance of bulk storage is modeled after Bath County, VA pumped hydro storage (PHS) facility [13]. Table 5 summarizes the calculation of the levelized cost for one day storage developed in an earlier work by Goudarzi and Pavlak [7]. Note the capacity cost is $197/kWh. For this study, the system logic is to charge storage whenever there is any excess wind power and to discharge whenever there is available charge and wind cannot meet load. NG provides power whenever load cannot be satisfied by either wind or storage. Note that the PHS results for this site can be used for other storage systems with similar efficiency and cost.

Figure 3 shows the state of charge of the PHS for wind penetration equal to average load in PJM. The PJM system challenge is in August where the storage is at its minimum charge and there is a higher load in the PJM region as well. The cost-performance chart for the wind + NG + one day of storage system is shown 8 ENERGY-TECH.com

Figure 3 - State of Charge of 2.16 TWh of storage @ average wind = average load for PJM

Figure 4 - Wind + NG + one day storage for PJM

November 2016

FEATURES Figure 5 illustrates the average three-year levelized cost varation at three different efficiencies of 50%, 80%, and 100% for the PJM site employing the Bath county PHS storage system. The sensitivity analysis on the efficiency of the Morkov storage modeling shows decreasing/increasing the storage efficiency at the level of one day does not make significant changes up to approximately 26% emission level where curtailment begins (the dotted line in Fig. 6 ).

To better understand the constraints of storage parameters on a wind system cost, the levelized cost curve for a wind system with five day storage at 100% efficiency (a large storage capacity and very efficienct storage system) together with a levelized cost curve for a wind system with one hour storage at 50% efficiency ( a small storage capacity with low efficiency) are plotted against the current levelized cost curve for the PJM wind system with a one day storage system and 80% efficiency, as shown in Fig. 7.

As the emission level decreases, it is apprarent from Fig. 7 that an efficient storage system at a larger capacity can reduce the levelized cost below 20% emissions.

It is seen that a zero percent CO2 emission with a 10-day storage capacity at 100% efficiency is achievable. However, the size and cost of the system is very high, about 5x that of an all-natural gas system. Also, it is seen that emission reduction for a wind system with a very efficient storage can be achieved at much lower levelized cost; however, this trend does not change for a wind system with a low efficient storage and lower capacity.

Figure 5 - The impact of storage efficiency on the wind system cost, PJM load/wind data in 2012+1-day storage

Figure 6 illustrates the impact of storage capacity variation from one hour storage to five day storage at 80% efficiency for the PJM region in 2012.Very large storage capacity does not reduce the levelized system cost except at high emission reductions. As emission level goes down to values lower than 20%, one day storage capacity offers higher overal system cost, while the five day storage capacity offers lower overal system cost.

Figure 7 - The impact of combined storage capacity and efficiency on the wind system cost.

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Figure 6 - The impact of storage capacity on the wind system cost, PJM load/wind data in 2012+80% efficient.

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FEATURES 4. Chen, H., Cong,Th. N,Yang,W.,Tan, Ch., Li,Y., and Ding, Y., 2009, “Progress in electrical energy storage system: A critical review,” Progress in Natural Science, 19, pp. 291-312.

5. Suberu, M.Y., Mustafa, M.W., and Bashir, N., 2014, “Energy storage systems for renewable energy power sector integration and mitigation of intermittency,” Renewable and Sustainable Energy Reviews, 35, pp. 499-514.

6. Castillo, A., Gayme D. F., 2014, “Grid-scale energy applications in renewable energy integration: A survey,” Energy Conversion and Management, 87, pp. 885-894.

7. Goudarzi, N., and Pavlak, A., 2016, “Wind systems: the cost-performance tradeoff study,” Submitted for publication to Energy for Sustainable Development.

8. Goudarzi, N., and Pavlak, A., 2013, “Cost performance tradeoff study of low-carbon system concepts,”The ASME 2014 Power Conference, Baltimore, MD, USA. 9. U.S. Energy Information Administration, 2015, “Levelized cost and levelized avoided cost of new generation resources in the annual energy outlook 2015,” Annual Energy Outlook 2015, available at: http://www.eia.gov/forecasts/aeo/electricity_generation.cfm (last accessed on 9/28/2016).

10. PJM Historical Metered Load Time Series, available for spreadsheet download here: http://www.pjm.com/markets-and-operations/ops-analysis/historical-load-data.aspx (last accessed on 9/28/2016).

11. U.S. Energy Information Administration, 2012, “Reserve electric generating capacity helps keep the lights on,”Today in Energy, available at: https://www.eia.gov/todayinenergy/detail. cfm?id=6510 (last accessed on 9/28/2016) 12. Dominion Electric Power, Bath County Pumped Storage Station, available at: https://www.dom.com/about/stations/hydro/bathcounty-pumped-storage-station.jsp (last accessed on 9/28/2016).

13. EIA, Historical wholesale market data for 2014, average of the national weighted average price, available at: http://www.eia.gov/ electricity/wholesale/xls/ice_electric-2014final.xls (last accessed on 9/28/2016).

Conclusion This paper follows earlier works [7, 8] in developing a system-concept modeling for wind energy systems. The earlier works studied one-year, multi-year, one-region, and multi-region wind/load data to calculate wind systems cost. Grid-scale storage systems can significantly improve the performance of renewable energy systems.This paper studied the impact of including a gridscale storage on the wind-system cost. The pumped-hydro storage parameters, as the most common storage system globally, are used. Here are several tentative conclusions from this work: • Grid-scale storage at the level of one day at average load reduces system costs only at lower emission levels.

• Increasing the efficiency of the PHS system moderately decreases the levelized system cost.

• Efficiency variation from 50% to 80% has more impact on the levelized system cost than from 80% to 100%. For efficiency values over 80%, other parameters such as fixed cost have more impact on the system cost.

• The one hour storage capacity becomes expensive at very low emission rates (due to?). While a large storage size has a more expensive initial investment, for very low emission levels, it ultimately might further reduce the system cost.

• Carbon-free systems appear to be achievable with storage but only at very high system costs. This zero carbon limit needs to be explored with realistic storage efficiencies and multiple storage costs. Further study is needed to explore very small grids and grids with very high or very low average CF values for different regions to obtain the range and overall average costs at different regions. ■

Acknowledgment The authors wish to thank the support of Future of Energy (FoE) Initiative2 since the beginning of this research.

References 1. Goudarzi, N., and Zhu,W.D., 2013, “A review on the development of the wind turbine generators across the world,” International Journal of Dynamics and Control, 1 (2), pp.192202.

2. Global Wind Energy Council, “the Annual Energy Outlook 2014,” Annual Energy Outlook 2015, available at: http:// www.gwec.net/wp-content/uploads/2015/03/GWEC_ Global_Wind_2014_Report_LR.pdf (last accessed on 3/28/2016).

3. US Department of Energy, 2015, “Wind Vision: A new era for wind power in the United States,” Chapter 4, available at: http://energy.gov/eere/wind/maps/wind-vision (last accessed on 9/28/2016).

10 ENERGY-TECH.com

Editor’s note: This paper, POWER2016-59461 is 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.

The wind industry scales renewable energy storage cost two different ways: $/kW and $/kWh. The former is used for power limited storage as to compensate for short-term high-power wind ramping; storage cost is dominated by power conversion equipment. The latter is used for energy limited storage as for large-size grid-scale storage and batteries; storage cost is dominated by the size of the battery. This paper uses the latter method.

