2015 08 Power Engineering

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119
DEMAND RESPONSE
WHAT’S DRIVING THE MARKET?
HRSG
WASTEWATER TREATMENT METHODS
VALVES & ACTUATORS
UNDERSTANDING YOUR OPTIONS
Advanced Class
Gas Turbines
August 2015 • www.power-eng.com

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18 A New Era of Demand Response
Demand response capability in North America has grown considerably in
the past five years,both at utilities and within competitive markets.Learn
how the use of DR in grid planning and operations has solidified as
utilities rely on DR to meet installed capacity requirements and operating
reserve requirements.
36 Valves & Actuators
Power plants use hundreds of valves and actuators as the final control
elements in their operations.Power Engineering examines the different
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them to operate at higher pressures,temperatures,and frequency.
28 Dense Slurry Coal Ash
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42 Water’s Journey
More than ever,waste water from power plants must be viewed
holistically,from the beginning of its journey through the facility,
all the way to its final discharge.Learn how increasingly stringent
wastewater regulations are forcing plant personnel to consider
complex treatment methods to comply with regulations.
12 The Fall of the
F-Class Turbine
For the first time in over 20 years,F-Class turbine technology no
longer commands majority share in the NorthAmerican 60-Hz,
heavy-duty gas turbine market.Find out why the trend toward
G-,H-,and J-class turbines is here to stay.
No.8,August 2015

2
OPINION
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prices dropping 48 percent by 2040.
Talk about a tipping point. These
new economic dynamics, along with
other technology and cost advances
particularly in energy storage, are why
states, cities, corporations, and nations
can now set once-unthinkable targets
forgenerationfromrenewableswithout
breaking the bank. In more news from
the month of June, Hawaii (100 percent
by 2045) and Vermont (75 percent by
2032) both signed unprecedented
renewable portfolio standards into
law. And in California, the state senate
passed Gov. Jerry Brown’s goal of 50
percent renewables generation by 2030.
It now awaits expected approval by the
state assembly.
Policy drivers like these will
continue to be critical to drive the
growth of renewables. In one piece of
bad news on the policy front at the end
of June, the U.S. Supreme Court issued
a key ruling against EPA regulation of
mercury emissions from coal-fred
power plants. It’s certainly not a good
development for the environment, but
unlike what I’ve read in various media
accounts, it does not directly affect
CO2
regulation such as the EPA’s Clean
Power Plan.
The court’s ruling does not change
the fundamental economics of energy:
coal is simply no longer a cost-effective
choice for new generation in the U.S.
and increasingly, overseas as well.
Compared to the much larger trends
in fnance and policy that are driving
the momentum of renewables, many
of which came to the fore in June, I
predict that this SCOTUS decision will
be a blip on the radar.
L
ast month, we Americans cel-
ebrated our nation’s birthday,
capped off perfectly by the USA
women’s soccer team’s sensational
5-2 victory in the World Cup final. As
we hit the halfway point of 2015, the
clean-energy industry also has much
to celebrate, much of it in the month of
June alone and much of it financial.
Consider all of these recent
developments:
• The White House announced $4
billion in clean-energy funding
commitments, including $1.1 bil-
lion from five large institutional
investors such as the University of
California and TIAA-CREF, with
the balance from major founda-
tions and nonprofits.
• Bill Gates quite literally doubled
down on financing innovative
renewables technologies. The
software mogul-turned-clean en-
ergy investor told the Financial
Times he would add an additional
$1 billion over the next five years
to his $1 billion already invested
in clean-tech companies and the
venture capital firms that back
them.
• Another tech mogul, Masayoshi
Son of Japanese telecom giant
Softbank, went even further. Al-
ready a major funder of large solar
energy projects in Japan, Softbank
committed $20 billion for solar in
India — aiming to help grow that
market to 100 GW in 2022 from 3
GW today.
• Sixty percent of large investment
firms plan to invest in solar pow-
er projects for the first time in the
next five years (including 32 per-
cent in the next year), according to
a survey released in June by solar
PPA market maker Wiser Capital.
Eighty percent said they want to
“support a clean-energy future”
and more than 60 percent are con-
fident in the chances of high ROI.
At the end of June, China upped its
commitment to reduce greenhouse
gas emissions by 60-65 percent from
2005 levels by 2030, including a goal
to receive 20 percent of its primary
energy from non-fossil fuels by 2030.
The announcement was part of a slew
of new GHG cut commitments from
the U.S., Brazil, and South Korea, in
advance of the United Nations climate
talks in Paris later this year.
A great driver of all of this recent
momentum is the rapidly changing
economics of clean energy. Headlines
about record-low prices for solar and
wind power in a myriad of regions
appear almost daily. To cite just two
examples, Michigan utility DTE
Electricity has asked regulators to
approve a rate cut because of falling
wind prices in the state, while Austin
Energy, seeking to procure 600 MW of
solar in Texas, received developer bids
at less than 4 cents per kilowatt-hour.
Those are just two examples of a
broad-based global trend that shows
no signs of slowing down. A June
report from Bloomberg New Energy
Finance predicts that wind power will
become “the least-cost option almost
universally” within 10 years, with
prices falling 32 percent by 2040. And
solar will join wind as cheaper than
fossil fuel-fred energy by 2030, with
Fireworks, a World
Cup, and Clean Energy
MomentumBY CLINT WILDER, CLEAN EDGE
Author
Clint Wilder is
senior editor at
clean-tech research
and advisory frm
Clean Edge and
the coauthor of
two books: “Clean
Tech Nation: How
the U.S. Can Lead
in the New Global
Economy” and
“The Clean Tech
Revolution.”

For info. http://powereng.hotims.com RS#2

4
GAS GENERATION
www.power-eng.com
I was surprised to learn that an ul-
tra-complex bit of precision engineering,
with a final price tag that can reach many
millions of dollars, would ultimately de-
pend on good old-fashioned air to keep
itself from melting down onto the boots
of the engineers.
“The air-cooled version of the turbine
is just much simpler and more cost-effec-
tive,” Abate told me. “The steam-cooled
turbine was technical-
ly elegant, but it was
expensive to operate.
Air cooling makes
the turbine cheaper
to maintain because
there are no steam
circuits to tear down
before accessing key
components. That adds up to lower life
cycle costs.”
In fact, air-cooled turbines are very
common in the industry. While air-
cooled designs do require hot air to be
extracted from the gas turbine to cool
hot-path components, and the theft of
this heat can compromise their overall
efficiency, they can still be preferable to
steam-cooled designs which do not incur
such performance penalties, if only for
their simplicity and lower operation and
maintenance costs.
So what’s old is new. It turns out GE’s
turbines are far from the only ones in
the industry to rely on such tried-and-
true engineering; Siemens and Alstom
(among others) also produce air-cooled
gas turbines, and it’s safe to bet that other
companies are right now putting new air-
cooled designs through the paces in R&D
labs across the world. I guess sometimes
simpler really is better.
W
hen I was a teenager, I dat-
ed a girl whose parents
wouldn’t let her dress grun-
ge. Having grown up in another era, her
mom couldn’t understand the movement
I suppose, and she flatly outlawed such
foolishness in the house. Did people real-
ly wear plaid flannel and cut holes in their
jeans intentionally?
The whole episode became a major
problem for us. (Actually, it created an
existential crisis worthy of Kierkegaard’s
storied prose.) Admittedly, it was the
mid-nineties, and Nirvana had been over
and done with for a couple years. But
fashion moves more slowly in a little farm
town, and grunge was still very much in
vogue where we lived.
Not to worry though. This was no av-
erage girl, and she quickly found an en-
terprising solution to her problem. If she
couldn’t dress grunge, she would find an-
other counter-cultural fashion statement
that her mom could relate to, and drag it
kicking and screaming into the modern
era. She would dress like a hippy. This
girl was committed. We’re talking full-on
Haite and Ashbury here. It was a circus!
But come on, dressing like an anachro-
nistic hippy? That’s so amateurish, and we
were better than that. Enter the mid-60s
Volkswagen Beetle.
Yes, as it happened, the neighbor up
the road was selling his pitiful little bug
for a pittance, so my girlfriend paid the
few hundred dollars he was asking and
drove it home that weekend. It was baby
blue, and that afternoon she sent away
for the mandatory flower decals to stick
on the hood. She let me drive it a time
or two. You had to stand on the clutch
to shift into reverse, but other than that
it handled like a dream—a fever-fueled,
hallucinogenic nightmare of a dream.
We drove that thing up and down the
back roads all over the county. It was awe-
some…and terrifying.
Here’s a hint though. If you’re going to
park your cranky geriatric bug at the local
drive-in burger place, shut the engine off.
Turns out vintage Beetles were air-cooled,
and idling one in a stationary position
long enough to eat a
double quarter-pound-
er with cheese will ren-
der it hotter than an
Oklahoma July. Can I
really be the only per-
son in the world who
didn’t already know
this? Next someone
will try to convince me that VW put the
trunk in the front of the blasted thing.
A few years ago I learned Volkswagen
would be ending the manufacture of their
original air-cooled masterpiece. Sure, the
company had already come out with a re-
placement—the “new” Beetle—but it was
thoroughly modern and water-cooled, so
it wasn’t the same. Yes, it seems the evolu-
tion of internal combustion engines has
unfailingly included an upgrade from air-
cooled to fluid-cooled systems. But not so
with natural gas-fired turbines, it seems.
Last year, I had the pleasure of speaking
with Victor Abate, president and CEO of
power generation products at GE Power
& Water. We were talking about GE’s HA
turbines, which are among the largest and
most efficient in the world. Unlike GE’s
previous H-class turbines which utilized
steam cooling, GE’s new HA turbines rely
on air for temperature regulation. (The
“A” stands for air, in fact.)
Economy
from Thin AirBY TIM MISER, ASSOCIATE EDITOR
Air cooling makes
the turbine cheaper
to maintain because
there are no steam
circuits to tear down.
- Victor Abate, GE

