2016 02 Power Engineering

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120YEARS
CONDENSER RELIABILITY
CLEANING,LEAK DETECTION AND TESTING
COAL ASH MANAGEMENT
COST-EFFECTIVE COMPLIANCE OPTIONS
CHP IN NORTH AMERICA
ANALYZING THE POTENTIAL
Combating
Boiler Slag
February 2016 • www.power-eng.com
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FEATURES
DEPARTMENTS
No.2,February 2016
120YEARS
20 Dry Ash Conversions
With the final version of the Environmental Protection
Agency’s Coal Combustion Residuals (CCR) rule now on
the books,utilities have the regulatory clarity they need
to move forward with compliance strategies.What should
you consider when developing and executing a plan to
meet the new CCR mandates.
33 Leak Detection “Ins” and “Outs”
When condensers experience air inleakage and water leakage,the results can be costly.
Proactive routine cleaning and leak detection can maximize output while minimizing outages.
30 Combating Boiler Slag
The tools used to combat the buildup of boiler slag at
power plants are wide ranging.Common tools include
soot blowers,sound waves,hydro blasters,CO2 blasters,
jackhammers,picks,and carefully-aimed shotguns.In
some severe cases,plant operators will turn to dynamite
to deal with ceaseless slagging.
36 Natural Gas Gensets:
Poised for Growth
As a source of emergency standby,prime,peaking,or
continuous power,natural gas-fired generator sets are
poised for significant growth,especially in the U.S.,
where low-priced natural gas is widely available.
16 Analyzing the
Potential of CHP
in North America
Combined heat and power has the potential to provide a quarter of U.S.power
needs.This time-tested form of power generation is poised for vigorous growth.
Our analysis of this emerging market will explain why.
2 Opinion
4 Industry News
6 Clearing the Air
8 Industry Watch
10 View on Renewables
12 Energy Matters
14 Nuclear Reactions
40 What Works
41 Generating Buzz
56 Ad Index

2
OPINION
www.power-eng.com
said Chip Bottone, chief executive offi-
cer of FuelCell Energy.
Bottone’s company has fuel cell pow-
er plants up and running in more than
50 locations worldwide.
Fuel cells have several advantages
over other more common forms of on-
site power. They are significantly clean-
er, quiet, less expensive to operate, and
require little real-estate.
Dominion Resources owns the
largest fuel cell power plant in North
America, a 15-MW project in Bridge-
port, Connecticut, capable of produc-
ing enough electricity for about 15,000
homes. Dominion sells the power to
Connecticut Light & Power under a 15-
year power purchase agreement.
Fuel cells are not a new technology.
They have long been associated with
the NASA space program and transpor-
tation vehicles. In recent years, though,
the applications and markets for fuel
cells have expanded. Fuel cells are be-
ing used for primary power, backup
power, emergency power, and auxilia-
ry power. They are used to power ho-
tels, hospitals, universities, and data
centers for Apple and eBay.
As the cost of centralized power rises,
the cost of decentralized power contin-
ues to fall. Some power professionals
believe the days of centralized power
are numbered. That point of view is a
bit extreme, but fuel cells are without
question going to play a starring role in
what is sure to be a significant transi-
tion to distributed generation.
If you have a question or a comment,
contact me at russellr@pennwell.com.
Follow me on Twitter @RussellRay1.
I
magine a source of power that is
virtually emission-free, highly re-
liable, occupies small spaces and
can generate enough electricity to pow-
er thousands of homes.
It’s not a pipe dream. The technology
has been around for a while and it is
increasingly being deployed in the U.S.
and abroad to meet public demand for
clean, reliable electricity.
More homes, businesses and utilities
are turning to fuel cells to meet their pow-
er generation needs. Installing groups of
modular fuel-cell systems to create small
power plants ranging from 5 MW to 63
MW in size is a growing market.
Several large scale fuel-cell power
plants have been built in Connecticut,
Delaware and California.
Just last month, state officials in
Connecticut approved plans to build
what will be the largest fuel cell power
plant in the world. Equipped with 21
fuel cells, the 63.3-MW Beacon Falls
fuel cell power plant will surpass the
59.9-MW fuel cell plant in South Korea.
The Beacon Falls project will be capa-
ble of generating enough electricity to
power 60,000 Connecticut homes and
is expected to be completed in 2019.
The power plant and substation will
be built on about eight acres. A solar
plant would require about 10 times
more land to achieve the same amount
of output.
In addition, fuel cells, which use
hydrogen and oxygen to generate elec-
tricity, have no moving parts, making
them inherently quiet and ideal for
use in urban settings where the power
is actually consumed. This limits the
need for transmission and distribution
lines, thus reducing the risk of power
outages caused by ice storms and heavy
winds.
The hydrogen used in fuel cells can
be produced by a variety of fuels, in-
cluding natural gas. A fuel cell splits
hydrogen into electrons and protons.
As protons pass through the cell’s thin
plastic membrane, the electrons are
forced into a circuit, creating an elec-
tric current.
Although the universe is 80 percent
hydrogen, it is almost never found nat-
urally by itself because it’s locked up in
other compounds like water and cellu-
lose. That’s why the source of hydrogen
is typically natural gas or methane. The
electrochemical reaction in fuel cells
creates water vapor, eliminating the
harmful emissions of a combustion
engine.
What’s more, the cost of fuel cells is
falling thanks to increasing demand,
or better economies of scale, making
the technology even more attractive.
Leading fuel cell manufacturer Fu-
elCell Energy Inc. will supply the fuel
cells for the Beacon Falls project.
Since power from fuel cells have
been deemed renewable in 13 states,
including Connecticut, the power from
these systems can be used to comply
with new standards for renewable pow-
er, also known as renewable portfolio
standards (RPS).
“This one project meets about 10
percent of the State of Connecticut’s
RPS requirements for 2016, and no
state funds are needed as private capi-
tal will be used to finance the project,”
Fuel Cells to Play
Important Role
in Power Generation
BY RUSSELL RAY, CHIEF EDITOR

US Corporate Office | 660.829.5100 proenergyservices.com
Whether it’s a planned project or an urgent need, ProEnergy has a solution
for every aspect of your plant’s operation. From a full inventory of equipment
to a complete team of experienced engineers, you can rest assured
we’ve got all the pieces you need when you need them most.
THE RIGHT PIECES
AT THE RIGHT TIME

4 www.power-eng.com
INDUSTRY NEWS
connection expected between April and
December.
NRC Begins Inspection at
Arkansas Nuclear One
The U.S. Nuclear Regulatory Com-
mission (NRC) began a comprehensive
inspection at Entergy’s Arkansas Nuclear
One power plant.
A team of 25 inspectors will devote
about 3,600 hours of effort to inde-
pendently assess and document the ade-
quacy of Entergy programs and process-
es used to identify, evaluate, and correct
performance issues; provide insights into
the causes of performance deficiencies;
and evaluate the adequacy of a third-par-
ty safety culture assessment conducted at
the site.
The NRC placed ANO under special
inspections after a 2013 incident during
a planned outage where heavy equipment
fell and killed a worker. In June 2014,
the NRC issued yellow findings for how
the equipment was handled. In January
2015, the NRC issued additional yellow
findings associated with flood protection
at the plant. The findings moved ANO
into Column 4 of the plant performance
matrix, the second-highest level of the
matrix, which also means the plant is un-
der the highest level of NRC oversight of
operating power plants. Column 5 would
mean the plant could not operate.
Supreme Court Rules FERC Can
Issue Demand Response Rule
The U.S. Supreme Court overturned a
lower court ruling against the Federal En-
ergy Regulatory Commission (FERC) Or-
der 745, which pays consumers for using
less power during high-demand periods.
In Electric Power Supply Association v.
FERC, the high court voted 6-2 that FERC
hadauthorityundertheFederalPowerAct
to issue the so-called demand response
rule. The justices said FERC is not directly
regulating retail electricity sales with the
rule. Justice Samuel Alito recused himself
Court Denies Stay of
Clean Power Plan
The D.C. Circuit Court of Appeals
denied petitions to stay the Obama
administration’s Clean Power Plan,
preserving the landmark rule’s author-
ity to regulate carbon emissions from
power plants, even as the rule prepares
to defend against subsequent litigation
designed to erode its legality.
The Clean Power Plan calls for
sweeping new requirements to cut car-
bon dioxide emissions 32 percent be-
low 2005 levels by 2030. States have
until 2018 to submit their compliance
plans.
Stating that petitioners “have not
satisfied the stringent standards that
apply to petitions for extraordinary
writs that seek to stay agency action,”
the court declined to uphold action
brought by West Virginia and Peabody
Energy Corporation, which would
have rendered the law powerless, even
as it defended its constitutionality in
future legal cases.
The American Coalition for Clean
Coal Electricity (ACCCE) says efforts
to overturn the Clean Power Plan will
continue.
sPower Plans 700 MW of
Utility-Scale Solar in 2016
Sustainable Power Group (sPower)
has entered a contract with Rosendin
Electric Inc. (REI) to develop nearly 700
MW of utility-scale solar photovoltaic
(PV) projects in 2016.
Construction of the new projects be-
gan in January, with completion and grid
from the case because of a stock holding.
The demand response rule was adopt-
ed in March 2011 and was intended to
compensate large, individual consumers
such as utilities, large groups of electric-
ity consumers, and factories for using
less electricity during peak demand peri-
ods. A U.S. Court of Appeals for the D.C.
Circuit panel ruled in May 2014 that the
states have jurisdiction over demand re-
sponse because it affects retail customers
and how much electricity they buy, even
though it affects the wholesale markets.
EIA: Fossil-Fueled Power to Lose
Share to Renewables
Fossil-fueled power generation will
lose share to renewable resources across
the nation’s generation portfolios, ac-
cording to the U.S. Energy Information
Administration’s (EIA) Short-Term Ener-
gy Outlook. Published last month, the
current edition of the report is the first to
include energy forecasts for 2017.
“A decline in power generation from
fossil fuels in the forecast period is offset
by an increase from renewable resources,”
the report says.
The share of natural gas-fired power
generation is expected to fall from 33
percent in 2015 to 31 percent in 2017.
Likewise, the share of coal-fired power
generation will fall from 34 percent to 33
percent in the reporting period.
Renewables are expected to increase
their share of the country’s power gener-
ation portfolio, with hydropower rising
from 6 percent in 2015 to 7 percent in
2017, and the share of all other renew-
ables rising from 7 percent to 9 percent in
the same period.
The report sees continued growth
in utility-scale solar power, forecasting
a production average of 129 gigawat-
thours per day in 2017, which represents
a 45-percent increase over 2016 levels.
Levels in 2016 will themselves amount to
a 126-percent increase over 2014 levels.
All told, utility-scale solar is forecasted to