1

2

Available at: https://sites.google.com/site/futureofenergyinitiative/home

November 2016

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MAINTENANCE MATTERS

Lubrication Management and Technology Selection Application Guidance

By Mike Ruszkowski, Electric Power Research Institute

Lubrication has often been called the “life blood” of a power plant. A well-run lubrication program—which includes proper storage, contamination control, and monitoring of lubrication quality—has been shown to extend the life of plant equipment. Moreover, proper sampling and oil analysis can strengthen preventive maintenance and equipment reliability by providing evidence of equipment trends, including wear of equipment components.

Most utilities have implemented lubrication controls and analysis programs to varying degrees, but industry data indicate that a great deal more can be done. Although recent experience has shown that applying the technologies associated with lubrication management in power plants can provide significant benefits, many plants struggle to define and implement a quality lubrication program.

Over the years, the Electric Power Research Institute (EPRI) has conducted research to develop industry best practices and guidelines to improve the storage, handling, and use of oil lubrication products in power plant applications. This work has resulted in the publication of technical reports on lube oil predictive maintenance, handling, quality assurance, and cleanliness in bearing motor applications.

More recently, EPRI has published a new Lubrication Standards Guideline Manual (3002006568), which describes industry best practices for managing lubricants in a power plant and guidelines for improving the efficiency of a lubrication program. The manual, which serves as a master guide of lubrication and oil analysis standards as officially set forth by lubrication companies, will assist plant operators in selecting, handling, using, and disposing of lubricants. In addition to detailed instructions, the manual includes multiple photographs, illustrations, and tables to illustrate practices.

Lubrication standards guideline manual The Lubrication Manual includes six sections on lubricant and vendor selection, reception and storage, handling and application, contamination control, lubricant analysis, and environmental control. The approach taken, when creating this guideline, was to treat lubricants as a plant component and show best practices and processes of the lubricant from cradle (vendor selection) to grave (disposal).

12 ENERGY-TECH.com

Lubricant and vendor selection Selecting the correct lubricant for the machinery helps to build a solid foundation for machine reliability. The recommendations of the original equipment manufacturer (OEM) must be considered during the selection process.

Then adjustments can be made, if necessary, according to the machinery’s operating condition, available technologies, impact on the environment, energy consumption, and technological advances. Also taken into account is environment that the equipment is located in and the operating conditions.The lubricant selection should also be based on the life-cycle costs of assets.

This section of the manual describes requirements and suggestions for selecting the correct lubricant for machinery.

It includes information on selection parameters (e.g., OEM recommendations, viscosity, and compatibility), supplier selection process, lubricant identification, and consolidation.

The manual also discusses the lubricant identification system (LIS), which is a tool that uses visual aids to reduce the likelihood that lubricants are added to machines erroneously.

The lubricant identification system is based on the use of labels or cards on lubricant containers, lubricant application tools, and machines so technicians can ensure that the correct lubricant is applied to a machine.

The LIS combines the strengths of visual aids using forms, codes, and colors to identify the lubricant, but also provides a way to differentiate products that may have similar characteristics and identical viscosity, but different performance properties. The LIS and the alpha-numerical code may be used to identify: • Stored lubricants • Dedicated containers • Dedicated hoses • Grease guns

Reception and storage This section of the Lubrication Manual describes best practices for the reception, approval, and storage of new lubricants coming into the plant. A lubricant control process for receiving new lubricants reduces the possibility of costly mistakes that can severely affect the production process.

Without controls in place, lubricants may be received that are out of specification, incorrect, or contaminated. The reception November 2016

MAINTENANCE MATTERS of. It is important to select lubricant handling and application practices according to the machinery configuration.

This section of the manual covers requirements for lubricant handling, transfer, temporary storage, and application to machines. Information is included on lubricant application tasks, machinery configuration, handling and application devices, lubrication program management, lubrication routes, and machinery inspection devices and practices.

Figure 1. Example of lubricant handling room

Figure 2. Illustrations of leak and spill management

process should be implemented according to the lubricant’s importance to the plant as well as the package type.

Written procedures should be created for all lubricant control tasks in the reception of new lubricants, and these procedures should be updated when lubricant control activities change. Lubricant suppliers should also be involved in the design of this process. The lubricant control process should include verifying the purchase order, testing the new lubricants, and inspecting the product.

All incoming lubricants should be inspected for packaging damage, intact seals, proper labels, expiration date, correct product name and quantity, and any leakage. All abnormalities should be documented.

Proper lubricant storage is critical to help maintain lubricant performance properties as well as to prevent contamination and degradation. The lubrication handling room is the area where lubricants are opened to be transferred to other containers and delivery devices (Figure 1). A lubrication handling room can also be used for repairing and maintaining lubrication equipment, planning work, oil analysis field testing, and inspecting filters. The lubricant storage area and the lubrication handling room must protect lubricants from environmental risks (such as moisture and particles).

Handling and application Lubricants are formulated to meet specific machinery requirements. If lubricants are not correctly handled and applied to machinery, they can become contaminated and perform poorly, lose their protective properties for the machine, or simply become unusable, creating waste that must be disposed

Temporary storage containers are used to store lubricants in the lubrication handling room. Intermediate containers are hermetically sealable devices used to transport and/or apply lubricants to machinery. Grease guns and pumps are portable tools (normally hand-powered) that are used for lubrication tasks. Filtration carts are portable filtration systems used for filtering lubricants from a reservoir.

To ensure success, the lubrication program must be managed efficiently, by scheduling, executing, controlling, and monitoring lubrication tasks. This efficiency can be achieved through the use of lubrication program management software. “Lubrication routes� are essential for the planning, execution, and control of lubrication tasks. Lubrication routes are designed according to the type of work to be performed, type of lubricant to be applied, equipment required to perform the task, type of machine to which the task applies, task frequency, plant location, and technical skills needed to perform the task.

Contamination control This section of the manual reviews prevention and control of lubricant contaminants such as solid particles, moisture, excessive heat, air, and varnish. When contamination levels are not controlled, they can compromise the machinery, oil life, and performance. Information is included in the manual on contaminant exclusion, removal, and control objectives.

Contaminant exclusion refers to the establishment of a proactive strategy for avoiding machine failure by preventing contaminants from entering the lubricants and machinery. The strategy for controlling the ingression of contaminants can extend the life of the lubricant and machinery. Contaminant removal aims to eliminate contaminants present in the in-service lubricant.

Lubricant analysis This section of the manual describes the requirements for lubricant inspections and laboratory analysis to implement and maintain a complete, reliable, and updated monitoring program for lubricant health, contamination, and machine-wear debris.

Information is included on test slate selection, sampling, analysis limits, and analysis interpretation.

November 2016 ENERGY-TECH.com

13

MAINTENANCE MATTERS A lubricant analysis strategy works best when the tests are selected considering the critical failure modes. A combination of routine and exception tests should be conducted to monitor critical machines. Routine testing is to determine the root cause of failure and/or early failure symptoms. Exception testing is to identify the source of a problem with abnormal results.

A quality sample must be representative of the machine’s condition and component wear as well as provide information about lubricant contamination and health. Sampling aims to maximize the chance of capturing the target information and minimizing the distortion of information. Best practices include: performing the lubrication sample when equipment is running under normal conditions, locating the sampling point between the equipment being lubricated and the filter, installing fixed sampling ports in equipment, and basing sampling frequency on the machine/oil run-time and condition.

Environmental control New and used lubricants can cause significant damage to the environment when not disposed of responsibly.

Environmental regulations establish the minimum methods under which lubricants must be temporarily stored, transported, and disposed of to lessen the impact on the environment. To minimize the risk of lubricants affecting the environment, the temporary storage area for used lubricants should meet basic requirements that have been adjusted according to the local laws and regulations. In relation to lubricants, the rule of three R’s — reduce, reuse, and recycle — should be considered.

