power engineering june 2013
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Established in 1896, Power Engineering magazine is the comprehensive voice of the power generation industry that provides readers with the critical information needed to remain efficient and competitive in today's market. For three years in a row, Power Engineering has been named the most read and useful magazine in the power industry. Power Engineering Online provides up-to-the-minute energy news, stock quotes, five years of searchable editorial archives, power generation conference schedule and details, and an industry product and services guide. Power Engineering is part of the PennWell energy group, the largest U.S. publisher of electric power industry books, directories, maps and conferences.TRANSCRIPT
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BOILER CLEANINGTHE BEST TECHNIQUES AND STRATEGIES
the magazine of power generation
Emission Control
TECHNOLOGY
thhe magazine of power generatiion e
117YEARS
1306pe_C1 C1 6/4/13 4:07 PM
March 2013 • www.power-eng.com
EMISSIONS CONTROL UNDERSTANDING YOUR OPTIONS
HYDROPOWER THE POWER OF REHABILITATION
PRB COAL CHALLENGES AND SOLUTIONS
the magazine of power generation
Wind Turbine TECHNOLOGY CHOICES
NHA Spec
ial
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ising
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on 35
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the magazine of power generation
the magazine of power generation
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March 2013 • www.power-eng.com
EMISSIONS CONTROL UNDERSTANDING YOUR OPTIONS
HYDROPOWER THE POWER OF REHABILITATION
PRB COAL CHALLENGES AND SOLUTIONS
the magazine of power generation
Wind Turbine TECHNOLOGY CHOICES
NHA Spec
ial
Advert
ising
Secti
on 35
-47
117YEARS
the magazine of power generation
the magazine of power generation
A quick start guide to MAXIMIZING our interactive features.Welcome to the Digital Edition of
SHARE an article or page via social media.
Click PAGES to view thumbnails of each page and browse
through the entire issue.
Easily browse all BACK ISSUES.
SEARCH for specific articles or content.
View the table of CONTENTS and easily navigate directly to an article.
DOWNLOAD the issue to your desktop.
PRINT any or all pages.SHARE an article via email.
Easily NAVIGATE through the issue.
Click directly on the page to ZOOM in or out. Fit the issue to your screen.
TabTransition_Template.indd 1-2 3/19/13 6:03 PM
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Copyright 2013, Solvay Chemicals, Inc. All Rights Reserved
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often move to the back burner. But with MATS and MACT deadline mandates just over the
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Power Engineering ®
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Industry News:Global updates throughout the day
Newsletter:Stay current on industry news, events, features and more.
Newscast:A concise, weekly update of all the top power generation news
2 Opinion
4 Clearing the Air
6 Nuclear Reactions
8 Demand Response
10 View on Renewables
12 Gas Generation
14 Power Plant Profile
18 What Works
72 Ad Index
FEATURES No. 6, June 2013117VOLUME
20 Extending the Life of Coal Fired Plants Through theUse of Dry Sorbent Injection
40 Gas Turbine Combined Cycle Fast Start:The Physics Behind the Concept
y
Fast start capability is one of the major features of gas turbines that give power plants flexibility in their operations. Learn more about the key mechanisms that limit the startup times of modern combined cycle gas turbines.
28 Advances in BoilerCleaning Technology
From dynamite to the latest in online cleaning systems, Power Engineering looks at methods to keep boilers slag-free and working at peak efficiency.
50 Upgrading Electrostatic PrecipitatorsMany electrostatic precipitators will need to be upgraded or converted into a baghouse to handle particulate matter emission standards regulated by federal standards. Learn more about different methods for upgrading ESPs.
62 Development Status of theAlden “Fish-Friendly” Turbine
Several organizations have been working to advance the construction and installation of a “fish-friendly” turbine design. Read about their efforts and the search for a hydropower project to demonstrate the new technology.
56 Engineering Design forRICE NESHAP Compliance
Read about the steps taken and challenges faced by a team working to bring an NRG Energy peaking plant into compliance with regulations requiring less carbon dioxide emissions.
Many plants are lowering emissions through the use of dry sorbent injection,
which costs a fraction of the price of a wet scrubber. Power Engineering
looks at the benefits of DSI systems for adapting to changing regulations and
compliance dates.
1306pe_1 1 6/4/13 3:54 PM
www.power-eng.com2
OPINION
on several rulemakings that are sure
to have a significant impact on electric
utilities. Here are three of those forth-
coming rules:
• A final rule governing cooling wa-
ter intake structures at existing
power plants is expected to be is-
sued this month. The rule, which
targets plants using once-through
cooling systems, would require
many facilities to install closed-
cycle cooling systems. Closed-cy-
cle systems use less water from riv-
ers and bays and harm fewer fish.
Under the rule, plants that draw
more than 2 million gallons a day
and use at least 25 percent of that
water for cooling are required to
take action to protect the aquatic
environment. More than 670 U.S.
plants will be affected by the new
rule. The measure will require
some power producers to modify
cooling water intake structures or
construct new cooling towers.
• The EPA is expected to issue a rule
expanding the oversight of coal
ash management and disposal at
U.S. power plants. The rule would
require coal-fired power plants to
eliminate wet ash handling and
phase out surface impoundments,
or ponds, within five years. The
rule was proposed after a 40-acre
coal ash storage pond at Tennes-
see Valley Authority’s Kingston
plant in Harriman, Tenn., failed
in 2008, spilling more than 1 bil-
lion gallons of coal ash slurry. The
big question is this: Will the EPA
classify coal ash as a hazardous or
Navigating the regulatory
maze is a dangerous under-
taking for power producers
nowadays. Developing a sound, cost-
effective strategy for compliance has
been complicated by layers of new en-
vironmental rules and delays in imple-
mentation.
One misstep can set a project back
by years, costing power producers and
their customers millions. New rules
governing mercury emissions, cool-
ing technology, wastewater treatment,
coal ash management, regional haze,
and greenhouse gas emissions pose a
formidable challenge for utility execu-
tives and power plant managers. Some
of these rules have been finalized
while others are in the works.
Successful compliance requires a
carefully coordinated, catchall strategy
that includes a calculated integration
of technologies. Balance is the goal.
A comprehensive plan that achieves
the new environmental standards and
ensures reliable and affordable electrici-
ty is the end-game. But getting there will
be different for every power producer
and every plant.
The maze of environmental rules is
becoming more difficult to navigate.
There are a number of new environ-
mental rules awaiting final action or
implementation. These rules, which
will cost the industry billions in com-
pliance costs, will dictate the future
of power generation in the U.S. for
decades to come. It is very important
these rules be as flexible as possible.
The U.S. Environmental Protection
Agency is expected to move forward
non-hazardous waste? The differ-
ence is significant. A hazardous
classification would cost power
producers billions more in com-
pliance costs.
• In April, the EPA proposed efflu-
ent limitation guidelines to reduce
wastewater discharges from power
plants. The rule is expected to be
finalized by May 2014. The rule
would be the first update of the
effluent limitations guidelines
since 1982. The EPA proposed the
rule after the agency found that
the increased use of air pollution
controls was increasing pollution
in wastewater discharges. The rule
would reduce pollutants from the
following wastewater streams: flue
gas desulfurization, fly ash, bot-
tom ash, flue gas mercury control,
landfills and surface impound-
ments, nonchemical metal clean-
ing wastes, and fuel gasification.
You may have noticed a commonal-
ity in all of these measures. All three
rules call for significantly stricter stan-
dards for water usage in power plants.
The change in the EPA’s focus is clear.
After decades of advancing clean-air
regulations, the agency plans to put a
higher priority on new water rules for
power producers. At POWER-GEN In-
ternational 2013 in Orlando, Fla., all
of these rules and their impacts will
be thoroughly examined by experts
participating in several conference ses-
sions. To register online, visit www.
power-gen.com. If you have a question
or a comment, please contact me at
ManagingRegulatory MayhemBY RUSSELL RAY, MANAGING EDITOR
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CLEARING THE AIR
also be removed by injecting alkali
such as trona or lime/hydrated lime
upstream of PAC injection. The main
drawback of the PAC system is its
potential adverse effect on ESP per-
formance when ESP is used for par-
ticulate collection and to improve the
salability of fly ash. A new market en-
trant, injection of amended silicates,
can potentially negate both increased
SO3 concentration in the flue gas and
the attendant adverse effect on ESP
performance. The long-term viability
of amended silicate has not yet been
demonstrated, however.
Halogen compounds such as bro-
mine or hydrogen bromide added to
flue gas increase the conversion of
elemental mercury to ionic mercury,
thereby facilitating mercury capture
in downstream FGD. Halogen salts
can also be added to coal before the
pulverizers. During combustion, bro-
mide salts decompose and release
bromine ions, which in turn oxidize
elemental mercury to ionic mercury
that is removed in FGD. Bromine ions
can potentially increase fireside cor-
rosion. Some ionic mercury collected
in the FGD can revert back to elemen-
tal mercury and can be re-emitted
into the flue gas. Although chemicals
can be added to minimize re-emis-
sion, the exact mechanisms of the re-
emission reactions and the mitigation
measures are not clearly established.
Given the complexity of choos-
ing control technologies for limiting
mercury emissions, a comprehensive
site-specific study may be necessary
to help your company choose the op-
timal solution.
T he optimal selection of control
technologies to limit mercury
emissions depends on the type
of coal-fired unit (new or existing),
the rank of the coal and existing emis-
sion control systems.
Mercury in coal varies from 0.05
to 0.25 parts per million by weight,
depending on the type of coal. The
established regulatory limits on mer-
cury emissions depend on the type of
unit and the type of coal. The limits for
new coal-fired units are 0.04 lb/GWh
for units that burn low-rank coal such
as lignite with a higher heating value
(HHV) of less than 8,300 Btu/lb,
and 0.003 lb/GWh for units burning
high-rank coal with an HHV of more
than 8,300 Btu/lb. For existing units,
the corresponding limits are 0.12 lb/
GWh or 11.0 lb/TBtu and 0.013 lb/
GWh or 1.2 lb/TBtu, respectively.
These emission limits translate to re-
moval efficiency ranges of 65 percent
to more than 80 percent for new units
using low-rank coals and 95 percent
to more than 98 percent for new units
burning high-rank coals. The removal
efficiency ranges for existing units are
15 percent to more than 50 percent
for low-rank coals and 85 percent to
95 percent for high-rank coal.
Because the removal requirements
are based solely on lb/GWh, opera-
tors of new units may find that low-
mercury coal and the ultra super-crit-
ical steam cycle, which yield very low
heat rates in the range of 8,000 Btu/
KWh, offer substantial benefit. For
existing units, the control technology
selection depends on the removal
requirement, mercury concentration
and speciation, and type of existing
emission control system.
During combustion, mercury in
coal is first released as elemental
mercury (Hg0), before it is converted
to ionic or oxidized species (Hg++)
and as particulates. The conversions
depend on many factors, such as the
rate of cooling, concentrations of
halogens and sulfur trioxide (SO3),
amount of fly ash, fly ash properties
and unburned carbon in fly ash. The
concentration of elemental mercury
and ionic mercury varies from 20
percent to 80 percent, depending on
the coal, its halogen content and the
particulate mercury content. Elemen-
tal mercury is not water soluble and
is difficult to remove in downstream
flue gas desulfurization (FGD) sys-
tems. Ionic mercury, on the other
hand, is very water soluble and is eas-
ily removed in FGD systems, both
wet and dry. The particulate mercury
is also removed by devices such as an
electrostatic precipitator (ESP) or a
fabric filter (FF) with fly ash.
Mercury can be removed through
chemical adsorption on powdered
activated carbon (PAC). Activated
carbon is injected upstream of an ESP
or FF and is removed along with fly
ash. Because it is also adsorbed and
removed by PAC, the presence of SO3
adversely affects mercury removal.
If SCR is used for nitrogen oxides
(NOx) control, it can exacerbate this
problem; SCR tends to oxidize sulfur
dioxide (SO2) to SO
3 and increases
SO3 concentration in the flue gas.
Low-oxidation catalysts can be used
to minimize this problem. SO3 can
Finding Best-Fit Mercury Emission ControlsBY NAT SEKHAR, SENIOR CONSULTANT, CH2M HILL
Author
Nat Sekhar, P.E., a Se-
nior Consultant with
CH2M HILL, is an inter-
nationally recognized
emission control ex-
pert. He has been the
technical lead on more
than 25,000 emis-
sion control projects
incorporating flue gas
desulfurization, nitrous
oxide, electrostatic
precipitator/baghouse,
and other emission
control systems. Nat
has contributed to more
than 40 technical pub-
lications and presenta-
tions, and coauthored
the Fossil Fuel Power
Generation section in
McGraw Hill’s Encyclo-
pedia of Science and
Technology.
1306pe_4 4 6/4/13 3:54 PM
Founded in 1988, PIC has been a leader in the
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are experts at managing multi-faceted projects
including start-up and commissioning, operations
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Combine these capabilities with our responsive
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see why those who know choose PIC.
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NUCLEAR REACTIONS
years at the Summer and Vogtle construc-
tion sites, respectively. The historic com-
pletion of 7,000 cubic yards of basemat
structural concrete at each site by CB&I
(formerly Shaw Group) serves as the
foundation for the nuclear island struc-
tures, such as the reactor containment
and auxiliary buildings. Georgia Power
and SCG&E (and their co-owners) are
each building two Westinghouse AP1000
(1,100 MWe) reactors at the Vogtle and
Summer locations. Westinghouse and
CB&I are even further along in building
four AP1000 units in China.
The AP1000 is considered a third
generation (III+) advanced reactor that
provides a simplified design, reduced
capital costs, greater fuel efficiency and
enhanced safety margins through the
use of passive safety functions. There are
many other new advanced reactor de-
signs being developed, including mPow-
er’s (Babcock & Wilcox) small modular
reactor that received a DOE cost-sharing
award for certification and licensing.
Generation IV reactor designs are still
on the drawing board but have com-
mitted international partners pursuing
a defined set of approaches. Gen IV de-
signs provide even higher levels of safety
and reliability, proliferation resistance,
physical protection and economic com-
petitiveness, according to the American
Nuclear Society.
Many signs of life can be seen in the
progress made in the licensing and con-
struction of new reactor designs. Nuclear
energy may face continued economic,
technological and political challenges
but it will retain an important role in
world economic development, particu-
larly if efforts are increased to address
climate change.
With all the attention that is
being given to recent an-
nouncements of nuclear
power plant closures and threatened
shutdowns, it would be easy to think
that U.S. nuclear power is marching to
its death. Easily overlooked are the signs
of life and significant milestone achieve-
ments of new nuclear technology.
Nuclear plant owners started feeling
squeezed when decreased electricity de-
mand met a perceived natural gas glut
(much of the shale gas reserves have not
been tapped yet) and the ensuing low
prices. This combination has meant utili-
ties could get very little for their electric-
ity generation, and merchant nuclear
plants have become borderline breakeven
or worse. With the addition of costly Fu-
kushima modifications and aging major
equipment, speculation has increased
that more nuclear plants will follow the
path of Dominion’s Kewanee and Duke’s
Crystal River station.
Although it is likely that a few addi-
tional nuclear plant shutdowns will be
announced over the next year or so, po-
tential signs of life can be seen by stepping
back from the current bleak economic en-
vironment for nuclear power and looking
at the long-term prospects. According to
the U.S. Energy Information Administra-
tion (EIA), nuclear power’s share of the
electricity mix is expected to decrease by
only 2% by 2040, losing some ground
to natural gas and renewables, which
will also absorb increases in demand.
With any future regulatory effort to cap-
ture fees for carbon allowances, nuclear
power’s estimated share of generation
increases anywhere from 7-18%, taking
the gains from coal. Global long-term es-
timates show that nuclear power’s overall
proportion of electricity generation stays
fairly constant, with losses in Europe and
gains in Asia, according to the Interna-
tional Energy Agency.
The EIA predicts that by 2020 the U.S.
will become a natural gas (net) exporter,
which would put pressure on natural gas
and electricity prices and keep currently
operating nuclear power plants above
water. It is unlikely that more than a few
additional nuclear plants will close in the
U.S., given that regulated utilities will be
able to weather the current environment
and non-regulated nuclear generators
will want to retain enough nuclear ca-
pacity to be well positioned when prices
increase. Moreover, if too much nuclear
generation is lost at the same time aging
coal plants are closing, natural gas will
be used increasingly for baseload gen-
eration, putting even more pressure on
prices.
Despite economic challenges to the
nuclear industry, many experts support
nuclear power as an essential part of the
mix. At least one high-profile investor,
Microsoft Corp. Chairman Bill Gates,
touts the benefits of nuclear power and
calls for more investment in nuclear en-
ergy research. At the international energy
executives’ conference in March (CER-
AWeek), Gates endorsed nuclear power
as the best long-term solution to rising
world energy needs in the midst of cli-
mate change. Gates also discussed how
since Fukushima there is a greater de-
mand for improved reactor designs with
inherent safety features.
A significant milestone in U.S. nuclear
power was achieved very recently. In
March, South Carolina Electric and Gas
(SCG&E) and Georgia Power poured the
first new “nuclear concrete” in over 30
Nuclear Power’s Strong Future amid Challengesin the presentBY, MARY JO ROGERS, PH.D.
1306pe_6 6 6/4/13 3:54 PM
©2013 S
handong N
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Westinghouse AP1000® plant under construction in Haiyang, China
NO COMPANY
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ON ADVANCED
FOCUSED
NUCLEAR PLANT
IS
www.westinghousenuclear.com
TECHNOLOGY
For info. http://powereng.hotims.com RS# 4
1306pe_7 7 6/4/13 3:54 PM
www.power-eng.com8
DEMAND RESPONSE
management.
Supply chain management in other
industries is the key to efficiency. That
happened when logistics specialists real-
ized that silos of activity allowed massive
inefficiencies by masking the true costs
and inconsistencies in the way goods
moved to market. Like or loathe Amazon
and Wal-Mart, that’s where most people
go when they want something quickly
and at the lowest cost. In other words,
the market demanded and the suppliers
responded.
That is the key to understanding DR. It
is supply chain management, and we’d
be well advised to learn to do this well.
Today’s customers want green, reliable,
efficient, safe, and productive power.
Economic productivity and climate sus-
tainability demand it.
In coordinated communities, peaks in
one section can fill valleys in another. En-
ergy storage, EV charging and distributed
generation are in the mix. Perhaps the
future of Integrated Resource Planning
should include “Energy Districts” that
self-optimize and present a “flattened”
profile to the larger grid. Maybe the util-
ity of the future should develop, own and
operate those resources. They are expert
as asset and financial management.
Clearly, the US has not scratched the
surface of efficiency once we get outside
the thinking that it must be specific to a
customer facility. Efficiency is environ-
mental, but DR is management. It can
shape, tune and arrange energy use to
respond to opportunities. My father al-
ways said to learn a tool well, but then to
use the right tool for the job. With respect
to efficiency in the US, so far we’ve been
using hammers for everything. Enough.