www.power-eng.com
account for 1.1 percent of total U.S. power
generation in 2017. North Carolina, Ne-
vada and California will together account
for about two-thirds of capacity additions
in 2015 and 2016.
With its larger installed capacity
base, wind energy grew by 13 percent
in 2015, says the report. It is forecasted
to increase by 14 percent in 2016 and 3
percent in 2017.
MHPSA Ships First
Domestically-Manufactured
M501J from Georgia
Mitsubishi Hitachi Power Systems
Americas (MHPSA) has shipped the
first U.S.-manufactured M501J gas tur-
bine from its Savanah Machinery Works
(SMW) facility in Georgia. The new tur-
bine is now on its way to Grand River
Dam Authority’s (GRDA) Grand River
Energy Center in Oklahoma.
The J-series gas turbine will replace the
facility’s older coal-fired unit. Once oper-
ational, the 300-ton turbine will generate
495 MW of electricity, supplying power to
GRDA customers in all but two of Okla-
homa’s counties.
“What makes the J-series gas turbine
so unique is that it is the first and only
turbine in commercial operation today
capable of achieving 2,912°F turbine inlet
temperatures while delivering efficiencies
approaching 62 percent in combined-cy-
cle mode,” said David Brozek, senior vice
president at MHPSA.
Scheduled for completion in the sec-
ond quarter of 2017, GRDA’s turbine will
be the 28th J-series turbine to go into
commercial operation. In addition to the
GRDA Unit, SMW has a backlog of J-Se-
ries turbines that will be shipped over the
next several years.
MHPSA’s SMW manufacturing facility
opened in 2011, fulfilling a commitment
by the company to be closer to its North
American customer base and provide fast-
er support.
Hurst Boiler Commissions 1st
US Poultry Litter-Fueled Boiler
Hurst Boiler is commissioning the first
poultry litter-fueled boiler in the U.S. –
the world’s third such system – at a Clin-
ton, North Carolina cogeneration facility.
Commissioning is expected in mid-
2016, at which time the system will sup-
port Prestage Farm’s turkey operations.
The 1600 HP is the first Hurst Boiler
system in the country designed specifical-
ly to be fueled by poultry litter.
“While we have been carefully evaluat-
ing the potential to use litter in our boilers
in the U.S. market, one of our solid fuel
boilers in Guatemala began running al-
most three years ago on 100-percent litter,
simply because it was the most cost effec-
tive and reliable fuel,” said Tommy Hurst,
of Hurst Boiler Inc. “Since then, two more
systems have been installed and are pro-
viding steam to poultry facilities using
only chicken litter.”
“We are well aware of the many chal-
lenges and problems of litter as a fuel,
which is why we spent an inordinate
amount of time and resources making
sure that we had measures in place to
ensure success in the U.S. market,” said
Charlie Coffee, solid fuel boiler sales for
Hurst Boiler.
Coffee says there are many benefits to
using poultry litter. The ash from litter is
rich in potassium and phosphorous.
“By concentrating these nutrients in
ash, these systems can transform the po-
tential risk of phosphorous regulation
into an economic asset for companies,”
said Coffee.

6
CLEARING THE AIR
www.power-eng.com
W
hile admitting the final
version of the Clean Power
Plan (CPP) is better than
the proposed version, Jeff Holmstead,
an environmental attorney with Brace-
well & Giuliani, said the CPP is very
clever, but ultimately illegal.
Holmstead’s comments were made
in a mega-session at POWER-GEN In-
ternational 2015. Holmstead said short
of a stay, the CPP will carry the force
of law during litigation, but will likely
be struck down by the Supreme Court
in late 2017 or early 2018. Under the
law, he said, a single Supreme Court
justice—John Roberts—could stay the
rule unilaterally, though there is no
precedent for such an action, and it will
likely not happen.
The Clean Power Plan calls for
sweeping new requirements to cut car-
bon dioxide (CO2
) emissions 32 per-
cent below 2005 levels by 2030. States
have until 2018 to submit their compli-
ance plans.
On Jan. 21, the D.C. Circuit Court
of Appeals did indeed deny petition
to stay the rule, preserving the land-
mark legislation’s authority to regulate
carbon emissions from power plants,
even as the rule prepares to defend
against subsequent litigation designed
to erode its legality.
Stating that petitioners “have not
satisfied the stringent standards that
apply to petitions for extraordinary
writs that seek to stay agency action,”
the Court declined to uphold action
brought by West Virginia and Peabody
HOLMSTEAD:
CPP is Very Clever,
but Ultimately Illegal
BY TIM MISER, ASSOCIATE EDITOR
Energy Corporation, which would
have rendered the law powerless as it
defended its constitutionality in future
legal cases.
The final rule, Holmstead said, took a
much more national approach and was
designed to incentivize states to imple-
ment a mass-based cap and trade pro-
gram, instead of a rate-based program.
Still, he said, states are all watching one
another to see what the others will do.
The session, attended by more than
100 power professionals, also includ-
ed panelists Ben Machol with the EPA,
Steve Corneli with NRG Energy, and
John Lawhorn with the Midwest Inde-
pendent System Operator (MISO.)
Machol said the CPP was designed to
mitigate climate change and the asso-
ciated warming trend of the last many
years. He then highlighted key differ-
ences between the proposed version
and the final version of the CPP.
NRG Energy’s Corneli said there is no
longer a question about climate change.
The science is in, he said, and as a large
carbon emitter, NRG is in the process of
working toward a solution. Corneli ad-
vocated for a strategy that would “pick
the low-hanging fruit first”. States can
approach owners of coal plants and ask
them to commit to voluntarily retire
high-emission coal plants, he said.
Many states are already very close
to CPP compliance, he continued, and
emissions reductions will essential-
ly come from coal plants, not com-
bined-cycle gas-fired plants.
Lawhorn, whose work has modelled
the impact of the CPP, said the inter-
connected nature of the grid creates an
environment in which conditions that
affect one system operator may also af-
fect neighboring system operators.
MISO is talking with its neighbors
about collective efforts to analyze the
CPP, he said, adding the impacts of the
CPP “will be national in scope, reach-
ing beyond the border of any single sys-
tem operator.” Addressing the question
of whether the CPP delivered what it
was expected to deliver, Lawhorn said
there was no way to know, since state
implementation plans are not yet final-
ized. The default backstop for the CPP
is the federal implementation plan,
he noted, adding that states “need the
flexibility to implement the CPP on the
most economical basis possible.”
Jeff Holmstead

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8 www.power-eng.com
INDUSTRY WATCH
networks of key DER stakeholders.
DER project orchestrators uncover op-
portunities for smart cities and cam-
puses as well as individual energy con-
sumers large and small to save money,
increase resiliency, security and sus-
tainability, and promote economic
development. At the same time, they
help utilities find, size, and develop
opportunities to defer capital, improve
operations, and generate new revenue
sources, resulting in net savings for
ratepayers. They help wholesale mar-
kets maintain balance by creating new
DER-enabled energy, capacity and an-
cillary service resources. They develop
securitizable DER project investment
structures such that private investors
have opportunities to realize attractive
and portfolio-diversified risk-adjusted
returns. Finally, DER project orchestra-
tors engage project developers, service
providers, and technology vendors at
deeper levels of commitment, thereby
creating significant cross-project syner-
gies while driving down team integra-
tion risks and soft costs.
The emergence of new players and
partnerships in this space is evidence
of a shift to complex DER project or-
chestration over simple generation as-
set development. Though DER growth
is forecasted to rise, development barri-
ers abound, creating the need for a new
kind of player in the market. As such,
DER investments will be increasing-
ly specified, procured, and deployed
through the influence or direct con-
trol of project orchestrators. Wise DER
asset vendors and project developers
will find ways to partner with this new
breed of DER project orchestrator .
D
istributed Energy Resource
(DER) deployments are rap-
idly growing. While DER
drivers vary by technology, region,
and customer, “the overarching goal
of DER deployments is to make the
electricity grid more efficient, resilient,
cost-effective, and sustainable.”
Navigant Research forecasts the
world-wide capacity of DER to increase
four fold from 136 GW in 2015 to 531
GW in 2024. Of that increase, North
America is projected to be the second
largest market (after Asia Pacific) with
installed capacity increasing 46 GW to
134 GW—a compound annual growth
rate of 12.6 percent.
In light of these trends, players are
acting. Utilities are increasingly consid-
ering DER as tools for planning, such
as ConEd’s Brooklyn/Queens Demand
Management (BQDM) program that
seeks to use DER to defer $1 billion in
substation and related infrastructure
upgrades. Similarly, unregulated util-
ity businesses are pursuing new DER
business lines, such as Duke Energy
Renewables’ majority stake in REC So-
lar and subsequent partnership with
Green Charge Networks. Meanwhile,
leading DER firms are continuing to
make investments in North American,
such as Tesla’s factories in Sparks, NV.
As DER grid penetration accelerates,
feeder DG absorption constraints, in-
terconnect complexity, and cost and op-
erational concerns all rise accordingly.
While direct interconnection costs are
often regulated to be borne by the DER
project, broader issues of legacy fixed
investment and obligation-to-serve
operational readiness cost shifting to
non-participants is sparking debate
across the U.S. and beyond. The crux
of the matter is that although custom-
ers want to control their own destiny
and reduce costs, distribution utilities
remain obligated to maintain the grid’s
safety and reliability at the lowest cost
possible and with equitable cost ap-
portionment across rate classes. As this
DER growth tension plays out, private
investors are lining up, eagerly seeking
returns through ownership of a piece of
the growing DER pie, but also frustrat-
ed in their struggle to identify attrac-
tive risk-adjusted return opportunities
within this complex DER ecosystem.
A DER project orchestrator, much
like a network orchestrator, provides
proactive coordination of stakehold-
ers to achieve value creation benefits
for all. These benefits reach beyond
the typical project finance and gener-
ation asset metrics of interest to tradi-
tional project developers, and include
value propositions attractive to a wide
range of stakeholders. In pursuing this
broader basket of benefits, DER project
orchestrators unlock value by uncover-
ing and addressing hidden opportuni-
ties and risks among and between utili-
ties, investors, communities, wholesale
markets, and large or aggregated loads.
Finally, DER project orchestrators
operate at scale by leveraging broad
Holders of the
Hidden Keys to
DER Integration
BY KEN HORNE, ASSOCIATE DIRECTOR, DAN BRADLEY, MANAGING DIRECTOR,
AND MICHELLE BEBRIN, SENIOR CONSULTANT, NAVIGANT
Ken Horne Dan Bradley Michelle Bebrin