This section of the manual describes the requirements for appropriate storage, handling, and disposal of lubricants and diverse materials contaminated with lubricants, such as filters and other consumables. Information is included on disposal of used lubricant and contaminated material, and leak and spill management (Figure 2).

Turbine generator lubrication system For more specific application, EPRI also published a lubrication guide for turbine-generators—

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That guide addresses the maintenance of the main turbinegenerator lubricating oil system components and the testing of the lubricating fluid. The recommendations provide the basis for developing suitable preventive maintenance and predictive maintenance programs for the turbine-generator lubrication system components at a power plant.

Sidebar: Hoosier Energy improves its oil lubrication program Like many power plants, Merom Generating Station, a 1,070-MW coal-fired power generating station operated by Hoosier Energy Rural Electric Cooperative in central western Indiana, had a number of issues with its use, handling, and storage of lubricating oil. The existing facilities for used oil lacked organization and had aging environmental containment.

Open-topped containers allowed contamination of the oil, frequency of replacement was scheduled on a preventive maintenance (time-based) basis, and lubricants were purchased from a wide variety of vendors.

In early 2013, Merom initiated an oil lubrication improvement program that was implemented over the following three years. The $580,000 program was based on extensive use of EPRI publications and user group conferences.

Changes included: construction of a new containment facility for used oil, installation of new lubrication dispenser units at the flue gas desulfurization (FGD) processing areas to prevent cross-contamination of lubricants, replacement of all portable, open-topped containers with closed-top plastic containers to reduce introducing contaminants into new oil, introduction of a procedure requiring approvals prior to a lubricant being brought on site, implementation of a consolidation plan to reduce the varieties of lubricant and maintain a more manageable inventory, and construction of a climate-controlled lubrication storage facility to reduce condensation, meet OSHA standards, and provide environmental spill control.

The result is the creation of a “best-in-class,” highly functional, and efficient lubrication program, while enabling $100,000 in annual expense savings. Other realized benefits to be quantified include elimination of cross-contamination, reduction of contaminant induction, contained storage, reduced oil disposal expense, efficient dispensing processes, warranty integrity, improved safety through handling procedures, and procurement policy. ■ Mike Ruszkowski (mruszkowski@epri.com) is Principal Program Manager of EPRI’s Generation Maintenance Applications Center (GenMAC).

The Hoosier Energy case study was developed in EPRI’s Maintenance Management and Technology Program (Program 69). Rick Roberts (rroberts@epri.com) is Principal Program Manager of that program.

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November 2016

FEATURES

Know what pump bearings to pick

By Heinz P. Bloch, P.E.

The stipulations found in prominent Industry Standards can confuse pump users when certain specification clauses seem at odds with best available practices. There are certain stipulations that are not supported by field observations and long-term experience of Best-of-Class process and/or manufacturing plants. Occasionally, these discrepancies can be explained by the scope and intent of widely accepted Industry Standards, such as API-610 (the American Petroleum Institute’s pump quality standard). This pump standard and a number of similar documents are based on input from many contributors.

The contributors or their representatives, both equipment manufacturers and users, volunteer to serve on a subcommittee tasked with developing a particular standard.

API makes efforts not to let the content of its standards be dictated by special interests. The American Petroleum Institute’s aim is to impart quality within reasonable cost boundaries.

That said, component recommendations and other guidelines found in API-610 quite adequately cover the predominant requirements of most process pumps installed in a variety of plants. However, what’s adequate for one entity may not be considered adequate by another entity. Particulars often matter more to one user and matter less to another. Take bearings, for instance. Rolling element bearings for pumps can incorporate many different contours, configurations, clearances, cage materials, metal alloys, heat treatments, and so forth.

While standard bearing performance and life expectancies are

adequately covered in API-610, there exist superior options of interest to reliability-focused users. Here are some of the details.

API-610 and process pump bearings API-610 lists back-to-back oriented 40-degree angular contact bearings with brass or bronze cages as preferred for taking up axial thrust. However, using 40-degree angular contact thrust bearing sets with brass or bronze cages will not always optimize bearing life. Competent bearing manufacturers design contact angles so as to ascertain favorable rolling motion and minimize skidding. The desirable performance characteristics of bearing sets may vary for different styles of pumps. Figure 1 shows but a small portion of the many different options and possibilities. For instance, sets consisting of two 15-degree or 29-degree back-to-back angular contact bearings are often best for hydraulically balanced and lightto-moderately loaded pumps operating at high speeds. As regards cage materials, the “required” copper-bearing alloys are generally more heat-tolerant than high-performance plastics, but very few---if any--- process pump bearings are exposed to elevated temperatures at either assembly or during operation.

The operating performance of bearings with high performance plastics can exceed the performance of bearings with brass or bronze cages. Certain cage types may make it easier for the lubricant to reach the bearing’s rolling elements while other cage configurations make it more difficult for oil to reach all parts of the bearing.

Figure 1: Sets of thrust bearings with different orientations (Ref. 4): tandem, for load sharing of a pump shaft thrusting from right-to-left (a); back-to-back, the customary orientation with thrust load on pump shafts expected in each direction (b); face-to-face, rarely desirable in centrifugal process pumps (c). (Source: Ref. 1)

November 2016 ENERGY-TECH.com

15

FEATURES Also, different orientation arrangements (Figure 2) are available. Process pumps with moderate thrust loads often use paired back-toback sets of bearings; pumps with very heavy primary thrust loads sometimes use a triplex set.

A triplex set is shown on the right in Figure 2.

Here, two 40-degree bearings are installed in back-to-back/tandem fashion. For optimum performance, the various bearings may or may not have identical load angles.

Figure 2: Triplex bearing set, consisting of dimen¬sionally matched angular contact bearings. Direction of primary thrust is inscribed. Contact angles other than those indicated may be desirable in some applications (Ref. 1).

Figure 3: Competent bearing manufacturers de¬sign contact angles so as to ascertain favorable rolling motion and minimize skid¬ding (Source: SKF USA, Lansdale, PA).

16 ENERGY-TECH.com

Lubricant application choices are of particular importance in process pumps.Years of experience show that oil supplied by old-style oil rings is not always meeting the expectations of reliabilityfocused pump users. Special installation, design, and fabrication constraints must be observed. Oil rings may no longer be adequate for high speed pumps in installations demanding high reliability (Refs. 1 and 2). API-610 leaves the details of oil ring design to the pump vendor; however, not all vendors are aware of the issues involved. Also, whenever two or three bearings are mounted adjacent to each other, lubricant application concerns will take on greater importance. A small amount of oil applied near the edge of the first bearing might not easily travel to the edge of the third bearing. Likewise, a drop of oil applied at the edge of the third bearing might not readily flow towards the first bearing. To complicate matters, certain cage styles and their respective angles of inclination will produce a fan effect, called “windage.” Depending on bearing orientation and based on which side the lube oil is applied, this fan effect can oppose the direction of oil flow (Ref. 1).

Again, a close review of the introductory pages to API-610 will show that the guidelines or recommendations of this standard describe minimum requirements. It is thus implied that the user-purchaser will sometimes find better or more suitable components. Reliability-focused buyers keep in mind upgrade options which can include oil mist, oil spray, and superior bearings. These owner-buyers consider API-610 a commendable effort to standardize components; such components will facilitate warehousing and commonality of maintenance. Standardized bearings allow installation or assembly with only a minimum of measuring needed by the person doing the work.

