Venue: TUM

Location: München, Germany,Macedonia, Macedonia

Event Date/Time: Jun 30, 2010 End Date/Time: Jul 01, 2010
Abstract Submission Date: Jun 10, 2010
Paper Submission Date: Jun 15, 2010
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With concerns over carbon constraints
playing a decisive role
in planning new capacity, gas
turbines are once again returning
as the technology of choice for power
generation, especially in the U.S.
“Opposition to coal, coupled with lingering
questions about the technical and economic
feasibility of CO2 sequestration,
and uncertainty around competing bills
being floated in Congress, have helped to
breathe new life into combined cycle
plants based over the past year or two,”
says Douglas Todd, President, Process
Power Plants (Galway, NY) — who spent
30 years working with GE before starting
his own consultancy.
As operators plan additional capacity,
they typically evaluate competing gas turbine
designs by carrying out a lifecycle
cost assessment. This assessment has historically
been governed by factors that
can directly improve the turbine’s overall
economic performance throughout its
working life. But in recent years, the
process has grown more complex.
This complexity is the result of notable
pendulum swings in several trends — related,
for instance, to the use of coal versus
natural gas, the preference for supersized
gas turbines, and the trend from baseload
toward cyclic operation. All these trends
have significantly changed the power generation
landscape in recent years.
While capital costs, operations-andmaintenance
considerations, thermodynamic
efficiency and emissions performance
have historically ranked high on the
list of decisive factors that must be considered
during the purchase of gas turbines,
today a far more wide-reaching list of factors
must be scrutinized and reconciled in
light of these market and technology drivers.
These factors include:
• The need for greater operational flexibility
(to allow operators to move toward
cyclic rather than baseload operation, in
order to meet the demands that the market
is placing on them, and tap into additional
revenue streams from peak demand and
ancillary markets)
• Considerations related to turbine size (in
pursuit of cost and performance efficiencies

that are associated with larger machines)
• The need for greater fuel flexibility (to
allow the unit to switch from natural gas to
distillate, to cope with variability in
Liquefied Natural Gas (LNG) composition
and Wobbe Index, or to consider syngas or
hydrogen from an Integrated Gasification
Combined Cycle (IGCC) option, in the face
of natural gas price volatility)
• The need to limit carbon emissions (in
light of increasingly vocal opposition to
global warming and the likelihood of regulatory
and market-based programs to
reduce CO2 emissions)
Natural gas volatility has everyone
concerned about using more gas in the
future. “It is definitely a major issue that
is keeping us up at night, but many of the
other options — coal and nuclear, in particular
— have their own issues,” says
Holly Doyal, Manager of Generation
Services for Southern Company, a power
generator with an installed capacity of
more than 40 GW.
Tending to a peak
Recent trends in combined cycle operation
show that operational flexibility may well be
more important than installed cost. The average
capacity factor for combined-cycle
plants in the U.S. (in terms of megawatts
produced for the month of August) has risen
from 52% in 2003 to 60% in 2006, according
to Andrew Baxter, 7F Platform Leader
for GE Energy. Similarly, he notes that the
gap between off-peak and peak demand “has
been growing at an alarming rate.”
For instance, in 2003, the difference
between average off-peak demand (with the
average U.S. combined-cycle capacity at
29% at 5 a.m.) and average peak demand
(with average combined-cycle capacity at
69% at 5 p.m.) was 40%. By 2006, this difference
had grown to 47%, and peak
demand in that time frame had grown 1.5
times faster than off-peak demand, adds
Baxter of GE Energy.
With the volatility in natural gas prices,
ongoing environmental concerns, and an
increase in the gap between peak and offpeak
power demand — all working in tandem
to drive cyclic operation — operational
flexibility has emerged as one of the
most important factors when designing
combined cycle applications, says Baxter.
“When it comes to buying gas turbines,
such flexibility comes from increased turndown
capabilities, faster start capabilities
and increased fuel flexibility.”
Customers looking to build combinedcycle
plants that maximize annual efficiency
must have a clear understanding of their
operating mission in terms of the anticipated
load profile and hours per start.
“Operators must understand how these
machines are going to be used, how their
plant will be run, what is the dispatch
model, and which ancillary markets might
they be able to sell into,” adds Bryan
Sixberry, Marketing Leader, 7F Platform
for GE Energy. “Dollars-per-kilowatt-hour
is no longer the biggest driver in the technology-
selection process. Efficiency at the
top end may not be as important as operational
flexibility in the long run.”
For instance, Baxter of GE Energy says:
“If I am running at 5 pm and the grid says ‘I
only need 4% load from you,’do I go to 50%
and then dump some of that capacity, or do I
shut off and have to restart the next day?”
Baxter continues: “For larger and larger
machines, if you do not have expanded turndown
capabilities — in terms of how far
down in load the gas turbine can go while still
maintaining its permitted CO and NOx
allowance — you will not have the operational
flexibility you need.” He adds: “The
lower (in terms of load) I can idle my
machine at night and still meet my emissions
limits, the lower I can maintain my overall
cost of operation and still maintain long-term
profitability. Sometimes shutting down is
cheaper because you incur no cost during offpeak
periods, but other times the cost of the
restart is greater in the long run than the shutdown,
so this has to be evaluated on a caseby-
case basis when building capacity.”
