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Components and Plant System Design Optimization

POWER2007-22039 pp. 1-9; (9 pages)
doi:10.1115/POWER2007-22039

Refurbishment of the Port Arthur Steam Energy facility began in early 2005 after key commercial agreements were concluded. The plant, which had been idle since October 2000, was originally constructed in 1983 and 1984 to recover energy from three petroleum coke calcining kilns at the Great Lakes Carbon LLC facility. Major repairs were needed because of extensive damage from sulfuric acid corrosion of the HRSG system and deterioration of water treatment facilities. In addition, major improvements were made including an acoustic cleaning system, multiclones for particulate emission reduction, magnesium oxide injection for corrosion control, a complete new control system with all new field instrumentation, stack improvements to increase dispersion, and improvements to the HRSG system and water treatment system to improve reliability and reduce maintenance. Rising energy prices dictated a fast-paced schedule. Following a major reconstruction effort with a peak force of 435 people, the facility was in full operation by August 2005, less than nine months from commencement. The facility is producing approximately 450,000 lb/hr of high pressure steam, the majority of which is sold to the neighboring Valero Port Arthur refinery, and producing 4 to 5 MW of power. By capturing 1800–2000°F heat that would other wise be wasted, the project recovers nearly 5 trillion Bru/year, off setting over 200 tons/yr of NOx and over 280,000 tons/yr of carbon dioxide that would otherwise be emitted by natural gas combustion. The success of the project can be attributed to management of the project which included innovative inspection techniques, development of the scope of work, design of improvements, and extensive construction and repairs.

POWER2007-22046 pp. 11-28; (18 pages)
doi:10.1115/POWER2007-22046

Bull Run Unit 1, rated at 950 MW, is the first of four fossil supercritical power plants at TVA; the unit went into commercial operation in 1967. The boiler, built by Combustion Engineering (CE), has a radiant reheat twin divided furnace with tangential-fired burners for burning coal. The unit’s maximum continuous rating (MCR) is 6,400,000 lbs/hr of main steam flow, with a design temperature of 1003°F and pressure of 3840 psig. Through the end of November 2003, the unit had a total of 589 cumulative starts and 253,343 operating hours. In 1986 TVA located and repaired extensive cracking in the mixing link headers (27 of 32 saddle welds cracked) downstream of the superheater outlet headers. Visible sag was also noted at the mid-span of the mixing headers. Since that time through 2003, additional cracking of girth welds in the mixing link headers was discovered, followed by cracking in the main piping girth welds at the connections to the mixing headers and at one of the connections to the turbine. From 1988 through 2003 several elastic analyses which were performed were unable to explain the observed girth weld cracking and sagging in the piping. In October 2003, TVA contracted with Structural Integrity Associates (SI) and BW Roberts Engineering Consulting to perform elastic and creep analyses of the Bull Run main steam piping system to determine the most likely contributing factors to noticeable creep sagging and cracking problems in the mixing header link piping and main steam piping girth welds, and, to develop recommendations to mitigate additional cracking and creep/sagging. The evaluations concluded that improper hanger sizing along with longer-term hanger operational problems (non-ideal loads/travel, topped/bottomed out hangers) contributed to the observable creep sagging and girth weld cracking. The elastic and creep piping analyses performed to address these issues are described in this paper.

POWER2007-22113 pp. 29-37; (9 pages)
doi:10.1115/POWER2007-22113

Successful cogeneration system design requires a combination of engineering, investigation, and forecasting skills. Operating schedules for the facility must be considered in the design of the cogeneration system to optimize overall plant utilization and economics. This results in tradeoffs between electrical power production and thermal heat recovery for many applications of the technology. Optimizing these two parameters requires a thorough understanding of how and when the facility uses power and heat and the owner’s objectives of the investment in the cogeneration system. Customer-sited cogeneration systems have been accepted as one option to mitigate electrical supply shortages. On the utility side, this requires that cogeneration systems operate at a relatively high capacity factor, especially during peak periods. On the customer side, the cogeneration system must be capable of meeting onsite energy needs to reduce energy costs. In California, the Self-Generation Incentive Program (SGIP) provides incentives for the installation of distributed generation systems. Incentives are paid on an installed capacity basis ($/kW) that varies by installed technology. Eligible technologies include photovoltaic, wind, fuel cells, internal combustion engines, and microturbines. Alternative Energy Systems Consulting, Inc. (AESC) provides technical support services to the SGIP, the sponsoring utilities and SGIP’s Working Group. The services that AESC provides varies with utility, but primarily includes program design support, regulatory review, technology evaluation, application review, generator performance metering, participant training and equipment field verification. Itron evaluates the SGIP to quantify performance of the systems and estimate overall impacts of the program. This paper will present best practice recommendations for cogeneration system design to meet the efficiency criteria of the SGIP. Recommendations are based on findings from numerous AESC performance reviews and on-site inspections, as well as results of Itron’s in-depth performance evaluation of the effectiveness of useful thermal energy recovery of on-site cogeneration systems receiving incentives from the SGIP. Information is presented through Program Year 2005. Results of several past studies have suggested that cogeneration systems were not operating as they were designed and, more importantly, were not achieving the efficiencies claimed at the design stage. This paper will also explore some of the key drivers behind the unexpectedly low thermal energy recovery and overall plant performance sampled from the fleet of SGIP cogenerators. Results from recent Itron studies will be combined with AESC’s expertise in actual operations to develop a list of best practices to be followed when designing and commissioning a cogeneration system.

POWER2007-22139 pp. 39-48; (10 pages)
doi:10.1115/POWER2007-22139

The optimisation of engine performance by predictive means can help save cost and reduce environmental pollution. This can be achieved by developing a performance model which depicts the operating conditions of a given engine. Such models can also be used for diagnostic and prognostic purposes. Creating such models requires a method that can cope with the lack of component parameters and some important measurement data. This kind of method is said to be adaptive since it predicts unknown component parameters that match available target measurement data. In this paper an industrial aeroderivative gas turbine has been modelled at design and off-design points using an adaptation approach. At design point, a sensitivity analysis has been used to evaluate the relationships between the available target performance parameters and the unknown component parameters. This ensured the proper selection of parameters for the adaptation process which led to a minimisation of the adaptation error and a comprehensive prediction of the unknown component and available target parameters. At off-design point, the adaptation process predicted component map scaling factors necessary to match available off-design point performance data.

Topics: Engines , Modeling
POWER2007-22174 pp. 49-54; (6 pages)
doi:10.1115/POWER2007-22174

The present paper applies fuzzy logic technique to predict the performance map of an axial compressor. This technique relies on employing the information of a data curve in concert with the information at the design point. Further, the learning capability of ANN technique is integrated to the potential of fuzzy logic. A comparison of the predicted results with experimental data reveals a very good agreement. The proposed technique has not only the capability to model the nonlinear surge line as well as the kink in a classical compressor performance map but also it can be used as an alternative tool to foresee the effect of modification of design variables, as well as to guide the design optimization procedure in a short time frame.

POWER2007-22201 pp. 55-59; (5 pages)
doi:10.1115/POWER2007-22201

One of the most important problems in the power plants is to increase the thermal efficiency of the cycle. Most of the works in this area is focused on regeneration devices, removing the heat losses of components[[ellipsis]]But usually, about half of the input energy in the thermal cycle wastes in the condensers. In this day and age with greenhouse effect and global warming problem, the less environment defect is also another important subject. In this work, a new condenser is offered that is the same as a core of BWR nuclear reactors, then during the working fluid is condensing in a cycle it is a boiling generator (boiling heat exchange) for another cycle. In this way not only could change some parts of unused energy to work, but also it has more capability with environment. It is possible to design this process several times with different cycles and different working fluids to low heat wastes from condensers. Here, it is offered this idea by using the data of Catalagzi power plant in Turkey. The results confirm that the thermal efficiency increases at least %7.5. It can use this method for most of the power plants or somewhere that needed to remove some heat from a device, same as radiators of the automobiles.

Operations and Maintenance

POWER2007-22006 pp. 61-69; (9 pages)
doi:10.1115/POWER2007-22006

In 2004, North Omaha Station Unit 1 (NOS 1) experienced multiple condenser vacuum upsets. At least one of them resulted in a unit trip. The upset conditions occurred over relatively short periods of time with no clear indication of the initiating mechanism. Overall, condenser vacuum was low. Various methods were employed to combat the vacuum issues and upset conditions. These included operating both sets of holding steam jet air ejectors (SJAEs) above 600 psig (50% above design), using the hogging SJAE during unit operation and, operating the condensate pumps in a recirculating mode. Air inleakage was a known problem on NOS 1. The air inleakage was no longer measurable since it exceeded the scale of the installed instrumentation (20 scfm). Besides air inleakage, tube fouling of the condenser tubes was also contributing to degraded condenser vacuum. NOS 1 had a history of fouling due to calcium carbonate plateout on the condenser tubes. During the January 2005 outage, major sources of air inleakage were identified and fixed. Leaking tubes in the SJAE intercondenser/aftercondenser were plugged. The condenser tubes were scraped to reduce fouling. Although condenser vacuum improved, problems persisted at low loads. Following a vacuum upset in June 2005, the hogging SJAE was placed into service. Helium testing in July 2005 indicated high air inleakage. The problems continued to persist and, in February 2006, the unit tripped on low condenser vacuum. At that time, the unit had been operating at about 58 Mwe. In order to maintain the unit on line at a reduced load of 40 Mwe, both the hogging SJAE and one set of first stage and second stage holding SJAEs had to be deployed. An attempt to remove the hogging SJAE from service was unsuccessful since it resulted in rapid decrease in air-removal capability of the holding SJAEs. This paper describes the methodology used to troubleshoot the condenser vacuum issues for NOS 1 and remedies proposed for proper performance and reliable operation.

POWER2007-22009 pp. 71-81; (11 pages)
doi:10.1115/POWER2007-22009

This paper presents generic methods for verifying online monitoring systems associated with coal-fired power plants. It is applicable to any on-line system. The methods fundamentally recognize that if coal-fired unite are to be understood, that system stoichiometrics must be understood in real-time, this implies that fuel chemistry must be understood in real-time. No accurate boiler efficiency can be determined without fuel chemistry, heating value and boundary conditions. From such fundamentals, four specific techniques are described, all based on an understanding (or not) of real-time system stoichiometrics. The specific techniques include: 1) comparing a computed ambient relative humidity which satisfies system stoichiometrics, to a directly measured value; 2) comparing a computed water/steam soot blowing flow which satisfies system stoichiometrics, to a directly measured value; 3) comparing computed Energy or Flow Compensators (based on computed boiler efficiency, heating value, etc.), to the unit’s DCS values; and 4) comparing a computed fuel flow rate, based on boiler efficiency, to the plant’s indication of fuel flow. Although developed using the Input/Loss Method, the presented methods can be applied to any online monitoring system such that verification of computed results can be had in real-time. If results agree with measured values, within defined error bands, the system is said to be understood and verified; from this, heat rate improvement will follow. This work has demonstrated that use of ambient relative humidity is a viable verification tool. Given its influence on system stoichiometrics, use of relative humidity immediately suggests that effluent (Stack) flow can be verified against an independently measured parameter which has nothing to do with coal-fired combustion per se. Whether an understanding of coal-fired combustion is believed to be in-hand, or not, use of relative humidity (and, indeed, soot blowing flow) provides the means for verifying the actual and absolute carbon and sulfur emission mass flow rates. Such knowledge should prove useful given emission taxes or an imposed cap and trade system. Of the four methods examined, success was not universal; notably any use of plant indicated fuel flow (as would be expected) must be employed with caution. Although applicable to any system, the Input/Loss Method was used for development of these methods. Input/Loss is a unique process which allows for complete understanding of a coal-fired power plant through explicit determinations of fuel chemistry including fuel water and mineral matter, fuel heating (calorific) value, As-Fired fuel flow, effluent flow, boiler efficiency and system heat rate. Input consists of routine plant data and any parameter which effects stoichiometrics, typically: effluent CO2 , O2 and, generally, effluent H2 O. The base technology of the Input/Loss Method has been documented in companion ASME papers, Parts I thru IV, which addressed topics of base formulations, benchmarking fuel chemistry calculations, high accuracy boiler efficiency methods and correcting instrumentation errors in those terms affecting system stoichiometric (e.g., CEMS and other data).

Topics: Coal , Power stations
POWER2007-22010 pp. 83-90; (8 pages)
doi:10.1115/POWER2007-22010

A last stage turbine blades failure was experienced in two units of 660 MW. These units have one high-pressure turbine and two tandem-compound low-pressure turbines with 44-inch last-stage blades. The blades that failed were in a low pressure (LP) turbine connected to the high pressure (HP) turbine (LP1) and in LP turbine connected to the generator (LP2). The failed blades had cracks in their roots initiating at the trailing edge, concave side of the steeple outermost fillet radius. Laboratory evaluation of the cracking indicates the failure mechanism to be high cycle fatigue (HCF). The last-stage blades failure evaluation was carried out. The investigation included a metallographic analysis of the cracked blades, natural frequency test and analysis, blade stress analysis, unit’s operation parameters and history of events analysis, fracture mechanics and crack propagation analysis. This paper provides an overview of this failure investigation, which led to the identification of the blades torsional vibrations near 120 Hz and some operation periods with low load low vacuum as the primary contribution to the observed failure.

Topics: Blades , Failure
POWER2007-22015 pp. 91-101; (11 pages)
doi:10.1115/POWER2007-22015

This paper discusses experiences and recommendations of six practicing thermal performance engineers with regards improving and maintaining the thermal efficiency of power plants. It discusses the authors’ perceived decline over the past decade for qualified staff, and capital projects involving efficiency improvements, instrumentation and testing/monitoring projects. Such observations extend to North America and Western Europe. This paper attempts to coalesce years of observations and hands-on experience in the field into summaries useful for prudent action. It also presents several recommendations aimed at improving the consciousness towards performance engineering, which has the potential of substantially reducing emissions per electrical output, and increasing the mostly forgotten thermal efficiencies of power plants (heat rate).

POWER2007-22028 pp. 103-110; (8 pages)
doi:10.1115/POWER2007-22028

Exergy analysis approved to be a powerful tool for assessing the thermodynamic performance of energy conversion processes. As one of the extensions, the Specific Analysis Approach is trying to deliver the spatial and temporal information on decomposed exergy losses of an energy conversion process in both absolute and relative terms, in a way that users are familiar with. The conceptual and computational complexities of exergy analyses are left behind the easily understood and accessible thermodynamic performance indicators, such as specific fuel consumption of the total plant and of different equipment components, under different load and time series. In this paper, this approach has been implemented in diagnosing the operating performances of a 300MW pulverized coal fired unit. The results show clearly the energy saving potential of the whole plant, and of different components. The possible equipment failures at the state the data were acquired were diagnosed.