November 2016

FEATURES Still, while some of the savings in time and money derived from standardization are beneficial, other hoped-for savings may be elusive. This is why the foreword and certain special notes in the API standards leave open the option to upgrade.

Knowledgeable users procure more reliable components or configurations whenever these are deemed necessary. To our point: Better bearings are available and are, if appropriate, being purchased and installed by best-of-class performers (Ref. 1). In particular, variations in contact angles (Figure 3) are available from leading bearing manufacturers and may outperform the standardized back-to-back oriented 40-degree angular contact bearings.

Quite evidently, an interested purchaser may greatly benefit from access to vendors with application engineering staff. Sadly, the cost-cutting efforts of a number of bearing manufacturers have led to the disbanding of some of these groups. Their websites are not disclosing the contact addresses of competent design engineers. It can be reasoned that these manufacturers want to sell bearings at lowest possible cost but their marketing strategy no longer includes striving to become your technology resource.

An observant user-purchaser will quickly learn that it pays to be highly selective when choosing a bearing supply source. Better yet, the buyer-purchaser benefits greatly from understanding the many interacting parameters affecting pump bearing life.

Bearing internal clearance questions explained One of the prerequisites to understanding pump bearings relates to visualizing that bearing elements under load will deflect or “flatten”; the rolling elements will make area contact with the so-called raceways. For the sake of illustration, we try to visualize how a one-pound bearing ball “flatten” to perhaps 0.0001 square inch and the pressure against a bearing race is thus 10,000 psi. The oil film, in compression-load, will separate the steel ball from the steel race and the bearing will survive.

That said, many texts show that sets of 40-degree angular contact bearings will not be ideal for every application; neither will all types and manner of bearing-internal looseness be ideal.

Bearing internal clearances vary from a small negative amount to a particular actual internal clearance amount. In Figure 4, a bearing is assigned 100% design life with zero internal clearance. A small negative clearance (called preload) is shown to result in slightly longer bearing life, whereas a large internal looseness would reduce the bearing life to slightly below 100%.

The axial internal clearances vary greatly for different size pump bearings. For example, in the nominally 60 to 70 mm bore/shaft size range offered by different bearing manufacturers, the axial internal looseness values presently range from zero to 52 micro-meters (microns). Actually, all of the above can

Figure 4: Slight preloading prevents skidding and slightly increases bearing life (by typically 15%). Operating with excessive preload or with bearing-internal looseness cause bearing life to decrease (Ref. 2)

work well, although each has its pluses and minuses. Moreover, important installation and operating guidelines may differ, depending on preload and/or clearance values.

Bearings with greater axial clearances have “room to expand.” Used in matched (flush-ground) 40-degree pairs they will allow installation on somewhat oversized shafts. Although expanding the bearing’s inner ring diameter, this size increase will simply reduce the pre-existing internal clearance. However, once operating, bearings with large internal looseness pose a somewhat greater skid risk than bearings with zero internal clearance or no looseness. As axial thrust created by impeller hydraulics loads up one of the two bearings, the adjacent bearing will tend to skid (Figure 5). Of course, skidding generates heat and can greatly limit bearing life.

In another scenario, if an inexperienced user-operator finds a hot bearing housing and pours water on the housing, thermal growth of the outer ring will likely be inhibited and the internal bearing clearance will decrease. While the clearance reduction will somewhat reduce the skidding risk, cooling water does not come for free (Ref. 2). Moreover, properly designed pump bearing housings with rolling element bearings and a suitable synthetic lubricant will simply not require any cooling water. This fact is acknowledged in API610 and is attested to by the uncooled bearing housings in an estimated 400,000 process pumps. Thousands of these operate

November 2016 ENERGY-TECH.com

17

FEATURES and cause a preload of unknown magnitude.

But the zero-clearance bearing pays back by definitely not requiring cooling water and by almost never skidding. The question is will your maintenance work forces do their part and learn the different maintenance details that go with different bearings? The answer depends on a plant’s culture. It certainly depends on whether your management asks for and supports the training efforts needed for this type of precision maintenance.

A reliability-focused company takes important first steps by supporting their reliability engineers. At the same time, reliability professionals must read factual information and then advocate buying bearings from the most qualified manufacturer. When competent bearing manufacturers have to answer questions regarding the axial clearance on their 7000 series pump bearings, they may be confronted by questioners whose focus is very limited for one reason or another.

A bearing sales person without pump application knowledge will not be able to explain why his product should be considered for your pumps.

One experienced manufacturer—call them “A”— has often been told that the pump user cannot interchange Vendor A’s “XYZ” bearing version with either Figure 5: Skidding bearing (left) vs. rolling bearing (right). Skidding generates heat and can quickly damage the of Vendor B’s “YZX” or “ZXY” offers. bearing (Source: MRC Bearing Division of SKF Industries, ~1985) However,Vendor “B” has done bearing simulations of these differences which we they (the manufacturer) can share with quite successfully in high temperature pumping services. serous clients or customers.Vendor A’s Actual bearing temperatures are often lower without (!) a “XYZ” arrangement will shows longer life as the load zone is cooled bearing housing than with (!) a cooled bearing housing maximized; this minimizes the stress levels on individual rolling (Ref. 3). Partial cooling water jackets can even force bearing elements. Rest assured that differences in clearance have no outer rings into a slightly out-of-round (oval) and obviously negative impact the mechanical seal, impeller hydraulics, or any undesirable “squeezed” condition. other issues. Keep in mind that the clearances shown will be reduced as a function of press fit and shaft geometry.

Visualize a set of bearings precisely ground for zero axial clearance; all of its rolling elements in the 180 degree arc from In all instances, look for the facts and reason on the matter.

3 o’clock to 9 o’clock will be loaded, although the bearings Visualize how, on a large internal clearance bearing, the load nearest the 6 o’clock location will see the highest load. In will act only on the rolling elements located in the 5-to-7contrast, a bearing with large internal clearance will have all o’clock positions. In contrast, in a zero clearance bearing the of its load acting on the rolling elements from 4 o’clock to 8 load is distributed on the rolling elements located between o’clock. Load on bearing elements is related to bearing life.

4 and 8 o’clock. It should be easy to judge in which of the two bearings the load per rolling element will be higher, but Bearings with zero internal clearance will have to be the manufacturer’s computerized analysis will show the actual mounted on shafts with a closely controlled and rather numbers. Although of minor importance, the film strength low interference fit, perhaps no greater than 0.0003 inches. demands on the lubricant will also be favorably influenced Abnormally high interference fits could open up the inner ring 18 ENERGY-TECH.com

November 2016

FEATURES by distributing a given load over a larger number of rolling elements.

Here’s a fitting analogy: A certain shoe store will sell you a size 9 shoe for your size 10 feet; the store wants to make a sale and rationalizes that your feet should be your own concern. “Why should I care—perhaps the buyer likes pain?”

So, I tend to buy my shoes from the salesperson dispensing the right advice. And yes, I would like to walk with a minimum amount of pain.

As to the mechanical end of process pumps, good engineering favors precision maintenance and long pump life.

