TP203
November 2012
The Increased Cost of
Cycling Operations at
Combined Cycle
Power Plants
Prepared By
Steven Lefton
Nikhil Kumar
Doug Hilleman
Dwight Agan
Intertek APTECH
Sunnyvale, CA USA
Presented at the International
Conference on Cycling Plant
Charlotte, North Carolina
November 2012
Intertek AIM
601 W. California Avenue, Sunnyvale, CA 94086, 408.745.7000
16100 Cairnway Drive, Suite 310 , Houston, TX 77084, 832.593.0550
www.intertek.com/aptech
The Increased Cost of Cycling Operations at Combined Cycle Power Plants
Presented at the International Conference on Cycling Plant
Charlotte, North Carolina, November 2012
Steven Lefton
Nikhil Kumar
Doug Hilleman
Dwight Agan
Intertek APTECH
Sunnyvale, California
1.
Abstract
The increased cycling operations (on/off and load following) at combined cycle power plants in the
United States will increase the cycling-related production and maintenance costs at these plants. The
increased cycling is primarily the result of additional variable generation of renewable wind and solar
megawatts. Additional influences include market pricing for gas fuel and additional emission restrictions
on existing coal-fired units. The resulting penetration of renewables into the North American grid is
increasing the number of on-off and load cycling operations, which increase these combined cycle plants’
damage and, thus, maintenance costs. This will increase the need for spinning reserve megawatts, their
costs, and the startup charges for putting combined cycle plants online. The number and the desire for
faster online times for market conditions increases the damage severity of the gas turbine starts. They are
increasing thermal transients with more rapid gas turbine acceleration and higher mass gas flows at higher
exhaust temperatures that are reaching the heat recovery steam generators (HRSG). These factors impact
the gas turbine and the HRSGs, as well as the balance of plant, plant water chemistry, and these
ultimately reduce the overall plant reliability. The average starts on these gas turbines/combined cycle are
increasing and the gas turbines/combined cycle run times are generally decreasing. Owners and
operators, as well as regulators, need to be aware of the increased costs that occur. While capacity factors
decrease, the production costs will also rise significantly due to cycling operations. This is a discussion
of the negative impacts of cycling operations on a combined cycle power plant. In order to quantify these
impacts, a new real-time costing code, Cost Advisor, which was developed by Intertek APTECH for a
Original Equipment Manufacturer (OEM) of gas turbines to provide improved cycling cost information to
owners and operators of combined cycle and cogeneration power plants, in order to provide improved
cycling cost information to owners and operators of combined cycle and cogeneration power plants will
be presented. An overview of the cost of cycling will also be presented and the lower-bound of the cost
of cycling range of a limited number of these studies will be discussed and quantified.
2.
Introduction
Every time a power plant is turned on and off, the gas turbine, HRSG or boiler, steam lines, steam
turbines, and auxiliary components go through unavoidably large thermal and pressure stresses, which
cause damage and incur additional future costs. This damage is made worse by the phenomenon that we
call fatigue and creep-fatigue interaction damage. These cycling-related costs and damages are
attributable to current startup, shutdown, and rapid load following, but they have not yet crystallized and
occurred in newer combined cycle and fossil plants. Therefore, we have to estimate and compare them to
similar combined cycle plants with longer histories, where we have estimated start/stop and load
following costs, the so-called cycling costs. Typical start definitions vary with size, and damage increases
associated with these operations as shown in Figure 1.
Generation Unit Cycling
Definitions
Fossil
Steam
CC
AGC & Load
cycling to 60%
1-2 hours
offline
2-4 hours off line
4 hours or more
Load Cycling
LL1
LL2
LL3
Lowest Load at Which Design SH/RH Temperatures
can be Maintained
Current “Advertised” Low Load
Lowest Load at Which the Unit can Remain On-Line (CC-60%)
Figure 1
Definitions of Hot, Warm, and Cold Starts for Combined Cycle Plants.
During the startup and shutdown of combined cycle power plants, there are operational constraints that
are designed to avoid damage to the combustion turbine, steam turbine, and to a limited extent, the HRSG
components. In the case of the HRSG, the startup and shutdown maximum permissible ramp rates are
primarily determined by the gas turbine startup ramp rates that approach 3000°F/hour when measured on
a minute basis during their occurrence, and these rapid rates significantly affect and reduce the
components creep-fatigue life and increase the stresses in the HRSG and gas turbine hot section
components. The ultimate result is that these combined cycle units incur significant increases in cost of
maintenance and increase in forced outages due to cycling that would not impact a base loaded unit.
