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ASME Conference Presenter Attendance Policy and Archival Proceedings

2014;():V001T00A001. doi:10.1115/POWER2014-NS1.
FREE TO VIEW

This online compilation of papers from the ASME 2014 Power Conference (POWER2014) represents the archival version of the Conference Proceedings. According to ASME’s conference presenter attendance policy, if a paper is not presented at the Conference, the paper will not be published in the official archival Proceedings, which are registered with the Library of Congress and are submitted for abstracting and indexing. The paper also will not be published in The ASME Digital Collection and may not be cited as a published paper.

Commentary by Dr. Valentin Fuster

Fuels and Combustion, Material Handling, Emissions

2014;():V001T01A001. doi:10.1115/POWER2014-32022.

Experimental investigations were performed on a non-premixed liquid fuel-lean burner. The present work aims to the development of a methodology for the recognition of flame instability regimes in industrial and aeronautical burners. Instability, in fact, is an unpleasant aspect of combustive system that negatively impacts on combustion efficiency. The online monitoring of the occurrence of instability conditions, permits to adjust combustion parameters (as fuel or air mass flow, temperature, pressure, etc.) and to stabilize again the flame.

High speed visualization systems are promising methods for on-line combustion monitoring.

In this study two high speed visualization systems in the visible range and in the infrared spectral region were applied to characterize combustion efficiency and flame stability.

Different processing techniques were used to extract representative data from flame images.

Wavelet Decomposition and Spectral analysis of pixel intensities of flame images were used for feature extraction. Finally a statistical analysis was performed to identify the most unstable regions of the flame by the pixel intensity variance.

Commentary by Dr. Valentin Fuster
2014;():V001T01A002. doi:10.1115/POWER2014-32031.

PGE in collaboration with EBC and MTU is carrying out a testing program to fire up to 100% of biocoal (torrefied biomass) in its 600 MW Boardman boiler. An important aspect of this program is the selection of suitable biomass feedstock from which biocoal will be produced, emphasizing potential problems of fouling and slagging in the boiler. We thoroughly tested seven different types of feedstock: Arundo Donax (AD), wheat waste, corn waste, woody hybrid poplar, and bark from hybrid poplar, woody pine, and bark from pine. It was found that all these material comprised significant amounts of soil (varying from 5–25% in weight) with low fusion temperatures and therefore must be avoided from flowing into the boiler. We developed a separation technology of the soil from the biomass and were able to obtain biomass feedstock only with the plant minerals. All separated biomass feedstock, from soil, showed mineral content that is respective to soil they grew at. Samples were characterized for ultimate and proximate analysis, ash content and analysis and fusion temperatures. AD, wheat, and corn showed high content of potassium and low flow temperatures and therefore may not be used at 100% firing test unless some of the mineral contents are removed to protect the boiler from corrosion and slagging. Woody and bark hybrid poplar were found to have high fusion temperatures; woody and bark pine showed flow temperatures around 2500°F. All four feedstock types can be used for 100% firing test, however, the ones which is mostly recommended are woody and bark hybrid poplar.

Topics: Feedstock , Biomass , Boilers , Coal
Commentary by Dr. Valentin Fuster
2014;():V001T01A003. doi:10.1115/POWER2014-32036.

As part of PGE-EBC-MTU collaboration of the testing program to fire up to 100% of biocoal in the 600 MW Boardman boiler we produced samples from the seven biomass feedstock: Arundo Donax (AD), wheat waste, corn waste, woody hybrid poplar, and bark from hybrid poplar, woody pine, and bark from pine. The idea was to produce a few thousand tons of biocoal from woody and bark poplar for a 100% firing tests and from the other types to produce a 1000 tons of biocoal from each material that will be co-fired up to 10% with Powder River Basin coal. Biocoal is produced by a torrefaction which is a thermal process carried out in absence of oxygen. We have produced biocoal samples from the above biomass feedstock in two pilot facilities, one in Israel and another in Michigan. The torrefaction process comprises the following steps: (1) shredding and soil separation, (2) drying, (3) torrefaction, and (4) compaction to produce biocoal briquettes. Biocoal briquettes are essential for logistics, safety, operational, and economic considerations. The briquettes must be durable, water resistant and can be pulverized in common coal mills. The briquettes that we produced did indeed conform to these properties. A real operational challenge was working with absence of oxygen which essential for the torrefaction process as well as for safety considerations because the entire process occurs at elevated temperatures which biocoal can burn. A 30,000 t/year torrefaction facility has been constructed at the Boardman Plant site to produce biocoal required for the firing tests.

Topics: Boilers , Coal
Commentary by Dr. Valentin Fuster
2014;():V001T01A004. doi:10.1115/POWER2014-32037.

As part of PGE-EBC-MTU collaboration of the testing program to fire up to 100% of biocoal in the 600 MW Boardman boiler we produced samples from the seven biomass feedstock: Arundo Donax (AD), wheat waste, corn waste, woody hybrid poplar, and bark from hybrid poplar, woody pine, and bark from pine. The various samples of biocoal were tested in a combustion chamber with the following results: (1) Biocoal was fired and burned providing temperature and gas concentration profiles similar to coal. (2) NOx emission from all biocoal originating from any type of biomass feedstock was found to be significantly lower than that from coal burning. (3) SOx emissions was found to correlate directly to sulfur content in the plant minerals, which is very small for all types of biomass tested. (4) Fouling was quite low for all biocoal tested, such that it can be handled with an optimized water cannons procedure. (5) Minerals in the biocoal were found to segregate from the carbon particles which means that slagging propensity can be predicted by the common slagging indices. (6) Carbon cycle analysis revealed significant reduction of CO2 when using these biomass feedstock types, particularly the bark types.

Commentary by Dr. Valentin Fuster
2014;():V001T01A005. doi:10.1115/POWER2014-32055.

Examination of the effect of toluene and carbon dioxide accompanying acid gases (mainly H2S) in the sulfur recovery process is very critical to determine the optimum operating temperature for enhanced sulfur recovery. Experimental and simulation were used to quantify the conversion efficiency with the addition of different amounts of toluene and carbon dioxide/toluene mixtures to the H2S gas stream. The results showed similar trends between predictions and experimental data, which revealed a decrease in conversion efficiency with increase in toluene or carbon dioxide/toluene addition to the H2S gas stream in a reactor. Further simulations were carried out to seek for the effect of toluene and CO2 addition to acid gas stream on the more favorable operating temperature of the reactor. The results showed that toluene increases the optimum reactor temperature at which enhanced sulfur recovery occurs, whereas it reduces the optimum operating temperature in the presence of CO2. The presence of toluene and CO2 in the acid gas stream affects the sulfur recovery efficiency by altering the optimum temperature of the reactor. These results reveal the importance of reactor temperature and its excursion on sulfur recovery in a Claus process. The effect of mean reactor temperature and its role on detailed chemical speciation from within the reactor as well as the role of key species formed in the process on sulfur recovery are presented.

Commentary by Dr. Valentin Fuster
2014;():V001T01A006. doi:10.1115/POWER2014-32056.

Experimental results are presented on the effect of xylene addition to H2S/O2 flames at equivalence ratio of 3.0 (Claus Condition) with respect to H2S and complete combustion of xylene. The results from the combustion of H2S/xylene mixture is compared with the baseline case of 100% H2S combustion to isolate the role of xylene addition in the Claus reactor. Combustion of H2S alone showed a decrease in its mole until it reached to an asymptotic minimum mole fraction value. This resulted in the formation of SO2 to a maximum mole fraction which subsequently decomposed from the formation of elemental sulfur through its reaction with H2S. Addition of small amount of xylene (0.5% and 1%) increased the asymptotic minimum value of H2S as well as the formation of H2 which provided oxidation competition between the formed H2 and H2S. Presence of xylene also triggered the formation of CH4 and CO which provided pathway on the formation of COS and CS2. The oxidation of CH4 and CO by SO2 and other sulfur radicals reduced the maximum mole fraction of SO2 but increased the subsequent rate of SO2 decomposition to increase the formation rate of elemental sulfur. These results show the direct impact of trace amounts of xylene in the feed stream on sulfur formation to reveal direct impact on the Claus reactor performance for sulfur capture.

Commentary by Dr. Valentin Fuster
2014;():V001T01A007. doi:10.1115/POWER2014-32089.

Selective Catalytic Reduction has been well demonstrated as an effective technology for reducing NOx emissions from coal-fired utility boilers. Emerging environmental regulations can have an impact on the traditional design and operation of an SCR system.

Increasing demands on SCR emission reduction performance affects the design of many of the SCR components aside from the catalyst bed. Obtaining an optimal distribution of ammonia reagent in the flue gas stream is a primary requirement for high performance levels. This requirement must be balanced with limited space availability, all while obtaining both robust operation and minimal operating costs. Addressing these issues has led to the development of a variety of ammonia injection and distribution methods. Gas mixer designs, such as the IsoSwirl™ mixer, offer a means to obtain high levels of NOx removal while addressing problematic conditions and featuring simple ammonia delivery systems. Ammonia injection methods may utilize either traditional, vapor-phase techniques or the direct injection of an aqueous ammonia supply which avoids ammonia vaporizer requirements.

Topics: Design
Commentary by Dr. Valentin Fuster
2014;():V001T01A008. doi:10.1115/POWER2014-32114.

