Power magazine march 2015 international

March2015•Vol.159•No.3
Vol. 159 • No. 3 • March 2015
NewWays to Manage
Water &Wastewater
Going Natural with Boiler Room
Ventilation
CCGT Steam Cycle Low-Load Ops
Issues
Flex-Gen Early Performance Results
Geothermal New Zealand

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CIRCLE 1 ON READER SERVICE CARD

March 2015 |POWER www.powermag.com 1
ONTHE COVER
National Oilwell Varco, in partnership with Oasys, offers forward osmosis systems for use
in the oil and gas industry for treating exploration and production wastewaters. Forward
osmosis, especially as a companion to reverse osmosis, is beginning to see use in the
power industry as well. Courtesy: Oasys Water
COVER STORY: WATER & WASTEWATER
22 Water and Wastewater Treatment Technology Update
You’ve heard of reverse osmosis (RO), but now it’s being joined by a new treat-
ment known as forward osmosis (FO). In addition to RO, FO, and membrane bioreac-
tors, advances in membranes and zero-liquid discharge offer new options to power
plants.
28 Feedwater Chemistry Meets Stainless Steel, Copper, and Iron
Whether you operate an older plant with a mix of piping metals or a newer one with
the latest alloys, this article covers the chemistry options that operators have to
minimize corrosion in a critical area of the plant.
34 Mining for Lithium in Geothermal Brine: Promising but Pricey
Brine, the wastewater stream from geothermal power production, is highly corro-
sive and hard on piping systems. Recently, a U.S. company developed a method
that both recovers valuable minerals from that brine and makes the remaining fluid
much less problematic for reinjection.Trouble is, an inability to fund the enterprise
may spell the company’s demise.
SPECIAL REPORT: AUXILIARY SYSTEM
EFFICIENCY & RELIABILITY
36 Save Power with Natural Cooling for Building Ventilation
Coal-fired power plants release a large amount of heat during the combustion pro-
cess. Switching from forced to natural ventilation in the boiler building can yield
potential energy savings.
38 SCR Reheat Burners Keep NOx in Spec at Low Loads
Optimal NOx removal by a selective catalytic reduction (SCR) system requires the
inlet gas temperature to remain within a prescribed range. How does a baseload unit
meet NOx permit limits when it’s cycled and SCR inlet gas temperatures dip?
FEATURES
COMBINED CYCLE GAS TURBINES
42 Protecting Steam Cycle Components During Low-Load Operation of Combined
Cycle Gas Turbine Plants
Know the tradeoffs when operating combined cycle plants at low loads.The solution
to one problem may trigger another problem or cause actual damage to your plant.
46 Are Flexible Generation Plants Performing as Expected?
Designed from the start for cycling and fast starts, the new “flex” generation com-
bined cycle plants promised to avoid the trauma inflicted upon earlier gas plants by
more aggressive operational modes. One of the earliest plants to adopt the technol-
ogy reports positive results.
Established 1882 • Vol. 159 • No. 3 March 2015
22
34
36

www.powermag.com POWER |March 20152
RENEWABLES
48 New Zealand’s Geothermal Industry Is Poised for the Future
Geothermal generation in New Zealand increased more than 20% per year from
2010 to 2014, and a current total capacity over 1,000 MWe typically contributes
about 16% to the country’s supply. However, with flat load growth, developers are
looking abroad for new opportunities.
FUELS
52 Nuclear Industry Pursues New Fuel Designs and Technologies
New fuel rod cladding technologies and fuel assembly options are being developed
to make nuclear fuel safer.
DEPARTMENTS
SPEAKING OF POWER
6 Speaking of Cuba, Change, and Coincidence
GLOBAL MONITOR
8 Cambodia’s Largest Hydropower Plant Begins Operation
8 U.S., Netherlands Harness Waste Gases for Distributed Generation
9 Entergy’s Ninemile 6 Plant Completes Construction
11 Google Backs Norwegian-Developed Solar Plant in Utah
11 DOE Wind Forecasting Grant Goes to Finnish Firm
12 Power Shortages Challenge Eskom, Force Load Shedding in South Africa
14 A Handheld Fuel Cell Generator
15 Manufacturing Supercapacitors from Atmospheric Carbon Dioxide
16 POWER Digest
FOCUS ON O&M
18 Advanced Bearing Technology Eliminates Subsynchronous Steam Turbine
Vibrations
LEGAL & REGULATORY
20 Cape Wind Finally Blows Out
ByThomas W. Overton, JD
COMMENTARY
60 FERC’s Work on the Clean Power Plan
By Cheryl LaFleur, Chairman, Federal Energy Regulatory Commission
Use the search bar at powermag.com to find these stories. (While you’re on our homepage,
subscribe to the weekly POWERnews eletter so you don’t miss the latest developments.)
Mississippi Supreme Court Strikes Down Kemper County IGCC Rate Increase
ARPA-E Summit Takes the Pulse of Energy Technology Innovation
New Zealand Strives to Maximize the Value of Geothermal Wastewater
Even More Delays and Cost Overruns for Vogtle Expansion
MIT Study: Carbon Sequestration May Not Work as Advertised
U.S. Electric Utility Toxic Releases Decrease 49% During the Past Decade
European Power Markets Force Changes at RWE, E.ON, and Vattenfall
Desert Sunlight PV Plant Comes Online
Japan Mulling $800 Million Stimulus for Battery Storage and Efficiency
AEP Looks to Sell Merchant Coal Fleet
Online-Only Stories You Might Have Missed
48
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42

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SPEAKING OF POWER
Speaking of Cuba, Change,
and Coincidence
S
ometimes, circumstances have a way
of developing in such an unexpect-
edly serendipitous way that they
practically force one to take notice. So it
is with Cuba and its power sector.
Coincidence
It all started with a letter to the POWER
editorial team from Cuba that I received
in mid-December. It had been written in
October and was forwarded by our corpo-
rate office. The very next week, on Dec. 17,
President Obama announced the administra-
tion’s changes in policy toward Cuba. After
sharing news of the letter with Contribut-
ing Editor Ken Maize, I learned that he was
headed to Cuba in January for a cultural ex-
change trip. (See “Cuban Revolucion Ener-
getica?” at powermag.com/blog.) Then, in
mid-January, I received another letter from
Cuba—this time via email. (Both the letter
and the email were from the same person,
to whom I have replied.)
Several things made these develop-
ments interesting. First, the stamp on the
letter bore a picture of a lizard not unlike
those in my backyard. It was also the first
letter to the editor I’ve seen in hard copy.
Usually, if we get something via the mail
service, it’s marketing materials or an un-
solicited article. (Note that both hit the
recycle bin because we’re a totally digital
organization.) As for the messages, both
were very complimentary about a wide
range of work written and published by
POWER and its editors. Usually, when we
get comments about content, it’s either
strongly for or against a single article and
is typically fueled by the writer’s political
or economic views. But this author noted
that his team of professionals “discuss al-
most all the articles.”
I appreciated the messages from Cuba
because it’s gratifying to know that one’s
work is useful, but I also learned some-
thing about Cuba’s power sector and the
dedicated people working in it, and that
prompted me to research further.
Cuba’s Energy Revolution
Most readers are familiar with Germa-
ny’s Energiewende, or energy transition;
fewer are aware that Cuba instituted a
plan in 2005 that goes further, in some
areas, according to German consultant
and author Dieter Seifried. One example:
A complete switch from incandescent to
compact fluorescent lamps was made in
Cuba five years earlier than in Germany
and the rest of the European Union. This
revolution entails efficiency measures,
adding distributed generation (DG), im-
proving transmission and distribution
(T&D), developing renewable energy as
well as domestic fossil fuel resources,
and increasing both international coop-
eration and public awareness of energy
issues. There’s still a long way to go with
this revolution, as Ken’s post notes.
According to the International Ener-
gy Association, in 2012 the majority of
Cuba’s 18,432 GWh for its roughly 11.3
million citizens was generated by oil
(15,652 GWh), with gas supplying 2,082
GWh. As for renewables, biofuels supplied
555 GWh, hydro 111 GWh, wind 17 GWh,
and solar photovoltaics 5 GWh. The U.S.
Energy Information Administration (EIA)
estimates that 2012 installed capacity
was 6.24 GW. The EIA notes that, “In an
effort to diversify its energy portfolio,
Cuba has set a goal of producing 24% of
its electricity from renewable sources by
2030. To meet this goal, Unión Eléctrica,
the state-owned power company, is plan-
ning 13 wind projects with a total capac-
ity of 633 MW. In addition, Cuba plans
to add 755 MW of biomass-fired capacity,
700 MW of solar capacity, and 56 MW of
hydroelectric power.”
Multiple sources note that the island na-
tion has a high proportion of mostly die-
sel-fueled distributed generation. The DG
emphasis makes sense for a largely rural,
sparsely populated, elongated island nation
that covers a relatively large area. Cuba is
the largest Caribbean island—slightly
smaller than the state of Pennsylvania.
The sudden loss of economic support
resulting from the collapse of the Soviet
Union was another driver of DG, accord-
ing to a 2008 article by Mario Alberto Ar-
rastía Avila, energy specialist at Cuba’s
Centre of Information Management and
Energy Development. Oil consumption fell
20% in two years, Avila notes, affecting
all sectors and making 16-hour blackouts
common. Hurricanes in 2004 and 2005
made matters worse, particularly for the
T&D system. Emergency generators, most
capable of burning diesel or fuel oil, were
the fastest way to restore service in many
areas and to ensure less-widespread loss
of power in the event of future hurri-
canes. DG accounted for as much as 40%
of total generation by 2009, according to
one source.
Change and Common Interests
More recently, renewable DG is being pur-
sued. The email I received mentioned a
new five-year program to develop solar
and wind projects. Today, the writer said,
almost all rural schools are equipped with
solar panels to power everything from TVs
and computers to lamps, water pumps,
and air conditioners; this DG model is be-
ing expanded to other sectors. Though
the country still relies on fossil fuels for
the vast majority of generation, it is bet-
ting, he said, on a future “that will rely
on diversity and efficiency.” And although
he and his group are in the business of
providing technical services to existing
fossil plants, they are fully supportive of
renewables.
POWER covers the global power indus-
try, even though the majority of our audi-
ence is in North America, because power is
of global concern. That is more true today
than ever before, as all nations look for
ways to develop and use energy affordably
but in more environmentally benign ways.
Here’s hoping we all can continue to learn
from each other, even when the politicians
and leaders of our many different coun-
tries disagree. ■
—Gail Reitenbach, PhD is POWER’s editor.