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10
VIEW ON RENEWABLES
www.power-eng.com
facility, but also requires that the custom-
er enter a contract with the utility and pay
distribution, delivery, and daily demand
charges to the utility. These green tariffs
can help utilities remain relevant and vi-
able among corporate customers seeking
new options.
Another option for corporations in reg-
ulated states are contracts in which the
corporation does not purchase the power
to serve its own retail load. Instead, while
the specific terms generally vary, in a con-
tract for differences, the renewable energy
seller sells its energy into the market for
the available market price (floating) and
the corporate customer agrees to fixed
price for the same power. The buyer then
settles monthly with the seller on the dif-
ference between the fixed and floating
prices with a payment going from buyer
to seller if the fixed price is above the mar-
ket price and in reverse where the floating
price is above the fixed price. This ar-
rangement provides a benefit to the seller
in terms of a fixed revenue stream and to
the buyer in the form of a hedge against
its retail supply arrangement. That said,
these arrangements can implicate regu-
latory and accounting obligations about
which corporations and sellers must be
aware.
Corporations’ ever-increasing demand
for renewables is driving new and inno-
vative options for procuring them. While
corporations in regulated states have been
limitedintheirabilitytodirectlypurchase
renewables and take advantage of their
lower costs, virtual PPAs and green tariffs
are beginning to offer those benefits. Cor-
porations can thus look forward to better
access to renewables going forward.
B
usinesses across the country are
seeing the green in renewable
energy. They recognize that in ad-
dition to helping meet corporate sustain-
ability goals, renewables are a desirable
option from a profitability standpoint be-
cause electricity generated by renewables
is increasingly cost-competitive with fos-
sil-fuel generation without the same price
volatility and risk. This is good news for
renewable developers as it increases de-
mand for renewable energy and presents
potential customers. Businesses target-
ing opportunities to purchase renewable
energy have several options: they can
install renewables (usually solar) on site,
purchase renewables directly from a spe-
cific project, or participate in a program
through their designated public utility.
However, the options available to the
company usually depends on the reg-
ulatory scheme applicable to the load
the company wishes to serve. States like
Illinois, Oregon, Texas, California, and
much of the Northeast have deregulated
their electricity markets, meaning that
the traditional system of public utility
monopolies has been replaced with a sys-
tem in which independent electricity sell-
ers can compete with the utility to serve
certain loads. In deregulated states, cor-
porations generally can enter into power
purchase agreements (PPAs) directly with
renewable energy projects; provided that
the customer qualifies for and has opted
into the applicable direct access program
and the seller is eligible to sell. Renewable
energy developers often have the option
to consider serving the load directly or
contracting with the qualified entity that
serves the rest of the corporation’s load.
Tying together the various pieces of the
service obligation and multiple contracts
is complex. In addition, with a pivot
from utility to commercial and industrial
off-takers comes new discussions about
traditional allocations or risks in renew-
able PPAs.
In states that have maintained their
traditional regulatory scheme for public
utilities, renewable developers cannot en-
ter into PPAs directly with corporations.
States long ago granted public utilities
the exclusive right to sell electricity in the
utility’s service territory in order to avoid
duplication of service. This restriction is a
central tenet of traditional public utility
regulation, and is one of the primary dif-
ferences between regulated and deregu-
lated states. Corporations wishing to pur-
chase renewable energy to power facilities
in regulated states depend on public utili-
ties to procure that renewable energy. For
over 20 years, utilities have met requests
for renewables from corporate customers
by offering “green tariffs” to large custom-
ers, charging these customers a premium
for the renewable energy and providing
them with renewable energy certificates
(RECs) so that the corporations can prove
their commitment to renewables.
Corporations are beginning to find
ways to work around restrictions in regu-
lated states. Utilities have begun offering
new green tariffs that are more appealing
to corporate buyers. In Utah, the Legisla-
ture has created an option that blends a
green tariff with a corporate PPA. The En-
ergy Resource Procurement Act, passed
in 2012, allows the customer to select
the renewable energy facility and negoti-
ate the price and RECs directly with the
Regulatory Tips for
Companies Seeking
Green Energy Opportunities
BY JENNIFER MARTIN AND EMMA FAZIO, STOEL RIVES
Jennifer Martin Emma Fazio

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12
ENERGY MATTERS
www.power-eng.com
A
fine line separates propaganda
from effective public relations.
For the last several years, EPA
has adopted a markedly different tone
in press releases and has employed a
more sophisticated social media strat-
egy. To ignore social media would be
foolish in today’s tweet-obsessed cul-
ture; however, EPA may have gone too
far. The Government Accountability
Office (GAO) concluded in a Decem-
ber 14, 2015 decision that EPA “vi-
olated publicity or propaganda and
anti-lobbying provisions…with its use
of certain social media platforms in as-
sociation with its Waters of the United
States (WOTUS) rulemaking…”
At issue is EPA’s use of Thunder-
clap, a “crowd-speaking platform” that
allows a single message to be shared
across multiple Facebook, Twitter and
Tumblr accounts at the same time.
When people join a Thunderclap, they
authorize the app to post a canned
message on their behalf to their so-
cial accounts. Think of Thunderclap
like a digital telephone tree. One per-
son calls three friends who then each
call three friends, who then each call
three friends, and so on. Except with
Thunderclap, social media replaces the
old-fashioned telephone and the elec-
tronic message goes out simultaneous-
ly to thousands of people.
The use of viral content sharing sites
is becoming more common as adver-
tisers, activists and companies aim to
recreate the social buzz that comes nat-
urally to funny cat memes. EPA created
a “campaign” which stated “Clean wa-
ter is important to me. I support EPA’s
EPA’s Thunderclap:
Propaganda
or Publicity?
BY ROBYNN ANDRACSEK, P.E., BURNS & MCDONNELL AND CONTRIBUTING EDITOR
efforts to protect it for my health, my
family, and my community.” When
the campaign reached its goal of 500
supporters, Thunderclap promoted this
message, reaching an estimated 1.8
million people.
GAO describes covert propaganda as
communications that fail to disclose
the agency’s role as the source of infor-
mation. The Thunder-
clap message did not
identify EPA as the au-
thor to the multitudes
of people who received
the Thunderclap and
that was EPA’s error.
By using the first per-
son (“I” and “me”) in
the message, EPA “de-
liberately disassociates
itself as the writer, when the message
was in fact written, and its posting so-
licited, by EPA.” By contrast, GAO de-
termined that EPA’s #CleanWaterRules
and #DitchtheMyth Twitter campaigns
were not propaganda or self-aggran-
dizement since references were made
to “our rule” and the EPA logo was in-
cluded in associated graphics.
Keeping to the theme of modern
communications, EPA responded to
the GAO decision in a strongly worded
blog. In EPA’s perspective, Thunderclap
was a General Services Administration
(GSA) approved platform appropriate-
ly used to catalyze the public engage-
ment process. EPA asserts that they did
not encourage the public to contact
Congress or any state legislature about
the Clean Water Rule. EPA insists they
“won’t back down from our mission”
and resents these “empty attacks.”
Social media is a developing com-
munication avenue that, by design,
evolves quickly. President Obama’s
administration is the first to imple-
ment (and the first to need) an Office
of Digital Strategy, but subsequent ad-
ministrations will surely continue this
department. The laws regulating pro-
paganda were written
for more traditional
avenues of reaching
an audience and are
quickly becoming
outdated. EPA’s own
public outreach began
to expand from dry
press releases as early
as summer 2011 when
EPA issued a press re-
lease entitled “Here’s what they’re say-
ing about the cross-state air pollution
rule.” Instead of news, the content was
a series of quotes from activist groups
such as the American Lung Associa-
tion, Environmental Defense Fund
and the Sierra Club. EPA followed this
up with similar “press releases” about
the Mercury and Air Toxics Standards
rule, Clean Water Act Proposed rule
and Motor Vehicle Emission and Fuel
Standards.
EPA is right that one of the most ef-
fective ways to share information today
is via the Internet and social media;
however, federal law prohibits gov-
ernmental agencies from engaging in
propaganda. This cautionary tale pro-
vides initial guidance for governmen-
tal agencies on where the line is drawn
between publicity and lobbying.
“To ignore social
media would be
foolish in today’s
tweet-obsessed
culture; however,
EPA may have
gone too far.”