In our work for National Renewable Energy Laboratory (NREL), Western Electricity Coordinating
Council (WECC), and the Department of Energy on the impact of the wind and solar renewable
penetration of the western United States grid, we observe a significant increase in starts as well as cycling
cost on combined cycle power plants. Figure 2A represents the number of starts (multiplied by unit
capacity) for combined cycle units, which start more with increasing renewable penetration. Figure 2B
represents the total increase in cycling cost of combined cycle units in the western United States grid.
These costs are developed based on Intertek APTECH’s lower bound cost submission to NREL and
WECC.
Figure 2A shows the number of starts (multiplied by unit capacity) for various renewable penetration scenarios.1
Figure 2B shows the estimated total cycling cost of combined cycle units for increasing penetration of renewables.2,3
This has also been reported by Strategic Power Systems in their data on the service hours per start of
F-Class gas turbine machines at 33 hours per start in 2007, 38 hours per start in 2008, and increasing to
52 hours per start in 2009. The 2009 data indicates increasing run times per start corresponding with a
significant decrease in the gas fuel prices.4 As a result of this expected increase in cycling of combined
cycle power plants, we believe it is necessary to carefully examine the effect of cycling on the entire
combined power plant and analyze how these cycles affect the costs due to increased starting and load
following. We have observed that an estimated 30% renewable penetration on the grid will result in over
a 100% increase in total cycling cost for combined cycle units alone (see Figure 2B). The bottom line is
that many combined cycle plants will see a steady diet of increased starts, lower capacity factors, and
increasing cycling costs.
3.
Effects of the Gas Turbine and Cycling on the Combined Cycle and Heat Recovery Steam
Generator
HRSGs of many new combined cycle units have also been experiencing early cycling-related failures
because the combined cycle plant has been designed primarily to attain high thermodynamic performance
at base load ratings and not for cycling operations until around 2005 when the newer combined cycle
plants have been moderately improved for cycling operations. However, these plants have yet to prove
their abilities in long-term cycling services. While these combined cycle plants are designed at a lower
1
The Western Wind and Solar Integration Study Phase 2, D. Lew, G. Brinkman, E. Ibanez, B.-M. Hodge,
M. Hummon, A. Florita, and M. Heaney NREL
2
Power Plant Cycling Costs - N. Kumar, P. Besuner, S. Lefton, D. Agan, and D. Hilleman, Intertek APTECH
Sunnyvale, California - NREL
3
Analysis of Cycling Costs in Western Wind and Solar Integration Study – GE Consulting
4
The Value of Reliability Data – A look back… A view of the future of an evolving generation mix. Salvatore A.
Della Villa, Jr. Strategic Power Systems, Inc.
cost to install than coal-fired units, they require more costly overhauls and repairs. Intertek APTECH has
discussed these cycling-related issues affecting HRSGs in five Electric Power Research Institute (EPRI)
reports and an American Society of Mechanical Engineers (ASME) paper:
1. “Heat Recovery Steam Generator Tube Failure Manual,” Electric Power Research Institute, EPRI
Technical Report 1004503, Final Report (November 2002).
2. “Delivering High Reliability Heat Recovery Steam,” Electric Power Research Institute, EPRI
Technical Report 1004240 (March 2003).
3. “Interim Nondestructive Examination Guidelines for HRSG,” Electric Power Research Institute,
EPRI Technical Report.
4. “Evaluation and Correction of Thermal Transient and Cycle Chemistry Influenced HRSG
Failures,” Electric Power Research Institute, EPRI Technical Report.
5. “Effects of Flexible Operations on Turbines and Generators,” Electric Power Research Institute,
EPRI Technical Report 100351, Final Report, Stephen Hesler, PM (December 2004).
6. “Analysis of Cycling Impacts on Combined Cycle Heat Recovery Steam Generators and
Evaluating Future Costs of Countermeasures to Reduce Impacts,” ASME Power 2008-60026,
July 22-24, Orlando, Florida, USA.