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VIEW ON RENEWABLES
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capacity limits and are struggling with
T&D networks critically in need of up-
grades.
The world may not be entirely ready
to change the way it sources electricity. It
will need to get ready because the conven-
tional energy status quo needs to adjust
rapidly in order to realize true energy in-
dependence for all.
True energy indepen-
dence will not rely 100
percent on the electricity
grid and it will look a lot
more like off grid solar.
The current focus on mi-
cro grids, under the defi-
nition that micro grids
include storage, is the off
grid model. True inde-
pendence will encourage
electricity conservation and include edu-
cating electricity users about the photo-
voltaic/storage systems that allow them
to decouple from the utility grid when
necessary.
The slow, messy changing of the elec-
tricity guard will also include altering the
antiquated concept of what utilities are
and what utilities should provide. De-
ployment of PV is often antithetical to the
utility model – simply put, it cuts into the
utility revenue model.
The slow messy changing of the
electricity guard will force electricity
users to become responsible for their
electricity future and this is not a bad
thing. All industrial and technological
changes cause seismic ruptures in the
status quo and this one will be no dif-
ferent. The results of this change will
be a seismic correction.
C
onventional energy technolo-
gies and investors in big oil, nat-
uralgasandcoalarehighlyresis-
tant to letting insurgent renewable energy
technologies such as solar and wind take
the lead. No matter, squint your eyes and
the energy future with renewable energy
as the dominant technology is visible over
the horizon – hazy and still a bit far off,
but visible. Currently, renewable ener-
gy’s share of global energy production is
a fraction of conventional energy’s share
but change is slowly taking hold despite
well-funded resistance to it.
The global photovoltaic industry has a
leading role to play in this messy chang-
ing of the energy guard. It’s been playing
a role for decades, though it has seldom
been easy and rarely highly profitable.
Viewed simply through the lens that
growth is always good, decades of neg-
ative or low margins could be written
off as the price of gaining share, though
it should be remembered that PV has
a very small share of global electricity
production.
There is another perspective with
which to view decades of PV industry
behavior, that of courageous persever-
ance in the face of well-funded (con-
ventional energy) competition. This
perspective is also true. Photovoltaic
industry participants have persevered
through slap dash and unreliable in-
centives, drastic, abrupt and some-
times retroactive changes to incentives,
end users waiting for the technology to
mature and many others miss or poor
understandings of the technology and
industry.
In truth, the global photovoltaic
industry has persevered through decades
of double digit growth and decades of fi-
nancial struggle.
The availability of government legis-
lated incentives is a fragile and unreliable
thread on which to hang the hopes and
dreams of an entire industry. Sudden
and retroactive changes have broken the
hearts and bank balances of many a PV
industry participant. Yet,
deployment often contin-
ues despite the cessation
of an incentive primarily
because, simply, it must.
It would be more fiscally
devastating than many
realize if deployment
ceased abruptly. There is
significant inventory on
demand and supply sides
of the solar industry and if deployment
ceased, it would become even more of
a burden. Jobs would be lost. Research
and development would stall. Continued
deployment, however, is different from
profitability.
Incentives are expensive to support,
and when governments in Europe be-
gan pulling the incentive-rug out from
under the PV industry this, along with
fallout from pricing set below cost,
stimulated an industry-wide consol-
idation that included the failure of
many well-known and industry lead-
ing companies.
Currently with deployment of renew-
ables (and PV) encouraged by govern-
ments and end user interest at a high lev-
el, utilities are pushing back on continued
accelerated deployment while globally,
utility grids have been pushed to their
The Slow,
Messy Changing of
the Electricity Guard
BY PAULA MINTS, SPV MARKET RESEARCH
“True energy
independence
will not rely 100
percent on the
electricity grid
and it will look a
lot more like off
grid solar.”

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8
ENERGY MATTERS
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design that has tripped up many owners
during permitting. Air permits include
separate limits when operating with and
without duct firing. Typically the max-
imum amount of duct firing is set by
either the desired amount of peak plant
output or the maximum practical design
limit. Often, preliminary engineering is
completed to estimate the amount of duct
firing that is required to achieve one of
these limits. Emissions produced during
duct firing are calculated based on this
heat input. However, the actual required
amount of duct firing is determined by fi-
nal major equipment OEM selection and
thermal cycle design optimization. The fi-
nalization of these two decisions is often
completed after air permit issuance. This
may result in limitations on duct firing
capability. In this case, it is important that
the design engineers determining cycle
design and the permitting engineers de-
veloping emissions estimates understand
and consider the impact various major
equipment OEMs and variations in cycle
design may have on heat input and asso-
ciated permit limitations.
Gas turbine technology is evolving at a
rapid pace. In the past three years, most of
the major gas turbine OEMs have released
several performance improvements.
Many owners, especially those with proj-
ect delays or longer permit approvals,
have been caught with air permit require-
ments restricting the ability to implement
the latest gas turbine technology platform
without revising the air permit. The is-
sues described above can be mitigated or
eliminated when the permitting and the
design engineers communicate.
Coordination up front can save time
and money in the end.
T
he battle for a good permit be-
gins well before the application
is submitted, with the initial
Front End Engineering Design (FEED)
and development of conceptual engineer-
ing information used as inputs to permit
modeling and development.
A lack of communication between per-
mitting and design engineers can lead to
big problems for a facility, as each group
has its own perspective, language, drivers,
and needs. Ultimately however, align-
ment between permitting and design en-
gineers will best serve the long term inter-
ests of the facility.
Particulate emission limits are a fre-
quent sourceofpermitting/designdiscon-
nect. A major contributor to condensable
particulate matter (PM) is the amount of
sulfur in the fuel gas and the amount of
oxidation of sulfur dioxide (SO2
) that oc-
curs through the gas turbine combustion
process. This occurs throughout the heat
recovery steam generator (HRSG) in the
selective catalytic reduction (SCR) sys-
tem, carbon monoxide (CO) catalyst, and
duct burner. The maximum amount of
sulfur in the gas may not be easy to define
over the life of the plant. Conservatively
using the sulfur tariff for the gas pipeline
is often too high an assumption and can
lead to serious impacts during dispersion
modeling, especially considering that the
actual gas sulfur content is typically sig-
nificantly lower than tariff value. How-
ever, owners are often hesitant to rely on
past gas supply sulfur levels as a reliable
prediction of long term levels, as several
shales predict a potential for increasing
sulfur content as production areas shift.
The type and location of SCR and oxi-
dation catalyst impacts the conversion
of SO2
to sulfur trioxide (SO3
) through-
out the gas turbine/HRSG train, and the
amount of ammonia injection and slip
impacts the amount of SO3 in the ex-
haust gas that is converted to ammonium
bisulfate. Because conversion of SO2
to
SO3
is not widely understood, most own-
ers are prudent to assume 100 percent
conversion of sulfur to particulate when
establishing their plant PM limit.
Start-up emissions are another area of
concern. Actual hot, warm, and cold start-
up emission rates are highly dependent
on the gas turbine manufacturers (OEM)
and starting package selection, the HRSG
and steam turbine generator design, OEM
selections, the overall steam cycle design,
and balance of plant equipment design.
“Conventional” start-up times are based
on holding the gas turbine at select, low
operating loads to allow the HRSG ma-
terials to gradually warm. These hold
points also provide time for cycle water
quality to be brought within specifica-
tion before steam can be admitted to
the steam turbine. This typically results
in the gas turbine operating outside of
emissions compliance load during start-
up with NOx, CO, and VOC emissions at
orders of magnitude higher than during
normal steady state operation. An alter-
native is to remove the gas turbine low
load hold points and reduce the overall
startup emissions. It is also important
to understand how to appropriately esti-
mate start-up emissions for the final plant
configuration. Calculation of start-up
emissions is not easy. Regardless of major
equipment selection, start-up emissions
are highly dependent on, and influenced
by, the overall cycle design.
Duct firing is another element of plant
FEEDing the
Permitting Beast
BY MEGAN PARSONS, BURNS & MCDONNELL, AND ROBYNN ANDRACSEK, P.E.,
BURNS & MCDONNELL AND CONTRIBUTING EDITOR Megan ParsonsRobynn Andracsek