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14
NUCLEAR REACTIONS
www.power-eng.com
investments need to be well thought
out and planned.
“We cannot risk creating a situation
in which we want clean, reliable and
affordable electricity, but we are not
able to provide it because we failed to
plan, invest and build when we could,”
Roderick said. “New energy infrastruc-
ture that will last for 50 years or more
cannot be built overnight. We need
careful, long-term
planning of invest-
ments and construc-
tion.”
Both plans have
one major goal in
mind: bring down
the amount of emis-
sions generated by
power plants around
the world. Where nu-
clear fits into these
plans is where ques-
tions arise, though
common sense
would say nuclear power is one of the
best zero-emission and reliable gener-
ating sources to build. However, nei-
ther plan gives any financial help to
offset the high upfront costs to build
a plant, nor do they supply answers
to the issue of market prices not fairly
compensating nuclear. Plant operators
say the increase in installed renewables
on the grid and low natural gas prices
have led to artificially low electricity
prices that do not cover the benefits of
nuclear power, much less normal oper-
ating costs. When those issues are re-
solved, then we can see nuclear power’s
true benefits.
T
wo plans were released in 2015
aimed at cutting emissions
around the world. The plans
have different requirements and meth-
ods of reducing pollutants resulting
from power generation, and they also
have different impacts on the future
development of nuclear power. While
one may be a boon for nuclear new
builds, the other may be a hindrance,
according to some in the industry.
President Obama and the U.S. En-
vironmental Protection Agency in Au-
gust revealed the Clean Power Plan,
which seeks to cut carbon emissions
32 percent below 2005 levels by 2030,
and allows states to create and imple-
ment their own plans to cut carbon
emissions. A federal appeals court in
January denied a stay against the rule,
which means states must move for-
ward with compliance requirements
and deadlines. However, several state
lawsuits challenging the plan are still
pending.
Some say the plan does not boost the
U.S. nuclear industry because it does
not recognize the value of nuclear’s
zero-carbon power generation. Accord-
ing to the Nuclear Energy Institute, the
rule also does not give credit for license
extensions. The rule does say, however,
that more premature shut downs of nu-
clear plants are expected in the future,
which would actually increase emis-
sions if the lost capacity is replaced
with natural gas. The final rule does
not consider the five reactors currently
under construction in the U.S. – Watts
Bar 2 in Tennessee, Vogtle 3 & 4 in
Georgia and Summer 2 & 3 in South
Carolina – in the goal setting calcula-
tion. When they are operational, they
will count toward compliance.
The second plan was reached at the
COP21 climate change talks in Par-
is, in which 196 countries agreed to
reduce greenhouse gas emissions to
a level that will limit the rise of the
global average temperature to well be-
low 2 degrees C (3.6 F) of pre-indus-
trial levels by 2030.
The reductions mean
nations will have to
lower their use of
fossil-fueled generat-
ing sources like coal,
oil and gas, and rely
more on low-car-
bon emitters, such
as renewables and
nuclear. The agree-
ment also calls for
developed countries
to fund $100 billion
a year to developing
countries starting in 2020 that is ex-
pected to increase over time. Every five
years, the nations will be required to
assess and report on their progress.
Westinghouse said in a release that it
believed the COP21 agreement would
be the shot in the arm that the nuclear
industry needs.
“The message from COP21 is clear:
it’s time to redirect investment and fi-
nancing from carbon-intensive fossil
fuels to building a new generation of
nuclear power plants for security of fu-
ture energy supply,” said Westinghouse
President and CEO Danny Roderick.
Roderick pointed out that these
COP21 vs. Clean Power Plan:
Which Benefits
Nuclear More?
BY SHARRYN DOTSON, EDITOR
New energy
infrastructure that
will last for 50 years
or more cannot be
built overnight.We
need careful, long-
term planning...
- Westinghouse President
& CEO Danny Roderick

16 www.power-eng.com
ONSITE POWER
BY ANNE HAMPSON
Packaged CHP systems
are pre-engineered and
assembled at the factory
for optimal operation,
and they can be placed
into service at a host
facility in a short amount
of time because they
require little on-site as-
sembly. Photo courtesy:
ICF International
emerged that are shifting the economics
and value proposition for CHP in the
US. This is already leading to increasing
levels of CHP deployment, and a shift
in its achievable potential ahead.
So how big is this potential, and what
does it look like? Determining the true
market for CHP can be a challenge. It
requires estimates of the technical, eco-
nomic, and likely achievable potential
for additional CHP installations—no
small task in some areas, and with
many variables to consider. The current
state of the market and starting point
for any analysis can be seen in the U.S.
Department of Energy CHP Installa-
tion Database (managed by ICF, and
available at: https://doe.icfwebservices.
com/chpdb/), which tracks CHP instal-
lations throughout the country, provid-
ing data on market trends and growth.
Traditionally, large industrial facilities
have been the primary CHP adopters,
accounting for 86 percent of currently
installed capacity (71GW). Commer-
cial and institutional facilities make
up the remaining 14 percent
(about 12 GW). However, a
shift may be coming.
Looking forward at the re-
maining technical potential for CHP,
we see a much different split, with in-
dustrial facilities accounting for about
45 percent and commercial/institution-
al facilities accounting for 55%. This
means that the future is smaller: the av-
erage system size of the remaining CHP
potential is significantly lower than
the average size of currently installed
systems. The total of this technical
potential in the United States ranges
in estimates between 110 – 160 GW for
systems that use all of their energy out-
put onsite. However, even beyond that
impressive figure, for some facilities
that use more thermal energy (typically
in the form of steam compared to elec-
tricity) a CHP system can be sized to
allow export of excess electricity to the
T
here’s a hot new technol-
ogy in energy. It’s driv-
en by rapidly improving
economics, better prod-
uct offerings that are
far easier to use, and innovative new
business models that can bring turn-
key solutions right to customers. It has
the potential to provide a quarter of
our power generation. It’s been making
waves in the market, and signs point to
more vigorous growth ahead. Except
this technology is not new. And it’s not
what you’re thinking.
Combined heat and power (CHP)
gets fewer headlines and has a lot less
sizzle than some other distributed en-
ergy technologies, but when you break
down the numbers, it delivers. The
basic concept goes all the way back
to Thomas Edison, who employed it
himself in his first commercial power
station. Over the ensuing years, CHP
has made serious inroads into our na-
tion’s power and heat supply, providing
electricity and thermal energy for over
4,400 commercial and industrial facili-
ties around the country. In fact, there is
currently over 82 GW of CHP capacity
installed in the US, accounting for 12
percent of electricity production and 8
percent of power generation capacity.
And while this is a lot more than most
people realize, it’s not anywhere near
the technology’s full potential. In fact,
a variety of game-changing factors have
Analyzing
the Potential
of CHP in
North America

17www.power-eng.com
The Potential for Additional CHP is Nationwide
CHP Technical
Potential (MW) 1,000–3,000 MW >5,000 MW
<1,000 MW 3,000–5,000 MW
Author
Anne Hampson is senior manager at ICF
International.
The spark spread is a metric used to
evaluate the cost effectiveness of a CHP
system based on the difference between
fuel and electricity prices. The larg-
er the spread, the more cost savings a
CHP system will provide. California
and the Northeastern states have tra-
ditionally been the primary targets for
CHP due to their high electricity prices
and moderate fuel prices. As natural
gas prices have decreased and electric-
ity prices have either remained stable
or continued to increase, more regions
of the country are showing favorable
spark spreads for CHP. The Midwest in
particular is a region where high levels
of technical potential are meeting in-
creasingly favorable economics, which
is leading to more projects under devel-
opment.
Packaged CHP Systems
As with any asset investment, one of
the primary barriers to CHP develop-
ment has been the high upfront capi-
tal cost of the system, especially when
considering that they are installed at
facilities whose core business is some-
thing other than power generation.
Traditionally, CHP systems have been
local utility. When accounting for this
excess electrical capacity, the potential
for CHP could increase by another 75 –
125 GW. In sum then, there is a very
substantial 185 – 285 GW of deploy-
able CHP in a country that has just over
1,000 GW of current electric generating
capacity. These estimates will be further
refined in an upcoming study to be re-
leased by the U.S. Department of Ener-
gy on the current amount of technical
potential for CHP in the United States
on a state-by-state basis.
Furthermore, unlike other clean ener-
gy technologies that are confined by the
availabilityoftheresourceitself(i.e.hours
of sunlight, or presence of wind), CHP
can use any combustible fuel. Therefore,
the technical potential for CHP is con-
strained only by the amount of energy
consuming facilities that can use both its
electric and thermal outputs.
Of course, estimating the technical
potential for additional CHP is only the
first step in analyzing the CHP market,
as it provides the universe for what is
capable of being served by the technol-
ogy. It’s an estimation of market size
constrained only by technological lim-
its—the ability of CHP technologies to
meet existing customer energy needs.
The technical potential does not consid-
er other factors such as economics, abil-
ity to retrofit, owner interest in applying
CHP, capital availability, and variation
of energy consumption within custom-
er application/size classes. All of these
factors affect the feasibility, cost and
ultimate acceptance of CHP at a site,
which are evaluated in the later stages of
economic and likely achievable poten-
tial analysis. But when we look at those
areas, we see the scales tipping quickly
and significantly in CHP’s favor.
ECONOMIC
GAME-CHANGERS
The evaluation of economic poten-
tial for CHP is not as straightforward as
the technical potential. The outcomes
depend a lot on the assumptions that are
used in its calculation (which can also
vary significantly from region to region).
Economic potential is also hard to char-
acterize because the term “economic”
means different things to different peo-
ple. Some companies would not consider
a CHP system to be economic unless it
had a payback period of less than 2 years,
whereas other companies would consider
a system to be economic at a 5-7 year pay-
back — which, when considered against
other energy technologies, is very compa-
rable and quite competitive.
All of the economic trends are point-
ing in the right direction for robust
growth in CHP’s economic potential
and actual deployment: systems are be-
coming more affordable due to low nat-
ural gas prices, new packaging options,
innovative business models, and the
potential for additional revenue streams
for their environmental attributes and/
or electric system benefits.
Natural Gas Prices
Natural gas, the preferred fuel for
CHP, has been selling at record low
prices, which is creating favorable spark
spreads in many regions of the country.