This is achieved by obtaining all the facts on bearing styles, clearances, lubricant application method and installation details. Understanding how components work is of great importance. Engineers and reliability professionals will put their well-researched knowledge into the hundreds of superior, low-risk practices described in Ref. 4. Of course, Best Practices are in no way limited to petrochemical plants and oil refineries. Best practices are followed in all major industries, including utilities, pharmaceutical plants and even bulk consumer goods plants. In all cases the application engineering groups of competent bearing manufacturers can be of great help, but remember that while all manufacturers are interested in making a sale, not all bearing manufacturers will be motivated to assist you with expert advice. Make an all-out effort to work with those who are willing and able to give experience-based advice. As you do, you---the user’s professional--- will absorb training that moves your company closer to the interacting goals of greater safety, reliability and profitability. ■

References 1. Bloch, Heinz P., “Pump Wisdom: Problem Solving for Operators and Specialists,” (2011), John Wiley & Sons, Hoboken, New Jersey 2. Bloch, H.P. and Budris, A.R., ”Pump User’s Handbook— Life Extension,” 4th Edition (2013), Fairmont Publishing/Taylor & Francis, Lilburn, Georgia 3. Bloch, Heinz P., “Improving Machinery Reliability,” (Editions 1982/1988/1998), Gulf Publishing/Elsevier Publishing Companies 4. Bloch, H.P., “Petrochemical Machinery Insights,” (2016) Elsevier Publishing Company, Oxford, UK, and Waltham, MA, ISBN 978-0-12-809272-9 Heinz P. Bloch is a consulting engineer residing in Westminster, Colorado, and Houston, Texas. He has held machinery-oriented staff and line positions with Exxon affiliates in the U.S., Italy, Spain, England, The Netherlands and Japan. Bloch is the author of 20 comprehensive texts and more than 660 other publications on machinery reliability improvement. In a career spanning 54 years he has advised process plants worldwide on equipment uptime extension and maintenance cost reduction opportunities. He is an ASME Life Fellow and maintains registration as a professional engineer in New Jersey.

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19

ASME FEATURE

Safety considerations in Biomass Torrefaction Ezra Bar-Ziv, Michigan Tech, Houghton, MI, Jordan Klinger, Treamin Energy, Atlantic Mine, MI

Abstract Torrefaction has been under investigation for some time for the production of a solid fuel replacement of fossil coal. The process converts raw biomasses, of any type, to a more coal-like carbonaceous solid that has similar combustion characteristics and can be a true drop-in fuel replacement. Despite the emphasis to move away from fossil energy to more sustainable energy sources, torrefaction has not emerged onto the market.

One prime factor for the delay-to-market are the plethora of unknown safety consideration for production scale necessary for a solid fuel replacement. This article chiefly discusses safety considerations encountered through experience in operating up to 4 tons/hour production facility. Safety events primarily occur through: (1) reactive suspended dust, (2) the highly variable torrefaction gas/vapor co-product, and (3) the torrefied biomass reactivity. Experience and mitigation strategies are shared in attempt overcome typical process safety pitfalls.

Introduction and background Environmental regulations prompted the development of torrefaction to produce torrefied-biomass (biocoal) (Bridgeman et al., 2008, Arias et al., 2008, Couhert et al., 2009, Duncan et al., 2012, Medic et al., 2012) as a renewable replacement of coal for power generation. Torrefaction is a mild thermal treatment of biomass under inert environment (Bourgeois and Doal 1984; Lipinsky, 2002), carried out at ~300oC. It produces a fuel that is similar to coal (Prins et al., 2006a).

The common feedstock used is woody biomass, however other sources can be used [Bridgeman et al., 2008]. We have developed an efficient torrefaction technology that was tested with 15 different types of feedstock (various types of woody feedstock, agricultural wastes, and energy crops) and found common behavior if woody biomass is being used. We also

Figure1. Fire and smoldering in biocoal bagged in super-bags at MTU after storage of 3-5 weeks.

20 ENERGY-TECH.com

developed a comprehensive model for torrefaction of woody biomass that has shown to be a powerful tool for the prediction of the properties of the bio-char end-product [Klinger et al.

2015a,b].

The various biocoal types were tested in a combustion chamber in order to determine their NOx, SOx, CO, PAH, and particulates emissions, and to compare them to those of PRB coal. Fouling of biocoal types was also tested but only the woody biomass was tested for slagging. This study utilized a well-developed firing methodology that was used for many coals (Spitz et al., 2007, 2008, Korytnyi et al., 2009).

Pulverized fuel was burned in a 50kW entrained-flow 2-D test facility, and the gases (CO2, O2, CO, NOx, SOx), PAH, LOI, gas temperature and heat flux were measured. Fouling and slagging were also measured as well as emissivities. In the experiments we fired a 400-600 kg pulverized sample.

Results of combustion experiments at 100% biocoal shows very close behavior for gas temperature to that of pulverized coal. However NOx showed a significantly lower emissions than those for coal and can be attributed to the higher volatile matter in the biocoal. These results indicate that there are no expected issues in the behaviour of firing and burning of the biocoal in any boiler, however, the ash behaviour is still to be revealed.

We have developed an efficient torrefaction technology (Bar-Ziv et al., 2015) and constructed three pilot plants based on this technology, in the range of 1-4 ton/hour torrefied biomass production. A torrefaction plant normally comprises: (1) Two-stage shredding of the biomass, coarse and fine, to reach the right size required for torrefaction; (2) drying of the biomass to bone-dry state; (3) fast heating of the biomass feedstock to the desired torrefaction temperature; (4) torrefaction to needed severity (fixed carbon, volatile matter, heat content); (4) grinding; (5) briquetting; (6) storage. We have accumulated thousands of hours of torrefaction operation and maintenance. During these hours we encountered safety events that needed immediate attention and adequate solutions.

The objective of this paper is to present safety considerations related to torrefaction and the various mitigation concepts. By no means is this a final statement to safety issues; it is a portrayal of our experience that might be of help to other in the development of torrefaction.

ASME Power Division Special Section | November 2016

ASME FEATURE ASME Power Division: Fuels & Combustion Technology

A Message from the Chair The FACT committee is committed to providing critical information on the understanding of fuels and combustion systems in traditional and modern utility and industrial power plants, including fuel handling, preparation, processing and by-product emissions controls.

The FACT committee will continue to remain a valuable information resource for ASME

Figure2. Furnace temperature, Water flow rate, and feedstock feed rate vs. time.

Safety considerations and mitigation Fire and smoldering have been observed at torrefaction facilities across the globe. In fact the notion between the torrefaction developers is that there are two groups: “those who had safety events” and “those who will have”. Figure 1 shows fires and smoldering occurring in biocoal super-bags at Michigan Tech after storage of 3-5 weeks. Note that the fire and smoldering occurred even at very cold temperatures (-20 °F) in the upper peninsula of Michigan.

All safety issues that have been encountered can be related to (1) Dust. Any dust of any form (feedstock or torrefiedbiomass dust) is a major safety risk, potentially causing fire and/or explosion. (2) Torrefaction Gases. Torrefaction gas production can be unstable causing severe operation issues that can potentially cause a major safety risk. (3) Biocoal Reactivity.

The reactivity of torrefied-biomass with oxygen in any form November 2016 | ASME Power Division Special Section

members.

The FACT Committee met twice last year, at the Clearwater conference in June in Clearwater, FL and at the recent ASME Power Conference in Charlotte, NC in June, 2016. At the Charlotte meeting, the committee discussed the success of last year’s ASME Power Conference, made recommendations for abstract/paper reviewers for the upcoming meeting in Charlotte Conference (Abstracts due October 19, 2016), selected track/session chairs, and discussed wider participation form the international community in the FACT track. Fuels, combustion and material handling are more important now than ever before as we focus on the global warming from the greenhouse gases, with the major gas being CO2 from power plants. We expect this issue to become even more important as we consider for the energy costs, availability, fuel flexibility, fuel reforming and technology readiness, amongst other parameters. At our Charlotte meeting, the Committee participants discuss the need to increase FACT member participation in committee meetings and attracting new engineers/researchers/students to FACT. I invite everyone with an interest in fuels, combustion, environmental issues, greenhouse gas (CO2) emission, global warming, alternative/biofuels and material handling technologies to join the committee. The FACT committee is a great place to share your industry knowledge, or research experiences for networking opportunities with your peers, and professionals and make you voice heard. The FACT committee also welcomes your active participation in the upcoming ASME Power Conference next June in Charlotte, NC well as your participation in Committee meetings and other activities.

