POWER October 2013 - 54

COAL-TO-GAS CONVERSIONS
4. Eliminate a derate. Cofiring natural
gas with PRB coal can restore a unit to full
capacity. Source: Black & Veatch
Mill derate
PA fan derate
Feeder derate
25
20
15
10
5
10
% of heat input
5. Cofiring a derated coal unit. Conversion
of a unit originally designed to burn a bituminous
coal to burn PRB coal often requires
a unit derate in output. The plant economics
favor cofiring natural gas, largely due to eliminating
the unit derate. Source: Black & Veatch
0% Cofiring
50% Cofiring
60
50
40
30
20
10
1st year
10% Cofiring
25% Cofiring
25
Slagging derate
term may become unattractive in the long term.
Figure 3 illustrates a comparison in the levelized
busbar cost between several gas deployment options
at a coal-fired power station, for 10-year
and 30-year service life options. The impact on
the levelized busbar cost of electricity remains a
strong function of the plant's expected capacity
factor and the cost of natural gas.
Black & Veatch has performed several
case studies for power industry clients on
the advantages of increased fuel flexibility at
several existing power plants. Three interesting
situations were recently studied:
■ Unit 1 was designed to burn bituminous
coal, is currently burning 100% PRB coal,
and is currently derated.
■ Unit 2 was designed to burn PRB coal and
now operates without derates.
■ Unit 3 was designed to burn PRB coal and
now faces expensive upgrades to meet best
available control technology (BACT)-level
emissions limits.
Each case represents a " real-world " situation
in which the effect of natural gas cofiring
was examined to determine the economics of
cofiring. The Electric Power Research Institute's
Vista program was used in this study,
which examined more than 2,000 performance,
600 maintenance, 20 emissions, and
60 different economic-related factors at each
unit. In each case, the gas cofiring or conversion
retrofit capital cost was at an assumed
" worst case " value of $100,000/MW.
Unit 1: The Currently Derated Case. In
20-year levelized
annual cost
6. Does not compete. Cofiring a unit
originally designed to burn PRB coal was not
economically justified. Source: Black & Veatch
0% Cofiring
50% Cofiring
50
45
40
35
30
25
20
15
10
5
54
10% Cofiring
25% Cofiring
typical operation, this unit is derated as much
as 24% from its MCR load due to fuel quality
limitations. The PRB coal has much lower heat
content and a higher moisture content than the
unit's design fuel. As the level of gas cofiring
increases, the derates due to fuel quality decrease
as well. All unit derates are eliminated
with 50% natural gas heat input (Figure 4).
The economic impact from natural gas cofiring
for these various gas heat input levels
was analyzed on a first-year and 20-year levelized
annual cost basis and considered all factors
that constitute the total fuel-related cost
of the unit (that is, omitting the operations and
maintenance of the turbine and water-side,
cooling towers, switchyard and generator, and
the like). In the short term, derate elimination
is the most powerful economic driver, but on
a long-term basis, an economic " sweet spot "
occurs when cofiring with 25% natural gas.
It must be noted, however, that the primary
driver here is the derate cost. If, for example,
the power station is not assessed any penalty
whatsoever for derate cost (but can benefit
from improvements in auxiliary energy use
and improved equipment availability), the
cost curve changes its shape (Figure 5).
Unit 2: The Non-Derated Case. The
non-derated case is similar to the prior case
when the derate due to using PRB coal was
eliminated. In general, natural gas cofiring at
this plant cannot compete with PRB coal on a
total fuel-related cost basis (Figure 6).
Unit 3: The BACT PRB Unit Case. In this
case a unit designed for PRB coal must now
install new and expensive emission control
equipment to meet tighter emissions limits.
The required controls include a wet limestone
flue gas desulfurization (FGD) system
at 95% removal efficiency, single scrubber
booster fan, conversion of a selective noncatalytic
reduction (SNCR) system to a selective
catalytic reduction (SCR) system at 90% efficiency,
trona sorbent injection system, and
an activated carbon injection (ACI) system.
The capital cost of the FGD is $800/kW and
the SCR is $200/kW. The trona sorbent injection
and ACI system are estimated to cost
$10 million. All operations and maintenance
costs (fixed and variable) were estimated by
the Vista program. All capital costs were assumed
to have a fixed charge rate of 15% and
7. Difficult predictions. A key parameter in this analysis is the assumed escalation rate of
the price of natural gas over 20 years. The study found that cofiring 100% natural gas is the cheapest
alternative because it avoids many costly environmental upgrades. Source: Black & Veatch
2.95%
120
100
80
60
40
20
1st year
20-year levelized
annual cost
5%
6% 7.5% 10%
0% Coal/2.95% Gas
0% Gas
25% Gas
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50% Gas
75% Gas
100% Gas
POWER | October 2013
mill/kWh
mill/kWh
Derate (% of MCR)
Busbar cost (mill/kWh)

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POWER October 2013

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