The effects of this additional cycling on the increases in wear and tear and associated increases in
maintenance costs, equivalent forced outage rates, heat rates, and production costs are not well
understood by utility decision makers, regional independent system operators, and public utility
commissions. The interactions and tradeoffs of costs, reliability, and cycling effects are also not well
known. In order to properly manage the assets of a power plant, a plant operator and asset manager has to
obtain reasonably accurate estimates of the full costs of their typical operations, especially of its
operational cycles and start types in order to bid the correct costs in an increasingly cycling environment.
Only then can you maximize your plant’s value, reduce operational damage, recover your cycling costs
with proper cost knowledge in bidding, and reduce both high-impact/low probability and frequent
outages.
4.
Heat Recovery Steam Generator Damage and Failures
HRSG tube failures are very costly due to cycling, as space is limited for repairs, and often it is cheaper to
replace the section rather than cut your way into a section of the HRSG, make repairs, and weld your way
out. Common cycling-dominated power plant failures occur mainly in the HRSG tubing and the HRSG
casing. Superheater and reheater sections mainly suffer from thermal quenching transients due to water in
headers from improperly sized/designed drains and from improperly operated/maintained attemperator
spray systems that generally result in tube-to-header failures, as shown in Figure 3.
Evaporator tube failures occur due to overheating and excessive deposition of iron and other chemical
deposits that get formed and transported during cycling operations. Economizer tube failures occur from
a variety of issues including: thermal fatigue due to quenching hot tubing, economizer steaming, external
corrosion, and flow assisted corrosion, as shown in Figure 4. HRSG casing can be subjected to thermal
fatigue and the effects of corrosion from air and fuel born corrosion, as well as improper water washing
the gas turbine and carry over to the HRSG.
Figure 3
Superheater/Reheater Tube Failure/Cracking at Header.
Figure 4
Flow-Assisted Corrosion at HRSG Low Pressure Drum.
4.1.
HRSG Header Borehole Cracking and Drum Penetration Cracking
The HRSG ramp rates are limited and often constrained by HRSG water chemistry conditions and the rate
of heating and cooling of the thicker-wall pressure parts. However, when the temperature of metal,
steam, or water rates change from 1500 to 3000°F/hour due to the gas turbine exhaust, the gas thermal
ramp rate is extremely rapid and very significant when calculated using the temperatures as measured by
their rates of change in less than 1-hour increments in which they actually occur. This rapid heating
causes changes in temperature of the inner surface of the pressure part. The temperature differences
develop through the thickness of the pressure part wall. This through-wall temperature gradient persists
until stable steam or water temperature conditions are reestablished, and then time elapses for the inner
surface temperature to stabilize. Further time is necessary to bring the entire wall thickness to a new
stable temperature close to that of the inner surface. These transients drive the establishment of a
temperature gradient through the wall of the component. The hotter inner surface wants to expand
relative to the cooler bulk temperature of the header, but the material is restrained from doing so, causing
the inner surface to develop a compressive thermal stress while the coolest parts experience a tensile
stress. This process results in cracking and more of this type of cracking has been observed on heavily
cycled units and is controlled by the transient and the creep-fatigue interaction properties of the
components.
Headers are heated and cooled predominantly by heat transfer at their inner wall surfaces, tube bore hole
surfaces, and pipe nozzle penetrations. Steam drums are heated and cooled predominantly by heat
transfer at their inner wall surfaces, as are downcomer/riser pipe/steam outlet pipe nozzle surfaces, and
feedwater nozzle penetrations. These high stresses and cracks, especially during shutdown, are well
described in many papers.5
Superheater and reheater attemperators have been documented as a routine cause of high temperature tube
failures and header cracking from thermal shock damage as these are cycled in routine load following and
on/off cyclic operation.
4.2.
HRSG Tube-to-Header Cracking in Economizer, Superheater, and Reheater
Due to the rapid gas turbine temperature rise of the gas turbine exhaust into a cold or warm HRSG, there
is very uneven heating of large tube banks at very rapid rates noted above, especially when compared to
conventional fossil power plant heat-up rates, typically at much lower temperatures of 500 to
1500°F/hour. The effects of cycling, and especially condensate that is not removed from these tube banks
from the previous shutdown, make the uneven heating cause very high tube-to-tube temperature
differences leading to differential expansion tube-to-header creaking and failures. These effects are very
damaging and we have written extensively on the effects and the resulting tube-to-header failures, as
shown in Figure 3, and as discussed in the ASME paper, “Analysis of Cycling Impacts on Combined
Cycle Heat Recovery Steam Generators and Evaluating Future Costs of Countermeasures to Reduce
Impacts.” These failures are in part because of the inferior creep-fatigue properties, such as those of T91
tubing, generally found in the high temperature sections of these HRSG units (Figure 5).