If you are interested in joining, please contact me.

Ashwani K. Gupta Chair, Fuels and Combustion Technologies (FACT) Committee University of Maryland College Park, MD 20742 E-mail: akgupta@umd.edu

ENERGY-TECH.com

21

ASME FEATURE major source of safety hazards and should be prevented, because there will always be reactive torrefied biomass fines. In analogy, pneumatic conveying of coal fines (after grinding) is limited to very short times (seconds) and to temperatures under 65 C, because of the potential release of volatile matter that will react with air. (2) The best practice for conveying of torrefied biomass is with mechanical conveying (augers, belts, buckets ‌). (3) All torrefied-biomass conveying must be conducted under inert atmosphere. Typical inert gases are nitrogen and dry flue gases (after condensing moisture) where fuel was burned at zero excess air and using catalytic converter for controlling CO and VOC. (4) Use of containment devices such, as rotary valves or airlocks, to compartmentalize unit operations is essential in the case of torrefied-biomass to mitigate propagation of safety events. (5) A blower should be attached in locations with potential dust with an outlet to fines removal or filtering devices such a bag filters or cyclones equipped with common explosion precautions. (6) In case all elements dealing with biomass conveying one should have an explosion relief doors with exhaust to the outdoors.

As a consequence we modified all sections concerning biomass/biocoal conveying accordingly: 1. All pneumatic conveying components were replaced by auger conveyors equipped with plenums and blowers to release fine dust with particulate cyclones and bag houses. For example, a few kilograms of fine sawdust dust were collected and removed to the bag filters from one of the new conveying systems after operation with 20 tons of biomass sawdust. This shows how quickly dust could accumulate and propagate to hazardous levels even on a relatively small production scale.

Figure3. Furnace temperature, Water flow rate, and feedstock feed rate vs. time.

(dust, bulk, briquettes) is very high and unless the product is compacted and cooled down to ambient temperature smoldering can occur even after 3-5 weeks of storage.

Dust safety effects Dust is a part of any torrefaction process and cannot be avoided. Safety issues concerning dust are caused at any temperature where fines are floating, suspended, or conveyed in presence of air (for example pneumatically). There are common practices, used in the wood pellet industry, that are applied to prevent or mitigate safety events related to biomass dust and these will not be discussed here.

Safety concerning dust of torrefied biomass is caused by the high reactivity of the bio-char in air. It has been observed from the beginning of the development of biomass torrefaction, this area is relatively new and requires more data; however it is rather clear that: (1) Pneumatic conveying with air could be a 22 ENERGY-TECH.com

2. We use a power generator (in a particular case that produces 40kW power with natural gas), operating at stoichiometric mixture (no excess oxygen) and using the exhaust gases as the inert gas wherever it is required.

Oxygen analyzers were placed and ensured that the oxygen concentration does not exceed 0.5%.

3. We are using the externally heated dryer which means that there is no suspended dust particles contacting the heating fluid, as well as the drying is conducted in inert environment.

The above ensured that MTU has a dust-free environment and consequently removed all risks involving dust reactivity. As a proof, we operated the torrefaction facility for a total of over 1000 hours as a dryer with the above precautions and did not notice any event.

Torrefaction gases As indicated, torrefaction gas production was found to be a major safety risk if it is not controlled. Beyond the issues related to release of the harmful VOCs, the torrefaction gases contain valuable heat that must be integrated into the system. The types and amounts of torrefaction gases strongly depend on many primary factors relating to the feedstock (feedstock type, ASME Power Division Special Section | November 2016

ASME FEATURE

Figure4. Cold briquettes

particle size, moisture content, etc.) as well as process factors such as material feed fluctuations, torrefaction temperature, residence time, reactive atmospheres, etc. These complex thermal-chemical-process interactions often create widely variable and fluctuation amount of torrefaction gases, and heat upon combustion for energy integration. A solution for this issue was adopted at MTU that uses the latent heat of water to absorb excess energy through a water spray into the system's heat management system, and was tested successfully for over 100 hours.

Figure 2 shows three plots during a period where there was very high syngas production and the water atomization system was able to treat it without difficulty. The top plot shows the furnace temperature where at ~3.25 hours the furnace temperature started to rise rather sharply showing immediate response of the water system (middle plot), at the same time.

The syngas production continued to increase rather sharply for 1 hour (from 3.3-4.2 hours), which is noticed by increase of water flow rate from 0.5 GPM to 2.5 GPM, then it started to decrease very sharply between 4.2-4.5 hours, then it stabilized.

Figure 3 shows another three plots during a period where there was moderate syngas production and the water atomization system was able to treat it without any difficulty.

The top plot shows the furnace temperature during 5-hour period (8-13 hours); the furnace temperature was kept constant at 800 °F within 5 °F. The water system (middle plot), at the same time sprayed water as required between 0-0.5 GPM. Note that during this period the feed rate was kept rather constant at about 2400 lb/hr, which yielded 1700 lb/hr of biocoal.

It is essential to indicate that all previous runs prior to installing the water atomization system ended up with terminating the test run because syngas production went out of control. The above results shows further validation of controlling the syngas production rather tightly.

Biocoal reactivity The biocoal reactivity is a major hazard that caused us quite a few smoldering cases. Here we refer to reactivity as the material's tendency to self-heat, or progress through heterogeneous oxidation reactions. Regardless of the solutions tried during hot compaction methods, the material ended up smoldering, for example we indicated above that even after 3-5 weeks biocoal started to smolder in winter.

Our working assumption for this issue is that a slight temperature difference within the biocoal material in a large quantity such as a pile, silo, or a super bag) will eventually smolder because (1) reactivity is very high even at low temperatures, and (2) heat transfer in large quantities is very poor due to a compounding effects of the material's physical properties and inability to dissipate heat quickly through a large pile. This heat will effectively build up, increasing the temperature and the rate by which the heat is generated.

Compaction is a critical aspect of any torrefaction process.

If the compacted material is not cooled to the ambient temperature, it might smolder due to hot spots within the briquette which can cause a safety hazard. To solve the potential for hot spots within the product, we suggest a cold briquetting scheme to ensure that all material has reached ambient temperature. Results for cold briquetting presented here have not had any issue, indicating a good chance for success.

During this entire vigorous change in syngas production the water control system stabilized the furnace temperature (after a few minutes from the initial production) and keeping the furnace temperature constant within 5 °F. It is important to note that during this period the feed rate was kept rather constant at about 2100 lb/hr, which yielded 1500 lb/hr of biocoal.

November 2016 | ASME Power Division Special Section

Numerous cold briquetting tests at MTU with dead wood have indicated measurements of three properties: 1. No swelling of the briquette - the shape of the briquette is identical to the shape of mold in the roller.

2. Durability that is defined as a fall from 20 feet (6 meter) high with no observed damage.

3. Water resistance by soaking the briquette in water for 48 hours.

Figure 4 shows a photo on the left that displays two briquettes, one placed horizontally and the other is placed on its side. The shape of the briquettes are rather nice and does not show any swelling. The photo on the right shows five piles ENERGY-TECH.com

23

ASME FEATURE of biocoal briquettes that we produced by cold briquetting at different conditions. The common denominator of all these briquettes that they all showed high durability according to the 20-feet fall criterion. It should be noted that as in hot briquetting, cold compaction requires the same curing time of about one week, only then we reach maximum durability.