The Department of Energy de-
fines Demand Response (DR)
as “changes in electric usage by
end-use customers from their normal
consumption patterns in response to
changes in the price of electricity over
time, or to incentive payments designed
to induce lower electricity use at times
of high wholesale market prices or when
system reliability is jeopardized.” The
2005 Energy Policy Act encourages the
use of Demand Response and FERC has
manifested this in a number of tariffs
which grant equivalency between DR
and generation in value. But…
What is Demand Response, really?
Electrons obey the laws of physics. They
travel to ground over the path of least re-
sistance. Our job is to get them to do a lit-
tle work along the way without wreaking
too much havoc, which they like to do.
Demand response is how we do that.
Everything about an electron’s intended
journey to ground is shaped by some-
one’s desire (“demand”) to achieve a goal.
Those goals are determined by the com-
munity of electron users; i.e., customers.
They demand power: clean, abundant,
cheap, renewable, and efficient. In that
sense, DR is everything a utility does.
Now is the time to use DR to meet
goals of efficiency and environmental
stewardship.
Thirty-one states have renewable en-
ergy portfolio standards. Too few of them
allow energy efficiency to count toward
those goals. If less energy is needed, then
it’s simple math that each source of that
energy can contribute a larger percent.
Similarly, DR is vital both in making re-
newable electrons behave as well as tim-
ing demand so that it peaks when those
renewable electrons are most available.
It is precisely this attribute that leads the
California Independent System Operator
(ISO) to predict that by 2020, the tradi-
tional fossil fuel supplied afternoon de-
mand peaks will disappear. Local solar
and other techniques will move peaks to
early evening.
That is a sea change in the way we
think about grid planning.
There is a form of Demand Response in
commercial production that is analogous to
most forms of generation, except perhaps
for black-start, but don’t rule that out.
Realistically, generation is always neces-
sary, since DR only can free, not generate,
electrons. Even that is subject to revision
as local solar, batteries and other forms
of distributed generation begin to assert
themselves on the demand side, respond-
ing not only to site needs but also to larg-
er microgrid and macro-grid conditions.
For two years, Massachusetts has been
the most energy efficient state. Utilities
there have done about all the efficient
lighting, weather-stripping, rebating and
retrofitting they know how to do. Yet, the
legislature demands more. The answer
may be to leave the customer site and
take the larger view; to examine what we
mean by “efficiency”.
The most efficient grid is a steady
state grid where demand and supply stay
constant and balanced. The rhythms of
life prevent that perfect state, but we are
well short of what we can do. Local dis-
tributed renewable and efficient electric
generation, coupled with intelligent and
efficient control and use can flatten ex-
isting demand curves, but it means that
Demand Response must be synonymous
with supply chain management. Huh?
If an electron is the product, then every-
thing that happens to it is supply chain
Demand Response Invades the Grid and Makes it SmartBY PHIL DAVIS, SENIOR MANAGER SMART GRID SOLUTIONS, SCHNEIDER ELECTRIC
1306pe_8 8 6/4/13 3:54 PM
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www.power-eng.com10
VIEW ON RENEWABLES
Elements ofSuccess in Tidal Energy DevelopmentBY JOHN M. FERLAND, OCEAN RENEWABLE POWER
fishermen, who helped ORPC site the
Cobscook Bay Project, resulting in a
location that met our requirements
while minimizing disturbance to
fishing activities.
ORPC has also benefitted from the
availability of local divers and com-
mercial vessel operators and crews
for support on environmental stud-
ies and Project construction, opera-
tions and maintenance. The Eastport
Port Authority was key in the Project’s
cable laying operations and has pro-
vided a range of services throughout
ORPC’s seven years working in the
area.
When ORPC initiated a marine
mammal observation program to
meet our licensing requirements,
professional fishermen, a local kayak
guide, a whale watch operator, and
others familiar with local waters re-
sponded. Following professional
training as observers, they joined our
operations team during the Project’s
initial construction phase, and will
continue to work with us as the proj-
ect build-out continues.
Local support for ORPC has helped
us create a strong economic footprint
statewide. Since 2007 we have spent
more than $21 million throughout
Maine, supported more than 100 jobs
statewide, and established a supply
chain reaching 13 of the state’s 16
counties.
The promise of economic growth
was a major reason why Maine imple-
mented the Ocean Energy Act in 2010.
The Act created regulatory reform
for small-scale tidal energy projects
and the opportunity for a long-term
In 2012 Ocean Renewable Power
Company (ORPC) began oper-
ating the first federally licensed,
commercial, grid-connected tidal en-
ergy project. Situated on the U.S. side
of the Bay of Fundy, the Cobscook
Bay Tidal Energy Project is the only
ocean energy project, except for one
involving a dam, that delivers power
to a utility grid in the Americas. The
Project benefits from having the first
long-term power purchase agreement
for tidal energy issued in the U.S., al-
lowing us to expand to up to 5 MW of
production.
As a first mover in an emerging
industry, ORPC has had to address
complexities related to technology
development, resource assessment,
project siting, marine construction,
regulatory requirements, environ-
mental monitoring and public policy.
Key to project success has been the
positive relationships ORPC has de-
veloped with host communities and
regulators. This facet of project devel-
opment is core to our company.
Through early, open and frequent
communications, ORPC developed
relationships and built trust with the
host communities of Eastport and
Lubec, Maine. Their economies and
ways of life have historically been
defined by the success of their ma-
rine industries. The local workforce
is highly skilled in marine operations
and has provided us with guidance
and expertise needed to work in lo-
cal waters. Strong relationships have
been established with the Eastport
Port Authority, local harbor pilots,
and most importantly, commercial
power purchase agreement through
the Maine Public Utilities Commis-
sion.. Additionally, Maine and the
Federal Energy Regulatory Commis-
sion (FERC) signed a Memorandum
of Understanding pledging to align
state and federal approaches to tidal
energy regulation.
ORPC has forged productive rela-
tionships with state and federal regu-
latory agencies. We recently submitted
the Project’s first annual environmen-
tal monitoring report to FERC. The
agency requires licensees to develop
adaptive management plans for evalu-
ating environmental monitoring data
and making science-based decisions
to modify monitoring as necessary.
The goal is to maintain levels of mon-
itoring proportional to project risk
through a collaborative effort with
regulatory agencies and key advisors
who comprise the adaptive manage-
ment team. Results to date indicate no
observed, adverse interaction of the
TidGen® Power System with the ma-
rine environment. We appreciate the
regulatory resource agency members
of our adaptive management team
for their guidance, and because of it,
ORPC is at the forefront of innovative
environmental monitoring efforts for
tidal energy projects.
Many challenges remain for the
tidal energy industry. Time will tell if
our experience in Maine can be repli-
cated in other jurisdictions. At a min-
imum, ORPC’s experience provides
examples of the types of community,
public policy and regulatory dynam-
ics that are necessary for a tidal energy
project to evolve successfully.
Author
John M. Ferland is
Vice President of
Project Development
for Ocean Renew-
able Power Compa-
ny, an international
industry leading
developer of tech-
nology and projects
that generate clean,
predictable power
from ocean and
river currents. He
leads the company’s
project develop-
ment, environmental
permitting and
project licensing ac-
tivities. John draws
on over 30 years of
experience in com-
mercialization strat-
egy for renewable
energy companies,
port emergency re-
sponse operations,
coastal resources
management, and
public policy.
1306pe_10 10 6/4/13 3:54 PM
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www.power-eng.com12
GAS GENERATION
POTENTIAL PRICE VOLATILITY
Although the industry has prepared for
increasing prices, there is concern about
the volatility of the pricing of natural gas.
Unlike other power generating fuels such
as coal, natural gas can be used by mul-
tiple industries for a variety of reasons.
“There are a lot of petrochemical re-
fineries and others that can use natural
gas, and you could potentially increase
demand quite a bit,” Thomas said.
As Thomas pointed it, it wasn’t long
ago that natural gas prices were in the
double-digit range, and it’s possible that
could happen again.
When companies are spending hun-
dreds of millions to build a power plant,
uncertainty is a concern, and price vola-
tility is an area being monitored.
EPA CONCERNS
The area of most uncertainty for the in-
dustry isn’t pricing, however. It’s the U.S.
Environmental Protection Agency.
Thomas said a long-term strategy with
the current uncertainty and regulatory
structure is “almost an oxymoron” be-
cause of changing regulations.
The EPA has recently revised rules,
such as the Mercury and Air Toxics Stan-
dards, or failed to finalize rules, such as
the New Source Performance Standard.
Any time a company is planning an in-
vestment that could cost up to $1 billion,
it needs as much information as possible.
With the current climate of rules chang-
ing, important information just isn’t
available right now.
ADVANTAGES
OF NATURAL GAS
Despite potential price volatility and
regulatory uncertainty, natural gas-fired
plants have many benefits. Several of the
executives noted the lower costs to build
Recently, I had the opportunity
to moderate a discussion about
natural gas-fired generation be-
tween executives from Alstom, Ameri-
can electric Power, Bechtel and Electric
Power Research Institute. The result was
a fast-paced conversation that brought up
many issues the industry is currently fac-
ing. The discussion was published in the
May issue of Power Engineering.
Here are a few key points that came out
of that discussion.
PREPARED FOR
HIGHER PRICES
Although recent increases in natural
gas prices have created media head-
lines, people in the industry have been
expecting prices to increase and are
prepared for it.
Scott Austin, manager of business
development for Bechtel’s thermal
business line, said that gas-fired power
generation would still be the fuel of
choice over the mid-term with prices
staying in the $5 to $7 MMBtu range,
with significant opportunities for new
builds in the next two years.
Pricing will affect how plants are oper-
ated, however. AEP Vice President of Gen-
erating Assets Toby Thomas said at higher
prices, natural gas-fired plants would be
cycled more often, while plants would be
more likely to run at base load constantly
when gas is in the $2 MMBtu range.
Recent reports from the U.S. Energy
Information Administration support
Thomas’ statement. As gas prices have
increased from a Henry Hub price of
$1.99 MMBtu on April 25, 2012, natural
gas-fired power generation has also de-
creased, producing around 32 percent of
the electricity in the U.S. in April last year.
That compares to 25 percent in March of
this year.
the plant – usually half of the price of a
coal-fired power plant and one-third of
a nuclear plant – and the quick dispatch
time that allows a plant to be at 50 per-
cent of its capacity in 10 minutes.
Operational costs are also lower as
fewer employees are needed at a natural
gas-fired plant and the fuel is brought
in through a transmission line and not
manually loaded.
Gas also burns cleaner than coal, and
most modern combined-cycle plants
would have met the NSPS regulation
without any additional costs.
NOT THE ONLY OPTION
Despite the advantages of gas, every
executive participating had concerns the
industry could become too reliant on it as
a fuel source for power generation.
“Gas is just an easy decision, and it re-
ally concerns me that the industry doesn’t
have the flexibility to provide more diver-
sity,” EPRI Vice President of Generation
Tom Alley said, who also noted the in-
dustry is being led toward natural gas as a
“destination” fuel source.”
Overreliance on natural gas could
strain the transmission system, causing
potential risks to grid reliability. To en-
sure reliability, companies need a diver-
sified energy portfolio – but the options
available for more diversity are currently
unclear.
Alstom Vice President – Gas Product
Platform Amy Ericson said “it’s pretty
scary out there” for the company’s cus-
tomers, who don’t know whether they
can count on nuclear license renewals
or plan for coal-fired generation with-
out carbon capture and storage tech-
nology. At the same time, she said, “the
prospect of only gas and renewable is
probably not the best choice” for the
industry or the U.S.
Natural Gas Execs DiscussIndustry Trends, ConcernsBY JUSTIN MARTINO, ASSOCIATE EDITOR
1306pe_12 12 6/4/13 3:54 PM
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www.power-eng.com14
POWER PLANT PROFILE
bringing a new coal plant online in the
late 2000s was never going to be easy. “I
would think there was always some con-
cern,” said Tim Riordan, vice president of
engineering services for AEP, “because
much of this was going to have to be de-
cided in the court system or with com-
missions or other federal agencies and of
course we don’t have control over that.”
Still, it wasn’t just a regulatory victory
when the plant finally went into service
on December 20, 2012. The event was
BY DENVER NICKS, ASSOCIATE EDITOR
Firsts are rare—by defi-
nition they come only
once—and lasts are rare
for the same reason. But
rarest of all is that which
is the first and last of its kind, like
Doctor Frankenstein’s hero-monster,
doomed to be forever alone on the
day it was born. AEP’s ultra-supercrit-
ical coal-fired Turk power plant may
prove to be one such rarity: a great
technological leap forward unlikely to
ever be repeated again in the United
States.
The Turk project was announced in
August 2006 but didn’t go online until
seven years later. AEP spent those inter-
vening years securing the necessary regu-
latory permits and fighting a battle in the
Arkansas Supreme Court. AEP ultimately
lost that battle, requiring a late-in-the-
game reconfiguration of where all the
plant’s power output would be sold, but
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also a technological victory: AEP had suc-
ceeded in bringing online the most effi-
cient coal-fired commercial power plant
ever built.
The 600 MW Turk Power Plant
is situated in Hempstead County, in the
southwestern corner of Arkansas, where
it employs 109 people on a total payroll
of $9 million and pumps $6 million in
school and county property tax revenues
every year, according to AEP. Through
its subsidiary the Southwestern Electric
AEP’s Turk is one of the most efficient, least polluting coal-fired power plants on the planet.
“This could very well be one of the last conventional coal burning facilities built in the country.” - Tim Riordan, AEP
Power Co., or SWEPCO,
which operates the facility,
AEP invested $1.3 billion
of the $1.8 billion required
to build the plant and the
company now owns 73
percent of its output. The
remaining ownership is
divided between the Arkansas Electric
Cooperative Corp.,
the East Texas Elec-
tric Cooperative,
and the Oklahoma
Municipal Power
Authority.
The at-
tribute that makes
Turk unique among power plants—that
gives cause to append the word “ultra”
to the preexisting and more familiar
“supercritical”—is that it works just like
a supercritical power plant, only better.
As an ultra-supercritical coal-fired power
plant, Turk operates at extraordinarily
high pressures and temperatures, well
above typical supercritical pressures of
around 4,500 psi and hotter than 1050
degrees Fahrenheit.
“As you increase temperature you
increase your ef-
ficiencies,” Rior-
dan explained. By
working at such a
high temperature
and pressure, Turk
achieves the high-
est efficiencies
around in coal power generation today;
according to AEP, between 39 and 40
percent of the thermal energy available
1306pe_15 15 6/4/13 3:54 PM
www.power-eng.com16
tested to withstand the pressure and tem-
perature of an ultra-supercritical power
plant. For use in the facility materials
need to have high creep rupture strength,
resistance against embrittlement, and
low oxidation growth in addition to ease
of manufacture and availability. “High
chrome, creep strength enhanced ferritic
steels (CSEF), and nickel based alloys
meet these needs,” Riordan said.
Working with both the original equip-
ment manufacturers and with EPRI (the
Electric Power Research Institute), and
other research groups, AEP worked “to
understand these components”—like
boiler headers, main steam lines, and
blade components—“for their weldabili-
ty and long term creep strength,” Riordan
said. “There was quite a bit of R&D work.”
In constructing Turk, AEP bought
the major components, like the boiler
turbine and environmental control
equipment, before its EPC agreement
like catalytic reduction systems, dry flue
gas desulfurization, baghouse technol-
ogy to combat particulate releases and
activated carbon injection to reduce Hg
emissions. The end result is one of the
most efficient, least polluting coal-fired
power plants on the planet.
Achieving super-high temperatures
and pressures wasn’t as easy as just dialing
up the heat. Special materials had to be
in the fuel comes out as electric power.
This level of efficiency in extracting en-
ergy from coal allows Turk to use less of
the stuff to produce the same amount
of power. Less coal burned means less
emissions of sulfur dioxide, nitrogen
oxide, mercury, carbon dioxide and
particulate matter. It also means fewer
waste products and less fly ash, and de-
creased need for the commodities used
in environmental control activities, like
activated carbon and ammonia. The re-
duction in pollutants is combined with
the latest emission-control technologies,
Joey White, machinist, works to move some of the Turk Plant’s emissions control equipment into place.
Drew Smith, machinist, performs maintenance on oneof the Turk Plant’s six coal pulverizers.
1306pe_16 16 6/4/13 3:54 PM
www.power-eng.com 17
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with Shaw was completed. Afterwards,
however, Shaw led construction on
everything but the boiler, in addition
to completing engineering details and
integration of the facility. The boiler,
along with the baghouse, dry scrub-
ber, and selective catalytic reduction
unit, were all provided by Babcock &
Wilcox, while Alstom provided the
main turbine and generator in addi-
tion to the feed pump turbine.
In designing and constructing Turk,
AEP included input from operating
staff to ensure the innovative facility
didn’t just make sense from an eco-
nomic and regulatory perspective, but
from an ergonomical perspective too.
Design plans gave consideration to
something as simple as making sure
that headroom was sufficient to safely
remove motors or maintain equip-
ment. “Many times with an EPC con-
tract the footprints get smaller and
smaller because of cost concerns,”
Riordan said. “We spent a lot of time
with our engineer of record, Shaw, to
make sure that we had a very safe and
maintainable facility.
“You really don’t want people stand-
ing on hand rails to operate a valve,
right?”
As to whether or not there will ever
be another American plant like Turk,
Riordan isn’t optimistic.
“I would hope so. Unfortunately
with the new environmental rules for
new generating facilities, the proposed
CO2 limits are probably going to pre-
vent that from happening in the near
term,” he said.
“This could very well be one of the
last conventional coal burning facili-
ties built in the country.”
1306pe_17 17 6/4/13 3:55 PM
www.power-eng.com18
WHAT WORKS
solution with a machine which is simi-
lar to a swimming pool pump. After
four hours of cleaning, his team checks
the condition of the tubes. “If it needs
more, then we’ll use a slightly stronger
solution and circulate it for another two
hours or so,” he said.
Conklin said the cleaning method is
very safe.
“We keep the chemical solution in
the tube bundle and circulate it from
there to our cleaning equipment,” he
said. “It’s cut off from all the other
equipment, so there’s no contamina-
tion – no safety issue.”
The formula includes corrosion in-
hibitors and is approved for use on steel,
iron, brass, copper, plastic and rubber.
Specially formulated ScaleBreak-SS is
safe for stainless steel.
Augusta Industrial Services reports
that chemical cleaning is economical.
Conklin said that’s because circulating
the chemicals is a much faster method
than standard manual cleaning.
After the first thorough cleaning,
subsequent visits often take less time.
“Next time we come out we might cut
the time in half – it could take only
two hours of descaling to clean every-
thing,” he says.
ScaleBreak does not con tain toxic
cresols or other tar oils that need
SARA Title III, Section 313 spill loss
or disposal reporting. The waste prod-
uct is mildly acidic and contains only
nontoxic salts after being used to re-
move potable water scale. It rinses eas-
ily with water and requires no special
equipment for handling.