Duct Burner2
H.P. Superheater4
H.P. Evaporator5
H.P. Steam Drum15
L.P. Vent Silencer16
H.P. Vent Silencer14
L.P. Steam Drum w/ Integral Deaerator17
Distribution Grid1
Observation Port3 Injection Grid7
S.C.R.8
C.O. Catalyst6
H.P. Economizer10
L.P. Superheater11
H.P. Evaporator9
L.P. Evaporator 13
DA. Pre-Heater 12
Stack18
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10
NUCLEAR REACTIONS
www.power-eng.com
so future leaders can see what may be
available to them and how.
Line leaders’ routines need to include
succession planning, development and
coaching in addition to the routines
they use to run the plant.
Leaders must serve as role models in
the time they spend developing their
own succession candidates as well as
coaching and mentoring others.
Leadership development and train-
ing programs must be seen as effective
by participants and sponsors.
Leadership roles at the site need to
be viewed as desirable opportunities by
potential succession candidates. If not,
site leaders need to figure out why.
Line leader and HR roles and respon-
sibilities should be documented, under-
stood clearly and executed accordingly.
HR personnel assigned to talent
management and leadership develop-
ment roles must be highly capable and
viewed as effective by line leaders.
Assessments of succession candidates
and potential leaders need to be con-
ducted by trained professionals who
understand what nuclear power de-
mands from talent to be successful.
Decisions about leadership changes
and promotions should be made me-
thodically, with adequate input from
all appropriate parties.
Overall program effectiveness re-
views need to be conducted regularly,
focusing on process, behavior and re-
sults.
Although these requirements may
appear demanding, the more successful
utilities are following them and have
made strategic decisions to invest in the
leadership capabilities necessary to run
nuclear plants effectively.
T
he cover story in the June issue
of Power Engineering magazine
highlighted the challenges
facing the energy, utility and manufac-
turing sectors in finding skilled labor
as baby boomers retire in greater num-
bers. These same challenges are being
seen in the supervisor and manager
ranks at nuclear power plants across
the country. Engineering—more than
any other department—appears to be
the canary in the coal mine. Engineer-
ing organizations are feeling the loss
of knowledge and the impact of too
many open engineering positions and
leadership roles filled by much less ex-
perienced engineering supervisors and
managers. As U.S. nuclear power plants
and their systems age and license exten-
sions go into effect, the need for highly
capable engineering leadership will in-
crease, if anything.
Operations departments are not feel-
ing as much pain as engineering be-
cause sites have been more diligent and
proactive in feeding the licensed opera-
tor and non-licensed operator pipelines
or face being out of compliance with
their legal commitments for operating
the reactor. Maintenance, work man-
agement and training organizations are
right behind engineering in struggling
to fill open positions with qualified
professionals and capable supervisors.
As nuclear operating companies
make short- and long-term asset man-
agement decisions about what equip-
ment to replace, fix, or maintain, they
need to be making strategic decisions
about investing in the talent they need
to effectively run organizations as com-
plicated as nuclear power plants. On the
surface, most nuclear utilities across the
U.S. appear to be doing so, in that they
have recruiting, assessment, and lead-
ership development programs in place
conceivably to grow talent and increase
leadership effectiveness. But scratch
below the surface, and many programs
fail to reach a large portion of nuclear
power leaders and potential leaders.
Leadership training programs may be
limited in their effectiveness and/or not
available to a large portion of the pop-
ulation. Succession planning, critical to
focusing developmental activities, too
often consist of lists of names repeated
too often and discussions concentrated
on personality and historical personal
references, good and bad. Instead, suc-
cession planning discussions need to
be regular meetings, supported by the
highest levels of leadership, and cen-
tered on leadership attributes necessary
to be effective. Candidates’ level of read-
iness should be based on independent
assessments of these attributes, which
also serve as a basis for future leaders’
development.
Some companies are applying the
necessary discipline and rigor to talent
development in order to close gaps and
grow their own talent, forestalling lead-
ership shortages. In my book, Nuclear
Energy Leadership: Lessons Learned
from U.S. Operators (2013), I offered
a checklist that nuclear sites can use
to identify where they need to work to
improve their talent development capa-
bilities:
The site must have documented pro-
cesses for succession planning, talent
management and leadership develop-
ment. Leaders need to follow these pro-
cesses and communicate about them
with the broader management team
Strategic
Investment in TalentBY MARY JO ROGERS, PH.D.
Author
Mary Jo Rogers,
Ph.D. is a partner
at Strategic
Talent Solutions.
She recently
published the book,
“Nuclear Energy
Leadership: Lessons
Learned from U.S.
Operators,” by
PennWell. maryjo@
strattalent.com.

12 www.power-eng.com
The Fall of the
F-Class Turbine
Advanced class turbines such as the M501J
are overtaking F-Class turbine technology
as the preferred choice for new gas-fired
projects.Photo courtesy:Mitsubishi Hitachi
Power Systems Americas.
BY MICHAEL J. DUCKER
temperatures and pressure ratio. As
advances were made in materials and
cooling technologies, gas turbines were
able to fire hotter, resulting in better
efficiencies and higher outputs. Design
changes in the compressor and tur-
bine section were commonly needed,
and thus when a manufacturer made
improvements significant enough to
increase output and efficiency, a new
turbine class was born. Although at
I
t seems oil prices are not the
only phenomenon experienc-
ing a sudden, and seemingly
unexpected, decline from the
status quo. For the first time
since F-Class turbine technology came
to dominate the market over 20 years
ago, the technology is no longer the
leader in North America 60 Hz heavy
duty gas turbine (HDGT) sales. Ad-
vanced class turbine (typically defined
as G-, H-, and J- class technologies)
sales have seen greater than 50 per-
cent year-on-year growth in the past
five years and are the reason for this
unseating. The recent gas turbine OEM
emphasis on these advanced technolo-
gies confirms the trend is here to stay.
DEFINING THE CLASSES
Historically, gas turbine frame
types were defined by output, firing
For the first time in over 20 years, F-Class turbine
technology no longer commands majority share in the
North America 60 Hz heavy duty gas turbine market
Author
Michael Ducker is the manager of Mar-
ket Research at Mitsubishi Hitachi Power
Systems Americas. In this role, Michael
is responsible for strategic analysis of
energy markets.
GAS TURBINES

HDGT Market Share
North Amreica Market Share Evolution between D/E-Class, F-Class, and G/H/J-Class Turbines.
1
D/E Class
%ofGTsalesbetweenclasses
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
GT Sale Year
1980 1985 1990 1995 2000 2005 2010
Actual
Trend
G/H/J Class
FClass
Source: 2014 McCoy Power Report
off, marking the beginning of the tran-
sition away from F-class technology
and into the new era where efficiency,
not a turbine class or flexibility, is now
king.
WHY NOW?
Just a few years ago, many gas turbine
OEMs hyper-focused their marketing
on the flexibility of F-class turbines.
With increasing penetration of renew-
ables – some studies even suggesting
upwards of 80 percent renewables in
the U.S. as technically achievable – it
seemed as though F-class turbines
would dominate the market and would
help transition the U.S. to a new wave
of renewable energy technologies. Yet
in this same time frame, several events
occurred helping to promote the up-
ward trajectory of advanced class tur-
bines.
First, EPA regulations combined
with low gas prices facilitated the clo-
sure of thousands of megawatts of
coal-fired generation. While this result
was not at all unexpected, what was
somewhat unexpected was how these
units were replaced. Many early retire-
ment forecasts pegged coal units with
primarily the only large HDGT prod-
ucts on the market. Yet in 1987, we see
the introduction of F-class technology
and a rapid rise of market shares as it
simultaneously erodes D/E-class tur-
bine sales. By 1996, F-class becomes
the relative market leader and enjoyed
nearly 20 years of sustained majori-
ty market share. Yet in the late 1990s
and early 2000s, the introduction of
advanced class turbines begins to take
times the nomenclature became murk-
ier, as evidenced by technologies called
“F-class” that featured firing tempera-
ture, output, efficiency, and design in
line with advanced technology, today’s
HDGT classes can be broadly catego-
rized into three areas based on OEM
gas turbine product names, size, and
efficiency. Focusing on size, D- and
E- class engines are typically in the
75 – 110 MW range. Products include
GE’s 7E.03, Siemens SGT6-2000E, and
Mitsubishi Hitachi’s H-100. F-class tur-
bines are typically in the 170-230 MW
range. Products include GE’s 7F.03-.05
models, Siemen’s SGT6-5000F, and
Mitsubishi Hitachi’s M501F. Lastly,
the advanced class turbines (G-, H-,
and J- frames) are typically in the 275
– 350 MW range. These include Mit-
subishi Hitachi’s M501J and M501G
machines, Siemens SGT6-8000H, and
GE’s 7HA.01 and .02 models.
A HISTORY LESSON
Before considering where the mar-
ket may be heading, it is worth taking
a look at where we have been. Figure
1 shows a historical evolution of mar-
ket shares between the HDGTs. Prior
to 1987, D- and E-class engines were
GAS TURBINES
Past 5-Year Reliability/Availability Data
(January 2010 - December 2014)
Third Party Verifed Reliability and Availability Data
Source: Source: ORAP®
—All rights reserved.
2
100%
98%
96%
94%
92%
90%
88%
86%
M501G F-Class
-1.36%
- 0.69%
Reliability
Availability
Reliability/Availability%
99.05% 91.78% 97.69% 91.09%

