POWER February 2014 - 33

InstrumentatIon & Control
A Decade of Worsening Heat Rates
Four factors have contributed to historically increasing heat rates
(Figure 1).
1. Increasing heat rates. Over the last decade, the average
net plant heat rate (NPHR) for the 100 coal-fired power
plants with the most net generation has worsened by 149 Btu/
kWh. Source: U.S. Energy Information Administration
2012 NPHR 2003 NPHR Linear (2012 NPHR)
Table 1. Typical heat rate penalties incurred by emissions
control equipment. Though they are necessary for regulatory
compliance, plant emissions controls increase heat rate. Source:
U.S. Environmental Protection Agency and Black & Veatch
Linear (2003 NPHR)
Flue gas desulfurization: limestone forcedoxidation
Flue
gas desulfurization: lime spray dryer
Selective catalytic reduction
Selective noncatalytic reduction
Mercury capture via activated carbon injection
Heat rate penalty
1.5%-1.9%
1.2%-1.5%
0.5%-0.6%
0.05%-0.10%
0.4%-0.5%
Plant ranking (1=largest)
Emissions Controls Retrofits. Plant emissions controls
contribute to efficiency losses at the power plant through direct
and indirect auxiliary power consumption, as well as potential
negative combustion and heat transfer impacts (Table 1). If the
total life-cycle energy costs of the reagents and waste associated
with emissions controls are considered as well, then the impacts
on energy production efficiency are even greater.
The Move to Powder River Basin (PRB) Coal.
Although low in sulfur and fuel-bound nitrogen, PRB coals
have a much lower heat content and much higher moisture
content, which presents challenges for most coal power
plants that were designed for bituminous coal. Not only does
the greater moisture content result in poorer boiler efficiency
than when burning a bituminous coal, but the greater fuel
burn rate of the PRB coal can result in increased auxiliary
power at the power plant.
These effects can be profound; one study conducted on behalf
regulations, the trend is expected to continue.
These emissions mandates worsen heat
rate (see sidebar) both by requiring additional
air quality controls and by forcing units
to switch to low-sulfur coal, primarily Powder
River Basin (PRB) coal. Furthermore,
according to a recent National Renewable
Energy Laboratory study, the need to accommodate
deep cycling at coal power plants will
increase as our electric generating system
continues to evolve (especially with the addition
of increased variable renewable generation),
which will place severe demands on
unit operations and equipment.
As a result of the impacts of emissions retrofits,
fuel switches, and increased cycling,
maintenance staff are finding themselves
pushed to deliver more with less budget.
A Smarter Way to Manage
Monitoring
As one grizzled coal unit operator told me reFebruary
2014 | POWER
of the Electric Power Research Institute by Black & Veatch found
that a 500-MW (net) coal power plant that switched from Northern
Appalachian coal would expect to experience, on average, 4.2%
poorer boiler efficiency and a 5.9% increase in auxiliary power,
with an overall heat rate impact of 5.0%.
Increased Unit Load Cycling. U.S. energy demand has
seen significant variation in recent years due to unusual weather
patterns and depressed economic conditions, as well as price
competition from natural gas generation. When coal power plants
operate at lower loads, they tend to suffer from poorer heat rates.
Increased numbers of starts and stops can not only negatively
affect heat rate, but they also can significantly increase maintenance
costs.
Shifting Maintenance Priorities. Depressed economic
conditions, price competition, and pending shutdowns of coal
power plants due to emissions regulations have placed combined
pressures upon power plant maintenance budgets. Several power
plants report that they can no longer spend money on efficiency
upgrades and must devote most of their maintenance budgets toward
activities that keep the plant running, regardless of the efficiency
losses.
cently, " We have thousands of thermocouples
and meters and sensors and alarms, and on a
good day we can pay attention to 1 in 10. We
know we're missing data that could help our
performance and maintenance planning, but
unless we hire 10 more operators, what can
we do? "
His plant manager expressed it this way:
" We spent millions adding plant instrumentation
and controls over the years, and it's time it
started working harder for us. " These concerns
are common throughout the industry, and an
excellent way to address them is through remote
monitoring and diagnostics as part of an
integrated, " smart " infrastructure.
For example, one such platform, offered
by Black & Veatch, is called Smart Integrated
Infrastructure (SII). It combines human knowledge
and experience with computer monitoring
and control systems to allow a utility to not only
manage its generating fleet but also optimize
and evolve its operations to respond to change.
www.powermag.com
A critical piece of the SII puzzle is the
thousands of sensors and controls at each
coal power plant, many of which not only
provide real-time data but also record their
data in a plant historian. These sensors provide
operators critical feedback for controlling
the power plant, but at the same time,
they can create information overload. The
result is that many subtle changes and early
warning signs of performance, operations,
and maintenance problems are overlooked.
To solve this conundrum, some utilities have
turned to remote monitoring and diagnostics
(M&D) to manage their data and leverage the
information provided by plant systems under
an SII framework.
Implementing Remote Monitoring
and Diagnostics
Remote M&D can be implemented for anywhere
from one to all units in a generating
fleet, with economies of scale encouraging
33
NPHR (Btu/kWh)
http://www.powermag.com
POWER February 2014

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