POWER March 2022 - 18

GAS POWER
quirements uncertainty. Gas generators
(see sidebar) will also need to comply
with certain hydrogen-related safety design
codes, including for fire protection,
venting, piping, and pipelines.
2. Co-firing with hydrogen or firing 100% hydrogen by volume could have a marked effect on a
natural gas-fired power unit's capacity. Courtesy: Kiewit Engineering
combustion for a majority of their fleets.
Much development has so far focused
on dry-low nitrogen oxide (DLN) technology
advancement, using lean-premixed
or multi-cluster combustion technologies
to control nitrogen oxide (NOx
) emissions,
and achievements are already
translating into project deals. Mitsubishi
Power, which in May 2020 snagged
a contract for two 1x1 M501JAC (Figure
1) CCGTs for the 840-MW Intermountain
Power Plant in Delta, Utah, commercially
guaranteed that the gas turbines
will combust a mix of 30% hydrogen (by
volume) and 70% natural gas fuel when
they go online in 2025. The contract requires
that the plant's hydrogen capability
will transition to 100% hydrogen by
2045, enabling its operator and majority
power purchaser, Los Angeles Department
of Water and Power, to meet California's
stringent climate goals.
Interest in CCUS
for gas generation
is growing, albeit
gradually.
As Michael Ducker, senior vice president
and head of Hydrogen Infrastructure
at Mitsubishi Power, told POWER,
the company has made headway on its
DLN multi-cluster burner. Many more
" customers are looking at, by the late
2020s and 2030s, gas turbines being
able to operate on 100% hydrogen, "
he said. " They're starting to scope out
projects, wanting that capability built-in
today, " he said. " Mitsubishi Power, from
a product development standpoint, is on
track and supportive of these projects. "
18
Some industry experts, however, caution
that banking on hydrogen combustion
as a replacement for natural gas to
achieve decarbonization will come with
crucial challenges. One especially underreported
concern is that hydrogen's
heating value and density are small
compared to natural gas, said Diane
Fischer, director of Generation Services
at Kiewit Engineering.
" If you go to 100% [by volume] of hydrogen,
that combustion turbine, from a
thermodynamic calculation perspective,
is going to be about at 30% capacity of
the original combustion turbine as fired
with natural gas, " she explained. " That's
entirely a function of the heating value
and the density of hydrogen compared
to natural gas. So, if you want to accomplish
the same thing with hydrogen,
you're going to need to put in a lot more
hydrogen than you would need to put in
with natural gas, " she said. Conversely,
" to get to the same capacity as you have
with natural gas, you're going to be well
over 200% of the volume that you originally
had to accomplish the same goal "
(Figure 2). Along with combustors designed
for these larger volumes that will
likely be needed for units firing mostly
hydrogen, hydrogen combustion may
require more downstream NOx
control,
and faster ignition speeds may be challenging
for units that will vary their fuel
mixes, she said.
Operating and maintaining a hydrogenfired
gas turbine may also prove challenging.
While typical natural gas units tamp
down the pressure of pipeline gas using
pressure reducers suitable for their
combustion turbines, hydrogen supplies,
whether from an electrolyzer or a delivery,
will need to be stored and pressurized,
much like calibration gases, Fischer
said. Other supply risks include potentially
unreliable supplies and system rewww.powermag.com
Carbon
Capture Growing More
Attractive
Because low-carbon fuels may be better
suited to regions that have " young "
thermal fleets (and which have access
to hydrogen and ammonia), gas power's
future may be more deeply entrenched
in its ability to abate its carbon emissions,
and integrate carbon capture, utilization,
and storage (CCUS) systems.
Interest in CCUS for gas generation is
growing, albeit gradually. As of November
2021, only 15 of an estimated 40
developing power projects with CCUS
were gas-fired.
Projects like SSE Thermal and Equinor's
Keadby 3, a 910-MW CCGT project
in North Lincolnshire in the UK, are being
closely watched. Slated to come online
in 2027, the natural gas-fired project will
feed hot flue gases to an integrated carbon
capture and compression plant to
capture at least 90% of its emitted CO2
.
In the U.S., where several CCUS projects
are bolstered by tax incentives, the
government in October granted $45 million
to 12 natural gas projects as part
of efforts to address point-source carbon
capture. Among them is a project
to equip Calpine's 1.1-GW Deer Park
CCGT facility in Texas with Shell's Cansolv
CO2
capture solution, a technology
that has been in operation since 2013 at
SaskPower's Boundary Dam project. GE
Gas Power will also notably get $6 million
to complete an engineering design
study to incorporate a 95% commercial
carbon capture solution into an unnamed
existing CCGT site that will provide advanced
operability, lower costs, and high
efficiency. The solution is expected to be
scalable to other commercial sites. Also,
much-watched are several commercial
projects that will feature NET Power's Allam
cycle. The Allam Cycle uses CO2
as
a working fluid in an oxyfuel supercritical
CO2
pure CO2
power cycle, producing a relatively
stream " at a significantly lower
capture cost. "
An extended version of this article
including details on efficiency penalties
associated with CCUS deployment and
insight on Siemens Energy's SeaFloat
CCGT technology is available online at
www.bit.ly/Gas-Tech. ■
-Sonal Patel is a POWER senior
associate editor.
POWER | March 2022

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POWER March 2022

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