In conclusion, cold briquetting has proven to provide: (1) safe compaction process; (2) high quality briquettes that are durable.

Summary and conclusions Torrefaction can provide a drop-in fuel for traditional fossil coal, however, there are still several safety barriers that require attention prior to development of a mature industry. Primary barriers include: (1) reactive and suspended dust, (2) inconsistent production of energy-baring co-product gases and vapors, and (3) the reactivity of the solid torrefied biomass. After numerous safety scenarios, experience has shown that these barriers can be overcome through adopting best engineering practices including mechanical conveying and dust collection/removal, a rigorous and adapting heat generation and management system, and a cold-compaction methodology for the respective issues. After adopting the reviewed schemes, no further safety issues have been encountered in the production and storage of torrefied biomass. .` References Arias B, Pevida C, Fermoso J, Plaza MG, Rubiera F, Pis JJ Influence of torrefaction on the grindability and reactivity of woody biomass. Fuel Process Technol 2008; 89:169-75. doi:10.1016/j. fuproc.2007.09.002.

Klinger, J., Bar-Ziv, E., & Shonnard, D. (2015). Predicting properties of torrefied biomass by intrinsic kinetics. Energy & Fuels, 29(1), 171176.

Klinger, J., Bar-Ziv, E., Shonnard, D.,Westover,T., & Emerson, R. (2015). Predicting Properties of Gas and Solid Streams by Intrinsic Kinetics of Fast Pyrolysis of Wood. Energy & Fuels, 30(1), 318-325.

Korytnyi E, Saveliev R, Perelman M, Chudnovsky B, Bar-Ziv E. “Computational fluid dynamic simulations of coal fired utility boilers: An engineering tool.” Fuel 88 (2009) 9–18.

Lipinsky, E., Arcate, J, Reed,T., 2002, “Torrefied wood, an enhanced wood fuel”, Fuel Chemistry Division Preprints, 47, pp. 408–410.

Medic D, Darr M, Shah A, Potter B, Zimmerman J Effects of torrefaction process parameters on biomass feedstock upgrading. Fuel 2012; 91:147-54. doi:10.1016/j.fuel.2011.07.019.

Prins, M., Ptasinski, K., Janssen, F., 2006a, “More efficient biomass gasification via torrefaction”, Energy, 31(15), pp. 3458–3470.

Spitz, N., Saveliev, R., Korytnyi, E., Perelman M., Bar-Ziv, E., Chudnovsky, B., "Prediction of Performance and Pollutant Emission from Pulverized Coal Utility Boilers," Chapter 3 in Electric Power: Generation,Transmission and Efficiency, Nova Science Publishers, Inc., 2007. Editor: C. M. Lefebvre, pp. 121-170, Inc. ISBN: 978-160021-979-5.

Bar-Ziv, E., R. Saveliev, and M. Perelman. "Torrefaction Apparatus and Process." US Patent 9193916, 2015. Print.

Bergman, P., Boersma, A., Kiel, J., Prins, M., Ptasinski, K., Janssen, F., 2004, “Torrefaction for entrained-flow gasification of biomass”, in: W.P.M.Van Swaaij,T. Fjällström, P. Helm, A. Grassi (Eds.), Second World Biomass Conference, Rome Italy, 10–14 May 2004.

Bourgeois, J., Doal, J., 1984, “Torrefied wood from temperate and tropical species, advantages and prospects,” in: H. Egneus, A. Ellengard (Eds.), Bioenergy 84,Vol III Biomass Conversion, Elsevier Applied Science Publishers, pp. 153–159.

Bridgeman TG, Jones JM, Shield I,Williams PT Torrefaction of reed canary grass, wheat straw and willow to enhance solid fuel qualities and combustion properties. Fuel 2008; 87:844-56. doi:10.1016/j. fuel.2007.05.041.

Couhert C, Salvador S, Commandré J Impact of torrefaction on syngas production from wood. Fuel 2009; 88:2286-90. doi:10.1016/j. fuel.2009.05.003.

Duncan A, Pollard A, Fellouah H Torrefied, spherical biomass pellets through the use of experimental design. Appl Energy. doi:10.1016/j. apenergy.2012.03.035.

24 ENERGY-TECH.com

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ASME Power Division Special Section | November 2016

MACHINE DOCTOR

Machine Doctor: Is it time to replace a compressor?

By Patrick J. Smith

After a compressor was modified and moved to another facility, there were numerous problems with high vibration.

The problems persisted even after complete rotor cartridges were changed out. This resulted in several unplanned outages, extended downtime and higher operating and maintenance costs. The high costs and uncertainty as to the causes led plant management to ask the question if the compressor should just be replaced.

The causes of turbomachinery vibrations are not always obvious. In some cases the cause does not have to do with internal damage or wear, but something that causes an unstable condition. The purpose of this article is to describe the problem, discuss the root cause analysis and then present the solution.

Introduction This case study pertains to a dual service, integrally geared centrifugal compressor driven by a 3,570 RPM, 350 HP induction motor. The gearbox consists of a bullgear and two rotors. The low speed (LS) rotor consists of a pinion operating at 54,880 RPM with a single overhung impeller. The LS rotor is the 1st stage of the main air compressor (MAC). The high speed rotor (HS) consists of a pinion operating at 75,459 RPM with impellers mounted at each end. The HS rotor comprises the 2nd stage of the MAC and the single gaseous

nitrogen (GAN) compressor stage. All impellers are an open type and run against a close clearance, stationary contour ring.

The compressor configuration is shown in Figure 1.

The pinion journal bearings are an offset, multi-lobe type with squeeze film dampers. There is a single non-contacting proximity type vibration probe adjacent to each bearing. The pinions are also fitted with thrust collars which are used to transmit pinion axial thrust to the bullgear. The thrust bearings are on the bullgear rotor as shown. The bullgear bearings consist of a single ball type antifriction radial bearing on the drive end (DE) and two ball type antifriction combination journal/thrust bearings on the non-drive end (NDE).

This machine uses an electric motor driven mail oil pump and an accumulator for oil back-up.

History This compressor was run for eleven years and was then idled when the plant was shut down. Three years later the compressor was modified and the machine and the plant were moved to a different site. The modifications included a new GAN impeller designed for lower flow, a new main drive motor and new cooler bundles. Neither the bullgear assembly nor the LS rotor cartridge were disassembled and the compressor was not shop tested.

During commissioning a noise was coming from the LS rotor when the compressor was being rotated to check the motor alignment. There appeared to be some small burrs and dings on the bullgear thrust faces. These were stoned, which reduced the noise.

After the compressor was started, the machine sounded okay and initially there were no vibration issues. However, a couple of weeks later there was a rise in the MAC 2nd stage vibration along with an unusual noise. The compressor was shut down and disassembled.

A MAC 2nd stage impeller rub, GAN stage impeller rub and damaged HS pinion gear teeth were discovered.

Figure1. Compressor configuration

November 2016 ENERGY-TECH.com

25

MACHINE DOCTOR The bullgear assembly and HS rotor cartridge were replaced. The bullgear assembly consists of the bullgear, shaft, bearings and bearing housings and the DE oil seal. The HS rotor cartridge consists of the pinion, impellers, bearings, seals and bearing housings.