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Cambodia’s Largest
Hydropower Plant Begins
Operation
The 338-MW Russey Chrum Krom hydro-
power plant in southwestern Koh Kong
province, Cambodia, was inaugurated on
Jan. 12. The Chinese-built project is the
largest hydropower station located in the
Southeast Asian country of more that 15
million people.
The dam was constructed by China Hua-
dian Corp. at a cost of about $500 million
under a 35-year build-operate-transfer
contract with the Cambodian government.
The first five years of the contract were
designed to accommodate construction,
which officially began on Apr. 1, 2010. It
is the largest investment China Huadian
has made in Cambodia.
The hydropower facility comprises an
upper and a lower station. The upper-
station dam was completed on Dec. 28,
2010. The lower portion was completed in
June 2013 and began to impound water
on Dec. 13, 2013. The upper dam’s genera-
tion capacity is 206 MW, while the lower
dam contributes 132 MW to the total.
Cambodia is in desperate need of reli-
able power. According to The World Bank,
electricity cost and access is a key con-
straint to further growth of the country’s
manufacturing sector. Even so, Cambodia’s
average annual growth rate was 7.7% dur-
ing the past two decades, making it the
sixth-fastest growing country in the world
during the period.
The Cambodian Ministry of Industry,
Mining, and Energy (MIME), forecasts
power demand will more than double by
2020. While that sounds daunting, with a
current nationwide capacity of only 1,072
MW, adding a plant the size of Russey
Chrum Krom goes a long way toward meet-
ing new demand requirements.
MIME’s electricity supply development
plan depends upon the construction of
four more hydropower projects (totaling
1,326 MW) and three coal-fired power
plants (totaling 1,235 MW) to accommo-
date growth to 2020 and beyond. While
some estimates have pegged Cambodia’s
theoretical hydropower potential to be
greater than 10,000 MW, prior to 2002 vir-
tually none of it had been developed.
Since 2002, five hydropower stations
have been added, and a sixth is expect-
ed to come online soon. The operational
sites are: Kirirom 1 (12 MW), Kirirom 3
(18 MW), Stung Atai (120 MW), Kamchay
(194.1 MW), and Russey Chrum Krom (338
MW). The 246-MW Stung Tatai station is
said to be complete and will be put into
service later this year.
In addition to generation from the hy-
dropower plants, Cambodia imports power
from Vietnam (170 MW) and Thailand (120
MW). It also gets power from two 50-MW
coal-fired units at the Sihanoukville proj-
ect, which came online in January 2014.
But just adding capacity is not enough.
Cambodia currently lacks the transmission
and distribution infrastructure to get the
electricity where it needs to go. Although
the Russey Chrum Krom hydropower plant
is technically a 338-MW facility, The Cam-
bodia Daily reports that its current output
is only about 5% due to its inability to
transmit the power outside of the provin-
cial town.
In time, Cambodian Prime Minister
Hun Sen—who was on hand for the in-
auguration ceremony (Figure 1)—says the
transmission network will be in place to
distribute the dam’s power nationally, but
that could take years.
—Aaron Larson
U.S., Netherlands
Harness Waste Gases for
Distributed Generation
Methane emissions are garnering increas-
ing attention because of their potential
impact on the climate. Though far less
methane is released to the atmosphere
than carbon dioxide, methane has 20 to 25
times the potential warming effect. That’s
spurred regulatory attention, highlighted
by the January announcement from the
Obama administration that it would roll
out a series of initiatives designed to sub-
stantially cut methane emissions from the
oil and gas industry.
But methane emissions are a problem
beyond oil and gas production, as the gas
is generated by a wide variety of industrial
and agricultural processes. Because these
emissions are typically impure, mixed with
other gases such as oxygen and carbon
dioxide, their low Btu value can make cap-
turing and using them uneconomic. Even
where there are economic incentives, such
as in associated gas production from oil
wells, the lack of gathering infrastructure
can lead to the waste gases being flared
or simply released to the atmosphere.
A variety of approaches are available to
convert such waste gases to power, but
they can come with additional challenges,
such as generating harmful emissions of
their own. In addition, they do not work
with all types of waste gas.
Irvine, Calif.–based company Ener-Core
believes it has a technology to harness
these waste gases for power generation
while producing far lower emissions. Rather
than combusting the gases in a turbine or
reciprocating engine, the company’s FP250
Powerstation employs an oxidizer that pro-
duces useful heat energy but does it at low
enough temperatures to avoid producing
harmful pollutants such as NOx (Figure 2).
The output from the oxidizer is then fed
into a 250-kW gas turbine generator.
The use of oxidizer technology allows
the FP250 to accept a much wider range
of fuel qualities, including very low–Btu
1. Cambodian Prime Minister Hun
Sen cuts the ribbon.The Russey Chrum
Krom inauguration ceremony included several
dignitaries and company executives. Cour-
tesy: Samdech Hun Sen, Cambodian Prime
Minister
2. Waste to power. Ener-Core’s FP250
system is capable of generating 250 kW from
very low–Btu waste gases that might other-
wise be flared or vented. This system is in-
stalled at the Fort Benning U.S. Army base in
Georgia. Courtesy: Ener-Core

waste gases that are unusable with other
methods. The system can be configured to
produce virtually undetectable levels of
NOx, CO, and volatile organic compounds.
The first FP250 system was installed
as a demonstration project at a landfill
at the Fort Benning, Georgia, Army base.
That one-year trial was funded by the De-
partment of Defense. The first commercial
FP250 system went online at a landfill in
the Netherlands this past June.
Ener-Core also recently completed a li-
cense deal with Dresser-Rand to deploy the
technology at an ethanol plant in Califor-
nia. That two-unit facility, using a larger
version that integrates Ener-Core’s oxidizer
system with Dresser-Rand’s KG2 turbine,
will produce 3.25 MW for Pacific Ethanol’s
refinery in Stockton and will include a
heat-recovery steam generator. Generating
its own power from previously flared waste
gases is expected to save the plant about
three to four million dollars a year. The $12
million project is projected to come online
in the second quarter of 2016.
According to spokesman Colin Mahoney,
Ener-Core is looking to enter into license
agreements with other turbine manufac-
turers with larger size turbines, as well as
with manufacturers of steam-generating
technologies that would enable its tech-
nology to generate industrial-grade steam
from waste gases.
—Thomas W. Overton, JD
Entergy’s Ninemile 6 Plant
Completes Construction
Entergy Louisiana’s two-unit, 560-MW com-
bined cycle plant in Westwego, La., just out-
side New Orleans, completed construction
on Dec. 26, both under budget and several
months ahead of its original schedule (Fig-
ure 3). It’s the first new plant Entergy Loui-
siana has added in nearly 30 years.
The Ninemile Point site has been gen-
erating power for New Orleans since 1951,
but the original two boiler units have
been retired for years. Unit 3 is nearing
end-of-life, and the new Unit 6 will help
replace the retired capacity. Construction,
led by CB&I, began in early 2012.
Unit 6 will operate on natural gas but
has the ability to burn fuel oil if neces-
sary. This is an important concern given
the location, which was hit hard by Hur-
ricane Katrina in 2005. In the event natu-
ral gas delivery is disrupted, the plant will
be able to switch over seamlessly to fuel
oil drawn from on-site tanks. The build-
ing pad was also raised 4 feet to protect
against possible flooding.
Though budgeted at $721 million, the
plant was completed for about $655 mil-
lion. Ninemile 6’s output will be shared
among Entergy Louisiana (55%), Entergy
Gulf States Louisiana (25%), and Entergy
New Orleans (20%) via life-of-unit power
purchase agreements.
3. Ready to roll. Entergy Louisiana com-
pleted construction on its new Ninemile 6
combined cycle plant months ahead of sched-
ule and about $70 million under budget. The
plant was dedicated in January. Courtesy: En-
tergy Louisiana

IS YOUR POWER
PROJECT A WINNER?
Find out by nominating it for a POWER award
All nominated projects must be in commercial operation by the nomination
deadline of April 30, 2015.You’ll find award information, lists of former winners,
and nomination forms at www.powermag.com/power-awards
25243
NOMINATION DEADLINE:
APRIL ��, ��
The 2015 categories are:
̋" Plant of theYear Award
̋" Reinvention Award (formerly
Marmaduke Award)
̋" Water Award
̋" Smart Grid Award
̋" Top Plants Awards (in gas, coal, nuclear,
and renewable subcategories)
Coal Top Plant
Award Winners
PrepareYour Plant for Cold
Weather Operations
Boosting CombustionTurbine
Response
Getting New Hydro Projects
Built