POWER2007-22036 pp. 111-115; (5 pages)
doi:10.1115/POWER2007-22036

Cimplicity is a Human-Machine interface software which acquires data from CNCs Robots and PLGs, data is then visualized on real time by an operator in a Cimplicity screen on a PC monitor. This software lets the operator perform operations, monitor and control status in a factory in an easy, natural, and intuitive way. This paper will focus on the use of Cimplicity HMI and Microsoft Excel in COMONSA, a cogeneration plant designed and installed by SEISA (International Energy Systems). The cogeneration plant is localized in Monclova, Coahuila, Mexico. This plant supplies energy and, heat to a metal manufacturing factory called INMAGUSA. In this case Cimplicity acquires data from a PLC connected to two reciprocating Engines, which are responsible of supplying heat and electrical energy to the factory, and other auxiliary devices that keep the cogeneration plant running. Cimplicity transforms the data received by the PLC and then displays it on screens while it is being stored on Excel sheets in predefined time intervals. A total of 1093 variables are displayed in 70 different screens. This paper will center on the variables, screens and programs created by the authors. Screens created for the purpose of making the process of invoicing easier for SEISA, for monitoring daily kWh and monthly factory consumption. And two algorithms programmed using Microsoft Visual Basic to facilitate optimal operation of the cogeneration plant.

POWER2007-22053 pp. 117-127; (11 pages)
doi:10.1115/POWER2007-22053

Due to the past years experience, we have seen an influence on the coal purchase policies. The main reason for using coal other tan the original design coal, apart from economic considerations, is to reduce SO2 emission by using a low sulfur content coal as well as decreasing coal index (fixed carbon to volatile matter ratio) in order to reduce NOx emission etc. Hence, the power generation plant was originally designed to operate on a particular coal, and due to high restriction in environmental requirements, emissions regulations, have led to modifications of the coal type and firing mode, while the boilers must burn a different coal type and its blends. It may lead to boiler reliability degradation and as a result reducing the power plant availability and increasing operating and maintenance cost. In order to prevent a different faults in boiler operation and as a result a reliability reduction, special monitoring and diagnostic techniques is required for engineering analysis and utility production management. In this sense an on-line supervision system have developed and implemented for 575, 550, 360 Mw coal fired units. The aim of the system is to achieve more effective and reliable operation with emission reduction. It is a valuable aid for: (1) operation staff and process engineers to survey the equipment and overall plant performance, (2) electricity production management in order to implement maintenance and operation strategies. The developed system provides an on-line information regards furnace performance, including fireball location, increase in furnace exit temperature indicates that it’s necessity to activate furnace sootblowers to control steam temperatures and prevent excessive accumulations of slag and heat surfaces tube overheating. The developed system indicates the superheater and reheater surfaces midwall metal temperature which provides timely information to assist engineering personnel to optimize mode of operation, in order to activate the optimal number of sootblowing of the corresponded surfaces, etc. The system includes also an online analysis of the erosion impact on the boiler backpass heat surfaces. By the using the developed system we found a correlation between furnace fouling and NOx emission due to the effect of flame temperature on the rate of NOx formation. As a result an optimal mode of furnace operation and sootblowing practice is used to reduce the high cost of controlling NOx emission. The developed system allows to fond the proper coal blends which provide a high boiler efficiency and reliability while minimizing NOx emissions.

Topics: Reliability , Boilers , Coal
POWER2007-22090 pp. 129-144; (16 pages)
doi:10.1115/POWER2007-22090

The most commonly used method for control over the turbine island efficiency variation is turbine balance test. However, this test requires many various resources and is therefore rarely performed. Besides, such tests are performed for a simplified variant of the cycle that’s why the test results are not suitable for the real operational conditions. For these reasons the balance test can not solve a variety of important problems: - to keep track of heat losses caused by the deviation of the operational parameters from their optimal values and, overall, by an unsuccessful operation of the equipment; - to evaluate the heat losses caused by the equipment degradation which is necessary in order to optimize the start and duration of repair works; - to compare an operation quality of different units with different operational conditions. All the above mentioned problems can only be solved by using the efficiency monitoring systems. But for these monitoring systems to have practical significance the following principal requirements must be fulfilled: - the integral diagnostic factor has to be found; this factor must have a high sensitivity to the turbine cycle efficiency variation as well as to the variation of turbine cycle equipment conditions; - the low uncertainty of the diagnostic factor calculation results has to be provided, the uncertainty value must be sufficiently close to the one of the traditional test results. In the presented paper our experience of operating the online turbine cycle Efficiency Monitoring System is described.

POWER2007-22118 pp. 145-152; (8 pages)
doi:10.1115/POWER2007-22118

The nuclear power industry is presently witnessing a renaissance. Global warming, greenhouse effects, concerns with use of as well as rising costs of fossil fuels, the desire to be weaned from foreign oil are all factors driving the need for increased reliance on nuclear power. Consequently, nuclear power plant owners are seeking to maximize the value of their generating assets through various means: improved operation, performance, capacity, availability, reliability and efficiency; license renewals, and; power uprates. Capacity factors are currently averaging well over 90% and, forced outage rates have decreased significantly, reflecting the maturation of operating and maintenance practices. In recognition of low fuel and relatively stable operating costs of their nuclear facilities, nuclear power plant owners have not only applied for license renewals, but have also upgraded the operation and, added electrical generating capacity to the operating units. Using a case study, this paper describes current efforts in maximizing the value of existing nuclear power plant generating assets. The focus of the paper is on maximizing benefits through improved operations and performance.

POWER2007-22158 pp. 153-160; (8 pages)
doi:10.1115/POWER2007-22158

The growing share of renewable energies in the power industry coupled with increased deregulation has led to the need for additional operating flexibility of steam turbine units in both Combined Cycle and Steam Power Plants. Siemens steam turbine engineering and controls presently have several solutions to address various operating requirements: - Use of an automatic step program to perform startups allows operating comfort and repeatability. - 3 start-up modes give the operator the flexibility to start quickly to meet demand or slowly to conserve turbine life. - Several options for lifetime management are available. These options range from a basic counter of equivalent operating hours to a detailed fatigue calculation. - Restarting capabilities have been improved to allow a faster response following a trip or shutdown. - In addition to control of speed, load and pressure, special control functions provide alternative work split modes during transient conditions. - Optimum steam temperatures are calculated by the steam turbine control system to achieve optimum startup performance. - Siemens steam turbines are also capable of load rejection to house load, some even to operation at full speed, no load. Several plants are already equipped with these solutions and have provided data showing they are operating with shorter start-up times and improved load rejection capabilities. Finally Siemens of course continues to pursue future development.

Topics: Steam turbines

Reliability, Availability and Maintainability

POWER2007-22038 pp. 161-174; (14 pages)
doi:10.1115/POWER2007-22038

Proper shaft-to-shaft alignment during normal machinery operation is essential for improved machinery reliability. Having the proper tools to perform an accurate coupling alignment are critical to maximized maintenance efficiency. Improvements in hardware and software technology have greatly simplified coupling alignment procedures. A comprehensive machine alignment consists of two elements: measurement of the shaft-to-shaft alignment and measurement of the thermal growth and dynamic movement of each bearing housing. Accurate measurement of these elements should be used to position the cold alignment condition in order to properly align the shaft under loaded conditions. Shaft-to-shaft alignment is typically measured using either laser or dial-indicator instrumentation. RoMaDyn used a laser based system utilizing bluetooth technology for shaft alignment readings. This system provides excellent accuracy, flexibility, and fast results. Often if unit casing temperatures change little immediately after a hot coast down, relative shaft to shaft thermal growth measurements can be acquired using laser coupling alignment readings. Hot and cold alignment data can then be incorporated into an alignment drawing to determine measured shaft relative thermal growth. The measured thermal growth readings or OEM calculated growth numbers are then incorporated into the cold unit alignment settings to provide the best hot alignment condition. This paper will discuss a recent case history involving chronic coupling failures at a customer’s facility. Acquired vibration and shaft alignment readings will be discussed. These measurements will illustrate the effects of alignment changes on machinery vibration levels and coupling reliability.

Topics: Lasers , Vibration , Failure
POWER2007-22055 pp. 175-184; (10 pages)
doi:10.1115/POWER2007-22055

Many gear speed reducers in the Power Generating Industry suffer from premature failure of gears and / or shaft support bearings. This paper and presentation describes proven strategies for failure avoidance. It gives cost justification calculations and shows case histories dealing with gearboxes in the Southern United States and other parts of the world. Implementation of these strategies has rapidly demonstrated its cost-effectiveness. Actual installation details are highlighted.

Topics: Reliability , Gears , Failure
POWER2007-22064 pp. 185-190; (6 pages)
doi:10.1115/POWER2007-22064

Prognosis and health monitoring (PHM) technology needs to be developed to meet the challenges posed by aging gas and steam turbines in power plants, transportation systems, gas pipelines, and other industries. It is necessary to use physics based residual life prediction and life extension techniques to take into account the state of damage due to prior service. This paper focuses on the requirements of the technology and the state of the development to date. In this study, Life Prediction Technologies Inc.’s (LPTi’s) prognosis tool known as XactLIFE™ was successfully used to establish the fracture critical location of RRA 501KB first stage gas turbine blades under steady state loads and to compute the average life to creep crack initiation in the blade airfoils. The analysis used typical engine operating data from the field in terms of engine speed and average turbine inlet temperature (TIT). The blade is known to suffer airfoil untwist and lengthening during service and this is obviously followed by stress rupture failure. The primary objectives of the case study are to show how prognosis can allow a user to predict fracture critical locations to avoid failures.

POWER2007-22068 pp. 191-195; (5 pages)
doi:10.1115/POWER2007-22068

A study team was commissioned by Headquarters, United States Army Installation Management Command (HQ IMCOM), under the leadership of the U.S. Army Engineer Research and Development Center-Construction Engineering Research Laboratory (ERDC-CERL), to determine the electric power requirements of Fort Wainwright, Alaska (FWA) through the year 2020, and energy supply alternatives to meet these requirements. Of particular importance was the impending winter and the fact that the installation thought it would not have the ability to meet all electrical demand, in approximately six months. Although several studies of the FWA electric power situation were performed over the past few years, the major concern was that recent increases in demand due to new construction brought about by newly added troop deployment units to the installation, a reduction in the number of facilities scheduled for demolition, coupled with the temporary loss of some generating capacity from the FWA Central Heating and Power Plant (CHPP), could result in a power shortfall during the upcoming 2006/2007 winter season. The study involved the following six primary tasks: (1) Establishing the generating capabilities of the FWA CHPP as well as FWA’s electric power import capacity, based on existing interties to the local utility; (2) Determining the annual electric power requirements through the year 2020; (3) Performing a limited condition assessment of the CHPP-related electrical system to identify critical items in need of repair/replacement; (4) Determining the ability of the local electric utility and other electric power suppliers to meet FWA electric demands through the year 2020; (5) Identifying options for meeting any electric power shortfalls likely to occur through the year 2020; and (6) Identifying methods and costs to improve electrical reliability focusing on redundart equipment and systems. The study determined that the potential power shortfall ranged from 2.3 megawatts (MW) to 3.8 MW for the winter of 2006/2007; 3.6 MW to 5.1 MW for the winter of 2007/2008; 6.3 MW to 7.8 MW in 2011; and 9.7 MW to 11.2 MW by the year 2020, Furthermore, the study corroborated earlier reviews that the switchgear was in immediate need of attention to ensure safe and reliable operation. The subsequent recommendations, which were implemented, included the installation of a nominal 7.5 megavolt-ampere (MVA) transformer to increase import capacity to meet potential shortfalls between 2006 and 2007 and a detailed review of the switchgear condition. Recommendations for upgrade of the switchgear are being pursued, along with further increase in transformer capacity (2 × 20 MVA substation) to ensure no electric power shortfalls through the year 2020.

Topics: Fortification
POWER2007-22072 pp. 197-200; (4 pages)
doi:10.1115/POWER2007-22072

The rotor is one of the most core components of the rotating machinery and its working states directly influence the working states of the whole rotating machinery. There exists much uncertainty in the field of fault diagnosis in the rotor system. This paper analyses the familiar faults of the rotor system and the corresponding faulty symptoms, then establishes the rotor’s Bayesian network model based on above information. A fault diagnosis system based on the Bayesian network model is developed. Using this model, the conditional probability of the fault happening is computed when the observation of the rotor is presented. Thus, the fault reason can be determined by these probabilities. The diagnosis system developed is used to diagnose the actual three faults of the rotor of the rotating machinery and the results prove the efficiency of the method proposed.

POWER2007-22073 pp. 201-209; (9 pages)
doi:10.1115/POWER2007-22073

A review is presented of 17 years experience in the application of a technology to increase the reliability of superheaters and reheaters without replacement. More than 20 superheaters and reheaters have been modified and have accumulated more than one million hours since they were modified. The technology, called TubeMod, optimizes the temperature profiles by redistributing steam flow from cold tubes to hot tubes to reduce peak temperatures to enhance life and avoid future failures. Removal of high temperature restrictions and application on a T91 superheater are also discussed.

POWER2007-22081 pp. 211-220; (10 pages)
doi:10.1115/POWER2007-22081

Under the auspices of the Standards Developing Organizations (SDOs), the nuclear industry is currently in the process of developing standards for Probabilistic Risk Assessments (PRAs) to support risk-informed applications of nuclear power plants, including PRA standards for Low Power and Shutdown (LP/SD) operations. A particularly challenging part of building a LP/SD PRA model is the definition of quasi-steady Plant Operating States (POSs). This document provides guidance for developing the POSs needed for the creation and use of a LP/SD risk model based on a standard set of 15 generally applicable POSs. NUREG/CR-6144, prepared by the Brookhaven National Laboratory for the Nuclear Regulatory Commission (NRC) (for the Surry plant), was used as a foundation to build the set of standard set of 15 POSs presented here. Within these standard POSs, there is room for modification for plant- and application-specific purposes such as the specific LP/SD risk application of transition risk analysis. Specifically, modifications are accomplished by subdividing POSs. Another particularly challenging part of building a LP/SD PRA model is defining and modeling periods of transition which for the suggested guidance, are defined as risk-significant activities between quasi-steady POSs which involve significant configuration changes. This guidance provides support for developing the models needed for the evaluation of the risk associated with plant transitions occurring in the process of the plant shutdown and startup. Specifically, guidance is provided to lead a PRA modeler through the identification and characterization of the transitions and the selection and generation of appropriate transition PRA modeling elements and data. The transition modeling guidelines are applicable for procedure-based transitions (as opposed to physical-phenomenon-type transitions such as the drop in decay heat level) occurring during LP/SD operations. The guidance presented is intended to be applicable for all Light-Water Reactors (LWRs). The detailed guidance processes described are currently focused on Pressurized-Water Reactors (PWRs).