Nearly all states now have renewable portfolio standards (RPS) requiring electricity suppliers to produce a certain fraction of their electricity using renewable sources. Many renewable energy technologies have been developed to contribute to RPS requirements, but these technologies lack the advantage of being a dispatchable source which would give a grid operator the ability to quickly augment power output on demand. Gas turbines burning biofuels can meet the need of being dispatchable while using renewable fuels. However, traditional combustion of liquid fuels would not meet the pollution levels of modern dry, low emission (DLE) gas turbines burning natural gas without extensive back-end clean-up. A Lean, Premixed, Prevaporized (LPP) combustion technology has been developed to vaporize liquid ethanol and blend it with natural gas creating a mixture which can be burned in practically any combustion device in place of ordinary natural gas. The LPP technology delivers a clean-burning gas which is able to fuel a gas turbine engine with no alterations made to the combustor hardware. Further, the fraction of ethanol blended in the LPP gas can be quickly modulated to maintain the supplier’s overall renewable quotient to balance fluctuations in power output of less reliable renewable power sources such as wind and solar. The LPP technology has successfully demonstrated over 1,000 hours of dispatchable power generation on a 30 kW Capstone C30 microturbine using vaporized liquid fuels. The full range of fuel mixtures ranging from 100% methane with no ethanol addition to 100% ethanol with no methane addition have been burned in the demonstration engine. Emissions from ethanol/natural gas mixtures have been comparable to baseline natural gas emissions of 3 ppm NOx and 30 ppm CO. Waste heat from the combustor exhaust is recovered in an indirect heat exchanger and is used to vaporize the ethanol as it is blended with natural gas. This design allows for startup on natural gas and blending of vaporized ethanol once the heat exchanger has reached its operating temperature.

Commentary by Dr. Valentin Fuster
2014;():V001T01A009. doi:10.1115/POWER2014-32150.

Turbulent statistics and energy budgets were calculated for a swirling turbulent flow using Generalized Feed Forward Neural Network (GFFNN) in a dump combustor model. Knowledge of turbulent statistics and energy budgets of fluid flow inside a combustor model is very useful and essential for better and/or optimum designs of gas turbine combustors. Several experimental techniques utilizing two dimensional (2D) or three dimensional (3D) Laser Doppler Velocimetry (LDV) measurements provide only limited discrete information at given points; especially, for the cases of complex flows such as dump combustor swirling flows. For these flows, numerical interpolating schemes are unsuitable. Recently, neural networks proved to be viable means of expanding a finite set of experimental measurements in order to enhance the understanding of complex phenomenon. This investigation showed that artificial neural networks are suitable for the prediction of turbulent swirling flow characteristics in a model dump combustor. These techniques are proposed for better designs and/or optimum performance of dump combustors.

Commentary by Dr. Valentin Fuster
2014;():V001T01A010. doi:10.1115/POWER2014-32160.

Gasification is a technologically advanced and environmentally friendly process for solid waste treatment. The chemical reactions in the gasification process highly depend on the agents’ flow rates which, due to fluid dynamics and thermodynamics, are in fact functions of particle size and structure. Therefore, in order to obtain a better prediction model, it is important to determine the effect of particle size on the operation of a gasification system. The purpose of this research is to investigate the effect of particle size of some common solid waste on the gasification process. Specimens including starch and polyethylene of different sizes are investigated experimentally. To achieve the aim, the gasification processes are monitored by a thermal gravimetric analysis system. The mass change and the heat flow are measured in real time during the reaction. Comparison between the experimental results and different gasification models are made. Based on the experimental results, the effect of particle size was studied and the importance of the porous structure was revealed. The relationship between particle size and porous structure during gasification was developed.

Commentary by Dr. Valentin Fuster
2014;():V001T01A011. doi:10.1115/POWER2014-32162.

Co-utilization of coal and lignocellulosic biomass has the potential to reduce greenhouse gases emission from energy production. As a fundamental step of typically thermochemical co-utilization (e.g., co-combustion, co-gasification), co-pyrolysis of coal and lignocellulosic biomass has remarkable effect on the conversation of the further step. Thermal behavior and kinetic analysis are prerequisite for predicting co-pyrolysis performance and modeling co-gasification and co-combustion processes. In this paper, co-pyrolysis behavior of a Chinese bituminous coal blended with lignocellulosic agricultural residue (wheat straw collected from north of China) and model compound (cellulose) were explored via thermogravimetric analyzer. Bituminous coal and lignocellulosic agricultural residue were heated from ambient temperature to 900 °C under different heating rates (10, 20, 40 °C·min−1) with various mass mixing ratios (coal/lignocellulosic agricultural residue ratios of 100, 75/25, 50/50, 25/75 and 0). Activation energy were calculate via iso-conversional method (eg. Kissinger-Akahira-Sunose, Flynn-Wall-Ozawa and Starink methods). The results indicated that pyrolysis rate of coal was accelerated by wheat straw under all mixing conditions. Cellulose promoted the pyrolysis rate of coal under equal or lesser than 50% mass ratio. Some signs about positive or passive synergistic effect were found in char yield. Char yields were lower than that calculated from individual samples for bituminous coal and wheat straw. With the increasing of cellulose mass ratio, the positive synergies on char yields were reduced, resulting in passive synergistic effect especially under higher coal/cellulose mass ratio (25/75). Nonlinearity performance was observed from the distribution of activation energy.

Topics: Coal , Pyrolysis
Commentary by Dr. Valentin Fuster
2014;():V001T01A012. doi:10.1115/POWER2014-32193.

Previous work conducted by the authors showed that for a stoichiometric inlet fuel-oxidizer ratio at 1 atm and 1200 K, an optimal range of exergetic efficiency exists for H2 combustion when singlet oxygen composes 0–20% of the oxidizer; with the maximum occurring at approximately 10%. Additionally, in the optimal range, 60% of the total exergy destruction occurs before ignition. These results provide encouraging evidence that it is possible to improve the exergetic efficiency of combustion inherently and thereby reduce fuel usage for a desired energy transfer. The focus of this study is to determine if the exergetic efficiency of combustion can be further optimized by varying other combustion parameters in addition to the inlet concentration of singlet oxygen.

The chemical kinetics simulation was accomplished by developing an adiabatic plug flow reactor model in CHEMKIN-PRO® and employing the Moscow State University H2-O2 mechanism. The ranges of parameters considered were: equivalence ratio 0.7–1.3, inlet temperature 1100–1300 K, inlet concentration of singlet oxygen 0–20%, and diluent type (Ar, N2, no dilution). Pressure was held fixed at 1 atm. The calculated quantities were: exergetic efficiency, exergy destruction before ignition, molar conversion of H2, exit temperature, ignition temperature, and ignition distance.

Results of the study show that over the optimum range the maximum exergetic efficiency occurs for an equivalence ratio of 1.3, with no dilution at 1300 K. Furthermore, the data show that for 20% inlet singlet oxygen there is significant variability in exergy destruction before ignition, ignition temperature, and ignition distance. Understanding how varying traditional combustion parameters impacts the enhancing effect that singlet oxygen has on the exergetic efficiency of H2 combustion provides a framework for directing future research efforts for hydrocarbon combustion under a broader range of operating conditions of practical engineering interest.

Topics: Combustion , Oxygen
Commentary by Dr. Valentin Fuster
2014;():V001T01A013. doi:10.1115/POWER2014-32215.

The results from the observed combustion behavior of propane over platinum and rhodium catalysts in a meso-scale heat recirculating combustor are presented. The extinction limits, conversion, product selectivity/yield, and activation energy using the two catalysts were compared in an effort to determine their performance using a liquid fuel. The extinction limits were also compared to those of non-catalytic combustion in the same reactor. The results showed that the addition of a catalyst greatly expanded the range of stable operating conditions, in respect to both extinction limits and flow rates supported. The Rh catalyst was found to exhibit a higher propane conversion rate, reaching a maximum of 90.4% at stoichiometric conditions (as opposed to the 61.4% offered by the Pt catalyst at lean conditions); however, the Pt catalyst had superior CO2 selectivity for most studied conditions, indicating higher combustion efficiency. The Pt catalyst also had a significantly smaller activation energy (13.8 kJ/mol) than the Rh catalyst (74.7 kJ/mol), except at equivalence ratios richer than Φ = 1.75 (corresponding to catalyst temperatures below 500 °C), where it abruptly changed to 211.4 kJ/mol, signifying a transition from diffusion-limited reactions to kinetically limited reactions at this point. The results reveal that Rh would be a more suitable catalyst for use in a liquid-fueled meso-scale combustor, as fuel conversion has been shown to be a limiting factor for combustion stability in these systems.

Commentary by Dr. Valentin Fuster
2014;():V001T01A014. doi:10.1115/POWER2014-32230.

This paper examines the gasification of woody biomass pellets and torrefied wood pellets at different temperatures using air or CO2 as the gasifying agents. The woody biomass pellets were pyrolyzed and gasified in a controlled reactor facility that allowed for the determination of sample weight loss as a function of time from which the kinetics parameters were evaluated. The experimental facility provided full optical access that allowed for in-situ monitoring of the fate of the biomass pellets and the release of gas phase under prescribed high temperature condition. Pellet sample of known weight was placed in a wire mesh cage and then introduced instantly into the high temperature zone of the reactor at known temperature and surrounding gas composition as gasifying agent. The weight loss as function of time was examined for different gasification temperatures ranging from 600–950°C using air or CO2 as the gasifying agent. Significant differences in the weight loss were observed to reveal the fundamental pyro-gasification behavior between the wood and torrefied wood pellets. The results show enhanced gasification with air at low to moderate temperatures while at high temperatures the oxygen evolved from CO2 provided a role in oxidation. The calculated activated energy was lower for woody pellets than torrefied wood pellets and it was lower with air than CO2. These kinetic parameters help in modeling to design biomass gasifiers and combustors for increased conversion efficiency and performance using biomass or municipal solid waste pellets.

