POWER March 2013 - 64

EMISSIONS
Emissions data for 11 days was obtained for
the 501FD combined cycle machine. The renewables
data included 1-second, 10-second,
and 1-minute resolution and was from four
wind farms and one large solar PV facility
in the Eastern Mid-Atlantic, Southern Great
Plains, Central Great Plains, Northern Great
Plains, and Southwest regions of the U.S.
Based on their analysis, the authors concluded
that the conventional method used to
calculate displaced emissions was inaccurate,
particularly for NOx
emissions. They said that
if system operators recognize the potential for
ancillary emissions from gas generators used
to fill in for variable renewable power, they
can take steps to produce a greater displacement
of emissions. They said that " by limiting
generators with GE's DLN system to power
levels of 50% or greater, ancillary emissions
can be minimized. " Operation of DLN controls
with existing firing modes that reduce
emissions when ramping may be practical.
They also said that on a time scale compatible
with renewable portfolio standard implementation,
design and market introduction of
generators that are more appropriate from an
emissions viewpoint may be feasible to pair
with variable renewable power plants.
Utility Perspective
Utilities that have relatively high and growing
amounts of intermittent renewable resources
on their systems also have analyzed
renewable integration costs, paying particular
attention to the cost of wear and tear on
equipment and increased maintenance at existing
conventional facilities.
For example, Public Service Company
of Colorado (PSCo), a unit of Xcel Energy,
prepared a report for state regulators in August
2011 that said the utility would add
around 700 MW of wind power to its system
by 2015, in line with its 2007 Colorado
Resource Plan. That additional wind capacity
meant PSCo would have around 1,934 MW
of nameplate wind generation capacity on
its system. One shortcoming of its planning
process, however, was its failure to consider
wind-induced cycling costs. With growing
amounts of wind on its system, the utility
said the cost impacts both of unit cycling and
wind curtailments will increase, making it
important to consider those costs as part of its
future planning decisions. The importance of
such calculations was highlighted for a single
hour last spring when wind energy supplied
57% of the Colorado system's electricity.
" With an ever-larger wind portfolio, the
depth and frequency of cyclical operation of
baseload units will increase and affect more
and more generators, " the PSCo report said.
" Coal-fired units that have historically been
base loaded will be required to turn-down
to their minimum capacity, or possibly turn
off entirely. These cycling evolutions will be
occurring more rapidly and more frequently
with greater levels of wind generation. "
The study said that any plant cycling causes
component wear-and-tear costs. In particular,
when a thermal generator is turned off and
on, the boiler, steam lines, turbine, and auxiliary
components endure large thermal and
pressure stresses. Eventually, those stresses
can cause component failures and drive up
maintenance costs. During low-load operation,
pressures and temperatures fluctuate
in pipes and tubes, causing fatigue and, ultimately,
early failure. Fatigue further erodes
the designed stress tolerances of full-output
operation, or creep tolerance. PSCo identified
this creep-fatigue interaction as " one of
the most important phenomena " contributing
to component failure.
Wind-induced cycling costs among PSCo's
coal-fired fleet pose an additional " hidden "
cost of integrating wind generation onto the
system, the report said. " It is appropriate to
determine this additional wind integration cost
and appropriately burden incremental wind
power with this cost in future resource planning
efforts. " A sample of the cost findings is
shown in Table 1.
The study evaluated two coal plant cycling
protocols. The first (referred to as " curtail " )
involved cycling coal plants down to their
economic minimum generation levels to accommodate
wind and curtailing wind in excess
of the level needed to meet system load.
The second protocol (referred to as " deep
cycle " ) involved cycling coal plants down to
Table 1. PSCo scenario results from 2011 to 2025. The dollar values are shown
as present value. Source: " Wind Induced Coal Plant Cycling Costs and the Implications of Wind
Curtailment for Public Service Company of Colorado, " August 2011
Installed
wind
Cycling
protocol
2 GW Curtail
2 GW
Deep cycle
3 GW Curtail
3 GW Deep cycle
64
Cycling cost
component ($,
million)
3.60
5.10
5.00
8.20
Curtailment cost
component ($,
million)
1.20
0.10
3.30
0.60
Total levelized
annual cost ($,
million)
4.82
5.21
8.30
8.75
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Total levelized
cost ($/MWh)
0.77
0.83
1.03
1.08
their lower emergency minimum levels to accommodate
wind and curtailing wind in excess
of the level needed to meet system load.
Although the analysis identified no significant
difference in the cost of each protocol,
the deep-cycle protocol was found to maximize
wind output while minimizing coal burn
and associated CO2
emissions. PSCo said
this protocol may result in reduced system
reliability as a result of routinely operating
baseload coal units down to their emergency
minimum loading levels. It said such a condition
would increase the wear and tear on
these units and possibly lead to more coal
unit outages. In contrast, the curtail protocol
would result in slightly less wind generation
than the deep-cycle protocol but would avoid
deep cycling the coal units and the potential
downside of reduced system reliability under
a deep-cycle protocol.
PSCo chose deep cycling as the preferred operational
protocol for its system in the near term,
given that there was no distinct cost advantage
to either protocol. However, it stopped short of
considering some additional factors that it said
could influence total costs. In particular, changes
in SO2
and NOx
emissions that may occur to
accommodate wind due to reduced coal burn or
coal units operating at suboptimal generating
levels were not considered.
Reevaluating Impacts
The Carnegie Mellon and PSCo studies,
among others, urge a systemwide approach
to understanding wind and solar energy's
effects on emissions. These studies helped
lead researchers at the National Renewable
Energy Laboratory (NREL) to acknowledge
in 2012 that many efforts to assess the emissions
benefits of wind had failed to account
for ancillary emissions from generating units
that cycle or ramp to compensate for the renewable
resources' intermittent generation.
In a paper given at the IEEE Power and Energy
Society General Meeting in San Diego
last July, NREL researchers, along with analysts
from Intertek-APTECH (IA), said that
regional integration studies have shown that
wind and solar may cause fossil-fueled generators
to cycle on and off and ramp more
frequently. They identified increased cycling,
deeper load following, and rapid ramping as
leading to potential wear and tear on fossilfueled
generators. They said this additional
wear and tear can lead to higher capital and
maintenance costs, higher equivalent forced
outage rates, and degraded performance over
time. What's more, they said that heat rates
and emissions from fossil-fueled generators
may be higher during cycling and ramping
than during steady-state operation.
The conference paper concluded that " the
impacts of generator cycling and part-loading
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POWER March 2013

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