Google Backs Norwegian-Developed
Solar Plant in Utah
The Utah Red Hills Renewable Energy Park, a 104-MW solar pho-
tovoltaic (PV) plant under development by Norwegian firm Scatec
Solar at Parowan in southwest Utah, closed financing on Jan. 7
thanks to an investment from Google in the $188 million project.
It will be the largest PV plant in Utah when completed.
Google has poured more than $1.5 billion into 18 renewable
energy projects around the world with a total capacity of 2.5
GW—among them POWER’s 2014 Plant of the Year, the Ivanpah
Solar Electric Generating System in California. Though the com-
pany has made a commitment to minimize its carbon footprint
and power its enormous, power-hungry data centers with renew-
able energy, it is also investing in these projects because of the
potential returns. Google will be the tax equity investor in Red
Hills, which means it will receive the project’s tax incentives in
addition to a portion of the income.
According to Scatec, the site has excellent solar irradiance, in
part because it is situated at an elevation of about 8,500 feet
(Figure 4). The project will sell its power to PacifiCorp subsidiary
Rocky Mountain Power under a 20-year power purchase agree-
ment and is expected to come online by the end of 2015.
Despite the state’s impressive potential, Utah has lagged
well behind other western states in solar energy deployment,
largely because it has only a voluntary renewable energy stan-
dard. It currently has about 18 MW of installed solar PV ca-
pacity, according to the Solar Energy Industries Association, a
small fraction of that operating in neighboring states such as
Nevada and Arizona.
DOE Wind Forecasting Grant Goes to
Finnish Firm
The U.S. Department of Energy (DOE) has awarded a $2.5 mil-
lion contract to Finnish environmental and industrial data firm
Vaisala to coordinate a study of methods to improve wind en-
ergy forecasting in complex landscapes. The Wind Forecasting
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4. High power. The Red Hills Renewable Energy park, under de-
velopment at a site in southwest Utah and shown here in this photo
mock-up, will comprise 325,000 solar photovoltaic modules. Courtesy:
Scatec Solar

Improvement Project 2 (WFIP2) is a DOE
initiative targeted at enhancing the reli-
ability of wind forecasting, specifically in
challenging areas. The goal is to improve
the accuracy of short-term 0- to 15-hour
wind power forecasts in mountainous
areas across North America and world-
wide, and thereby reduce the cost of grid
integration and optimize performance
through better short-term modeling of
wind variability.
Accurate wind forecasting has become
a key issue in wind generation, as devel-
opers have discovered that existing mod-
els do not always reliably predict wind
volumes and energy over the long term.
This creates uncertainties for financing
and development, and can challenge the
profitability of seemingly viable projects
(see “Reducing Weather-Related Risks in
Renewable Generation” in the January
2015 issue).
The WFIP2 project will comprise a
comprehensive three-phase study of at-
mospheric phenomena in complex ter-
rain, with the goal of enhancing the
widely used Weather Research and Fore-
casting model and the National Oceanic
and Atmospheric Administration’s Rapid
Refresh and High Resolution Rapid Re-
fresh models. Following a design and
planning phase, the project will collect
18 months of data to analyze environ-
mental characteristics affecting wind
flow patterns, ranging from soil mois-
ture and surface temperatures to the
topographical features of mountain-
valley regions (Figure 5).
The data will then be used to update
and improve the physics that underpin
current forecasting models. Enhanced
model predictions produced during the
third phase of the project will then be
compared with baseline forecasts pro-
duced by existing models to evaluate the
success of the initiative.
The project partners include Vaisala;
the National Center for Atmospheric Re-
search; researchers from the University of
Colorado at Boulder, Texas Tech University,
and the University of Notre Dame; Lock-
heed Martin; wind energy firms Iberdrola
Renewables and Eurus Energy; meteorol-
ogy consulting firm Sharply Focused; and
several western utilities.
Power Shortages
Challenge Eskom, Force
Load Shedding in South
Africa
The South African power system is severely
constrained and will remain tight until at
least the end of April, according to Eskom.
The company generates approximately
95% of the electricity used in South Africa
and approximately 45% of the electricity
used in all of Africa.
In a media presentation, CEO Tshediso
Matona explained that Eskom’s reserve
margin is very low and that the company
does not currently have enough capacity
to meet demand. The situation has neces-
sitated planned, controlled, and rotational
load shedding to protect the power system
from a total countrywide blackout.
The company says it avoided load shed-
ding over the past seven years by sub-
scribing to a “keeping the lights on at
all costs” philosophy. As a consequence,
much needed maintenance has been post-
poned over the years, resulting in a severe
maintenance backlog and an increase in
equipment breakdowns.
One measure Eskom uses to track reli-
ability is its unplanned capability loss fac-
tor (UCLF). An increasing UCLF percentage
indicates deteriorating plant health. From
2005 through 2009, the UCLF averaged
4.43%. However, since that time, as more
and more maintenance has been deferred,
the percentage has risen steadily, reach-
ing 14.85% by the end of 2014.
“We have arrived at a point that does
not allow us to ignore the health of our
plants,” Eskom said. “Our reserve margin
is so thin, that every incident creates a
major systems issue and could also have
safety implications for the plant. The mas-
sive usage of diesel helps to bridge the
problem somewhat, but can’t help the sys-
temic healing and a shortage of capacity
for the coming three years appears to be
unavoidable.”
This summer has seen increased use of
open cycle gas turbines and other reserves
5. For better wind data. The U.S. Department of Energy is funding a study to improve
forecasting models for wind energy in difficult terrain. Part of the initiative will involve deploying
wind-measuring equipment like Vaisala’sTriton wind profiler.TheTriton is a self-powered, mobile
SODAR (SOnic Detection And Ranging) unit that uses sound waves to collect high-level wind
speed and direction data. Courtesy: Vaisala
6. Koeberg Power Station is like a
beacon in the night. With an average
availability over the last three years of 83.1%,
Koeberg is Eskom’s most reliable power sta-
tion. Courtesy: Pipodesign/Phillipp P. Egli

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to balance supply and demand, but Eskom
says, “new generating capacity and other
levers are needed in order to ease the
pressure on the system.”
The maintenance season in South Africa
is usually from September to mid-May—
the Southern Hemisphere’s summer—
when Eskom typically sees lower demand
for electricity. This year, planned out-
ages will place additional stress on an
already fragile system. Unit 1 at the
Koeberg Power Station—the only nuclear
power station in Africa and Eskom’s self-
proclaimed best in class operator—is
expected to come offline on Feb. 9 for
a lengthy refueling outage, which will re-
move 900 MW from service (Figure 6).
Eskom completed a return-to-service
program in 2014 that included re-commis-
sioning three previously mothballed coal-
fired stations, including the Camden Power
Station, a 2014 POWER Top Plant award
winner (see the October issue). More ca-
pacity is needed though. In the first half
of 2015, the 100-MW Sere wind farm is
expected to enter service along with the
first of six 794-MW coal-fired units at the
Medupi facility, a greenfield project. Other
capacity additions will follow, including
the Ingula Pumped Storage Scheme Proj-
ect next year and the 6 x 800-MW Kusile
Power Station Project beginning in 2017.
For the time being though, load shed-
ding will be the norm. Eskom predicts in-
sufficient generation capacity and a high
probability of load shedding on 62 of the
89 days from Feb. 1 through Apr. 30. It
says that there is a medium probability of
load shedding on 18 additional days dur-
ing the period, leaving only nine days in
which generation capacity is expected to
be adequate—mostly over weekends.
—Aaron Larson
A Handheld Fuel Cell
Generator
After decades of potential but limited
deployment, fuel cells are beginning to
carve out a role in grid-scale generation
(see “59-MW Fuel Cell Park Opening Her-
alds Robust Global Technology Future” in
the May 2014 issue). Now, continually
falling costs are bringing fuel cell gen-
eration all the way down to the consumer
level.
In December 2014, Dresden, Germany–
based firm eZelleron launched a fund-
raising effort on crowd-sourcing website
Kickstarter for a personal charging device
based on its proprietary microtubular fuel
after
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7. Portable power. The kraftwerk por-
table charger can recharge a variety of elec-
tronic devices using an internal fuel cell and
liquefied petroleum gas. Courtesy: eZelleron
USB plug
LPG gas
tank
Refill valve
Control electronics
Power electronics
Insulation
Microtubular
metallic fuel cell
Gas control unit
Micro blower
Powerout
Gasin