Commentary by Dr. Valentin Fuster
2014;():V001T01A015. doi:10.1115/POWER2014-32252.

The results obtained from the modeling of thermal partial oxidation of kerosene based Jet-A fuel are presented using one dimensional chemical modeling. Two detailed kinetic models for alkenes chemistry ranging between C8 to C16 were evaluated and compared against experimental data of thermal partial oxidation of Jet-A fuel. The key difference between these two kinetic models was the inclusion of model for soot formation reactions. Chemical modeling was performed using dodecane to represent Jet-A fuel.

The results showed that the model with soot reactions was significantly more accurate in predicting reformate products from Jet-A. In particular, the formation of carbon monoxide, methane and acetylene closely followed the experimental data with the model that included soot formation reactions. The results revealed that the soot formation reactions promoted the smaller hydrocarbons to decompose via the alternate kinetic pathways and from additional radical formation. The results also reveal that the inclusions of soot formation reactions are critical in the modeling of thermal partial oxidation of fuels for fuel reforming.

Topics: Modeling , oxidation , Soot
Commentary by Dr. Valentin Fuster
2014;():V001T01A016. doi:10.1115/POWER2014-32258.

Recent discoveries of vast natural gas reserves in the United States have led to increased domestic natural gas production, resulting in lower prices. Utility and large industrial facilities are performing solid fuel conversions on their boilers to natural gas as a cost-effective and efficient fuel solution. Natural gas is not only economically beneficial but also environmentally efficient with cheaper prices and reduced SO2, NOx, and CO2 emissions. The Environmental Protection Agency (EPA) has recently released mandatory requirements that directly affect the cost effective operation of solid fuel boilers, resulting in natural gas becoming a more economically appealing choice of fuel for facility operators.

As more facilities consider boiler fuel conversions, it is important to understand all facets of the conversion, from the thermal evaluation of the boiler, to the complete design, supply and installation of the new firing system. Zeeco will provide specific details and recommended practices from a recent Circulating Fluidized Bed (CFB) Boiler solid fuel conversion to natural gas application designed for 1.3 billion Btu/hr of heat input for the maximum continuous steam rating. The information will detail the boiler conversion from a solid fuel fluid bed to a 100% natural gas fired boiler design. Thermal performance results, design and supply of the complete new gas firing system, and installation conversion assistance for the boiler modifications and firing system installation details are also provided.

Commentary by Dr. Valentin Fuster
2014;():V001T01A017. doi:10.1115/POWER2014-32263.

The state of Maryland issued a Request for Proposal to solicit exportable electrical power using locally sourced poultry littler as the primary fuel. The overall goal was to promote the use of renewable energy and reduce agricultural runoff to Chesapeake Bay. POWER Engineers (POWER) was brought on to the project team by the selected development contractor to provide a preliminary level design and high level cost estimate for the feasibility study and technology investigation. POWER’s scope included:

• Preliminary engineering for boiler technology selection and sizing

• Selection of fuel handling equipment and logistics

• Providing an air emissions estimate

• Water quality and demand requirements

• Developing an engineering and construction cost estimate

POWER determined that to produce 20.4 MW of electricity and process steam, it would take roughly 60 truckloads of 100% poultry litter waste-per-day to run the plant. The bubbling fluidized bed boiler technology developed by ANDRITZ for biomass applications and fully automated fuel handling system would make this biomass plant the first-of-its-kind in the United States. POWER’s team was able to reach out into new and different areas of technology and take a new approach to biomass facility design.

Commentary by Dr. Valentin Fuster
2014;():V001T01A018. doi:10.1115/POWER2014-32290.

Chemical-looping combustion holds significant promise as one of the next generation combustion technology for high-efficiency low-cost carbon capture from fossil fuel power plants. For thorough understanding of the chemical-looping combustion process and its successful implementation in CLC based industrial scale power plants, the development of high-fidelity modeling and simulation tools becomes essential for analysis and evaluation of efficient and cost effective designs. In this paper, multiphase flow simulations of coal-direct chemical-looping combustion process are performed using ANSYS Fluent CFD code. The details of solid-gas two-phase hydrodynamics in the CLC process are investigated by employing the Lagrangian particle-tracking approach called the discrete element method (DEM) for the movement and interaction of solid coal particles moving inside the gaseous medium created due to the combustion of coal particles with an oxidizer. The CFD/DEM simulations show excellent agreement with the experimental results obtained in a laboratory scale fuel reactor in cold flow conditions. More importantly, simulations provide important insights for making changes in fuel reactor configuration design that have resulted in significantly enhanced performance.

Commentary by Dr. Valentin Fuster

Steam Generators

2014;():V001T02A001. doi:10.1115/POWER2014-32080.

A method for determining time-optimum fluid temperature changes is presented. In contrast to present standards, two points at the edge of the opening are taken into consideration. The optimum fluid temperature changes are assumed in the form of a simple time function. It is possible to increase the fluid temperature stepwise and then the fluid temperature can be increased with a constant rate at the beginning of the heating process. Due to the stepwise increase in fluid temperature, heating time of a thick-walled component is of the same order as in the case of calculations according to EN 12952-3 European Standard, but the total circumferential stresses on the edge of the hole do not exceed the allowable value.

Topics: Pressure , Boilers , Heating
Commentary by Dr. Valentin Fuster
2014;():V001T02A002. doi:10.1115/POWER2014-32093.

A numerical method for modeling actual steam superheaters is presented. The finite volume method was used to determine flue gas, tube wall and steam temperature. The numerical technique presented in the paper can especially be used for modeling boiler superheaters with a complex tube arrangement when detail information on the tube wall temperature distribution is needed. The method of modeling the superheater can be used both in the design, performance as well as in upgrading the superheaters. If the steam temperature at the outlet of the superheater is too low or too high, the designed outlet temperature can be achieved by changing a flow arrangement of the superheater. For example, the impact of the change of the counter to parallel flow or to mixed flow can be easily assessed. The presented method of modeling is a useful tool in analyzing the impact of the internal scales or outer ash fouling on the superheater operating conditions. Both ash deposits at the external and scales at the internal surfaces of the tubes contribute to the reduction of the steam temperature at the outlet of the superheater. Furthermore, scale deposits on the inner surface of the tubes cause a significant temperature rise and may lead to the tube damage. The higher temperature of the flue gas over a part of parallel superheater tubes increases the steam temperature and decreases steam mass flow rate through the tubes with excessive heating. This results in an additional increase in the steam temperature at the outlet of the superheater.

Commentary by Dr. Valentin Fuster
2014;():V001T02A003. doi:10.1115/POWER2014-32106.

Waterside Deposits in evaporator tubes have been an issue in steam generators as long as boilers have been used. Substantial experience in deposit formation and management has been gained in conventional goal and oil/gas boilers over time. The role of boiling modes in the steam generator tubes is very critical to areas of deposit formation. Incipient boiling, nucleate boiling and convective boiling modes all have different deposition behavior. When Gas Turbine Combined Cycle (GTCC) power plants of larger size (> 100 MW) began operation in the 1990’s, deposits in evaporator tubes were not considered a significant issue. Operating boiler pressures were low (500–900 psig) as were flue gas temperatures, use of supplemental firing was limited. Other than known problems with feedwater contamination such as operation with leaking seawater-cooled condensers, deposits were not found to be forming. The rapid increase in size and operating pressures in HRSG’s raised the likelihood of waterside deposits developing. Both Vertical and Horizontal Gas Path HRSG designs are considered. Drawing on field observations, the morphology and location of HRSG deposits are reviewed, as are changes in deposit formation with the mode and rate of boiling.

Commentary by Dr. Valentin Fuster
2014;():V001T02A004. doi:10.1115/POWER2014-32112.

We Energies Oak Creek Power Plant units 5 and 6 were designed and built with no main steam temperature control mechanism. We Energies wanted to add desuperheaters to the units and do so in the simplest and most cost effective manner. Previous proposed solutions were deemed too expensive or potentially unreliable. The selected option from Alstom Power utilized the unique design elements of the boilers and offered up the temperature control required. The new desuperheater system has positively affected plant startup and normal operation of these boilers.

Topics: Power stations
Commentary by Dr. Valentin Fuster

Heat Exchangers and Cooling Systems

2014;():V001T03A001. doi:10.1115/POWER2014-32008.

The purpose of this paper is to show how compact heat exchanger technology can offer energy savings and hence cycle efficiency improvements on new and existing gas turbine installations by being utilised for fuel gas heating.

After a brief introduction to high temperature compact heat exchanger technology and comparison to traditional equipment, thermodynamic cycle analysis for a combined cycle gas turbine plant (CCGT) is used show the advantages of compact technology over conventional technology, analysing the fuel gas heating, to illustrate the overall savings. A case study is used to demonstrate an increase in net LHV electric efficiency in the range of 0.5 to 1.17 % achievable using high effectiveness compact diffusion bonded heat exchangers in fuel gas heating. Intermediate pressure and high pressure feed water heating is considered for increasing the fuel gas inlet temperature to the combustor. The model is built in Excel and is extended to a capital expenditure overview based on new or a retrofitting in existing plants.

Commentary by Dr. Valentin Fuster
2014;():V001T03A002. doi:10.1115/POWER2014-32010.

Degraded performance of a steam surface condenser will directly affect the availability and operational efficiency of any power plant, and this in turn will always impact plant optimization. Results of eddy current testing, loss of surface area through excessive numbers of plugged tubes or turbine blade failure, life extension studies, extended power uprates, the general effects of erosion and corrosion, etc. — these are all examples of issues that may lead to the replacement of tubes, tubesheets and/or waterboxes at some point during the operational life of a power plant steam surface condenser.