ONSITE POWER
from distributed CHP installations –
not only from reduced congestion on
transmission and distribution lines, but
from demand response and ancillary
services such as voltage and frequency
regulation. These services can poten-
tially be monetized and utilized as a
source of revenue for CHP customers,
with regional transmission organiza-
tions like PJM offering market-based
compensation for customer-generators
that can provide demand response and
ancillary services for the system. States
like New York and California are work-
ing hard on developing distribution
level markets for such services. These
markets are still a work in progress,
however, they show strong promise to
provide additional revenue streams to
CHP systems, further enhancing project
economics.
EXPECTED ACHIEVABLE
POTENTIAL
The expected achievable potential
for CHP is the final step to creating a
forecast of how much CHP will be de-
ployed. After the economic potential
is calculated (shown by grouping the
technical potential capacity into rang-
es based on their expected payback)
the results are multiplied by typical
customer acceptance factors to esti-
mate the amount of CHP capacity that
would actually be installed. Customer
acceptance of a clean energy technol-
ogy can be highly variable and takes
into account the fact that even at very
low paybacks (and high rates of re-
turn), some customers would still not
move forward with an installation. In
a recent analysis for the Pew Charita-
ble Trusts, ICF concluded that 18 GW
of CHP could be expected to enter the
market by 2030, based on current eco-
nomic conditions. As the economics
for CHP continue to improve and cus-
tomers become more comfortable with
new business models, the potential re-
mains for deployment at an even great-
er level.
custom-engineered for each installa-
tion, a process that involves ordering
all the components separately and then
assembling it onsite. This process can
be slow and expensive, and has been
described by Dana Levy at the New
York State Energy Research and Devel-
opment Authority (NYSERDA) as akin
to purchasing all the parts at an auto
supply store and going home to assem-
ble your car.
Packaged systems are dramatically
changing that story for smaller CHP sys-
tems. Most CHP technologies are fairly
mature, so rather than seeing reductions
in cost coming from the prime mover
technology itself, they are coming from
innovative ways of packaging the tech-
nology with the heat recovery system,
generator, and controls all in one package
so that the unit can be installed at a lower
cost. These packaged systems are pre-en-
gineered and assembled at the factory for
optimaloperation,andtheycanbeplaced
into service at a host facility in a short
amount of time because they require little
on-site assembly. Packaged units can also
be stacked together to make larger capac-
ity systems which increase the operation-
al flexibility and reliability of the overall
system. These attributes, coupled with
standardized controls and monitoring
software are making pre-packaged CHP
systems less expensive to install, operate
and maintain.
While there are many US companies
pursing the packaged CHP market, there
has been a notable increase in European
companies that are entering the US mar-
ket and utilizing their experience from
Europe, where small packaged CHP sys-
tems are a much more common practice.
Packaged system developers are also tak-
ing advantage of the replicability of these
systems to attract hotel, supermarket, and
assisted living community chains that
can deploy a portfolio of systems at mul-
tiple facilities.
Innovative Business Models
As distributed generation systems
like CHP have received higher levels
of recognition, many developers have
started offering leased system options
or “build, own, and operate” business
models for their customers. With these
offerings, the developer pays for all of
the up-front costs of a CHP installation,
and the customer only pays for the de-
livered energy, typically at a guaranteed
discount compared to local utility costs.
Think of it as SolarCity for CHP. The de-
veloper owns and operates the CHP sys-
tem, providing remote monitoring and
all system maintenance at no additional
cost to the customer. While this busi-
ness model has been around for a while
it has become more prominent given its
relative recent success in the solar pho-
tovoltaic market. Innovative business
models can make CHP systems a much
more attractive proposition for small to
medium-sized businesses that are hesi-
tant to commit to a large capital invest-
ment or to what can be a complicated
process of working out the technical is-
sues for their site. The transfer of own-
ership and operational risk from the
end-user to the developer is also bring-
ing in customers that would not other-
wise consider generating on-site power.
Additional Revenue Streams
CHP systems reduce greenhouse gas
emissions by producing power and heat
more efficiently than central utility sys-
tems that may still rely on coal for power
generation. The avoided consumption
of utility electricity from CHP custom-
ers can add up to significant amounts of
prevented emissions over time. While
markets for greenhouse gas emissions
have been slow to develop in the U.S.,
they could potentially provide a valu-
able source of revenue for customers
with CHP systems. And now, as states
are confronted with designing pro-
grams to bring them into compliance
with EPA’s Clean Power Plan, CHP, like
many other clean energy technologies,
may be able to sell its positive environ-
mental attributes, delivering additional
value to system owners.
Additionally, utilities can benefit

www.power-eng.com 19
Boilers – Critical
Process ComponentBY SCOTT LYNCH, PRESIDENT AND CEO, ABMA
major injuries. This risk far outweighs
the cost of proper maintenance as down
time can cost companies millions in lost
productivity.
UPGRADING A BOILER
In many cases, the boiler shell will
outlast many of the component parts.
With technological advances and ever
changing environmental regulations, it
is important to explore boiler upgrades
on a regular basis. There are times when
an upgrade can pay for itself in just a few
years, maybe even months with energy
and fuel savings. There is also an op-
portunity to explore additional upgrades
whengoingthroughacompliancereview.
PURCHASING
A NEW BOILER
Whetheraboilerneedstobepurchased
to replace on old unit or expansion is on
the horizon, there are great opportunities
to purchase the ideal boiler system for an
end-user’s needs.
An end-user may know best what it
needs from a boiler, but a boiler manu-
facturer understands today’s technol-
ogy and how to create a boiler that offers
the best value while addressing unique
challenges. Collaboration is important
early in the process to ensure high perfor-
mance and cost-effective decision.
Large boilers for industrial, commer-
cial and institutional use are not widgets,
they are highly engineered, extremely
customized complex systems. The design
and build process does not take days, it
takes months and boiler manufacturers
investment significant time and resourc-
es to create each system. Purchasing the
proper boiler and instituting a textbook
maintenance schedule, will enable this
investment to serve the needs of an end-
user for decades to come.
ABMA and its members cannot change
perceptions overnight and we don’t plan
to create Super Bowl commercials any-
time soon. Our goal is to move the needle
and personalize our message to the needs
of various audiences, and we are confi-
dent that this educational campaign will
lead to a more successful industry and ad-
vance the safety of our products.
As an association, ABMA is partner-
ing with marketing firm Larnish Larsen
to create awareness and highlight the
critical nature of the boiler industry and
ensure that there is an understanding
of why boilers are so important, what is
needed to properly maintain a boiler and
how investing in a boiler room can offer
many benefits and potential long-term
cost savings to an end-user.
T
hink about a hospital that
isn’t able to sterilize its
medical equipment, the
college campus with no
hot water for their thou-
sands of students or the food processing
plant that cannot make steam and pro-
duction comes to halt. These are all re-
alities without fully operational boilers.
In many cases, the boiler is thought of
as that room in the basement that does
what we need it to do. But our industry
knows that there is much more to this
story and ABMA has decided it is time
to focus our efforts on moving percep-
tions toward reality.
So why is the boiler room “that room
in the basement”? In many cases, the
boiler room is not seen as a critical com-
ponent of the business. A hospital is wor-
ried about saving lives, a college campus
is investing in educating future leaders,
and a food processing facility is focused
on its product development.
MAINTAINING A BOILER
I hear all the time that lack of regular
maintenance is a top reason for the break
down and replacement of boilers. With
proper care and maintenance, a boiler
can run efficiently for years and years.
But in many cases, the dollars to properly
maintain a boiler room are not allocated
and operators are not properly trained.
Over time, the boiler goes into disrepair
or in the worst cases, explodes, costing
companies significantly more dollars and
ABM
A
SpecialSection
Scott Lynch

ABM
A
SpecialSection
industry commentary, utilities now
have the regulatory clarity necessary
for compliance strategy development,
technology selection, budgeting, per-
mitting, scheduling and ultimately
project implementation. As a result,
numerous utilities are now moving
forward with project planning and ex-
ecution in accordance with the compli-
ance requirements and deadlines. Proj-
ect activity presently includes existing
CCR impoundment stabilization,
dry landfill expansion/construction,
W
ith the final is-
sue of the Envi-
ronmental Pro-
tection Agency
(EPA) Coal
Combustion Residual (CCR) rules on
April 17, 2015 and the Steam Electric
Power Effluent Limitations Guidelines
(ELG) on Nov. 3, 2015, utilities now
have defined compliance requirements
for post-combustion solid waste man-
agement, groundwater and surface wa-
ter and wastewater management.
After nearly five years of data collec-
tion, technology and cost evaluations,
draft rulemaking, public comment and
Dry Ash
Conversions
Implications, Options and Technical
Considerations for CCR & ELG Compliance
BY KEVIN L. MCDONOUGH

