2015 09 power engineering
TRANSCRIPT
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YEARS
119
THE 316(B) RULE ONE YEAR LATER
SMALL GAS TURBINES ONE OF THE BIGGEST TRENDS IN DISTRIBUTED GENERATION
EMISSIONS CONTROL MULTI-POLLUTANT COMPLIANCE OPTIONS
SPECIAL REPORT:
BIG Solar
September 2015 • www.power-eng.com
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CHIEF EDITOR — Russell Ray
(918) 832-9368 [email protected]
ASSOCIATE EDITOR — Sharryn Dotson
(918) 832-9339 [email protected]
ASSOCIATE EDITOR — Tim Miser
(918) 831-9492 [email protected]
CONTRIBUTING EDITOR—Brad Buecker
CONTRIBUTING EDITOR—Brian Schimmoller
CONTRIBUTING EDITOR—Robynn Andracsek
CONTRIBUTING EDITOR—Wayne Barber
(540) 252-2137 [email protected]
CONTRIBUTING EDITOR—Barry Cassell
(804) 815-9186 [email protected]
GRAPHIC DESIGNER — Deanna Priddy Taylor
(918) 832-9378 [email protected]
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Phone: (847) 763-9540
E-mail: [email protected]
MARKETING MANAGER — Rachel Campbell
(918) 831-9576 [email protected]
SENIOR VICE PRESIDENT, NORTH AMERICAN
POWER GENERATION GROUP — Richard Baker
(918) 831-9187 [email protected]
NATIONAL BRAND MANAGER — Rick Huntzicker
(770) 578-2688 [email protected]
CHAIRMAN — Frank T. Lauinger
PRESIDENT/CHIEF EXECUTIVE OFFICER — Robert F. Biolchini
CHIEF FINANCIAL OFFICER/SENIOR
VICE PRESIDENT — Mark C. Wilmoth
CIRCULATION MANAGER — Linda Thomas
PRODUCTION MANAGER — Katie Noftsger
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DEPARTMENTS
2 Opinion
4 Industry News
8 Gas Generation
10 View on Renewables
11 Energy Matters
46 What Works
48 Products and Literature
56 Ad Index
18 Circulating Fluidized Bed Scrubber vs. Spray Dryer Absorber
In response to more stringent air emissions regulations, utilities are under pressure to add flue gas desulfurization to their coal-fired units. Power Engineering investigates the differences between state-of-the-art circulating fluidized bed scrubbers and the latest advanced spray dryer absorber designs.
34 316(b): One Year LaterAs the one-year anniversary of the EPA’s newest 316(b) regulations approaches, Power Engineering examines the details of the rule and how power producers can best meet the revised mandates.
42 Maintaining Maximum Efficiency in Power Generation Units
Pressure to lower industrial carbon dioxide emissions continues to foster increased interest in improved efficiency at steam generating facilities. Read about some of the issues operators face in their quest for more efficient plants.
24 Improving the Flexibility and Efficiency of a Gas Turbine-Based Distributed Power Plant
By building smaller, more flexible gas-fired power plants closer to actual load centers, network operators can better satisfy their customers’ power demands. Learn how an efficient and flexible distributed generation model can help power producers meet the challenges of today’s power landscape.
38 Turbine Oils: A Key Factor in System Reliability Turbine lubricants must perform under the hostile conditions of heat, friction, and chemical degradation. Learn how the right mix of oil and additives, combined with a disciplined program of testing and maintenance, can prevent unwanted varnish and forestall premature equipment wear.
12 Large-Scale Solar on the Rise
The cost of generating electricity from utility-scale solar power has
plummeted in recent years, but the possible end of federal investment
tax credits threatens to temper an otherwise sunny outlook for the
industry. Find out what the future holds for solar in North America.
No. 9, September 2015
1509PE_1 1 9/9/15 9:09 AM
2
OPINION
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In another bizarre twist, the CO2 lim-
it for existing plants is 1,307 pounds
per megawatt-hour while the CO2 lim-
it for new plants is 1,400 pounds per
MWh. Under the final rule, the stan-
dard for an existing plant is more strin-
gent than the standard for a brand new
plant. What gives?
The new standards can’t be achieved
without installing a carbon capture
and storage system, an expensive and
questionable technology.
“We just commissioned the most
efficient coal-fired power plant in the
country in Arkansas and its CO2 emis-
sions are just under 1,800 pounds
per megawatt-hour,” said Mark Mc-
Cullough, executive vice president of
Generation at American Electric Power.
The new CO2 standards are among a
host of new, costly requirements faced
by coal-fired power plants. The new
rules mean as much as 90,000 MW of
coal-fired generation will be retired be-
tween now and 2040. Most of those re-
tirements are expected to be achieved
by 2020.
The only real option for replacing
that dispatchable output is power fu-
eled with natural gas. “The risk profile
of coal and nuclear, from a utility per-
spective, is just too high,” McCullough
said. But too much reliance on natural
gas could lead to serious economic and
security issues for the nation’s power
sector, McCullough said.
“Absence of diversity is a recipe for a
big problem,” he said.
If you have a question or a comment,
contact me at [email protected].
Follow me on Twitter @RussellRay1.
The minute the Obama admin-
istration unveiled its final plan
to cut greenhouse gas emis-
sions from U.S. power plants, oppo-
nents launched the first of many legal
efforts to kill what some have described
as the most prejudicial regulation ever
proposed by the U.S. Environmental
Protection Agency (EPA).
The Clean Power Plan calls for sweep-
ing new requirements to cut carbon di-
oxide (CO2) emissions 32 percent below
2005 levels by 2030. The rule will require
a massive restructuring of the power
sector. It will decimate coal by establish-
ing unattainable CO2 standards for coal
plants. It does nothing to promote the use
of cleaner-burning natural gas, but it will
stimulate the deployment of intermittent
wind and solar power with new incen-
tives. What’s more, it will require states to
spend billions to comply with a rule that
may ultimately be vacated by the U.S. Su-
preme Court.
Several states have asked a federal ap-
peals court to stay the controversial plan
until the courts decide whether the EPA
has the authority to force states to limit
CO2 from U.S. power plants. More states
are expected to join a lawsuit challeng-
ing the rule, a case that will likely end
years from now at the Supreme Court.
What are the plaintiffs’ chances of
winning the case against the EPA? Bet-
ter than average, I would say.
On June 29, the high court struck
down the EPA’s Mercury and Air Toxics
Standard, better known as the MATS
rule, which established the first limits
on mercury, arsenic and acid-gas emis-
sions from coal-fired power plants.
The final MATS rule was issued back
in 2012 and became effective earlier
this year. However, the Supreme Court
remanded the rule to the D.C. Circuit
Court, saying the EPA failed to consid-
er the $9.6 billion cost of implement-
ing the new rule when drafting it. The
industry spent billions to comply with
the MATS rule, which now faces the
possibility of being vacated.
How the Supreme Court will rule on
the Clean Power Plan is anyone’s guess,
but its ruling on the MATS rule is com-
pelling evidence the high court may
reject the plan.
The states’ case against the Clean
Power Plan centers on the EPA’s au-
thority to regulate greenhouse gas
emissions from power plants under
section 111(d) of the Clean Air Act
(CAA). The states contend power plant
emissions are already regulated under
section 112 of the CAA. The CAA pro-
hibits the EPA from regulating power
plant emissions under more than one
section of the law.
What’s more, opponents of the plan
argue the EPA is already regulating pow-
er plant emissions under the MATS rule
and, thus, does not have the authority
to regulate such emissions under section
111(d) of the CAA. However, if the MATS
rule is vacated by the D.C. Circuit Court,
that legal argument will vanish.
“That may undermine one of the
key legal challenges to the EPA’s Clean
Power Plan,” said Andy Byers, associate
vice president at Black & Veatch. “A lot
of folks are speculating the EPA may go
back to the circuit court and ask them
to overturn their (MATS) rule.”
What You Need to Know About the Clean Power PlanBY RUSSELL RAY, CHIEF EDITOR
1509PE_2 2 9/9/15 9:10 AM
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4
INDUSTRY NEWS
www.power-eng.com
PJM Increases Payments to Power Producers 37 Percent
PJM Interconnection, the largest
electric grid in the U.S., will increase
payments to power generators 37 per-
cent.
The company said the increase will
begin in June 2018, and will be $164.77
per megawatt (MW) per day, as deter-
mined in a capacity auction held last
month. The price is almost $45 above
the previous 12 months reached in an
auction last year.
Precipitating the increase was a deci-
sion by federal regulators to allow PJM
to penalize generators that fail to sup-
ply promised power. The decision was
intended to prevent unplanned shut-
downs and fuel shortages, like those
that greatly inflated prices during the
winter of 2014.
Capacity costs were set at higher lev-
els for two regions because of supply
constraints. The eastern mid-Atantic
region, including New Jersey, Delaware
and Pennsylvania, finalized a price of
$225.42/MW/day, while prices in Ex-
elon Corp.’s ComEd utility territory
rose to $215.Under the new rules, the
grid operator can impose penalties of
about $2,800 per megawatt-hour on
generators who fail to deliver promised
power during emergency hours.
Exelon-Pepco Merger in Doubt After Regulators Reject Proposal
The D.C. Public Service Commis-
sion last month rebuffed a multi-bil-
lion dollar proposed merger between
power companies Exelon and Pepco.
The three-member commission unani-
mously rejected the $6.8 billion merger.
Chicago-based Exelon announced in
April 2014 plans to acquire Washing-
ton-based Pepco Holdings. The deal
would have created the largest electric
and gas utility in the region with about
10 million customers in cities includ-
ing Baltimore, Chicago, Philadelphia
and Washington.
Despite garnering the approval
of several surrounding states, Exelon
and Pepco failed to reach settlements
with regulators in Washington D.C.
Chairwoman Betty Ann Kane said
in a statement the companies failed to
show the merger was a benefit to the
public.
“The evidence in the record is that
sale and change in control proposed in
the merger would move us in the oppo-
site direction,” Kane said.