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Yet the regulatory permitting issue is
unfortunate with the number of own-
ers and developers who, in prior years,
based air permits, certificates of public
need, transmission interconnect studies,
and the like on a smaller F-class tech-
nology but viewed changing permits to
advanced class turbines as too costly or,
more importantly, a potential regulato-
ry delay. When a permit is in hand, not
many developers are eager to risk opening
their projects to public or governmental
change of hearts even if the economics
make better sense. As more permits are
initially filed to include advanced class
technologies, it is likely this portion of
the F-class market share will continue to
deteriorate over time.
Of course there are other strategic
reasons a developer may choose F-class
over advanced class turbines – such as
parts pooling, desire for multi-unit
configurations, mitigating regional re-
quirements for loss-of-load contingen-
cies, and other reasons not considered
beyond maximum capacity needs or
permitting issues. Still, the economics
and competitiveness of advanced class
turbines over F-class technologies are
difficult to negate.
THE DRIVE TOWARDS
EFFICIENCY
In 2011, Mitsubishi Hitachi Power Sys-
tems (MHPS) demonstrated the J-class
technology at its “T-Point” test facility in
Takasago, Japan. 2,900°F turbine inlet
temperature was achieved, translating
into a combined cycle efficiency of 61.5
percent. Today, MHPS is poised to release
additional improvements to its advanced
class technologies capable of achieving
>63 percent efficiency. General Electric
markets its 7HA.02 capable of achiev-
ing >61 percent efficiency and Siemens,
though quiet recently, still maintains
their SGT6-8000H at 60 percent efficien-
cy. With natural gas prices continuing at
record lows, will these major gains on
efficiency still be realized in the market?
order until system load is met. Therefore,
competitiveness in deregulated power
markets translates into being “1st on, last
off” – meaning the most efficient units
will be the first ones to power on (and be-
gin earning profits) and the last ones to
turn off (maximizing profits throughout
operation). From the value chain of these
markets, advanced class turbines are the
clear winner and, subsequently, sales in
these markets have reflected that.
WHY F-CLASS STILL SELLS
Some still consider F-class as the
“proven” technology (i.e. less risky
from a reliability standpoint) even
though the new F-class engines of to-
day have less operating hours than
the G-class engines
that have been run-
ning since the late
1990s. Additional-
ly, 3rd party gener-
ator reliability and
availability data
clearly shows some
of these advanced
engines featuring steam cooling are ac-
tually more reliable than their F-class
counterparts (see Figure 2).
Still, other themes emerge outside
of the “proven” technology view-
point. Primarily, two rational reasons
come to light for a developer to choose
F-class over advanced class technolo-
gies: transmission issues that would
require system upgrades to incorporate
a larger unit, or the tragedy of regula-
tory permits. Not much can or likely
will change with the former. There will
continue to be a market for D/E-class
and F-class turbines to meet the needs
of developers who have finite capacity
needs. These include building a gas tur-
bine in a region that does not require
>500 MW capacity due to demand or
building at a brownfield/other site that
would require significant – and costly
– transmission upgrades to enable the
larger unit.
low utilization rates as the most at risk
to retire, and thus a 1:1 capacity re-
placement would be unlikely. Yet what
materialized are a number of the large
advanced class turbines replacing these
coal units that had minimal operating
hours. Long-term resource planning
hinges on having an adequate installed
base to meet peak demand, and this
motivated many owners to replace old-
er under-utilized capacity with new,
highly efficient baseload NGCC capac-
ity that simultaneously displaced more
costly generation on their system.
Moreover, continued expansion of de-
regulated energy markets and consolida-
tion of balancing authorities in the US
and Canada helps to improve region-wide
load balancing. As a
result, a highly inte-
grated grid capable
of pooling many re-
sources with minor
flexibility require-
ments reduces the
needs to procure
sources with major
flexibility capabilities. For instance, as
PJM has grown, the entire regional trans-
mission organization (RTO) now only
typically procures 2,000 MW of primary
reserve requirements for a market that
sees peak loads in excess of 150,000 MW
(<2 percent of total demand). These an-
cillary services are pooled across the RTO
and within regional subsets, not just via
a few highly flexible units. Undoubtedly
some markets need greater flexibility, but
advanced class turbines are continuing to
push the envelope in this area. Minimum
emissions compliant loads and start
times are now nearly equivalent between
F-class and advanced class units.
And thus if flexibility attributes
between the gas turbine classes is es-
sentially equivalent, what is valued in
these markets? At their core, deregu-
lated energy markets thrive on the eco-
nomic dispatch principal whereby units
are cost-effectively dispatched in merit
GAS TURBINES
“The economics and
competitiveness
of advanced class
turbines over F-class
technologies are
diffcult to negate.”

ADVANCED CLASS
TURBINES WILL
CONTINUE TO LEAD
Moving forward, there are many
questions regarding centralized power
generation and the role it will play in a
future considered ripe for demand re-
sponse, energy efficiency, and distrib-
uted generation. Yet at least within the
bulk power category, advanced class
turbines are in a position to succeed
and recent market events certainly sup-
port this fact. The way any successful
developer operates is simply to hedge
risks against potential market out-
comes.
When one stacks up the potential
and likely future market needs for cen-
tralized power, it is hard to see F-class
technology being a better hedge over
the advanced class turbines.
Meanwhile, President Obama’s
proposed CO2 new source (NSPS) and
existing source performance standards
(ESPS) will no doubt have a profound
effect on the drive towards better
efficiency. The NSPS rules themselves
are essentially an efficiency standard,
whereby the more efficient the unit is
the lower the lb-CO2/MWh emissions
rates will be. The ESPS rules may
further exacerbate coal retirements
and give way to newer, more efficient
advanced class gas turbines. Just
the threat of CO2 taxes or a formal
carbon trading scheme, even if
assumed 10-15 years away, can still
make a dent in a project’s proforma.
While the regulations themselves
will be contested, the general trends
are driving towards a low-carbon
regulatory and policy landscape.
In North America, the future
certainly seems promising for high
efficiency gas turbines. Deregulated
markets continue to expand, and
with recent and new environmental
regulations continuing to push coal
out of the market, baseload gas
generation is a nice fit. This trend is
not unique just to the United States
and Canada; Mexico’s recent market
reforms are bolstering the need for
more efficient and environmentally
friendly gas-fired generation in lieu
of existing coal assets. Additionally,
as markets continue to move towards
greater dependencies on gas-fired
generation, gas units will evermore
be competing amongst themselves to
be the lowest cost energy producer.
Efficiency will drive who outperforms
who in the markets.

MARKET ANALYSIS
A New Era of
Demand Response
D
emand Response (DR)
capability in North
America has grown
considerablyinthepast
five years, both at utili-
ties and within competitive markets such
as PJM. However, DR technologies and
policies have generally relegated DR to a
minor role as a last-called resource. DR
has typically been slower to respond than
combustion turbines, and the load relief
it provides has been difficult to assess pre-
cisely (if at all) in the real-time operating
environment in which control center staff
operate. Furthermore, regulatory policies
in support of DR have generally focused
on the magnitude of megawatts achieved
at the expense of the quality and useful-
ness of those megawatts. Slowly, but sure-
ly, this is changing.
The use of DR in grid planning and
operations has solidified as utilities in-
creasingly rely on DR to meet installed
capacity requirements and sometimes
even operating reserve requirements. Fur-
thermore, independent system operators
(ISOs) led by PJM have incorporated DR
into procurement mechanisms for capaci-
ty, energy, and ancillary services. Industry
acceptance of DR as an integral part of the
future grid continues to grow, with states
like California and New York rolling out
major regulatory initiatives and Hawaiian
Electric issuing a request for proposals to
Authors
Stuart Schare is a Managing Director of
Energy at Navigant Consulting Inc. Brett
Feldman serves as Senior Research An-
alyst at Navigant Consulting.
Blurring the Lines between Generation
and Demand-Side Resources
BY STUART SCHARE AND BRETT FELDMAN

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MARKET ANALYSIS
in electricity usage by end-use customers
from their normal consumption patterns.
What makes these consumption changes
“demand response” is that they are in re-
sponse to changes in the price of electrici-
ty or to direct incentives, typically at times
of high wholesale market prices or when
system reliability is jeopardized.
Common examples of DR include
direct load control of residential air con-
ditioning, curtailment of commercial
cooling and lighting loads by building op-
erators participating in utility programs,
and shutdown or deferral of industrial/
manufacturing processes. An important
distinction for DR is that it must be dis-
patchable by a utility or system operator,
or be initiated by a customer in response
to a non-fixed price signal. Thus, static
time-of-use rates and scheduled thermal
energy storage are not typically consid-
ered to be DR; but critical peak pricing—
where the highest price tier is only in ef-
fect periodically as called by the utility or
operator—is characterized as DR.
UTILITY PROGRAM
OR GRID RESOURCE?
DR has matured from manual response
to inflexible, interruptible industrial rates
of a generation ago to the much more
automated and customizable programs
and products being offered today—with
plenty of everything in between account-
ing for the bulk of current DR capacity in
North America. An important distinction
in characterizing DR activity is whether
the curtailment capacity is part of a verti-
cally integrated utility program or within
a market defined by an independent sys-
tem operator (ISO).
Utility programs are typically based on
a regulator-approved tariff, and offer a
fixed incentive, or set of participation and
incentive options, to eligible customers
who voluntarily enroll in the programs.
While voluntary, many programs have
non-performance penalties or provisions
for withholding incentives or removing
customers from the programs.
One of the most frequently used and
long-standing programs is Florida Power
& Light’s (FPL) On Call Savings Program
with more than 800,000 participants
and well over 1,000 MW of central air
conditioning curtailment capability. Xcel
Energy in Minnesota and Colorado has a
similar participation rate of over 20 per-
cent of eligible customers. Other non-ISO
utilities with significant residential DR
programs include Duke Energy Caroli-
nas, NV Energy, and PacifiCorp. Most
investor-owned utilities also offer one or
more rates or programs for commercial/
industrial DR.
DR programs tend to be more lim-
ited in ability than generators in that
they are often only available when
cooling loads are prominent, and they
are commonly restricted to perhaps
a dozen events per year of four to six
hours in duration, often within a nar-
row window of eligible hours.
DR IN ISO MARKETS
In the United States and Canada, there
are nine major Regional Transmission Or-
ganizations (RTO) and ISOs responsible
for running wholesale electricity markets
DR aggregators for the provision of “grid
services,” including ancillary services,
from demand-side resources. So which
technologies and policies will drive DR
into the future as a more integrated and
valued resource?
This article describes the current DR
landscape in North America, including
state and regional activities that uniquely
affect how much DR is in place and how it
is utilized. It covers some of the emerging
DR technologies that are allowing DR to
be viewed more on par with generators,
and it reviews new applications of DR that
are raising its prominence as a valued re-
source alternative for utilities and system
operators. Looking ahead, emerging state
policies and utility initiatives are driv-
ing DR to a heightened prominence that
would have been difficult to envision just
five years ago.
DR IN NORTH AMERICA
Demand response is a term that can
mean many different things to many dif-
ferent people. A common definition that
tracesbackatleasttoaU.S.Departmentof
Energy report nearly 10 years ago charac-
terizes DR as changes (usually reductions)
North America RTO and ISO Map
and Associated DR Capacity
1
ISO
New England
NewYork ISO
Electric Reliability
Council ofTexas
California
ISO
Southwest
Power Pool
Midcontinent
ISO
Alberta
Electric
System
Operator Ontario
Independent
Electricity System
Operator
PJM
Interconnection
500
MW
1000
MW
1000
MW
3000
MW
2000
MW
10,000
MW