Retubing, and the modular replacement of existing condenser tube bundles, are two options available to power plant owners & operators that can help to regain lost performance, and even in some cases improve on the original unit design. However, the use of different tube materials and wall thickness for retubing, as well as different tube diameters and quantities for modular replacements; means that these changes must be accompanied by the necessary detailed evaluation of the impact to the original design.

In addition to Tubes, it may also be necessary to replace existing Tubesheets and/or even Waterboxes. This work scope should always include a detailed review of the possible impacts of any changes due to these replacements. Failure to perform the necessary thermal and mechanical evaluations can lead to additional operational issues that may also impact unit performance & longevity.

Commentary by Dr. Valentin Fuster
2014;():V001T03A003. doi:10.1115/POWER2014-32030.

The turnkey repowering conversion of any existing steam surface condenser, from operation within a traditional steam plant Rankine cycle to that of Combined Cycle configuration, includes a great number of detailed and complex thermal & mechanical design, modification, installation and operational challenges to be considered and overcome. Indeed, it may not always be possible to even consider the reuse and conversion of an existing steam surface condenser from a traditional Rankine cycle to Combined Cycle operation due to one, or more, existing limitations. The purpose of this paper, through case studies, is to showcase the entire process of the determination and subsequent implementation of the minimum requirements for the modification and refurbishment of two steam surface condensers at existing power plant facilities.

Commentary by Dr. Valentin Fuster
2014;():V001T03A004. doi:10.1115/POWER2014-32113.

Section 316(b) of the Clean Water Act requires plants with intake flows of over 2 million gallons of water per day taken from the waters of the United States to implement the “best available” technology to reduce injury and death of fish and other aquatic life that may be impinged on or entrained in the intake. The two options commonly identified to address 316(b) are closed cycle cooling and fish screens. A third option that is often overlooked and may be less expansive is to implement changes in the plant, allowing it to operate with less condenser circulating water (CCW) flow.

Most CCW systems of power plants were originally designed to achieve an economic optimum balance between capital cost and the operating benefit of a lower main condenser (MC) pressure with the resulting increased electrical output. For those plants that are located on rivers, lakes, and oceans where CCW was abundant and free, economics often dictated high CCW flows impelled by low-head pumps and MC’s designed with minimal surface areas, as larger MC’s were not justified on the basis of economics. The passage of Section 316(b) of the Clean Water Act suggests a new look at the existing CCW system design for many plants with the goal of reducing the required CCW flow rate. In some instances simply reducing the CCW flow rate may be sufficient to meet 316(b) requirements. In other cases, the reduction of CCW flow may significantly reduce the capital and operating cost of adding cooling towers and/or fish screens.

This paper investigates ways to reduce the required CCW flow to existing power plants by redesigning and modifying the existing CCW system based on current technology. The result could be a new, improved, MC and other turbine cycle equipment and perhaps new CCW pumps, resulting in the same or better plant performance. The paper presents case studies in which the CCW systems for two power plants are redesigned to reduce the CCW flow.

Commentary by Dr. Valentin Fuster
2014;():V001T03A005. doi:10.1115/POWER2014-32157.

This paper offers numerical modelling of a waste heat recovery system. A thin layer of metal foam is attached to a cold plate to absorb heat from hot gases leaving the system. The heat transferred from the exhaust gas is then transferred to a cold liquid flowing in a secondary loop. Two different foam PPI (Pores Per Inch) values are examined over a range of fluid velocities. Numerical results are then compared to both experimental data and theoretical results available in the literature. Challenges in getting the simulation results to match those of the experiments are addressed and discussed in detail. In particular, interface boundary conditions specified between a porous layer and a fluid layer are investigated. While physically one expects much lower fluid velocity in the pores compared to that of free flow, capturing this sharp gradient at the interface can add to the difficulties of numerical simulation. The existing models in the literature are modified by considering the pressure gradient inside and outside the foam. Comparisons against the numerical modelling are presented. Finally, based on experimentally-validated numerical results, thermo-hydraulic performance of foam heat exchangers as waste heat recovery units is discussed with the main goal of reducing the excess pressure drop and maximising the amount of heat that can be recovered from the hot gas stream.

Commentary by Dr. Valentin Fuster
2014;():V001T03A006. doi:10.1115/POWER2014-32165.

This paper describes design and optimization of a Waste Heat Recovery Unit (WHRU) for a power cycle which uses CO2 as a working fluid. This system is designed for offshore installation to increase gas turbine efficiency by recovering waste heat from the exhaust for production of additional power. Due to severe constraints on weight and space in an offshore setting, it is essential to reduce size and weight of the equipment to a minimum. Process simulations are performed to optimize the geometry of the WHRU using different objective functions and thermal-hydraulic models. The underlying heat exchanger model used in the simulations is an in-house model that includes the calculation of weight and volume for frame and structure for the casing in addition to the thermal-hydraulic performance of the heat exchanger core. The results show that the for a set of given process constraints, optimization with respect to minimum total weight or minimum core weight shown similar results for the total installed weight, although the design of heat exchanger differs. The applied method also shows how the WHRU geometry can be optimized for different material combinations.

Commentary by Dr. Valentin Fuster
2014;():V001T03A007. doi:10.1115/POWER2014-32217.

American Exchanger Services, Inc (AM-EX) performed a 2012 repair of a vertical head-up High Pressure (HP) Feedwater Heater breech lock channel during a shop based re-tube for the American Electric Power (AEP) Wilkes Power Plant, Unit 1. The 48 year old channel is a carbon steel cup-forging that had 1-1/2″ deep circumferential cracks extending radially into the tight knuckle radius at the channel barrel to tubesheet junction. A small area was also found on the backside of the tubesheet which had corroded to a depth of 7/16″.

Several methods to repair these types of failures may be employed, such as grinding out the crack and weld repair, grinding or machining out the crack, leaving as is and performing regular inspections and monitoring crack propagation, or leave as is and perform a fitness for service analysis (API 579-1/ASME FFS-1). A repair was chosen that reduced the stresses in the highly stressed corner radius and was validated using modern calculations. The channel barrel was in the re-tube process so immediate access to a vertical lathe was available and this, in part, lead to the crack removal approach. The design alteration was to machine a pocket to completely remove the crack, verify tubesheet stresses are within allowable stress limits by Finite Element Analysis (FEA), and prescribe future Nondestructive Examination (NDE) to monitor potential future cracking. The size of the machined “pocket” was determined by the actual crack length “as measured” and the repair was verified using FEA. The machined pocket was Dye Penetrant Tested (PT) in September of 2013 (after approximately one year of returning to service), and no defects were noted.

This is not a new repair method; in fact it was researched by Electric Power Research Institute (EPRI) in 1988 symposium [1], and based on an EPRI 1985 [2] similar repair. In the 1985 repair similar methods of FEA were employed, however using less sophisticated forms of the calculation. Modern computing allows for 3D analysis with more complex geometries, and more conservative meshing. This analysis demonstrates that the earlier papers were correct in their understanding of the problem and the proposed solutions. The Wilkes HP feedwater heater was repaired in a similar manner with a machined radius that sufficiently reduced stresses to safe levels allowing an alteration of the vessel to be in compliance with National Board Inspection Code (NBIC) [3] and American Society of Engineers Boiler and Pressure Vessel Code (ASME B&PV CODE) [4].

Commentary by Dr. Valentin Fuster
2014;():V001T03A008. doi:10.1115/POWER2014-32248.

Westinghouse Electric Company and Tranter Inc. are collaborating to develop the modular, low-pressure horizontal shell and plate feedwater heater (SPFWH™) heat exchanger product. This design utilizes easily removable modules of welded heat transfer plates within a pressure vessel instead of traditional tubes as the pressure boundary and heat transfer interface between the steam and feedwater. Design advantages include improved long-term performance, inspection and maintenance access. Each SPFWH™ heat exchanger will be designed to meet all plant-specific requirements and is ASME Section VIII compliant.

A prototype SPFWH™ heat exchanger design (herein called the prototype or test unit) was fabricated and tested to validate the functionality of the design features and benchmark the correlations used to predict the performance. The test was performed in the Tranter Inc. laboratory facility using full temperature and pressure steam conditions over a broad operating range typical of low pressure feedwater heaters.

Heat transfer coefficient characteristics have been evaluated and the prototype test data shows good agreement with established empirical correlations and other industry research. These results indicate that the SPFWH™ heat exchanger design is a viable alternative to a shell-and-tube type heat exchanger due to the performance, compactness, modularity, and robustness of the new design.

Commentary by Dr. Valentin Fuster
2014;():V001T03A009. doi:10.1115/POWER2014-32249.

In power plant locations with adequate supply of cooling water the steam from the steam turbine is condensed in a water cooled condenser. In most instances circulating water from the cooling tower is used to condense the turbine exhaust steam. In other instances once through cooling is deployed wherein water from a lake, river or sea is used to condense the turbine exhaust steam. In water challenged locations or locations where wet cooling cannot be deployed due to permitting or regulatory issues, the steam from the steam turbine is condensed in an air cooled condenser (ACC) wherein ambient air is used to cool and condense the turbine exhaust steam. In a combined cycle plant, during normal operation, the water or air cooled condenser condenses the turbine exhaust steam. During bypass operation, when the steam turbine is out of service, the high-pressure steam from the HRSG is attemperated in a pressure reducing/desuperheating (PRD) valve and then admitted into the water cooled or air cooled condenser. The bypass steam flow is substantially higher than the design turbine exhaust steam flow and the duration of bypass operation can vary from a few hours to several weeks.