The companies expressed disap-
pointment in the decision and said the
commission did not recognize the ben-
efits of the merger.
Excel Energy Cuts GHG Emissions 20 Percent
Xcel Energy has become the first utility
in the nation to register nearly a decade’s
worth of greenhouse gas emissions data
with The Climate Registry, a nonprofit
organization that operates voluntary
and compliance greenhouse gas report-
ing programs throughout the world.
The company pledged to begin re-
ducing emissions in 2005, according to
Xcel Energy Vice President Frank Prag-
er. In the years since, the utility has
seen more than a 20-percent reduction
in carbon dioxide emissions and is on
track to achieve a 30-percent reduction
companywide by 2020.
Xcel Energy reached Climate Regis-
tered status by measuring and report-
ing the company’s emissions from
2005 to 2011. The data was then ver-
ified by a third party.
The company’s emissions from 2012
to 2014 are being verified and regis-
tered with The Climate Registry.
Obama Announces $1 Billion in DOE Initiatives
President Obama last month an-
nounced more than $1 billion in initia-
tives promoting clean energy.
The president’s Clean Power Plan per-
mits the Department of Energy’s Loan
Programs Office to guarantee up to $1
billion for commercial-scale distributed
energy projects like rooftop solar, smart
grid technology and methane capture for
oil and gas wells.
Distributed energy technologies reduce
greenhouse gas emissions while strength-
ening energy security and creating eco-
nomic opportunity, but projects often
encounter roadblocks when it comes to
lenders who are unwilling to take on the
risk of a new technology.
Additionally, the DOE is awarding
$24 million through the Advanced Re-
search Projects Agency – Energy for 11
high-performance solar power projects
aimed at lowering the cost and improv-
ing the performance of solar photovol-
taic power systems.
GE Signs its Largest Battery Storage Deal to Date
GE announced it will provide Coachel-
la Energy Storage Partners (CESP) with a
30-MW battery energy storage system as
part of CESP’s supply contract with the
Imperial Irrigation District (IID).
Representing GE’s largest energy stor-
age project to date, the plant will be built
in California’s Imperial Valley, 100 miles
east of San Diego. The facility will aid grid
flexibility and increase reliability on the
IID network by providing solar ramping,
frequency regulation, power balancing,
and black start capability for an adjacent
gas turbine.
GE will provide CESP with an integrat-
ed energy storage solution, configured
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6 www.power-eng.com
using GE’s Mark VI plant controls, GE
Brilliance MW inverters, GE Prolec trans-
formers, medium-voltage switchgear, and
advanced lithium ion batteries housed in
a GE purpose-built enclosure. The plant
will be operated by ZGlobal, an engineer-
ing collaborator with CESP, for the first 18
months, after which control will transfer
to the IID. Construction is expected to
begin early next year, with commercial
operation scheduled for the third quarter
of 2016.
NRC Issues Corrective Actions Against Millstone 2 Nuclear Unit
Dominion is implementing a range
of corrective actions at the Millstone
Unit 2 nuclear plant in Connecticut to
address violations.
In September 2011, the NRC became
aware that Dominion had submitted re-
quests for approval of amendments to
the Millstone 2 operating license that
were incomplete and inaccurate. The
requests were to modify requirements
for Unit 2’s charging pumps and irra-
diated fuel decay time. NRC’s Office of
Investigations began an investigation
the following November to determine
if there was any wrongdoing. On April
29, 2015, NRC notified Dominion that
the violations were considered for esca-
lated enforcement.
The first violation was for a will-
ful violation for changes made to the
plant’s Updated Final Safety Analysis
Report, without a license amendment,
that removed credit for a specific type
of safety-related pump in the mitiga-
tion of a plant accident. The second vi-
olation was a non-willful violation for
a failure to provide complete and accu-
rate information to the NRC pertain-
ing to the changes. The third violation,
related to the utility’s failure to obtain
a license amendment prior to making
changes related to spent fuel pool heat-
load analysis, was not considered for
escalated enforcement.
Louisiana Regulators Approve Merger of Entergy Utilities
The Louisiana Public Service Commis-
sion approved the merger of Entergy Lou-
isiana LLC and Entergy Gulf States Louisi-
ana LLC into a single utility.
The new utility will operate under the
name Entergy Louisiana LLC after the
deal closes Oct. 1. It will have over $16.5
billion in assets and 66,194 GWh in com-
bined sales. Louisiana’s utilities provide
electricity to more than one million cus-
tomers, and natural gas service to over
93,000 customers in the greater Baton
Rouge area. The merged company will be
a unit of Entergy Corp.
GE’s Gas Turbine Surpasses 75 Million Operating Hours
GE’s LM2500 aeroderivative gas tur-
bine has reached a milestone of 75 mil-
lion combined operating hours.
The current fleet of gas turbines totals
more than 2,800 turbines across six con-
tinents. Main features includes reaching
full power within 10 minutes, direct drive
for 50-hertz and 60-herts power genera-
tion, variable speed for mechanical drive,
dual-fuel capability for distillate or natu-
ral gas, reduced NOx with dry low emis-
sions combustor and natural gas fuel and
optional steam or water injection system
for NOx control.
The first LM2500 gas turbine began op-
erating on a U.S. Navy cargo ship, GE said
in a release. The turbine consists of a 16 or
17-stage axial flow compressor, annular
combustor, two-stage, high-pressure, sin-
gle rotor gas turbine and efficient six-stage
power turbine.
DOE Picks 8 Projects to Receive Funding for Cutting Cost of CO2 Capture and Compression
The U.S. Department of Energy’s
(DOE) National Energy Technology
Laboratory has selected eight projects to
receive funding to construct small- and
large-scale pilots for reducing the cost of
carbon dioxide (CO2) capture and com-
pression through DOE’s Carbon Capture
Program.
The Carbon Capture Program is de-
veloping technologies that will enable
cost-effective implementation of carbon
capture and storage (CCS) in the pow-
er generation sector and ensure that the
U.S. will continue to have access to safe,
reliable and affordable energy from fossil
fuels. The program consists of two core
research technology areas, post-combus-
tion capture and pre-combustion capture,
and also supports related CO2 compres-
sion efforts. Current research and devel-
opment efforts are advancing technol-
ogies that could provide step-change
reductions in both cost and energy pen-
alty compared to currently available tech-
nologies.
MidAmerican Building Iowa Wind Farms for $900 Million
MidAmerican Energy says it will build
its next two wind farms in northwest
Iowa.
The company says there will be 134
generators at the Ida County site and 104
at the site in O’Brien County, providing
a combined capacity of 552 megawatts.
The estimated investment for the two
projects is $900 million. A MidAmeri-
can vice president, Mike Gehringer, says
that by the end of the year, more of Mi-
dAmerican’s electricity will come from
wind than from any other single source.
MidAmerican spokeswoman Ruth Com-
er says that by the end of 2016, when both
projects are completed, the Berkshire Ha-
thaway-owned company will have more
than 2,000 wind turbines across Iowa.
1509PE_6 6 9/9/15 9:10 AM
NOx Reduction Catalyst
Bring down NOx and mercury emissions
Regulators worldwide are clamping down on mercury emissions, and complying with the
latest standards can be a costly burden. Topsoe’s DNX® series NOx reduction catalysts
can help you meet today’s tough standards without breaking the bank.
A unique tri-modal pore structure and specialized additives enable superior
mercury oxidation, while also ensuring high activity and durability,
outstanding poison resistance and low SO2 oxidation.
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8
GAS GENERATION
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complete borescope inspections at recom-
mended intervals. Although not a precise
indicator of part condition, signs of major
damage such as large crack indications,
excessive wear or oxidation, foreign object
damage, tip rubbing, and missing coating
should be explored. It is important to
document damage that occurs over time
in order to track the progression of known
conditions.
During major overhauls, users should
conduct cycling-targeted, non-destructive
testing (NDT), particularly on rotating
hardware. Depending on material, there
are multiple NDT techniques that can
identify cracks. These include liquid pen-
etrant, magnetic particle, and eddy cur-
rent inspections. Users should complete
pre- and post-repair inspections, especial-
ly if weld repair is required. In addition,
they should inspect the integrity of the
coating and determine if new coatings are
required. Always review repair inspection
reports for non-conformances so as to un-
derstand the condition of hardware prior
to reuse.
ASSESSMENT
FOR PART REUSE
With inspection results in hand, it must
then be determined if it is safe to continue
to use hardware. Recall the difference in
failure modes between base loaded and
cycling machines and the fact that many
parts are life limited by time at tempera-
ture failure modes. When coupled with
the results of the cycling targeted failure
mode inspections, knowledge of the ac-
cumulated operating hours of hardware
enables educated decisions concerning
part reuse. Given the cost of replacement
hardware, significant monetary benefits
can be realized using this strategy.
Gas turbine maintenance inter-
vals are determined by hours,
starts, or a combination of both.
The latter is often referred to as equivalent
operating hours (EOH). The increasing
integration of renewable energy sourc-
es into generation portfolios has meant
changes in dispatch, and many tradition-
ally base-loaded assets are being forced
to load follow and on-off cycle, as seen
in many gas turbine and combined-cycle
arrangements across the country. With
such shifts in operational patterns
comes a shift in the failure modes that
manifest, as well as the inspection
techniques required to effectively diag-
nose these respective modes. Given the
competitive marketplace, it is valuable
to understand applicable failure modes
and inspection techniques to effective-
ly balance the fine line between scrap-
ping parts prematurely and running
hardware beyond safe conditions.
CYCLING VS. BASE
LOAD FAILURE MODES
When a unit starts and stops, it is ex-
posed to significant cyclic stresses in ad-
dition to large thermal transients in the
high-temperature sections of the engine.
This can lead to thermal mechanical fa-
tigue or low-cycle fatigue cracking. After
cracks begin, they continue to propagate
with each new cycle. If not addressed in
time, liberation of a rotating blade can
lead to substantial forced outage time and
repair costs.