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Reforming the Energy Vision (REV), the
initiative’s goal is to transform the cur-
rent utility model into a distribution sys-
tem platform (DSP). The role of the DSP
would be to lay the groundwork required
for energy service providers on both the
grid side and the customer side of the
meter to provide products and services
2014 Polar Vortex, most DR bid into PJM
was only required to be available for ten
six-hour events during summer months.
Within the New York ISO footprint, the
New York Public Service Commission is
undertaking perhaps the most ambitious
plan to date from a state looking to mod-
ernize its electric utility sector. Called
and managing a large transmission grid
with high voltages. Some of these orga-
nizations have crafted DR programs or
integrated DR into their market designs,
thereby encouraging customer load par-
ticipation. DR has matured in the elec-
tricity market and has been afforded the
opportunity to bid directly against gen-
eration in these markets—commonly for
capacity, but also for energy and ancillary
services in some regions.
Currently, there are approximately
30,000 MW of DR in North America,
according to Navigant Research’s recent
Demand Response report, with a bit over
half coming from the RTOs/ISOs. This is
made up of about 8 million residential
and commercial & industrial (C&I) cus-
tomers. This market size equates to ap-
proximately $1.5 billion in DR revenues
for DR providers and customers.
PJM manages the largest DR market in
the world, at approximately 10,000 MW.
In some zones within the ISO, DR makes
up more than 10 percent of the capacity
resource base. PJM has also been a leader
in making it possible for DR to participate
and submit bids for reductions in the syn-
chronized reserves and frequency regu-
lation markets. However, there are some
headwindsthatmay challengethecontin-
ued growth of DR in PJM markets, such as
regulatory/legal challenges and increased
operational requirements that limit com-
pensation for DR that is not available 24
hours a day, year round. Until recently,
punctuated by the grid demands of the
“Looking Ahead,
emerging state
policies and utility
initiatives are driving
DR to a heightened
prominence that
would have been
diffcult to envision
just fve years ago.”

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MARKET ANALYSIS
to enhance the distribution system’s ef-
ficiency. Examples of these products and
services include network sensors, dis-
tribution automation, DR, distributed
generation, and microgrids. As part of
the proceeding, utilities are required to
develop their own DR programs as a sup-
plement to or replacement of the NYISO
DR programs.
In California, the ISO (CAISO) is one
of several bodies contributing to a “bifur-
cation” plan to split
DR into supply-side
and “load-modifying”
resources. Essential-
ly, this means is that
price-based programs
intended to shape
loads will remain with
the utilities, while
programs focused on
reliability, flexibility,
and ancillary services
will reside with CAI-
SO. Furthermore, a
stakeholder process is underway where
all types of DR would be identified, as
well as how they could play a part in
California’s electrical grid and what ben-
efits they could provide. State policy is
directing utilities to consider DR, not
just generation, as a partner in planning
how to balance and ensure reliability for
the electric grid. Further, the California
PUC is leading a process to value different
types of DR for its ability to contribute to
reliability, as well as to support the state’s
goals for reducing greenhouse gas (GHG)
emissions.
DR VENDORS AND
SERVICE PROVIDERS
As DR offerings and technologies
have matured, an ecosystem of vendors
has emerged with continually advanc-
ing hardware, controls, and head-end
communications systems. Similarly,
load curtailment “aggregators” have
formed to recruit and enable custom-
ers to collectively deliver to utilities
and ISOs DR capacity measured in the
tens or hundreds of megawatts—or
even more in some ISO markets.
The DR market can be segmented from
a vendor/aggregator perspective. On the
C&I side, companies such as EnerNOC,
CPower, and Johnson Controls special-
ize in one or more DR-related services
including recruiting customers, automat-
ing rapid and reliable load response, and
providing granular building usage data
and performance diag-
nostics.
The bulk of the
mass-market segment
includes single-fami-
ly homes with central
air conditioning and/
or electric water heat-
ing, as well as small
businesses with pack-
aged units of 20 tons
or less. As load control
switches are nearly a
commodity, and com-
municating “smart” thermostats are fast
becoming the specialty domain of Nest
and a variety of established and start-up
companies, players in the mass market
segment such as Comverge and Eaton
(formerly Cooper Power Systems) special-
ize in one or more of the following: mar-
keting/customer acquisition, head-end
control systems, and communications be-
tween the customer and the service pro-
vider/utility (for example, Eaton offers a
two-way mesh network dedicated to load
control).
A few vendors attempt to service all
markets in the DR space. Honeywell is
probably the best established, leveraging
its experience in commercial building
management as well as its thermostat
hardware business and its 2010 acquisi-
tion of Akuacom, an early developer of
open source Auto-DR software on the
OpenADR platform. Other major players
include Schneider Electric and Siemens,
global companies attempting to develop
differentiated services and acquire market
“State policies
provide one
indication of
the future of
DR, and these
suggest a more
integrated role
for DR in resource
planning and grid
management.”

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share from those who have focused lon-
ger on the DR market.
DR AS A GRID
MANAGEMENT RESOURCE
If DR is now well-established as a ca-
pacity resource that can provide emer-
gency relief for reliability purposes, it has
only recently begun making a name for
itself as an operating resource to be used
on a more regular basis for providing
10-minute operating reserves and other
more precise ancillary services.
Many of the core attributes describ-
ing combustion turbines and other
generators have analogs for DR re-
sources. For example, both generators
and DR can be characterized by their
megawatts of capacity and by the time
it takes to bring those megawatts onto
the grid.
The real question is whether the per-
formance of DR is comparable to gen-
eration—or at least whether DR can
perform well enough compete and to
provide a portion of the services re-
quired by grid operators.
DR has been active in the synchro-
nous reserves market in PJM for several
years, providing up to 25% of the re-
quirement at times. However, chang-
es to the transmission system in 2013
dramatically lowered prices in this
market and made it uneconomic for a
lot of the DR to participate.
These conditions may change in the
future, so the technical capability is
ready to jump in when prices warrant it.
The frequency regulation market has
shown signs of growth, particularly
since PJM implemented FERC
Order 755 which affords greater
compensation to faster-responding
resources. Several alternative resource
providers, including batteries and DR,
have begun bidding into the market
and showing their ability to compete.
A major driver for DR is the increasing
penetration of intermittent renewable
energy due to both regulatory mandates