Topics: Modeling
POWER2007-22114 pp. 221-230; (10 pages)
doi:10.1115/POWER2007-22114

Over the past several years, customer-sited cogeneration systems have been viewed as a way to mitigate electrical supply shortages. On the utility side, achieving this goal requires cogeneration systems to operate at a relatively high capacity factor, especially during peak periods. On the customer side, the cogeneration system must be capable of reducing operating costs, which can be accomplished by running the system at high operational efficiency and recovering available waste heat. Our firm has been evaluating customer-sited cogeneration systems installed under the Self Generation Incentive Program (SGIP). This paper will present the results of an in-depth performance evaluation conducted for the SGIP Working Group to evaluate the effectiveness of useful thermal energy recovery of on-site cogeneration systems that received incentives from the program. An earlier study investigated levels of energy efficiency and useful waste heat recovery achieved by cogeneration systems in the SGIP. This study raised some interesting questions regarding the actual operational efficiencies of cogeneration systems and low thermal heat recovery. By incorporating fuel consumption, thermal energy recovery and prime mover performance data obtained through the Program’s measurement and evaluation monitoring efforts, actual measured performance was compared to engineering estimates of performance for each project. Thermal heat recovery plays an important role in the overall performance of a cogeneration system. This paper will explore some of the key drivers behind the unexpectedly low thermal energy recovery and overall plant performance. Possible ways to improve the useful waste heat recovery will also be discussed. Regular maintenance and thorough monitoring of the cogeneration system has big impact on the performance. Because the performance data includes the actual timing (hour and month) of cogeneration system operation, the effects of this distributed generation resource is evaluated by taking into account the large differences between peak and offpeak energy costs and benefits. This program-level distributed generation analysis can help program designers and policy makers to understand the limitations of smaller cogeneration applications relative to those systems envisioned under Public Utility Regulatory Policy Act (PURPA) and thus may have important policy implications for the future of cogeneration and distributed generation programs throughout the U.S.

POWER2007-22117 pp. 231-236; (6 pages)
doi:10.1115/POWER2007-22117

The global energy market continues to face significant change, evolving over time in several dimensions. One of them is a structural change, where it went into de-regulation and that has become a viable opportunity and reality; another is clean technology as new generating alternatives with greater efficiency and “environmental friendliness” has become available. Today, there is a keen interest in power plants using the latest gas turbine technology, which has higher firing temperatures, greater output, and improved efficiencies and remains environmental friendly. With evolving markets and variations in prices, the importance of reliability has increased greatly. As these technologies evolve and improve, it is important to recognize that the operational performance and profitability is expected to be consistently on the rise. Consequently, market conditions and expectations continue to place a significant emphasis on the achievable level of reliability and availability, which in turn provides the importance on having feedback from the plants within the framework of quality data resulting in building up benchmarking statistics. ORAP® (Operational Reliability Analysis Program) which is owned by Strategic Power System Inc.® (SPS) tracks reliability and availability performance on gas turbines from various MW size ranges, manufacturers, applications, and duty cycles. NERC is another data source with several years of data from varied fuels and power plant types. This paper presents the importance of having benchmarking data from an independent third party and the results of quality analysis by OEM experts. This focused approach develops the methodology of setting targets for MTBF, MTTR, FOR and failure rate not only at system level but also even down to component level for any operating power plant. The reliability growth potential is identified and reliability techniques are applied.

POWER2007-22119 pp. 237-243; (7 pages)
doi:10.1115/POWER2007-22119

Redundancy of components and subsystems is part of the design of reliable complex engineering systems used in several industrial applications, including power generation facilities. Such engineering systems may be in one or more intermediate operating states at various times. For example, these systems could continue operating during the repair of failed components and during maintenance intervals. For this reason, they do not lend themselves well to traditional reliability modeling techniques that do not account for a system’s progression through various intermediate states. The use of traditional reliability modeling techniques may lead to significantly different estimates of the performance of a complex system required to exhibit high reliability. This paper discusses the application of a Markov modeling approach for the development of reliability estimates of complex engineering systems. This approach is expected to have advantages for modeling reliability for such systems, since they are commonly comprised of redundant sets of components and require a strict set of maintenance operations to ensure their reliability.

Topics: Safety , Modeling
POWER2007-22146 pp. 245-253; (9 pages)
doi:10.1115/POWER2007-22146

Adding damped structure can decrease dynamic stress of blade and avoid blade fatigue failure from forced vibration. Based on the structural feature of long blade with friction damper, the numerical model for dynamic analysis of damped blade in steam turbine has been developed. The blade was described by twisted beam element, the usual space beam element was adopted to analyze the frame of damper, and the slip motion between rubbing surface was modeled by a damping connector. The following matrices which are necessary for finite element analysis were obtained: the stiffness matrix, mass matrix and damping matrix of finite element for blade and damper, the stiffness matrix and damping matrix of damping connector. Then the gross finite element motion equation of the blade was got. Meanwhile, harmonic wave propagation method was adopted to improve calculation efficiency. The comparison of calculation results and experimental data of a 360mm blade shows good agreement. The dynamic characteristic of a last stage long blade in steam turbine with damper was analyzed in detail, its responses with different thickness shroud and gap between shrouds were investigated in detail too, then the optimal structure of damped shroud was obtained, the comparison for response between damped blade and freestanding blade shows the maximum response of blade with optimal damper is 42.4% of that of freestanding blade. At last, a tie wire was added to the damped blade, numerical result shows it can decrease blade response further.

POWER2007-22178 pp. 255-262; (8 pages)
doi:10.1115/POWER2007-22178

Though piping is one of the largest and most expensive types of components in a plant, piping vibration is seldom monitored in a routine manner. Piping itself rarely fails due to vibration, but the same can not be said for related components such as supports, welds, valves, etc. Typically the only time piping vibration is monitored is if high vibration is perceived by operators or is expected due to plant operational changes such as uprates or major component replacements. The procedure for a comprehensive piping vibration monitoring program is thus not as widely known as that for other components such as rotating machinery. This paper presents the steps involved with monitoring piping vibration, obtaining meaningful data and ways to interpret the data. It could be viewed as a primer to those who have never been involved with vibration testing on piping, or as a guideline and checklist for those who have.

Topics: Pipes , Vibration

Turbines, Generators and Auxiliaries

POWER2007-22011 pp. 263-269; (7 pages)
doi:10.1115/POWER2007-22011

Rotor vibration characteristics are first analyzed, when the rotor winding inter-turn short circuit fault, the air-gap dynamic eccentricity fault, the air-gap static eccentricity fault and the imbalance fault occurs. Next, the generator stator current characteristics on the faults also were analyzed, the results show that the faults can’t be diagnosed based only on rotor vibration characteristics or stator current characteristics. But considering the differences of compositive characteristics of the rotor vibration and stator current caused by different rotor faults, a new method of generator vibration fault diagnosis, based on compositive characteristics, is developed. Finally, the rotor vibration and stator current of a type SDF-9 generator is measured in the laboratory to verify the theoretical analysis presented above.

POWER2007-22019 pp. 271-274; (4 pages)
doi:10.1115/POWER2007-22019

Due to the disturbance of electric power system or other shock load, the torsional vibration of turbine-generator shafts occurs. Alternative shear stress due to torsional vibration decreases the shafts life, even results in shafts broken. It is significant to calculate and analyze natural properties and the responses of tosional vibration excited by the disturbance of electric power system in order to analyze and prevent catastrophic accident. The calculation and analysis system of torsional vibration of turbine-generator shafts is developed. With multi-mass lumped model, the model of torsional vibration of turbine-generator shafts is obtained. The system calculates the natural frequencies and the modal shapes of torsional vibration with the transfer matrix method, the response of torsional vibration of shafts with the increment transfer matrix method, such as torsional angle, angular velocity, angular acceleration, cross-section torque, and torsional stress. The response spectrum of torsional vibration can be obtained by fast Fourier transform algorithm Take an example of a 200MW turbine-generator, which is in the condition of non-all-phase operation. The responses of torsional vibration of shafts are calculated and analyzed. The bolt broken reasons of the coupling of inter-pressure rotor and low-pressure rotor and the coupling of generator and exciter are discussed. The results are identical with the data recorded in field. It is proved that the system is good precision, convenient using, friendly interfacing, and visual calculating.

POWER2007-22020 pp. 275-278; (4 pages)
doi:10.1115/POWER2007-22020

It is very important to monitor vibration and diagnose fault for the operating safety of turbine-generator. The remote monitor and diagnosis via the cyber-based technology is a necessity. The difference between browser/server mode and client/server mode is discussed. There are many advantages of applying Java technology. Using Java, a vibration monitoring and fault diagnosis system of turbine-generator based on browser/server mode is developed. The functions as well as the structure of the whole system are analyzed. Online transmission of batch data via Internet is presented, especially for different program languages. Java Applet technology is used to develop client program. With double-buffer method, a lot of graphic interfaces of dynamic making online are presented, which are not blinking. It is proved that the system is already adopted and functions well in several power plants.

POWER2007-22022 pp. 279-282; (4 pages)
doi:10.1115/POWER2007-22022

The fault diagnosis method based on artificial neural networks is summarized. An object-oriented paradigm is introduced to fault diagnosis for large scale rotating machinery, for example, turbine-generator. A fault diagnosis method based on object-oriented artificial neural networks for more symptom domains is presented. The training patterns are constructed. A treatment for incomplete symptom domains and/or concurrent faults in diagnosing is given. Verification is carried out for the actual turbine-generator data with incomplete symptom domains.

POWER2007-22029 pp. 283-289; (7 pages)
doi:10.1115/POWER2007-22029

In a steam turbine stage there is an interaction between blades and the flow field. The blades are subjected to the forces caused by the flow field, but also the flow field is affected by the blades and its movement. The nozzle wakes cause uneven pressure field downstream and produce alternating forces on blades which lead to blade vibrations. Some of the vibrations originated in this way may damage the blades and affect the turbine performance. The results of numerical computations about the forces acting on the blades as a result of the variations in the flow field in the axial clearance rotor-stator in the last stage of a 110 MW steam turbine are presented. The analysis is focused on discussing the pressure field because it is necessary for further computation of the useful life time. The flow field was resolved using computational fluids dynamics and the computed pressure field was integrated around the blades to get the forces acting on blades. These computed dynamical forces will be used in the blade useful life estimation and in the investigation to the failure causes of these blades. The Navier-Stokes equations are resolved in two and three dimensions using a commercial program based on finite-volume method. 2-D and 3-D geometry models were built to represent the dimensional aspects of the last stage of the turbine. Periodic boundary conditions were applied to both sides of a periodic segment of the 2-D and 3-D models with the purpose of reducing computational efforts. The computations were conducted in steady state and transient conditions. The results show that the force magnitude acting on blades has an harmonic pattern. Finally a Fourier analysis was used to determine the coefficients and frequency of a Fourier equation which can be used to calculate the alternating stresses on the blade in order to predict the useful life of the blades. Also, the pressure and velocity fields are shown between the diaphragm and rotor blades along the axial clearance.

POWER2007-22030 pp. 291-298; (8 pages)
doi:10.1115/POWER2007-22030

In the past, several 300 MW steam turbine rotors were affected by vibrations, which appeared at bearing #1 during load conditions. At certain loads, vibrations of the #1 bearing increased considerably. Near full load the amplitude of vibration sometimes reduced to acceptable levels. Practically, the phenomena were partially cured by trim balancing of the HP rotor, readjusting the valve opening characteristics and by correction of the clearances in the sealing system. The results are briefly summarized. On the other hand, the simulation of the various parameters using rotordynamic codes was conducted to explain the phenomena analytically. In this part, the rotordynamic rotor model was constructed and the following simulations were carried out: rotor bearing instability, effect of the destabilizing steam forces on the rotor at the first row, effect of the seal rotordynamic forces and the valve opening sequence on the rotor stability. All results were analyzed to present general conclusions.

POWER2007-22048 pp. 299-303; (5 pages)
doi:10.1115/POWER2007-22048

Turbine blades are always subjected to severe aerodynamic loading. The aerodynamic loading is uniform and Of harmonic nature. The harmonic nature depends on the rotor speed and number of nozzles (vanes counts). This harmonic loading is the main sources responsible for blade excitation. In some circumstances, the aerodynamic loading is not uniform and varies circumferentially. This paper discussed the effect of the non-uniform aerodynamic loading on the blade vibrational responses. The work involved the experimental study of forced response amplitude of model blades due to inlet flow distortion in the presence of airflow. This controlled inlet flow distortion therefore represents a nearly realistic environment involving rotating blades in the presence of airflow. A test rig was fabricated consisting of a rotating bladed disk assembly, an inlet flow section (where flow could be controlled or distorted in an incremental manner), flow conditioning module and an aerodynamic flow generator (air suction module with an intake fan) for investigations under laboratory conditions. Tests were undertaken for a combination of different air-flow velocities and blade rotational speeds. The experimental results showed that when the blades were subjected to unsteady aerodynamic loading, the responses of the blades increased and new frequencies were excited. The magnitude of the responses and the responses that corresponding to these new excited frequencies increased with the increase in the airflow velocity. Moreover, as the flow velocity increased the number of the newly excited frequency increased.

Topics: Blades
POWER2007-22049 pp. 305-311; (7 pages)
doi:10.1115/POWER2007-22049

The objective of this paper is to provide a RELAP5 model of the heater drain system of a BWR. Most water driven turbine power plants have comparable systems. The purpose of the RELAP5 model is to simulate and evaluate operational transients in the heater drain system so evaluations of the system can be performed. Other possible uses of this model are for reactor simulator support, for support to operations in determining what if scenarios during operation and for supporting plant engineering in changing and modifying the system for optimum operation.