For cycling units, it is also common to
sustain damage at interface or contact sur-
faces. Damage occurs from the repetitive
relative movement between surfaces, or as
a result of increased deflection of the rotor
through critical speeds. Some examples
of these surfaces include rotor to blade
root interfaces, tip contact faces on adja-
cent shrouded blades, and compressor or
turbine blade tips. In addition, cycling has
been shown to increase coating spallation
rates for coated parts, thus leading to pre-
mature oxidation of the hardware. The
impact of cycling is not limited to a sin-
gle section of the gas turbine. TG Advisers
has been involved in root cause failure
analyses ultimately attributed to cycling
in the compressor, combustion, and hot
sections of gas turbines.
It is also important to understand base
load failure modes. Base loaded machines
are mainly limited by failure modes that
result from prolonged operation at ele-
vated temperatures. These failure modes
include creep, coating/surface oxidation
damage, and embrittlement. Creep dam-
age is very difficult to detect non-destruc-
tively. As a result, hot section rotating
blades often have conservative life guide-
lines. This design philosophy is under-
standable given the scatter in material
properties, difficulty of detecting creep,
and severity of a blade failure. The risk for
failure modes that require extended time
at high temperatures, such as creep, is less
in gas turbines that exhibit cycle dominat-
ed maintenance intervals.
CYCLING-TARGETED
INSPECTIONS
The key to effective inspections is un-
derstanding the applicable failure modes
and how they manifest. This holds true
for broad condition inspections such as
in-situ borescope inspections, as well as
for detailed inspections completed during
major outages.
Prior to overhaul, and as a routine
maintenance practice, users should
Renewable Energy – Pushing Gas Turbine Components to Their Cycling Limit!BY THOMAS R. REID, TG ADVISERS, INC.
1509PE_8 8 9/9/15 9:10 AM
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VIEW ON RENEWABLES
www.power-eng.com
– sweeping a greater area to make the
most of the available wind resource.
At an average wind speed of 7.5 me-
ters per second (nearly 17 miles per
hour), the Siemens SWT-2.3-120 yields
an increase of nearly 10 percent in an-
nual energy production (AEP) com-
pared to that of its pioneering prede-
cessor under the same
conditions – helping
to deliver higher re-
turns and a decrease
in the Levelized Cost
of Energy .
Production of this
new wind turbine
will begin in 2017,
and we are pleased
that its production will support clean
energy jobs here in the U.S., where we
have close to 2,000 workers in our new
unit and service businesses.
The nacelles and hubs will be as-
sembled at our facility in Hutchinson,
Kansas, and the blades will be manu-
factured at our blade factory in Ft. Mad-
ison, Iowa. And our national network
of wind service technicians is ready to
keep these turbines running optimally
throughout their lifecycle.
With more than 5,000 wind turbines
installed in the U.S., Siemens is leading
the effort to ensure that wind power is
an increasingly important part of the
nation’s energy mix.
At Siemens, we have more than 30
years of global experience in onshore
wind – and this new turbine is the lat-
est example of our strong commitment
to the growth of wind energy in the
United States.
The Department of Energy’s
Wind Vision report recently laid
out a plan to double wind ener-
gy in the U.S. by 2020, double again to
20 percent by 2030, and expand to over
one third of energy production by 2050.
With policymakers in Washington
focusing on reducing greenhouse gas
emissions, wind power is a natural com-
plement to fast-growing natural gas – a
prime building block for lowering car-
bon emissions. The U.S. already leads
the world in the amount of electricity
that is produced by wind – with more
than 181 million megawatt hours in
2014 – and the cost of wind energy has
dropped by half over the past five years.
As a share of the nation’s energy mix,
wind has grown from under 1 percent to
nearly 5 percent over the past eight years
– competing with natural gas for the top
spot of new power added to the system.
Because it is a low-cost solution with
zero emissions, it is clear that wind ener-
gy will play an important role in cost-ef-
fectively meeting the goals set forth by
the Obama administration.
In order to continue to reduce the
cost of wind energy, ongoing technol-
ogy enhancements are essential. Be-
cause of performance enhancements,
onshore wind is nearly reaching grid
parity. At Siemens, we are committed
to continually enhancing our technol-
ogy in order to grow the wind indus-
try here in the U.S. Earlier this year,
at the 2015 AWEA WINDPOWER Con-
ference & Exhibition in Orlando, Sie-
mens announced the latest addition
to our G2 product platform. This new
SWT2.3-120 wind turbine builds upon
the proven design principles of our G2
platform. Nearly 8,000 units have been
installed globally.
With wind power becoming an
increasingly important part of the
U.S. energy mix, this new turbine
was designed in America specifically
to meet the needs of the American
market. The SWT-
2.3-120 offers proven
technology tailored
to local requirements
and designed to
lower the levelized
cost of energy.
Building upon the
achievements of the
SWT-2.3-108, the new
SWT-2.3-120 features a high-perfor-
mance 120-meter rotor that enables en-
hanced energy production, lower sound
power levels and improved operating
temperature and altitude capabilities.
At our aerodynamic R&D center in
Boulder, Colorado, the new blade type
was designed to optimize the perfor-
mance of next generation wind com-
ponents – resulting in an aero-elastic
blade design that improves efficiency
and reduces loads through intelligent
use of the blade’s flexing capabilities.
This allows for the SWT-2.3-120’s larg-
er rotor size without a proportional in-
crease in structural loading – decreas-
ing wear and tear on the turbine.
The new blade was designed with the
goal of increasing energy production
for sites with medium to low wind con-
ditions, which comprise a significant
part of the U.S. market. The 59-meter
blades extend the reach of the rotor
WIND POWER: Made for American Needs BY JACOB ANDERSEN, CEO ONSHORE AMERICAS, SIEMENS WIND POWER & RENEWABLES DIVISION
“As a share of the nation’s energy mix, wind has grown from under 1 percent to nearly 5 percent over the past eight years.”
1509PE_10 10 9/9/15 9:10 AM
11
ENERGY MATTERS
www.power-eng.com
April EscamillaRobynn Andracsek
communities were the least likely
to mount a serious challenge to the
industry because low income people are
often less well-educated, have less access
to computers and internet technology,
are less knowledgeable of how to access
and interpret environmental data, and
are the least likely to have the resources
for a time consuming legal battle.”
The Freedom of Information Act
(FOIA), enacted in 1967, is the usual
method to obtain records about a
plant’s operation: emissions, limits, or
almost anything needed to demonstrate
compliance (other than business
confidential information). For larger,
more publically sensitive projects such
as those at power plants, many states
have already adopted a policy of creating
websites where the most requested
documents can be downloaded by the
public. This simple action saves the
agency manpower in fulfilling repetitive
FOIA requests. However, FOIA requests
and state websites put the burden of
transparency on the government and
not the regulated entity. By requiring
each coal plant to post their compliance
information on the internet, neighbors,
activists, and other interested parties
can play armchair watchdog.
For now, EPA seems to have met the
needs of all parties involved. Citizens
can scrutinize their local utility, state
agencies can redirect their budgets to
enforcing other regulations, and EPA
can stay neutral until they are dragged
into action by a lawsuit. And the
utilities? While they are busy managing
ash and protecting the environment,
citizen groups will be watching every
move.
The new rules on Coal Com-
bustion Residuals (CCR) have
a novel requirement aimed at
making compliance efforts transparent:
many records must be posted on the in-
ternet to allow easy public accessibility.
Requiring a website is an interesting de-
velopment and is an obvious next step
in regulatory communication.
On April 17, 2015, the Environmental
Protection Agency (EPA) published the
final version of the federal CCR rule
on the storage and disposal of CCRs
generated by electric utilities. The CCR
rule is expected to affect more than
1,000 active CCR management units
throughout the U.S, particularly the
owners and operators of CCR landfills
and surface impoundments. The new
rule includes provisions addressing the
potential for catastrophic failure of CCR
containments, groundwater monitoring,
operational requirements, recordkeeping
and reporting, as well as closure
procedures for inactive or failing facilities.
Under the rule, there are numerous
requirements that must be performed
by a professional engineer, and others
by a qualified individual. The rule will
require installation of groundwater
monitoring wells, and a groundwater
monitoring program for taking
samples and assessing that data. In
addition to thorough recordkeeping
and notification requirements, owners
and operators of CCR sites are now
required to maintain a public website
hosting all compliance information,
including monitoring reports. The rule
also outlines timeframes and procedures
for site closure, and also details closure
consequences for sites failing to meet
these criteria. The first provisions of
this rule are expected to take effect on
October 19, 2015.
As part of these provisions, all owners
and operators of over 1,000 identified
active landfills and surface impound-
ments, currently receiving CCRs are
now required to establish and maintain
a website of CCR facility operation-
al compliance data called “CCR Rule
Compliance Data and Information.”
The website must be made publically
available, and host items identified in
the CCR rule are required to be publi-
cally accessible. Some of the items that
must be included are annual ground-
water monitoring results, corrective ac-
tion reports, fugitive dust control plans,
structural stability assessments, emer-
gency action plans, and closure com-
pletion notifications. As information is
uploaded to the site, notifications must
be sent to the state and local tribal au-
thorities.
The requirement for a website stems
from another unusual aspect of the CCR
rule: the rule does not require permits,
does not require states to adopt or
implement these requirements, and EPA
cannot enforce these requirements. EPA
has promulgated a rule that relieves itself
of the burden of assessing compliance.
Commenters on the draft rule fell on
both sides of the argument as to whether
or not civilian enforcement would be
effective. Some were encouraged by
the opportunity to enforce the rule
themselves since “…citizens have shown
no reluctance to challenge companies
that they believe are not responsibly
following environmental regulations.”
Others felt “environmental justice
Kicking Ash and Taking NamesBY APRIL ESCAMILLA, BURNS & MCDONNELL, AND ROBYNN ANDRACSEK, P.E., BURNS & MCDONNELL AND CONTRIBUTING EDITOR
1509PE_11 11 9/9/15 9:10 AM
12 www.power-eng.com
RENEWABLE POWER
The utility-scale solar en-
ergy industry is feeling
its oats. The cost of gen-
erating electricity from
solar power has plum-
meted in recent years, and experts say
it will continue to drop. Utility-scale
solar is on par with, if not cheaper
than, power produced with fossil fuel
in many markets in the U.S., and there
are more than 27 GW of solar projects
either under construction or in the
planning stages.