MARKET ANALYSIS
of the generation portfolio. The state
will experience steeply declining net
loads (customer demand minus cus-
tomer-sited renewable generation) in
the mid-to-late morning as solar pro-
duction picks up, and even more dra-
matic increases in net load growth in
the late afternoon as solar production
drops off concurrent with an increase
in residential loads.
The new load shape provides op-
portunities for DR (as well as storage),
especially in the late afternoons when
load curtailment could slow—or at
least help manage—the sharp ramp
up. Alternatively, DR could be used
to shave off some of the new evening
peak. In the mornings when net load is
in decline, DR can also help to balance
the grid by soaking up excess supply as
generators struggle to ramp down. Re-
call that DR is defined as “changes” in
usage by end-use customers, but these
changes don’t always have to be reduc-
tions.
An increase in demand—in response
to an incentive or price signal—is also
demand response. Some of the ap-
plications and technologies for DR
as a down-ramping resource include
over-cooling cold storage facilities and
refrigerated warehouses, within ac-
ceptable limits of course.
Essentially, the customers are using
existing facilities and technologies for
on-demand thermal storage. In this
case, the benefit may be the ability to
draw power from the grid, as well as
the ability to tap into the stored energy
at a later time to reduce demand from
the grid.A newer and more innovative
application of customer-sited thermal
storage is grid-interactive water heat-
ing (GIWH). GIWH is the emerging
consensus term for describing electric
water heaters controlled by real-time,
two-way communication with the util-
ity, grid operator, or load aggregator.
When equipped with grid-interac-
tive controls, an electric water heater
and improving economic and regulatory
treatment of renewables.
Resources like solar and wind pow-
er rely on natural elements that can
sometimes be unpredictable and re-
quire backup power resources to re-
spond quickly if clouds roll in or the
wind stops blowing.
Traditionally, this has been accom-
plished by having fossil power plants
on standby or generating at below op-
timal levels.
As the penetration of intermittent
renewables increases, however, build-
ing generation just for this purpose
may kill the business case for the re-
newable energy, so cheaper, more flex-
ible backup alternatives must be con-
sidered. DR can help fill this void.
California is perhaps the poster
child for renewable energy inputs un-
settling a grid. In 2013, CAISO con-
structed the now famous “duck chart,”
which shows the anticipated future
load shape for the state in the shoulder
seasons as solar becomes a larger part
Source:
Attribute DR Resources Generation Resources
Resource Size
Number and size of customers;
curtailable share of total load
MW unit size
Responsiveness Advanced notifcation requirements Start-up/ramp-up times
Reliability
Communications reliability
& variance in customer load
response
Availability of fuel supply
& transmission capacity
Limitations
Constraints on number and
duration of events
Emissions limits
Temperature
Dependency
Temperature-dependent loads;
hourly/seasonal variations
Temperature-dependent
heat rates and capacity
Resource
Diversifcation
Diversity of self-generation,
customer sectors,and participating
end-uses
Fuel diversity and
baseload vs.peaking
AnalogousAttributes between DR and Generation Resources
California’s Future Load Shape
and Opportunities for DR
2
Increase in load could allow
generators time to ramp down
Overgeneration risk Reductions in load could allow
generators time to ramp up or
shave off the new evening peak
2012
(actual)
2013 (actual)
Ramp need
~13,000 MW
in three hours
28,000
26,000
24,000
22,000
20,000
18,000
16,000
14,000
12,000
10,000
0
Megawatts
Hour
Net load – March 31
12am 3am 6am 9am 12pm 3pm 6pm 9pm
2014
2015
2016
2017
2020
2018
2019

25www.power-eng.com For info. http://powereng.hotims.com RS#14
can respond to near real-time input by enabling fast
up and down regulation and frequency control for the
purpose of providing ancillary services and renewable
storage to the utility or grid-operator.
In addition to two way communication, GIHWs
can measure and transmit information on water tem-
perature, so grid operators know how much energy
storage potential the fleet of GIWHs have at any given
time; and based on customer usage patterns, they also
can judge how much load curtailment, or regulation
down service, the fleet can provide while still meeting
customers’ needs.
Through the use of high-storage capacity, highly in-
sulated water heater tanks, GIWH can provide even
greater storage and operational capacity/flexibility
than traditional water heaters that are simply retrofit-
ted with interactive controls.
THE FUTURE OF DR
IN NORTH AMERICA
If DR is on a decades-long evolutionary path, will it
continue to mature into an even more valuable grid re-
source on par with generation? Or will energy storage and
the increasing demands for grid management in a world
of high renewables penetrations squeeze DR out of the
picture?
State policies provide one indication of the future
of DR, and these suggest a more integrated role for DR
in resource planning and grid management—but with
stricter requirements on how DR must perform. The days
of rarely called interruptible rates and monthly capacity
payments for the occasional 3-hour event may be in the
past. The advent of grid modernization is tied to the new
resiliency view on how the grid should be designed.
States like California, Illinois, Maryland, New York,
Massachusetts, and Hawaii have begun grid moderniza-
tion proceedings to investigate how the future grid should
look in terms of issues including metering and dynamic
rates, distributed generation, and the associated implica-
tions transmission and distribution infrastructure.
This modernization approach goes beyond siloed
hearings on the individual aspects of utility operations to
create a holistic structure for grid planning and payment
formulas. DR may finally be able to compete on a level
playing field, which could eliminate some current forms
of DR while encouraging development of others.
At the national level, a current FERC Supreme Court
case has much bearing on the ability of DR to partici-
pate in wholesale markets in the United States. In ear-
ly 2011, the FERC issued Order 745, which required

MARKET ANALYSIS
This change encompasses a diverse
suite of technologies that includes en-
ergy storage, energy efficiency, DR, and
the advanced software and hardware
that enable greater control and interop-
erability across heterogeneous grid ele-
ments. These are all key components of
the emerging energy cloud that is be-
ing accelerated by evolving regulation
of carbon emissions, a more proactive
consumer or pro-
sumer, and the con-
tinuously improving
financial viability of
distributed resources
compared to tradi-
tional generation.
Navigant projects
that there will be
about 70,000 MW of
DR in North America by 2023, an 11
percent annual growth rate. One indi-
cation of the growing prominence of
DR and the vendors/service providers
supporting it is the growth in
membership of the leading
DR trade association.
The Peak Load Manage-
ment Alliance (PLMA) has
been in existence since 1999,
yet just in the past three
years had more than dou-
bled in membership from
less than 40 members to
nearly 90 today.
The recent setbacks and
regulatory uncertainty in
PJM—while interrupting
DR’s long-term trajectory—
are an indication that the
industry demands more re-
sponsiveness and account-
ability from DR resources.
This will push the continued
evolution to more fully auto-
mated, fast-responding, and controlla-
ble DR resources that are able to play
an increasing role in integrating inter-
mittent renewable energy and in man-
aging real-time grid operations.
wholesale energy markets to pay the
same for DR as they do for electricity
generation. Energy supplier and gen-
eration groups challenged the order in
federal courts as unjust and unreason-
able compensation.
In May 2014, a panel of the U.S.
Court of Appeals overturned the or-
der by a 2-1 vote, potentially reverting
things to how they were before—or
making them worse, depending on
interpretation. The majority opinion
went even further and found that DR
in the wholesale energy market is a re-
tail transaction, which is outside of the
FERC’s jurisdiction.
In December 2014, FERC asked the
U.S. Supreme Court to review the case,
which was granted, setting the stage
for a hearing likely in early 2016. If the
worst-case scenario plays out and DR is
disallowed from all wholesale markets,
states and utilities will have to fill the
void. Depending on their status and
disposition, this could take months to
several years to enact. The short-term
momentum of DR would be halted, but
in the long term, if states and utilities
assign higher value to DR than do the
wholesale markets, it could lead to in-
creased opportunities for DR.
DR IN THE
ENERGY CLOUD
Aside from government policy, the
power sector is undergoing a fundamen-
tal transformation that could lead to an
increase in DR capacity or how widely DR
is used.
Led by rooftop so-
lar, encouraged by
the prospect of cheap
storage, and with the
possibility of massive
amounts of electric
vehicles on the grid,
the industry is slowly
shifting away from a
centralized hub-and-
spoke grid architecture based on large
centralized generation assets like fossil
fuel, hydro, or nuclear power plants.
The new paradigm—dubbed the En-
ergy Cloud in a 2015 Navigant white
paper—envisions an increasingly de-
centralized electrical grid that makes
greater use of distributed energy re-
sources, including DR.
“Navigant projects
that there will be
about 70,000 MW
of DR in North
America by 2023,
an 11 percent
annual growth rate.”
“Smart”thermostats are fast becoming the
specialty domain of several established startup
companies,as demand response (DR) becomes
a major resource for power producers.In
some places,DR developers are granted the
opportunity to bid directly against generation.

A large Hyundai shovel operates on the surface of cured dense slurry at the
Matra power facility’s impoundment in Hungary,attesting to the compressional
strength and environmental stability of the end-product.The shovel excavates
cured slurry from around the perimeter for use in building up the levee of the
15-tiered,150-foot-high impoundment.Photo courtesy:NAES
ENVIRONMENTAL REGULATION

29www.power-eng.com
BY DALE TIMMONS
T
he Environmental Protec-
tion Agency’s (EPA) newly
enacted Coal Combustion
Residuals (CCR) rules and
proposed Effluent Limita-
tions Guidelines (ELG) will significantly
impact waste management practices in
the coal-fired power industry. The new
rules will regulate fly ash settling ponds
out of existence; regulate the location, de-
sign, operation, and closure requirements
for impoundments; and impose new re-
quirements for wastewater.
Traditional “dry ash” management
techniques satisfy the rules’ proposed re-
quirements, but they suffer from inherent
technical deficiencies and pose prohibi-
tive costs.
The Circumix™ Dense Slurry System
(DSS) technology, developed by GEA
EGI Ltd. of Hungary and represented ex-
clusively by NAES Corporation in North
America, mixes wastewater with CCRs to
produce a stable product with near-stoi-
chiometric use of water. Once cured, the
slurry exhibits low hydraulic conduc-
tivity, high compressional strength, no
discharge of fly ash transport water, little
or no fugitive emissions, and enhanced
metals sequestration, thereby achieving
the goals of the CCR and ELG rules.
The EPA has also imposed stricter stan-
dards for air emissions with the Mercury
and Air Toxics Standards (MATS). As with
the proposed CCR and ELG rules, the vast
majority of toxic metals targeted by MATS
originate from coal-fired power plants.
The EPA recognized that many processes
designed to remove metals from gaseous
emissions result in a transfer of the metals
to other effluents, which is one reason it
Author
Dale Timmons is a egistered geologist
and Business Development Program
Manager with NAES Corporation.
Dense Slurry
Coal Ash Management:
Full Compliance,
Lower Cost,
Less Risk