5.
Effect of Cycling on GT Operating Costs
During every startup and shutdown and in load cycling to minimum load of the gas turbine, the hot-gaspath components sustain significant thermal cycling. These thermal cycles frequently shorten the lives of
these parts and also reduce the inspection and overhaul intervals required for the engine as compared with
an engine running continuous duty (base load). This shortening of the life of the parts and overhaul
intervals increase operating costs in two ways. First, more parts have to be replaced during the overhauls
and inspections, so-called parts fall out, which increase the costs of the overhaul. Often at the hot gas
path inspection, parts are found to be damaged and are not repairable. For example, when hot section
parts crack (thermal barrier coating crack) due to cycling, the cracks often proceeds into the base metal
(see Figure 6). Figure 7 is an example that shows the effects of gas turbine blade coating cracking that
5
“Optimization of F-Class Combined Cycle Unit Starts and Shutdowns Based on HRSG High Pressure Superheater
Header Tubehole Cracking Avoidance Constraints”, M. Pearson of J. Michael Pearson and Associates Co Ltd.,
J. Grover and S. Paterson of Aptech Engineering Services, R. Anderson of Competitive Power Resources, and
B. Dooley of Structural Integrity Associates.
proceeds into the base metal. The part is not repairable and must be replaced at a cost not expected or
generally included in most long-term service agreements. We have seen these very significant costs for
the replacement of 10 to nearly 100% (depending on the number of cycles, the thermal barrier coatings,
and the gas turbine manufacturer) of the blades and vanes in the first three rows of the gas turbine hot
section and the combustor. In addition, there are the compressor thrusting and compressor-to-case rubs
that have increased the number of total gas turbine catastrophic failures that has been shown to be startrelated. Secondly, because the costs of these replacement parts and total overhauls are disbursed earlier in
time, there is an additional cost due to the time value of money.
Reference Intertek APTECH analysis of Yukio, Takahashi’s “Follow Up Investigation on Creep-fatigue Evaluation of Various Alloys”
Figure 5
Creep-fatigue Interaction Curve.
Figure 6
Gas Turbine First Stage Blade Thermal Barrier Coating Cracking Extending into Base Platform.
Figure 7
Cross-section View of Pressure Side Airfoil Cracking of Surface Coating Extending into Vane Base Metal of a Gas
Turbine Blade.
6.
Steam Turbine and Generator Effects of Cycling
Figure 8 shows severe turbine nozzle block fatigue cracking and case cracking from a heavily cycled
steam turbine. In order to predict damage in a steam turbine, gas turbine, or HRSG, known damage
mechanisms must be correlated to temperatures and pressures in real-time and alarmed for the operators.
The correlation of high pressure rotor bore surface temperatures and their ramp rates to thermal stresses
are shown in Figure 9. Lacking a detailed stress analysis model, we have applied a statistical model to
thermal transient data stress output from the manufacturer’s on-board turbine thermal stress analyzer.
Our stress model had a 0.97 correlation coefficient and, thus, a nearly perfect fit to actual plant data that
shows increased stresses with increased megawatt ramp rates. Intertek APTECH then combined the
temperature-to-stress statistical model with its other cost models developed during a cost of cycling
project. This allowed us to estimate the effects of changing thermal ramp rates on damage and,
ultimately, on costs. More details are reported in the EPRI report “The Effects of Flexible Operations on
Turbines and Generators.”
Figure 8
Actual Nozzle Block Cracking.
Figure 9
Large Turbine Rotor Stress Shown as a Function of Megawatt Ramp Rate.
7.
Effects of increased cycling on the Generator
Increased generator failures and insurance claims have been noted and generators which were previously
not a concern are now reported to be the number three in insurance damage claims.6 With the increased
starts, we have seen an increase in the generator lead failure, hydrogen leakage, seal oil in the generator
stator, and the need to rewedge and rewind generators in cycling duty. Lube and seal oil ingress into
generators cause wedges and windings to become loose as stator iron gets very hot with oil pluggage,
causing reduced localized cooling of the stator core. The hotter core iron then expands causing areas of
the core iron to loosen its tight compaction. Pieces of the loose stator core iron have been dislodged,
eroded, and in some areas fatigued-off, causing these small pieces to act like magnetic termites and short
windings. All these mechanisms cause high-impact/low-probability events to become more common in
cycling units with long outages and high repair costs.