Yet, there are a few clouds darken-
ing the utility-scale solar market. The
darkest being the possible sun setting
of federal investment tax credits (ITC)
at the end of 2016.
Solar has about 1 percent of the
power generation market in the U.S.,
but the industry is scoring some his-
toric firsts. Georgetown, Texas, about
50 miles north of Austin, recently an-
nounced that it will use solar and wind
power to become one of a handful of
U.S. cities running on 100 percent re-
newable energy.
The solar power will come from a
150 MW project in West Texas, accord-
ing to John Lamontagne, senior direc-
tor of corporate communications at
SunEdison. What’s interesting about
the announcement is why the city
chose SunEdison: price.
“They did it because we were the
lowest cost option for local ratepayers,”
Lamontagne says. “In other words,
solar energy (along with wind power)
were the cheapest ways to power that
town.”
PROJECT PROFILE
There are two main ways to gener-
ate solar power: photovoltaic cells or
concentrated solar power (CSP). CSP
uses mirrors to focus solar energy to
create heat, which can then power a
traditional steam turbine. Photovoltaic
cells use an electronic process to con-
vert sunlight into electricity.
The Ivanpah Solar Electric Generat-
ing System uses solar thermal technol-
ogy to produce energy. Unlike tradi-
tional solar farms, more than 300,000
computer-controlled mirrors track the
sun and reflect it towards boilers that
sit atop immense towers. Steam is cre-
ated when the concentrated light hits
the boilers. The steam is piped to a tur-
bine where it creates electricity.
Ivanpah, which has been live since
January 1, 2014, has three units with
a total generating capacity of 377 MW.
Units 1 and 3 provide power for Pa-
cific Gas & Electric while unit 2 sends
electricity to Southern California Edi-
son. The plant has a 30-year license to
operate on public land in California’s
Mojave Desert, 45 minutes southwest
of Las Vegas. About 65 full-time op-
erations and maintenance employees
work at the plant.
Ivanpah, a partnership between
BrightSource Energy, Google and
Large-Scale Solar on the RiseBY ROBERT SPRINGER
NRG called Solar Partners, was built
by Bechtel. NRG Energy Services han-
dles the plant’s operations and main-
tenance.
The plant reaches full load during
sunny days, says Mitchell Samuelian,
vice president of operations and main-
tenance for NRG Renew and the former
general manager of Ivanpah. “On sun-
ny days we’ve made over 103 percent
of our estimated energy that we were
supposed to reach in the year,” he says.
1509PE_12 12 9/9/15 9:10 AM
13 www.power-eng.com
The challenge is how to produce the
most electricity during partly cloudy
weather. The goal, explains David
Knox, senior director, wholesale and
new business communications at
NRG, is to “collect as much solar en-
ergy as you can to start it up as quickly
as you can, and then to continue that
throughout the day, whether it be high
noon or early evening and optimizing
that throughout the entire day.”
This is technically very challenging
to do, according to Samuelian, “Be-
cause you’ve got clouds moving in and
out and you’ve got a steam plant with
thermal inertia and the parts and piec-
es move around,” he says.
In the early morning, virtually all
of the mirrors are aimed at the tower,
but as the day goes on some go into a
standby position so the tower doesn’t
overheat. The process is regulated by
infrared cameras, Samuelian says.
“They monitor the boilers surface with
infrared cameras, and they balance
turbine load with the amount of solar
they’re putting in and with how much
sunlight’s in the sky,” he says.
The boiler has three sections – super
heat, reheat and evaporator – and mul-
tiple mirrors heat a different section
of the boiler. Supercomputers balance
the energy on the three spots and give
aiming signals to each unit every 10 sec-
onds, according to Samuelian.
“I think that people don’t understand
The Ivanpah Solar Electric Generating System uses
mirrors to direct concentrated solar power at a
boiler, which produces steam to power a turbine and
produce clean electricity for Northern and Southern
California. Photo Courtesy: Ivanpah Solar Electric
Generating System
Author
Robert Springer is an Oregon-based
freelance journalist covering the energy
industry. His work has been published in
several publications, including Renew-
ableEnergyWorld.com and Power Engi-
neering magazine.
1509PE_13 13 9/9/15 9:10 AM
14 www.power-eng.com
RENEWABLE POWER
the complexity associated with that. I
mean these are actually run by big su-
percomputers that control the system,”
says Samuelian.
The plant uses recycled water, and
is using much less than originally
thought, at about 40 percent of the 100
acre feet allotment for all three units, ac-
cording to Samuelian. Using air-cooled
condensers helps, as does having “a
closed loop cooling system that ejects
the heat to the air rather than evaporat-
ing water. There’s a golf course next to
us out in the desert, and I think we use
the amount of water equal to two holes
on the golf course,” Samuelian says.
Another challenge is the sheer size of
the plant. A coal-fired plant of similar
size would have a much smaller foot-
print, Samuelian says. Ivanpah’s three
units cover about 3,000 acres and is
about five miles end to end. “So if I’ve
got someone working in the solar field
on one end of the plant and I need them
to go look at something else on the oth-
er end of the plant, there’s restrictions
on what speed you can drive onsite, for
wildlife considerations, and creating
dust, and so, the speed limits like 10
miles an hour,” says Samuelian. It takes
about half an hour to go from one end
of the plant to the other.
FOLLOWING THE
PHOTONS: SOLAR IS MORE
THAN PANELS
Solar panels get the lion’s share of
the publicity, but they’d just be large,
shiny mirrors without the ability to
take the electricity the solar panels pro-
duce from the panel to the grid. ABB, a
global provider of power and automa-
tion technologies, manufactures and
installs the equipment that allows util-
ities to get solar energy onto the grid.
ABB’s products take over once the
solar panels have converted the ener-
gy from photons into DC power, says
Bob Stojanovic, ABB’s director of solar
power for North America. “What ABB
makes is everything from the connec-
tors that connect the cabling to the de-
vices,” he says.
Groups of solar panels (or “strings”)
run in a series and in parallel until they
get the maximum voltage they’re de-
signed for, and the electricity is taken
to a combiner box, which is a group of
fuses and switches that take the input
from the strings and combine it into a
single output, according to Stojanovic.
“And that typically runs back to another
larger combiner box, which is typically
a bunch of breakers or large fuses that
take the rest of these strings and com-
bine it into one big DC input into an
inverter,” he says.
The DC power needs to be converted
to AC to reduce losses and because that’s
what the North American grid supports.
Stojanovic says they typically get
somewhere around 300 to 690 volts
of AC out of the inverter, and “then it
goes through what’s called an inverter
step-up transformer” or padmount
transformer, he says. The transformer
typically boosts the voltage up to 34.5
KV.
Although there are small losses
during the conversion process, the fi-
nal boost to 34.5 KV will decrease the
loss as the power is sent to the substa-
tion, according to Stojanovic. “Inside
the substation you’ll typically string,
depending on the plant design, some-
where between, five to eight converters
together on the same circuit, and you’ll
bring it back to a main breaker, a feeder
breaker which will then feed it into the
main power transformer,” he says.
ABB manufactures turnkey substa-
tions and almost all of the equipment
that’s in the substations, Stojanovic
says, “Everything from the reclosers to
the tank breakers to the power trans-
formers, the current transformers, and
the instrument transformers where
you measure power and voltage.”
Stojanovic says that ABB has no
ABB provides concentrated solar power
and thermal automation solutions for
solar farms around the world, including
this customized application with eSolar’s
Sierra SunTower facility in Southern
California. Photo Courtesy: ABB
1509PE_14 14 9/9/15 9:10 AM
exist? No, definitely not. It has become
very competitive to the point where I
think it would certainly cause a consid-
erable slowdown in the industry, but
I’m confident that the industry can ab-
sorb it if it’s forced to,” he says. “It will
certainly spur a high level of consolida-
tion in the industry and only the very
strong and very efficient will survive
the expiration of the ITC. “
David Feldman, senior financial an-
alyst at the National Renewable Ener-
gy Laboratory, notes that the personal
homeowner credit completely goes
away, so the distributed market could
be harder hit than the utility-scale one.
He also thinks it’s time for the ITC to
go away entirely, albeit gradually. “The
best thing that I think that could hap-
pen is that they just agree to somehow
put some sort of orderly ramp-down in
place rather than just a hard cliff; but I
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desire to enter the solar panel market,
although the company looked into
it a few years ago, as they realized it
was not a core competency. “What we
manufacture is power and automation
equipment. That’s really where we can
add value,” he says.
WHAT HAPPENS IN 2017?
There are a myriad of predictions for
what would happen to the U.S. solar
industry if the federal investment tax
credit were to decrease from the cur-
rent 30 percent to 10 percent in 2017.
The predictions range from an extreme
disruption of the industry to a 12 to 18
month hiccup in the industry’s rapid
growth of the past few years.
“I think right now people are pro-
ceeding with cautious optimism,” says
Katherine Gensler, director of gov-
ernment affairs for the Solar Energy
Industries Association (SEIA). “This
is in contrast to say the last five or six
years, where there was sort of a boom-
ing industry and a growing industry.”
Gensler adds that the eight year ITC
extension that the industry received in
2008 allowed the industry to grow and
especially helped larger utility-scale
projects that had long lead times.
Charles Pimentel, Solar Frontier’s
chief operating officer, is not optimis-
tic that congress will extend the ITC in
its current form, although he is “con-
fident that congress will provide some
kind of interim solution, whether it be
a complete extension, or whether it be
some kind of safe harbor, or some kind
of grandfathering in of projects com-
pleted by the end of 2016,” he says.