In some cases, maintenance costs may
jump up the priority list of factors influencing
gas turbine evaluation. According to the
Electric Power Research Institute (Palo
Alto, CA), the extensive maintenance costs
associated with gas turbines can exceed the
initial equipment cost by as much as a factor
of three over the lifecycle of the equipment,
and this can be exacerbated by the
frequent startups and shutdowns of cyclic
operation. So it is in the purchaser’s best
interest to choose gas turbines wisely — in
light of reasonably anticipated operating
scenarios the turbines are likely to experience
over the long haul — in order to keep
a lid on maintenance costs.
Is bigger always better?
In recent years, electricity demand has
grown steadily worldwide, and in general,
this trend supports the use of larger, moreefficient
combined cycle plants, says
Baxter of GE. “With bigger turbines,
economies of scale are always at work,
there are no two ways about it — the capital
cost-per-megawatt decreases with
increasing gas turbine size, so bigger units
always lead to increased profitability for the
operator,” adds Philip Kiameh, Manager at
Ontario Power Generation (formerly
Ontario Hydro), the second-largest electric
utility in North America. “And O&M costs
also tend to fall with increasing size,
because twice the size does not mean twice
the work to maintain these units; they may
require 10% more maintenance costs butnot twice as much.”
Any additional efficiency that can be
squeezed out of a given turbine will help to
reduce the cost per megawatt, and larger gas
turbines definitely tend to have better heat
rates and greater efficiencies. Thus, in general,
they tend to be more economical on an
installed basis (in terms of MW per dollar),
says Brian Fuller, Manager of Retail
Generation Services for Southern Company.
However, while larger turbines do deliver
certain cost and efficiency advantages, at
some point, they can also engender a variety
of reliability and financial penalties, so for
many operators, it is not necessarily a foregone
conclusion that “bigger is better” in
every situation (Figure 1).
For many years, efficiency was a primary
driver for gas turbine selection, and this
tended to favor larger units, but now we are
seeing a little pullback in this area, says
Klaus Brun, Manager, Rotating Machinery
and Measurement Technology for
Southwest Research Institute (SwRI; San
Antonio, TX). “After witnessing infancy
problems with a lot of the newest, largest
gas turbines, many operators are being
more conservative now, willing to forego
perhaps 1% - 2% efficiency in order to use
more-well-established gas turbines that
have a better proven reliability record.”
The higher firing temperatures associated
with today’s larger gas turbines can also
lead to increased emissions, so larger units
tend to lose some turndown flexibility and
face more operating constraints, adds
Baxter of GE Energy. “In general, larger
turbines (such as H-Class machines) tend to
be best-suited for applications where you
are more likely to be running near 100%
capacity 100% of the time.”
How the plant will be dispatched on a
day-to-day basis impacts the decision, and in
some cases, the larger the machine, the less
flexibility you will have, says Sixberry of GE
Energy. “For instance, if a given gas turbine cannot easily turn down below 70% load, you
cannot operate it cost-effectively under many
of today’s typical operating scenarios.”
Meanwhile, “larger turbines, such as the
H-class units with 400 MW capacity or
higher, clearly present a large single-shaft
risk,” says Jaisen Mody, Director of
Generation Projects for Portland General
Electric (PGE; Portland, OR). “We are a
smaller utility, so we prefer to use multiple
smaller gas turbines so that if one goes down
for any reason, we are still protected and
have not put all of our eggs in one basket.”
With newer technologies, insurance
companies are always looking at potential
business-interruption risk, adds Baxter of
GE Energy. As a result, insurers tend to put
a high premium on some of the newer gas
turbines, and this may also become a factor
during the purchase process.
Because of significant failure rates
associated with some of the newer and larger
gas turbines, many of today’s operators
are willing to go with an older gas turbine
model which may be available in the aftermarket,
adds Brun of SwRI. “These are still
modern, very efficient, reliable machines
that can offer a less costly option.”
While they do offer some fixed-scale
cost advantages, the larger units can be very
cumbersome, and there are limits to how big
you can make it without becoming unwieldy
and sacrificing operational flexibility, says
Baxter of GE Energy. “For these reasons, we
have definitely seen the preference going
back from H-Class to F-Class turbines.”
The impact of cyclic duty
Duty cycle is having a significant impact on
gas turbine purchasing decisions. “Because
the trend has been toward more cyclic duty,
which creates particular operational challenges,
operators must select technologies
that are more able to handle the rigors of
cyclic operation,” says Fuller of Southern
Company. Weekly and even daily startup and shutdown associated with cyclic operation
can greatly shorten the overall life
expectancy of stationary and moving
blades, nozzles and other gas turbine components,
and contribute to higher overall
operations and maintenance costs over the
life of the asset.
“Every startup and shutdown cycle
takes the machine one step closer to its
death by shortening its ultimate life by
some amount,” says Kiameh of Ontario
Power Systems. When we are evaluating
gas turbines, we have to ask ‘Can a particular
machine withstand that kind of duty, and
will it likely engender extra maintenance
costs from cycle operation over the long
run?’ adds Fuller of Southern Company.