Electron Microprobe Image of a No-Lime Sample 1
Source:NAES Corporation
fly ash transport water discharge, little
or no fugitive dust, and enhanced se-
questration of contained metals. These
properties meet the performance re-
quirements specified in the new CCR
rule and the proposed ELG.
DSS is currently used at eight power
plants – seven of them in Europe and
one in the U.S. Two more plants are
being built or commissioned – one in
Europe and one in India – that will use
the technology. Circumix DSS systems
have processed over 60 million cubic
yards of dense slurry into environmen-
tally stable end products, primarily
using flue gas desulfurization (FGD)
water and other plant wastewater as the
stabilizing medium.
In addition to achieving compliance
with the new ELG and CCR rules, DSS
offers numerous additional advantages:
• Combined stabilization of ash and
wastewater
• Reduction of water use by 80 to 90
percent compared to traditional
practice
• Zero discharge of transport water
• Significant reduction of plant-wide
wastewater
of trucks and heavy equipment signifi-
cantly increases safety risks.
DENSE SLURRY SYSTEM ASH
MANAGEMENT
A dense slurry system (DSS) offers a
safer, less expensive alternative to dry ash
management while producing a product
with improved environmental perfor-
mance. DSS is a high-intensity mixing
process that combines plant wastewater
with CCRs to produce dense slurry that
is easily pumped to an impoundment or
landfill. The process maximizes the avail-
ability of reactive ions in the ash and opti-
mizes the use of wastewater.
Dense slurry produced by the DSS
process displays a consistency of 50 to 60
percent solids by weight with a density
of about 1.3 g/cm3
, which is maintained
to within 1 percent. This is thick enough
to minimize free water but thin enough
to allow pumping to a distance of over 6
miles using centrifugal pumps.
Once discharged, the slurry hard-
ens in 24 to 72 hours and substantial-
ly cures in about a month. The cured
product exhibits low hydraulic conduc-
tivity, high compressional strength, no
proposed the ELG rule.
Suffice it to say, the CCR, MATS, and
proposed ELG rules are requiring own-
ers and operators of coal-fired power
plants in the U.S. to make pivotal de-
cisions regarding future operations at
these plants and how best to address
the regulatory changes.
DRY ASH MANAGEMENT
Power plants face a number of chal-
lenges when converting to an alterna-
tive ash management system because
few options are available. Conventional
practice is commonly called “dry ash”
management, which is misleading. So-
called dry ash management for transport
and disposal to an impoundment or
landfill typically involves the addition of
20 to 25 percent water to suppress dust.
Once the wetted ash is transported and
disposed of, it is typically spread and
compacted using heavy equipment. Ad-
ditional water is often added using sprin-
klers or water trucks to control dust and
improve compaction.
Traditional dry ash management typ-
ically involves handling and moving the
ash multiple times, with each transfer
adding more risk of dust release. To ad-
dress this, the new CCR rules impose
stringent controls on fugitive dust at im-
poundments. Even after ash is spread and
compacted, it can easily be mobilized
by wind if allowed to dry. It also exhib-
its relatively high hydraulic conductivity,
which translates into high rates of leach-
ate production.
Traditional dry ash management also
poses a major expense. The costs of
transferring the ash to ash/water mixing
facilities, together with the capital and
operating costs of the facilities them-
selves, are high. Truck transport, road
construction and maintenance, fuel
management, heavy equipment opera-
tion and maintenance, continual dust
suppression, lighting and security at the
disposal site, plus associated labor fur-
ther reduce the appeal of dry ash han-
dling. Lastly, the continual operation

Electron Microprobe Image of a Lime-Added Sample 2
Source:NAES Corporation
31www.power-eng.com
concrete contains about 25 percent
bound water.)
Although DSS has been used extensive-
lyinEuropeandatoneplantintheUnited
States for decades, plant-specific testing is
still required to establish the proper blend
of solid waste products and wastewater
for optimal environmental performance.
While performance-enhancing additives
are available, all of the DSS facilities cur-
rently in operation process ash that is suf-
ficiently reactive on its own.
The ash produced by some power
plants in the United States, however, ex-
hibits little or no reactivity. Where this
is the case, additives may be used to in-
crease compressional strength and reduce
hydraulic conductivity. Typically, 2 to 3
percent active lime is enough to achieve
adequate solidification.
CASE STUDY:
PRB COAL ASH
For example, NAES tested samples
of Powder River Basin (PRB) coal ash to
determine their performance relative to
DSS. The samples contained over 20 per-
cent CaO, but only 0.14 percent of it was
chemically active.
Figure 1 shows an electron microprobe
image of cured slurry product made using
60 percent PRB fly ash and 40 percent
water. (Note the regions where ettringite
crystals have formed.) After six weeks of
curing, the low reactivity of the ash result-
ed in very little cementation. The cured
product exhibits a porosity of about
50 percent, as evidenced by the dark
regions of empty space in the image.
After curing, the sample showed com-
pressional strength of 48,263 Nm-2
(7
psi) and the hydraulic conductivity
measured 3 x 10-5
cm/sec.
To find out how the PRB slurry per-
formance could be improved, NAES pre-
pared another sample – this time using
50 percent fly ash, 2.5 percent active lime,
and 47.5 percent water by weight – and
allowed it to cure for six weeks. In figure
2, the cured product shows a significant
reduction in porosity compared to the
variations in the amount of water used
to make the slurry can impact process-
ing parameters of that slurry. It has also
demonstrated that small quantities of ad-
ditives, where indicated, can dramatically
improve product performance.
The compressional strength and hy-
draulic conductivity of cured DSS prod-
ucts depend largely on the chemical
reactivity of the fly ash contained in the
slurry. This reactivity in turn depends on
several variables: type of fuel, emission
controls used, type of boiler, and combus-
tion temperature, among others.
As dense slurry cures, hydrated mineral
crystals grow in the spaces between ash
particles, including the following:
Ettringite 60% Bound Water
Allite 32% Bound Water
This interstitial crystal growth se-
questers water, entrains small parti-
cles, and inhibits fluid flow. In addi-
tion, the crystals act as an adhesive that
binds ash particles together, resulting
in greater compressional strength.
This process – the same that occurs
in the curing of concrete – is a desired
outcome of DSS. (For reference, most
• Low hydraulic conductivity (10-6
to
10-10
cm/sec)
• High compressional strength
• Enhanced metals sequestration
• No risk of liquefaction or spills asso-
ciated with liquefaction
• Significant reduction of leachate vol-
ume
• Significant reduction of fugitive dust
emissions
• Enhanced land-use efficiencies from
elevated disposal facilities
• Reduced energy consumption
Several variables contribute to low hy-
draulic conductivities in the cured prod-
uct, including particle size distribution,
particle shape, water chemistry, and ash
chemistry. The mixing process results in
close packing of the ash particles upon
discharge. The chemistry of the ash
and water determine the type of crystal
growth that takes place in the interstitial
spaces between ash particles upon curing.
PERFORMANCE
ENHANCEMENT OF SLURRY
PRODUCTS
NAES has found in recent testing that

Hydration Curves Showing Sequestration
ofWater OverTime
3
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 5 10 15 20 25 30 35 40 45 50
0% CaO
2,5% CaO
5% CaO
10% CaO
Free water
(kg free water/kg total process water)
Number of days of curing
Freewaterpercentage
by progressively reducing hydraulic
conductivity and increasing compres-
sional strength.
In active impoundments and land-
fills that receive dense slurry, evapo-
ration removes significant quantities
of water before it can infiltrate the im-
poundment. The hydration reactions
that occur during curing, coupled with
evaporation, result in zero discharge of
fly ash transport water.
A COMMERCIALLY
OPERATING DSS
IMPOUNDMENT IN
HUNGARY
The active ash disposal impoundment
at the Matra Plant, which began opera-
tion in 1998, consists of 15 tiers, each 10
feet thick, of solidified Type F ash that has
been pumped to the impoundment from
the plant as dense slurry. The 150-foot
high impoundment covers an area of 314
acres at its base and 122 acres at the top.
The established tiers have been planted
with fruit trees.
The top of the impoundment is di-
vided into six smaller enclosures sep-
arated by dikes. When an enclosure
is full, discharge is transferred to an
adjacent enclosure. Cured dense slur-
ry from the perimeter of the full im-
poundment is then excavated and used
to construct the dike for the next tier.
To prevent interruptions in plant
operations caused by lack of dispos-
al space, at least two of the multiple
smaller impoundments at the top of
the facility are always made available
to receive dense slurry. The impound-
ment poses no risk of liquefaction of
ash products or catastrophic failure
(e.g., inundation of the surrounding
community) because the compres-
sional strength of the contents ranges
from 5,000 to 11,000 lbs/ft2
. Hence,
there have been no slope failures or
other incidents requiring remedi-
al action since operations began. All
leachate is returned to the plant for
use in DSS processing, making this a
amount of water sequestered with the
concentration of lime.
The samples were molded into
4-inch plastic tubes wrapped with geo-
textile fabric at the base to allow leach-
ate to drain out of the slurry. The cap-
tured leachate was periodically poured
back through the curing product. The
samples and drained water were main-
tained in a closed system to prevent
evaporation of water.
As shown in the hydration curves for
the four mixes (Figure 3), water is rap-
idly sequestered during curing. The mix
with 2.5 percent active lime sequestered
90 percent of the free water in 15 days.
Samples with higher active-lime concen-
trations sequestered the same amount of
water in five days or less.
NAES also found that as the thick-
ness of accumulated slurry product in-
creases in an impoundment or landfill,
so does the amount of water seques-
tered. As dense slurry impoundments
accumulate more slurry, the amount of
leachate produced thus declines over
time because the water that infiltrates
has more time to react as it percolates
through the curing product. These con-
tinuing reactions enhance the perfor-
mance of the impoundment over time
no-lime sample – about 6 percent po-
rosity in the lime-added product versus
50 percent in the no-lime product. The
reduction in hydraulic conductivity of
the lime-added sample – 3.4 x 10-6
– rep-
resents about one order of magnitude.
The compressional strength increased by
97 percent to 1,296,214 Nm-2
(188 psi).
SEQUESTRATION
OF WATER
Mineral growth that takes place during
curing sequesters significant quantities of
water. This is important because the EPA’s
preferred options under the proposed
ELG prohibits discharge of fly ash trans-
port water under any circumstance. Dis-
posal facilities that use the DSS process
have achieved zero discharge of transport
water by reprocessing leachate to produce
more dense slurry.
To assess how much water is seques-
tered in the DSS curing process, NAES
tested ash samples from the Matra Pow-
er Plant near Budapest, Hungary, the
‘flagship’ of DSS facilities. Using a slur-
ry of 60 percent fly ash and 40 percent
water by weight, NAES prepared sam-
ples with 2.5, 5, and 10 percent active
lime added, as well as a control sample
without added lime, to correlate the