He doesn’t foresee long term damage
to the industry if the ITC is allowed
to expire. “Will the industry cease to
1509PE_15 15 9/9/15 9:10 AM
16 www.power-eng.com
RENEWABLE POWER
commission to leave things as they are,
while Pacific Gas & Electric and South-
ern California Edison want payments
lowered to new net metered installa-
tions.
FUTURE OF SOLAR IN N.A.
While experts agree that solar has a
place at or near the head of the table
of renewable energy options for North
America, the industry has some sub-
stantive challenges in addition to the
possible expiration of the ITC at the
end of 2016.
ABB’s Stojanovic is an “optimist”
when it comes to technological innova-
tions that will continue to drive down
equipment costs and increase efficien-
cies in the next few years. “They’ve ba-
sically proven everybody wrong over
the last five years by blowing away
whatever cost curves they thought they
think whoever’s in office, it’s going to
take congress as well as the president
to decide what the policy is going for-
ward. But all energy is policy, so it’s not
just solar,” he says.
NET METERING:
A DEBATE IN MANY STATES
Net metering, or the process of selling
excess electricity generated on-site back
to a utility at retail power rates, is an
issue that utilities and solar-using rate
payers are passionate about. The rate
at which customers are paid for energy
sold back to a utility impacts its bottom
line and the cost effectiveness of a roof-
top solar installation, experts say.
Pimentel says that while net meter-
ing does impact a utilities bottom line,
it won’t destroy their business model
as rooftop solar is such a tiny percent-
age of the energy generated in North
America.
“If a homeowner is typically paying
the utility $250 every month and all
of a sudden the utility is only getting
$15 a month, that impacts their reve-
nue,” he says. However, if a utility has 2
million customers and only 5,000 use
solar “it’s not going to destroy the utili-
ty. It will affect their revenue and their
economics, but it’s certainly not going
to destroy them,” he says.
It makes sense for customers to be
paid the retail rate, according to Feld-
man, as utilities don’t have to pay for
pay transmission charges, the facili-
ties are collocated and there are other
benefits which make distributed solar
worth a higher value price.
The solar industry itself is of two
minds about net metering. In Califor-
nia, the SEIA and the Alliance for Solar
Choice have asked the public utilities
Solar Frontier’s CIGS solar modules provide 82.5 MW of
the Catalina Solar Project’s 143 MW. The project is near
Bakersfield, California. Photo Courtesy: Solar Frontier
1509PE_16 16 9/9/15 9:10 AM
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plants are not being planned for post
2016 until the ITC debate is resolved.
“There’s a lot more uncertainty about
the near-term future, but then once we
get through the uncertainty, the indus-
try is strong and will continue to grow,”
she says.
had in line,” he says.
Solar’s biggest challenge going for-
ward is making energy that’s affordable
in the daytime also affordable at night,
Stojanovic said. “I don’t think cost for
solar is the issue anymore,” he says.
Interconnection continues to be an
issue, according to Feldman. Putting
the right amount of solar technology in
the right location at the right cost is a
challenge. He says that a utility indus-
try that has placed a high premium on
reliability (a good thing) might be act-
ing too conservatively when it comes
to solar. In addition to reliability, flexi-
bility and storage are important factors
for utilities to consider, Feldman says.
Samuelian thinks era of the me-
ga-solar projects is over, as the low
price of oil and natural gas is “really
kind of driving the energy market in
general,” he says. Knox sees the home
solar market as “an incredible growth
market,” he says. “We just really see a
huge potential for the home solar mar-
ket, not instead of but in addition to
the utility-scale market.”
Many different technologies – in-
cluding wind, storage, diesel genera-
tors and solar – could converge to help
create a self-sustaining micro grid,
Samuelian says.
The number of states that have ag-
gressive solar and renewables programs
has grown exponentially, Pimentel
says, with North Carolina being the
poster child for this group. “Two years
ago, nothing was going on in North
Carolina, and now North Carolina will
do gigawatts next year,” he says. Geor-
gia is also getting into solar in a big
way, according to Pimentel.
New markets will be important for
the industry, Feldman says, as states
start to satisfy their Renewable Port-
folio Standards (RPS). If Arizona, for
example, hits its RPS, utility-scale so-
lar might not make sense there as the
demand will have evaporated. On
the other hand, states like California
and Hawaii have very aggressive RPS’,
which could balance out the demand.
Solar is also competing against wind,
Feldman notes.
Gensler says that there is “still some
trajectory” left in the market through
2016, but large utility-scale solar
1509PE_17 17 9/9/15 9:10 AM
18 www.power-eng.com
EMISSIONS CONTROL
JEA’s Northside Generating Station includes two Amec Fos-
ter Wheeler CFB boilers, each producing 831,000 ACFM of
flue gas. Each boiler uses a single SDA followed by a pulse
jet fabric filter to treat the flue gas produced by the pet
coke- and coal-fired unit. SO2 emissions are reduced up to
90 percent and SO3, HCl, and HF emissions are reduced up
to 99 percent. The plant has been in operation since 2002.
Photo Courtesy: Amec Foster Wheeler
Circulating Fluidized Bed Scrubber vs. Spray Dryer AbsorberBY MATTHEW FISCHER AND GREG DARLING
Toxics Standards or MATS), Regional
Haze (RH), and SO2, NOx, and partic-
ulates (Cross-State Air Pollution Rule
or CSAPR) have ratcheted up the pres-
sure on coal-fired generators to quickly
reduce a variety of pollutants. The EPA
estimates that CSAPR alone requires
more than 3,000 units at more than
1,000 plants located in 28 states to re-
duce emissions that cross state lines and
contribute to ground-level ozone and
fine particle pollution. CSPAR Phase 1
compliance takes effect this year while
MATS and RH reduction are ongoing
programs.
The debate over what limits will be
imposed has now shifted to how indi-
vidual units will comply with the pre-
scribed deadlines. There are as many
technical approaches to meeting new
emission limits as there are differences
in plant designs. Adding to the com-
plexity of any solution is the uncertain-
ty of future rules that will require fur-
ther reductions of an expanding range
of pollutants.
In the past, SO2
capture on a large
scale was the province of wet flue gas
desulfurization (WFGD) technology.
It has the advantage of a relatively low
operating cost and uses readily available
limestone as the reagent, which can be
recycled into a number of useful prod-
ucts to offset operating costs. However,
WFGD scrubbers do have disadvantag-
es, such as large capital and high main-
tenance costs. By design, many WFGD
systems require periodic discharge of
the scrubber liquor to maintain solids
Many utilities are
under pressure to
add flue gas desul-
furization to their
coal-fired units in
response to more stringent air emis-
sions regulations. There are a number
of multi-pollutant compliance options
available that have an edge over wet flue
gas desulfurization systems. This article
sorts out the difference between state-
of-the-art circulating fluidized bed
scrubbers and the latest advanced spray
dryer absorber designs.
By Matthew Fischer and Greg Dar-
ling, Amec Foster Wheeler
The converging U.S. Environmental
Protection Agency (EPA) rules for re-
ducing mercury, metals, acid gases, and
organic compounds (Mercury and Air
Author
Matthew Fischer is Product Leader, Dry
FGD Systems, and Greg Darling is Prod-
uct Leader, CFBS Systems, for Amec Fos-
ter Wheeler North America Corporation
Global Power Group – Environmental
Systems.
1509PE_18 18 9/9/15 9:10 AM
1SDA Design Details
Source: Amec Foster Wheeler
The SDA uses hydrated lime to treat flue gas. The heat of the flue gas evaporates the droplets, which cools the flue gas. Cooled flue gas with the dried products is directed to a fabric filter.
Solids DischargeHopper
PerforatedDistributionPlate & FlowStraightener
Flue Gas In
ReactionVessel
Two-PhaseReactionProcess
Two FluidNozzles
Flue Gas Out
19 www.power-eng.com
Source: Amec Foster Wheeler
The optimized two-fluid nozzle design ensures balanced atomizing air distribution in order to produce a consistent droplet size, and reduced compressed air consumption by a quarter. Also, tungsten carbide inserts have significantly reduced nozzle wear.
Two-Fluid Nozzles Released 2
Inserts
NozzleShroud
Lime Slurry
Atomizing Air
Shroud Air
LanceAssembly
Two FluidNozzle
Lime Slurry
Atomizing Air
AirReservoir
absorber (SDA), which sprays atom-
ized lime slurry droplets into the flue
gas. Acid gases are absorbed by the
atomized slurry droplets while simul-
taneously evaporating into a solid par-
ticulate. The flue gas and solid partic-
ulate are then directed to a fabric filter
where the solid materials are collected
from the flue gas. Amec Foster Wheeler
has installed 60 SDA units represent-
ing over 4,500 MW of plant capacity.
The second is the circulating fluidized
bed scrubber (CFBS, which circulates
boiler ash and lime between a scrubber
and fabric filter. Amec Foster Wheeler
has install 78 CFB scrubber units rep-
resenting over 7,000 MW of capacity in
the power and industrial industries.
Spray dryer absorber
SDA technology operates using ab-
sorption as the predominant collec-
tion mechanism. In general, the acid
gas dissolves into the alkaline slurry
droplets and then reacts with the alka-
line material to form a filterable solid.
Intimate contact between the alkaline
sorbent (hydrated lime) and flue gases
make the gas removal process effective.
and/or chlorides. This effluent requires
additional treatment which adds capital
and operating costs. Also the uncertain-
ty of future regulations, specifically the
Steam Electric Power Generating Efflu-
ent Limitation Guidelines (ELG), may
require additional discharge treatment.
WFGD is also limited in its ability to
capture mercury and SO3. Some plants
have reported increased mercury re-
moval as a desirable, but expensive
co-benefit when a selective catalytic re-
duction (SCR) system for NOx removal
was installed upstream of the WFGD
scrubber. Other plants have also add-
ed injection of one or more proprietary
reagents into the furnace, such as dry
sorbent injection (DSI), as a means to
increase the mercury removal co-ben-
efit. Stacking technologies is not a cost
effective long-term strategy to reduce
pollutants—it’s unnecessarily expen-
sive and reduces the overall reliability of
the entire unit. A more holistic solution
is preferred.