8.
Balance-of-Plant Effects of Cycling
In addition, there is significant damage in the balance of plant that is caused by 1) cycling-related
chemical upsets in feedwater and boiler water, 2) equipment corrosion during offline and startup periods,
3) excessive deposits, buildup, and under-deposit corrosion in the boiler, e.g., corrosion transport from
air-cooled condensers to the HRSG, and 4) other transient behavior causing damage during starts, load
cycling, and shutdowns.
We observe more switchgear, transformer, and large motor failures due to cycling operations. The impact
of cycling on NOx control system and ammonia injection grids causes ammonium bisulfate to participate
out on the HRSG tubing, causing more starts and offline cleaning to remove the deposits.
Piping systems valves and check valves are particularly susceptible to cracking and failure when multiple
unit 2:1, 3:1 combined cycle plants with multiple HRSGs are started up, and cooler steam is blended into
an operating hot piping system. Piping systems need to be subjected to transient stress analysis and
brought up to much higher standards to include these transient effects. All of these component failures
cause increased costs.
9.
Top-Down Method for Estimating Cycling Costs
Intertek APTECH has found that accurate estimates of total unit damage costs can be derived using a
regression analysis of historical unit damage with historical costs and equivalent forced outages, along
with component-specific data that indicate the breakdown of cycling costs among various cycle types
(e.g., hot, warm, and cold starts, load follows). Intertek APTECH’s damage model is intended to provide
information on the cycling-related damage for the entire unit. It is founded on physical models and uses
plant temperature and other real-time thermocouple data (we call this “signature data”) to provide crossvalidation and calibration relative to the megawatt changes, but requires only hourly megawatt
operational data to estimate damage. Relying solely on hourly megawatt unit load data is an inherent
advantage due to the fact that these types of data are more readily available. In addition, hourly megawatt
data provide an accurate history of past unit operations. Our damage model accounts for creep damage,
fatigue damage, erosion, corrosion, and all other types of damage that are known to occur in most
combined cycle power plants.
Intertek APTECH’s damage model validation process has included the assessment of key components
with finite element analysis and creep/fatigue analysis methods to determine remaining useful component
6
Reference Combined Cycle Journal.
life, augmented by information from thousands of laboratory failure and stress analyses of power plant
components. These life analyses of key high cycling cost components are statistically calibrated to the
failure history of these components. Then all damage is calibrated to actual plant costs and these costs
must back predict or back cast historical costs to be validated. Traditional, uncalibrated engineering
fatigue and creep analyses, however ambitious and expensive, are rarely useful and are often misleading
in predicting cycling costs.
Real-time, minute-by-minute thermocouple data (or “cycling signature data”) provide information about
the damage mechanisms and accumulation rates that may occur as a result of cycling operations. The
signature data are used to calibrate, revise, and/or confirm the results of the general damage and cost
models described above. This is done by using the signature data as input to analytical models, as well as
to qualitative “expert opinion reviews” for the evaluation of cycling-related damage during load
transients. This helps to calibrate and confirm the susceptibility of a given unit to cycling-related damage,
as reflected in capital and maintenance spending and cost per cycle calculated using the top-down and
bottom-up regression techniques.
Critical components for which detailed plant signature data are analyzed include the steam drums, water
wall/evaporator tubing, superheater and reheater tubing and headers, economizer inlet, and startup system
components, as well as turbine/generator-related components, such as valves, cases, generator windings,
and steam chests. The maximum temperature ramp rate and the overall range of temperature change
experienced by a component during the transient are key indicators of cycling-related creep and fatigue
damage. These parameters are used to quantify the severity of each unit’s load, startup, and shutdown
transients. The signature data are also used in evaluating and troubleshooting each unit’s cycling
operations, leading to recommendations for temperature ramp rate limits, e.g., superheater ramp rates,
economizer ramp rates in startup and during shutdown/cooling, and other operational improvements
aimed at minimizing damage, maximizing the asset’s life and reliability, and reducing maintenance costs.