cell technology. Called kraftwerk (German
for “power station”), the charger gener-
ates power from liquefied petroleum gas
(LPG) such as propane or butane using
commonly available recharge canisters.
Most of the palm sized–, 7-ounce unit is
taken up by the LPG fuel tank; the actual
fuel cell is smaller than a cigarette (Figure
7).
The Kickstarter project reached its
funding goal in a week, and the compa-
ny is promising to begin delivery of the
units in December 2015. According to the
company’s website, the microtubular fuel
cells can also be packed into arrays for
larger capacity. It offers 250-W modules
that can be combined into stacks of up to
80 kW capacity.
Manufacturing
Supercapacitors from
Atmospheric Carbon
Dioxide
Researchers at Oregon State University
(OSU) have developed a method to man-
ufacture nanoporous graphene for use in
supercapacitors from atmospheric carbon
dioxide (CO2). Graphene is a form of car-
bon that is essentially a one-atom-thick
layer of graphite, in which the carbon at-
oms are arranged in a hexagonal lattice.
Because of its virtually two-dimensional
character, it has a variety of fascinating
chemical and physical properties. Gra-
phene is 100 times stronger than steel
and is an excellent conductor of heat and
electricity.
Nanoporous graphene is graphene in
which nanopores have been created in
the lattice (Figure 8). It has a very high
specific surface area, about 1,900 square
meters per gram. This gives it an electri-
cal conductivity at least 10 times higher
than the activated carbon currently used
to make commercial supercapacitors.
However, the method developed at OSU
to create nanoporous graphene is faster,
less expensive, and has less environmen-
tal impact than previous methods such as
chemical etching, which often use toxic
materials. Rather than etching graphene,
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to high temperature in a flow of carbon
dioxide. This produces a controlled reac-
tion that converts the elements into their
metal oxides and nanoporous graphene.
Because of its simplicity and low cost,
OSU researchers believe the method has
good potential to be scaled up for com-
mercial manufacture. Supercapacitors
with nanoporous graphene electrodes
could potentially have far higher storage
capacity than current designs using acti-
vated carbon.
POWER Digest
TIC to Build First U.S. J-series GT
Plant. The Industrial Co. (TIC), a wholly
owned subsidiary of Kiewit Corp., was
recently awarded an engineering, pro-
curement, and construction contract to
build a gas turbine (GT) power plant for
the Grand River Dam Authority (GRDA),
Oklahoma’s state-owned electric utility.
The 495-MW Grand River Energy Center
Unit 3 will feature the first U.S.-installed
Mitsubishi Hitachi Power Systems
Americas Inc. M501J-series GT. Construc-
tion will begin in early 2015 in Chouteau,
Okla. The new plant will help GRDA meet
new emissions regulations by reducing its
dependence on coal-fired power genera-
tion. The project is scheduled to become
operational in May 2017.
South Africa to Develop Continent’s
First CSP Project. The South Africa De-
partment of Energy awarded preferred
bidder status for a 100-MW concentrating
solar power (CSP) project to a consortium
led by SolarReserve, a global developer
of utility-scale solar power projects, and
International Company for Water and
Power Projects, the Saudi water and
power developer, owner, and operator. The
Redstone Solar Thermal Power project is
scheduled to achieve financial close lat-
er in 2015 and commence operations in
early 2018. It will be the first of its kind
in Africa and will feature SolarReserve’s
molten salt energy storage technology in
a tower configuration, providing 12 hours
of full-load energy storage. The project
also features dry cooling to minimize wa-
ter use.
Saudi Arabia Plans First CSP-
Combined Cycle Plant. The Green Duba
project will integrate 50 MW of parabolic
trough concentrated solar power (CSP) in
a combined cycle plant with a total ca-
pacity of 600 MW. Saudi Electricity Co.
selected General Electric to supply the
gas turbine–based plant, to be built in
the western Red Sea port of Duba. Project
completion is expected by 2018. The tech-
nology provider for the CSP component
was not named.
Morocco Adds Solar Thermal Ca-
pacity. The Moroccan Agency for Solar
Energy (MASEN) has selected a consor-
tium including SENER to construct the
200-MW Noor 2 and 150-MW Noor 3,
which represent phases 2 and 3 of the
country’s largest solar complex, located
in Ouarzazate, in southern Morocco.
SENER will perform the engineering, con-
struction, and commissioning of the two
solar thermal power plants, which make
use of different technologies: Noor 2 will
use SENERtrough parabolic troughs (de-
signed and patented by SENER), while
Noor 3 will use a central tower and an
array of heliostats. Noor 4, for which a
contract has not yet been awarded, will
use photovoltaic technology.
B&W to Design and Manufacture
Equipment for Vietnamese Plant.
The Babcock & Wilcox Co. (B&W) sub-
sidiary Babcock & Wilcox Power Gen-
eration Group Inc. has been chosen to
design and manufacture a supercritical
coal-fired boiler and selective catalytic
reduction system for the Duyen Hai 3
Extension power plant in Vietnam. The
selection was made by Japanese prime
contractor Sumitomo Corp., which will
build the 688-MW plant for Power Gen-
eration Corporation 1, a subsidiary of
Electricity Vietnam. It will be B&W’s
sixth steam generator in Vietnam. B&W
has received a full notice to proceed,
engineering is under way, and the plant
is scheduled for commercial operation in
mid-2018.
Siemens Delivers Three F-Class
Gas Turbines to Peru. Siemens has
received an order for three SGT6-5000F
dual-fuel gas turbines from Peruvian util-
ity EnerSur. The turbines will be used for
the Nodo Energético del Sur–Planta No. 2
Región Moquegua project in the port of
Ilo, in the Moquegua region of southern
Peru. They will power three simple cycle
plants with a combined capacity of 600
MW. Commercial operation is scheduled for
March 2017.
Construction Begins on UK Biomass
Plant. Ground was broken on Jan. 20 for
the Snetterton Renewable Energy Plant—a
44.2-MW straw-powered biomass plant—
located in Norfolk County, England. Bur-
meister & Wain Scandinavian Contractor
A/S (BWSC) will oversee the construction
process and will own the plant in part-
nership with a Danish infrastructure fund
managed by Copenhagen Infrastructure
Partners A/S.
The project was originally developed by
Iceni Energy Ltd., with renewable energy
project developer Eco2 Ltd. later joining
forces to take the project forward to fi-
nancial close. The plant is expected to be
operational by mid-2017. BWSC will be in
charge of the operation and maintenance
of the plant for a 15-year period and has
contracted for supply of straw for the next
12 years.
This is the second biomass power plant
the group is constructing in the UK. The
other is the Brigg Renewable Energy Plant
in Lincolnshire, further north in England.
Novel Wind Power System to Be
Tested in Florida. SheerWind—an en-
ergy technology company based in Chas-
ka, Minn.—will design, manufacture, and
commission its unique INVELOX wind pow-
er system at Tampa Electric’s Big Bend
Power Station in Apollo Beach, Fla. While
the system utilizes conventional wind
power equipment, the design is completely
different. Wind enters an omnidirectional
intake area at the top of the structure and
is funneled down to a venturi, where it
is concentrated and further accelerated.
Turbine generators are placed inside to
take advantage of the velocity increase
and convert the wind to electrical power.
A diffuser section on the outlet slows the
wind speed prior to exiting the system at
the bottom.
One of the advantages of the INVELOX
solution is that turbines and rotors are
installed at ground level for easier, safer,
and cheaper operation and maintenance.
The system is capable of operating in a
wide range of wind speeds (from 2 mph
to over 100 mph) and is said to pose no
harm to birds or other animals. Multiple
turbines can be installed in series to in-
crease output capacity from each tower.
A 200-kW system will be installed this
year as a pilot project. If the technology
is proven to be viable following collection
of sufficient data (expected to take from
six to eight months), Tampa Electric may
consider purchasing a utility-scale 1.8-MW
INVELOX system.
Another Massive Coal Plant Planned
for India. Hong Kong–based China Light
& Power Holdings Ltd. is planning a
2,000-MW coal-based power plant in Gu-
jarat, India, at a projected investment of
$2 billion. The new plant would join to its
existing 600-MW gas-fired power plant in
the state and will most likely be fueled by
imported coal. ■
—Thomas W. Overton, JD; Aaron Larson;
and Gail Reitenbach, PhD