TECHNOLOGY
COMPARISON
Interest in dry or semi-
dry FGD scrubbers is in-
creasing due to its ability
to capture mercury, acid
gases, dioxins, and fu-
rans, in addition to SO2
and particulates. These
multi-pollutant technol-
ogies also have added
benefits: no liquid dis-
charge and significantly
reduced water consump-
tion, which is increas-
ingly important to pow-
er plants that are under
pressure to reduce water
consumption.
Two multi-pollutant
technologies dominate
the utility sector. The
fundamental difference
between the two tech-
nologies is the manner in which the re-
agent is mixed with the incoming flue
gas to remove the desired pollutants.
The first technology is the spray dryer
1509PE_19 19 9/9/15 9:10 AM
Source: FWEC
The principal operating steps is recycling a solids/hydrated lime and water mixture in the flue gas flow to capture pollutants, cool the gas, and then capture solids in a fabric filter. Other reactive absorbents like activated carbon can be added to target specific pollutants.
CFBS Design Details 3
Inlet Flue Gas
and Ash
CFB Scrubber
Fabric Filter
Air
Air
Water
HydratedLime
Solid By-
Product
Reactor Ash Drain
20 www.power-eng.com
EMISSIONS CONTROL
frequency (1–3 weeks continuous
operation), reduced cost of operation
(20-25 percent less compressed air
consumption), and longer life with
its new tungsten carbide inserts. In
addition no special tools are required
for routine maintenance.
The SDA design also provides
additional operating flexibility for
the entire plant. For example, any
two-fluid nozzle can be removed
for maintenance without decreasing
boiler load. Emissions performance is
maintained even when multiple two-
fluid nozzles are taken out of service.
The SDA is also capable of high unit
turndown, down to 25 percent of rated
flue gas flow without recirculation
of the flue gases while maintaining
emission requirements.
The design of the unit also provides
for fast load response enabling unit
cycling or load following. An added
advantage is low absorber pressure
drop that keeps the parasitic fan power
loss to a minimum.
The key to efficient performance is the
means used to atomize the lime slurry
into droplets within the gas stream. The
SDA offered by Amec Foster Wheeler uti-
lizes a two-fluid nozzle to atomize the
lime slurry. The fine spray provides in-
creased contact area in order for gas ab-
sorption to occur compared to the CFBS
(it’s easier to mix a gas with a liquid
than with a solid). Acid gases are then
absorbed onto the atomized droplets.
Evaporation of the slurry water in the
droplets occurs simultaneously with
acid gas absorption. The cooled flue
gas carries the dried reaction product
downstream to the fabric filter. This
dried reaction product can be recycled
to optimize lime use. Industry experience with earlier
SDAs was they were expensive to
operate and maintain regardless of
the atomization mechanism used.
Amec Foster Wheeler has redesigned
its two-fluid nozzle to improve the
distribution and mixing of atomizing
air with lime slurry, which improves
mixing efficiency and decreases
operating and maintenance costs.
The optimized nozzle design delivers
even atomizing air distribution to
produce a consistent droplet size
while providing longer nozzle life. In
14 field applications, the optimized
nozzle has demonstrated low cleaning
The 420MW-rated coal-fired unit at Basin
Electric’s Dry Fork Station has operated
the world’s largest CFBS since it entered
service in June 2011. Since it began
operation, the CFBS has exceeded its
design performance reducing SO2 by 95
percent to 98 percent. Photo Courtesy:
Basin Electric Co-Op and Wyoming
Municipal Power Agency
1509PE_20 20 9/9/15 9:10 AM
21
( 8 7 7 - 4 S I - P O W E R )8 7 7 - 4 7 4 - 7 6 9 3
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Circulating fluidized bed scrubber
Boiler flue gas enters the CFBS (with or without
ash) at the bottom of the up-flow vessel, flowing
upward through a venturi section that accelerates the
gas flow rate, causing turbulent flow. The turbulator
wall surface of the vessel causes highly turbulent
mixing of the flue gas, solids, and water for 4 to 6
seconds to achieve a high capture efficiency of the
vapor phase acid gases and metals contained within
the flue gas. The gas and solids mixture then leaves
the top of the scrubber and the fabric filter removes
the solid material.
Recycled solids/hydrated lime and water mix with
the turbulent flowing gas moving vertically through
the vessel, which provides gas cooling, reactivation
of recycled ash, and capture of pollutants. The
CFBS process achieves a very high solids-to-gas
ratio, which dramatically improves the ability of
vapor phase pollutants to find adsorption sites on
the colliding solid particles. The water plays the
important role of cooling the gas to enhance the
adsorption of the vapor phase pollutants onto the
solid particles.
The gas and solids mixture exit at the top of the
scrubber and enter the fabric filter where solids
entrained in the flue gas are captured and recycled back
1509PE_21 21 9/9/15 9:10 AM
Source: FWEC
Flue gas enters vertically upward into the scrubber and through a set of venturis that accelerate the gas flow. Wall turbulators increase flue gas and reagent mixing efficiency. Multiple venturis allow a single scrubber to be scaled up to 600 MW in unit capacity.
Turbulent Mixing 4
AbsorberBottom
Recycled Solids
Multiple Venturi Design
CFBScrubber
Dry Flue Gaswith Solids
Raw FlueGas & Ash
Hydrated Lime
Water
22 www.power-eng.com
EMISSIONS CONTROL
scrubbing performance over a wider
range of fuel sulfur content. SDA sys-
tems are temperature limited because
fresh lime is introduced as slurry (lime
and water). In addition, due to water
being introduced independently and
purely for temperature control, the
CFBS can utilize lower quality water, as
it is not used for pebble lime hydration.
The CFBS has the ability to effective-
ly treat more flue gas volume than an
SDA. The multiple venturis present al-
low a single CFBS vessel to be scaled up
to almost twice that of the SDA vessel
option.
Turndown capability is built into
the SDA design, where a CFBS requires
a flue gas recirculation system in or-
der to achieve equivalent turndown.
An SDA utilizing the two-fluid nozzle
design can maintain required emis-
sion levels down to approximately 25
percent of MCR. In a CFBS at lower
loads additional recirculated flue gas
is required to maintain bed velocities
in order to maintain required emission
levels. If turndown during non-peak
power demands is a consideration the
additional parasitic load is an operat-
ing cost consideration for the CFBS.
The CFBS provides greater sor-
bent utilization compared to a once-
through SDA system as reagent recycle
is incorporated into the design. How-
ever, due to the difference in hydration
efficiency, a SDA equipped with recy-
cle offers greater overall sorbent utili-
zation compared to CFBS. In an SDA
the recycled solids are slurried within a
tank providing essentially 100 percent
hydration. In a CFBS water spray noz-
zles wet the dry recirculated solids as it
passes through the vessel. This hydra-
tion process is less efficient due to the
quantity of recycled solids and the lack
of sufficient wetting time.
All the other performance character-
istics are relatively equivalent including
net auxiliary power. The pressure drop
in the SDA (10 inches H2O) is much
to the scrubber to capture additional
pollutants. A portion of the recycled
solids is removed from the fabric filter in
order to maintain the right quantity of
material in the circulating loop.
The effectiveness of the sorbent is
largely a function of residence time. A
CFBS can keep solids in the system from
20 to 30 minutes. This is a sufficient
period of time for the sorbent to react
with the acid gases. Two independent
control systems maintain the dry flue gas
at optimum temperature and at adequate
removal efficiency by controlling the
amount of water added and the amount
of fresh sorbent added separately.
As a result, unlike the SDA scrubber,
pollutant capture is not limited by inlet
flue gas temperature.
TECHNICAL COMPARISON
Table 1 summarizes the important
technical differences between the SDA
and CFBS options. Table 2 summariz-
es the performance differences. In gen-
eral, the CFBS is slightly better at SO2
control, with up to 98+% capture with
high amounts of sulfur in the fuel.
Plant turndown capability is equiva-
lent, when the CFBS is equipped with
flue gas recirculation.
In general, the CFBS offers slightly
greater SO2 removal flexibility when
compared to SDA. The amount of fresh
lime injection is not limited by flue gas
temperature thus allowing greater SO2
1509PE_22 22 9/9/15 9:10 AM
23 www.power-eng.com
Source: Amec Foster Wheeler
Performance characteristic SDA CFBS
Fuel sulfur content < 2.5% < 3.5%
SO2 removal % 95 – 97 % 95 – 98+ %
Capacity per vessel 40,000 – 1,000,000 acfm75,000 – 1,800,000
acfm
Turndown capability, % of MCR flue gas flow
25% without FGR 50% without FGR
Sorbent Calcium hydroxide slurry 25% with FGR
Sorbent Treatment SlakerDry calcium hydroxide
Sorbent Utilization (Molar Ca/S ratio)
1.4 – 1.5 (without recycle) 1.3 – 1.4
1.15 – 1.25 (with recycle)
Control flexibility Temperature limitedTemperature independent
Water quality Medium Low
Capital cost Slightly lower Slightly higher
Footprint, includes fabric filter
Large in power island, small overall
Moderate in power island, small overall
Key Technical Characteristics of SDA and CFBS 1
Notes: MCR = maximum continuous rating; FGR = flue gas recirculation; acfm = actual cubic feet per minute
Source: Amec Foster Wheeler
Parameter SDA CFBS
SO2 removal efficiency, % 95 98
Expected SO2 removal, % 97 98+
SO3 removal, % 95+ 95+
HCl/HF removal, % 99 99
Total PM Removal efficiency, % 99+ 99+
Mercury removal efficiency, % (with or without PAC) Equal Equal
Pressure drop, inches H2O 10 16
Auxiliary power consumption Higher Lower
Total power consumption (including ID fan) Equal Equal
Availability, % 99 99
Water consumption Equal Equal
Noise Equal Equal
Key Performance Characteristics of SDA and CFBS 2
Notes: ID = induced draft; PAC = powdered activated carbon; PM = particulate matter
approximately equivalent. However,
depending on the unit capacity, pres-
sure drop may have a greater operating
cost impact compared to the additional
auxiliary power of an SDA.