After the repair the MAC 1st stage vibration was high, but stable. A spectrum analysis showed a large subsynchronous component. See Figure 2. Due to concerns with the elevated vibration the LS rotor was eventually replaced. However, the high vibration and high subsynchronous component persisted.

Because of the repair history, plant management questioned if this machine should be replaced. They were concerned that it would only be a matter of time until there was another problem. The repair history included three incidents where the LS rotor was repaired or replaced, four incidents where HS rotor was repaired or replaced, and four incidents where the bullgear assembly was repaired or replaced.

There were also concerns with the elevated MAC1st stage vibration and high subsynchronous component.

The compressor ran in this condition for almost two years until there was a GAN stage vibration trip. With this compressor frame, it has been observed that high pinion vibrations can result from damaged bullgear bearings. So, it was decided to repair the HS rotor cartridge and replace the bullgear assembly with a spare. However, subsequent inspection of the bullgear assembly showed no damage to the bullgear or the bearings.

After the repair, the compressor vibrations were lower, but two weeks later the machine tripped on high MAC 1ststage vibration. When the machine was disassembled, a light GAN stage impeller rub was also observed. The LS and HS rotor cartridges were sent to the manufacturer and were overhauled. Also, a new bullgear assembly was purchased and installed. A subsequent inspection of the bullgear assembly again showed no damage to the bullgear or the bearings.

An inspection of the LS and HS rotor cartridges showed some light residue in 1ststage pinion bearing and LS pinion teeth, and a minor GAN impeller rub.

When the compressor was restarted the MAC 1st stage vibration was still high, but stable. The MAC 2nd stage and GAN stage vibrations were low. The machine ran for the next six months until there was an unrelated plant trip which also tripped the compressor. On re-start the compressor tripped on high GAN stage vibration. It was decided to replace the bullgear assembly and the LS and HS rotor cartridges. On restart, all the stage vibrations were good. However, subsequent inspection of the bullgear assembly and LS and HS rotor cartridges showed no damage to the bullgear or bearings and no damage to the HS or LS rotor or bearings other than a light GAN stage impeller rub.

26 ENERGY-TECH.com

November 2016

MACHINE DOCTOR

Figure2. First Stage Vibration Spectrum

Root cause analysis Other than the mechanical damage that was discovered during commissioning, inspections of the bullgear assembly and rotor cartridges that were performed after an assembly or cartridge was removed from service did not show any damage except for the light GAN stage impeller rubs. A picture of one of the GAN stage impeller rubs is shown in Figure 3. As seen, there is a light axial blade rub that starts about midway along the blade and extends out to the OD.

The two main problems were a high MAC 1st stage vibration and repeated problems with light GAN stage impeller rubs. Replacing parts was not correcting the problem and it was clear that there wasn’t a good understanding of what was causing these problems, or even if these were problems. Rather than replace the machine, a formal root cause analysis was performed.

After reviewing the history, data and machine design, the following causes were investigated as part of the root cause analysis: • Gearbox distortion • GAN impeller clearance too tight • Machine design

Gearbox distortion The main drive motor is C-face mount type and as such, the motor is supported by a flange off the compressor gearbox. The main drive motor is at the upper end of the size for the compressor frame. However, a review of other compressors showed that this was not the first 350 HP motor installed on this compressor frame and it was not the heaviest. So, this was considered an unlikely contributor.

Figure3. GAN Impeller

GAN impeller clearance too tight A review of the impeller rubs showed that there was contact only along a certain arc on the contour ring. So, it was speculated that the inlet contour ring mounting face could be slightly cocked and not perpendicular

November 2016 ENERGY-TECH.com

27

MACHINE DOCTOR to the rotor centerline. The impeller and contour ring were replaced as part of the original modifications when the compressor was relocated and the contour ring was not replaced during any of the repairs. The clearance between the impeller and contour ring is the manufacturer’s standard clearance for this stage. A review of the impeller rubs showed only light contact and it wasn’t conclusive if the impeller rubs could lead to a change in vibration. It is possible that the rubs were not even a problem. This wasn’t eliminated as a cause, but it was felt that this was less likely a contributing factor.

Machine design The mechanical design of the compressor was also reviewed and no mechanical limits were exceeded. A review of the operating trends did not show that the machine was operated above the design limits and so a machine design issue was eliminated as a contributor.

The LS and HS rotor cartridge bearings are a tilt pad type with a squeeze film damper. As described in the EnergyTech article, “Squeeze Film Dampers for Turbomachinery”, “…In simplest form, the squeeze film damper consists of an inner bearing and an outer bearing. The inner bearing OD is permitted to move radially, but is prevented from spinning, typically by using a loose fitting anti-rotation pin. The inner bearing OD is the bearing journal of the squeeze film damper and it operates against the bearing housing bore which acts as the damper bearing. The gap between the squeeze film damper journal and the damper bearing is filled with a lubricant.

During operation the journal moves due to the rotor dynamic forces and the fluid is displaced to accommodate this motion. As a result hydrodynamic forces are generated in the oil film that is developed between the damper journal and the damper bearing and this helps dissipate vibration energy and lower the forces transmitted to the support structure.”

The compressor that is the subject of this article uses an o-ring type squeeze film damper design. Oil pressure is a key parameter for the squeeze film damper to work properly. A review of the operating trends showed that this compressor was operating on the low end of design pressure range. It was just above the alarm point. It also appeared that the MAC 1st stage vibration loosely correlated with oil pressure. A higher oil pressure seemed to 28 ENERGY-TECH.com

coincide with lower vibration levels. And, a further review of other operating compressors of the same frame showed that this compressor operated at the lowest oil pressure of any other similar compressor in the end users fleet.

As further described in the Energy-Tech article, “Squeeze Film Dampers for Turbomachinery”, if there is something that reduces or eliminates the effectiveness of the squeeze film damper, a high sub synchronous vibration can result. And, in this case, the subsynchronous frequency corresponds to the calculated 1st critical speed. So, it seems plausible that there

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MACHINE DOCTOR could be a larger response from the 1st critical speed due to an issue with the squeeze film damper.

The issue of lower oil pressure was identified previously and the main oil pump was replaced at one point. The oil system also includes an accumulator as the back-up oil supply and the accumulator was also replaced at one point. However, neither resulted in any improvement in oil pressure. Inspections of other components in the oil system did not explain the lower oil pressure.

Discussion It was concluded that the most likely cause of the mechanical problems with this compressor was a malfunctioning squeeze film damper caused by low oil pressure. Although the reason for the low oil pressure was not identified, the mail oil pump motor is being increased in size and speed in order to increase the capacity and oil pressure. A review of the lube oil system did not show any issues with the sizing of any of the other components based on the higher oil flow.

In addition, a new GAN contour ring is being purchased in case there is a machining issue with the existing contour ring that causes it to be “cocked.” The clearance is also being slightly increased. A review of the design does not show there to be a performance problem with a slight increase in clearance.

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Conclusion Experience and history show that high LS and HS rotor vibrations can result from damaged bullgear bearings.

However, in this case, the bullgear assembly, which included new bearings was replaced multiple times and it did not correct the problem. The repair dispositions showed that there has been typically been no bullgear or bullgear bearing damage.

This is a good example of where just changing parts does not correct the problem. An understanding of the machine design is still needed to assist with the root cause analysis in order to come up with an effective corrective action. In this case, some simple, low cost changes will avoid a much more costly compressor replacement .■

References 1. Smith, Patrick J., “Squeeze Film Dampers for Turbomachinery”, EnergyTech Magazine, May 2010.

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 emailing editorial@woodwardbizmedia.com

November 2016 ENERGY-TECH.com

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