POWER2007-22056 pp. 313-320; (8 pages)
doi:10.1115/POWER2007-22056

New low pressure (LP), stages for variable speed, mechanical drive and geared power generation steam turbines have been developed. The new blade and nozzle designs can be applied to a wide range of turbine rotational speeds and last stage blade annulus areas, thus forming a family of low pressure stages—High Speed (HS) blades and nozzles. Different family members are exact scales of each other and the tip speeds of the corresponding blades within the family are identical. Thus the aeromechanical and aerodynamic characteristics of the individual stages within the family are identical as well. Last stage blades and nozzles have been developed concurrently with the three upstream stages, creating optimised, reusable low pressure turbine sections. These blades represent a step forward in improving speed, mass flow capability, reliability and aerodynamic efficiency of the low pressure stages for the industrial steam turbines. These four stages are designed as a system using the most modern design tools applied on Power Generation and Aircraft Engines turbo-machineries. The aerodynamic performance of the last three stage of the newly designed group will be verified in a full-scale test facility. The last stage blade construction incorporates a three hooks, axial entry dovetail with improved load carrying capability over other blade attachment methods. The next to the last stage blade also uses a three hooks axial entry dovetail, while the two front stage blades employ internal tangential entry dovetails. The last and next to the last stage blades utilize continuous tip coupling via implementation of integral snubber cover while a Z-lock integral cover is employed for the two upstream stages. Low dynamic strains at all operating conditions (off and on resonance speeds) will be validated via steam turbine testing at realistic steam conditions (steam flows, temperatures and pressures). Low load, high condenser pressure operation will also be verified using a three stage test turbine operated in the actual steam conditions as well. In addition, resonance speed margins of the four stages have been verified through full-scale wheel box tests in the vacuum spin cell, thus allowing the application of these stages to Power Generation applications. Stator blades are produced with a manufacturing technology, which combines full milling and electro-discharge machining. This process allows machining of the blades from an integral disc, and thus improving uniformity of the throat distribution. Accuracy of the throat distribution is also improved when compared to the assembled or welded stator blade technology. This paper will discuss the aerodynamic and aeromechanical design, development and testing program completed for this new low pressure stages family.

POWER2007-22060 pp. 321-326; (6 pages)
doi:10.1115/POWER2007-22060

The reliability of large generators is of major importance to maintain the integrity of power plant. Continuous monitoring or frequent inspection is therefore desirable to be able to remedy growing defects before a catastrophic failure or more major work becomes necessary. Recent test information may also permit more effective use of routine or unscheduled outages by means of additional preparation and provisioning. The stator core is a major electro-mechanical component of a generator to which this applies in particular, as failure and associated repair or replacement necessitates major disassembly of other parts of the machine. Information on condition of the core structure is therefore significant, but is increasingly difficult to obtain at frequent intervals. Low power core testing can be performed more quickly and easily than using traditional full flux methods and may need to be considered an indispensable tool to increase or maintain essential monitoring levels. Low power core testing presents opportunities to maintain the level of stator core lamination monitoring in a more time and resource efficient manner using comparatively short windows in available outage time, often partly overlapping with other concurrent maintenance activities. These opportunities are enhanced with wider use of low power EL CID testing without removal of the rotor, not feasible with thermal loop tests.

Topics: Testing , Insulation , Stators
POWER2007-22062 pp. 327-334; (8 pages)
doi:10.1115/POWER2007-22062

Interest in online turbine condition monitoring has increased among utilities in order to minimize unforeseen standstills and for better planning of overhauls or repair work. The AMODIS® (ALSTOM Monitoring and Diagnostic System) Steam Turbine Condition Monitoring system monitors steam turbines locally or remotely via long distances [1]. The system also collects all data to compare current events with past events. This monitoring system is not an expert system recommending how to solve malfunctions. It is more a system which helps operators to take measures before the standard alarm or turbine trip is activated. An interlock of the process parameters generates early warning alarms which are based on the OEM experience and help operators to get a clear picture of an arising problem and to react early enough to avoid forced outages. Additional sensors for additional process parameters have to be installed. The system is part of the AMODIS plant monitoring system and consists of six separately available modules: • Steam inlet valves : To detect increased friction in the actuator and the steam valve guide. • Jacking oil and turning gear : To detect malfunction in the jacking oil and turning gear systems. • Bearing supervision : To detect possible tilting of the bearing pedestal or abnormal oil consumption. • Thermal expansion : To detect extreme or abnormal differential expansion and to detect expansion hindrance. • Thermal efficiency : To detect loss of internal efficiency at an early stage. • Lube oil condition monitoring : To monitor the oil with an online particle counter and a sensor for content of water. All modules can be supplied separately. Modules to check vibration and performance are also available in an AMODIS system but are not covered in this paper.

POWER2007-22128 pp. 335-342; (8 pages)
doi:10.1115/POWER2007-22128

In 2006 Eskom awarded a contract for the retrofitting of the boiler and turbine plant on 6 350MWe units in South Africa. The object of the project is to ensure that the continuous unit rating is increased to 400MWe whilst retaining as much of the existing plant as possible. In addition the plant life will be extended by twenty years. The optimisation process began with the development of various thermodynamic options which would allow a range of power increases. These were then integrated into an economic model which allowed the best option to be identified. In general, a key objective while retrofitting plant is to limit the extent of plant to be changed while still being able to meet the newly defined plant operation conditions, thus allowing for full utilisation of the current assets. This paper details the process followed in the development of the turbine plant retrofit solution. Particular attention is given to the successful Contractor’s Integrated Retrofit Project philosophy, which allows for full optimisation and integration of new components into the plant, while giving assurance of the suitability of the retained equipment.

POWER2007-22129 pp. 343-347; (5 pages)
doi:10.1115/POWER2007-22129

In many cases after 25 plus years of service it may be time to look at the replacement/ upgrade of the instrumentation associated with the stator water cooling skid applicable to armature bars that need to operate in a high or low oxygenated environment. Standards, codes, consolidation, location, redundancy, obsolescence, environmental, safety concerns and runback functionality should be reviewed prior to the next outage or scheduled stator rewind and prudent instrumentation enhancements, if deficient from the list above, should be considered. At the time of instrumentation upgrades, consideration should be given to relocation and improvement of the runback system, e.g. timers, relays, power supplies, and system functionality. Field adjustments quantifying the runback circuit is operating correctly, from both the series of on-off pulses to the turbine reference motor causing a proper load reduction rate and the two trip timers activating at the time the runback begins, need to be verified for proper operation.

POWER2007-22147 pp. 349-358; (10 pages)
doi:10.1115/POWER2007-22147

Computational fluid dynamics is widely used in the aerodynamic performance analysis of the low pressure exhaust system (LPES) which consists of the exhaust hood and condenser neck. However, most of the former studies analyzed the exhaust system separately without considering the effect on flow field from the last stage. In order to get the detailed information of flow field in LPES of steam turbines and reduce energy loss, a numerical model includes condenser neck, exhaust hood and last stage was constructed. This model can describe the effect of unsymmetrical inlet flow on the aerodynamic performance of LPES, so the effect of the inhomogeneous flow from the last stage was taken into account. The Reynolds averaged N-S equations with RNG k-ε turbulence model were adopted to analyze the flow field in the exhaust system considering the interaction between the exhaust system and the last stage, the mixing plane approach was used. The combined model can provide more reasonable numerical results of LPES, it shows that the inhomogeneous flow from the last stage is one of the main reasons leading to flow separation in diffuser. The influence of inner low pressure heater and the diffuse function of the condenser neck structure are the main reasons for the nonuniform velocity distribution of the flow field at the LPES outlet. Furthermore, based on the numerical results, an optimal LPES which has better aerodynamic performance and more reasonable flow is obtained. The optimal structure has low steam resistance and low exhaust pressure, so it can increase the efficiency of turbine.

POWER2007-22189 pp. 359-365; (7 pages)
doi:10.1115/POWER2007-22189

Increasing energy costs and environmental pressures encourage steam turbine users to find the most economical and efficient operation points for their plant. Main steam flow to the turbine is one of the key measurements to determine turbine efficiency and performance. Conventional inferred mass flow measurements, using pressure readings from the turbine first stage, have inherent inaccuracies and assumptions that often lead to incorrect steam flow readings. If those reading accuracies can be improved, the turbine operator will see many advantages, including improved fuel intake and heat rate measurements, higher turbine efficiency over varying loads, better steam control, and increased power generation. Since fuel contributes almost 50% of the total variable cost of electricity generation, operators are discovering the cost benefit of adding direction main steam line flow measurement. This paper compares and contrasts various techniques for computing steam mass flows in utility boilers and outlines the operational benefits of using real time main steam line flowmeters over inferential steam flow computations. Also, a case study is presented which highlights the operational improvements of direct steam flow measurement.

POWER2007-22198 pp. 367-374; (8 pages)
doi:10.1115/POWER2007-22198

A novel online structure damage identification using Principal Component Analysis (PCA) techniques and the perceptron backpropagation neural network is presented. There are three phases to execute this method. In Phase I, system modal information, frequencies and mode shapes, are calculated. Phase II is for damage location identification; the Residual Force Vectors (RFVs) are computed as input to the first neural network. Then the network was trained to simulate damage location identification. Phase III is the severity identification step. The PCA method is used to modify the input for the second neural network. Then this network identifies the severity. There are three advantages of using the PCA method, First, PCA method characterizes the original modal information precisely. Second, PCA method creates the unique data for different damage cases unlike other modal property based data. Third, the accuracy of the damage identification improves significantly, when compared with previously developed methods. This method can be operated online for the real time structural damage identification.

Fuels, Combustion, Emission Technologies and Material Handling

POWER2007-22007 pp. 375-390; (16 pages)
doi:10.1115/POWER2007-22007

This paper asserts a new method of analyzing fossil fuels, useful for sorting coals into well defined categories and for the identification of outlying ultimate analysis data. It describes a series of techniques starting with a new multi-variant approach for describing the lower Ranks of coal, progressing to a classical, but modified, single-variant approach for the volatile and high energy Ranks. In addition, for a few special cases, multiple low and high Ranks are also well described by the multi-variant approach. As useful as these techniques are for analyzing fuel chemistry in the laboratory arena, this work was initiated in support of Exergetic Systems’ Input/Loss Method. At commercial coal-fired power plants, Input/Loss allows the determination of fuel chemistry based on combustion effluents. The methods presented allow equations to be developed independent of combustion stoichiometrics, which improve Input/Loss accuracy in determining fuel chemistry on-line and in real time.

Topics: Fossil fuels
POWER2007-22024 pp. 391-396; (6 pages)
doi:10.1115/POWER2007-22024

Air-fuel balance is the key to clean combustion. Coal-fired public utilities are under constant pressure to meet environmental air quality standards in reducing NOx emissions. Reduction of NOx is critically dependent, on controlled combustion conditions. Accurate measurement and control of the Primary and Secondary Air is an important factor in attaining this goal. Once the Primary Air can be measured accurately, the next variable to consider in the chain is the Secondary air. The actual “Burner Zone Stoichiometry” is the sum of the two air flows to any one burner plus the fuel flow. As shown in Figure 1 below, the Primary air conveys the fuel to the burner and supplies some of the combustion air. The Secondary air provides the oxygen to complete the combustion in the “Burner Zone” to the extent the burner is designed. On a typical burner, there is more combustion air delivered to the burner by the Secondary air than the Primary air generally by a factor of 2, depending on burner design. The additional air or Secondary air completes the combustion in the “Burner Zone”, based on optimizing a set of conditions such as NOx, CO, and boiler tube flame impingement. Maintaining desired stoichiometric ratio and Primary/Secondary air ratio to minimize emissions requires accurate measurement/control of the Primary and Secondary air.

Topics: Coal
POWER2007-22026 pp. 397-411; (15 pages)
doi:10.1115/POWER2007-22026

Climate change is a very important environmental, social and economic global problem. During the last century, the Earth’s average surface temperature rose by around 0.6°C. Evidence is getting stronger that most of the global warming that has occurred over the last 50 years is attributable to human activities. Human activities that contribute to climate change include the burning of fossil fuels because it causes emissions of carbon dioxide (CO2 ), which is the main gas responsible for climate change. In order to bring climate change to a halt, global greenhouse gas emissions would have to be reduced significantly. The European Union (EU) is engaged in international efforts to combat climate change. The EU is also taking serious steps to address its own greenhouse gas emissions. In March 2000 the Commission launched the European Climate Change Programme (ECCP). The ECCP led to the adoption of a range of new policies and measures, among which the EU’s emissions trading scheme, which started its operation on 1 January 2005, will play a key role. In this paper, we want to shortly explain the mechanisms of the Kyoto Protocol, paying particular attention to the Emission Trading. We want to illustrate the European directive and the consequent Italian one: we will explain the Italian implementing norms that have been emitted for the period 2005–2007 and 2008–2012. Limiting then the analysis to the sector of electricity production, we want to show some examples of Italian power plants: we will illustrate them and we will estimate their CO2 emissions (according to a typical annual operation). The emission levels will be compared with CO2 quotas assigned in the period 2008–2012: these results will be commented in terms of the unavoidable economic implications that such allocation will involve. The CO2 quotas, assigned to Italy already for the period 2005–2007, involve a large control of these emissions: such situation will be reflected unavoidably on the increase of the kWh cost (it is already particularly high in comparison with the European average because of the particular energetic mix on which our electricity production is based): these effects could be particularly heavy for the competitiveness of our production system and for the modernization and the widening of our power plant park.

POWER2007-22043 pp. 413-420; (8 pages)
doi:10.1115/POWER2007-22043

Currently there is a need for a model to estimate mass emissions of atmospheric pollutants at the exit of the stacks of thermal power plants that operate under a variable regime of electric power generation based on the variables that typically are monitored during the operation of the plants. The recommended alternative to calculate the mass emissions of pollutants is based on the experimental measurements of pollutant concentration, velocity and temperature at the exit of the stack. This alternative is expensive and cumbersome to implement. Alternatively the US EPA emission factors can be used. However, the emission factors require modifications to account for the type of fuel, the technology used to control emissions, maintenance of the equipment, and the local environmental conditions. As a solution, this paper presents a model to estimate emissions of atmospheric pollutants in thermal power plants based on the variables that are continuously monitored during the operation of most of the thermal power plants in Mexico such as fuel chemical composition, fuel consumption, air to fuel ratio of the combustion process, and mean boiler temperature. The proposed model was calibrated by continuously measuring all the variables included in the three models during one week of operation of a 2.2 GW thermal power plant located in the continental area of the Gulf of Mexico. This plant has six units of generation that operate with fuel oil and one with natural gas. Results obtained from the three methodologies described before were compared. It was concluded that the NOx, SOx and CO results of the proposed model follow closely the results obtained using the measurements of concentration, velocity and temperature at the exit of the stack method. It was also found that the results of the emission factors methodology require to be adjusted to include the particular operating conditions of each unit of electricity generation.