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Advanced Bearing Tech-
nology Eliminates Subsyn-
chronous Steam Turbine
Vibrations
A facility’s steam turbine ranks at, or
at least near, the top of the list of vital
power plant equipment. Without it, the
thermal energy in pressurized steam can
not be converted to rotary motion, which
is required to generate electricity. That is
why it is imperative for a plant’s steam
turbine to operate flawlessly.
Abnormal vibrations are a good indi-
cation that something’s not right. If ig-
nored, the problem causing the vibration
will frequently worsen, and in a turbine it
could result in damage to blades or other
internal components. In extreme cases,
catastrophic failure of the equipment can
occur, endangering personnel and costing
millions of dollars to repair.
Commissioning Hiccup
Doosan Škoda Power understands that ab-
normal turbine vibration requires action.
The company has more than a century’s ex-
perience manufacturing steam turbines and
has invested in research and development
to be an international leader in the delivery
of advanced clean energy technologies.
For one of its power generation custom-
ers in Scandinavia, Doosan Škoda Power
engineered a 46-MW steam turbine as part
of a combined cycle system for generation
of electricity as well as heat recovery. Dur-
ing the initial commissioning process, the
turbine experienced rotor instability that
prevented the drive train from operating
at full load. High subsynchronous vibra-
tions forced a trip in turbine operation at
just 27 MW versus the rated 46 MW.
Changes to the bearing clearances and
configurations mitigated the vibrations
but were not able to eliminate them com-
pletely. Doosan Škoda Power decided to
contact Bearings Plus, a Waukesha Bear-
ings business, for a damper solution.
Assessing and Solving the Problem
Bearings Plus performed a system-level
rotordynamic assessment of the turbine,
which evaluated the rotor, bearings, and
seals. The cause of the vibrations was
confirmed to be a flexible rotor (caused
by the large span between the bearings)
combined with steam whirl forces in sec-
ondary sealing locations.
The steam turbine’s original five-pad
rocker pivot tilt pad journal (TPJ) bear-
ings were designed with asymmetrical oil
film stiffness to try to accommodate the
rotordynamics of the combined cycle sys-
tem. However, the rotor flexibility and de-
stabilizing steam whirl forces resulted in
a negatively damped system and, conse-
quently, strong subsynchronous vibrations
at about 30 Hz (Figure 1).
For a solution, Bearings Plus suggested
soft-mounting the rotor system on TPJ bear-
ings with trademarked ISFD technology. In
contrast to the original design, bearings
with this integral squeeze film damper tech-
nology provide low-stiffness and high-effec-
tive damping to maximize the damping ratio
and eliminate subsynchronous vibrations.
How It Works
The ISFD design is manufactured through
electrical discharge machining. Integral
“S” shape springs connect an outer and
inner ring, and a squeeze film damper
land extends between each set of springs.
Bearing pads are housed in the inner ring
(Figure 2). The unique design allows for
high-precision control of concentricity,
stiffness, and rotor positioning. It pro-
duces superior damping effectiveness by
separating stiffness from damping.
While a conventional squeeze film
damper (SFD) experiences a dynamic stiff-
ness from the damper film that is depen-
dent on amplitude and frequency, in the
ISFD design, the stiffness is defined only
by the springs. This allows for good pre-
dictability, and precise placement of criti-
cal speeds and rotor modes, regardless of
vibration amplitudes and frequencies.
Whereas damping in a conventional SFD
is generated by squeezing in the damper
film and governed by circumferential film
flow, the segmented ISFD design prevents
circumferential flow and absorbs energy
through the piston/dashpot effect. Flow
resistance at the oil supply nozzle and end
seals controls ISFD damping.
Both the stiffness and the damping of the
ISFD design are optimized for the application
through a rigorous rotordynamic analysis. For
the steam turbine, because steam whirl was
one of the root causes of the subsynchronous
vibrations, the analysis of the ISFD solution
paid careful attention to modeling destabiliz-
ing seal forces and stage forces.
A damped eigenvalue analysis without
those forces showed a better stability mar-
gin by a factor of 12 with the ISFD design
compared to the original bearings. With the
destabilizing forces, the ISFD solution main-
tained a high stability margin. The combina-
tion of low stiffness and optimum damping at
1. Abnormal vibrations identified.The waterfall spectrum shows subsynchronous vibra-
tions at 30 Hz with the original five-pad tilt pad journal bearings. Courtesy: Waukesha Bearings
2. The ISFD design. This four-pad tilt
pad journal bearing utilizes integral squeeze
film damper technology. Courtesy: Wauke-
sha Bearings

the bearing support is the key in transforming
bending modes to more rigid body modes and
improving the overall stability and damping
ratio of the rotor/bearing system.
Proven Results
Field vibration data after installation
proved that the solution worked. The sub-
synchronous vibration spikes experienced at
the initial commissioning were eliminated
with the use of the ISFD design (Figure 3).
The larger stability margin provided by the
bearings with ISFD technology freed the
system from significant subsynchronous vi-
brations and enabled full-speed, full-power
operation of the turbine.
More than 3,200 bearings with ISFD
technology have been supplied over the
last 20 years and have established this
unique design as a leading solution to vi-
bration problems in turbomachinery. ISFD
technology is successful in a broad range of
turbomachinery due to the flexibility of its
design. The technology can be used with
tilt pad bearings, as described above, as
well as with Flexure Pivot bearings, fixed
profile bearings, and rolling element bear-
ings, in sizes from 10 mm up to 400 mm.
ISFD technology has successfully im-
proved stability, shifted critical speeds, and
reduced amplification factors in steam and
gas turbines, integrally geared air and pro-
cess compressors, centrifugal compressors,
turbo-expanders, radial turbines, supercriti-
cal CO2 power turbines, generators, motors,
and overhung process equipment. The cost to
implement an ISFD bearing-damper solution
is nominal compared to the ongoing, poten-
tially significant costs that can result from
vibration problems’ effects across a machine.
In many applications, the minimal space
requirements of the ISFD design allow
bearings with ISFD technology to serve
as drop-in replacements to existing bear-
ings. Most importantly, the ISFD bearing-
damper solution can be engineered to a
specific support stiffness and damping for
each application’s operating conditions to
maximize the ratio of energy transmitted
to the bearing locations, thus significantly
improving the stability of the system. ■
—Jong Kim is senior principal engineer of
Waukesha Bearings.
Mystaffwantstoworkhere...
Theyareproudofwhattheydo!
Kalenborn Abresist
5541 North State Road 13, Urbana, IN 46990
E-mail: info@abresist.com
www.abresist.com
I made my first sales call in June, 1973 for Abresist
products. I tell my sales staff,“Follow the customer’s
material through their plant to where it leaves or changes
and isn’t abrasive anymore. Their processes are very
complex and their wear problems are common”.
Listen to what has worked and what hasn’t. Keep
learning...our customers are our best source to solve
abrasion, corrosion and wear problems. Take care of them.
New company name. New products.
Same mission in Urbana, Indiana.
www.abresist.com
Joe Accetta (top) —
President
3. Problem solved. The waterfall spectrum shows the subsynchronous vibrations were
eliminated using the ISFD design. Courtesy: Waukesha Bearings

Cape Wind Finally
Blows Out
Thomas W. Overton, JD
I
f ever there were a case of winning all the battles and
losing the war, it would be the saga of the long-delayed-
and-now-probably-dead Cape Wind offshore wind project in
Massachusetts.
As I wrote last year (see “When States Try to Manipulate
Wholesale Power Markets” in the March 2014 issue), this project
that hoped to be the nation’s first offshore wind farm has been
fighting headwinds since it was first proposed more than a de-
cade ago. The fundamental problem has always been the price
tag. Even with the help of subsidies and loan guarantees, Cape
Wind was going to be so expensive that its developers could
not offer its power into the ISO-New England power market at
competitive prices.
The issue is not, as some supporters have claimed, an opposi-
tion to wind power amongst the region’s utilities. They’re already
buying quite a lot of it under various state renewable portfolio
standards, including Massachusetts’ Green Communities Act. The
problem is that land-based wind power is substantially cheaper
than anything Cape Wind could offer.
When National Grid and NStar were bullied into signing pow-
er purchase agreements (PPAs) with Cape Wind (for 50% and
27.5% of its power, respectively) by the Massachusetts state
government, they were forced to pay an initial rate of 18.7
cents/kWh—more than twice what they were paying for land-
based wind—with a 3.5% increase every year. That made a lot
of people unhappy.
Escape Clause
But those PPAs had an out. Cape Wind’s developers had to either
close financing and begin construction by the end of 2014 or
post a $645,000 security deposit to extend the deadline by six
months (or $1.29 million for another year). Cape Wind still needs
to raise a lot more money (and sell the remaining 22.5% of its
output), but having PPAs in place is pretty much a prerequisite
for a project like this to proceed. With the total cost projected
to be around $2.5 billion, one would have thought committing
$645,000 to save the PPAs would be a no-brainer. For whatever
reason—the developers may not have had the money to do it—
Cape Wind chose to forgo the deposit.
Instead, Cape Wind invoked what is known as a force majeure
clause in the PPA. Force majeure—French for “superior force”—is
the name given to a common provision in most contracts that
can free the parties from performing their obligations when an
extraordinary event beyond their control makes performance im-
possible. Though the term had a traditional meaning, U.S. courts
nowadays strictly construe these clauses as drafted in the con-
tract. For an event to trigger force majeure, it has to fit within
the terms of the agreement.
On Dec. 31, Cape Wind chief Jim Gordon wrote to NStar and
National Grid, as well as Massachusetts regulators, asserting that
the repeated litigation against Cape Wind excused it from its
obligations to close financing by that date.
In one respect, Gordon had a point. Opponents of Cape Wind
have filed a rather impressive 26 lawsuits against the project,
including the one I wrote about last March. Every single one of
them failed, with the most recent one having been dismissed in
May. The groups behind them, starting with billionaire and bête
noire of the left Bill Koch, have been frank about their aim to
delay Cape Wind as long as they could.
Out the Door
The utilities’ feelings about the PPAs can probably be judged by
the alacrity with which they abandoned them the moment they
had the opportunity. On Jan. 6, the second business day after the
deadline had passed, both NStar and National Grid announced
that they were jumping ship. Overnight, Cape Wind went from
having sold 77.5% of its power to 0%. Northeast Utilities (which
merged with NStar in 2012) CEO Tom May later told The Boston
Globe he was waiting for the first possible moment to get out.
Cape Wind has since responded that the joint move is invalid,
because its failure to begin construction was excused by force
majeure. Unfortunately for Cape Wind, that’s a dispute that won’t
be resolved without more litigation. The force majeure clause in
the PPA is too long to quote here, but it does require that the
triggering event be both “unusual” and “unexpected,” and that
it not be anything that “merely increases the costs or causes an
economic hardship to a Party.”
With the Koch-funded litigation over the project having be-
come a fixture in the process well before the PPAs took effect,
it may be tough for Cape Wind to convince a court that there
was anything unusual or unexpected about it at the time the
agreement was signed. Meanwhile, its chances of closing financ-
ing, let alone beginning construction, without a PPA in place
are basically nil. (As I write this in late January, Cape Wind has
been suspended from participation in the ISO-New England power
market, and its developers just abandoned two leases they had
entered to support construction.)
If there’s a lesson to be drawn here, it’s probably that there is a
limit to how far governments can go to force energy projects through
when the market is resisting them. Had Cape Wind made more finan-
cial sense, it’s likely that the customers for its power wouldn’t have
bolted for the exits the moment the doors were unlocked. ■
—Thomas W. Overton, JD is a POWER associate editor.
Its chances of closing financing
. . . without a PPA in place are
basically nil.