21www.power-eng.com
groundwater monitoring, fly ash and/
or bottom ash wet-to-dry conversions,
gypsum dewatering, wastewater treat-
ment and overall plant water balance
management. This activity is expected
to continue in earnest for the immedi-
ate three to five years and largely con-
clude in 2023 at the close of the ELG
compliance window.
The CCR rules target benefits such
as ground water protection and the
prevention of CCR impoundment
catastrophic failures. As opposed to
the initial draft rule, which was more
focused on the closure of surface im-
poundments, the final rule was issued
with a more defined set of criteria by
which coal unit operators could contin-
ue to utilize surface impoundments as
an alternative to complete wet-to-dry
conversions. Its focus is based on the
following implementation timeframes
from the publication of the rule: a) lo-
cation restrictions (aquifer, wetlands,
fault zones, seismic zones and unstable
areas): 42 months; b) design criteria
(lined/unlined, leaking/not leaking,
structural integrity): 18 months; c) op-
erating criteria (flood control, fugitive
dust control, inspections): six to 18
months; d) groundwater monitoring
and corrective action: 30 months; e)
closure requirements and post-closure
care: 36 to 162 months; and f) record-
keeping, notification and internet
posting: 6 months.
The ELG rule seeks to strengthen
the controls on discharges from steam
electric power plants by revising tech-
nology-based effluent limitations
guidelines and standards for the steam
electric power generation industry.
It also seeks to reduce the amount of
potentially harmful metals and other
pollutants discharged to surface wa-
ter (direct discharges) and publicly
owned treatment works (indirect dis-
charges to POTWs). Targeted waste-
water streams include Flue Gas Desul-
furization (FGD) Wastewater, Fly Ash
and Bottom Ash Wastewater, Flue Gas
Mercury Control (FGMC) Wastewater,
Combustion Residual Leachate from
Landfills and Surface Impoundments,
Nonchemical Metal Cleaning Wastes
and Coal and Pet Coke Gasification
Wastewater. According to the EPA, Best
Available Technology (BAT) compli-
ance technologies include chemical
precipitation, biological treatment,
evaporation, dry handling and prop-
erly designed surface impoundments
for the differing waste streams. For
fly ash and bottom ash, however, the
technology basis for compliance is dry
handling or closed-loop zero liquid
discharge (ZLD) systems for all units
>50MW, with the exception that fly ash
and bottom ash transport waters can
be used as a source of FGD process wa-
ter. For generating units <50MW, the
ash systems must meet Best Practicable
Technology (BPT) requirements that
include Total Suspended Solid and Oil/
Grease limitations in the ash effluent
wastewater streams. The rule mandates
This Continuous Dewatering
and Recirculation (CDR™) from
United Conveyor Corp was recently
commissioned at a plant in the
Southeast region of the US. The
technology combines the benefits
of a recirculation system and the
proven technology of a submerged
flight conveyor.Photo courtesy:
United Conveyor.
Author
Kevin L. McDonough is Vice President of
Sales & Marketing for United Conveyor

Our boiler manufacturing experience and passion for customer service has made a
significant difference to our customers, who include the largest independent power
producers, refining, petrochemical, and industrial companies in North America. At
RENTECH, we aren’t resting on our reputation – we are continually building one!
MARKET LEADER IN LARGE FIRED PACKAGED BOILERS
Over the past four years, we have supplied more large fired packaged boilers than
any other manufacturer in the North American market for units > 100,000 lb/hr
in size. Our Packaged Boiler design has been specified time and again for critical
industrial processes, turbine warm-up and auxiliary boiler applications because of its
rugged design and proven reliability. 100% Membrane Wall construction eliminates
the need for refractory and enables quick start-up to achieve full steam capacity of
the boiler in a fraction of the time that it takes with older designs. In addition to
significantly reducing maintenance and operating costs, a water-cooled membrane
wall furnace offers further benefits in reducing emissions.
INTEGRATED SOLUTIONS FOR ACHIEVING LOWER EMISSIONS
Our approach to achieving lower emissions starts with optimization of the boiler
design. Coupled with RENTECH’s knowledge of low emissions burner and catalytic
reduction technologies, we are capable of supplying a system that fully complies
with all performance criteria and is backed by a single-source guarantee.
HRSGS FOR SMALL- AND MEDIUM-SIZED GAS TURBINES
We specialize in, and are the largest supplier of, HRSGs for today’s high-efficiency
gas turbines that operate in the 3-40 MW size range. Our expertise in high-
fired applications incorporates full optimization of the duct-burner performance
while utilizing Catalytic Oxidation and SCR for control of emissions from the
entire system.
RENTECH BOILER SYSTEMS CONTINUES TO LEAD THE INDUSTRY
IN PRODUCING NEW, INNOVATIVE BOILER DESIGNS.
Design Features:
100% headered membrane water wall
construction
No refractory walls or seals
Fully drainable Convective Super-heater that
eliminates the problems associated with radiant
designs
Customized designs for applications requiring
lowest emissions
Standard 5-year warranty on front and rear
furnace walls
Turnkey Capabilities:
Integrated Low NOx Burner and SCR/CO catalyst
systems guaranteed to achieve less than 5 ppmvd
Installation and start-up services
Comprehensive engineering and design evaluation
of other boiler systems
Rebuilds, upgrades and major modifications of
existing boilers
FIRED BOILERS HRSGs WASTEHEAT BOILERS SCR AND CO SYSTEMS
INDUSTRIAL WATERTUBE BOILERS
WASTE HEAT BOILERS SCR SYSTEMS

ABM
A
SpecialSection
handling systems, along with the de-
commissioning of existing wet back-up
systems. Utility operators may elect to
install additional redundancy for pri-
mary dry systems that currently utilize
wet back-up systems.
In contrast to fly ash, many installa-
tions presently utilize wet sluicing sys-
tems to transport bottom ash from the
operating units to surface impound-
ments. Due to the traditional coal unit
boiler and associated bottom ash hop-
per designs, wet-to-dry conversions
pose numerous unique design consid-
erations, such as boiler operating seal
requirements, spatial limitations both
under the boiler and beyond the walls
of the powerhouse, water balance re-
quirements, as well as unit outage con-
siderations.
Although the technical and eco-
nomic criteria is unique to a given
plant, consideration must be given to
flexibility to account for typical plant
operating conditions and maintenance
activities. Specifically, the ELG notes
that “transport water does not include
low volume, short duration discharges
of wastewater from minor leaks (e.g.
leaks from valve packing, pipe flang-
es, or piping) or minor maintenance
events (e.g., replacement of valves or
pipe sections).”
The overwhelming majority of util-
ity installations currently utilize dry
handling systems for fly ash (>85%).
These positive and negative pressure
pneumatic systems in various dilute
and dense phase conveying regimes,
have been proven to be highly reliable
systems if properly designed, operat-
ed and maintained consistent with
fuel/ash characteristics and plant op-
erating conditions. The new ELG re-
quirements will likely result in dry
ash conversions for any remaining wet
a compliance timeframe that is “as
soon as possible beginning November
1, 2018, but no later than December 31,
2023”. Under the implementation ap-
proach, each state (permitting author-
ity) shall confirm the required compli-
ance date within the defined window
with particular consideration for ex-
isting National Pollutant Discharge
Elimination System (NPDES) permit
validity dates and sufficient timelines
for implementation. The combination
of the CCR and ELG requirements will
likely drive dozens of wet-to-dry con-
versions, pond closures, along with
dry landfill and wastewater treatment
projects. In fact, numerous projects are
currently underway.
While the ELG does mandate ZLD
requirements for both Fly Ash and Bot-
tom Ash transport water, it is worth
noting that the EPA has attempt-
ed to incorporate some operational
This Continuous Dewatering and Recirculation
(CDR™) system from United Conveyor Corpora-
tion is installed at a plant in South Carolina. The
technology was the preferred wet-to-dry conver-
sion option due to physical limitations underneath
the boiler. Photo courtesy:United Conveyor.

25www.power-eng.com
Available Technologies (BAT) noted in
the ELG, UCC has implemented vari-
ous technologies throughout the U.S.
utility coal fleet, which are summa-
rized below.
UNDER BOILER
SUBMERGED FLIGHT
CONVEYOR (SFC) SYSTEM
System Overview:
The SFC collects bottom ash from
the boiler into a water-filled trough
where it quenches and cools the ash.
Horizontal flights move the ash con-
tinuously through the trough and up
a dewatering ramp where it is then
discharged into a load-out bunker or
secondary transfer conveyor. Bottom
ash is typically allowed to dewater in
the bunker to 15 percent or 20 percent
moisture, which is ideal for fugitive
dust emission control and landfill com-
paction. In addition, the SFC produces
a dewatered product with a consistent
particle size distribution suitable for
beneficial reuse. Overflow water from
the SFC trough is commonly captured,
cooled and recirculated to complete a
zero liquid discharge system, although
the final ELG allows some flexibility
for the management of cooling water
overflows. The under boiler SFC has
been the industry standard on new
units for the past few decades. In ad-
dition, numerous utilities have suc-
cessfully retrofitted SFCs on existing
units. The SFC is a proven bottom ash
system and a cost-effective solution
when long-term life cycle costs are a
major decision factor and when ex-
isting bottom ash hoppers may be in
need of repair. Feedback from existing
reference installations has indicated
that maintenance costs for an SFC Sys-
tem are only 1/3 that of a conventional
water-impounded bottom ash hopper
and sluice conveying system.
System Design Considerations:
The key variables that determine
viability for an SFC retrofit include
available physical space and planned
and distance, ash marketability/bene-
ficiation, unburned carbon concerns,
ash characteristics, physical param-
eters, multiple unit synergies, plant
water balance and maintenance re-
quirements. Due to the extent and
complexity of the project variables, it
is also critical to select a technology
provider with sufficient experience,
proven reference installations and ex-
ecution capacity to meet the needs of
the plant within a defined timeframe.
Relative to the survey of Best
a multitude of variables in order to de-
termine the optimal solution for com-
pliance. Accordingly, a single technical
solution does not necessarily translate
to all bottom ash applications (i.e. “one
size does not fit all”). Therefore, select-
ing the most appropriate technical al-
ternative requires careful evaluation
of a combination of factors including:
schedule requirements, site impacts,
spatial constraints, budget, outage re-
quirements, site environmental con-
siderations, ash conveying capacities
The patented 100% Dry Pneumatic
Ash Extractor (PAX™) from United
Conveyor is installed at a plant in
the Eastern US,as they preferred a
conversion solution that removed
water as a conveying medium.
Photo courtesy:United Conveyor.