POWER2007-22044 pp. 421-430; (10 pages)
doi:10.1115/POWER2007-22044

This paper looks at a two new conveyor technologies that offer the opportunities for significant improvement in the handling of coal in power plants, and in bulk transportation facilities, and other coal-handling operations. This first technology is “flow-engineered” chutes. Based on material testing and flow studies, these chutes allow the development of transfer chute systems that provide better control, continuous coal flow at higher capacities, and dramatic reductions in material spillage and the release of airborne dust. By regulating the coal flow path of movement, these engineered chutes improve the load placement on the belt, eliminate chute blockages, reduce safety hazards, and minimize maintenance costs. The second leading edge system is air-supported conveyors. Air supported conveyors are now seeing increasing acceptance in coal handling applications in power plants. This is due to the advantages they offer to coal-handling, including high efficiency and low maintenance. This technology also provides a reduction in the release of coal dust, as the carrying side of the conveyor is completely enclosed. This paper will discuss recent installations of these systems in coal handling facilities. In particular, it will feature the engineering and installation of flow-engineered chute systems at AmerenUE’s Meramec and Rush Island Electric Generating Stations, to improve conveyor system performance, while reducing dust as much as 98%. He will also discuss recent application of air-supported conveyor systems in coal handling systems, and discuss the benefits of the application of conveyors combining both “leading edge” systems.

POWER2007-22057 pp. 431-435; (5 pages)
doi:10.1115/POWER2007-22057

MHI G class gas turbine was designed to operate with a Turbine Inlet Temperature (TIT) of 1500 °C. This elevated temperature results in high thermal efficiency but also can induce relatively high emissions. MHI has developed a new Dry Low NOx (DLN) combustor that improves this class turbine compliance with stringent environmental regulations imposed around world. In addition to targeting an environmentally friendly combustor with lower emissions, the redesigned DLN combustor also improves the stability margin. Verification tests of the new DLN combustor were conducted in a M501G1 gas turbine at MHI’s T-Point Combined Cycle Power Plant from May, 2005 to March, 2007. In addition to verifying lower emission levels, these tests confirmed a wide stable operation margin as well as the reliability and durability of the components. The new design is optimized to be retrofitted into existing G class engines. The combustor is now in mass production as a MHI’s standard combustor. This paper describes the design process applied for the new combustor, including the Computational fluid Dynamics’ (CFD) and other analytical tools used.

POWER2007-22065 pp. 437-446; (10 pages)
doi:10.1115/POWER2007-22065

Computational Fluid Dynamic (CFD) models give good predictions of coal combustion in utility boilers if the coal combustion kinetic parameters are known. We developed a three-step methodology to provide reliable prediction of the behavior of a coal in a utility boiler: (1) Obtaining the combustion kinetic model parameters from a series of experiments in a test facility, CFD codes and optimization algorithm. (2) Validation of the combustion kinetic parameters by comparison of different experimental data with simulation results obtained by the set of combustion kinetic parameters. (3) The extracted kinetic parameters are then used for simulations of full-scale boilers using the same CFD code. Three to four bituminous and sub-bituminous coals with known behavior in Israel Electric Corporation (IEC) 550MW opposite-wall (3 coals) and 575MW tangential-fired (4 coals) boilers were used to show the capability of the method. An unfamiliar bituminous coal was then examined prior of its firing in the utility boilers and prediction of its combustion behavior in the two boilers was carried out. This methodology was used to examine a Venezuelan coal that was found to yield high LOI.

POWER2007-22067 pp. 447-454; (8 pages)
doi:10.1115/POWER2007-22067

Slagging caused by deposit of molten fly ash on hot walls is a major concern in the operation of full-scale utility boilers. We carried out a comprehensive study, experimental and modeling, on slagging with various coals. Coal samples were taken prior and during combustion and analyzed by SEM (Scanning Electron Microscope). From the SEM analysis the coals could be divided into two types: (1) Coal with tiny particulates of the mineral matter deposited loosely on the surface of coal particles or between carbon particles (external ash) and (2) coal with the mineral matter encapsulated within the coal particles (internal ash). We found different slagging and char combustion characteristics directly related to the two coal types. It was observed that internal ash coals show higher slagging propensity and higher carbon content in the fly ash. Previous models to predict slagging did not distinguish between the two coal types and their impact on slagging and combustion behavior. We developed a model for high temperature ash deposition on the furnace walls for these two coal types. In this model, char combustion and carbon content in the fly ash are also considered. Comparison of experimental observation with calculation results from the ash deposition model show good agreement. Another conclusion from the model is that slagging propensity for internal ash coals increases with coal particle size. However, this conclusion has to be verified experimentally.

Topics: Combustion , Coal
POWER2007-22094 pp. 455-462; (8 pages)
doi:10.1115/POWER2007-22094

Liquefied Natural Gas (LNG) from offshore reserves is expected to expand its role in supplementing US natural gas supplies. The quality and hydrocarbon contents of the natural gas imported from these international sources, frequently differs from the compositions of domestic natural gas. With the range of variations in fuel characteristics known to exist with offshore LNG, use of this LNG in gas turbine engines could violate applicable fuel specifications, and lead to operational issues such as, but not limited to, combustion dynamics, flashback, increased emissions, or decreased component life. Another potential issue for gas turbines generating power is that rapid changes in the fuel characteristics that may occur when blending imported and domestic gas, may lead to substantial fluctuations in power output. Fuel flexibility is dominantly tied to the combustion system design. Conventional diffusion flame combustion systems are more tolerant of wide variations in fuel compositions but they are limited by their emission levels. The more advanced premixed flame combustors, the Dry Low NOxs (DLN) and Ultra Low NOx (ULN) combustion systems have significantly better performances in terms of emissions but they are also more sensitive to changes in the fuel composition and characteristics. Siemens has performed test campaigns with commercially operating engines and high pressure combustion test rigs to evaluate their commercially available combustion system configurations for LNG applicability. From these test campaigns, Siemens has defined the set of combustion hardware modifications which is robust to changes in fuel composition within the tested limits. Along with the said combustion hardware upgrade, Siemens has also designed an Integrated Fuel Gas Characterization (IFGC) system (Patent Pending). This IFGC system acts like an early warning system and feeds forward signals into the plant control system. Depending on the changes in the properties of the incoming fuel, the IFGC system is designed to adjust the engine tuning settings to compensate for these dynamic changes in the fuel. Customer implementation of the required hardware as well as associated site-specific engineering will mitigate the operational and emissions risk associated with the fuel changes. Overall, it is Siemens recommendation that LNG type fuels will be acceptable to be used in Siemens Gas Turbines with the preferred combustion hardware in place along with the Integrated Fuel Gas Characterization System. A site specific evaluation would be required to determine the optimal system depending on the expected fuels that the unit would be operating with, along with the emissions permit levels associated with the site.

POWER2007-22105 pp. 463-467; (5 pages)
doi:10.1115/POWER2007-22105

A study was carried out to find out the cause of premature plugging of air heaters of a 350 MWe oil fired boiler. The unit burnt a heavy fuel oil number 6, with both high levels of sulfur (3.75%) and asphaltenes (16.2%), as well as high viscosity (555 SSF at 50°C) and API gravity of 11.2. Particle concentration at the furnace exit and at the stack were measured, also flue gas analyses were performed at the same sites. In the furnace were employed water cooled probes of six meters in length which allowed traversing 70% of its width. In addition, the oil droplet size distribution from an atomizer was measured with a Malver Particle Sizer. Cold condition using simulating fluids were taken in this analysis. Also, the unburned carbon particles size distribution, both from the furnace exit and from the stack, was performed with a particle Malver Sizer. The atomizer produced large oil drops, 5.7% by volume larger than 300 micron size, which were considered as promoters of unburned carbon. The concentration of carbon particles in the stack was 60% of that of the furnace exit. Furthermore, the particles from the stack were of smaller size (95% <150 μm) than those of the furnace (89% <150 μm). Deposition of carbon particles in the internal component of the boiler, mainly in the air heaters, was the cause of this finding. To solve the premature plugging of the air heaters of this oil fired boiler, the atomizers should be modified to reduce at a minimum level the oil drops larger than 200 micron size.

Topics: Coke , Boilers
POWER2007-22109 pp. 469-480; (12 pages)
doi:10.1115/POWER2007-22109

Over the past few decades, interest in the effects of greenhouse gas (GHG) emissions on global climate change has peaked. Increasing temperatures worldwide have been blamed for numerous negative impacts on agriculture, weather, forestry, marine ecosystems, and human health. The U.S. Environmental Protection Agency reports that the primary GHG emitted in the U.S. is carbon dioxide (CO2 ), most of which stems from fossil fuel combustion [1]. In fact, CO2 represents approximately 85% of all GHG emissions nationwide. The other primary GHGs include nitrous oxide (N2 O), methane (CH4 ), ozone (O3 ), and fluorinated gases. Since the energy sector is responsible for a majority of the GHGs released into the atmosphere, policies that address their mitigation through the production of electricity using renewable fuels and distributed generation are of significant interest. Use of renewable fuels and clean technologies to meet energy demand instead of relying on traditional electrical grid systems is expected to result in fewer CO2 and CH4 emissions, hence reducing global climate change impacts. Technologies considered cleaner include photovoltaics, wind turbines, and combined heat and power (CHP) devices using microturbines or internal combustion engines. The Self-Generation Incentive Program (SGIP) in California [2] provides incentives for the installation of these technologies under certain circumstances. This paper assesses the GHG emission impacts from California’s SGIP during the 2005 program year by estimating the reductions in CO2 and CH4 released when SGIP projects are in operation. Our analysis focuses on these emissions since these are the two GHGs characteristic of SGIP projects. Results of this analysis show that emissions of GHGs are reduced due to the SGIP. This is because projects operating under this program reduce reliance on electricity generated by conventional power plants and encourage the use of renewable fuels, such as captured waste heat and methane.

Topics: Emissions
POWER2007-22116 pp. 481-492; (12 pages)
doi:10.1115/POWER2007-22116

This paper presents the results of a study conducted by Itron, Sustainable Conservation and Bowen & Associates for the Sacramento Municipal Utility District (SMUD) to investigate the status and costs of controls for reducing emissions of oxides of nitrogen (NOx ) from small (100 to 300 kW) reciprocating engines operating on biogas from dairy digesters. During the course of the study, it became apparent that simultaneous environmental policies have created a fundamental “catch 22” situation for California’s biogas industry. On one hand, California air quality regulations require distributed generation (DG) technologies to achieve aggressive emission limits for control of oxides of nitrogen (NOx ). At the same time, California’s Governor and Legislature have passed landmark legislation calling for GHG emissions to be reduced by twenty-five percent to 1990 levels by no later than 2020. A “catch 22” occurs because while DG technologies, particularly biogas fueled technologies, can play a key role in reducing GHG emissions, NOx control technologies needed to meet the required NOx levels have not matured to commercial readiness. This requires project developers to take substantial risks on both the financial and technical front without the likelihood of recouping their investments. The result creates an impasse that potentially deprives California not only of forward progress in reducing GHG emissions but forestalls significant interim NOx reductions that could otherwise be achieved. However, the situation highlights a problem that extends beyond California’s borders and the biogas industry: how to simultaneously achieve aggressive air quality targets while making significant reductions in greenhouse gas (GHG) emissions. This paper presents the findings of an investigation into proposed NOx emissions limits for biogas to energy applications and how those requirements interact with policies to reduce GHG emissions.

POWER2007-22141 pp. 493-496; (4 pages)
doi:10.1115/POWER2007-22141

Ammonia injection grid (AIG) is used to introduce vaporized ammonia (NH3 ) into an exhaust gas stream for nitrous oxide (NOx ) reduction in selective catalytic reduction (SCR) systems. Computational and experimental studies on the AIG resulted in significant improvements in the turbulence mixing between the injected ammonia and the exhaust gas. Improved mixing is instrumental to maximize catalyst performance, extend catalyst life time, minimize catalyst volume, decrease system pressure drop, minimize reagent use and ammonia slip, minimize the overall size of the SCR system, and minimize risks associated with designing the SCR system. It is found that an AIG with a turbulence-generating edge dramatically increases the mixing efficiency and, therefore, reduces the mixing distance required to obtain acceptable distributions of the NH3 to NOx ratio. Results indicate over 50% reduction of the required mixing distance due to the turbulence generating edge. This work summarizes the obtained results from computational CFD simulations for two-dimensional and three-dimensional models, however the proposed arrangement of the injection grid has been successfully tested in laboratory experiments and applied to several commercial power generating systems. The commercial performance results will be reported in the subsequent publications.

POWER2007-22144 pp. 497-505; (9 pages)
doi:10.1115/POWER2007-22144

Gasification converts the carbon-containing material into a synthesis gas (syngas) which can be used as a fuel to generate electricity or used as a basic chemical building block for a large number of uses in the petrochemical and refining industries. Based on the mode of conveyance of the fuel and the gasifying medium, gasification can be classified into fixed or moving bed, fluidized bed, and entrained flow reactors. Entrained flow gasifiers normally feature dilute flow with small particle size and can be successfully modeled with the Discrete Phase Method (DPM). For the other types, the Eulerian-Eulerian (E-E) or the so called two-fluid multiphase model is a more appropriate approach. The E-E model treats the solid phase as a distinct interpenetrating granular “fluid” and it is the most general-purposed multi-fluid model. This approach provides transient, three-dimensional, detailed information inside the reactor which would otherwise be unobtainable through experiments due to the large scale, high pressure and/or temperature. In this paper, a transient, three-dimensional model of the Power Systems Development Facility (PSDF) transport gasifier will be presented to illustrate how Computational Fluid Dynamics (CFD) can be used for large-scale complicated geometry with detailed physics and chemistry. In the model, eleven species are included in the gas phase while four pseudo-species are assumed in the solid phase. A total of sixteen reactions, both homogeneous (involving only gas phase species) and heterogeneous (involving species in both gas and solid phases), are used to model the coal gasification chemistry. Computational results have been validated against PSDF experimental data from lignite to bituminous coals under both air and oxygen blown conditions. The PSDF gasifier geometry was meshed with about 70,000, hexahedra-dominated cells. A total of six cases with different coal, feed gas, and/or operation conditions have been performed. The predicted and measured temperature profiles along the gasifier and gas compositions at the outlet agreed fairly well.