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WATER & WASTEWATER
Water and Wastewater Treatment
Technology Update
W
ater is the lifeblood of a thermal
power plant. As such, obtaining
clean and pure makeup water and
dealing with wastewater has been a require-
ment since the first steam generating unit
went into operation. As rules and regulations
change, new technology is often necessary to
meet more restrictive guidelines. The desire
for energy savings, more reliable treatment
methods, and solutions to water availability
challenges can also lead to innovations.
Reverse osmosis (RO) is a widely used
technology in the power industry. Devel-
oped in the 1950s, the first commercial RO
plant began operating in 1965. The process
uses a semipermeable membrane to purify
water by applying pressure to overcome os-
motic pressure, forcing water from a region
of high-solute concentration through the
membrane to a region of low-solute concen-
tration. A newer membrane technology that
may not be as familiar to readers is forward
osmosis (FO).
Fast Forward to Forward Osmosis
The first FO water treatment plant was built
in 1998 for use on landfill leachate; today,
research and development continues to refine
the process. While not as common as RO, FO
systems are proving to offer a new solution for
some challenging situations. Boston-based Oa-
sys Water recently installed a system to treat a
Chinese coal-fired power plant’s flue gas des-
ulfurization (FGD) wastewater (Figure 1).
Lisa Marchewka, vice president of strategy
and marketing for Oasys, explains, “We use
membrane technology, but instead of using hy-
draulic pressure to force water through a mem-
brane, we instead use a high-molarity ‘draw’
solution that pulls freshwater across the mem-
brane rather than pushing it on the surface.”
The key ingredient in the system is the
draw solution. Oasys uses ammonium bi-
carbonate, which is an off-the-shelf product
available in bulk. Although ammonium bi-
carbonate is not completely harmless, it is
a relatively safe product that was once used
in homes before modern day baking powder
became available. In fact, Oasys obtains its
product from the well-known baking soda
company Arm & Hammer.
Feedwater enters the FO system at one
end of the membrane module (Figure 2). The
draw solution flows on the opposite side of the
membrane, counter to the direction of feedwa-
ter flow, and pulls water molecules through the
membrane. The draw solution becomes more
and more diluted until it exits the module and
is directed to the thermal process.
In the thermal recovery device, the diluted
draw solution is heated to evaporate only the
draw solutes, leaving behind the clean, puri-
fied water. Because evaporation of the water
The handling of power plant water and wastewater is becoming increasingly com-
plex. Fortunately, innovative treatment technologies can help. Recent advances in-
clude forward osmosis, membrane bioreactor wastewater treatment systems, and
reverse osmosis membrane improvements.
Aaron Larson
Courtesy: U.S. Water

WATER & WASTEWATER
is not required in the thermal column (Fig-
ure 3), less energy is consumed than would
otherwise be necessary. Another advantage
of this arrangement is that no impurities en-
ter the thermal process, therefore scaling and
foaming are not a problem.
By design, the closed loop system should
not require additional ammonium bicarbon-
ate to be added. The plant has typical me-
chanical components though, such as tanks,
valves, pumps, and piping, so there is always
the potential for leaks or a component fail-
ing. For that reason, Oasys suggests that ad-
ditional draw solution be kept on hand.
Benefits of FO
Oasys says its FO system offers some advan-
tages over other more common water treat-
ment options. According to Marchewka, in
RO systems used for seawater desalination,
the typical water recovery rate is only about
50%. In other words, for every two gallons of
seawater taken into a system, one gallon of
purified water is produced and one gallon of
reject water is discharged back to the source.
The FO process can be used to take the reject
from a seawater desalination RO system and
concentrate that to achieve an additional 80%
recovery. Therefore, combining the two sys-
tems can result in an overall recovery of 90%.
RO systems also are limited in the salinity
that they can handle. Once the system reaches
its maximum hydraulic pressure, water can
no longer be pushed through the membrane
to achieve recovery. In contrast, FO technol-
ogies can treat water up to 150,000 ppm of
total dissolved solids—four times the maxi-
mum for conventional RO systems—and con-
centrate it to over 280,000 ppm. So not only
can much higher recovery be achieved using
FO—because it is not limited by an osmotic
gradient—but it also operates at a lower pres-
sure, which offers an energy savings.
Thermal systems, such as multiple effect
distillation, multi-stage flash, or mechanical
vapor recompression, offer another option
for desalination of seawater and brine con-
centrating. Although thermal systems can be
designed to work well in many situations,
they have limitations of their own.
For one thing, thermal systems are capi-
tal intensive to install. The materials used
have to be capable of handling the corrosive
effects of seawater, so they are frequently
constructed of more expensive alloys. The
energy consumed by a thermal system is also
much higher than in FO systems.
In thermal systems, the feedwater must be
heated to its vaporization temperature, which
requires significant energy. The vapor is then
condensed to produce the distillate. In that
process, impurities in the water can cause
scaling or foaming, resulting in a very main-
tenance-intensive operation. As noted previ-
ously, only the draw solution and clean water
enter the thermal recovery column of the FO
system, which eliminates this problem.
Innovative FO Uses
Although FO and RO may sound like rival sys-
tems designed using similar technology—the
membrane portion of an FO system does look
nearly identical to that of an RO system, at
least on the outside—Oasys views its FO sys-
tem as more of a complement to RO systems
rather than a replacement for them. It suggests
FO systems are better able to compete directly
with thermal evaporation systems.
“The focus of the company, right now,
is more on industrial high-salinity recov-
1. In with the new. Oasys Water’s forward osmosis technology is installed to treat flue
gas desulfurization wastewater at the Changxing Power Plant in China. Courtesy: Oasys Water
3. The draw solution thermal re-
covery system. Heat is added in the ther-
mal column to evaporate the draw solution,
leaving behind purified water. Courtesy: Oa-
sys Water
2. No magic involved. This process diagram shows how a forward osmosis system
produces purified water. Source: Oasys Water
Saline water
Concentrated brine
Draw
solution
Salt-rejecting
membrane
Recovery
system
Heat
Clean water
Salt
Draw
solutes
Water
diffusion
Organics,
minerals,
pollutants

WATER & WASTEWATER
ery projects, specifically in zero-liquid
discharge, or near zero-liquid discharge sys-
tems,” said Marchewka.
In addition to the FGD wastewater treat-
ment system Oasys installed at the Changx-
ing Power Plant, it has another FO system
already operating in China. That system has
the flexibility to be used for seawater de-
salination or for treating cooling tower blow-
down, depending on the plant’s needs.
Through a partnership with National
Oilwell Varco (NOV), Oasys’ technology
is being deployed in the oil and gas in-
dustry too (see this issue’s cover photo).
NOV says the system is suitable for on-
shore unconventional shale plays, and it
markets the solution as a means of treating
exploration and production wastewaters. It
touts that these streams can be converted
to freshwater quality, fully treated for re-
use in new drilling and completion fluids
or for surface discharge in remote areas
where disposal options have traditionally
been limited and expensive.
Oasys says it is the first company to de-
ploy an FO-based brine concentrator. The
company can also imagine using the technol-
ogy for things like brackish desalination and
other municipal applications.
One final advantage that really benefits
operators is the FO system’s ability to handle
variation. Marchewka noted that the company
has learned from its experience in China that
the water chemistry from the FGD process
is quite variable—seasons, load, and various
other operating parameters all factor in. Al-
though changes can be problematic for many
systems, because the FO system operates at
lower pressure and pulls the water across the
membrane with the draw solution, it is much
less prone to fouling and scaling, and it can
handle the challenge.
“It actually gives operators a nice ben-
efit when dealing with fluctuations and
changes in water quality and water chem-
istry,” says Marchewka.
UtilizingTreated Municipal
Wastewater
Power plants continue to face greater restric-
tions in the usage of water from traditional
sources, such as oceans, lakes, rivers, and
wells. In the U.S., regulations like 316(b) are
forcing facilities to consider alternatives to
business as usual. State-of-the-art technology
has made treated municipal wastewater gen-
erated by publicly owned treatment works
(POTW) an attractive source of cooling water
makeup for many power plants.
A study conducted at the University of
Pittsburgh, evaluating more than 400 existing
coal-fired power plants, revealed that 49.4%
of them could have sufficient cooling water
supplied by POTWs within a 10-mile radius
of their plant. If the radius were expanded to
25 miles, the percentage increased to 75.9%.
It also evaluated 110 proposed power plants
and found that 81% of those facilities could
meet their cooling water supply requirements
from POTWs within 10 miles of their pro-
posed locations. The 25-mile radius satisfied
all but three of the plants.
According to Kaveh Someah, vice presi-
dent of global energy for Ovivo USA, the
use of reclaimed water started decades ago
and is gaining in popularity. There are a
number of treatment technologies that must
be considered based on an individual plant’s
situation, but one of the more advanced
methods includes the use of a membrane
bioreactor (MBR).
An MBR is a wastewater treatment process
utilizing biological treatment alongside filtra-
tion all in one common tank. MBR systems
are considered the best available technology
for wastewater treatment and reuse applica-
tions, because they are reliable, space efficient,
and cost effective. Ovivo—formerly known as
Eimco Water Technologies—worked with a
power plant in Texas to develop a solution that
uses an MBR system to provide makeup water
to the plant’s cooling pond.
The Membrane Bioreactor
Treatment Process
At the Texas facility, the screen box design
handles course screening, allowing raw
wastewater to be pumped straight into a fine-
screening system to remove particles that
could potentially damage the membranes.
The screened influent enters the equalization
basin, which maintains flow forward up to
the peaking capacity of the membranes.
If sufficient hydraulic pressure is not
available, the plant is designed with an emer-
gency overflow to a basin located adjacent to
the equalization basin. Once plant flow and
level return to normal, any overflow can be
pumped back to the equalization basin for
feed forward.
From the equalization basin, screened and
equalized wastewater is pumped to the anox-
ic basin. The level in the anoxic basin varies,
depending on hydraulic loading conditions.
Control of the MBR plant is based on level in
the anoxic basin.
A programmable logic controller (PLC) re-
ceives a level input and varies the flow rate of
treated water to accommodate influent flow. It
also initiates an intermittent mode to preserve
biology, reduce power consumption during
low plant loading, and protect equipment.
A mixer in the anoxic basin operates con-
tinuously to mix the activated sludge with
incoming wastewater, maintaining a uniform
concentration of mixed liquor suspended sol-
ids. Pumps in the anoxic basin are used for
feeding forward and internal recycling.
4. A state-of-the-art wastewater
treatment process. The submerged
membrane bioreactor configuration relies on
course bubble aeration to produce mixing and
limit fouling. Courtesy: Ovivo USA
5. Waste not, want not. The Palo Verde Water Reclamation Facility can treat up to 90
million gallons of secondary effluent from the Phoenix metropolitan area and provides all of the
cooling water for the Palo Verde Nuclear Generating Station. Courtesy: Arizona Public Service