As a result, “certain manufacturers,
machines and exotic materials that are more
appropriate to withstand the rigors of cyclic
duty will emerge during the gas turbine
selection process,” says Kiameh.
Payment schedule also needs to be considered
when buying gas turbines. “Buyers
must evaluate both fixed and variable costs
when seeking the most attractive, least-cost
solution,” says Fuller. In some cases, these
costs can be tempered, he notes, by seeking
the most advantageous payment schedule
in terms of upfront versus backend-loaded
payment arrangements, which can vary
considerably by vendor. Similarly, “the cost
of long-term maintenance agreements, with
10- to 20-year schedules, can vary significantly
over the life of the turbine, but for us,
these costs are well-spent because they provide
better protection against failure risk.”
Toward that end, the fleet performance
and reliability record of the vendor is also
of paramount importance. “Plant economics
are closely governed by failure rates and
resulting outages, and some suppliers have
much higher failure rates than others, so the
importance of finding a good manufacturer
with a proven track record and a solid reputation
cannot be overstated,” says Kiameh
of Ontario Power.
When the cost to produce power may be
$50,000/hour, and the plant could go down
for one month per year or four months per year (because of potential gas turbine outages),
that is a huge difference, he adds.
“Of course capital costs and service contract
expenditures can vary enormously by vendor,
but you get what you pay for. You must check
the failure rates on the fleet, and secure solid,
long-term service contracts to maintain the
reliability of your own machines.”
Many agree that when it comes to guaranteeing
availability and reliability, those
suppliers that are able to monitor gas turbine
operation remotely — using specially
trained technicians who are watching the
gas turbine signatures 24/7 — have an
edge. Such suppliers not only provide the
experts, but they have real-time access to
parts and extensive modeling, so they are often able to do a better job keeping overall
operations and maintenance costs down.
“You are never going to have people good
enough to do it the way they can do it, so
this has to be a big part of the evaluation
during the purchase of any gas turbine,”
says one industry observer.
Beyond operator control
While many factors must be reconciled
when purchasing a gas turbine, in some
cases some of that decision-making may
be taken out of the operator’s hands. For
instance, India and China are such huge
consumers of power generation plants
right now that they are driving up the
price of materials.
By some industry accounts, the average
price of power plants has gone up by 40% -
100% in the last three years. Similarly,
strong, concurrent demand in both the U.S.
and abroad, coupled with the recent cancellation
of several coal-based power plants,
are also creating time-delivery pinch points
in the supply chain.
Because so many utilities are procuring
and installing gas turbines for combined
cycle plants right now for exactly the same
reasons, the equipment supply is often tight
when it is needed, and buyers often cannot
obtain the unit types they want, or those that
are best-suited for their application, says
Mike Hoy, Engineering Manager for Combustion Turbines and Distributed
Resources for the Tennessee Valley
Authority. “They may be stuck with whatever
is available from the manufacturer in
the time frame they need, or be forced to
consider used grey-market equipment,
which may require equipment relocation or
even lead to a potential mismatch of individual
“We are all hearing about this tightness
and bottlenecks in the supply chain from
many vendors,” says Fuller of Southern
Company. While this may not impact big
utilities with a lot of buying clout as much,
he notes that supply chain tightness “is likely
to create more of a problem for operators
with a short-term, fast-turnaround project, or
some of the smaller players, who may be at
a disadvantage when it comes to garnering
the attention of oversubscribed suppliers.
Meanwhile, in a roundabout way, the
aging electricity transmission and distribution
grid infrastructure (with transmission
capacity at its limits in many parts of the
U.S.) is also impacting purchasing decisions
among many utility operators. “If you
cannot physically get additional power to
serve your region from somewhere else,
you are going to have to build the needed
capacity to produce the power yourself,”
says Brun of SwRI.
In these cases, particular equipment purchases
may be further dictated by regulatory
requirements related to SOx, NOx, CO,
unburned hydrocarbons and other emissions,
since more-severe emissions thresholds prevail
in so-called non-attainment areas in the
U.S. For instance, Brun of SwRI says:
“When facing the need to add capacity, a
given utility may be forced to ask:
• Do I have sufficient grid capacity to take
power from one place to another?
• Do I build my power plant in, say, Los
Angeles (a NOx non-attainment area) but then
have to add a Selective Catalytic Reduction
system to reach ultra-low NOx limits?”
Kiameh of Ontario Power extols the
virtues of natural gas combined cycle plants
for regions where grid transmission limitations
exist. “Since these facilities can be
quickly and cost-effectively built big or
small, it is often easier to build smaller,
cleaner-burning combined cycles inside
city limits, so they tend to be less impacted
by the inadequacy of the aging transmission-
distribution network,” he says. And, he
notes that as an added bonus, “by reducing
reliance on transmission and distribution
networks and building the combined cycle
plant closer to where the power is needed,
you make your own power source less vulnerable
to ice storms, sabotage and terrorism,
and you are also able to reduce electric
losses that invariably result from long-distance
power transmission.anyways the trbines can use diesel fuel. end


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