Both technologies are simple, reli-
able, and robust. When maintenance
of the CFBS is required, the accumu-
lated solids can easily be removed
through the bottom of the scrubber.
Also, the water nozzles are low main-
tenance and can be replaced with the
unit in operation. SDA two-fluid noz-
zles may also be removed and main-
tained during plant operation without
loss of unit capacity.
NO ONE SIZE FITS
ALL TECHNOLOGY
In the past, dry scrubbing technol-
ogy was typically chosen over WFGD
technology for its much lower capital
cost and water usage, provided that the
boiler size was not too large and the
fuel sulfur content was not too high.
Today, CFBS technology has broken
through these limitations with single
unit designs up to 600 MW backed by
operating units coal-fired units of over
500 MW and on fuels with sulfur levels
above 4 percent by weight. SDA have
also been deployed on equal-sized
units but are less tolerant to fuel sulfur
content change.
The utility retrofit market has leaned
more toward the CFBS technology of late
due to the higher SO2 removal perfor-
mance. The limited turndown without
flue gas recirculation and use of hydrat-
ed lime is also viewed as a disadvantage.
However, the new generation of SDA
nozzles now available has significant-
ly reduced cleaning frequency, which
was a major criticism by early adopters.
With extended nozzle life and reduced
compressed air consumption, the perfor-
mance gap between the SDA and CFBS
has narrowed. Specific site and environ-
mental permit requirements will be the
determining factor.
less than the equivalent sized CFBS
(16 inches H2O), which is proportional
to ID fan power consumed. However,
the auxiliary power used by the SDA,
principally for compressed (atomizing)
air, exceeds that required by the CFBS.
The net result is that the total auxilia-
ry power used by the either option is
1509PE_23 23 9/9/15 9:10 AM
24 www.power-eng.com
A 6 MWe ORC installation with air-coled
condenser in Germany. Photo courtesy: Siemens
SMALL GAS TURBINES
1509PE_24 24 9/9/15 9:16 AM
25 www.power-eng.com
Improving the Flexibility and Efficiency of Gas Turbine-Based Distributed Power Plants
For the past 100 years
across most of the world,
consumers have re-
ceived their electricity
from large central power
plants, which provide energy to the en-
tire system from a single location via
a network of transmission lines. This
model, which relies heavily on fossil
fuels, is facing an increasing number of
challenges.
The major initial efforts to reduce
the environmental impact of power
generation centered on fuel switching
from coal to natural gas, with plans for
massive centralized coal-fired power
stations giving way to more efficient,
less polluting, natural gas-fired power
plants in the so-called “dash for gas,”
changing the power mix from predom-
inantly thermal coal-fired steam tur-
bine plant to a more even split between
coal and combined cycle gas turbines.
With increasing global efforts to re-
duce greenhouse gas emissions, there
is an increasing penetration of inter-
mittent and variable renewable energy.
BY MICHAEL WELCH AND ANDREW PYM
Both wind and solar generation out-
put vary significantly over the course
of hours to days, sometimes in a pre-
dictable fashion, but often imperfectly
forecast. This intermittency and vari-
ability of wind and solar power gener-
ation presents challenges for grid op-
erators to maintain stable and reliable
grid operation, especially in countries
where renewable power is given dis-
patch priority, requiring redundancy
and flexibility in fossil-fueled power
generation so that the system can re-
spond quickly to these fluctuations,
outages and grid support obligations.
Predominantly to date this has been
achieved by operating central power
plant so that they maintain their con-
nection to the grid but run at part-load
so that they can rapidly respond to
transients on the system network.
Without sufficient system flexibility,
system operators may need to curtail
power generation from wind and
solar sources. The centralized power
generation model has created a trend
over the past century towards ever
1509PE_25 25 9/9/15 9:16 AM
26 www.power-eng.com
Renewables Impact on Available Power Generation
Over a Week In Germany In 2013
1
Pumped Storage
Gas70.000
60.000
50.000
40.000
30.000
20.000
10.000
0
MW
23.06.(Sun.)
22.06.(Sat.)
21.06.(Fri.)
20.06.(Th.)
19.06.(Wed.)
18.06.(Tue.)
17.06.(Mon)
HydroNuclear
Lignite Coal
Hard Coal
Wind
Solar
the ability to operate at low output lev-
els, while still maintaining high effi-
ciencies, low emissions and low power
plant maintenance downtimes. Dis-
tributed Generation is also enabler for
enhanced smart grid capabilities.
FLEXIBILITY OF A
MULTIPLE GAS TURBINE
SOLUTION
Conventional modern large-scale
Combined Cycle Gas Turbine power
plant (CCGT) are usually based on a
single gas turbine with a single steam
turbine (1+1 configuration), or two gas
turbines with a common steam turbine
(2+1 configuration). While this con-
figuration offers very high efficiencies
at full load, in excess of 60 percent to-
day, the efficiency falls as load reduc-
es. There is also a minimum emissions
compliance load, which limits the op-
erating range of the power plant.
With around 1/3 of the total station
power generated by the steam turbine,
it can take over 30 minutes to achieve
full station load. In addition, with
the gas turbine shut down for main-
tenance in a 1+1 configuration, the
complete station is offline, whereas in
a 2+1 configuration, an outage of one
gas turbine will reduce station power
generation to less than 50 percent of
its rated output. A solution based on
multiple gas turbines may offer much
greater flexibility, improved efficiency
across the power range and enhanced
operability compared to a convention-
al CCGT solution.
The Advantages of Modularity
Modularity can help enhance plant
flexibility and reliability. By having
multiple units, load can be shared
across them, and units switched on
and off to match the required load.
This enables the power plant to oper-
ate efficiently over a much wider load
range within the permitted emissions
limits than a conventional CCGT can
achieve. Future plant expansion is easy
increasing unit sizes, based on the
assumption that larger units and
bigger plant provided lower cost
power generation due to economies
of scale, with small increases in power
generation efficiency also contributing
to this. The accepted penalty was losses
in the transmission and distribution
networks, and the potential for
consumers to lose their power supply
in case of transmission or distribution
system outages. However, maximum
efficiency occurs at full-load, so
operating a large central plant at
part-load reduces the efficiency of
power generation considerably, and
the need for part-load operation may
impact on the operational range of
the power station due to the need to
comply with emissions legislation. In
addition, cycling of the units, ramping
up and down in load, can create the
need for more frequent maintenance
and power station outages. A large
utility-scale turbine undergoing major
maintenance can require around two
to three weeks outage for disassembly,
inspection, parts replacement and
reassembly. Cycling also reduces
part life and severely impacts plant
economic returns and in some cases,
overall viability.
Another issue facing centralized
power generation is water usage. In
many parts of the world, water is a scarce
resource for which power generation
competes with agricultural, industrial
and domestic needs. In 2010, World
Bank estimates indicated 15 percent
of the world’s water withdrawals were
used for energy production, and with
electricity demand expected to grow 35
percent by 2035, water usage for power
generation will increase significantly,
especially in systems relying on the
centralized generation model.
Distributed Generation can help ad-
dress all the above issues. By building
smaller, more flexible power plants
closer to the actual load centers, net-
work operators can better compensate
for the intermittency of renewables,
reduce transmission system losses and
improve security of supply and reduce
capital expenditure on capacity expan-
sion/augmentation while the power
plant operators by using multiple units
can optimize the plant design to meet
the needs of the network operators
with fast ramp up and turn down and
SMALL GAS TURBINES
1509PE_26 26 9/9/15 9:16 AM
Typical Modular Outdoor Gas Turbine Generator Set Installation
2
3Typical Start Times for Open
Cycle Gas Turbines
Pow
er O
utpu
t (%
)
100
80
60
40
20
0
TrentSGT-800
Minutes1 2 3 4 5 6 7 8 9 10
27 www.power-eng.com
second and 200 kW/second.
However, gas turbines can also ac-
cept step load applications while still
maintaining power generation with-
in the required frequency and voltage
limits. The maximum acceptable step
load depends on the gas turbine design
– a single shaft gas turbine can accept
a larger single load application than
a twin-shaft variant – but this ability
to step load enables the turbines to
reach full load much faster than by
employing a simple ramp rate for load-
ing. Figure 4 shows the comparison of
time taken for a twin-shaft 12MW gas
turbine to reach full load using the
maximum permissible load steps for
this particular gas turbine model – full
load can be achieved in half the time
by applying load in steps.
Single-shaft gas turbine designs
can accept greater step loads, varying
from 50 percent to 100 percent de-
pending on the model, rating and site
conditions. In the case of a 50MW sin-
gle-shaft gas turbine, it is possible to
load the unit from zero to full load in
two steps within 30 seconds.
Reducing Maintenance Outages
When scheduled maintenance is re-
quired and parts need to be replaced,
to achieve simply by adding one or
more units whenever required, either
at the same location or at a different
tactical point in the power network,
rather than having to build a new large
power plant and associated transmis-
sion system. By distributing capacity in
this way a ‘virtual generation’ benefit
is also achieved via loss offset in the
transmission network. The modular at-
tributes also enable plant to be moved
easily if market conditions change or
the plant is sold. This reduces opera-
tional and financial risk which is ben-
eficial for accessing finance at more
favorable terms. Small gas turbines
tend to come in pre-designed, pre-as-
sembled standardized packages which
have undergone significant levels of
factory testing and require only a sim-
ple concrete foundation. This reduces
the amount of planning, engineering,
site installation and construction work
required compared to a conventional
power plant, enabling the power plant
to be brought online faster, while still
maintaining a competitive first cost,
and reduces the risk of construction
delays and associated contract penal-
ties in addition to lost revenue. In ad-
dition, these packages can be supplied
with weather-proof acoustic enclo-
sures, eliminating the need for build-
ings. All the auxiliary systems required
for turbine operation – including the
control system - can be mounted ei-
ther within the enclosure, adjacent to
the enclosure or on the enclosure roof,
minimizing the number of intercon-
nections required.