Conklin also likes that chemical
cleaning can take less of a toll on his
crew. Mechanical cleaning and hydro-
blasting are physically taxing methods,
and fatigue can contribute to accidents.
ScaleBreak’s formulation makes it a safe
choice for service personnel, since they
don’t have to deal with caustic chemi-
cals or noxious fumes.
About two years ago, a power plant
in Georgia pulled covers to in-
spect eight of their A/C chillers
and found that they showed substantial
scale buildup on the inner surfaces of the
tubes, the outer surfaces and the tube
facings. The buildup resisted the facil-
ity’s standard mechanical cleaning pro-
cedures. The tubes’ inner diameters were
narrowed to the point where adequately
sized cleaning brushes could not be in-
serted into the tubes.
The power company asked Augusta
Industrial Services, Inc., which services
nuclear power plants throughout the
southeastern United States, to help find
a solution. Augusta Industrial Services,
based in Augusta, Georgia, visited the
plant to investigate the situation.
“The tube bundles were so bad –
fouled with scale and grit – that you
couldn’t put the correct brush in the
chiller to clean it. Therefore the regular
mechanical cleaning method was out
of the question,” explains Augusta’s
supervisor Shawn Conklin.
Often power plants will allow the
chiller tubes to be cleaned by hydro
blasting, but that method was not an
option in this situation. “The number
one concern is safety, and with the pos-
sibility of puncturing a tube by hydro
blasting, the plant’s engineers would
not allow us to use high pressure water
on these chillers,” said Conklin.
The power company asked Augusta
Industrial Services to find a chemical
cleaning solution for clearing out the
tubes. Two of Augusta’s on site supervi-
sors (Shawn Conklin and Taylor Smoot)
conducted its research. After consider-
ing the alternatives and discussing them
with the plant’s engineers, they received
approval to call Goodway Technologies
Corp. to request a sample of the chemi-
cal ScaleBreak for testing. All involved
parties liked that the independent studies
showed that ScaleBreak dissolves calcium
deposits, rust, lime and lithium carbon-
ate on contact without damaging the
equipment being serviced.
Augusta Industrial Services test-clean-
ing consisted of several chunks of the
deposit, that was scrapped off of the tube
face, being placed into a beaker and then
adding a capful of the ScaleBreak at a
time until the pieces started to.
As the test-cleaning satisfied the en-
gineering staff, the Augusta supervisors
were given the approval to proceed with
an initial order of ScaleBreak and the
cleaning of one unit.
“Actually, the first time we cleaned it
we mixed it wrong – we were told the unit
capacity was 400 gallons, but it was re-
ally 700 gallons, so our mixture was too
weak. Even so, it was already starting to
remove some scale,” said Conklin. “So we
had more ScaleBreak shipped to us over-
night. We got the calculations right, circu-
lated it for four hours, drained it, rinsed it,
and we just couldn’t believe how clean it
was – we were really surprised.” Conklin’s
crew ordered more ScaleBreak and took
care of the other seven chillers without
any difficulties.
Conklin explains how the process
works. “We calculate the tube bundle’s
volume – anywhere between 150 gal-
lons to 1,000 gallons – then we calcu-
late how much ScaleBreak versus wa-
ter to use. Right now we like to use a
60-40 mixture – 60 percent ScaleBreak
and 40 percent water. That works out
really well for us.” Conklin continues.
Conklin said they circulate the
Dealing with Scale BuildupBY SANDI HAGUE, HAGUEDIRECT LLC
1306pe_18 18 6/4/13 3:55 PM
348 Circuit Street
Hanover, MA 02339
T (781)829-6501
www.sturtevantinc.com
Make Pollution Control Affordable with Sturtevant’s® FGT.
• Reduces Sorbent Usage by 30%
• Dependable Sorbent Milling
The Simpactor® FGT has the highest capacity and produces the fi nest cuts with a PSD range of d50 15µM and lower.
The Simpactor® FGT addresses all concerns of milling dry sorbents: dependability, maintenance, power consumption and capital cost.
Added benefi ts:
• Coolest milling process to keep sorbents below 120º F
• Least internal mill build up of sorbent
• Lowest wear rate of internal mill impact parts and drive system
• Best suited for 24/7 adverse climate operation
• Easy to operate: Adjust grind while in operation
For 130 years, Sturtevant has been recognized internationally as a premier manufacturer of custom size reduction and air classifi cation equipment to the powder processing industry.
Please visit Sturtevant’s website for more information
on the Simpactor® pin mill.
For info. http://powereng.hotims.com RS# 10
1306pe_19 19 6/4/13 3:55 PM
www.power-eng.com20
1306pe_20 20 6/4/13 4:02 PM
www.power-eng.com 21
risk of prematurely converting a plant
to natural gas and facing the unafford-
able cost to convert back if the price
and availability of natural gas becomes
uneconomical. These choices have sig-
nificant impact on the plant’s opera-
tional costs and the economy.
An alternative to avoid these issues is
to use Dry sorbent injection (DSI). Dry
sorbent injection is a pollution con-
trol technology that plays a role in the
U.S. power sector’s compliance with
the Mercury and Air Toxics Standard
(MATS). The Environmental Protec-
tion Agency (EPA) finalized the MATS
rule in December 2011. The MATS rule
requires that all U.S. coal- and oil-fired
power plants greater than 25 mega-
watts meet emission limits consistent
with the average performance of the
top 12 percent of existing units, known
as the maximum achievable control
Extending the Life of COAL FIRED PLANTS
BY STEVE COULOMBE, PRODUCT MANAGER FOR DSI MILLS AT STURTEVANT
Operators of coal fired
power plants have a
lot to worry about
today: The price of
coal relative to natu-
ral gas, stack emissions, EPA regula-
tions and the unpredictable nature of
future potential regulations. With an
uncertain future, one question hangs
in the balance: is it economical to
maintain a coal fired power plant and
reduce its stack emissions?
This tough question is driving trends
towards plant upgrades, early plant re-
tirement and conversion to natural gas
as solutions to control pollution. Pro-
ducers of coal fired power are experi-
encing two hidden costs to early plant
retirement or conversion which are
important to understand. The first is
the unpredictability of the future cost
of natural gas and the second is the
The Sturtevant DSI pin mill reduces sorbent to a fine
particle size, which is used to lower emissions of sulfur
dioxide, sulfur trioxide and hydrogen chloride. Photo
courtesy of Sturtevant
Dry SorbentInjection
through the use of
1306pe_21 21 6/4/13 4:02 PM
www.power-eng.com22
For info. http://powereng.hotims.com RS# 11For info. http://powereng.hotims.com RS# 12
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THE BEST WAY IS
• Dissolve calcium, lime, rust, lithium carbonate and more
• Increases system efficiency • Safe for use on steel, iron, brass,
copper, plastic and rubber• Special formulation available for
use on stainless steel• Use on power plant surface
condensers, boilers, chillers, heat exchangers, and more
Goodway ScaleBreak® removes tough scale build-up quickly, safely and easily.
DE-SCALEWITHOUT FAIL.
(SO2) or sulfur trioxide (SO3) emis-
sions through the same process as HCl
removal. While the MATS rule does not
specifically address SO2 or SO3, it has
similar qualities to HCl and other acid
gases that enable it to respond simi-
larly in a DSI system. SO2 and SO3 are
also regulated under the Cross State
Air Pollution Rule (CSAPR). There-
fore, installing a DSI system to comply
with MATS will also help plants meet
or even exceed their CSAPR emission
limits.
THE APPLICATION OF
A MILL IN PROCESSING
SORBENTS FOR DSI
Dry Sorbent Injection, is part of
a Flue Gas Desulfurization system
(FGD), capable of SO2 and SO3
mitigation, as well as HCl, and mer-
cury removal depending on sorbent
technology (MACT). The rule applies
to three pollutants: mercury (Hg), hy-
drochloric acid (HCl), and filterable
particulate matter (fPM) and has a
compliance deadline in 2015 (with op-
portunities for additional compliance
time depending upon case-by-case
circumstances). While DSI systems do
not control mercury, they can, when
combined with a particulate control
filter, meet this standard for two of the
three controlled pollutants.
DSI systems remove hydrogen chlo-
ride (HCl) and other acid gases like
SO2 and SO3, through two basic steps.
Step one. A powdered alka-
line sorbent is injected into the flue
gas (combustion exhaust gas exiting
a power plant) where it reacts with
the HCl and SOx. The sorbents most
commonly associated with DSI are
trona (sodium sesquicarbonate, a
naturally occurring mineral mined in
Wyoming), sodium bicarbonate, and
hydrated lime.
Step two. The compound
formed by the alkaline sorbent and the
acidic gas is removed by a downstream
particulate matter control device such
as an electrostatic precipitator (ESP) or
a fabric filter (FF), also referred to as
a bag house. Testing has demonstrated
that fabric filters are more effective
(when combined with DSI) than ESPs,
with respect to overall HCl and SOx
reduction. For modeling purposes,
the EPA estimates a DSI system with a
fabric filter is expected to achieve 90%
removal of HCl, while an ESP only
achieves 60 percent removal, although
actual performance will vary by indi-
vidual plant.
As mentioned, DSI systems can also
significantly reduce sulfur dioxide
1306pe_22 22 6/4/13 4:02 PM
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Designed to meet today’s boiler cleaning needs by responding to changing
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1306pe_23 23 6/4/13 4:02 PM
www.power-eng.com24
and state regulations, considering a
DSI and mill can bring a plant quickly
into a safe condition to comply cost
effectively while still keeping all
options open to future alternative fuel
choices. Operators have found that
relieving the pressure of making an
early conversion decision, potentially
pre-maturely, will save significant
money and jobs for plant facilities
due to less closures while meeting
the future energy demands of the
community.
DSI with mill systems can be
pre-tested by engineering firms
specializing in DSI installations and
has proven its effectiveness over the
last 10 years throughout the U.S.A.
Milled DSI systems have been
installed for over twelve years and
maintain constant operation. These
mills are specially designed to meet
both the rigors of DSI and the needs
of the power generation community.
It is important to understand that
general, commercially available mills,
are designed for many applications.
These applications do not necessarily
reflect the needs of power generators.
The typical system installed for DSI
selections. DSI treatment for mercury
removal is similar to other forms of
FGD but uses either powder activated
carbon reactant or Amended Silicates,
a patented process for mercury remov-
al. Formed particulate is then captured
in the same way that other DSI systems
capture their reacted compounds as
described above. When investigating
the use of a DSI system the first con-
sideration is typically the cost to oper-
ate the system. A DSI system has a far
less cost to operate and install than a
wet scrubber system
for power plants, in-
dustrial boilers, in-
cinerators or co-fired
plants that are only
partially converting
to natural gas fired,
or undecided to con-
vert, or may want to
fire oil or coal for 5 or
more years. Research has shown that
the capital and installation costs to op-
erate a DSI system are only 10 percent
on average, compared to that of a wet
scrubber system.
SOx is mitigated most effectively
by alkaline type sorbents like Trona
and Sodium Bicarbonate (SBC),
although hydrated lime or limestone,
if locally obtained, can be a viable
solution. SBC must be milled (ground
finer), and Trona should be milled
for maximum effect. The purposed of
milling is both to reduce the amount
of sorbent consumed by the system
and increase the sorbent surface area
which increases the availability of a
reactive particle surface. As SO3 is
eliminated, blue plumes from sulfuric
acid disappear, boilers run more
efficient, system
corrosion is lowered
and mercury can be
removed more easily.
A variety of sorbents
can be blended,
as supplied to the
on-site mill before
DSI, or milled and
injected separately if
optimum injection points need to be
considered. SO2 removal to levels of
95 percent can help control acid rain
and is also a good reason to consider a
DSI system with milling.
With the advent of the MATS and the
ongoing EPA rule changes, litigation
Research has shown that the capital and installation costs to operate a DSI system are only 10% on average.
The Ghent Generating Station is a coal-fired power plant owned and operated by Kentucky Utilities near
Carrollton, Ky. Dry sorbent injection systems were installed to comply with new federal emission standards.
A Trona mill system led to a 30 percent decrease in sorbent usage. Photo courtesy of Sturtevant
1306pe_24 24 6/4/13 4:02 PM
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1306pe_25 25 6/4/13 4:02 PM
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will be installed in an out-building
with no temperature control and must
be operated 24/7 with minimum down
time or cleaning time. Manufacturers
have designed unique features to these
mills to make them suitable for DSI.
Some typical features include rotating
round pin sections to minimize the
wear caused by milling naturally
occurring minerals which have abrasive
properties, special metal coatings which
also minimize wear and pre-heating
and cooling systems for plants operating
in ambient temperatures below 40F or
above 90F. An important consideration
in DSI systems is designing for use of
these specific-duty pin mills. .
The benefit of using a pin mill is in its
ability to offer the smallest particle sizes
to increase the reactive surface area and
help the plant consume less sorbent. A
pin mill for DSI operates by blowing
sorbent into the top of the mill using
a pneumatic conveying system. The
sorbent then enters the mill where one
rotor with a set of pins rotates between
a second, stationary rotor. The sorbent
works itself through pressure and force
from the inside of the rotor to the outside
of the rotor where the action of the pins
reduces the particle size. Fine particles
exit the outer edge of the rotor where
they are then blown into the process
to be added to back to the DSI system
for injection. This simple process is the
heart of DSI systems as it is responsible
for controlling the effectiveness of the
removal of gasses from the system.
Particle size reduction has a key role
in FGD and understanding the part
sorbent milling plays in trona systems
is the best example.
A typical example of DSI is the use of
milled trona. Supplier-delivered trona
with a particle distribution where 50
percent of the particle size is 30μm or less
(referred to as d50) has an average per-
particle surface area of about 2,800μm2.
The advantage of operating a DSI system
is by reducing ongoing operating costs.
This is where the pin mill plays its key
role. A pin mill is capable of reducing
the d50 from 30μm to 7μm which, in
a single particle, is the equivalent of
reducing a dust particle to the size of a
red blood cell. This reduction in size
has an exponential impact on particle
surface area by volume, increasing the
reactive surface area from about 4,000in2
to 20,000in2 for equivalent mass.
When considering the future of coal-
and oil-fired power, alternatives to
conversion and early retirement exist.
DSI is affordable, compliant and easy to
operate and should be considered when
planning the future of any plant.
1306pe_26 26 6/4/13 4:02 PM
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1306pe_27 27 6/4/13 4:02 PM
www.power-eng.com28
Nearly 50 years ago,
Norm Harty, presi-
dent of N.B. Harty
General Contrac-
tors Inc., was a
driller and dynamite blaster for road
and railway construction when Ken-
neth Bridegroom, a supervisor at a
power plant where Harty was subcon-
tracting, asked if dynamite could be
used to clean the inside of a boiler.
“Back then I was hungry,” Harty
BY JUSTIN MARTINO, ASSOCIATE EDITOR
said. “I was really, really searching for
anything.”
Although Harty had never seen the
inside of a power plant before, he told
Bridegroom he could do the job. Af-
ter a labor strike and a buildup of slag
prompted the plant to contact Harty,
he used dynamite to remove a slag de-
posit, inventing the process as he went
along.
“I didn’t really realize exactly what
I had done, but Bridegroom did,” he
If slag is allowed to build up inside a boiler, it can lead not
only to efficiency problems but can also cause damage
because of the weight. Photo courtesy of Norm Harty.
said. “The rest is history. The next
thing I knew I was going all over the
east doing this, and it was all by word
of mouth.”
Harty used his technique for 17
years before he had any competitors
attempting to use the same process.
Using dynamite is still an option for
power plants, and Harty’s company
cleans nearly 100 boilers a year.
Other operators are looking at differ-
ent methods that have been developed
1306pe_28 28 6/4/13 4:02 PM
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RELOADED
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For info. http://powereng.hotims.com RS# 17
1306pe_29 29 6/4/13 4:02 PM
www.power-eng.com30
because less fuel is needed to produce
the same amount of power, according
to Tim Martin, Director of Product
Management for Clyde Bergemann
Power Group Americas Inc., Boiler Ef-
ficiency Division.
FUEL SWITCHES LEADING
TO SLAG DEPOSITS
Slag deposits can be caused by mul-
tiple sources. Harty said older boilers,
especially in the eastern U.S., were
much smaller because the plants were
burning high-sulfur eastern coal with
a high Btu output. Less fuel was need-
ed to produce the required heat, and
the boilers did not produce as much
ash.
The high-sulfur coal released more
maintenance, Harty said.
Dirty boiler tubes can also affect
the operation of a plant. Slag buildup
on tubes will act as an insulation pro-
tecting the tube from the heat of the
boiler, requiring more fuel to reach
the same temperature and produce the
same output as a clean boiler. Harty
said cleaning the slag deposits inside
a boiler can increase boiler efficiency
from 1 percent to 4 percent.
“Even 2 to 3 percent in a boiler that
generates 600 MW, that’s hundreds
of thousands of dollars each day or
week,” he said. “They’re still burning
the coal, but the coal fire doesn’t get to
the tube.”
Clean boilers can also help reduce
the emissions produced by the plant
to clean boiler tubes without taking
the plant offline, including improving
the soot blowers located in the boiler.
Whichever methods is chosen, howev-
er, the importance of keeping a clean
boiler is not in question.
THE IMPORTANCE OF
BOILER TUBE CLEANING
Power plants burning anything
other than natural gas will, over time,
build up ash that forms slag deposits
on the exterior of the tubes running
through the boiler. The slag can be a
safety hazard – the tubes expand and
contract as they heat up and cool down
and the deposits may break off and
fall, a problem that arises most nota-
bly when a plant is taken offline for
Norm Harty has been using explosives to clean boilers for
nearly 50 years, which helps increase boiler efficiency and
heat transfer. Photo courtesy of Norm Harty.
1306pe_30 30 6/4/13 4:03 PM
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1306pe_31 31 6/4/13 4:03 PM
www.power-eng.com32
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cleaning the boilers have changed.
Although coal plants previous ran at
full load as much as
possible, the drop
in price of natural
gas has caused many
owners to cycle the
plants more so that
they’re not always
running at full load.
“It’s been a huge
change in the way
the coal plants are operated,” Booher
said. “Not only is natural gas at record
lows, which causes coal plants to be
dispatched lower, but there’s also ex-
tensive renewables online now. So in a
place like Texas, where many large coal
plants are designed to run full load,
these are now up and down on load.”
Harty said that bringing the boiler
pollutants into the air, so plants be-
gan using western coal, such as Pow-
der River Basin coal, in their fuel mix.
Western coals create more ash and
produces less Btus, requiring more fuel
for the same temperature. Plants that
burn lignite, often located along the
Missouri River, require even more fuel.
Those boilers might be twice as large as
a Midwest plant built to burn western
coal and three or four times as large as
plants built to burn eastern coal, many
of which are being decommissioned
right now, Harty said.