Intertek APTECH uses a statistical regression model to develop best estimates of the total combined cycle
equipment damage costs due to typical cycling, which include incremental equivalent forced outage rates,
capital, and maintenance costs. These costs are first estimated for an equivalent hot start used to describe
each cycle type, and then estimated for the typical cycles experienced by the specific units studied based
on how they are operated. Figure 10 shows the results of this type of regression analysis typically run
with and without equivalent forced outage costs to separate the forced outage effects. This, and our other
correlations of starts to plant outages, confirm our assertions that cycling causes increased forced outages.
Best Estimate of Smoothed Plant X Units 2, 3, 4, Gas Turbine Portion of the Combined Cycle Plant
including Forced Outage, Maintenance, Operation and Capital Costs
Smoothed Annual Candidate Costs in Year 2009 Dollars
Best Fit of Annual Costs (Results in $XX per Equivalent Hot Start and a COV=5%)
Annual Outage, Maintenance, Operation
and Capital Costs (in 2009 currency)
Adjusted for major overhauls and assumes 474 EHS per year for cycling the three gas turbines in the future
$40,000K
$35,000K
$30,000K
$25,000K
$20,000K
$15,000K
$10,000K
$5,000K
$0K
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
Year
Figure 10
Best Estimate Forced Outage, Maintenance, Operation, and Capital.
10.
Bottom-Up Method for Estimating Cycling Costs
The “top-down” method described above provides a measure of total cost of cycling based on historical
spending of the whole plant without regard for specific components. The “bottom-up” method seeks the
relative distribution of those costs as a means of apportioning the total costs and providing a sound
methodology for evaluating potential countermeasures. By identifying the major costs of damage to
components that currently contribute to the wear-and-tear elements of cycling costs, the calculated cost of
cycling can also be adjusted in the future. Improvements identified reflect improvements made through
identification of problem components with high costs and forced outage rates. Root cause analysis,
hardware fixes, and changes in operating practices, component replacements, and upgrades can be
implemented. The cycling costs estimated using the bottom-up method also serve as a “sanity check” on
the unit-wide costs derived in the top-down method. When we also perform the bottom-up analysis, it is
generally within 5% to 10% of the costs derived from the top-down method, which provides validation of
our top-down methodology. Figure 11 gives an example of the distribution of cycling damage costs
among the major plant systems of a combined cycle unit.
Figure 11
Total Operations and Maintenance Costs for Combined Cycle.
11.
Results of the Cycling Costs
The overall range of cycling costs compared with commonly assumed costs is shown in Figure 12, which
includes all cycle types of hot, warm, and cold starts for the three unit types of small drum, large
supercritical, and gas turbines. The unit’s specific analysis results depend heavily on the regression
analysis of the costs versus cycles and the unit signature data during cyclic operations, including the range
of all load changes. The increased incremental costs that are attributed to cycling are broken down into
the following categories:
1.
2.
3.
4.
5.
Increases in maintenance and overhaul capital expenditures
Forced outage effects, including forced outage time, replacement energy, and capacity
Cost of increased unit heat rate, both long-term efficiency, and while at low/variable loads
Cost of startup fuel, auxiliary power, chemicals, and extra startup manpower
Long-term generation capacity cost increases due to unit life shortening
Figure 11 gives an example of the breakdown of maintenance and overhaul cycling costs for a combined
cycle power plant. Cost ranges of the lower-bound of studies that we have performed are significant. We
published the lower-bound range of cost for combined cycle plants in the publication for NREL.7
7
Impact of Wind and Solar on Emissions and Wear and Tear of Fossil-Fueled Generators, D. Lew, G. Brinkman,
N. Kumar, P. Besuner, D. Agan, and S. Lefton.
Estimated Cycling Costs Often Wrong
“Quantify True Unit Cost Per Cycle”
Unit Type
Small Drum
Large
Supercritical
GT Simple Cycle
GT Comb. Cycle
Typical Industry Value Potential Range
(without consideration of true costs)
of Total Cost
$5,000
$10,000
$3,000 - $100,000
$15,000 - $500,000
$100
$200
$300 - $80,000
$15,000 - $150,000
Figure 12
Typical Cycling Costs.
12.
COSTCOM Methods Properly Predict Future Damage
Intertek APTECH’s methodology, first developed in 1989 for fossil power plants, correlates plant
operations with past damage and then calibrates real component costs to these damages. We make the
effort to verify that the cost models accurately “predict” past costs so that they can quantify and predict
future costs more accurately. When possible, we estimate cycling cost using at least two different
methods with independent investigators (e.g., top-down regression methods vs. bottom-up cost
accounting and in plant studies). The major combined cycle plant components are broken down by costs
in Figure 11 and separate damage models are developed from analysis of plant signature data collected
from the plant data acquisition systems. Cost calibrations are executed in all of these major component
and cost areas.