POWER2007-22145 pp. 507-513; (7 pages)
doi:10.1115/POWER2007-22145

A difficult balance must be maintained between new asset investment costs, operating and maintenance costs, and maintaining an acceptable level of risk. Various capital investment and budget allocation strategies have been implemented to prioritize asset allocation. To maintain a competitive edge in plant operations, these sound fundamentals must also be applied to all areas of a plant, including the coal yard. By ignoring even “small” deficiencies, operations are exposed to wasted budget dollars and manpower assets and well as to potentially large risks.

POWER2007-22153 pp. 515-532; (18 pages)
doi:10.1115/POWER2007-22153

All the different kinds of coal which are often non-flowable are successfully being “induced” to vertically flow and discharge from storage. This includes Bins, Silos, and Rail Cars which can completely empty. The Storage Piles are being made safe for added reclaim.

Topics: Machinery , Coal
POWER2007-22155 pp. 533-545; (13 pages)
doi:10.1115/POWER2007-22155

In the early twenty-first century, emphasis on fossil fuel emission reductions was focused on gaseous emissions. NOx emissions were recognized as precursors of smog and as such adversely affected the quality of life. Lately, emphasis on emission reductions has shifted to solid emissions. Particulates are recognized as health hazards that contribute to respiratory ailments. Fossil fuel combustion — so fundamental to the nation’s economy — unfortunately produces both emissions. Thus, the development of after-treatment technologies to treat fossil fuel combustion was pursued. Imposition of after-treatment technology proved costly from both application and maintenance aspects. In some instances, introduction of after-treatment technology caused a decrease in fuel efficiency. In view of the foregoing, it is important to note that there is a technology that REDUCES gaseous AND solid emissions of liquid fossil fuels. Furthermore, this technology can INCREASE fuel efficiency. The technology that can deliver this “triple-crown” of dual emission reduction and enhanced fuel efficiency is EMULSIFIED FUEL TECHNOLOGY (EFT). In this paper, we consider the constitution, production and characteristics of Emulsified Fuels. Then we consider their combustion and the environmental benefits that can accrue to their utilization. Finally, we consider past applications of EFT and the future markets for this intriguing technology.

POWER2007-22181 pp. 547-557; (11 pages)
doi:10.1115/POWER2007-22181

In the past few years, with the development of advanced numerical computational codes, numerical simulation became a promising option to developing and improving the technology in different fields. The obtained results by simulations are used to get important information during the design phase or optimization of industrial equipment. Its employment generates reliable results at low cost due to the reduced number of experiments as well as the opportunity to develop new products and perform many simulations before its production. However, the numerical simulation credibility can only be verified when compared to the obtained results by experiments. This work aims to present and evaluate different aerodynamics models applied to combustion chambers using a CFD tool. In addition, aerodynamic analysis is made in a model of combustion chamber, where the flow is simulated with successive refining of the mesh as part of its validation process. For it, it is used a Low Nox Emission Combustion Chamber from Floxcom project as reference to validate turbulence models. Once that it is done, the selected turbulence model with satisfactory precision is used to describe the aerodynamic behavior of an annular combustion chamber from velocity and pressure distribution, which are important parameters to set load losses and recirculation intensity, which can affect the complex phenomenon of combustion.

Renewable and Advanced Energy Systems

POWER2007-22054 pp. 559-565; (7 pages)
doi:10.1115/POWER2007-22054

PBMR (Pty) Ltd. is undertaking the implementation of its demonstration project in Koeberg, South Africa with construction planned to start in 2008. Key test facilities have been completed and full-scale tests of first-of-a-kind components are underway. PBMR (Pty) Ltd., as part of a Westinghouse-led consortium, has been awarded the lead contract for the pre-conceptual design of the NGNP project; which could lead to a major demonstration project in the US some time next decade. Also, PBMR is working with Shaw and Westinghouse to develop several important non-power applications, using the high temperatures available from a 500MWt version of the reactor to produce high pressure steam for oil sands in-situ recovery operations, high temperature energy for steam methane reforming, and for thermal water splitting to produce hydrogen and oxygen. Water splitting offers dramatic improvements in coal-to-methane and coal-to-liquids applications by avoiding the inefficiencies of converting coal to hydrogen, with its associated CO2 emissions. This paper presents an update of the status of this work and the projected uses of this breakthrough nuclear technology.

POWER2007-22063 pp. 567-574; (8 pages)
doi:10.1115/POWER2007-22063

Biodiesel is an alternative fuel that has become more attractive recently because of its environmental benefits and the fact that it is made from renewable resources. As it can be blended in any proportion with mineral Diesel, and there are several reports which presented substantial reductions in emissions of unburned hydrocarbons, carbon monoxide and particulate in IC engines without reducing the output power significantly. The aim of this work was to perform an emissions and performance experimental analysis to evaluate and compare the use of Biodiesel obtained from different sources, Castor, Soy and Palm Oil, on a 30 kW regenerative gas micro turbine engine installed in the laboratories of the Federal University of Itajubá – Unifei, Brazil, at different power levels at steady state condition. All the fuels were characterized in terms of its viscosity and heat value, and the thermal performance and the emissions were measured. In all cases, it was performed a comparison between the obtained results with Biodiesel and Diesel. None of the fuels presented any problem related to atomization process in the related tests, and have shown no significant changes in performance of the microturbine reaching levels of around 26% of thermal efficiency. The minimum Heat Rate obtained at full load, was for the Biodiesel from Palm oil case, and the maximum was for Castor oil with a value 8.38% higher than when operated with Diesel. In Addition, when measuring pollutants emissions in the exhaust gases, it was observed a slightly increment in CO and a reduction in NOx concentration.

POWER2007-22098 pp. 575-586; (12 pages)
doi:10.1115/POWER2007-22098

A model of a Micro Gas Turbine system for cogeneration is presented. The analyzed plant is based on an aero derivative Gas Turbine with a single staged centrifugal Compressor and an axial Turbine with two stages. The net power output is 260 kWe in simple cycle mode. Exhaust gases can be sent to a counter flow surface compact heat exchanger for thermal regeneration, which turns to be thermodynamically favourable in this range of power output. If a thermal load is required the system operates in CHP configuration and part, or the whole, of turbine exhaust gases are sent to a Heat Recovery Boiler for water heating. The HRB is, in analogy to the Regenerator, a counter flow surface heat exchanger. The mass of hot gases directed to each heat exchanger can be controlled by a regulation valve that allows, for a given fuel mass flow rate, to enhance the net power output or to privilege the thermal generation at the HRB. This degree of freedom allows the system to operate at different cogeneration degrees, thus covering many power-to-heat demand ratios. The whole system is modeled in the Simulink® environment, a powerful tool for dynamic system analysis. All components are studied and a mathematical representation for each of them is described. Equations are then implemented in Simulink® allowing to create customized blocks of different components which are then properly coupled, respecting the physical causality of the real system, by connections that may represent either mechanical or fluid dynamic links. Models are classified depending on whether state variables for the considered component can be defined or not. Compressor and turbine are represented as “Black Box” components without state, while the combustion chamber is modelled as a “white box” applying energy and mass conservation equations with three state variables. Heat exchangers are considered as “White Box” without state, and the physics of the heat exchange process is studied according to the Effectiveness-NTU method. A further dynamic equation is the shaft dynamic balance equation. Model results are reported in the paper in several transient conditions: in all cases the computational time proved to be lower than real time.

POWER2007-22108 pp. 587-593; (7 pages)
doi:10.1115/POWER2007-22108

This paper presents the results of a study conducted by Itron for the California Public Utilities Commission (CPUC) to examine the relationships between solar photovoltaic (PV) performance, costs, and PV incentive structures. The intent is twofold. The first intent is to create a baseline of PV performance and costs using actual performance data and reported costs from a large number of PV systems installed and operating in California. The second intent is to examine how PV performance and projected PV cost reductions can influence PV incentive payments. This study should help provide policy makers responsible for developing PV incentive programs with information that will result in incentive structures that fairly and transparently reward improved PV cost and performance while simultaneously providing a reasonable pathway to move PV towards an incentive-free market environment. PV performance monitoring data for over one hundred operating commercial, industrial, and institutional solar PV systems are combined with projected electricity retail rates and future PV costs within a breakeven levelized cost model to produce associated PV incentive levels. Preliminary results for 39 prototype PV market scenarios provide insights into how PV incentive levels can be set to take advantage of utility-specific electricity retail rates, PV configuration and location, and projected PV cost reductions while facilitating the development of PV systems that can compete without incentives. Potential implications of these performance and cost-effectiveness results are discussed with respect to PV incentive programs and PV markets.

POWER2007-22115 pp. 595-604; (10 pages)
doi:10.1115/POWER2007-22115

Developing approaches that can improve the value and “affordability” of renewable distributed generation (DG) is a key factor in developing a sustainable market. Program support activity is increasing in the U.S. in response to the 21+ states that have legislated Renewable Portfolio Standards. This paper addresses technology performance and related market entry barriers of several new innovative applications intended to increase the amount of available and harvested biogas resources, incorporate high-value applications of building-applied photovoltaics (BA-PV) and develop a more complete understanding of the impacts of these renewable DG resources upon the local electric distribution system — with the goal of achieving significantly positive net benefits to project owners/developers, their host customer facility operations, and to the serving electric and gas utilities. The overarching goal of this $10 million co-funded California Energy Commission and Commerce Energy Public Interest Energy Research Program (PIER) was to provide effective and more affordable renewable energy solutions within the Chino Basin, while applicable throughout California through specific targeted technology and market demonstrations that will lead to development of a sustainable market for on-site power generation using several types of biogas fuel and solar photovoltaic energy resources. Key outcomes resulting from the Program conclude that approximately 28 to 50 MW of PV and biogas distributed resources are expected to be developed in the nonresidential market segment alone through 2012, representing about 10 percent of Southern California Edison’s total peak load in the basin. Distribution system deferral benefits to SCE are location-specific. Up to $4.4 million in system deferral benefits may be achieved from this incremental renewable generation within the basin. Based on this first California Energy Commission-supported Programmatic RD&D approach, this paper explores the following questions: 1) How can electric grid benefits resulting from a geographically targeted renewable distributed generation effort be more fully quantified and improved? 2) Will the applications of food waste codigestion (with the local dairy waste), or ultrasound technology (applying high concentrations of sonic energy) improve waste activated sludge solids destruction and increase biogas production efficiency and onsite power generation at municipal/regional wastewater treatment facilities? 3) Can side-by-side testing and evaluation of 13 separate photovoltaic systems lead to a recommended format for an independent Consumer Reports style evaluation of the PV industry’s leaders in nonresidential and building-applied applications? These answers and other important results regarding the latest biogas and solar PV technology and their associated benefits and costs that were implemented within the 565 MVA Commerce Energy/SCE distribution system mini-grid are summarized in this paper. An overall program description and project descriptions for each biogas/PV project and associated final report documentation can be downloaded from the Commerce Energy PIER Program website at http://www.pierminigrid.org/.

POWER2007-22137 pp. 605-614; (10 pages)
doi:10.1115/POWER2007-22137

This paper outlines a demonstration project planned and implemented at the Canadian Centre for Housing Technology (CCHT) in 2006. The CCHT, located on the campus of the National Research Council (NRC) in Ottawa, Ontario, Canada maintains two identical, detached, single-family houses that have the capacity to assess energy and building technologies in side by side comparisons with daily simulated occupancy effects. The paper describes the residential integrated total energy system being installed in one of the homes at the CCHT for this demonstration, consisting of two one-ton ground source heat pumps, an air handler with supplemental/back-up hydronic heating capability, a natural gas fired storage type water tank, an indirect domestic hot water storage tank and a multistage thermostat capable of controlling the system. There is also a description of the bore-field, consisting of three vertical wells arranged to suit a typical suburban landscape. Two of the wells serve the heat pumps; the third well is arranged between the other two to sink the waste heat from a cogeneration unit. The 6 kWe cogeneration unit to be installed in May 2007 is also described. The heat pump system was deliberately sized to satisfy the cooling load in Canada’s heat dominated climate, leaving room in the operation of the system to accept waste heat from the cogeneration unit, either directly or indirectly through recycling the heat through the ground to the heat pumps. This paper presents and discusses preliminary testing results during the fall of 2006 and modeling work of the ground heat exchanger component of the system and therefore sets the stage for performance modeling work that is currently underway at Natural Resources Canada (NRCan).

Topics: Testing
POWER2007-22142 pp. 615-621; (7 pages)
doi:10.1115/POWER2007-22142

Standard centrifugal pumps are manufactured in a large number of sizes in order to cover a wide range of heads and flow rates. Conventional turbines, however, are not mass produced since they are custom designed and manufactured. Therefore, pumps are available in the market at comparatively lower cost and shorter delivery periods. In this paper an experimental study is presented in which the use of pumps as turbine (PAT) is explored for micro-hydro power generation. The objective of the study is to explore cheap alternate sources of energy production in remote locations of Pakistan. Extensive research has been carried out by Williams [1] in the field of using pumps as turbines. Only centrifugal pumps were studied to explore their use as turbines in that work. Since then quite a bit of advancement in this sector of technology has taken place. However, to the best of our knowledge, axial flow pumps have never been tested as turbines. The site conditions for micro-hydro power station usually find axial flow pumps to be more appropriate compared cross flow and pelton turbines. A commercially available axial flow pump was selected and test rig was designed and constructed in order to determine the performance characteristics of using the pump as a turbine. The test bed has a provision of simulating various head and flow rate conditions and dynamometer to measure the power output in order to determine the performance of the turbine. The simulated head and flow rates were varied for various typical conditions. Some minor modifications in the basic pump unit were made to accomplish these tests. The experimental study resulted in generating data for which head was varied from 4 to 12 m and flow rate from 700 to 900 m3 /hr. For these conditions power developed ranged from 5–20 kW with a maximum efficiency of 70% corresponding to a head of 6.8 m and a flow rate of 800 m3 /hr. Pump affinity laws and the data collected in this experimental study were then used to select a Kaplan turbine. This information was then used to choose a commercially available pump for typical low head and high flow rate conditions in Pakistan to generate about 100 kW of electric power, when running in turbine mode. This paper discusses the design and construction of the test rig to carry out experiments for testing pumps as turbines. Details of experimental procedure and results to determine performance characteristics are also presented. Finally selection procedure of a pump for a specific head and flow condition are also discussed in this paper.