Fuel switches can create a problem
in a plant. If more ash is produced than
the plant’s current system can handle,
the slag buildup can become uncon-
trollable over time. This can happen
when units are burning Powder River
Basin coals or other coals that have
low melting points for the ash or sig-
nificant sodium levels, which makes
the ash more tena-
cious in areas such as
the convection pass,
said Joel Booher, a
business manager for
Diamond Power.
“Unless the fur-
nace box is very
large, what you’ll see
is the boiler eventu-
ally can’t take it anymore, and you’ll
have uncontrollable slag formation,”
Booher said. “That was what we were
fighting against.”
CHANGES IN THE WAY
COAL PLANTS ARE USED
As power plants operators use coal
plants differently, the methods of
“The boiler eventually can’t take it anymore, and you’ll have uncontrollable slag formation.”- Joel Booher
1306pe_32 32 6/4/13 4:03 PM
www.power-eng.comFor info. http://powereng.hotims.com RS# 20
said. “Once slag becomes a problem,
their cleaning devices aren’t strong
enough or in the proper location to re-
move it.”
If buildup reaches a point the on-
line cleaning products installed by the
plant are unable to remove the slag,
the plant must be taken offline for
cleaning. Offline cleaning may involve
water jets, compressed air or dynamite.
USING DYNAMITE TO
CLEAN BOILER TUBES
Harty said that older methods be-
ing used for offline cleaning when
he first started cleaning boilers were
“very crude” and could involve using
shotguns to fire slugs at tubes to knock
off slag or using a large iron ball sus-
pended on a chain or chisels and ham-
mers to strike the tubes to remove any
build up.
“It was one massive thing to do, and
it was very dangerous,” he said. “They
had a lot of people get hurt.”
Modern methods of offline boiler
tube cleaning have made many im-
provements over older methods, and
Harty said using dynamite as a meth-
od of offline cleaning has multiple ad-
vantages over other methods, such as
high-pressure water, with one of those
being that no moisture is introduced
into the boiler.
“The water and moisture will go
down into the ash tanks and set like
concrete because that slag is in such a
fine state,” he said. “They buy that right
now to put in concrete and strengthen
the concrete. If you dry clean it with
explosives, you don’t have any mois-
ture and the slag will fall into the hop-
per and down into the grinder and out
the sluice area.”
Harty also said he can reduce down-
time for plants that have to be taken
offline for cleaning. Whereas using
high pressure water requires setting
up pipes and hoses, dynamite can be
down and back up can create some
efficiency for the plant by partially re-
moving the slag through cycling. Boil-
er tubes will expand up to 18 inches
from top to bottom when hot, and the
expansion and contraction of the tube-
can knock off slag.
Jeff Kite, principal engineer for boil-
er performance at Diamond Power,
said boilers in plants that are being
cycled more often don’t have to be
cleaned as often, but the boilers were
not designed to be cycled so it makes it
difficult on operations in general.
“Supercritical units do not easily
accommodate being asked to go from
full load to half load on a regular ba-
sis,” Booher added. “They’re designed
to be run at stable high loads, and it’s
hard on the metal throughout the boil-
er to be cycled up and down.”
CURRENT
CLEANING SYSTEMS
Most power plants have some sort of
soot blower system that works to clean
the plant when the boiler is online
and producing power, Martin said.
Soot blower systems have been around
since at least the 1930s, he said, adding
that he has seen photographs of soot
blowers that were operated by a chain
raised and lowered by a hand-operated
crank.
Soot blowers and other online
cleaning systems use compressed air,
steam or water to keep slag buildup
from occurring without the necessity
of taking the plant offline. As compa-
nies look for solutions that allow the
plant to keep operating, newer soot
blowing systems may allow a plant to
keep its boilers clean without requir-
ing a planned maintenance where the
boiler is taken offline, although older
systems may require a shutdown for
cleaning.
“Some of the online cleaning prod-
ucts might be 20 years old,” Martin
1306pe_33 33 6/4/13 4:03 PM
34
In order to clean a tube using explo-
sives, Harty said his company will use
primer cord around tubs that are close
together to avoid damage. The cord has
connectors that will delay the charges.
Without using the connectors, he said
the process could destroy the wall or
insulation of the boiler.
Sticks of dynamite can be used
used quickly and with less equipment.
He added that his company recently
cleaned a boiler in Nevada in less than
36 hours.
“Downtime is money,” he said.
“Downtime is loss of revenue. That’s
why they want you in and want you
out.”
Using dynamite to clean slag is
popular in western coal plants because
of the need to conserve water, he said.
“Water is really scarce out west, and
this is another reason explosives are
being used predominately in the west-
ern plants,” he said. “They can’t afford
to waste a drop of water, and by using
dynamite they’re able to save their wa-
ter and clean their boiler.”
Although soot cleaning systems may be used to
clean a boiler without taking it offline, a plant with
older online systems may require a shutdown.
Photo courtesy of Norm Harty.
1306pe_34 34 6/4/13 4:03 PM
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after hitting the hot boiler tube, could
create more steam than the boiler
could handle and even cause a change
in the power produced by the boiler.
“Many units have induced draft fans
that really run on the ragged edge, and
they can’t handle that extra gas volume
going through there,” Booher said.
“Oftentimes these high-flow cleaning
devices can cause disturbances of the
unit.”
Modern systems can use retractable
soot blowers, such as Diamond’s Pow-
er HydroJet™ water cleaning systems,
allowing less water to be used since
less force can be used over the shorter
distance. Systems using retractable
soot blowers can create a 60 or 70 per-
cent water use reduction and provide
as much or better cleaning effective-
ness, Kite said.
The systems can also interpret where
the boiler is developing a buildup of
slag, which can help operators avoid
attempting to clean sections of tube
that are already clean. If water or steam
hits a clean section of a boiler tube, it
can cause tube erosion over time. Cold
water hitting a hot tube can also cause
the tube to contract, leading to tube
damage and a possible blow out.
“Water cleaning can damage tubes if
done improperly,” Kite said. “If an op-
erator has this wonderful tool that can
clean his boiler, he has a habit of us-
ing it too much if he doesn’t have input
coming back to him letting him know
what’s going on.”
make a sequence and run the devices
in order, operators were unable to get
any sort of feedback without a visual
inspection of the boiler.
“Realistically, it wasn’t until the ‘90s
that we started implementing heat
transfer sensors, which are devices
made out of sections of boiler tubing
placed within the cleaning radius of
the water lances that provide feedback
of heat transfer and can be used to de-
termine how clean or dirty that section
is,” Kite said.
Older soot blower systems might
also utilize an “across-the-boiler” sys-
tem, where a nozzle will need to spray
water across a 60-foot space in order
to reach the place that needed to be
cleaned. That system might use 200
gallons of water per minute, which,
in more open places where there is a
heavy amount of slag. Harty said he
has seen slag reach 60 to 70 feet deep
in some boilers. At one point, his com-
pany cleaned 150 truckloads of slag
from a boiler, though he called that
“an extreme case.”
IMPROVEMENTS
IN ONLINE BOILER
CLEANING
Many companies would prefer to not
take their plants offline for cleaning,
and both Diamond Power and Clyde
Bergemann have developed online
cleaning solutions that are improve-
ments over the previous soot blowers.
Previous soot blowers had “sim-
plistic controls,” Kite said. Although
the operator of the system was able to
Modern systems use a variety of solutions to create “intelligent soot blowing,” which can help prevent outages and damage to the boiler.- Jeff Kite, Diamond Power
1306pe_36 36 6/4/13 4:03 PM
www.power-eng.com 37
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devices installed in the system and
that device’s ability to impact the goals
set by the plant operator. Ultimately,
the system will allow an operator to
clean tubes only when and where they
need cleaning.
“The idea would be to use it as
little as possible because it can cause
damage to the unit,” Booher said.
“If the system can automatically
determine where to clean and which
blowers make the biggest effect, then
in the end you can end up blowing
less soot blowers to maintain the same
general boiler cleanliness.”
VARIABLE PRESSURE
BLOWERS
Clyde Bergemann has also intro-
duced a variation in intelligent soot
be difficult for the operations staff to
understand in order to make the right
decisions,” he said. “Goal-based ISB
uses intelligent soot blowing to achieve
the goals the operators already want to
achieve – keeping steam temperature
in the right range or keeping their gas
temperatures in the right range. It’s
simpler and quicker to commission.”
Although gas temperature may
be a common goal for many boiler
operators, Booher said different
operators may have a different goal
that is important to them. Diamond
Power will work with the plant
engineering staff to configure the ISB
system, and if a goal can be quantified,
it can be incorporated into the system.
Once the system is in place, it will
analyze data from individual cleaning
Modern systems use a variety of
solutions to provide “intelligent soot
blowing,” which can help prevent out-
ages and damage to the boiler.
GOAL-BASED INTELLIGENT
SOOT BLOWING
Intelligent soot blowing, or ISB, uses
automatic control systems to analyze
the cleaning needs of the boiler.
Introduced in the ‘90s, it is becoming
the standard for boilers, Booher
said, with many new boilers using
an ISB system. Improvements can
still be made on previous generation
of intelligent soot blowing systems,
however.
“What is coming to light is that
these systems can be complicated in
their calculations, and so they can
1306pe_37 37 6/4/13 4:03 PM
www.power-eng.com38
to remove one pound of iron oxide. The
same amount of iron oxide can be re-
moved by 2.5 pounds of citric acid or
1.58 pounds of hydrochloric acid.
“When you look at costs, I can clean
a 30,000 gallon boiler for around
$50,000 to $60,000,” he said. “Clean-
ing that same boiler with EDTA will
cost you over $100,000.”
Bodman said his company will run
solubility tests with hydrocholic acid,
citric acid and EDTA and allow the
company to choose the method used.
Once the cleaning starts, he said it
takes approximately 2 to 3.5 days. De-
pending on the boiler and water treat-
ment, some boilers require cleaning
every two years, while other boilers,
like ones used in paper mills, may be
cleaned every five to seven years.
A VARIETY OF OPTIONS
Although boiler tube cleaning is a
very important part of the industry,
choosing the right method for a boiler
is up to the operator. Modern advances
in the industry, however, can make the
process simpler and safer than it used
to be, however.
“Soot blowing has really changed
over the years, going from a product
that you just install and turn on into
really getting more into the engineering
aspect and studying how it affects the
boiler performance,” Martin said.
Whether an operator chooses to
install a new online system or use
an offline system, each boiler may
have different problems and require
a unique solution to reach maximum
efficiency. For Harty, who went from
blasting passes for roadways to using
dynamite to clean multi-million dollar
pieces equipment almost 50 years
ago and has seen cleaning systems
continue to evolve during that time,
finding solutions to unique problems
is a familiar concept.
“In a power plant, you have to be
flexible and innovative,” he said.
INTERIOR TUBE CLEANING
Although cleaning slag from the in-
side of the boiler and exterior of the
boiler tubes is a key aspect of keeping
a boiler efficient, cleaning any depos-
its that may form on the interior of the
tubes is also important.
If deposits from impurities in the
water form on the interior of a tube, it
can create an insulation problem, ac-
cording to George Bodman of George
H. Bodman Inc.
“if you put a tenth of an inch of scale
in there, your temperature will go from
600 degrees farenheit to probably 700
to 750 degrees farenheit,” he said. “If
that tube gets to 809 degrees farenheit,
the tube is going to blow out.”
Scaling can also reduce the efficien-
cy of the boiler by requiring more heat,
and corrosion can form under the scale
that will create a hole in the tube itself.
The process of removing the scale is
individualized for each tube, Bodman
said, and the preplanning for the clean-
ing should start at least six months in
advance by getting a tube sample of
the boiler. The sample can be used to
determine the deposit weight density
as well as the scale matrix.
Bodman said he also talks to the
water treatment representatives to find
out what has previously been done and
why the deposit has formed. The next
step after that is to speak with plant
personnel and the plant chemist or rel-
ibility engineer to set up a program on
how to remove the deposit.
Around 90 percent of boilers are are
currently chemically cleaned, Bodman
said, although some can be cleaned
with high-pressure water.
Plant operators can choose to use a
variety of chemicals, including hydro-
chloric acid, ethalene diamene tetra-
cedic acid (EDTA) and hydroxyacetic-
formic acid.
EDTA is more expensive, but also has
less environmental impact, Bodman
said. It requires 13.6 pounds of EDTA
blowing that uses variable pressure
when cleaning boiler tubes. Martin
said the goal of the system is to provide
just enough pressure to clean the tube
to avoid creating any damage.
“We could go in with a very, very
high pressure, and we know that
whatever is on the tube is going to
be cleaned, but there’s a downside to
that, and that’s tube erosion,” he said.
“What the SMART Clean™ does is look
at cleaning with the proper intensity.
We clean with just enough intensity to
clean the ash off the tube, but not too
much intensity to cause tube erosion.”
The system is designed to create
maximum efficiency for the plant.
By keeping slag from building up on
the tubes, the plant is able to operate
with maximum heat transfer, and by
avoiding erosion, the operator can
prevent future tube leaks that can shut
down the boiler in a forced outage.
Martin said the system can save
money for a plant operator by
completely eliminating planned
outages to clean the tubes. He said
the company has clients with boilers
that were going offline every three
months who eliminated the problem
by installing the SMART Clean™
system. Those boilers only come down
for typical maintenance issues now, he
said.
He added the system is not a large
investment for a boiler operator, and
the investment will be returned within
six months to a year, with the owner of
the boiler receiving the benefits of not
requiring outages for the next 20 years.
Each job requires a different
approach, and not all of the SMART
Clean™ products may not be necessary.
“We use a lot of different techniques,”
Martin said. “Some are more advanced
than others. Really, every boiler is
unique. We look at it from a fresh
perspective and look at their specific
needs, and then we can propose the
right technology to meet those needs.”
1306pe_38 38 6/4/13 4:03 PM
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www.power-eng.com40
Gas Turbine Startup Diagram 1
Spee
d, L
oad
(%)
120
100
80
60
40
20
0
Minutes
0 10 20 30 40 50 60
0 – Start Command1 – LCI engages2 – HRSG Purge Start 4 – Ignition Speed5 – GT Fire + Warmup6 – Full Speed No Load (FSNL)7 – Synchronization8 – Full Speed Full Load (FSFL)
Start Command to FSFL: 40 minutes
18 minutes (Fast Start)
Conventional
Fast
Speed
Load
Purg
e C
redi
t + L
CI P
reco
nnec
t + “
Fire
on
the
Fly”
Fast
Loa
ding
(2
0+
% p
er m
inut
e)
Nor
mal
Loa
ding
(~
8% p
er m
inut
e)
Nor
mal
Loa
ding
(~
8% p
er m
inut
e)
GT Load Hold for ST Temp. Matching(Conventional Start)
Typical gas turbine startup diagram (conventional and fast versions). Conventional start with GT hold can take up to 50 minutes to reach MECL. Purge credit shaves off 12 minutes of that time. Eliminating GT hold saves another 15+ minutes. With fast start feature MECL point is passed in less than 10 minutes.
C
6
2
5
54
7
7
3
0 0
1
1
8
8
8 86
F
Alas, modern gas turbine based com-
bined cycle (GTCC) systems comprise
steel behemoths weighing tens of
thousands of pounds and operate at
extremely high pressures and tempera-
tures while connected to each other via
a maze of pipes and valves. This com-
plex architecture presents formidable
challenges to designers and operators
alike to handle major operational
transients with large flow, pressure
and temperature (FPT) gradients with-
out adverse impact on reliability, avail-
ability and maintainability (RAM).
This is primarily achieved by advanced
control schemes incorporating model
based controls (MBC), design features
such as terminal attemperators and
cascaded steam bypass as well as mate-
rial selection. As a result, in terms of
dynamic response to transient events,
the difference between a modern
GTCC and its forerunners is as pro-
nounced as that between cars with car-
bureted vis-à-vis fuel-injected engines.
The goal of this article is to provide
the reader with relevant and easy-to-
use technical information (in the form
Nowadays all major
gas turbine OEMs
promote their
products with an
emphasis on “flex-
ibility” in addition to output and effi-
ciency. The most advertised flexibility
feature is the fast start capability of
advanced F, G or H class machines in
simple and combined cycle modes.
Gas Turbine Combined Cycle Fast Start:
The PHYSICSBehind the Concept BY S. C. GÜLEN, BECHTEL, PRINCIPAL ENGINEER
1306pe_40 40 6/4/13 4:03 PM
www.power-eng.com 41
Steam Turbine Cool-Down Profles 2
ST M
etal
Tem
pera
ture
(˚F
)
1,200
1,000
800
600
400
200
0
Time Since Shutdown, hours
0 50 100 150 200
HOT WARM COLDHOT WARM COLD
HP Inner Bowl
IP Inner Bowl
�c = 100-150 hrs. (HP)
�c = 50-75 hrs. (IP)
Typical steam turbine cool-down profles (as measured at HP and IP inner bowls). Shaded regions indicate typical time windows for “hot”, “warm” and “cold” start classifcations. Red dashed lines indicate average metal HP bowl temperature corresponding to the same.
�C
or load up-down ramps) and associ-
ated thermal stress-strain loop.
In principle, the solution is simple
enough: thermal decoupling of GT and
ST start processes. Thus, GT is started
and rolled to full speed at no load
(FSNL) at the maximum rate dictated
by the size of static starter (Load Com-
mutating Inverter, LCI), shaft torque
limit, particular Dry Low NOx (DLN)
combustion system limits (e.g., avail-
ability of heated fuel gas, minimum
fuel requirement by the lean blow-out
margin, Wobbe index variation, etc.)
among others. Following synchroni-
zation, GT is loaded as fast as possible
first to its minimum emissions-com-
pliant load (MECL) and then to its full
load at full speed (FSFL).
GTCC start time definition hinges
on when to start the chronometer. Un-
less specified unambiguously, one can
never be sure when time t = 0 is and
the difference can be significant. For
a conventional start with HRSG purge
and normal loading rate (i.e., no holds
anything” in the process - literally. The
failure mode to avoid is crack initia-
tion and propagation. Failure to con-
trol thermal stresses results in cracks
via low/high cycle fatigue (LCF and
HCF) and brittle fracture. In fact, LCF
is found to account for roughly two
thirds of ST rotor life with the remain-
der attributable mainly to creep. In
particular, thick-walled components
such as HP drum, ST valves, casings
and rotor are exposed to LCF due to
thermal cycling (start-stop sequence
of simple charts, basic equations and
representative physical quantities) to
form an informed opinion on avail-
able technologies and their purported
capabilities and benefits along with
potential pitfalls and physical limits.
The focus is on GTCC startup, which
can be considered as a primus inter pares
among all GTCC transients. Admitted-
ly, an article limited to a few thousand
words cannot do justice to the subject
matter at hand. The reader is encour-
aged to consult the listed references for
a thorough understanding and guid-
ance for applying the basic principles
to his/her own projects.