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WATER & WASTEWATER
Diversion valves on the pump discharge
allow operator-controlled manual wasting of
waste-activated sludge—that is, removing a
portion of it—in order to maintain a proper
mixed liquor suspended solids concentration.
Waste-activated sludge is pumped to a sludge
holding tank that is aerated to prevent sep-
tic conditions. Sludge may be removed via
pump truck, if necessary.
From the anoxic basin, activated sludge is
pumped to the pre-aeration basin. Fine bub-
ble diffusers evenly disperse air, providing a
residual dissolved oxygen concentration to
prevent premature fouling of the membranes
in the MBR basin. The aerated mixed liquor
gravity feeds into the adjacent MBR basin.
Submerged membranes in the MBR (Fig-
ure 4) filter the sludge to produce an extreme-
ly clean effluent referred to as permeate. The
flow rate of permeate is controlled using a
modulating valve to maintain a constant level
in the basin. The membranes foul over time,
so the PLC automatically opens the control
valve to adjust flow until parameters signal
that fouling warrants an in-situ cleaning.
During the cleaning process, the mem-
branes are relaxed by closing the permeate
control valve and scouring the membranes
with the blower. Excess membrane biofilm
is scoured away to recover flux and improve
performance. A maximum relax time is set to
prevent membrane abrasion.
Permeate from the membranes is pumped
to an in-line chlorine tablet feeder for dis-
infection prior to discharge. Disinfected ef-
fluent then flows by gravity to the discharge
point. Sludge is processed through a belt
press for dewatering, and dry solids are re-
moved for disposal. The recovered water is
recycled back into the process for treatment.
The system in Texas is sized to treat
100,000 gallons of wastewater per day, pro-
viding effluent water suitable for makeup to
the plant’s cooling pond. Ovivo has many
other systems using various technologies op-
erating all around the world.
Zero-Liquid Discharge—and Beyond
One of the largest zero-liquid discharge
(ZLD) systems is at the Palo Verde Water
Reclamation Facility in Arizona (Figure 5).
It is a 90 million gallon per day tertiary treat-
ment plant that reclaims treated secondary ef-
fluent from the cities of Phoenix, Scottsdale,
Tempe, Mesa, Glendale, and Tolleson. Ac-
cording to Someah, the Palo Verde Nuclear
Generating Station is a ZLD facility and the
only nuclear power station that uses 100%
reclaimed water for its cooling.
Palo Verde’s process includes a series of
trickling filters to achieve biological de-nitri-
fication. Next, first- and second-stage solid
contact clarifiers remove hardness-causing
minerals and calcium from the water. Final
polishing is accomplished in mixed media
gravity filters, after which the softened water
enters the plant’s cooling water cycle.
“The technology to treat the water has
come a long way and has advanced drasti-
cally over the last decade,” said Someah.
“Today there are cost-effective technologies
offered by Ovivo that will allow the industry
to use the secondary treated water and treat it
further for use for cooling water source and,
with further treatment, for boiler feedwater.”
Membrane Innovations
The RO process is well understood and has
proven to work satisfactorily in many appli-
cations. Even so, membrane manufacturers
continue to improve upon thin-film com-
posite technology used in their elements.
According to U.S. Water Services Inc. (U.S.
Water), a Minnesota-based integrated water
management solutions provider, a couple of
significant advances have enabled design and
operation improvements in RO systems.
One improvement is in the fouling char-
acteristics of some membranes. Power plants
are frequently being forced to use poorer
quality water as a source for makeup to circu-
lating and demineralized water systems. The
latest fouling-resistant membranes have been
designed to meet the more difficult working
conditions while reducing cleaning frequen-
cy and minimizing pretreatment.
Pressure requirements for low-energy ele-
ments have also been improved. Historically,
low-energy elements have had rejection rates
too low to gain much acceptance in the power
industry. The negative impacts of increased
salt ion passage to downstream components,
such as mixed bed demineralizers or electro-
deionization systems, were too great.
However, newer membrane technology is
lowering pressure requirements while keep-
ing the rejection at, or near, traditional rates
of brackish water membranes. The improve-
ment allows original equipment manufac-
turers, like U.S. Water, to reduce pump and
motor sizes, which saves energy and im-
proves net plant heat rate.
While membrane improvements are help-
ful, the control of microbiological activity is
still extremely important to aide in the long-
term reliability of RO systems. Many fa-
cilities have large water tanks that serve as
process and firewater reserves. Holding times
in these tanks can be very long. As the water
sits relatively stagnant, controlling the micro-
biological growth in these tanks needs to be
considered. When they are left unmanaged,
operators often struggle to maintain control
and will be required to clean RO systems
more frequently.
Challenges can also result from active bio-
logical growth on RO membranes or from the
slimy byproduct shed from biofilms upstream
of the RO. U.S. Water strongly recommends
that plants maintain a free halogen level in
the process water tank and upstream multi-
media (Figure 6) or ultrafiltration systems at
all times to help minimize these issues. ■
—Aaron Larson is a POWER associate
editor.
6. Managing alternatives. Multimedia filters offer an option for removing suspended
solids, iron, and manganese from incoming water, which can improve RO performance. Cour-
tesy: U.S. Water

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WATER & WASTEWATER
Feedwater Chemistry Meets
Stainless Steel, Copper, and Iron
A
lloys found in the condensate and
feedwater systems of power plants in-
clude carbon steel for piping, pumps,
and in some cases heat exchangers. Many
systems still have some copper-based alloys
from admiralty brass, and copper-nickel (Cu-
Ni) alloys all the way to 400 Series Monel,
primarily as feedwater heater tubes.
The major corrosion mechanisms affect
the carbon steel and copper alloys. These in-
clude flow accelerated corrosion (FAC) and
corrosion fatigue in carbon steel as well as
ammonia-induced stress corrosion cracking,
and ammonia grooving in copper alloys. FAC
can have a variety of appearances (Figures 1
and 2).
Gradually, as aging feedwater heaters are
replaced, plants often choose to go with a
stainless steel alloy such as 304 or 316 for
feedwater tubing. When the last copper feed-
water heater is replaced, a change in feedwa-
ter chemistry is in order.
Stainless Steel
Stainless steel is protected by a tight adher-
ent chromium oxide layer that forms on the
surface. Stainless steels alloys are resistant to
essentially all the corrosion mechanisms that
commonly affect copper and carbon steel al-
loys in feedwater.
There is the tendency to think that stainless
steel is the perfect alloy to replace copper-
alloy feedwater heaters. However, stainless
steel has its own Achilles heel: Chlorides can
cause pitting, and chloride and caustic have,
in some cases, led to stress corrosion crack-
ing (SCC).
Typically, these chemicals are not present
in sufficient concentration to cause corrosion
on the tube side of feedwater heaters. How-
ever, there are cases where contamination of
the steam that feeds the shell side of the stain-
less steel–tubed heat exchanger has resulted
in SCC.
Remember, it is not the average concen-
tration of the chloride or caustic that is of
concern. Spikes in contamination can collect
and concentrate in the desuperheating zone
Developing a feedwater chemistry program that will minimize corrosion across a
variety of metallurgies doesn’t have to be difficult.This article reviews the require-
ments for three common metallurgies in condensate and feedwater piping and the
chemistry options that operators have to minimize corrosion in this critical area of
the plant.
David Daniels
Courtesy: Plymouth Tube Co.