The requirements for admission of bypass steam into a water cooled condenser are substantially different from that for an air cooled condenser. In a water cooled condenser the bypass steam is admitted in the steam dome. The bypass steam as well as the turbine exhaust steam is condensed outside the tubes. In an air cooled condenser the bypass steam is admitted in the large diameter steam duct. The bypass, as well as the turbine exhaust steam (normal operation), is condensed inside the tubes. There are similarities and differences in the requirements for admission of bypass steam into a water cooled and air cooled condenser. The differences must be identified and addressed to ensure safe and reliable performance of the condenser.

Commentary by Dr. Valentin Fuster
2014;():V001T03A010. doi:10.1115/POWER2014-32274.

Eddy Current Testing (ECT) of condenser tubes is essential to maintaining good plant reliability and availability. Early identification of defects can allow for adequate remedial action and prevent forced outages caused by condenser tube leaks. The well-known catastrophic failure in the nuclear industry in Japan has not only raised concern in Japan over aging nuclear power plants, but has also raised concern over safe operations in the United States and around the world. Ongoing reliability and instability issues due to reported leaks in condensers have also been the topic for nuclear watchdogs. This focus on the nuclear plant condenser has brought to light the various levels of sophistication and capability in ECT.

In ECT, the type of defect present in a condenser tube is determined by the characteristics it presents under test. The tubes must be adequately cleaned prior to testing and some awareness or evidence of the type of defect to be uncovered should be available to the testing team. In cases where defects are discovered that are inconsistent with prior awareness further exploratory testing is common. Exploratory testing can proceed to test areas of suspected defects in the tubing, and it may result in a complete redefinition of the test procedure, inclusive of instruments, probe types and other key ECT criteria. A comprehensive knowledge of testing options and their practical application is necessary to redefine a test that will yield meaningful results and achieve the intended objective; to identify the type and extent of defect and take remedial action therefore preventing failure.

This paper addresses such a case at the South Texas Project (STP) Nuclear Power Plant where peculiar defects were undeterminable under standard ECT procedures. The defects continued to negatively impact reliability and stability at the plant until a new ECT process and test procedure were developed, demonstrated and deployed. The result achieved was accurate defect detectability and improved nuclear plant reliability.

Commentary by Dr. Valentin Fuster
2014;():V001T03A011. doi:10.1115/POWER2014-32275.

Operating temperature information was gathered using thermocouples installed on the outside of an existing high pressure feedwater heater (FWH). The operating data was collected to demonstrate the basis for the evaluation of the operational effectiveness of the heater especially during rapid load changes. This information provides insight into the selection of shell side design temperatures of the skirt and shell sections of a feedwater heater. This direct measurement of the temperature was useful in evaluating the appropriateness of both skirt and shell design temperatures selected by standard HEI practice. Also, consideration will be given to upgraded turbines and their impact on the design temperatures and pressures of existing FWH(s).

Commentary by Dr. Valentin Fuster

Turbines, Generators and Auxiliaries

2014;():V001T04A001. doi:10.1115/POWER2014-32043.

As a high-speed rotating part, forced convection of the surface of rotor is high-intensity when steam turbine is running. The thermal state of the rotor directly affects the distribution of the stress and vibration characteristics. In order to effectively monitor and control the thermal state of the rotor, heat transfer coefficient must be quickly and accurately calculated. Typically, different manufacturers select different empirical formulas and the calculated values vary greatly. Combining with empirical formulas, the accuracy of steam turbine rotor surface heat transfer coefficient is improved, so that the results become closer to the numerical calculation values, then also result in analyzing the thermal state of rotor more precisely. Taking a certain 300MW turbine rotor as an application, the heat transfer coefficients of rotor are analyzed and calculated. And the improved method can be also applied in a 600MW steam turbine rotor.

Commentary by Dr. Valentin Fuster
2014;():V001T04A002. doi:10.1115/POWER2014-32072.

Over the last decade, the Author’s company (Alstom Power) has retrofitted the steam turbines in 34 nuclear units on a diverse range of half and full-speed machines, powered by Pressurised and Boiling Water Reactors. Some of those projects have been described in other papers, with an explanation of the novel laser measurement and fast-track installation techniques that have been developed to meet the onerous demands of nuclear plants and authorities.

The ageing global nuclear fleet has suffered reduced levels of reliability and performance due to effects such as Stress Corrosion Cracking (SCC), moisture erosion and shaft line torsional faults. Alstom has developed a range of steam turbine retrofit solutions that are resistant to SCC and erosion, have extended maintenance intervals and deliver high levels of efficiency. A portfolio of rear stage blades is available, from which an optimum design can be selected to suit each project.

This paper focuses on the improvements in thermal performance and reliability of a number of recent nuclear steam turbine retrofits. It outlines the existing designs and some of the challenges faced by the plants concerning reliability, operation and efficiency and then describes the approach to addressing those issues by retrofitting with modern designs. The paper describes the blading design and the techniques which are used to evaluate exhaust performance. It will also show the methods which have been used to integrate longer Last Stage Blades into existing LP frames.

The paper concludes by presenting the experience, in terms of performance and installation, of some of the projects.

Commentary by Dr. Valentin Fuster
2014;():V001T04A003. doi:10.1115/POWER2014-32101.

Reactive power is an unwanted but unavoidable part of alternating current electric power delivery systems. Governed by the laws of physics, it occurs due to the inherent nature of the components of these systems. This article develops an understanding of reactive power and the control of it to reduce its adverse effects and to improve the efficiency of an electric power delivery system.

The article begins by identifying and representing electric power circuit components, real power, and reactive power. These are then mathematically shown how they interact and affect the power delivery system.

Control and mitigation of the effects of reactive power are then developed with emphasis on mechanical solutions using rotating machines. In particular, peaking or retired generators are identified for use as rotating condensers as well as new installations. A description of the gear type synchronous self-synchronizing (SSS) overrunning clutches used to connect and dis-connect a generator from the peaking prime mover or the retired generator from a starting system is included.

Topics: Generators
Commentary by Dr. Valentin Fuster
2014;():V001T04A004. doi:10.1115/POWER2014-32273.

Online social networking communities can help strengthen professional ties among members of almost any profession. How useful they are to the engineering professions in contributing to the process of intergenerational knowledge transfer depends on the site. Prior to the popularity of online communications and networking tools such as Facebook, Twitter and Linked In, Power Industry engineers have utilized with varying success a number of knowledge transfer facilitation tools, both within their companies and outside them. This paper will discuss the pros and cons of both traditional and emerging methods and present specific examples that address technical issues, learning styles, differences in generational approaches to learning and communication. Issues relating to global needs in the engineering profession, organizational flexibility, the ability of people and organizations to adapt and change, and educational and workforce challenges will also be discussed. Short case studies illustrating various solutions for addressing some of these issues, including development of useful technical content and formation of communities of practice, will also be provided.

Commentary by Dr. Valentin Fuster
2014;():V001T04A005. doi:10.1115/POWER2014-32295.

Water cooled steam turbine-generator stator systems are subject to flow restrictions and pluggage by copper that originates from within the stators. Deposition may occur within hollow stator bars or coils, or in filters or screens in the water flow circuit. In extreme cases of deposition, flow restriction can cause the generator to overheat due to reduction of cooling flow, resulting in unit outages and potentially serious equipment damage. Chemistry programs to minimize corrosion and transport of copper within the system include high oxygen, low oxygen, and alkaline (pH elevation). In all cases high purity water is required for the application. Examination of copper deposits can provide clues to the adequacy of the chemistry treatment program for minimizing system corrosion.

Topics: Cooling , Copper , Stators , Water
Commentary by Dr. Valentin Fuster
2014;():V001T04A006. doi:10.1115/POWER2014-32296.

Much has been done in recent years to upgrade turbines and improve plant efficiency. Recent years have also seen improvements and upgrades in the hydrogen cooled generator auxiliaries that improve plant efficiency and safety. A summary of upgrades and new products that are available and that have been implemented are presented in this paper.

Topics: Generators
Commentary by Dr. Valentin Fuster

Plant Operations and Maintenance

2014;():V001T05A001. doi:10.1115/POWER2014-32001.

The Heat Exchange Institute (HEI) Standards for Steam Surface Condensers were promulgated to design and predict the performance of surface condensers for power plant applications by providing basic overall tube bundle heat transfer rates and correction factors to be applied to account for different tube diameters, wall thicknesses (BWG), tube materials, circulating water inlet temperatures and, average water velocities.

From 1958 to 1973, nonferrous alloys were generally the tube materials of choice for steam power plant surface condenser service. By the time the 7th edition of the HEI Standards was issued in 1978, concerns with corrosion and other issues with nonferrous tubing materials had led to increased specification of stainless steel while titanium was still in its infancy.

Since then, operational experience gained with stainless steel and titanium coupled with technological advances in these materials have resulted in revisions and incorporation of additional correction factors in subsequent editions of the HEI Standards for Steam Surface Condensers. The latest edition (11th edition) was issued in October 2012. Significant developments in the HEI heat transfer correction factors since issuance of the 7th edition pertain to stainless steel and titanium.

Using a case study, this paper analyzes the impact of developments in HEI heat transfer correction factors on steam surface condenser performance and operation with focus on admiralty, austenitic, super-austenitic and super-ferritic stainless steels as well as titanium tube materials. The paper examines how changes in the correction factors affect condenser performance and plant operation. It highlights the importance of using and validating the proper correction factors to predict and ensure optimum condenser performance and operation.

Commentary by Dr. Valentin Fuster
2014;():V001T05A002. doi:10.1115/POWER2014-32002.

Increased competition and consolidation of plant ownership have created a need for power companies to leverage technological advances and tools as they attempt to maximize generating asset value by doing more efficiently with less. Legacy-based, labor-intensive systems are being supplanted with automated, standardized systems for fleet-wide data collection, analysis, diagnostics and reporting.