ABMA
Special Section
www.power-eng.com
enhancements, including improved
dewatering elements, valves and op-
erational sequencing, have addressed
many of the performance concerns.
If designed, operated and maintained
properly, this technology still rep-
resents a viable wet-to-dry conversion
solution, and particularly if a plant
currently has existing dewatering bins
installed as a means of coarse particu-
late separation with overflows directed
to an operating surface impoundment.
In this scenario, the system can be ret-
rofitted to a closed-loop system with
the addition of settling and surge tanks
and associated return water pumps,
valves and piping. Several units have
recently been converted using this
approach and are in compliance with
the ELG zero liquid discharge require-
ments.
Due to the scope of the system – in-
cluding multiple tanks, overflow pip-
ing, underflow piping, valves, pumps,
etc. – system controls and associated
operation can be complex. Redundan-
cies must also be balanced with added
complexity. In addition, these systems
can retain ash in solution for extend-
ed periods of time, often numerous
days and even longer in certain cir-
cumstances. In these cases, additional
consideration has to be given for the
water quality/chemistry in a closed-
loop system, particularly relative to
the zero liquid discharge requirements
outage schedules. Many existing boil-
ers do not possess the physical space
to accommodate an SFC retrofit due to
limited headroom between the boil-
er throat and grade, deep bottom ash
hopper pits, structural steel interfer-
ences, equipment/ductwork interfer-
ences around the bottom ash hopper or
limited space outside the powerhouse
wall for storage, truck traffic or ash
transfer. In addition, this retrofit will
require removal of the existing bottom
ash hopper and associated equipment.
As such, the retrofit typically requires
a 6-8 week outage for successful proj-
ect execution. If the SFC cooling water
overflows are captured in a closed-loop
system, the system must be designed to
ensure that the water temperatures are
maintained at appropriate levels, often
requiring some form of heat exchanger
in the hydraulic system.
DEWATERING BIN SYSTEM
System Overview:
Conventional dewatering bin sys-
tems, often with associated settling
and surge tanks, have been implement-
ed throughout the U.S fleet since the
1960s and represent the traditional
approach to bottom ash closed-loop
design. Dozens of these systems
are currently in operation, although
performance issues related to main-
tainability and operability have been
noted for these prior generation de-
watering solutions. Recent design
This under-the-boiler Submerged
Flight Conveyor (SFC™) by United
Conveyor is installed at a plant in
Midwest. Numerous utilities have
successfully implemented the SFC
technology which has been the
industry standard on new units for
the past few decades.Photo courtesy:
United Conveyor.

www.power-eng.com
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of ELG. Plants must determine and
specify their desired approach for wa-
ter sampling and analysis for ongoing
water quality management, which can
be accomplished via additional system
instrumentation and continuous mon-
itoring or intermittent sampling and
analysis. To manage unanticipated
excursions in water quality, the system
can also be designed with blowdown
provisions; in particular, bottom ash
sluice water can be used as a FGD sys-
tem makeup water source or as a dry fly
ash conditioning water source.
CONTINUOUS
DEWATERING AND
RECIRCULATION (CDR)
SYSTEM
System Overview:
The Continuous Dewatering and Re-
circulation (CDR) system with Remote
Submerged Flight Conveyors (R-SFC)
is a preferred wet-to-dry conversion
option for installations that have phys-
ical limitations underneath the boilers
and seek to minimize costly outage-re-
lated activity, while also realizing the
benefits of the SFC, which produces a
highly consistent dewatered bottom
ash product.
The CDR system is designed to re-
ceive existing sluice conveying lines
and divert the bottom ash slurry to a
remote dewatering conveyor located
outside of the powerhouse. Materi-
al is collected, dewatered and then
discharged into a load-out bunker or
secondary transfer conveyor to a con-
dition that is favorable for transport to
and compaction in a dry landfill. In
addition, the CDR system can be read-
ily designed to ensure that beneficial
reuse products can be separated.
After completing a fine particulate
settling phase, the sluice water is then
pumped back to the boiler house to
complete a closed-loop, zero-liquid
discharge system. The CDR system
has been designed to address the com-
plexities of a bottom ash water balance,
considering multiple flow sources, in-
termittent conveying cycles and vari-
able flow rates. The conversion option
is highly favorable when considering
physical space limitations underneath
the boiler and maintaining plant avail-
ability, as this can be implemented
with little to no outage requirements if
commissioning is planned and execut-
ed properly.
For CDR systems, R-SFC location,
conveying distance and hydraulic
profile are key variables in the proper
design of the closed-loop system. Ac-
cordingly, pump selection, sizing and
quantity are key factors in the system
design. Experience is essential to prop-
erly select pumps that balance the flow
and pressure requirements with the an-
ticipated water quality.
As with the dewatering bin system,
additional consideration has to be
given for the water quality/chemistry
in a closed-loop system, particularly
relative to the zero liquid discharge
requirements of ELG. Plants will need
to monitor water quality in the closed-
loop system.
Should an installation have a par-
ticle size distribution that has an in-
creased concentration of fines in the
bottom ash water recirculation system
(e.g. finer bottom ash, economizer
ash, etc.), the CDR system can also be
scaled to provide for additional settling
area, additional mechanical particu-
late separation and/or polymer addi-
tion to reduce TSS concentrations in
the recirculating water.
CDR SYSTEM
WITH CLARIFIER
System Overview:
The CDR System with clarifier
matches the system described above,
but with an additional clarification
phase that reduces the Total Suspended
Solids (TSS) concentration in the bot-
tom ash transport water. The addition-
al clarification phase is provided by

ABM
A
SpecialSection
most appropriate relative to key vari-
ables including existing system oper-
ation, fly ash and
bottom ash benefi-
cial reuse and cost.
In any case, econ-
omizer ash can be
incorporated into
the dry fly ash or
dry bottom ash sys-
tems with proper
consideration for
generation rates,
particle size distribution and unique
material characteristics.
MILL REJECTS (PYRITES)
IMPLICATIONS
The CCR and ELG rules made no new
distinctions for mill rejects, as these are
not included in the definition of coal
combustion residuals.. The majority of
existing Mill Reject (Pyrites) removal
systems currently use sluice conveying
systems for removal and most are con-
nected in some manner to the existing
bottom ash sluice conveying systems and
discharged to surface impoundments. In
any case, the Mill Reject systems can be
readily tied into SFC, CDR or Dewatering
Bin Systems or can be segregated via inde-
pendent systems to allow for bottom ash
separation and beneficial reuse.
CONCLUSION
While the final Coal Combustion
Residual and Effluent Limitations
Guidelines present challenging regu-
latory requirements for new and exist-
ing coal unit installations, numerous
options are available to achieve com-
pliance, and in many cases improve
system operations with newer technol-
ogies. A careful evaluation of multiple
alternatives, with consideration for
each unique set of plant operating and
design criteria can result in an optimal
selection of a safe, reliable and cost-ef-
fective compliance solution for fly and
bottom ash handling.
means of a thickener/clarifier located
downstream of the remote submerged
flight conveyor (R-SFC) with polymer
addition. This technology selection is
suitable for installations that anticipate
a higher concentration of fines in the
ash particulate or require lower TSS
levels suitable for certain types of recir-
culation pumps.
If the plant desires to keep exist-
ing high pressure “clean water” slurry
pumps in operation, the CDR System
with clarifier is highly effective in pro-
ducing water quality (TSS) suitable for
these types of pumps. In addition, this
system, while likely higher in both
capital and operating cost, will provide
greater control in water quality should
the bottom ash sluice water be needed
as a source for FGD makeup or dry fly
ash conditioning water.
PNEUMATIC ASH
EXTRACTOR (PAX) SYSTEM
System Overview:
The patented UCC PAX Pneumatic
Ash Extractor is a preferred wet-to-dry
conversion alternative when a plant
desires to convert from the traditional
water-impounded hopper design and
eliminate water usage for the bottom ash
systems. As a 100% dry solution, the
PAX system is particularly ideal for in-
stallations that have physical limitations
under the boiler. For this technical alter-
native, bottom ash is collected dry in a
refractory-lined hopper under the boiler.
Percolating air cools the ash to help com-
plete combustion of unburned material
and protection of ancillary equipment.
As the ash cools, it is crushed then fed
into a pneumatic vacuum conveying line
and transported to a storage silo or trans-
fer station for dry bottom ash unloading.
One of the important design features
of the PAX system is the design of the
dry, refractory-lined hopper. Simi-
lar to traditional systems, this multi-V
hopper provides for system redundancy
and operational flexibility during upset
conditions. The
system can also be
designed with ad-
ditional boiler iso-
lation features that
provide improved
reliability.
For PAX sys-
tems, vacuum con-
veying distance
and Dry Bottom
Ash Silo location are key variables in the
proper design of the conveying system.
In addition, ash characteristics (specific
gravity, density, chemical constituents,
etc.) and generation rates are also of es-
sential importance in system sizing and
equipment selection.
Several utility clients have recently se-
lected PAX as their preferred bottom ash
compliance technology and several oth-
ers are actively investigating its potential
application. Utility feedback indicates
that the condition of the existing bottom
ash hoppers, long-term life cycle cost
analysis and environmental risk analysis
are key factors in the PAX system evalua-
tion. Based on favorable field data from
operating references on O&M costs, the
PAX option may be ideal if existing bot-
tom ash hoppers need to be significant-
ly repaired/replaced and/or an owner
wants to remove bottom ash sluice water
from their environmental risk profile to
address current ELG requirement and
longer term regulatory exposure.
ECONOMIZER ASH
IMPLICATIONS
The new rules made no new distinc-
tion for economizer ash. As presently
defined, economizer ash is considered
fly ash when “it is collected with the
fly ash systems” and bottom ash when
“it is collected with the bottom ash sys-
tems.” With this apparent regulatory
flexibility, plants will have the option
to manage economizer ash as is deemed
“Economizer ash can
be incorporated into
the dry fly ash or dry
bottom ash systems with
proper consideration
for generation rates,
particle size distribution
and unique material
characteristics.”