POWER2007-22175 pp. 623-628; (6 pages)
doi:10.1115/POWER2007-22175

What I invented is a method on how to use gravitational and buoyant forces and generate multiple times more energy than energy is spent. In another words, generated energy is greater then spent energy. Even though this is considered as not possible with today’s scientific knowledge, I have experimentally proved it on miniature prototype I’ve made and tested. The measurement on my miniature prototype shows that generated energy is greater than energy we have to spend in order to produce energy. This method may provide as much energy as we want at any point on Planet Earth. There will be no need to burn gas or any other material in order to produce energy, as it is today. All energy needs anywhere in the World will be provided using this method. Today we use gasoline or other material to burn in order to produce energy. Ultimately, using this method to generate energy pollution and other environmental problems will be significantly reduced or even eliminated. The biggest obstacle with this method is to convince other people to believe that my claim is feasible in practice. Even though, I’ve made and tested prototype to prove my claim, still resistance and disbelieve exist. Reason for disbelieve is that my method violates existing First Law of Thermodynamic and therefore is considered as not possible. The method is very simple, but in order to generate significant amount of energy Multiplier Device must be quite a massive. Size of the Device is in direct proportion with energy wanted to generate. For example, Device should be about 30 feet high and 9 feet in diameter in order to produce about 5000 J/sec, which is to have power about 5kWatts. Yes, I’ve made much smaller Device to prove the feasibility of my method, by measurement and calculation. To make Energy Multiplier Device operational without any energy from outside, the size of the Device must be much greater. How the World will benefit from this project? First, this method of energy generation will allow to produce as much energy as we want at any point on Planet Earth, at least theoretically. Amount of energy produced using this method is in direct proportion with the dimensions. If we are able to make Device with unlimited height, the Device will be able to produce unlimited amount of energy. The method produces 100% clean energy, so the benefits will be: – to eliminate burning any material to produce energy; – to eliminate CO2 generation, main reason for climate change (global warming); – to significantly reduce air pollution, if not eliminate; – to eliminate environmental problems; – To provide enough energy for unlimited use; – to provide energy independence for any entity, Country, State, Household, etc; – other benefits are up to your imaginations. By the way, this project has been selected for oral presentation at World Renewable Energy Congress, Florence, Italy, 19–25 August 2006.

Combined Cycle Power Plants

POWER2007-22032 pp. 629-635; (7 pages)
doi:10.1115/POWER2007-22032

A system was developed to diagnose the operation of combined cycle power plants and to determine, when deviations are found, which components are causing the deviations and the impact of each component deviation. The system works by comparing the values of the actual operating variables with some reference values that are calculated by a model that was adjusted to the design heat balances. The model can use the actual values of the environmental parameters as well as the design values, so the effect of environmental changes can be quantified and separated. The determination of the individual equipment impacts is done by adjusting the equipment parameters in order to reproduce the values of the measured variables. The adjustment is done by varying the values of the characteristic parameters of the equipment in order to minimize the sum of the squares of the differences between the values of the measured variables and the calculated values from the model.

POWER2007-22041 pp. 637-644; (8 pages)
doi:10.1115/POWER2007-22041

As a gas turbine entry temperature (TET) increases, thermal loading on first stage blades increases too and therefore, a variety of cooling techniques and thermal barrier coatings (TBCs) are used to maintain the blade temperature within the acceptable limits. In this work a multi-block three dimensional Navier-Stokes commercial turbomachinery oriented CFD-code has been used to compute steady state conjugated heat transfer (CHT) on the blade suction and pressure coated sides of a rotating first inter-stage (nozzle and bucket) with cooling holes of a 60 MW Gas turbine. A Spallart Allmaras model was used for modeling the turbulence. Convection and radiation were modeled for a super alloy blade with and without TBC. The CFD simulations were configured with a mesh domain of nozzle and bucket inter-stage in order to predict the fluid parameters at inlet and outlet of bucket for validate with turbine inter-stage parameter data test of gas turbine manufacturer. The effects of blade surface temperature changes were simulated with both configurations coated and uncoated blades.

POWER2007-22078 pp. 645-652; (8 pages)
doi:10.1115/POWER2007-22078

The paper addresses the need for efficiency gains in the modern industrial engine as utilized in Combined Heat and Power (CHP) generation and other Distributed Generation (DG) situations. Power generation is discussed in terms of reciprocating-engine-based plant operating on Otto type thermodynamic cycles. The current state of the technology and the research being conducted is examined. Internal combustion engine (ICE) performance improvement in the industrial engine sector focuses on improvements in the combustion characteristics of the plant, with emphasis on areas such as piston design, valve timing and supercharging. Maximum brake thermal efficiencies, in percentage terms, are currently in the forties. In CHP generation, most of the energy not utilised for mechanical power is recovered as heat from various engine systems such as jacket water and exhaust and utilised for space or process heating. In other Distributed Generation situations, this energy is not utilised in this manner and is lost to the surroundings. While second law analysis would provide a more meaningful interpretation of the efficiency defect, this approach is still not the norm. Distributed Generation benefits directly from efficiency improvements; the more efficient use of primary energy leads to reduced fuel costs. Combined Heat and Power generation is, however, more sensitive to the matching between the plant and its energy sinks, as its successful implementation is dictated by the ability of a site to fully utilise the heat and electrical power produced by the plant. At present, the energy balance of such engines typically dictates that heat is produced in greater quantity than electrical power, the ratio being of the order of 1.1 — 1.5: 1. Due to this production imbalance, it is accepted that in order to be economically feasible, thermal and electrical demand should be coincident and also all heat and power should be utilised. This has traditionally led to certain sectors being deemed unsuitable for CHP use. Some current research is aimed at tipping the production balance of these engines in favour of electrical power production; however, performance gains in this regard are slow. The paper concludes with some brief commentary on current industrial engine developments and applications and proposes some directions for progress.

Topics: Engines
POWER2007-22100 pp. 653-663; (11 pages)
doi:10.1115/POWER2007-22100

Siemens H-Class . Siemens has developed the world-largest H-class Gas Turbine (SGT™) that sets unparalleled standards for high efficiency, low life cycle costs and operating flexibility. With a power output of 340+ MW, the SGT5–8000H gas turbine will be the primary driver of the new Siemens Combined Cycle Power Plant (SCC™) for the 50 Hz market, the SCC5–8000H, with an output of 530+ MW at more than 60% efficiency. After extensive lab and component testing, the prototype has been shipped to the power plant for an 18-month validation phase. In this paper, the compressor technology, which was developed for the Siemens H-class, is presented through its development and validation phases. Reliability and Availability . The compressor has been extensively validated in the Siemens Berlin Test Facility during consecutive engine test programs. All key parameters, such as mass flow, operating range, efficiency and aero mechanical behavior meet or exceed expectations. Six-sigma methodology has been exploited throughout the development to implement the technologies into a robust design. Efficiency . The new compressor technology applies the Siemens advanced aerodynamics design methodology based on the high performance airfoil (HPA) systematic which leads to broader operation range and higher efficiency than a standard controlled diffusion airfoil (CDA) design. Operational Flexibility . The compressor features an IGV and three rows of variable guide vanes for improved turndown capability and improved part load efficiency. Serviceability . The design has been optimized for serviceability and less complexity. Following the Siemens tradition, all compressor rotating blades can be replaced without rotor lift or destacking. Evolutionary Design Innovation . The compressor design incorporates the best features and experience from the operating fleets and technology innovation prepared through detailed research, analysis and lab testing in the past decade. The design tools are based on best practices from former Siemens KWU and Westinghouse with enhancements allowing for routine front-to-back compressor 3D CFD multistage analysis, unsteady blade row interaction, forced response analyses and aero-elastic analysis.

POWER2007-22143 pp. 665-675; (11 pages)
doi:10.1115/POWER2007-22143

The present paper deals with the dynamic analysis of a heavy duty combustion turbine running on natural gas. Hence, a mathematical model of the power plant has been implemented. The model is able to simulate the engine behavior during steady state, as well as transient conditions. In order to test the model efficacy and accuracy, a dynamic analysis of a Siemens V94.3 A running as topper in a Combined Cycle (CC) complex has been carried out. Therefore, numerical results have been compared with experimental data extracted from the monitoring system of the plant for different running conditions. Comparison results analysis highlighted that the developed mathematical model is able to simulate correctly engine behavior in different combustion turbine conditions.

POWER2007-22183 pp. 677-684; (8 pages)
doi:10.1115/POWER2007-22183

The present work investigates gas turbine and municipal solid waste (MSW) incinerator hybrid combined cycles for power production. The aims are to achieve high efficiency for energy recovery from MSW while minimizing environmental impacts. In the combined cycles, the topping cycle consists of a gas turbine, while the bottoming cycle is a steam cycle, utilizing the heat from MSW combustion. Comprehensive simulations were made to analyze the viability of the combined cycles and their thermodynamic advantages over conventional incineration of MSW. The results showed that the hybrid combined cycles could offer dramatically higher efficiency for power production and provide practical solutions to problems typically associated with MSW. The environmental impact has been examined and it is shown that the combined cycles could provide an effective means of reducing greenhouse gas emissions. The capital and operating analyses indicate that the combined cycles for power production and waste handling are economically competitive.

Performance Testing and Performance Test Codes

POWER2007-22087 pp. 685-694; (10 pages)
doi:10.1115/POWER2007-22087

The ASME Performance Test Code, PTC 11 Fans, is currently undergoing revision. While there are several changes being made, there are also new additions, the most notable of which is a method to measure input power at reduced fan loads. This information is often required to validate a power guarantee; a condition that presents a unique challenge because fan operation needs to be established at a specific flow and pressure rise that can be corrected to guarantee inlet conditions using the fan laws of similarity. Part 1 of this paper outlines a testing procedure to achieve results close to the specified condition. There is a very low probability that any particular test can be performed at the guarantee condition so several tests within acceptable bounds of the specified point are necessary. Part 2 of this paper discusses a multipoint, distance-weighted interpolation method for determining the final result.

POWER2007-22095 pp. 695-700; (6 pages)
doi:10.1115/POWER2007-22095

One of the most important aspects of American Society of Mechanical Engineers (ASME) Performance Test Code (PTC) thermal performance testing is the proper determination of test uncertainty since the Uncertainty Analysis (UA) validates the quality of a test as well as demonstrates that the test meets code requirements. It can also carry a commercial relevance when test tolerances are linked to uncertainty figures. This paper introduces an approach to the calculation of the random component of uncertainty when covariance exists between certain primary measurements in thermal performance testing. It demonstrates how to identify parameters that are co-variant, provides a methodology for properly calculating the aggregated random uncertainty of co-variant measurements, and discusses the effect of co-variance on UA results.

POWER2007-22099 pp. 701-711; (11 pages)
doi:10.1115/POWER2007-22099

The ASME performance test codes require an uncertainty analysis as part of a code test, and some codes require both a pre-test and a post-test uncertainty analysis. ASME PTC-19.1, Test Uncertainty provides the basic approach to conducting an uncertainty analysis. The individual test codes, such as ASME PTC-11, Fans, provide specific guidance for uncertainty analysis of tests of particular equipment or processes. The following issues related to an uncertainty analysis for a PTC-11 fan test are discussed. • Evaluating uncertainties for traverse measurements — Fan testing requires one or more traverses to measure flow rate as well as various pressures, temperatures, and gas composition. Evaluating and propagating the uncertainty associated with traverse point measurements to obtain overall uncertainty is explained. • Evaluating uncertainties for non-traverse measurements — Fan testing also requires the measurement of power input, fan speed, and atmospheric temperature and pressure. Evaluating the uncertainties in these quantities is discussed. • Propagating uncertainties of the measurements into the final results — An analytical method is compared to “dithering” to obtain a sensitivity factor. • Using a pre-test uncertainty analysis to optimize the test design — Examples are provided on how a pre-test uncertainty analysis can be used to reduce the uncertainties of a fan test. The results include results of sample pre-test and post-test uncertainty analyses for fans.

Topics: Testing , Uncertainty
POWER2007-22107 pp. 713-726; (14 pages)
doi:10.1115/POWER2007-22107

Accurate performance correction equations are essential to the successful implementation of an initial performance test of a new unit, and to continually monitor performance in a meaningful way. Developers of these formulations must consider the latest design information of all major equipment in the cycle. Per Section 5.3.5 of ASME PTC 46–1996 [Ref. 1], these corrections are to be developed from a heat balance computer model after it is “finalized following purchase of all major equipment and receipt of performance information from all vendors.” This paper reviews the requirements for the development of accurate correction curve/factor formulations for a typical combined cycle power plant, and demonstrates how significantly skewed the results of a test can be if assumptions on equipment design performance are made prior to manufacturers’ final submittals.

POWER2007-22110 pp. 727-737; (11 pages)
doi:10.1115/POWER2007-22110

For many years now, an increased emphasis has been placed on the energy requirements of electric motor driven equipment. For end-users footing monthly electrical bills, efficiency is important along with the assurance that the equipment delivers the specified output. With fans, it is now commonplace to put performance guarantees in place when purchasing new equipment which specify volume flow, pressure requirements and expectations for efficiency or power that have to be met. Test procedures suitable for conducting fan performance guarantee tests are available in many published AMCA, ASME, ANSI, BS and ISO performance test standards and codes. These procedures specify how to measure the fan performance at discrete operating points and provide uncertainty analysis methods to estimate the accuracy of the test. Some test standards are believed to provide more accurate field test results than others. It is generally recognized throughout industry that it is virtually impossible to have suitable correlation between the site and the specified design conditions for the purpose of a ‘guarantee test’. This is often due to differences in the actual system resistance compared to what was predicted by the original design calculations as well as difficulties of adjusting system resistance and maintaining system stability with a process operating on line. The method of fan volume flow control, whether variable speed or throttle control, influences the amount of time and effort required to get the test point as close as possible to the specified operating point. With possibly the exception of AMCA and BS, published test standards and codes generally do not provide methods for evaluating whether the performance guaranteed by the fan vendor has been verified by a performance test. This technical paper provides guidelines for how to approach the difficult problem of verifying guaranteed operating points on fans. It specifically deals with the following aspects: - Evaluation of both partial and full capacity operating points. - Data collection methodology for selecting the number and relative positions of performance test points that are required to verify a guaranteed operating point. - Evaluation methodology that will relate the test points obtained to the specified operating point; Single Point, Multiple Point Line and Multiple Point Box data collection and evaluation methods. - Potential acceptance tolerances for flow, pressure, power and/or efficiency of the guaranteed operating point. - Field test accuracy and the implications on acceptance tolerances.