WATER & WASTEWATER
of the shell side of the feedwater heater and
in crevices. These are the areas that can fail,
even if the steam is pure most of the time.
Where there is a potential for chloride or
caustic contamination of the steam, stainless
steels may not be the best fit or, at a mini-
mum, alloys should be considered that have
a higher resistance to chloride attack, such
as 316 or 904L. In general however, it may
be more productive to work on eliminating
the potential for contamination than to alloy
around the problem.
The most commonly quoted downside to
the replacement of copper-alloy feedwater
heater tubes with stainless steel is the dif-
ference in thermal conductivity. A quick
look at the reference values will show that
a 304 stainless steel has only one-seventh
the thermal conductivity of admiralty brass
and about one-third the conductivity of 90-
10 Cu-Ni alloy. Numerous papers have been
published discussing why these “textbook”
values are unlikely to be experienced in the
real world. This is certainly an important
consideration with condenser tubes, where
the potential for cooling water–side deposits
and condenser cleanliness is likely to have a
much more prominent effect on heat transfer
than the textbook thermal conductivity of the
tube metal. However, feedwater heater tubes
should have little steam- or water-side foul-
ing. Other factors, such as tube thickness
may offset some of the thermal conductivity
loss, and there are other design factors, such
as susceptibility to vibration damage, to con-
sider in selecting a material.
Carbon Steel
Carbon steel is passivated by the formation
of a dual layer of magnetite (Fe3O4). The
layer closest to the metal is dense but very
thin, whereas the layer closest to the water is
more porous and less stable. Hydroxide ions
are necessary for the formation of magnetite.
Due to the common utility practice of using
feedwater to control the final temperature
of superheat and reheat steam, the source of
hydroxide in feedwater must be volatile, and
ammonia or an amine is generally used for
this purpose. A solid alkali such as sodium
hydroxide must never be introduced ahead
of where the takeoff to the attemporation is
located.
Ammonia is very volatile, remaining in
gaseous state during initial condensation.
This may occur in the deaerator, condenser,
or on the shell side of a feedwater heater. This
lowers the effective pH of the first condensate
and increases the solubility of the magnetite
layer in that area. This can increase the rate
of FAC in these areas.
For carbon steel, higher pH values are bet-
ter for the production and stability of mag-
netite. Operating with low pH values in the
feedwater and condensate destabilizes mag-
netite and increases the rate of FAC on carbon
steel in the feedwater system. It also increas-
es the iron in the feedwater, which generally
winds up on the waterwall tubes. This iron
deposition increases the risk of under-deposit
corrosion mechanisms, inhibits heat transfer
across the tube, and increases the frequency
of chemical cleaning.
A case can be made for the use of carbon
steel feedwater heater tubes, particularly al-
loys such as T-22, which contains 2.25%
chromium (Cr) and 1% molybdenum (Mo).
It has better thermal conductivity than stain-
less steel, is highly resistant to chloride SCC,
and because it contains 2.25% Cr, is gener-
ally considered immune to FAC.
Copper Alloys
Copper alloy corrosion in the power industry
has been studied in depth due to problems
with copper deposits on the high-pressure
(HP) turbine that reduced turbine efficiency
and the maximum load that the unit could
produce.
Zinc-containing brass alloys such as ad-
miralty brass are particularly susceptible to
attack from ammonia vapors. This can result
in ammonia-induced SCC on the steam side
of the condenser or feedwater heater. The
same alloys are susceptible to a mechanism
termed “ammonia grooving,” where steam
and ammonia condense on the tube sheet and
support plates of the feedwater heater and run
over the tubes, creating a narrow group of
corrosion directly adjacent to the tube sheet
or support plate. Copper alloys containing
nickel are far less susceptible to ammonia-
induced SCC.
Admiralty brass alloys have the additional
concern of corrosion of zinc in the alloy due
to low-pH conditions in the feedwater or
steam. Over time, the zinc can leach from
the brass matrix, leaving only the copper
sponge, which has little structural strength.
This mechanism is called dezincification. Al-
though not as common, copper-nickel alloys
can also suffer from dealloying (Figure 3).
There are three separate rates associated
with the rate of corrosion of any copper alloy.
These have been referred to as:
■ Rd—the rate at which corrosion products
leave the surface as a dissolved species
in the water (typically copper ammonium
complexes).
■ Rf—the rate at which corrosion products
(copper oxides in operating steam and
condensate systems) form on the surface
of the metal.
■ Rs—the rate at which copper corrosion
products (typically oxides) leave the sur-
face as suspended particles.
These rates are not necessarily correlated
with each other and may not occur under the
same chemical conditions. Copper oxide for-
mation (Rf) can be protective, minimizing
further corrosion of the alloy—as long as it
remains intact. When chemical conditions
change, such as moving from an oxidizing to
a reducing condition, Rd and Rs may increase
dramatically. Protective copper oxides are
aggressively dissolved by the combination of
ammonia, carbon dioxide, and oxygen. The
most common place for all three of these to
1 Typical.Classic flow-accelerated corrosion
(FAC) orange peel texture with no oxide coating.
Courtesy: M&M Engineering Associates Inc.
2. Atypical. Compare the previous exam-
ple with this one showing an unusual pattern
of FAC in a deaerator. Courtesy: M&M Engi-
neering Associates Inc.
3. Weakened. Dealloying, dezincifica-
tion in brass alloys, or removal of nickel from
copper-nickel alloys will destroy the strength
of the material. Courtesy: M&M Engineering
Associates Inc.

WATER & WASTEWATER
be present is in a copper-tubed condenser that
has air in-leakage issues.
Once these corrosion products are dis-
solved or entrained, they are subject to down-
stream chemical conditions, where a change
in the at-temperature pH or the oxidation re-
duction potential (ORP) in a specific location
can cause the copper to “plate out” as copper
metal on suction strainers, pump impellers,
or on another feedwater heater tube surface
in the form of a pure copper “snakeskin.”
They may also continue on through the feed-
water system and deposit on a boiler or su-
perheater tube or on the HP turbine. Similar
conditions (plating out) can occur in stainless
steel sample lines, making the accurate mea-
surement of copper corrosion products in a
conventional sample line difficult.
Chemical Control of Feedwater
Proper alloy selection, either in the initial
construction or as equipment is replaced,
should be carefully considered. Once the
decision is made, the water chemistry pro-
gram must follow to minimize corrosion of
the feedwater equipment and deposits in the
boiler and turbine. The more metals there are
in the mix, the more things need to be con-
sidered in the chemistry program. Copper al-
loys, in particular, force compromises, as the
optimum chemistry requirements for copper
and iron cannot be met simultaneously.
Feedwater pH Control. The pH limits
recommended on all ferrous-alloy condensate
and feedwater piping are now a minimum of
9.2 with an upper limit of 9.8 or even 10.0
in systems with an air-cooled condenser. If
there are no copper alloys in the system, the
biggest downside to having too much ammo-
nia in the system is the frequent replacement
of cation conductivity columns rather than
corrosion in the carbon steel.
For those operating heat-recovery steam
generators (HRSGs), there can be a sig-
nificant drop in pH of the low-pressure (LP)
drum water as ammonia (and some amines)
leaves with the LP steam. It is important that
the LP drum pH be monitored continuously
and controlled certainly within the range of
9.2–9.8. Some suggest a minimum pH of 9.4
for water in the LP drum to protect down-
stream high-pressure and intermediate-pres-
sure economizers.
The current recommended pH range for
systems that have copper in either the main
condenser or feedwater heaters is 9.0–9.3.
(See the sidebar for an explanation of the ne-
cessity of accurate pH measurement.) Labo-
ratory studies have shown that is actually the
minimum range for avoiding copper corro-
sion in the copper alloys used in feedwater
heaters and condensers. Lower feedwater and
condensate pH values (for example, pH 7.0)
have higher copper corrosion rates than pH 9,
particularly under oxidizing conditions.
Ammonia or Amines. The addition of
ammonia to condensate is the simplest and
most direct way to raise the pH of the con-
densate and feedwater into the desired range
to create and stabilize the magnetite layer. In
all-ferrous systems, there should be a clear
case or desired objective for using any other
chemical for pH control. On the other hand,
the use of neutralizing amines in the utility
steam cycle has a long, successful history,
particularly in units that have copper alloys
in the feedwater heaters.
The decision to use neutralizing amine
for iron corrosion should be based primar-
ily on the need to provide more alkalinity (a
higher pH) in an area of concern than can be
achieved simply by increasing the ammonia
levels. This may include areas where steam
is first condensing into water, such as in an
air-cooled condenser, or where water/steam
mixtures are being released, such as in the
deaerator.
Although amines are more common when
copper alloys are found in the feedwater sys-
Measuring pH
Accurate pH measurement in high-purity
water is difficult. The very low specific
conductivity of the water combined with
the potential for ammonia to be lost and
carbon dioxide to be simultaneously ab-
sorbed by the sample while it is being
collected and measured can lead to con-
fusing results. Inaccurate pH monitoring
can result in over- or under-feeding of
ammonia or amines.
Continuous online pH monitoring using
pH probes specifically developed for high-
purity water can improve the accuracy and
reliability of the measurement.
The pH of high-purity waters can also be
calculated from a combination of the spe-
cific conductivity and cation conductivity
results. This can be done manually, or there
are commercially available instruments that
display a calculated and measured pH.
Due to these issues with pH, specific
conductivity is often used to control the
ammonia feed instead of controlling di-
rectly from a pH meter.
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