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OWNED&PRODUCEDBY PRESENTEDBY SUPPORTEDBY

ABM
A
SpecialSection
How to Deal
with Ceaseless
Slagging
BY RUSSELL RAY, CHIEF EDITOR
I
t’s no secret that excessive boiler
deposits can lead to serious reli-
ability and performance issues
for power plants. Regular boiler
maintenance that includes thor-
ough boiler cleaning will
lead to lower operating
costs, reduced fuel con-
sumption, greater effi-
ciency, and a longer lifespan of the boiler.
Over time, the burning of coal, bio-
mass and other solid fuels creates molten
ash. The ash accumulates to create a stony
ABM
A
SpecialSection

31www.power-eng.com
compressed air. But these soot blower sys-
tems are powerful and can cause erosion
if they are used on a slag-free section of
tubing.
Power producers have been using soot
blowers to clear their boilers of slag for
decades. But modern-day soot blowing
systems are more sophisticated than tra-
ditional systems. The goal is to provide
just enough pressure to clean the tube
and avoid causing damage.
Intelligent soot blowing systems func-
tion only when the furnace walls and
boiler tubes need to be cleaned. This
technology prevents boiler tube erosion
caused by unnecessary soot blowing.
Traditional systems operate on a specif-
ic sequence and are blind to the actual
conditions inside the boiler. Blowing
high-pressure steam on a bare tube can
damage the tube. On the flip side, some
areas of the boiler accumulate slag more
quickly and require more frequent clean-
ing. Without an intelligent system, slag
can accumulate to excessive levels and
severely restrict heat transfer. This could
lead to unplanned downtime.
But soot blowing systems only temper
slag deposits. More effective methods for
slag removal are typically used during the
next planned outage.
WATER LANCES
Ajetofhigh-pressurewaterisonemeth-
od used to break down the buildup of
slag during a planned outage. The
use of hydro-blasting systems
equipped with pumps
capable of sending up
to 1,200 gallons
per minute
through their
hoses can
strip away the
toughest slag
deposits.
The problem
with using high-pressure water lances is
the risk of introducing moisture into the
boiler.
Water lances cover about a 20-foot
generation and equipment maintenance.
According to the Electric Power Research
Institute, slagging and problems associat-
ed with excessive slagging cost coal-fired
power plants more than $2 billion a year.
The cofiring of other fuels with coal, es-
pecially biomass, has created big slagging
problems for power plant boilers not de-
signed to handle ash from these alterna-
tivefuels.Muchthoughtneedstobegiven
to selecting a biofuel and the appropriate
replacement levels for cocombustion. But
the industry has demonstrated that these
problems can be overcome.
Boiler service companies say routine
slag removal can boost boiler efficiency
by as much as 4 percent, in addition to
extending the life of the boiler.
The tools used to combat the buildup of
boiler slag at power plants are wide rang-
ing. Common tools include soot blowers,
soundwaves,hydroblasters,CO2
blasters,
jackhammers, picks, and carefully-aimed
shotguns. In some severe cases, power
plant operators will turn to dynamite to
deal with ceaseless slagging.
SOOT BLOWERS
To clean a boiler while it’s online and
producing power, most power plants
use soot blowers driven by steam or
buildup on the furnace walls of the boiler
known as slag. Slag may also fuse to the
fire side of the boiler tube, preventing suf-
ficient heat transfer. A reduction in heat
transfer from the flue gas to the steam
tubes can cause lower boiler efficiency,
hotter flue gas temperatures and, in some
instances, a boiler shutdown. What’s
more, slag causes boiler corrosion, which
can lead to unexpected failures.
It has been estimated that slagging inci-
dents cost the global power sector several
billion dollars each year in reduced power
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:N.B.Harty
Retractable sootblower.
Photo courtesy:Diamond Power

ABM
A
SpecialSection
Most acoustic systems have a fre-
quency range of 60 Hz to 420 Hz. They
create a series of very rapid and pow-
erful sound waves that are transmitted
into the dry deposits. This causes the
ash to move at differing speeds, allow-
ing the ash to break away from adjoin-
ing particles and the surface they are
surface they are fused with.
EXPLOSIVES
Using explosives to clean slag from
boilers isn’t a new process, but it’s one
that many plant operators prefer.
The industry began using dynamite
to clean boilers in the 1960s. Dynamite
is still used today, but most operators
prefer to use binary explosives, which
are safer to handle because they require
two different ingredients that will not
explode until they are mixed together.
Explosives are very effective at clear-
ing out large, thick volumes of slag.
However, if the explosives are not
charged properly, the damage it could
do to the boiler can be great and very
expensive to repair. Using a qualified,
licensed and experienced contractor is
crucial.
Norm Harty of N.B. Harty General
Contractor Inc. has been using dyna-
mite to clean boilers for years. He and
his staff have developed the procedure
into a state-of-the art technique that can
quickly clean the slag from a boiler.
To clean a boiler using explosives,
Harty said his company will use prim-
er cord around tubes that are close to
avoid damage. The cord has connectors
to delay the chargers, which he said is
important to avoid destroying the wall
or insulation of the boiler.
Harty said using explosives has sev-
eral advantages, including speed and
convenience. “With dynamite,” he said,
“you can put all of it in a pickup truck
and clean any boiler.”
cause significant damage to the boiler.
What’s more, handling and disposing the
chemical waste is costly and risky. The
risk of a spill and environmental damage
should be considered.
ACOUSTIC CLEANING
To dislodge large volumes of dry de-
posits, power producers will use built-in
horns or speakers to unleash powerful
sound waves. The waves loosen the build-
up without risking damage or fatigue to
the boiler.
While this can be done by using acous-
tic horns, other acoustic technologies can
be engineered specifically for a power
plant. They are part of an engineered, in-
tegrated system in which the frequency is
determined by 3D modeling.
Deposits are dislodged amid a change
in pressure that breaks the bond of the
particles from themselves and the struc-
ture. Acoustic cleaning systems typically
remove deposits more effectively at lower
frequencies. Lower frequencies produce
higher levels of displacement in larger ar-
eas, but extremely low frequencies could
cause structural damage to the boiler.
diameter area. They have a small nozzle
area and require high purity water. Some
companies provide hands-free hydro-
blasters, which are operated remotely and
safely outside the boiler.
CHEMICAL CLEANING
Using chemical solutions is an effec-
tive method for cleaning boilers because
it ensures that all of the treated surfaces
will be clean, allowing operators to see
the true condition of the metal inside the
boiler. Previously unnoticed pits or goug-
es will become clearly visible, allowing for
a more effective inspection.
The advantages of chemical cleaning
include:
• The quality of steam can be main-
tained at the turbine inlet
• Corrosion of the metal surface of the
boiler can be minimized
• Under deposit corrosion of the metal
can be avoided
• Better heat transfer
• Minimizing downtime due to boiler
tube failures
But chemical cleaning is expensive and
dangerous. The chemical solutions can
Norm Harty has been using explosives to clean boilers for
nearly 50 years.Photo courtesy:N.B.Harty

33www.power-eng.com
Technician Checking For Air In-Leakage Around Valves 1
Photo courtesy:Conco
Leak Detection
“Ins”and“Outs”BY BARRY VAN NAME
you an indication that there is a problem
that could be traced to a leak. You might
also experience a need for more frequent
maintenance of equipment that could
lead to increased risk to turbine compo-
nents. Also, high levels of dissolved O2
in
the feedwater will cause increased corro-
sion and deterioration of your boiler and
feed systems.
All plants need to test for leaks, but the
test can be either reactive or proactive.
When it’s reactive, the condenser is telling
you when to test. Emergency inspections
are performed as a result of catastrophic
failure or because inleakage has exceeded
the capability of your air removal system.
Waiting for an emergency situation can
be very costly and result in damage to an-
cillary equipment. With proactive testing,
W
hen considering
the damaging
and costly effects
resulting from
condenser air in-
leakage and water leakage, we must also
consider methods to avoid these condi-
tions and maintain condenser reliability.
Effective cleaning and testing strategies
will maximize megawatt output while
minimizing condenser-related outages
during normal operating cycles. Properly
performed, your results can be quanti-
fied, permitting an accurate calculation of
return-on-investment.
To achieve maximum condenser per-
formance,wemustconsiderthecombined
efforts of cleaning, leak detection and
testing. Many plants have an established
cleaning regimen, usually annually, as
well as an eddy current testing regimen
that could take place up to every few
years, depending on the age and condi-
tion of the condenser. However, many of
the leak detection programs occur on an
as-needed basis. By combining proactive
cleaning, leak detection and eddy current
testing, the result will be improved total
performance of your condenser and con-
denser components.
Condensers are designed with air
removal systems to handle a certain
amount of air inleakage and keep the unit
runningatpeakefficiency. Wheneveryou
have a leak that exceeds the capability of
the air removal system, the efficiency of
the condenser is adversely affected. An in-
creased plant heat rate will certainly give
ABM
A
SpecialSection

2016 02 Power Engineering

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