Focus is also shifting from monitoring the performance/condition of individual plants and components to entire fleets for maximum economic benefit. Today’s virtual environment allows an enterprise to monitor in real time the performance and health of individual plants as well as an entire fleet for continuous learning and to sustain optimum performance.

This paper provides an overview of performance/condition monitoring and optimization for fossil power plants. It examines performance and condition monitoring models, their capabilities and benefits in analyzing plant issues and, some of the results that might be achieved. It discusses the key features and benefits of on-line monitoring systems and provides examples of key performance/condition data, parameters and indicators to monitor and diagnose operation, performance, health, economics, integrity, reliability and environmental issues. The paper also examines current performance/condition monitoring initiatives in the power industry.

Commentary by Dr. Valentin Fuster
2014;():V001T05A003. doi:10.1115/POWER2014-32062.

NFPA 85, Chapter 9.5.4 states “A pulverizer that is tripped under load shall be inerted and maintained under an inert atmosphere until confirmation that no burning or smoldering fuel exists in the pulverizer or the fuel is removed”. Pulverizer systems with the potential for a resident inventory of combustible material upon trip must be designed and equipped with an inerting system that is capable of maintaining an inert atmosphere to meet this requirement. Proper design of the inerting system and operating procedure, integrated with the mill operation during start-up, shut down and emergency trip is critical for safe mill operation.

This paper presents a mill steam inerting system review and performance validation. The technology has been applied to ball tube mill systems at Hoosier Energy’s Merom Generating Station. A testing technique, used to validate performance of the steam inerting system at this generating plant, is described. It quantifies the compliance of the steam inerting system to meet NFPA requirements during start-up and shut down of the pulverizer. This type of operation is considered to be the most difficult for inerting as the primary air is flowing through the system. The developed testing approach can be applied to evaluate the performance of either existing or newly installed steam inerting systems. The validation technology, developed based on a ball tube mill system, can be readily applied on other types of mill systems, since the steam inerting principle is the same and inerting system requirements are similar, regardless of different mill types.

Topics: Steam
Commentary by Dr. Valentin Fuster
2014;():V001T05A004. doi:10.1115/POWER2014-32077.

Fuel gas for many Combined Cycle Power Plants is supplied directly by the gas provider’s regulator station in locations where the gas pipeline pressure is sufficient without further compression. Other locations require one or more onsite compressors to boost the fuel gas pressure. A rising concern is the fuel gas system transient response immediately after a significant reduction in the plant fuel gas consumption. Transient analysis models have been developed for typical fuel gas systems of combined cycle plants to ensure that the system is configured to respond appropriately to unplanned disturbances in fuel gas flow such as when a gas turbine trip occurs. Pressure control (regulator) and booster compressor control loop tuning parameters based on quantitative transient model results could be applied to set up targets for use in specifying and commissioning the fuel gas system. Case studies are presented for typical large combined cycle plants with two gas turbines taking fuel from a common plant header. This is done for designs without or with fuel gas booster compressors.

Commentary by Dr. Valentin Fuster
2014;():V001T05A005. doi:10.1115/POWER2014-32129.

This study examines the transient behavior of a seal injection system, for four boiler circulating water pumps, in an effort to optimize seal flush rates under startup conditions. During startup, seal injection supply water experiences a large increase in pressure, going from 1.8–26.2 MPa. This large increase in supply pressure presents a challenge in maintaining the desired differential pressure across the seals, and hence the optimum seal flush rate. Overshoot of the control valve position can result in starving the seals of seal water. Delayed responses expose the seals to excessively large differential pressures.

The seal injection system was modeled using PIPENET™ Vision. The model consists of a detailed replica of the seal injection system pipe network. Initial and boundary conditions were obtained from plant DCS data and pump OEM specifications. A baseline model was developed and validated using actual system response data. Extended models considered two types of control systems, manual and differential pressure-control; as well as, control valves with various flow characteristics: linear and equal percentage. Additionally, a diffuser breakdown assembly and startup control valve were also introduced as control components into the model.

Results show that the implantation of a diffuser breakdown assembly in series with the primary control valve (modified linear), in conjunction with automated controls produced a differential pressure of 436 kPa which was within the OEM specified range of differential pressures (345–690 kPa). A startup control valve used in series with the primary control valve also produced acceptable results (388 kPa). The proper design and operation of seal injection systems is vital to extending time between overhauls, thereby reducing maintenance costs. The use of the aforementioned control components in series with control valves is common for boiler feedwater regulation systems during startup; however, this is the first application known to the authors for pump seal injection systems in fossil plants. The results of the hydraulic simulation outlined in this study show this application is viable.

Commentary by Dr. Valentin Fuster
2014;():V001T05A006. doi:10.1115/POWER2014-32186.

The aim of this paper is to introduce readers to the UK’s Combined Heat and Power (CHP) industry, whilst identifying the key influences to the industry’s steady decline and the future diversification from an asset owner to a credible CHP or Utilities Operations and Maintenance (O&M) Service provider. There is a lack of research specific to the CHP and Utility O&M sectors that identify how to focus on attaining service excellence that adds real value to customers and stakeholders.

The Service–Profit Chain (SPC) model developed by J. Heskett et al[1] is a recognised theory and business model that established the connection between profitability, customer loyalty, employee satisfaction and productivity. The application of the SPC model to the CHP and Utilities market sectors has identified a possible shortfall with the SPC model framework; in that it requires additional links to the resource support infrastructure and customer service cycle, whilst including the organization’s strategic service vision.

Going beyond the application of the SPC model, this study will identify the additional management tools required to enhance and support the diversification process. An O&M SPC implementation model and a site specific Key Performance Indicator (KPI) model have been designed to complement the organization’s diversification. In addition to this, 10 golden rules have been developed in conjunction with a six tier approach to attain a meaningful O&M Service culture, which should ensure a sustainable future for an O&M Service provider.

Commentary by Dr. Valentin Fuster
2014;():V001T05A007. doi:10.1115/POWER2014-32208.

High-energy piping systems are essential to the safe and cost-effective operation of power plants. The propensity for piping failures increases with the age of the systems involved. Prolonged operation, particularly at elevated temperatures, may result in metallurgical degradation which in-turn increases the potential for cracking and crack propagation until a final failure stage is reached by the component. As a result, power plant operators have become increasingly cognizant of the importance of condition assessment evaluations for high-energy piping systems.

Power plant operators are faced with specific challenges to maintain the integrity of their high energy piping systems including the reduction of onsite engineers, aging workforces, equipment, and the need to remain competitive in a challenging global energy market. Plant managers are routinely faced with the complex task of evaluating the current condition of their equipment, forecasting outage budgets and schedules, and performing risk assessments. Additionally, insurance companies are increasingly requiring inspection and maintenance records that are not always up-to-date or readily available.

The solution to strategically maintaining the integrity of high-energy piping systems involves taking a comprehensive approach to piping management utilizing unit specific operational training, advanced data management, strategic inspection, maintenance and replacement prioritization. Implementing this comprehensive approach has resulted in avoiding both catastrophic and leak type failures for plant managers that have adopted this strategy. Implementing a unit specific, targeted plan enables utility owners and operators to succeed in today’s competitive market by increasing the unit’s reliability and availability without sacrificing safety or environmental standards.

Thielsch Engineering, Inc. hosts over 30 years of advanced engineering experience and provides extensive services to more than 150 power plants each year. Our firm is also the creator and proprietary owners of the 4 SYTE System Strategies that is currently operating in more than 60 power plants throughout the U.S. and Canada. We are an employee-owned company with 425 partners who are dedicated to best practices and customer service is a priority. Thielsch has offices in Rhode Island, Ohio, Texas and Florida.

Commentary by Dr. Valentin Fuster
2014;():V001T05A008. doi:10.1115/POWER2014-32272.

With availability of natural gas at competitive prices and increased scrutiny of coal-fired generation, conversion of coal-fired units to natural gas-firing is a popular option to consider as an alternative to capital-intense environmental equipment upgrades or even retirement. Many owners are considering this option as a way to keep an existing plant open while meeting new and pending environmental regulations. There are many technical challenges associated with such a conversion and the owner should consider them all carefully on a case-by-case basis. This paper will present an overview of these challenges, with a focus on the steam generator and what an owner/operator needs to understand when considering conversion to natural gas-firing.

Typical effects of a conversion to natural gas-firing for a utility-scale coal-fired steam generator are discussed along with potential operational effects of such a project. A general discussion of differences in furnace and convective pass performance characteristics for the different fuels is presented along with a discussion of how these differences can translate to technical challenges in a conversion project. Typical effects on boiler efficiency and emissions as well as the most commonly required modifications are reviewed. Finally, a comprehensive review of the operational affects of the converted unit is presented.

Topics: Boilers , Coal , Natural gas
Commentary by Dr. Valentin Fuster
2014;():V001T05A009. doi:10.1115/POWER2014-32303.

One of the most frequent problems in geothermal power plants is scaling. If scaling is allowed to build in the wellhead it can hinder the flow from the well. In this study we investigate how exactly that problem was solved at HS Energy in Iceland. We look at the problem, describe it and how it has been successfully solved. The solution, a valve called the Elli valve, which can be regarded a derivative of the Giffard’s injector, is then described. This valve has been shown to allow for a better flow control, less problems with regards to scaling removal and has economical advantages over other control valves. This solution should allow geothermal power plants dealing with scaling problems to use the presented solution to solve it effectively, in a cost efficient manner.