12.1. Description of Real Time Operations
The developed code COSTCOM and our combined cycle Cost Advisor developed in 2012 for an OEM’s
combined cycle power plants, is a real-time software system that allows power plant operators and
managers to see the comprehensive costs of their cycling operation within 1-minute of the current
operation as shown in Figures 13 and 14). It is a PC-based program which gathers data from the existing
plant information system for through-the-plant network. The system includes three modules: 1) an engine
that calculates the results based on the plant inputs of some 15-20 variables in real time, 2) a viewer that
displays the real time and historical results, and 3) an administrator which is used for changing the display
settings, such as the alarm level or localization settings for language, local currency, units of measure,
temperature/ramp rate limits in green ( normal), yellow (caution), and red (do not exceed).8
8
Cost Advisor and COSTCOM User Manual.
Figure 13
Combined Cycle Cost Advisor Main Screen.
Figure 14
Cost Advisor Cost Screen Page 2 Showing a Start and its Cost in Real Time.
Based on the key damage process indicators (DPI) for equipment health showing temperatures, pressures,
flow rates, stress levels, and power outputs from the critical plant components (e.g., gas turbines, HRSGs,
and steam turbine generators), it classifies the current cycling transient type that is occurring and the
damage and other costs being incurred during that transient. The relationship between the measured key
variables and the damage and costs are determined by codification of an extensive cost of cycling study of
the plant using the methodologies described above. Once that relationship is determined, certain
parameters in the computational “engine” are customized for that unit so it can accurately determine the
damage and cost of current operation from the key DPI being monitored in real time. The basic principle
is that given the current plant design, past cycling damage at past cycling rates of change have given past
historical costs and the damage models must be calibrated via multivariable regression analyses to these
past costs in order to predict future damage and costs.
COSTCOM also shows the level of overall plant damage costs per day being incurred during a cycling (or
any other) operation. From this, the operator can determine if the unit can be “pushed” to get online and
produce megawatts faster (when the costs being incurred are low and the dispatch “rewards” are high) or
if the unit’s ramp rates should be reduced because damage levels are too high relative to marketplace
rewards. For example, the main screen first provides alerts to the operator with colored bar displays to
indicate high temperatures and high rate of change of DPI, such as megawatt, stresses, temperatures, and
ramp rates in normal (green), normal (yellow caution), and alarming (red do not exceed) levels for the
overall unit damage being incurred. Secondly, it shows the responsible key measured variables
(temperatures, ramp rates, flows, and stress levels) for the high damage and real time costs. It can also
give advance warning of damage and allow an operator to avoid a damaging transients and it encourages
the operators to stay in the green box of normal temperatures and ramp rates. In studies of combined
cycle units, we have had operators reduce the cycling damage as measured by signature data as much as
30-50% during starts and trips/shutdowns by revised procedures and minor changes to plant hardware.
This will have the effect on costs and damage rates in the future which will also be reduced by the
30-50% reduction in damage per cycle.
13.
Conclusion
Combined cycle plants will bear an increased burden of cycling operation and costs due to the increase in
wind and solar integration into the grid. Thus, combined cycle plants not only need to know these costs,
but also control their cycling costs as well as recover them in the electricity markets. These costs
dominate the typical plants variable cost of operations and maintenance that should be broken down into
cycling operations and maintenance and base loaded operations and maintenance. As part of the
developments we have performed and published in “Impacts of Renewable Generation on Fossil Fuel
Unit Cycling: Costs and Emissions”9, we have presented (Figure 15) the lower-bound cost from our
analysis of a large number of combined cycle units’ cycling costs. We believe most plants built before
2005 far exceed these lower-bound costs, and plants built after 2005 are still in the honeymoon stage with
low accumulated damage and may still exhibit similar lower-bound and beyond the lower-bound with
significantly elevated cycling costs in the future.
9
G. Brinkman, D. Lew, National Renewable Energy Laboratory, N. Kumar, S. Lefton, Intertek APTECH,
Venkataraman, G. Jordan, GE Energy Schenectady.
Figure 15
Lower-bound Hot, Warm, and Cold Starts, Maintenance and Capital Cost per Megawatt Capacity (Including
Outliers).
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