There are many considerations in a
successful GTCC start from standstill,
which are discussed in detail else-
where [1-3]. Correct steam chemistry,
establishment of steam seals, vibra-
tion, overspeed and thrust controls are
all vital for acceptable component life
and RAM. When all said and done,
however, the single most important
issue from a fast start perspective is
steam turbine (ST) thermal stress
management. Furthermore, if the heat
recovery steam generator (HRSG) is
drum-type, high pressure (HP) drum
thermal stress management becomes
an integral part of the problem.
In a nutshell, GTCC startup optimi-
zation problem can be formulated as
to minimize the time required to reach
the dispatch power (e.g., full load or a
specific part load) without “breaking
Modulus of Elasticity E 26,000 ksi
Linear Coefficientof Thermal Expansion
α 6-7 x 10-6 1/R
Poisson's Ratio ν 0.30
Thermal Conductivity k 18.0 Btu/h-ft-F
Density ρ 490 lb/cuft
Heat Capacity c 0.125-0.175 Btu/lb-R
Thermal Diffusivity δ 0.20-0.25 ft2/h
Defnition of key material parameters and their typical values 1
Source:
1306pe_41 41 6/4/13 4:03 PM
www.power-eng.com42
S-N and CLE Curves 3
Typical S-N and CLE curves for ST rotor LCF (CrMoV) [5]. Metal �T in CLE chart represents the total temperature change between initial and fnal states (beyond 600°F, curves are fat).
Tota
l Str
ain
Ra
ng
e
1.000
0.100
0.010
0.001
10 100 1,000 10,000 100,000
S-N Curve CLE Curve
Cycles to Failure
0 100 200 300 400 500 600
10.0
8.3
6.7
5.0
3.3
1.7
0.0
σ�max = 44,54, 87 ksi
for K� = 2.0, 1.5 and 1.0
σ�max = 44,54, 87 ksi
for K� = 2.0, 1.5 and 1.0
5,000 Cycles5,000 Cycles
Increasing��, �
Increasing��, �
ΔT/
Δt,
˚F/m
in.
Metal Temp. �, ˚F
0.100
0.050
0.0200.010
0.001
0.100
0.050
0.0200.010
0.001
1
5,000 = 0.02%
1
5,000 = 0.02%
Steam Turbine Roll Times 4
Steam turbine roll times for varying steam fows and temperatures. (Steam pressure 120 psia,rotational inertia 700 kp-ft2, rated IP turbine inlet fow 681.5 kpph.)
Steam T = 700˚F
800˚ F
900˚F
Stem Flow, % of Rated
ST
Ro
ll Ti
me, m
inu
tes
18
16
14
12
10
8
6
4
2
0
0% 5% 10% 15% 20% 25% 30%
Steam T = 700˚F
800˚ F
900˚ F
low load with reduced exhaust en-
ergy (flow and temperature) to con-
trol HRSG steam production rate and
steam temperatures (at the HP drum
and HP superheater exit). Elimination
of direct HRSG steam temperature
control via GT load and exhaust ener-
gy is the “thermal decoupling”, which
is the key enabler of fast start. It can be
the rule is sequential combustion (reheat)
GTs, which can turn off their second
combustors to operate at 20% or lower
load while emissions-compliant.
Two steps are instrumental in reduc-
ing GT start time: elimination of (i)
HRSG purge sequence (by performing
it right after shutdown in compliance
with NFPA® 85) and (ii) hold time at
for HRSG warming) the difference be-
tween start command and ignition is
20 minutes (see Figure 1). Thus, the
same start time (40 minutes to be ex-
act) can be quoted as 20 minutes by
someone who sets t = 0 at ignition.
Today’s fast start GTs with features like
“purge credit”, LCI pre-connect and
“fire on the fly” can reach FSFL in 18
minutes or less from the start com-
mand (depending on the loading rate).
The rush to MECL is critical for re-
duction of startup emissions. The
reason for that lies in the basic design
philosophy of modern DLN combus-
tors with fuel-air premixing, which are
designed to run near the lean limit for
low emissions. This is accomplished
by piloted, multi-nozzle fuel injectors
via sequential activation of fuel flow
through individual nozzles (known as
staging) to prevent lean blow-out and
combustion dynamics while staying
within the narrow equivalence ratio
band to control NOx and CO emis-
sions. For older units MECL is 60%;
for modern units the low load limit
is around 50% (maybe 40% for most
advanced systems). The exception to
1306pe_42 42 6/5/13 10:38 AM
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1306pe_43 43 6/4/13 4:03 PM
www.power-eng.com44
Steam Turbine Roll 5
center
Tem
pera
tur,
˚F
1,000
800
700
200
100
Time, minutes
70 80 90 120
100
80
70
60
40
20
10
Spee
d, F
low
& S
tress
, %
Typical ST roll via IP steam admission and the ensuing warm-up period [6]. Representative of a single-shaft GTCC cold start (total three hours). Note how the quasi-stationary Phase II is preceded by a short non-stationary period.
Rotor
Temperature
Phase I Phase II
Non-stationary start to Phase II
Steam Temperature
� = 30 min.
� =
78
min
.
� = 235 min.
Steam Flow
Max
. �
Bulk
Surfa
ce
ST S
peed
T
r
Surface Stress
steamsurface
mean
to start maintenance as soon as pos-
sible to minimize the downtime). The
natural cooling time depicted in Figure
2 is represented by the exponential de-
cay law
Eq. 1
with a characteristic cooling time con-
stant, τc, as a function of the ambient
temperature, Tamb
, and the starting
value (denoted by subscript 0). This
temperature is the main GTCC startup
classification gauge instead of widely
used but fuzzy terms such as “hot” or
“warm”, whose definitions vary from
one source to another.
Component Tm
and, more precisely,
its variation in a metal structure across
a characteristic dimension, Lc, (e.g., di-
ameter of ST rotor – 20-25 in. for mod-
ern GTCC units) along a characteristic
dimension, x, is the key determinant
of thermal stress via the following for-
mula:
Eq. 2
where E’ = E / (1-ν). For the ST rotor,
ΔTm
in Eq. 2 is the difference between
rotor surface or bore and mean body
(bulk) temperatures for surface and
bore stresses, respectively. For a given
steam temperature, Tstm
, bulk rotor
body Tm
varies according to the expo-
nential decay law
accomplished via a bypass stack and
modulated damper controlling the
exhaust flow to the HRSG. A recently
proposed technique is “air attempera-
tion” of the GT exhaust gas flow via
air injection into the transition duct.
Ignoring the obvious but wasteful
practice of “sky venting”, the currently
accepted method is a “cascaded” steam
bypass system with terminal attem-
perators (TA). Steam generation and
temperature-pressure ramp rates in HP
drum are dictated by GT exhaust en-
ergy whereas final steam temperature
control is accomplished by TAs. Until
steam temperatures reach acceptable
levels for admission into the ST, steam
is bypassed via a route including the
reheat superheater so that the latter is
pressurized and “wet” (i.e., cooled by
steam flow obviating the need for ex-
pensive alloys).
Steam FPT acceptable for admission
into the ST is dictated by metal tem-
peratures (primarily valves, casings or
shells and the rotor). The critical com-
ponent is the rotor, whose temperature
cannot be measured directly and in-
ferred by proxies (e.g., HP and IP inner
bowl). ST metal temperature, Tm
, is a
direct function of unit downtime and
ambient temperature as shown in Fig-
ure 2 (unless forced cooling is applied
Source:
m/mo
P T h Bi δ τ
[-] psia F Btu/h-ft2-F [-] ft2/h min
1.0 120 700 116 7 0.26 37
1.0 120 1,050 100 6 0.21 54
1.0 1,200 700 958 56 5
1.0 1,200 1,050 701 41 8
0.2 120 700 32 2 135
0.2 120 1,050 28 2 196
0.2 1,200 700 264 15 16
0.2 1,200 1,050 193 11 28
Representative values of major parameters characterizing the transient heat transfer during steam turbine warm-up for typical steam fow, pressure and temperatures.
2
1306pe_44 44 6/4/13 4:03 PM
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Determination of HTC is one of the
most uncertainty-prone undertakings
in transient heat transfer problem in a
complex geometry such as steam path
flow. Its dependence on steam flow is
based on the well-known Nusselt num-
ber correlation for heat transfer in in-
ternal flows, i.e., h ∝ . The heat
transferred from steam to the rotor at
the surface increases the rotor’s bulk
temperature according to Fourier’s law
Eq. 6
Equation 6 introduces the thermal
diffusivity, δ = k/ρc, which quantifies
the speed with which the temperature
of a heated or cooled body changes.
Typical values for the key parameters
governing ST rotor thermal transients
are given in Table 2.
For ferritic steels used in modern
GTCC units, k and ρ do not show sig-
nificant variation. Thus, δ is primarily
a function of temperature and chang-
es by about 25% between 700 and
1,050°F; i.e., rate of change of metal
temperature is 25% faster at the higher
temperature. The data in Table 2 can
be summarized as follows: higher
steam flow and/or pressure result in
higher rates of heat transfer between
steam and metal, which is quantified
by higher Biot numbers and shorter
time constants (i.e., faster heating
or cooling). In conjunction with the
data in Table 2, Eqs. 5 and 6 identify
the two distinct phases in ST start with
thermal stress control:
(i) low flow and high steam-metal
ΔT with low HTC until tempera-
ture gradients settle down (non-
stationary phase or Phase I) and
(ii) increasing steam FPT to load the
unit with high HTC and nearly
constant, low steam-metal ΔT
(quasi-stationary phase or Phase II).
Equation 5 describes Phase I via its
simplified solution for a cylindrical ge-
ometry given by [4]
Eq. 7
which gives the maximum thermal
stress implied by a given step rise in
Tstm
at time t = 0 (with a time lag char-
acterized by the Biot number). Note
that the base stress formula of Eq. 2 is
amplified by a stress concentration factor
KT, which accounts for the presence of
geometric discontinuities on the rotor
Eq. 3
with a characteristic time constant, τ,
which is a function of rotor material
(e.g., 1% CrMoV) and size cum geom-
etry represented by Lc,
Eq. 4
where h is the convective heat trans-
fer coefficient (HTC) between steam
and metal. Equations 1-4 tell the en-
tire ST thermal stress management
story in the concise language of math-
ematics. Thermal stress is determined
by the temperature gradient in the ro-
tor (essentially a cylinder) via Eq. 2;
the latter is determined by the initial
steam-metal ΔT (denominator of LHS
of Eq. 3) with a time lag, which itself is
dictated by HTC in Eq. 4. Everything
hinges on the initial value of Tm
, Tm,0
,
which is a function of the cooling pe-
riod (Eq. 1).
In physical terms, this translates
into a mechanism to control steam FPT
into the steam turbine at initial values
sufficient (i) to roll the unit from turn-
ing gear (TG) speed to FSNL, (ii) to
warm the ST rotor until steam-metal
ΔT decreases to an acceptable level
and (iii) to ramp them up at acceptable
rates to their rated levels while ensur-
ing that thermal stresses do not exceed
prescribed limits.
Steam flow enters the picture via
HTC in Eq. 4, which controls the rate
of heat transfer between steam and the
rotor surface as described by the heat
flux balance at the steam-metal bound-
ary (x = 0)
Eq. 5
This equation introduces the di-
mensionless Biot number, Bi = h·Lc/k,
which is a relative measure of the
uniformity of temperature gradi-
ents inside a heated or cooled body.
Dynamic Response of Selected HRSG
Heat Exchanger Sections6
Representative of a single-shaft GTCC cold start (total time of about three hours).
TEM
PERA
TURE
TIME
Warm-Up Hold
HP Sphtr.
GT
Exha
ust
HP Drum IP/LP Sphtrs.
IP Drum
LP Drum
Increasing �
2 min.
7.5 min.
12.5 min.15 min.
20 min.10-1
5 ˚F
/min
.
(< ~
50
psi/m
in.)
1306pe_46 46 6/4/13 4:03 PM
www.power-eng.com
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(which is not a perfect cylinder after all). Similarly, Eq. 6
describes Phase II via its simplified form given by
Eq. 8
where ϕF is the form factor (0.125 for a cylinder [4]). Equa-
tion 8 gives the allowable Tstm
ramp rate for a given maxi-
mum allowable stress, σmax
, which is dependent on rotor ma-
terial and typically lies in a range of 50-80 ksi. For the cited
range, with the data in Table 2, Eq. 7 suggests that for low
HTC (~100 Btu/h-ft2-F or less) steam-metal ΔT can range
from 200-300°F (high KT) to 500°F and higher (low K
T).
For high HTC (~650 Btu/h-ft2-F), steam-metal ΔT can range
from 100-200°F (high KT) to about 400°F (low K
T). Simi-
larly, using Eq. 8 with Table 2, it can be seen that allowable
values for dTstm
/dt range from 3-6°F to 8-10°F.
The allowable stress is not a precisely defined material
property. (For ferritic steels used in ST rotor construction,
0.2% tensile yield strength lies between 70-90 ksi for tem-
peratures 600-1,000°F.) It is derived from the S-N curves re-
lating total strain to cycles to failure, which gives the fatigue
life of the material in question (for LCF life of CrMoV alloy
see Figure 3). Based on the relationship between stress and
strain, ε, via the modulus of elasticity, σ = E´ • ε, this curve is
used to determine σmax
for a defined fatigue life. In practice,
the relationship between σ and ΔT allows the translation
of the S-N curve into Cyclic Life Ependiture (CLE) curves,
which determine the allowable Tstm
ramp rates (Figure 3).
Depending on the rotor material, size and geometry and its
temperature at start initiation, the range is limited to about
5 to 10°F per minute except for very hot “restarts” after a
few hours of downtime.
Steam turbines with cascaded steam bypass are typically
started by admitting steam from the reheat superheater into
the IP section. Admission steam FPT should be sufficient
to overcome the rotational inertia (in lb-ft2) of the entire
ST and its generator, Irot
, and accelerate it from TG speed (a
few rpm) to FSNL (3,000 or 3,600 rpm). Based on avail-
able steam FPT and initial IP rotor temperature, using the
relationship between ST power generation (expansion from
IP inlet to the condenser), rotor torque and rate of change
in angular speed, ω, the roll time can be estimated as 2 to
15 minutes (see Figure 4) via
Eq. 9
where N is the rotor speed (rpm) and the argument of
the integral on the RHS of Eq. 9 is the power (in Btu/s) gen-
erated by steam expanding between IP turbine inlet and
condenser [6].
1306pe_47 47 6/4/13 4:03 PM
www.power-eng.com48
Startup Time 7
ST Only
Startup time of a typical steam turbine in a modern GTCC with drum-type HRSG (from the start of ST roll to the point when all bypass valves are closed and all admission valves are fully open).
Star
t Tim
e, m
inut
es
250
200
150
100
50
0
Initial ST Metal Temperature, ˚F
0 200 400 600 800 1,000
Downtime, hours
� 166 97 58 27 5
rpm
/min
, ˚F/
min
16
14
12
10
8
6
4
2
0
Steam Temperature Ramp Rate
Shaft Acceleration Rate
GT Hold For HRSG
Warm
up
The chart in Figure 5 shows the
first two hours of ST roll, warm-up
and loading phases for an initial Tm
of
180°F (about 5-6 days of downtime per
Figure 2). Steam is admitted into the IP
turbine at 715°F and 120 psia at a flow
rate of 10% of its rated value at full
load. This is sufficient for acceleration
from TG to synchronization in 8 min-
utes (see Figure 4). Initial steam-metal
ΔT is 500+°F but this is acceptable due
to the low HTC (less than 30 Btu/h-
ft2-F per Table 2) and the ensuing low
σmax
from Eq. 7 (also very high τ > 200
minutes). Following synchronization,
IP steam flow is ramped steadily to
40% to accelerate the warm-up process
via increased HTC. Once the steam-
metal ΔT (based on rotor surface tem-
perature inferred via IP inner bowl
thermocouple) reaches about 250°F,
Tstm
is ramped (via TA control) at a rate
defined by the CLE curve (about 3 to
4°F per minute for an acceptable life of
4 to 5,000 cycles from Figure 3).
The other component subject to LCF
damage due to cycling is the cylindri-
cal HP drum of the HRSG (4-5 inches
wall thickness). The limiting thermal
stress is at the inner drum wall con-
trolled by saturated steam p-T inside
the drum. During startup, mechani-
cal stress due to internal drum pres-
sure and thermal stress due to thermal
expansion are in opposite directions,
while they are in the same direction
during shutdown. Unlike the ST,
which is thermally decoupled from the
GT via TAs, HRSG sections are directly
“under fire”. They respond to GT ex-
haust temperature transients much
faster than the ST rotor in direct pro-
portion to their distance from the inlet
(see Figure 6). Thermal stress calcula-
tions and material properties similar
to those described above limit the p-T
ramp rate inside the drum to 10-15 °F/
min (about 50 psi/min max.) for units
designed up to ~1,800 psig at ST throt-
tle (~6-10% higher at the HP drum).
Advanced steam cycles with 2,400
psig throttle and drum-type HRSGs
(very thick walls) would push down
the ramp rate to a few degrees per
minute (see Eq. 8 for the relationship
between dTstm
/dt and Lc). This can be
alleviated to a certain degree by using
stronger alloy steel (obviously more
expensive) and/or designing the HRSG
per EN-12952 rather than the ASME
code, which results in thinner walls.
One obvious solution is once-through
design of the HP evaporator, which
eliminates the thick-walled drum al-
together but has its own drawbacks
and caveats. A recent design approach
proposes to replace the HP drum by a
cylindrical, thin-walled knock-out ves-
sel with external separator bottles and
thus avoid the thermal stress problem
in cold starts. According to HRSG
OEMs, cold starts (Tdrum
< ~400°F) are
20 times more damaging than warm
starts (Tdrum
< ~500°F) whereas hot
starts (Tdrum
> 500°F) do not impact
LCF life. In “hot” starts, HP and reheat
superheaters subjected to very steep
gas temperature ramps are critical in
terms of HRSG life consumption. In
this context, one should add that the
desirability of purge credit is due to
more than startup time reduction. It
prevents excessive quenching of super-
heaters, which act as “supercoolers”
during hot starts when subjected to
relatively cold GT exhaust with detri-
mental impact on their fatigue life.
Natural p-T decay of the HP drum
can be described by Eq. 1 with τc of 60
to 80 hours. It takes about 2-3 days
for the pressure to decay to the atmo-
spheric conditions. Bottling up the
HRSG via stack dampers with insula-
tion up to the damper, steam sparging
(requires auxiliary boiler) or running
the SCR ammonia vaporizer heaters
help keep the HRSG warm and pressur-
ized over limited duration shutdowns
1306pe_48 48 6/4/13 4:03 PM
www.power-eng.com 49
THE WORLD’S FIRST IMPACT & TORQUE GUN
PUSH the shifter handle forward, engage the 4,000 rpm
high speed impact at low noise and vibration for a quick,
corrosion-overcoming pre-torque or run-up.