POWER2007-22120 pp. 739-748; (10 pages)
doi:10.1115/POWER2007-22120

Based on the present revival of coal as the fossil fuel of choice for power generation, there is a high probability that several IGCC projects will materialize in the near future. One of the challenges facing the Owners, EPC Contractors and OEM’s will be to define the performance commercial guarantees and the practical means to determine them. In addition following the current huge upturn in conventional supercritical coal fired power plants, a large number of facilities will conduct thermal performance tests. The proper conductance of the test, data collection and correction to reference conditions, have many technical implications and could affect drastically the commercial outcome of a project both for the Contractor and the Owner. For IGCC plants, in anticipation of this probability, ASME Performance Test Committee had developed a Performance Test Code for such type of plant — PTC 47, which was published in January 2007. In the first part, the paper will provide details about the specific challenges facing the implementation of the Code, in particular the proposed use of the input/output method (mass and energy balance). The presentation will cover other highlights of the code recommendations. The methodology is fully applicable to conventional power plants, since they use same type of fuel. The determination of the heat input based on actual continuous measurement of the mass flow and composition of the coal will be discussed in details. The practicality and the measurement uncertainty associated with fuel composition will also be analyzed. A comparison with the indirect method for determination of the heat input will also be presented. The article will evaluate how the code requirements are reflected in the definition of the power plant design, configuration and instrumentation. The implications of test tolerance as a commercial issue and measurement uncertainty as a technical issue will also be presented and evaluated Other unique aspects of the entire IGCC plant performance testing will be discussed: (1) stability criteria related to the gasification and integration processes, (2) corrections from test to guarantees conditions due to complex chemical, mechanical processes. Finally, the article will indicate the progress on the development of performance evaluation methodologies for other main IGCC components: gasifier, air separation unit, gas cleaning systems and Power Island.

POWER2007-22125 pp. 749-756; (8 pages)
doi:10.1115/POWER2007-22125

This paper details the design of a Pitot tube used for water flow rate measurements in large pipes. The paper describes first the nowadays commonly used device (simplex pitot), based on standard CTI Code ATC-105 from Cooling Tower Institute [1]. The disadvantages of the simplex pitot are pointed out, and the detailed description of the proposed device (multiport pitot) is explained. The Multiport Pitot, which design is also based on norm ATC-105, is able to perform real-time measurements. The paper also includes the results obtained from the water flow rate measurements made in the cooling system of a thermal power plant in Mexico. These measurement results were compared to simulation results obtained with a computational commercial simulation tool.

POWER2007-22126 pp. 757-765; (9 pages)
doi:10.1115/POWER2007-22126

ASME codes cover testing of all types of gas turbines between the ASME PTC 22 and ASME PTC 55, which will be available by 2008. The testing of gas turbines in land-based units is handled in PTC 22, while the testing of Aircraft gas turbines is handled in PTC 55. The paper addresses the development of ASME Test Codes, and the testing of gas turbines for aircraft, power generation and mechanical drive gas turbines highlighting some of the many differences in the characteristics of both engines.

Topics: Gas turbines , Testing
POWER2007-22132 pp. 767-774; (8 pages)
doi:10.1115/POWER2007-22132

With the renewed interest in the construction of coal-fired power plants in the United States, there has also been an increased interest in the methodology used to calculate/determine the overall performance of a coal fired power plant. This methodology is detailed in the ASME PTC 46 (1996) Code, which provides an excellent framework for determining the power output and heat rate of coal fired power plants. Unfortunately, the power industry has been slow to adopt this methodology, in part because of the lack of some details in the Code regarding the planning needed to design a performance test program for the determination of coal fired power plant performance. This paper will expand on the ASME PTC 46 (1996) Code by discussing key concepts that need to be addressed when planning an overall plant performance test of a coal fired power plant. The most difficult aspect of calculating coal fired power plant performance is integrating the calculation of boiler performance with the calculation of turbine cycle performance and other balance of plant aspects. If proper planning of the performance test is not performed, the integration of boiler and turbine data will result in a test result that does not accurately reflect the true performance of the overall plant. This planning must start very early in the development of the test program, and be implemented in all stages of the test program design. This paper will address the necessary planning of the test program, including: • Determination of Actual Plant Performance. • Selection of a Test Goal. • Development of the Basic Correction Algorithm. • Designing a Plant Model. • Development of Correction Curves. • Operation of the Power Plant during the Test. All nomenclature in this paper utilizes the ASME PTC 46 definitions for the calculation and correction of plant performance.

POWER2007-22152 pp. 775-784; (10 pages)
doi:10.1115/POWER2007-22152

“Combined Turbine Equipment Performance” represents the combined performance of the Gas Turbine-Generator(s) and the Steam Turbine-Generator(s), while disregarding or holding the performance of the remaining equipment in the Power Plant at its design levels. The lack of established industry standards and methods addressing the manner in which combined turbine equipment performance should be determined has invited confusion and has created opportunities for technical errors to go undetected. This paper presents a method and the supporting theory by which the corrected performance of the turbine-generators within a combined cycle plant can be combined to gauge their combined performance levels for either contractual compliance or for diagnostic purposes. The Combined Turbine Equipment Performance methodology provided in this paper, allows the performance engineer to easily separate the performance contribution of each turbine generator from the overall plant performance. As such, this information becomes a powerful diagnostic tool in circumstances where a reconciliation of overall plant performance is desired. Individual (gas or steam) turbine performance can be determined by conducting a test in accordance with the respective test code (ASME PTC 22 or PTC 6.2). However, each of these test codes corrects the measured equipment performance to fundamentally different reference conditions. Where the gas turbine-generator measured performance is corrected primarily to ambient reference conditions, the steam turbine-generator measured performance is corrected to steam flows and other steam reference conditions. The simple mathematical addition of the corrected performance of each turbine ignores the well-known fact that the steam turbine-generator output in a combined cycle plant is impacted by the gas turbine exhaust conditions, in particular the gas turbine exhaust flow and temperature. The purpose of this paper is to provide a method for the determination of “Combined Turbine Equipment Performance”, review the supporting theory, highlight the assumptions, and develop useful transfer functions for some commonly used combined cycle plant configurations, and bound the uncertainty associated with the methodology.

Power Plant Heat Exchangers and Cooling Systems Technologies for Design, Operation and Maintenance

POWER2007-22052 pp. 785-789; (5 pages)
doi:10.1115/POWER2007-22052

Cooling tower fill may be composed of wood or plastic, but it must provide adequate surface area for heat dissipation. Online and field water quality analysis can maximize tower efficiency and minimize maintenance. Uncontrolled levels of pH, bio-growth, or over-application of chemicals cause degradation of the material and plugging. Automatic control of pH conditioner can be accomplished with proven differential pH methods tied to analog and/or digital control. Oxidizing biocide application can be optimized with ORP and halogen analysis and control. Overuse of this type of biocide can also cause wood delignification that can affect the structural integrity of the tower. Another cause of fouling is excessive solids accumulation. Solids buildup can be minimized with side-stream filtration and/or clarification and monitored with low maintenance self-cleaning optical probes.

POWER2007-22106 pp. 791-804; (14 pages)
doi:10.1115/POWER2007-22106

Power plants today are plagued with aging balance-of-plant heat exchangers, particularly lube oil coolers and hydrogen coolers that have reached the end of their useful lives. Refurbishment of these coolers requires that Plant Engineers and Maintenance Personnel carefully evaluate the extent of the damage, research available solutions and develop a plan of action. A better understanding of what must be considered and what options are available will allow them to perform these tasks more effectively. This paper illustrates the challenges, considerations and options to effectively refurbish lube oil and hydrogen coolers as well as refurbishment activities, specialized tools, techniques and procedures. Also discussed are examples of common problems encountered and their solutions.

Topics: Hydrogen , Coolers
POWER2007-22134 pp. 805-811; (7 pages)
doi:10.1115/POWER2007-22134

Many papers published over the last 25 years have strongly emphasized the need for an ongoing program of condition assessment through inspection and testing with subsequent failure cause analysis of feedwater heaters. Plants must be run more competitively; therefore, Utilities must try to decrease operation and maintenance costs, while optimizing overall plant efficiency. One recognized area that needs to be addressed in accomplishing this goal is the heat cycle. This paper specifically deals with the feedwater heating system. Utility engineers must monitor feedwater heater performance in order to recognize degradation, identify and mitigate failure mechanisms, and prevent in-service failures while optimizing availability. Periodic tube plugging without complete analysis of the degraded/failed areas resolves the immediate need for return to service; however, heater life will not be optimized. This paper is a direct follow-up to a previously published ASME paper that detailed the establishment of a comprehensive life cycle management program for feedwater heaters implemented at Peach Bottom Atomic Power Station (PBAPS). This particular paper reports the eventual results and benefits achieved through the continuance and perseverance of this program. This successful condition assessment case history included the following inspection, testing, and maintenance activities to ascertain reliable data in support of root cause analysis: • Removal of previously installed plugs. • Videoprobe inspection of failed areas. • Videoprobe inspections of the steam space. • Extraction of tube samples for further analysis. • Eddy current testing of selected tubes. • Evaluation of the condition of “insurance” plugged tubes for return to service. • Hydrostatic testing of selected tubes. • Repair plans based on the results of the above program. • Reviewing operating data to assess case history. • Monitor and continue the program over future planned unit outages. This paper concludes that no single method of inspection or testing should solely be relied upon in assessing actual conditions. It is a combination of evaluating all gathered data that affords the best chance in arresting problems and optimizing feedwater heater life. Problem heaters should be continuously monitored over time until the facts ultimately help to justify replacement.

POWER2007-22135 pp. 813-823; (11 pages)
doi:10.1115/POWER2007-22135

In the power generation industry today, a variety of factors can lead to the insufficiency of existing heat exchangers. These factors include loss of surface area from purposely plugged tubes, power uprates, warmer raw water temperatures and increased spent fuel loads. While plants were generally designed for a life of 40 years, many plants are near or exceed that. It is common that the heat exchangers can be at or near the end of their physical life.

POWER2007-22148 pp. 825-829; (5 pages)
doi:10.1115/POWER2007-22148

South Texas Project (STP) Nuclear Power Plant was commissioned for operation in 1988. There are two units, Unit 1 and Unit 2, similar in design and capacity. Unit 1 is base loaded and produces 1,250 megawatts of power. There are 96,234 titanium condenser tubes, size 3/4” O.D. by 22 BWG in the multi-stage condenser. The tubes in the condenser were known to be fouled with calcium carbonate; however the extent of the fouling was unknown prior to the outage. The last effective cleaning on the Unit 1 condenser had been conducted five years ago in 2001 and only thin calcium deposits were noted at that time. It is well known that fouling of the condenser can have significant impact on unit operations: It increases unit heat rate and it can also limit unit generation capacity. However, due to the size and capacity of a condenser, and the heat transfer characteristics of a deposit type, fouling may go unrecognized until the deposition rate reaches an advanced level. As was the case at the South Texas Project Nuclear Power Plant in Wadsworth, Texas, where scale build up in the condenser tubes had not only developed, hardened, and thickened over time, but had also rendered many of the tubes completely blocked and useless. The tenacious scale, when combined with the large size of the condenser, made returning the condenser to its new and clean condition an extremely challenging project. A comprehensive cleaning project was planned and executed in September, 2006 cleaning all 96,234 titanium condenser tubes utilizing innovative scale cutting technology and mechanical scrapers. The completion of the project resulted in virtually all tubes being opened, clean, and available for service. This paper will acquaint you with the project from its conception to fruition and report the outcome.

POWER2007-22157 pp. 831-836; (6 pages)
doi:10.1115/POWER2007-22157

A special vertical pumping system was designed for cooling system of a power plant. In order to study flow pattern and hydraulic performances of vertical pumping system with bell inlet and symmetric volute outlet, especially the flow fields in the suction passage of pumping system, the incompressible N-S equations are solved by the finite volume method. Base on the k-ε model with Wall-Function Law, the SIMPLEC algorithm is applied for the solution of the discretization governing equation. Using multiple reference frames, solutions of the flow fields of whole vertical pumping system at a Reynolds number of more than 113,000 for flow in the pumping system are presented. The normal height of pumping system is put forward. The hydraulic performances of pumping system at the different operating points near to the Best Efficiency Point (BEP) were predicted. A model pumping system was designed to test the performances of the system and the measurements of velocity distribution in outlet section of the suction passage were taken. The velocity distribution of measurements and the velocity distribution of computation in outlet section of suction passage show an asymmetrical flow field even under the operation at BEP. In general the hydraulic condition of suction passage can meet the requirements of pump operation. The differences between the computational results and the measurements results are discussed.

POWER2007-22185 pp. 837-841; (5 pages)
doi:10.1115/POWER2007-22185

The objective was to provide a useful computational tool for assessing the impact of condenser tube modifications on power plant condenser performance and unit heat rate, which directly affect the operating cost. To achieve this, a methodology was utilized to evaluate the economics of condenser modifications based upon design and economic information. The numerical model of condenser performance was developed using the Heat Exchanger Institute method and the Resistance Summation method. The software calculates results based on both methods but this paper will only discuss the results from the Heat Exchanger Institute method for the case study. Since condenser performance has a direct impact upon fuel costs, heat rate, power production and emissions, this computational model can be used to assess the economic impact of a proposed condenser tubing replacement over a specified service life. A case study will be discussed concerning a condenser tube replacement project that was analyzed to determine the ideal replacement tube material for the relevant parameters associated with this particular unit.

Integrated Gasification Combined Cycle (IGCC) Power Plants

POWER2007-22025 pp. 843-855; (13 pages)
doi:10.1115/POWER2007-22025

In this paper two options for H2 production, by means of fossil fuels, are presented and their performances are evaluated when they are integrated with advanced H2 /air cycles. In this investigation two different schemes have been analyzed: an advanced combined cycle power plant (CC) and a new advanced mixed cycle power plant (AMC). The two methods for producing H2 are as follows: • partial oxidation of methane; • gasification of coal. These hydrogen production plants require material and energetic integrations with the power section and the best interconnections must be investigated in order to obtain good overall performance. With reference to thermodynamic and economic performance, significant comparisons have been made between the above mentioned reference plants. An efficiency decrease and an increase in the cost of electricity have been obtained when power plants are equipped with a fossil fuel decarbonization section. The main results of the performed investigation are quite variable among the different H2 production technologies here considered: the efficiency decreases in a range of 5.5 percentage points to nearly 10 for the partial oxidation of the natural gas and in a range of 6.2–6.4 percentage points for the coal gasification. The electricity production cost increases in a range of about 33–37% for the first option and in a range of about 24–32% for the second one. The clean use of coal seems to have very good potentiality because, in comparison with natural gas decarbonisation, it allows lower energy penalizations (about 6 percentage points) and lower economic increases (about 24% for the CC).

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