Commentary by Dr. Valentin Fuster
2014;():V001T05A010. doi:10.1115/POWER2014-32304.

Even though the Icelandic public relies greatly on geothermal power, to date, intensive maintenance procedures on the geothermal turbines have been conducted by foreign contractors. Such repairs are very time consuming, risky, expensive and leak capital out of the country. This has been discussed greatly within the industry and plans have been made on how the power companies, along with domestic machine shops can address this problem. However, in spring 2013 a turbine failure was observed in a routine quadrennial check at the Nesjavellir geothermal power plant. Corrosion products where found on the last set of the labyrinth packing and the rotor had been worn down approximately 8 mm radius. The backup rotor was also in a non-operational state. The unexpected downtime in power production had to be minimized in order to fulfill contracts. Because of time constraints, foreign service companies were not considered to be feasible due to their waiting queues and the time required for shipping overseas. This scenario initiated collaboration between the power company and domestic machine shops to manufacture spare parts and conduct the overall repair on site. This was due to several reasons such as; currency exchange rate, machines and know-how at the machine shops had improved over the last decade and the fact that the power company was ready to pay for the development cost. This paper presents the problem, how it was solved collaboratively domestically in only a fraction of time that conventional procedures would have taken. The paper investigates the causes of the turbine failure and provides a description the current state of turbine repair facilities in Iceland.

Commentary by Dr. Valentin Fuster
2014;():V001T05A011. doi:10.1115/POWER2014-32305.

Iceland relies greatly on geothermal energy, for electricity, district heating and industrial activities. It is therefore of great importance that the maintenance on site is carried out quite successfully to minimize down time. Reykjavik Energy is the largest energy company in Iceland utilizing geothermal energy. The company operates two cogenerating geothermal power plants, Hellisheidi (303 MWe and 133 MWt) and Nesjavellir (120 MWe and 300 MWt). In this study we investigate the development of the wellhead maintenance at the Hellisheidi geothermal power plant. We look at the maintenance recommendations provided to on-site employees and how maintenance procedures have developed since the power plant began its operations. We investigate real data retrospectively and use it to calculate expected waiting times between repairs. The result is a maintenance model based on the observed and statistically analyzed data provided by the power company on the maintenance procedures. Such model should prove of great significance to other geothermal power plants in the early stages of planning the wellhead maintenance.

Commentary by Dr. Valentin Fuster

Reliability, Availability and Maintainability (RAM)

2014;():V001T06A001. doi:10.1115/POWER2014-32024.

Increased renewable generation on the grid along with market deregulation has resulted in a significant increase in the cycling of coal and gas-fired power plant. This increase in cycling will result in increased wear-and-tear costs for units that were not traditionally designed for cycling. Asset owners can make operational changes to mitigate the wear-and-tear impact or alternatively retrofit existing units for improved flexibility. With retrofits, these plants can provide increased operational flexibility, or in other words cycle more, but this comes at an initial cost. On the other hand, increased flexibility in terms of faster starts, better turndowns and ramp rates also provides opportunity for the asset owners to recover their costs in the market. This paper evaluates the operational, as well as cost-benefit of retrofitting power plants for flexibility using a portfolio of generation resources in North America.

Commentary by Dr. Valentin Fuster
2014;():V001T06A002. doi:10.1115/POWER2014-32061.

Human cognition, bias and error have been studied significantly over the past few decades and are utilized in several fields, including reliability and safety engineering. Research has indicated that both man-machine interfaces and training are critical during human intervention. Additionally, it has been shown that humans contribute significantly to failures, and thus downtime. This trend is likely to continue as systems become more complex. Several methods, such as Human Reliability Assessment (HRA) and Probabilistic Risk Assessment (PRA), had been proposed and utilized throughout industry. These methods are both qualitative and quantitative and aim to understand, and thus improve, human performance within the system. Additionally, much of the research is focused on risk reduction — for example, design of a power plant to maximize redundancy in human performance during a mishap. Human error is a complicated process in itself and closely tied to cognition, information processing, system automation, team dynamics and biases inherent to humans. It cannot be eliminated by training and familiarity alone, and system design plays a major role in susceptibility to error. The digital age has spurred many advances in processing power, sensor technology and data capture. These advances have resulted in situations where a very large amount of data can be captured and presented to the user. The large amount of information has to be processed with limited attention resources, which can result in human error. This contribution will discuss human error and information processing along with the role of humans in modern power plants. Finally, trends in information overload will be discussed with applications to reducing human error in power plants.

Commentary by Dr. Valentin Fuster
2014;():V001T06A003. doi:10.1115/POWER2014-32083.

This study examines the upgrade of two forward-curved centrifugal induced draft fans, to support fuel blends with greater fractions of PRB coal for a 160 MWe generating unit. After a post installation event, an audible periodic low frequency vibration in the breeching was noticed at loads ranging from 75–95 MWe. A detailed investigation was conducted which included fluid dynamic and vibration analyses of the fan and system, as well as an assessment of the fan and motor performance characteristics.

Results of the analyses revealed system resistances which generated operating points in the stall region on the fan performance curve. Non-uniform fan inlet flow distributions were characterized by axial and transverse distortion parameters. Data showed relatively high transverse distortion parameters over the affected load range with the maximum of 20.5% distortion occurring at 95 MWe; with a corresponding breeching vibration frequency approximately four-thirds shaft speed.

Based on the data obtained and observed system behavior, it was determined the phenomenon responsible for the flow-induced vibration was the onset of rotating stall. The magnitude of the pressure pulses associated with this low frequency vibration is capable of causing fatigue damage to large ductwork and producing unwanted acoustic emissions. In light of the large number of similar conversions performed throughout industry and increases in partial-load operation, the accurate diagnosis of such phenomenon is vital for reliable plant operations. This work summarizes an effective and practical methodology for making such evaluations, while addressing issues of fan performance and system effects.

Topics: Stability , Coal , Fans
Commentary by Dr. Valentin Fuster
2014;():V001T06A004. doi:10.1115/POWER2014-32148.

Capacity measures a system’s ability to survive stress. For example, structures are engineered in part to have the capacity to survive the worst wind loads expected over the life of the structure. Likewise wind electric power systems should have the capacity to reliably survive the worst combination of high load and low wind. A superior approach for quantifying wind’s contribution to system capacity is well known. It is to view wind as a negative load and use the Effective Load Carrying Capacity (ELCC) methodology for a given year. A frequent mistake is to average these annual ELCC estimates. A main contribution of this paper is to explain why the system design criteria should take the worst of the annual ELCC estimates over a number of years and not an average of annual ELCC estimates. Based on extreme events, wind generation contributes little to system capacity (<6.6% of wind nameplate). The empirical evidence shows that wind generation is an energy source, not a capacity resource.

Topics: Reliability , Wind
Commentary by Dr. Valentin Fuster
2014;():V001T06A005. doi:10.1115/POWER2014-32207.

Boiler tube failures remain the leading cause of lost availability in power boilers across global markets. The need for strategic planning in regard to inspections, preventative maintenance and targeted replacements has never been greater. Identifying the root problem(s) is essential and must be properly managed for continued safety, reliability and availability.

The process associated with integrating a boiler management program can be viewed as an insurmountable obstacle for many utility operators and owners. In many cases, the cookie cutter approach that is often used results in insufficient reliability recovery. However, using modern technology and tactics to strategically manage and properly identify specific operating and design conditions has proven exceedingly successful in reducing a unit’s forced outage rate [EFOR].

Specific challenges plants are faced with include the reduction of onsite engineers, aging workforces and equipment, and the need to remain competitive in a challenging global energy market. Plant managers are routinely faced with the complex task of determining the current condition of their equipment, forecasting outage budgets and schedules, and performing risk assessments. Additionally, insurance companies are increasingly requiring inspection and maintenance records that are not always up-to-date or readily available. The solutions to reducing the EFOR of a unit involves taking a comprehensive approach to boiler management utilizing unit specific operational training, advanced data management, and strategic inspection, maintenance and replacement prioritization. Implementing this comprehensive approach has awarded millions in savings for plant managers that have adopted this strategy. Implementing a unit specific, target driven, and strategic plan enables utility owners and operators to succeed in today’s competitive market by increasing the unit’s reliability and availability without sacrificing safety or environmental standards.

Thielsch Engineering, Inc. developed a program titled: 4-SYTE System Strategy that is currently utilized in more than 60 power plants within the United States and Canada. Unit specific strategic planning is necessary for all facilities that rely on these critical components. Advanced technology must be adopted by all energy producers to ensure they remain competitive and profitable.

Commentary by Dr. Valentin Fuster
2014;():V001T06A006. doi:10.1115/POWER2014-32210.

In this paper, we present the experience of 10 years of collaboration between the Electric Research Institute and Pemex Refining to modernize the power electric systems of the National Refining System in Mexico, collaborating together to design an electrical energy system for distribution that can operate reliably at the increase in the quantity and quality of oil products with the integration of new processing plants. We present the extensive cooperation between the personnel involved and in contrast unexecuted planning to implement the solutions. Also, after a decade of collaboration, we present the different scenarios, factors and challenges in the medium and long term that will assure that the electrical systems are in healthier conditions to operate for the next years and will achieve the required reliability of the national refining system for gasoline demand, to result in an operational reliability conferring to a World Class utility practice.

Commentary by Dr. Valentin Fuster
2014;():V001T06A007. doi:10.1115/POWER2014-32219.

Ideal plant designs perform as intended. The goal of Reliability, Availability and Maintainability (RAM) processes is to convert designs into operational task requirements to achieve lifecycle goals. This paper discusses developing Power Generation RAM programs. Given the performance-based nature of ASME RAM standards, different approaches can be used to achieve its goals.