PULL the shifter handle back, engage the continuous
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destructible side load.
PATENTS RECEIVED & PENDING
TORQUEGUN.COM
2013PR
OD
UCT OF THE YEAR
the
company
torque guntm
TM
TM
to enable GT starts with no low-load
hold. Beyond about three days, how-
ever, this is increasingly impractical
and even in plants designed for fast
starts limited duration GT holds are
needed to accomplish HP drum warm-
up in two steps (somewhat similar to
that shown in Figure 6).
Combining the elements discussed
above and illustrated by the ST roll
example in Figure 5, a representative
ST start curve can be established as a
function of the key controlling param-
eter, namely, ST metal temperature at
the startup initiation (Figure 7). Ap-
propriate GT start time per Figure 1
(from start command to the point
when ST roll begins) should be added
to that for total GTCC start time (e.g.,
18 minutes for the fast start). The four-
minute mile of fast start capability is
roughly 30 minutes from a standstill
(to be defined precisely) to combined
cycle full load for a "hot" start (e.g., fol-
lowing an overnight shutdown). This
is generally compared to a conven-
tional hot start, which takes around
one hour (see Figure 1). The under-
lying physics discussed herein briefly
and summarized in Figure 7 hopefully
makes it clear that this particular case
is only one single point in a continuum
of start scenarios driven mainly by the
downtime preceding the pushing of
the start button.
References
1. Chrusciel, A., Zachary, J., Keith, S., 2001,
“Challenges in the Design of High Load
Cycling Operation for Combined Cycle
Power Plants,” POWER-GEN International
2001, Las Vegas, NV.
2. Akhtar, Z., 2006,”Design Features for
Minimizing Start-Up Time in Combined
Cycle Plants,” POWER-GEN Europe 2006,
Köln, Germany.
3. Ugolini, D.J., Bauerschmidt, J.R., 2006,
“Optimization of Start-Up Times for Com-
bined Cycle Power Plants,” Electric Power
Conference 2006, Atlanta, GA.
4. VGB PowerTech Guideline, 1990, “Ther-
mal Behaviour of Steam Turbines, Re-
vised 2nd Ed.,” VGB-R105e, VGB Pow-
erTech Service GmbH, Essen, Germany.
5. Viswanathan, R., 1989, “Damage Mecha-
nisms and Life Assessment of High-Tem-
perature Components,” ASM Internation-
al, Metals Park, OH, USA.
6. Gülen, S.C., Kim, K., 2013, “Gas Turbine
Combined Cycle Dynamic Simulation:
A Physics Based Simple Approach,”
GT2013-94584, ASME Turbo Expo, June
3-7, 2013, San Antonio, TX, USA.
1306pe_49 49 6/4/13 4:03 PM
www.power-eng.com50
Source: www.aircleancompany.com
#ESP Process Schematic
Dirty Air Clean Air
Ground Plate
Ground Plate
ParticleParticle Charged
Particle
Charged
Particle Sp
aci
ng
Sp
aci
ng
Sp
aci
ng
Sp
aci
ng
IonizerIonizer High voltage PlateHigh voltage Plate
Zoneof
Charging
Zoneof
Charging
Upgrading Electrostatic PrecipitatorsBY BRYANT PURSE, RAYMOND ZBACNIK, MITCHELL KRASNOPOLER, KIEWIT POWER ENGINEERS
ESPs. This article will address some of
the general principles of dry electro-
static precipitators and discuss modern
methods for upgrading ESPs.
BASICS OF ELECTROSTATIC
PRECIPITATORS
ESPs can be designed for high volu-
metric gas flow rates, variable tem-
peratures and pressures, and variable
particulate loading. Precipitators have
been placed in a number of locations
at different power plants, including
downstream of the economizer (hot
side), downstream of the air preheat-
er (cold side), or after a wet scrubber
(which requires a wet ESP). This article
will focus on dry ESPs and will high-
light typical upgrade options. With a
properly designed electrostatic precipi-
tator, 99% collection efficiency is pos-
sible with medium and high ash coals.
History and Principles of ESPs
The first electrostatic precipitator
was developed by a physical chemis-
try professor, Dr. Frederick Cottrell, in
1906. He was awarded a patent for his
design on August 11, 1908. Dr. Cot-
trell successfully demonstrated in his
research the precipitation of particu-
lates from an air stream via particle
charging in an electric field. The prin-
ciples in this early design still apply
today. Transformer-rectifiers energize
discharge electrodes with a negative
potential, producing an electrical field
between the discharge electrodes and
the positively-grounded collecting
plates.
Particulate matter that enters the
electrical field develops a negative
charge and migrates away from the
discharge electrodes and towards the
collecting plates. When the particu-
lates reach the collection plates, the
negative charge is neutralized and a
cake-like layer of ash accumulates. Mi-
gration and collection of the charged
particles depends upon the particu-
late resistivity and the electrical field
between the two electrodes, as well
as the gas flow profile. Particulate
matter that precipitates on the collec-
tion plates is periodically removed by
Electrostatic precipitators
(ESPs) have been used for
over 100 years to remove
entrained solid particu-
lates or fine mists from
gas flows in the power, cement, metal
production, paper, and other indus-
tries. As a response to ever changing
state and federal regulations for coal-
fired utility power plants, existing
ESPs or new air quality control sys-
tems are needed to meet lower emis-
sion limits. Since many of these ESPs
have been in operation for 30 to 50
years, many are in need of upgrades to
improve performance and reliability.
Even if a new pulse jet fabric filter will
be installed downstream of an ESP, an
ESP upgrade may be economical be-
cause the enhanced ESP could reduce
maintenance costs and preserve fly ash
sales. Many of the modern ESP designs
and controls can be installed in old
Authors
Bryant Purse is an AQCS Process En-gineer for Kiewit Power Engineers of Lenexa, Kansas. He develops perfor-mance testing procedures, equipment specifications, process calculations, and supports field performance testing, proposals, and client presentations.
Ray Zbacnik is an AQCS Process Spe-cialist for Kiewit Power Engineers of Lenexa, Kansas. Zbacnik has almost 40 years of chemical engineering experi-ence, which includes 20 years of AQCS experience in the power industry.
Mitchell Krasnopoler serves Kiewit Pow-er Engineers of Lenexa as the Manager of Air Quality. He has almost 25 years of engineering experience in air pollution control technologies; extensive experi-ence in flue gas desulfurization (FGD) design, operations and testing expertise and over 30 years of design experience for various fossil and nuclear power gen-eration projects.
1306pe_50 50 6/4/13 4:03 PM
www.power-eng.com 51
A complicating factor
with the MATS regula-
tions is that they impose
stricter limits on acid gas
and mercury emissions.
The regulations call for an
HCl emission limit of 0.002
lb/MMBtu and a mercury
emission limit of 1.2 lb/
TBtu. At many plants, tech-
niques to meet these new
limits include activated car-
bon injection (ACI) for mer-
cury removal and perhaps
dry sorbent injection (DSI)
or acid gas control. Plant
personnel must ensure that
the existing ESP can handle the addi-
tional particulate loading.
Changes in particulate loading from
ACI or DSI treatment are not the only
issue. Ash resistivity (the ability of the
ash to accept and transfer an electri-
cal charge) changes with the addition
of carbon or scrubber particulates.
Also, resistivity may be altered due to
changes in such operating conditions
as temperature, moisture, and chemi-
cal composition.
Sodium Ion Depletion:
Another issue that can drive ESP up-
grades is sodium ion depletion. This
phenomenon influences hot side ESP
performance with PRB as the fuel. The
nature of the PRB ash (low sodium,
low chloride, high ash), increases ash
resistivity and has forced some power
plants to de-rate the unit periodically
and shut it down for collection plate
washing. Mechanical rapping is sim-
ply not sufficient. Sodium depletion
occurs when positively-charged sodi-
um ions migrate towards the negative
charge of the ionizing electrodes and
form a sodium-rich layer in the col-
lected ash. This outer layer dislodges
by rapping, but the inner ash layer,
depleted of sodium ions, has different
characteristics making it much more
difficult to remove because of the re-
sistivity increase. The layer continues
to build, reducing the ability to apply
power to the field. Because sodium
depletion alters the chemical proper-
ties of the ash, an ESP upgrade may
not completely solve the problem, but
an upgrade may combat the decrease
in performance.
UPGRADE TECHNOLOGIES
Due to the above-mentioned fac-
tors and stricter environmental regu-
lations, many existing ESPs will have
to either be upgraded or converted to
fabric filter devices, aka baghouses. A
potential option at some plants may
even be a polishing fabric filter in-
stalled downstream of the existing
ESP. The configuration will be heav-
ily dependent upon the plant’s current
process conditions and the desired
outlet emissions. The most common
methods of improving an electrostatic
precipitator are:
• Upgrading the collection elec-
trodes
• Upgrading the discharge elec-
trodes
• Upgrading the rapping system
• Upgrading the transformer-rectifi-
er assemblies
• Improving the flow distribution
Other methods such as adjusting
the aspect ratio (the ratio of the ESP’s
effective height to the ESP’s effective
length) or fly ash/flue gas condition-
ing (altering the chemical/physical
characteristics of the fly ash) are less
common. Neither of these methods
will be discussed in this article.
Upgrading the Collection Elec-
trodes
Collection electrodes (CEs) typically
are of a plate design for dry ESPs. Tu-
bulare collection electrodes have been
utilized, but these are primarily for
wet ESP applications. In most cases,
mechanical rapping. The fly ash falls
to collection hoppers from which it is
then disposed.
REASONS FOR
ESP UPGRADES
A number of factors influence ESP
upgrades including performance deg-
radation, increased maintenance, poor
reliability, changes in particulate re-
sistivity, sodium ion depletion (pri-
marily for hot-side ESPs), volumetric
flow rate changes, increased inlet par-
ticulate loading (typically due to dry
sorbent injection), stricter emission
regulations and compliance protocols,
and even normal wear and tear such as
plate warping and leaks in the casing.
An ESP upgrade will improve perfor-
mance and reliability, which will re-
duce the plant’s operating costs in the
long run.
MATS Regulations
One of the primary drivers for ESP
upgrades is the EPA’s new Mercury and
Air Toxics Standards (MATS) regula-
tions. The MATS ruling established a
filterable particulate emission limit
of 0.03 lb/MMBtu based on EPA Test
Method 5.
An example of a rigid discharge electrode. Photo
courtesy of www.environmentawareness.com
1306pe_51 51 6/4/13 4:03 PM
www.power-eng.comFor info. http://powereng.hotims.com RS# 28
collection plates include stiffeners that act as baffles to
prevent particle re-entrainment. Properly designed collec-
tion plates eliminate excessive rapping and ensure equal
distribution of the rapping force throughout the plate.
Collection electrode design should be correlated with
the discharge electrode (DE) design. For ESPs with weight-
ed wire discharge electrodes, typical plate spacing is 6 to
12 inches. Many modern ESPs have rigid frame or plate
discharge electrodes, and in these designs the typical plate
spacing is 12 to 16 inches.
A common practice for upgrading an ESP is the altera-
tion of the plate spacing to increase the efficiency of the
unit. New collecting plates will restore DE-to-CE spac-
ing and alignment. New CEs may also improve rapping
efficiency by decreasing rapping density and allowing
increased rapping acceleration. Wider spacing along with
new power supplies will increase the voltage and power
input to the electric fields.
Upgrading the Discharge Electrodes
Discharge electrodes receive negative, high voltage,
direct current and generate the field that charges the en-
trained dust particles. A simple increase of applied volt-
age is not necessarily a good solution because of the threat
of spark-over between the discharge and collection elec-
trodes. Spark-over causes a short-term breakdown of the
electric field. It is important to design an ESP where spark-
ing does not occur too frequently. For well-designed ESPs,
sparking usually occurs between 50 and 100 times per
minute.
The discharge electrode should be designed to optimize
the induced electrical field, and should be customized
for the individual process. In the past, the weighted wire
design for the discharge electrode was common, but me-
chanical fatigue has caused operating problems. Although
most ESP vendors prefer the tube and pin electrode design,
other common rigid discharge electrodes should also be
considered, such as rigid masts and rigid frame electrodes.
Selection of modern discharge electrodes, per the cor-
rect requirements for the application, can greatly improve
ESP performance.
Upgrading the Rapping System
Rapping is the process by which a mechanically-induced
force is applied to the collections plates to dislodge the col-
lected ash.
For maximum efficiency, it is important to allow some
buildup of dust particles and not rap the plates too fre-
quently.
Plates are typically rapped once the dust layer reaches
a thickness range of 0.03 to 0.50 inches. Rapping in this
1306pe_52 52 6/4/13 4:03 PM
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range prevents re-entrainment of ash.
One method to increase rapper efficiency is improve-
ment of the rapper controls, in part by setting proper rap-
ping frequencies.
The inlet collection plates need to be rapped more fre-
quently than those in the outlet fields. Also, rapping dis-
charge electrodes at a proper frequency to prevent dust
accumulation on these instruments is important. Fine-
tuning of existing rappers and controls may avoid the is-
sue, and cost, of installing new rappers.
Increasing the number of rappers will improve the rap-
ping system by enhancing the rapping energy. Modifica-
tion of rapper placement or by dedicating existing or new
rappers to fewer plates increases rapper density. Such op-
tions for an existing system should be evaluated before in-
vesting in completely new rappers.
Upgrading the Transformer-Rectifier Assemblies
A critical component of a precipitator is the high-voltage
equipment, consisting of a step-up transformer, a high-
voltage rectifier, and control metering and protection cir-
cuitry. The system must be designed to ensure adequate
power to the discharge electrodes without causing exces-
sive sparking.
Depending upon the required operating conditions of
the ESP, an upgrade can be as simple as modernizing the
T-R set.
However, before increasing the power to the unit, the
electrode design and plate spacing may be modified in-
stead. The most common upgrade utilizes a three-phase,
high frequency switch mode power supplies (SMPS), with
control system adjustment to prevent excessive spark-over.
This upgrade efficiently delivers power to the ESP, maxi-
mizes the average voltage of the ESP, and reduces the fre-
quency of sparking.
However, utilizing a switch mode power supply may not
be feasible for every application.
Improving the Flow Distribution
Maldistribution of flue gas flow can lead to degraded
performance of the ESP.
Variable flue gas flow changes the particle distribution
throughout the unit. Thus, some areas of the ESP may be
exposed to a greater gas flow and particulate loading that
exceeds local collection capabilities.
Flow distribution devices can be installed to normalize
the flows to all ESP chambers. Normalizing the flow will
prevent sneakage of untreated gas around the collecting
fields.
Physical and Computational Fluid Dynamic (CFD) model-
ing are tools for analyzing an ESP flue gas profile. The meth-
ods can help identify what devices are needed to optimize
1306pe_53 53 6/4/13 4:03 PM
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be evaluated and studied.
This evaluation requires the follow-
ing:
• Understand boiler feed coal chem-
istry
• Study the physical and chemical
properties of the fly ash
• Evaluate the origi-
nal process design
conditions and cur-
rent operating con-
ditions
• Review the flue
gas profile/flow dis-
tribution
• Examine the ex-
isting ESP casing and internals for
corrosion
• Examine the structural integrity
of the ESP foundation
• Inspect ESP casing and compo-
nents for wear
• Evaluate the control systems
• Consider site layout/configuration
limitations
• Evaluate the ESP electrical system
and electrical characteristics of
the ESP.
References
“Steam, Its Generation and Use,” Chapter
33, “Particulate Control,” Babcock & Wil-
cox Company, Edition 41, Barberton, Ohio,
2005.
US Patent No. 895,729; “Art of Separating
Suspended Particles from Gaseous Bodies,”
Application Filed 9 July 1907. Awarded 11
August 1908.
http://www.google.com/pat-
ents/US895729
US EPA Technology Transfer Network,
“Particulate Matter Controls,” Section 6.
http://www.epa.gov/ttn/catc/
dir1/cs6ch3.pdf
the flue gas flow into, through, and out
of the precipitator.
CONCLUSION
As previously discussed, ESP up-
grades involve many different meth-
ods that can be optimized in part or
in whole. Emissions
testing provides the
ultimate indicator
that the performance
of the ESP may have
declined or that the
unit will not perform
to meet new regula-
tions.
However, the cause of performance
degradation may not always be clear.
Simply replacing one component
may not increase ESP efficiency. Due
to the complicated nature of precipita-
tor upgrades, the existing ESP should
One method to increase rapper efficiency is improvement of the rapper controls.- Kiewit Power Engineers
1306pe_54 54 6/4/13 4:03 PM
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must comply by Oct. 19, 2013.
The EPA estimates that over 900,000
CI engines and over 335,000 SI engines
will be affected.
This includes engines located in
both major and area sources of air tox-
ics emissions.
The compliance requirements vary
and are based on engine size, use of
engine, type of engine and source.
Although the regulation affects an esti-
mated 900,000 existing compression ig-
nited or diesel engines, almost 90 percent
of these engines will only be required to
meet best maintenance practices. How-
ever, a significant number of diesel and
dual-fuel engines will require the addi-
tion of emissions control catalyst to meet
the HAPs limits required by the RICE NE-
SHAP regulation.
Since the EPA has chosen carbon
monoxide (CO) as a surrogate for
the principal hazardous air pollutant
formaldehyde, this article focuses on
a project to reduce CO emissions from
diesel and dual-fuel engines.
In order to comply with the latest RICE
NESHAP Standards, the equipment in-
stallation requirements for nonemergen-
cy diesel and dual-fuel engines greater
than 500 horsepower typically include
the following:
• Catalyst housing with an oxidiza-
tion catalyst
• CPMS (continuous parametric
monitoring system)
• Crankcase ventilation system
• Use of ultra-low-sulfur-diesel
(ULSD) fuel
• Engine hour meter
• Limitations on engine start-up time
• Performance tests to demonstrate
engine emission compliance
Operators of stationary engines af-
fected by RICE NESHAP who are not in
compliance by the deadline dates can be
fined on a daily basis.
A one-year compliance extension can
be requested, but the request must be
made at least 120 days before the compli-
ance due dates.
BACKGROUND:
NRG APPLICATION
NRG Energy, a leading power gen-
eration company, operates a 12 MW
peaking plant near Harrisburg, Penn.
and needed to reduce the CO emis-
sions in order to comply with the RICE
NESHAP regulation.
In February 2010, the U. S. En-
vironmental Protection Agency
(EPA) issued a new national
emission standard for hazard-
ous air pollutants (HAPs) that
affected existing stationary diesel, dual-
fuel and gas engines.