33www.power-eng.com
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‘recipe’ for stabilizing CCRs. NAES
conducted testing at numerous loca-
tions using a pilot-scale dense slurry
processing system.
Prior to the pilot test, samples of
combustion products and wastewater
are analyzed to determine their chem-
istry and particle size distribution.
zero-discharge facility for both trans-
port water and leachate.
DSS TESTING
The physical and chemical proper-
ties of ash and water vary from plant
to plant, so these materials must be
tested at each site to determine the best
The tiered and elevated DSS impoundment at Matra
Power Plant in Hungary is planted with fruit trees.Inset:
The cured dense slurry from the impoundment perimeter
is used to construct a dike for newly discharged slurry on
the top level.Photo courtesy:NAES
The pilot-scale system is then used to
process a range of promising ‘recipes.’
Each recipe is allowed to cure for 90
days before the samples are collected
for testing.
Data collected during slurry pro-
cessing includes rheology parameters
(yield stress and rigidity), water con-
tent/flow dynamics, energy consump-
tion, mix ratios, and water stoichiome-
try. Cured samples may be analyzed for
the following:
• Compressional strength
• Porosity and hydraulic conductivity
• Bulk chemistry
• Moisture and density
• Electron microprobe analysis
• Leach performance

WEBCAST
REGISTER TODAY
THE TOTAL CONDENSER PERFORMANCE WORKSHOP™:
NON-DESTRUCTIVE TESTING
SEPTEMBER 1, 2015 | 2:00PM CDT
produce the dense slurry
• Zero discharge of transport water
• Zero discharge of leachate if re-
used for dense slurry production
• Enhanced sequestration of con-
tained metals
• Reduced risk of groundwater con-
tamination
• Reduced or eliminated risk of dust
generation
• High compressional strength
In addition, the tiered, elevated
disposal facilities typically used with
DSS enable more efficient use of dis-
posal space. Piping the slurry to these
impoundments reduces or eliminates
the use of heavy equipment and its
attendant safety and environmental
risks. More to the point, DSS process-
ing eliminates ash sludge liquefaction,
and with it the risk of dike failure and
catastrophic releases.
The data collected, along with plant
information, are used to determine
system capacity, slurry pumping re-
quirements, and impoundment/land-
fill design. They are also used to esti-
mate probable leachate production and
environmental performance of the sta-
bilized product.
ENVIRONMENTAL
PERFORMANCE
The CCR and ELG rules are closely
related and interdependent. Design
changes at coal-fired power plants that
affect the quantity and chemistry of
generated wastewater also affect the
transportation, management, com-
position, beneficial reuse options,
and disposal of combustion products.
These changes in turn affect the design,
operations, monitoring, and closure
requirements for impoundments into
which CCRs are deposited. They also
influence decisions regarding the man-
agement and fate of CCRs in existing
impoundments.
In terms of environmental protec-
tion, operational safety, and financial
risk, DSS has proven itself altogether
superior to “dry ash” management.
It not only meets the requirements of
CCR and ELG but yields a product with
outstanding environmental perfor-
mance:
• Hydraulic conductivity that is sub-
stantially lower than that resulting
from traditional “dry ash” man-
agement as described in the pro-
posed ELG
• 80-90 percent less consumption of
water compared to traditional ash
sluicing
• Stabilization of wastewater (in-
cluding FGD water) used to

Valves &
ActuatorsBY RUSSELL RAY, CHIEF EDITOR
unchanged, innovative applications
and design modifications are being
developed to withstand these demand-
ing environments. In addition, these
improvements can reduce costs by sup-
porting the control valve’s ability to
throttle accurately, thereby providing
better performance for high-pressure
steam bypass, turbine bypass and oth-
er critical power plant operations.
Actuators regulate mass and energy
flows by adjusting valves, flaps and
cocks.
The actuator and valve create a single
unit — the control valve. Actuators
perform different motion sequences,
including linear, pivoting and rotating
motions, and they are powered by
pneumatic, hydraulic or electrical
energy.
Actuators receive a control signal
from automation systems. The signal
is converted into a motion so that the
A
single power plant uses
hundreds of valves to
control almost every as-
pect of its operation.
Valves, in conjunction with a con-
trolling actuator, are used for pollu-
tion control, feed water, cooling water,
chemical treatment, bottom ash and
steam turbine control systems.
They work in harsh environments
and are exposed to a variety of chem-
icals, abrasive materials and high
temperatures. They are critical in
optimizing efficiency, and they are
often the final control element in the
operation of a power plant.
What’s more, additional demands
are being placed on valves and actu-
ators as power plants are forced to be
more flexible to accommodate the
growth of intermittent sources of re-
newable power and mandates to curb
carbon emissions. As a result, valves
and actuators must operate at higher
pressures, temperatures and frequency.
Although the basic technology for
most valves and actuators has remained
Cycle Isolation testing utilizes acoustic monitor-
ing instruments to help customers monitor valve
performance.Photo courtesy:ValvTechnologies
OPERATIONS & MAINTENANCE

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acts as a piston to create linear force to
close and open the valve. Power plants
have traditionally used pneumatic
actuators to drive the many control
valves throughout their facilities.
However, major improvements in
control element of the actuating el-
ement assumes a corresponding po-
sition. With control valves, this is a
stroke motion. With flaps, ball cocks
or rotary plug valves, this is a pivoting
motion.
VALVE-ACTUATOR TYPES
There are three common types of
actuators: Electric, pneumatic, and hy-
draulic.
Pneumatic valve actuators are pow-
ered with air or gas. The air pressure
The Rotork CVA offers an accurate and responsive method of
automating control valves without the complexity and cost of a
pneumatic supply.Photo courtesy:Rotork
OPERATIONS & MAINTENANCE

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position transmitter is greater than
300:1 position turndown.
The valve body is coupled to an actu-
ator assembly that contains a fail-safe
spring to quickly close the valve, halt-
ing fuel flow in the event of a power
failure or turbine trip condition. When
electric control-valve actuator technol-
ogy are helping power producers lower
costs and boost efficiency. Valve actua-
tors powered by an electric motor can
withstand the demands of continuous
movement. In addition, they work ef-
fectively in harsh environments, and
provide superior performance in a
wide range of applications. The bene-
fits include better efficiency, less main-
tenance and enhanced performance
of the control valves. What’s more,
electric actuators do not require recali-
bration over time. Once calibrated, the
electric control valve actuator can op-
erate for months, even years, without
adjustment.
Hydraulic actuators, which use pres-
surized hydraulic fluid to open and
close valves, are increasingly popular
because of their ability to achieve high
torque. Hydraulic actuators are de-
signed to carry out linear movement of
all kinds. When a large amount of force
is required to operate a valve, hydraulic
actuators are normally used. The most
common type of hydraulic actuator
uses pistons that slide up and down
within a cylinder containing hydraulic
oil and a spring.
Young & Franklin offers electrome-
chanically actuated (EMA) gas control
valves designed specifically for the
challenging operating conditions of in-
dustrial gas turbines.
Industrial gas turbines require pre-
cise control of the combustion process
to drive efficiency, reduce emissions,
and maximize availability. According
to Young & Franklin, the company’s
EMA valves offer substantial advan-
tages over their hydraulically actuated
counterparts.
Young & Franklin 3010 Series
Choked flow valves are electromechan-
ically actuated (EMA), single seat pre-
cision fuel control valves. These sonic
flow valves are available in a range of
sizes suitable for industrial or power
turbines of any size.
The Y&F 3010 EMA gas control valve
(GCV) is a modern, high precision
control valve with excellent speed and
valve position accuracy at low open-
ings. This GCV electronically re-ze-
ros its closed position reference every
time the power is cycled and the valve

2015 08 Power Engineering

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2015 08 Power Engineering