Improved operations and maintenance (O&M) programs offer to manage risk at lower cost. This paper introduces a risk management process to develop, maintain and use better risk-based failure management plans with an approach that is simple and clear. It predicts that software will become a more important RAM program development tool.

Commentary by Dr. Valentin Fuster
2014;():V001T06A008. doi:10.1115/POWER2014-32280.

Coal-fired units are increasingly expected to operate at varying loads while simultaneously dealing with various operational influences as well as fuel variations. Maintaining unit load availability while managing adverse effects of various operational issues such as, flue gas temperature excursions at the SCR inlet, high steam temperatures and the like presents significant challenges. Dynamic adjustment of sootblowing activities and different operational parameters is required to effectively control slagging, fouling and achieve reliability in unit operation.

Closed-loop optimizers aim to reduce ongoing manual adjustments by control operators and provide consistency in unit operation. Such optimizers are typically computer software-based and work by interfacing an algorithmic and/or artificial intelligence based decision making system to plant control system [1]. KCP&L is in the process of implementing Siemens SPPA-P3000 combustion and sootblowing optimizers at several Units.

The Sootblowing Optimizer solution determines the need for sootblowing based on dynamic plant operating conditions, equipment availability and plant operational drivers. The system then generates sootblower activation signals for propagation in a closed-loop manner to the existing sootblower control system at ‘optimal’ times.

SPPA-P3000 Sootblowing Optimizer has been successfully installed at Hawthorn Unit 5, a 594-MW, wall-fired boiler, firing 100 percent Powder River Basin coal. This paper discusses implementation approach as well as operational experience with the Sootblowing Optimizer and presents longer-term operational trends showing unit load sustainability and heat rate improvement.

Topics: Heat , Optimization
Commentary by Dr. Valentin Fuster
2014;():V001T06A009. doi:10.1115/POWER2014-32282.

When an RBD is required, Failure distribution and Outage distribution are requested as inputs for each block.

Should field data exist, the two distributions can be obtained by managing data in the most appropriate manner. While the Failure distribution is often a right censored data set, the outage distribution is always a time-to-failure distribution obtained through the RRX interpolation. Moreover, being the reliability approach conservative, the weibull 3P assumption is welcome, because the gamma value, in this particular circumstance, guarantees a minimum outage duration. However it has been noticed that while the 2P sometimes could be not-conservative enough, the 3P could result too much conservative with the risk of declaring a lower target than the actual one and hence with the consequence of not being commercially competitive. The proposed approach applies and develops the mixed weibull application, where each subpopulation distribution comes out from a single dataset, which represents a step forward after the traditional 2P and the more conservative 3P.

Commentary by Dr. Valentin Fuster

Plant Systems, Structures, Components and Materials Issues

2014;():V001T07A001. doi:10.1115/POWER2014-32003.

The circulating water system is a very important system in Ghazlan Steam Power Plant- 4276 MW, as it supplies the sea water to the tubes side of the Condensers during normal operation. A large butterfly cross-connect valve was installed at the circulating water pumps discharge header to isolate the pumps and the header for maintenance. A forced unit shutdown occurred due to valve’s shafts end leakage and collapse after maintenance work. This paper explains the wrong design location of the valve in the piping as the root cause of the problem. Analysis with ASME reference will be presented. This paper will also present potential solutions and actions taken as a lesson learned to avoid occurrence in other plants.

Topics: Pumps , Valves , Failure , Water
Commentary by Dr. Valentin Fuster
2014;():V001T07A002. doi:10.1115/POWER2014-32027.

T-91 and P-91 are the oldest of a new class of creep-strength-enhanced ferritic steels (CSEF) approved for use in boilers and pressure vessels. These newer alloys develop high strength through heat treatment, a rapid cooling or quenching to form martensite, followed by a temper to improve ductility. As a result, these alloys offer a much higher allowable stress which means thinner sections provide adequate strength for high-temperature service. Most of the applications thus far have been a substitute for P-22/T-22. The primary advantages of T91 materials over conventional low-alloy steels are: higher allowable stresses for a given temperature, improved oxidation, corrosion, creep and fatigue resistance. T23 is also considered as a member of the family of CSEF steels. The alloying elements such as tungsten, vanadium, boron, titanium and niobium and heat treatment separate this alloy from the well defined T22 steel. Although, T23 is designated for tubing application, its piping counterpart P23 has a strong potential in header applications due to superior strength compared to P22 headers.

Now that T-91 and P-91 have been in service for nearly 30 years, some shortcomings have become apparent. A perusal of the allowable stress values for T-91 shows a drop off in tensile strength above about 1150°F. Thus, start-up conditions where superheaters, and especially reheaters, may experience metal temperatures above 1200°F, lead to over-tempering and loss of creep strength.

During welding, the temperature varies from above the melting point of the steel to room temperature. The heat-affected zone (HAZ) is defined as the zone next to the fusion line at the edge of the weld metal that has been heated high enough to form austenite, i.e., above the lower critical transformation temperature. On cooling, the austenite transforms to martensite. Next to this region of microstructural transformation, there is an area heated to just below the austenite formation temperature, but above the tempering temperature of the tube/pipe when manufactured. This region has been, in effect, over-tempered by the welding and subsequent post-weld heat treatment (PWHT). Over-tempering softens the tempered martensite with the associated loss of both tensile and creep strength. This region of low strength is subject to failure during service.

Creep strength of T91 steel is obtained via a quenching process followed by controlled tempering treatment. Elements such as niobium and vanadium in the steel precipitate at defect sites as carbides; this is known as the ‘pinning effect’. Any subsequent welding/cold working requires a precise PWHT. Inappropriate and/or lack of PWHT can destroy the ‘pinning effect’ resulting in loss of creep strength and premature failures.

Several case studies will be presented with the problems associated with T91/T23 materials. Case studies will be presented, with the results of optical microscopy, scanning electron microscopy, hardness measurements and energy dispersive spectroscopy analysis. One case study will discuss how the over-tempering caused a reduced creep strength, resulting in premature creep failure in a finishing superheater tube. A second case presents the carburization of a heat recovery steam generator (HRSG) superheater tube, resulting in reduced corrosion/oxidation resistance. A case study demonstrates how a short-term overheating excursion led to reheat cracking in T23 tubing. Another case will present creep degradation in T91 reheater steel tube due to high temperature exposures (over-tempering).

Topics: Creep , Steel
Commentary by Dr. Valentin Fuster
2014;():V001T07A003. doi:10.1115/POWER2014-32119.

In this paper, a zone based temperature monitoring and control system is presented to reduce Air Conditioning (A/C) usage in commercial buildings. Reducing Heating, Ventilation and Air-Conditioning (HVAC) energy usage is a topic of immense interest as HVAC energy consumption represents up to 40% of energy usage in the US and worldwide. Our approach to reducing A/C usage is based on two unique features — extensive monitoring and zone based control. First, multiple temperature sensors are deployed in the building/room of interest to provide an improved temperature picture without the need for a system model. Second, a zone based control approach is developed which is based on flexible definition of zones and results in a generic scalable solution that can be applied to buildings of different sizes and configuration. Our control approach results in efficient A/C operation through extensive monitoring and localized control. In addition, the approach provides redundancy to isolate unforeseen issues such as communication issues to the particular zones. The proposed monitoring and control approach is deployed in telecom base stations and retail stores to highlight the generic nature and scalability of the approach. The energy saving potential and secondary benefits such as flexible localized operation of our unique zone-based control is highlighted in the results. Though the savings vary from 15% to 35% depending on the local conditions and the buildings under consideration our approach is shown to reduce A/C usage in all cases.

Commentary by Dr. Valentin Fuster
2014;():V001T07A004. doi:10.1115/POWER2014-32242.

Dissimilar metal welds between different grades of ferritic steels or between ferritic steel and austenitic nickel alloys are used extensively in power plants. When such weldments are exposed to high temperature conditions, as might be found in service in a thermal power plant, local microstructural evolution will occur. This is due to diffusion, driven by chemical potential gradients, of solute atoms. Such diffusion can cause major changes in hardness and mechanical properties of joints and can lead to the formation of embrittling phases and/or softened zones. This can potentially lead to premature component failure by, for example, high temperature creep.

Whilst finite element modelling of mechanical behavior and damage evolution is well established this is not the case for chemical diffusion and microstructural evolution at weld interfaces. In the present study, the general purpose linked thermodynamic and kinetic software packages Thermo-Calc and DICTRA have been applied to simulate chemical diffusion and precipitation/dissolution (i.e. phase fraction evolution) in dissimilar weld joints using commercially available thermodynamic databases TCFE7 and TTNI6. Two approaches for modelling multiphase, multicomponent systems using this software will be presented and discussed and their implementation will be illustrated.

The paper will present results on modelling a range of dissimilar metal interfaces of both the ferritic-ferritic type and the ferritic-austenitic type (for example, grade 22 to grade 91 steel and grade 22 to Inconel 625). Ferritic-ferritic case studies will compare model predictions with a number of previously published experimental studies and it will be shown that the current approach can give good quantitative agreement in terms of carbon composition profiles and carbide depleted/carbide enriched zones. The results obtained from modelling a grade 22 steel-Inconel 625 system where the crystal structure of the matrix is different on either side of the weld will be compared with experimental observations on a weld overlaid tube component. The experimental results will include scanning and transmission electron microscopy studies of the weld interface regions and it will be shown that the predictions of diffusion and precipitate formation compare well with observations made experimentally following exposure at 650 °C. Also discussed are the options for further refining the computational model based on empirically observed phenomena, such as the unmixed zone of a weld.

Commentary by Dr. Valentin Fuster

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