This regulation, known as Reciprocat-
ing Internal Combustion Engine Nation-
al Emission Standard for Hazardous Air
Pollutants (RICE NESHAP) was finalized
in January 2013, but the original compli-
ance dates have not changed. Diesel and
dual-fuel compression ignition (CI) en-
gines must comply by May 3, 2013 and
natural gas spark ignited (SI) engines
Engineering Design for RICE NESHAP ComplianceBY STEPHEN R. NEWCOMB, P.E., RPA ENGINEERING; MARC ROST, JOHNSON MATTHEY STATIONARY EMISSIONS CONTROL LLC; RAY KULPA, SOLBERG MANUFACTURING; AND BARD RUPP, NRG ENERGY
NRG Energy RICE NESHAP installation at Harrisburg, Penn., showing catalyst housing (left) and crankcase ventilation system (right).
1306pe_56 56 6/4/13 4:04 PM
www.power-eng.com 57
SCOPE REQUIREMENTS
FOR NRG ENERGY
PAXTON PLANT
Oxidation catalyst
The oxidation catalyst systems in-
stalled at NRG were furnished by John-
son Matthey Stationary Emissions Con-
trol LLC and designed to meet the RICE
NESHAP emissions limit for CO emis-
sions. For CI engines larger than 500 HP
at either area sources or major sources,
this limit is either an absolute emission
limit of 23 ppmvd CO at 15 percent O2 or
a 70 percent reduction of CO emissions.
The catalyst that was used for each
engine was a combination of Platinum
Group Metals (PGM) on a stainless steel
metal monolith. The monolith was sup-
plied in block-sized modules, and these
blocks were inserted in carbon steel hous-
ings, with one housing for each of the two
engines. The catalyst
blocks were arranged
in a single layer, with
the weight of each
block being limited to
50 pounds to facilitate
installation and removal from the cata-
lyst housing.
Each of the catalyst housings was
equipped with a hinged door to pro-
vide access to the catalyst blocks from
an adjacent walkway. The housings were
installed outside of the generator building
and were externally insulated to reduce
heat loss. Each of the housings included
spare catalyst tracks for future use should
environmental regulations become more
stringent. The catalyst tracks are designed
to float within the housing to compen-
sate for thermal expansion and to seal
the catalyst modules to prevent exhaust
gas from bypassing the catalyst.
The engine exhaust flow rates, tem-
peratures and emissions were measured
in previous exhaust stack testing, and
these values were used as the design ba-
sis for this project. Although the current
CO emission values were not available,
the oxidation catalyst will convert CO
to carbon dioxide (CO2) by the design
reduction efficiency based on the proper
selection of the catalyst’s gas hourly space
velocity regardless of the amount of CO
in the engine exhaust.
According to the RICE NESHAP Rule,
the minimum and maximum tempera-
ture limits for lean burn CI engines is
450°F and 1350°F, respectively. The
minimum temperature is required for
the catalyzed reaction to occur; the upper
temperature limit avoids thermal sinter-
ing of the catalyst. The measured exhaust
temperatures of these engines from the
previous testing were typically within the
limits of the Rule at 500°F to 750°F from
During 2012, NRG worked with RPA
Engineering (RPA), a leading, full-service
engineering firm based in Wyomissing,
Pa. to specify, design and install an oxi-
dation catalyst and associated equipment
to meet RICE NESHAP requirements.
Engine operation
The NRG Energy Center Paxton
peaking plant is comprised of two
Cooper-Bessemer LSVB-20-GDT CI
engines that were installed in 1986.
Each engine is rated at 8656 bhp and
generates 6 MW of electricity.
NRG can operate these engines on full
diesel fuel for a limited amount of hours,
or dual-fuel (which is comprised of ap-
proximately 95 percent natural gas and 5
percent pilot diesel oil).
The engines are started on diesel fuel
and are switched over to dual-fuel opera-
tion at approximately one-third load.
NRG operates the engines on dual-fuel
because of the current cost advantages of
natural gas, but NRG also has the capabil-
ity to operate on diesel fuel only should
this be desired.
The Cooper-Bessemer engines at NRG
had been previously modified to sub-
stantially reduce the emissions of NOx in
the engine exhaust compared to an un-
modified dual-fuel engine.
Engine No. 1 is equipped with an
AMPS System and Engine No. 2 is
equipped with a
Cooper Clean Burn
System.
RICE NESHAP re-
quires that engine’s
time spent at idle be
minimized and that the engine startup
be limited to a period needed for ap-
propriate and safe loading of the en-
gine, not to exceed 30 minutes, after
which time the non-startup emission
limitations apply.
The catalyst used for the engines was a combination of
Platinum Group Metals on a stainless steel metal monolith,
with the catalyst blocks arranged in a single layer and the
weight of each block limited to 50 pounds.
Operators not in compliance with RICE NESHAP can be fined daily.
1306pe_57 57 6/4/13 4:04 PM
www.power-eng.com58
operators are installing open systems
to prevent the ingestion of raw blow-by
into the engine turbocharger or exhaust.
While the EPA does not specifically man-
date an efficiency level, best practices dic-
tate that all visible emissions are elimi-
nated from the crankcase vent.
This is only possible with a high effi-
ciency filter and not with the traditional
wire mesh.
In the case of NRG, Solberg Manufac-
turing Inc. designed and delivered a high-
efficiency, open crankcase ventilation
system to capture the vented hazardous
blow-by emissions from each of the two
existing Cooper-Bessemer engines. The
Solberg system includes an internal air/
oil separator cartridge with an efficiency
of 99.97 percent for 0.3 micron particles
and oil mist. This is packaged with a vac-
uum source, custom piping and a valve
to allow NRG to maintain the natural
crankcase pressure of the engine. The oily
emissions are pulled through the car-
tridge, and the entrained oil is coalesced
and collected at the bottom of the canis-
ter. The collected oil is recovered through
a drain port and is scavenged to a waste
oil tank inside the building. The result is
clean air and no visible emissions vented
from the crankcase to atmosphere.
Additional requirements
The engines were already equipped
with non-resettable hour meters, and
they were not required to be added to
the NRG installation to meet compli-
ance requirements. NRG was required
to use ultra-low-sulfur-diesel fuel as
part of the installation of the catalytic
oxidation system.
CHALLENGES
The RICE NESHAP installation at the
NRG Energy Paxton Plant presented sev-
eral major, but not uncommon, challeng-
es to the project team. The team worked
together to overcome these challenges as
described below.
Space limitations
The configuration of the existing
engine installation did not leave much
room for the installation of the cata-
lyst housing or the crankcase ventila-
tion system in an accessible location.
The exhaust system for each engine in-
cluded an existing, but out-of-service,
heat recovery steam generator (HRSG)
and an exhaust silencer.
Catalyst location options
Initially, NRG and RPA considered
three options for the catalyst location.
The most open area in the existing instal-
lation was the 36-inch diameter exhaust
pipe between the HRSG and the silencer.
One problem with this location was that
it would require platform modifications
to provide access to the catalyst. Another
problem was that replacement of the ex-
isting HRSG with a new operating unit
would cause catalyst inlet temperatures
too low for catalytic oxidation.
NRG and RPA also considered a loca-
tion inside the generator building be-
tween the expansion joint and the HRSG
inlet. This location would have required
new platforms for access and modifica-
tions to the building structure.
The third option, which required more
initial cost to implement, was to remove
the existing out-of-service HRSG and
place the catalyst housing in a location
just outside the generator building wall.
start-up to full load operation.
Continuous parametric monitor-
ing system (CPMS):
The RICE NESHAP Rule requires the
catalyst inlet temperature (as based on
a four-hour rolling average) to be docu-
mented and maintained within the mini-
mum and maximum operating tempera-
ture limitations noted above. The Rule
also requires that the pressure drop across
the catalyst be measured once per month
to demonstrate that it is maintained with-
in a +/- 2-inch w.c. tolerance (as measured
during the initial performance test).
NRG collects and stores the data with a
Johnson Matthey HapGuard Continuous
Parametric Monitoring System.
CPMS data readings are acquired at
least every five minutes. The CPMS calcu-
lates and stores a one-hour and four-hour
rolling average of temperature and differ-
ential pressure data for a minimum of 12
months. The CPMS will initiate an alarm
signal when temperature or pressure
readings and calculations exceed the lim-
its set by the operator. The operator has
the provision to define alarm set points
and unit identification during the system
commissioning.
There is a dedicated, programmable
CPMS for each engine’s catalytic con-
verter, which is installed in a NEMA 4
enclosure near the catalyst housing for
each engine. The CPMS is programmable
from a keypad on the front panel display.
Real time catalyst inlet temperature and
differential pressure are displayed on the
front panel display. The CPMS communi-
cates acquired data, calculated data and
monthly reports to NRG’s plant comput-
er by Ethernet connection.
Crankcase ventilation system:
RICE NESHAP specifically requires
that each diesel engine must have a
crankcase ventilation system to capture
the hazardous blow-by emissions vented
from the crankcase during operation.
These emissions consist of oil mist, met-
als and other particulate emissions.
Open or closed systems are accept-
ed under the standard; however, most
The NRG Energy Center Paxton peaking
plant, a 12 MW peaking plant plant located
near Harisburg, Penn., needed to reduce CO
emissions to comply with the RICE NESHAP
regulation.
1306pe_58 58 6/4/13 4:04 PM
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corporate and product identity used herein, are trademarks of Caterpillar and may not be used without permission.
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www.power-eng.com60
catalyst housing during operation.
The longer run of exhaust pipe created
by the removal of the existing HRSG led
to greater thermal expansion in the ex-
haust pipe between the catalyst housing
and the silencer. This was resolved by
adding a new fabric expansion joint de-
signed to compensate for four inches of
thermal expansion.
SYSTEM PRESSURE
LIMITATIONS
Catalyst pressure drop
Another concern with the catalyst
housing design was the maximum pres-
sure drop across the catalyst that could
be allowed before affecting engine per-
formance. The NRG Cooper-Bessemer
LSVB-GDT-20T engine has a maximum
allowable backpressure of 20-inches
w.c. Most of this pressure allowance was
already used up by the existing compo-
nents in the engine exhaust pipe.
In order to determine the maximum
pressure drop that could be allowed for
the catalyst, RPA Engineering modeled
the engine exhaust system and ran sev-
eral different exhaust flow conditions to
determine the maximum allowable de-
sign pressure drop for clean catalyst. The
pressure drop allowance also needed to
compensate for “dirty” conditions.
The standard catalyst housing design
used by Johnson Matthey was custom-
ized after computational fluid dynamic
modeling indicted that uniform flow
across the catalyst face could be achieved
with minimal inlet and outlet
transitions between the exhaust
pipe and the catalyst housing.
The compactness of the catalyst
housing combined with the rel-
atively stringent allowable pres-
sure drop limitation resulted in
a unique housing configuration
that fit within the existing ex-
haust system design.
Crankcase Pressure Re-
quirement
The NRG Cooper-Bessemer
engines are designed to operate
with a slightly positive crank-
case pressure to reduce the pos-
sibility of an explosion. This im-
pacted the design of the required
crankcase ventilation system.
The Solberg recirculation system in-
corporates a regenerative blower to cre-
ate suction to overcome the differential
pressure created by the oil saturated filter
element. However, the systems integrat-
ed piping will recirculate the exhaust air
from the blower back to the inlet of the
crankcase ventilation system. The result is
an equilibrium state in which the natural
engine crankcase pressure is maintained.
A manual control valve was included to
restrict the recirculation air over time
and produce a slight vacuum, if neces-
sary, to overcome eventual leaks through
worn engine seals. The NRG operators
monitor crankcase pressure on a regular
basis. Due to the concern with an upset
condition leading to the possibility of
NRG and RPA determined that the exist-
ing platform could be easily modified to
provide access to the new catalyst hous-
ings and also determined that there was
sufficient space to allow the installation
of a new HRSG, if needed.
After careful deliberation, NRG pro-
ceeded with the third option. Due to the
fact that space needed to be maintained
for a possible future HRSG, the
allowable length that the cata-
lyst housing took up in the ex-
haust duct was more limited.
Crankcase ventilation lo-
cation options
Another concern was de-
termining a location for the
crankcase ventilation system.
The engine crankcase is vented
through a six-inch pipe to a lo-
cation just outside the generator
building. A separate two-inch
cylinder head vent pipe joins the
main six-inch crankcase vent
pipe at a location just above the
engine. The high elevation at
which the crankcase vent pipe
ran inside the building made it
difficult to select a location that
would provide operator access
for system maintenance and ad-
justment.
The decision to remove the existing
HRSG contributed to finding an accessi-
ble location for the crankcase ventilation
system outside the generator building on
the existing platform. The Solberg crank-
case ventilation system also was able to
be customized to meet installation re-
quirements, and the units were mirror
images of each other.
Other factors
The selected location of the catalyst
immediately downstream of an exist-
ing metal bellows expansion joint raised
concerns about the resultant force that
would be imposed on the catalyst hous-
ing. Johnson Matthey performed a finite
element analysis to verify that this force
would not lead to excessive stress in the
A dedicated continuous parametric monitoring
system communicates information to the plant’s
computer using an Ethernet connection.
1306pe_60 60 6/4/13 4:04 PM
www.power-eng.com 61
For info. http://powereng.hotims.com RS# 33
the engines to operate at the desired
crankcase pressure of 0.4 to 0.5-inches
w.c. While the installation presented
some challenges, the equipment was
successfully installed through a coop-
erative effort among all members of
the team.
negative pressure in the engine crank-
case, a pressure switch was installed on
the engine that would alarm in case of
a low positive pressure in the engine
crankcase.
SYSTEM START-UP
The RICE NESHAP equipment was in-
stalled at the NRG Energy Paxton Plant
in the fall of 2012. The RICE NESHAP
systems for each engine were started up
in November 2012 by representatives of
Johnson Matthey and Solberg Manufac-
turing. During start-up the crankcase
ventilation system functioned as intend-
ed and there was no visible discharge
from the crankcase ventilation vent pipe.
Sample analysis for CO emissions
using a Testo 350 portable gas analyzer
were taken at 58 percent load, 67 percent
load, 83 percent load and 100 percent
load with Engine No. 1 operating on
dual fuel. As expected, the untreated CO
emissions at the engine outlet were the
highest at the lower engine loads. Un-
treated CO emissions decreased as the
engine load increased. The measured
CO conversion efficiency recorded the
highest CO conversion rate of 97percent
at the lower engine load, which then lev-
eled off at 95 percent CO conversion ef-
ficiency at full load. During the sample
testing, CO emissions at the outlet of the
catalyst had reached a plateau at an ab-
solute value of approximately 25 ppm,
regardless of the CO concentration at the
inlet of the catalyst.
CONCLUSION
The new RICE NESHAP regulation
has placed a significant requirement
on existing CI engines to reduce HAPs.
Using CO as a surrogate for HAPs, the
RICE NESHAP regulation required the
NRG engines to reduce CO emissions
by at least 70 percent or to a level of
23 ppmvd at 15 percent O2. NRG in-
stalled a precious metal-based cata-
lytic converter system to comply with
these emission limits. Emissions
testing with a lower span CO cell to
measure the CO conversion at low
CO concentrations showed that these
emission limits were achieved. The
addition of the crankcase ventilation
filters removed all visible emissions at
the crankcase vent pipe while enabling
1306pe_61 61 6/4/13 4:04 PM
www.power-eng.com62
from happening. In the absence of tur-
bine technology that provides high fish
passage on its own, hydro plant owners
must rely on such alternative measures as
spill or bypasses to protect fish.
To help overcome this problem, the
Electric Power Research Institute (EPRI),
U.S. Department of Energy (DOE), Alden
Research Laboratory Inc., Voith Hydro
Inc. and several industry partners have
been working to advance design of a
“fish-friendly” turbine. This turbine has
been conceptualized, tested using physi-
cal scale and computational fluid dy-
namics modeling, redesigned, produced
at model scale, and tested again. As a
result of this work, the Alden turbine is
now ready for installation and testing at a
hydroelectric plant, and efforts are under
way to find an industry partner to accom-
plish this next step.
UNDERSTANDING
THE BACKGROUND
Four years of work have gone into
a collaborative research and develop-
ment project funded by EPRI, DOE and
hydropower industry partners such as
Brookfield Renewable Power, Dairyland
Power Cooperative, Electricite de France,
New York Power Authority, New York
State Energy Research and Development
Authority, Puget Sound Energy, SCANA
Corp. and Southern Company. The ob-
jective of this project was to complete the
developmental engineering required for
the “fish-friendly” turbine developed by
Alden to prepare it for full-scale deploy-
ment and testing.
In 2009, EPRI, in response to a 2008
DOE funding opportunity announce-
ment with cost-sharing support from
the hydropower industry, was awarded a
$1.2 million DOE grant, matched by an
equal amount from EPRI and its industry
partners, to conduct engineering devel-
opment and physical scale model perfor-
mance testing of the Alden turbine. The
developmental engineering included:
• Using computational fluid dynam-
ics (CFD) to convert a conceptual
design into a design from which the
turbine can be built; and
• Constructing and testing a physical
model of the turbine to evaluate its
performance characteristics for eco-
nomic analysis.
The Alden turbine was developed
through DOE’s former Advanced Hydro
Turbine Systems Program and, more
recently, through EPRI’s Waterpower
Over four years, mul-
tiple entities within
the hydropower in-
dustry have worked to
advance design, con-
struction and installation of a specific
“fish-friendly” turbine design. Efforts are
under way to find a hydroelectric project
operator to install this unit and demon-
strate its effectiveness for safely passing
fish and producing electricity.
In an ideal operating scenario, every
drop of water available to a hydroelectric
powerhouse is run through the turbines
to generate electricity. However, the need
to support high fish passage survival at
most hydropower facilities precludes this
Development Statusof the Alden
“Fish-Friendly” TurbineBY NORMAN PERKINS, DOUGLAS A. DIXON, RAJESH DHAM AND JASON FOUST
This 1:8.71 physical model of the Alden
turbine runner was tested by Voith Hydro and
provided peak efficiency of 91.85%, which
translates to a maximum calculated prototype
efficiency of 93.64%.
1306pe_62 62 6/4/13 4:04 PM
www.power-eng.com 63
#
FEA Image ofTurbine Runner 1
Finite element analysis of the turbine runnerwas performed to determine the staticstresses for the stay vanes, wicket gatesand runner modifcations.
#
CFD Imageof Turbine Runner 2
Computational fuid dynamics simulations of theturbine runner included everything from thepenstock to the draft tube outlet and tailwater.The same loss sources were modeled here aswere studied using the physical model.
production, and finally reduced supply
costs. Although the runner is being de-
veloped to provide a new family of fish-
friendly hydro turbines for smaller ma-
chines across a range of head and flow
applications, Alden and Voith Hydro fo-
cused the design effort for potential pilot
application at a project with operating
conditions corresponding to 92 feet of net
head with a discharge rate of 1,500 cubic
feet per second (cfs).
Calculations show that the improved
flow environment through the final tur-
bine is expected to produce significant ef-
ficiency improvements (5% at the design
conditions listed above) with the same
or slightly improved fish-friendly char-
acteristics as compared with the original
Alden concept. While some small perfor-
mance improvements are predicted for
the final distributor, the majority of the
efficiency improvement is realized in the
final runner and draft tube as a result of
the improved runner-draft tube interac-
tion at the selected design condition.
After the modified turbine hydraulic
passageways were defined and structural
analysis was performed for the anticipat-
ed operating range, the hydraulic shapes
were released for model manufacture,
including the inlet pipe, transition piece,
spiral case, stay ring, wicket gates, runner
and draft tube. Physical model testing
was conducted in 2010 at Voith Hydro’s S.
Morgan Smith Memorial Hydraulic Lab-
oratory in York, Pa. Data was collected
on performance, thrust, runaway speed,
pressure pulsations, minimum pres-
sures, cavitation and wicket gate torques
to characterize the hydraulic behavior of
the turbine and identify the acceptable
operating range for the target site design.
Results of the hydraulic testing also
were incorporated into the final sizing of
the mechanical equipment. Voith Hydro
manufactured the physical model at a
scale of 1:8.71 and conducted the tests at a
speed of 900 rpm. During testing, a mod-
el peak efficiency of 91.85% was record-
ed. The prototype efficiency adjustment
translates into a maximum calculated
relatively thick semi-circular entrance
edges to minimize strike damage to fish,
extremely long blades with nearly 180 de-
grees of blade wrap, and a runner height
that is larger than a conventional turbine
of similar diameter. Each blade is fixed
to a central hub (crown) and an external
shroud (band), eliminating all gaps and
resulting leakage vortices within the run-
ner passage.
Runner geometry was evaluated ac-
cording to three distinct design criteria,
with fish friendliness being the most
important, followed by increased power
Program and DOE’s Wind & Water Power
Program. The turbine was designed to
support high fish passage survival, which
would offset the need for measures —
such as intake screens, fish passage spills
and alternative downstream fish by-
passes — that are expensive and decrease
generation. To reduce injury to fish, the
Alden runner has: only three blades, no
clearances between the blades and the
crown or housing, and, with the excep-
tion of small areas around the blade lead-
ing edges, pressure and velocity (shear)
gradients that meet established bio-crite-
ria for safe fish passage.
Before 2009, numerous studies sup-
ported by DOE, EPRI and industry col-
laboration were conducted to validate
the theoretical concept of the turbine.
Studies included: CFD modeling, use of
a one-third-scale test facility to evaluate
the turbine biological and engineering
performance, additional conceptual tur-
bine development efforts (in 2006), and
laboratory experiments that examined
the relationship between turbine blade
leading edge geometry and fish injury/
survival after blade strike.
HYDRAULIC
DEVELOPMENT
The Alden runner reduces blade strike
mortality through several modifications:
• Reducing the number of blades rela-
tive to conventional applications;
• Employing special blade leading
edge geometries; and
Rotating slower than conventional tur-
bines. The current Alden turbine design
incorporates a runner that features three
blades that rotate at a speed of 120 revo-
lutions per minute (rpm). Application of
conventional turbine technologies for
the target site results in a 13-bladed Fran-
cis turbine that rotates at 189.5 rpm, or a
five-bladed Kaplan turbine that rotates at
267.9 rpm.
The blade shapes were developed to
meet criteria for pressure change rates,
shear rates and minimum pressures
through the runner. The blades feature
1306pe_63 63 6/4/13 4:04 PM
www.power-eng.com64
Anticipated Range of Application for Alden Turbine 3
The Alden turbine design represents a new family with a range of head and fow applications.Future design modifcations are anticipated to extend operation of the turbine above120 feet of net head.
compared. The CFD hill chart is gener-
ally similar in shape to that derived from
the physical model test results. However,
the CFD model tended to over-predict
efficiency for low flows with small gate
opening angles.
This resulted in displacement of the
CFD-derived highest efficiency area to
lower flows.
The reasons for these differences are
not clear.
It may be noted that the plotted ef-
ficiency contours are at intervals of only
0.5%, which accentuates visual differenc-
es between the contours from the CFD
and physical data.
The peak efficiency of 93.6% expected
for the full scale turbine was well-pre-
dicted by the CFD simulations. It is con-
cluded that the CFD simulations are most
reliable in predicting the more controlled
(coherent) flow patterns near the turbine
design point.
This direct comparison between CFD
simulations and physical model test data
provides useful information for turbine
designers and researchers.
This kind of validation allows the de-
veloped CFD model to be used to explore
other issues of concern, such as deter-
mining values for local pressures, pres-
sure change rates, shear and the locations
where related fish survival criteria are
met or exceeded.
prototype efficiency of 93.64%.
The final aspect of the developmental
engineering included the design for the
supporting mechanical and balance of
plant equipment for supply of the com-
plete unit. In this phase, finite element
analysis (FEA) was performed to deter-
mine the static stresses for the stay vanes,
wicket gates and runner modifications
(see Figure 1). Mechanical design and
analysis of the final spiral case and stay
ring decks was completed.
CFD SIMULATIONS
AND COMPARISON
WITH PHYSICAL
MODEL DATA
The data on efficiency and
power obtained from the physical
model testing, scaled up to proto-
type values, were used to compile
the “hill chart” to visually show
the best efficiency point (BEP)
and range of acceptable operat-
ing conditions. CFD simulations
of the entire turbine (see Figure 2)
were initiated, from the penstock
to the draft tube outlet and tail-
water. These simulations included
the fluid-filled spaces between
the outer runner shroud and the casing,
as well as between the head cover and
runner top, thereby including the same
loss sources as in the physical model.
Plotting the resulting efficiencies from
the physical model and CFD simulations
using non-dimensional head and flow
coefficients, which included the turbine
diameter and runner rotating speed, aid-
ed a direct comparison between the BEP
operating conditions and maximum effi-
ciency value. The general shape of the ef-
ficiency lines on the “hill chart” was also
Source:
Price of Alden vs Conventional Turbines 1
Alden Turbine
Conventional Francis Turbine (Same Power)
Conventional Kaplan Turbine (Same Power)
Diameter (mm) 3,900 2,510 2,650
Maximum Power (MW) 13.6 13.6 13.6
Turbine Cost 1 0.5 0.55
Generator Cost 0.8 0.65 0.65
Installation andCommissioning Cost
0.25 0.25 0.25
Automation/Balanceof Plant Cost
0.25 0.25 0.25
Relative Cost 2.3 1.65 1.7
Premium for Alden 39% 35%
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www.power-eng.com66
funding opportunity announcement,
EPRI was selected to receive $1.5 mil-
lion of support with a cost-share match
requirement to install and test the Al-
den turbine at a site to be determined.
References
Additional Tests Examining Survival of Fish
Struck by Turbine Blades, EPRI, Palo Alto, Calif.,
2011.
Amaral, S.V., et al, “Effects of Leading Edge
Turbine Blade Thickness on Fish Strike Survival
and Injury,” Proceedings of HydroVision 2008,
HCI Publications, Kansas City, Mo., 2008.
Cook, T.C., et al, Final Report – Pilot Scale
Tests Alden/Concepts NREC Turbine, prepared
by Alden Research Laboratory for U.S. De-
partment of Energy, Contract No. DE-AC07-
99ID13733, 2003.
Coulson, S., et al, “Alden Fish Friendly Tur-
bine: Final Development for Commercial Ap-
plication,” Proceedings of HydroVision 2011,
PennWell Corporation, Tulsa, Okla., 2011.
Demonstration Development Project: So-
licitation and Selection of a Site to Test a Fish-
Friendly Hydropower Turbine, EPRI Technical
Update No. 1022538 prepared by Alden Re-
search Laboratory, 2011.
EPRI-DOE Conference on Environmentally-
Enhanced Hydropower Turbines: Technical
Papers, EPRI, Palo Alto, Calif., and U.S. Depart-
ment of Energy, Washington, D.C., 2011.
Evaluation of the Effects of Turbine Blade
Leading Edge Design on Fish Survival, EPRI Re-
port No. 1014937 prepared by Alden Research
Laboratory, 2008.
“Fish Friendly” Hydropower Turbine Devel-
opment and Deployment: Alden Turbine Pre-
liminary Engineering and Model Testing, EPRI
Report 1019890 prepared by Alden Research
Laboratory, 2011.
Hecker, G.E., and T.C. Cook, “Development
and Evaluation of a New Helical Fish Friendly
Hydro-Turbine,” Journal of Hydraulic Engineer-
ing, Volume 131, No. 10, October 2005, pages
1-21.
Redesign of the Alden/Concepts NREC He-
lical Turbine for Increased Power Density and
Fish Survival: Evaluation of a Conceptual Proto-
type Turbine, EPRI, Palo Alto, Calif., 2009.
ALDEN TURBINE
DEVELOPMENT: PRICING
AND SCHEDULE
Below is a preliminary schedule for in-
stallation at a potential test site:
• Definition of unit layout, four
months from contract award from
the potential utility to Voith Hydro;
• Embeds arrive at site, 14 months
from contract award;
• Powerhouse crane available for Voith
Hydro use, 22 months from contract
award; and
• Equipment commissioned and
handover to owner, 28 months from
contract award.
The Alden turbine is, by design, lower
in power density than conventional tur-
bines.
The larger, more slowly rotating equip-
ment leads to a relatively more expensive
turbine-generator solution. For the site
conditions at a comparable prototype
site, sizing for a conventional Francis unit
gives a 13-bladed, 2.5-meter-diameter
runner with an rpm of 189.5. Sizing for a
conventional Kaplan turbine gives a five-
bladed, 2.7-meter-diameter runner with
an rpm of 276.9. During the Alden tur-
bine development, a detailed cost study
was performed to determine the equip-
ment, installation and commissioning
cost.
Table 1 provides a comparison of the
installed equipment price for the Alden
turbine vs. conventional hydro turbines.
The prices are normalized relative to the
Alden turbine.
The relative pricing does not include
civil work. The larger size and slower
speed of the turbine allows for a higher
setting relative to the tailwater.
For the prototype design, the Alden
distributor centerline is 5 feet above tail-
water, while the conventional Francis
centerline is anticipated to be set 2 feet
above tailwater.
The conventional Kaplan centerline
is set the lowest, falling 16 feet below
tailwater.
The higher setting of the Alden turbine
may result in less excavation and lower
civil costs.
APPLICABILITY TO
OTHER HYDRO SITES
Although the turbine was hydraulical-
ly and mechanically designed for a target
site condition, it represents a new turbine
family with a range of head and flow ap-
plications. Figure 3 shows the anticipated
turbine application range.
The green region, labeled “current ap-
plication,” spans 75 to 100 feet of net
head and represents the head range cov-
ered by the current design. The larger yel-
low region, labeled “modified current ap-
plication,” can be accomplished through
appropriate sizing and design modifica-
tions to the turbine. This region spans
from 30 to 120 feet of net head. At 120
feet of net head, stress limitations of the
current design limit applicability. It is an-
ticipated that future design modifications
to the turbine can extend the operation
above 120 feet of net head. Below 30 feet
of net head, turbine application switches
to large bulb units.
SUMMARY AND
NEXT STEPS
The work performed to date has im-
proved the performance characteristics
of the Alden turbine while maintaining
its fish-friendly characteristics.
The preliminary engineering re-
quired to make the turbine commer-
cially available has been completed.
Design modifications to the turbine
components have improved efficiency
to almost 94% at the selected design
point, while providing the same or
slightly improved fish passage survival.
These turbine modifications were also
selected to decrease manufacturing and
supply costs, resulting in a solution that
is economically competitive with con-
ventional turbines. The improved tur-
bine is now available for commercial
deployment.
In 2011, in response to another DOE
1306pe_66 66 6/4/13 4:04 PM
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Ring Granulators, Reversible Hammermills,
Double Roll Crushers, Frozen Coal Crackers
for crushing coal, limstone and slag.
For info. http://powereng.hotims.com RS# 463
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For info. http://powereng.hotims.com RS# 466
24 / 7 EMERGENCY SERVICE
BOILERS20,000 - 400,000 #/Hr.
DIESEL & TURBINE GENERATORS50 - 25,000 KW
GEARS & TURBINES25 - 4000 HP
LARGEST INVENTORIES OF:
Air Pre-Heaters • Economizers • DeaeratorsPumps • Motors • Fuel Oil Heating & Pump Sets
Valves • Tubes • Controls • CompressorsPulverizers • Rental Boilers & Generators
847-541-5600 FAX: 847-541-1279 visit www.wabashpower.com
FOR SALE/RENT
POWER
EQUIPMENT CO.
444 Carpenter Avenue, Wheeling, IL 60090
wabash
For info. http://powereng.hotims.com RS# 459
For info. http://powereng.hotims.com RS# 461
For info. http://powereng.hotims.com RS# 464
GEORGE H. BODMAN, INC.Chemical cleaning advisory services for
boilers and balance of plant systems
George H. BodmanPres / Technical Advisor
P.O. Box 5758 Office (281) 359-4006Kingwood, TX 77325-5758 1-800-286-6069email: [email protected] Fax (281) 359-4225
For sale or rent
The world’s verybest portable end
prep tools and abrasive saws
800-343-6926www.escotool.com
Tur bine ControlsWoodward, GE, MHC
Parts and ServiceObsolete Parts Inventory
Control System, ModernizationTraining, Troubleshooting
(610) [email protected]
TurboGen Consultants, Inc.
For info. http://powereng.hotims.com RS# 462
For info. http://powereng.hotims.com RS# 460
rental
equipment
the steam & power special forces®
1-800-990-0374
www.rentalboilers.com
Rental Boilers • Deaerator Systems •
Economizers • Water Softener Systems •
24-Hour Emergency Service
1306pe_71 71 6/4/13 4:05 PM
www.power-eng.com72
INDEX
RS# COMPANY PG# SALES OFFICERS# COMPANY PG#
1421 S. Sheridan Rd., Tulsa, OK 74112Phone: 918-835-3161, Fax: 918-831-9834e-mail: [email protected]
Sr. Vice President NorthAmerican Power Group Richard Baker
Reprints Foster Printing Servive4295 Ohio StreetMichigan City, IN 46360Phone: 866-879-9144e-mail: [email protected]
National Brand Manager Rick HuntzickerPalladian Professional Park3225 Shallowford Rd., Suite 800Marietta, GA 30062Phone: 770-578-2688, Fax: 770-578-2690e-mail: [email protected], AR, DC, FL, GA, KS, KY, LA, MD, MO,MS, NC, SC, TN, TX, VA, WV
Brand Sales Manager Dan Idoine806 Park Village DriveLouisville, OH 44641Phone: 330-875-6581, Fax: 330-875-4462e-mail: [email protected], DE, IL, IN, MA, ME, MI, NH, NJ, NY,OH, PA, RI, VT, Quebec, New Brunswick,Nova Scotia, Newfoundland, Ontario
Brand Sales Manager Tina Shibley1421 S. Sheridan RoadTulsa, OK 74112Phone: 918-831-9552; Fax: 918-831-9834e-mail: [email protected], AZ, CA, CO, HI, IA, ID, MN, MT, ND,NE, NM, NV, OK, OR, SD UT, WA, WI, WY,Alberta, British Columbia, Saskatchewan,Northwest Territory, Yukon Territory,Manitoba
International Sales Mgr Anthony OrfeoThe Water TowerGunpowder MillsPowdermill LaneWaltham Abbey, Essex EN9 1BNUnited KingdomPhone: +44 1992 656 609, Fax: +44 1992 656 700e-mail: [email protected], Asia, Central America, Europe,Middle East, South America
European Sales Asif YusufThe Water TowerGunpowder MillsPowdermill LaneWaltham Abbey, Essex EN9 1BNUnited KingdomPhone: +44 1992 656 631, Fax: +44 1992 656 700e-mail: [email protected] and Middle East
Classifieds/Literature Showcase
Account Executive Paige Rogers1421 S. Sheridan Rd.Tulsa, OK 74112Phone: 918-831-9441, Fax: 918-831-9834email: [email protected]
14 Mitsubishi Power Systems Americas Inc 25
www.mpshq.com
16 New York Blower Company 27 www.nyb.com
23 Nol-Tec Systems Inc 37 www.nol-tec.com
15 Nord-Lock\Superbolt 26 www.nord-lock.com
17 Orion Instruments 29 www.orioninstruments.com
30 PennWell Webcast 54 www.power-eng.com/webcast
6 Philadelphia Gear Corporation 11
3 PIC Group Inc 5 www.picworld.com
31 POWER-GEN INTERNATIONAL 55 www.power-gen.com
24 Renewable Energy World North America 39
RenewableEnergyWorld-Events.com
21 Siemens AG 35 www.siemens.com/energy
1 Solvay Chemicals Inc C2 www.solvair.us
9 Structural Integrity Associates 17 www.structint.com/power-eng
10 Sturtevant Inc 19 www.sturtevantinc.com
5 Team Industrial Services 9 www.teamindustrialservices.com
19 Wanzek Construction Inc 32 www.wanzek.com
4 Westinghouse Electric Co 7 www.westinghousenuclear.com
Advertisers and advertising agencies assume lia-
bility for all contents (including text representation
and illustrations) of advertisements printed, and
also assume responsibility for any claims arising
therefrom made against the publisher. It is the
advertiser’s or agency’s responsibility to obtain
appropriate releases on any items or individuals
pictured in the advertisement.
27 Aggreko 47 www.coolingtowers.com
22 APEX Engineering Products 36 www.apexengineeringproducts.com
7 Bibb Engineers, Architects, Constructors 13
www.bibb-eac.com
25 Brand Energy and Infrastructure Services 43
www.beis.com
Brandenburg Industrial Service Company C4
www.brandenburg.com
32 Caterpillar Inc. 59 www.catgaspower.com
34 COAL-GEN 65 www.coal-gen.com
13 Diamond Power International 23 www.diamondpower.com
11 Dresser-Rand 22 www.dresser-rand.com/products
20 Fibrwrap 33 www.fibrwrap.com
12 Goodway Technologies Corp 22 www.goodway.com
2 Gundlach Crushers/Pennsylvania Crusher 3
www.TerraSource.com
33 Harco 61 www.harcolabs.com
26 Hitachi Power Systems Amercia Ltd 45
www.hitachipowersystems.us
35 Hobas Pipe USA C3 www.hobaspipe.com
HYTORC 49 www.torquegun.com
8 Ingersoll Rand 15 www.ingersollrandproducts.com
29 Light Engineering Inc 53 www.It-eng.com/products/find-a-
distributor
18 Magnetrol International 31 www.magnetrol.com
28 Membrana 52 www.liqui-cel.com
1306pe_72 72 6/4/13 4:05 PM
HOBAS PIPE USA
281-821-2200
www.hobaspipe.com
What Makes HOBAS® The Standard?
Precision centrifugal casting, consistent high quality, fiberglass-reinforced, polymer mortar pipes
Responsive customer service, on-site field reps backed by extensive engineering support
Time Proven
Leak Free
Long Lasting
Corrosion Resistant
High Strength
Quick, Easy Installation
High Flow Capacity
For info. http://powereng.hotims.com RS# 35
1306pe_C3 C3 6/4/13 4:07 PM