Having multiple units also helps
maintain high power plant availabil-
ity and output. As mentioned earlier,
with a single gas turbine installation,
a maintenance outage means that the
entire power station has to be taken of-
fline. A power plant of similar output
but based on, say, 5 smaller gas tur-
bines can still generate 80 percent of
rated station output with one turbine
out of service, 60 percent with two
turbines out etc. Decentralized power
plant using this concept have been used
for many years
in the Oil & Gas
industry for on-
shore fields and
offshore platforms
with no possibili-
ty to connect to a
power grid, with
many Oil & Gas
operators choos-
ing the so-called
‘N+1’ configura-
tion so that there
is a spare unit to
ensure 100 per-
cent power output
is available even
with one gas tur-
bine out of ser-
vice.
Ramp Rate
The ability of a power plant to re-
spond rapidly to variable grid demands
is critical in today’s power environ-
ment with a high percentage of inter-
mittent renewable power generation.
Multiple small gas turbines allow the
full plant load to be achieved relatively
quickly from pushing the start button
as the units can ramp up in parallel.
The ramp rates of small gas tur-
bines typically range between 100 kW/
SMALL GAS TURBINES
1509PE_27 27 9/9/15 9:16 AM
A 7.7 MW Tri-Fuel Gas Turbine Installed in a Cogeneration Plant in the U.S.
5
Expected Ramp Rate and Step Load Acceptance
for a Twin-Shaft 12-MW Gas Turbine
4
Pow
er O
utpu
t (M
W)
14
12
10
8
6
4
2
0
Seconds
Ramp
Step
0 5 10 15 20 25 30 35 40 45 50 55 60
28 www.power-eng.com
reducing the maintenance require-
ments still further.
FUEL FLEXIBILITY
While Utility-scale gas turbines are
designed primarily for operation on
pipeline quality natural gas with a pre-
mium liquid fuel such as diesel as an
alternative or back-up fuel, the major-
ity of smaller gas turbine models are
able to operate on a much wider range
of gaseous and liquid fuels.
Low emissions combustion systems
have also been developed that will
operate on non-standard gas fuels,
including those with variable compo-
sitions. This is a potentially important
feature for decentralized power plant
as it enables the power plant to oper-
ate on a locally available fuel, which,
as some of these are classified as waste
gases, may also be more economical
than utilizing pipeline quality nat-
ural gas. Examples of such potential
gas fuels are landfill gas, digester gas,
high hydrogen content gases such as
refinery gas or syngas, ethane and pro-
pane. It is potentially possible to use
two completely different gas fuels and
switch between these fuels as neces-
sary, determined by fuel availability or
pricing.
Most gas turbines are available in
dual fuel configuration, able to oper-
ate on either gas fuel or liquid fuel. The
the large utility scale gas turbines re-
quire considerable downtime as the
unit has to be disassembled on site,
parts changed and then the unit reas-
sembled. The smaller gas turbines are
generally of Light Industrial or Aerod-
erivative designs which, while many
variants have the capability for on-
site maintenance as well, are primar-
ily designed for off-site maintenance
employing gas generator and turbine
module exchange programs. This re-
duces the turbine outage times for ma-
jor inspections from several weeks per
unit to between one day and five days
depending on the gas turbine model
and the type of maintenance interven-
tion required. Meanwhile in a power
plant based on multiple units, the re-
maining units are still available to gen-
erate power, enabling the power sta-
tion to stay online generating revenue,
with only a relatively small percentage
of total plant output unavailable.
Routine maintenance require-
ments during plant operation are also
low, with no requirement for highly
skilled maintenance personnel to be
permanently based on site and low
consumption of consumables such as
lubricating oil. The various gas
turbine OEMs are all working
on further developments to
improve system reliability and
remote monitoring systems to
enable unmanned operation
for prolonged periods of time.
As has been well-document-
ed elsewhere, the output of a
gas turbine is dependent on
ambient temperature: as ambi-
ent air temperature rises, a gas
turbine’s power output reduc-
es. Conversely this means that
if you design a power plant
to give a specific output at the maxi-
mum ambient temperature foreseen,
on cooler days more power is available
for dispatch. If there are distribution or
transmission system constraints that
limit the amount of power that can be
exported, then on cooler days, while
still producing maximum station out-
put, the gas turbines will operate at
part-load. Most GT OEMs calculate
the time between overhaul (TBO) for
the various different gas turbine mod-
els based on an Equivalent Operat-
ing Hours (EOH) formula – part-load
operation can help extend the TBO
SMALL GAS TURBINES
1509PE_28 28 9/9/15 9:16 AM
6Efficiency vs. Load Comparison
Efficiency versus load comparison for a 50-MW gas turbine (light blue line) and 4 x 12.5-MW gas turbines (dark blue line) in open cycle at 40oC ambient temperature.
4 x 12.5-MW gas turbines
Pow
er O
utpu
t (%
)
40
30
20
10
0
Power Plant Output (MW)
0 10 20 30 40
50-MW gas turbine
Efficiencies 7
Typical gas turbine nominal efficiencies (vertical axis) by power output (horizontal axis)with complex cycle designs indicated by circles.
50
45
40
35
30
25
20
15
10
5
0
Seconds
0 20 40 60 80 100 120
29 www.power-eng.com
environmentally friendly manner for
base load, load following and peak-
ing service. Figure 6 compares the net
plant efficiency of a single 50MW class
aero-derivative gas turbine in open
cycle with four open cycle 12.5 MW
class gas turbines with performance
data calculated for an ambient air tem-
perature of 40° C. While at high loads
the single unit is more efficient, once
the power plant output drops below
50% of rated plant output, the multi-
ple unit solution has a higher efficien-
cy as units can be turned on and off
to maximize efficiency. The multiple
unit solution also offers a wider power
plant operating range from a combus-
tion emissions perspective. Most gas
turbine models guarantee nitrous ox-
ide (NOx) and carbon monoxide (CO)
from 50% of rated load to 100% of
rated load, as required by most global
legislation, although some units offer
these guarantees down to 30% or 40%
load. Therefore a single unit solution at
low loads will start to exceed the per-
mitted emissions. A multiple unit solu-
tion though enables the power plant
to have a greater turn-down capability
Smaller open
cycle (simple cy-
cle) gas turbines
have been used
for peaking ap-
plications for
many years be-
cause they can be
started quickly
and ramped up
and down rap-
idly to meet the
grid demands. In
open cycle, a gas
turbine is rela-
tively inefficient
with efficiencies
varying from
around 28% for a small industrial gas
turbine to just over 40 percent for the
larger aero-derivative gas turbines. In
peaking applications, this is perhaps
not so much of an issue as the price
of electricity is very high during the
periods of gas turbine operation, but
with increasing demand for flexible
power generation across the whole
day, a power plant today needs to be
able to operate efficiently and in an
turbines can operate on 100 percent
gas fuel or 100 percent liquid fuel, with
rapid automatic changeover between
the fuels with no requirement to tem-
porarily reduce load to undertake the
fuel change. The liquid fuels that may
be considered are typically #2 diesel,
kerosene, LPG and naphtha, although
there are gas turbine models available
that can utilize Light, Intermediate
and Heavy Fuel Oils, Residual Oils,
Bio-Oils and even Heavy Crude Oils.
On some gas turbines it is possible to
simultaneously operate on both gas
and liquid fuels – commonly referred
to as bifueling or mixed fuel operation
- using one fuel type to compensate for
shortage of another.
There are examples of tri-fuel gas
turbine installations, with units capa-
ble of operating on a gas fuel and two
different liquid fuels, or a liquid fuel
and two different gas fuels. Figure 5 is a
gas turbine installed in a cogeneration
plant at a university in the U.S. and
configured to operate on either pipe-
line quality natural gas or a processed
landfill gas, with diesel as a back-up
fuel in case of loss of gas supplies, while
still meeting strict emissions limits.
Improving Part-Load Efficiency
and Emissions Performance
SMALL GAS TURBINES
1509PE_29 29 9/9/15 9:16 AM
8Efficiency Variations
Net
Pla
nt E
ffici
ency
(%
)
41
40
39
38
37
36
35
34
33
32
3133 66 100
Comparison of variation of efficiency with load based on a 25-MW power plant using multiple small turbines and ORC or 42 bar, 400oC steam to create a combined cycle plant.
ORCSteam Cycle
30 www.power-eng.com
temperature heat recovery steam gen-
erators (HRSGs) and steam turbine sys-
tems required to achieve this efficien-
cy level adds considerable cost. Lower
cost solutions using low pressure steam
systems can be employed, but this re-
duces the plant efficiency. In addition,
for decentralized plant located close to
load demand, the availability of water
may be an issue, or the operation and
maintenance level required by classical
steam solution cannot be easily accom-
modated, so an
alternative tech-
nology to generate
electricity from
the wasted energy
in the gas turbine
exhaust needs to
be considered.
Organic Ran-
kine Cycle (ORC)
Technology
The Rankine Cy-
cle is a thermody-
namic cycle which
converts heat into
work. For power
generation, by ap-
plying heat exter-
nally to a closed
loop, the working fluid is heated till
it becomes a vapor, expands across
a turbine to drive a generator and is
then cooled and condensed ready to
commence the cycle again. Water is
normally the working fluid used, and
the water (steam)-based Rankine Cycle
provides approximately 85 percent of
worldwide power generation.
A utility scale gas turbine tends to
have a high exhaust gas temperature,
typically between 530°C
(990°F) and 640°C (1180°F), as the
designs are optimized for combined
cycle applications with multi-pressure
level multi-pass boilers producing high
pressure, superheated steam (up to 160
bar and 600°C) for inlet to steam tur-
bines with reheat between different
while still complying with applicable
emissions legislation. In the example
in Figure 6, and assuming 50 percent
turndown limit, the power plant will
still meet emissions requirements
down to 12.5 percent of rated pow-
er plant output. However, for a truly
flexible power plant, the efficiency of
the gas turbines needs to be as high as
possible as well as providing as wide an
operating range for the power plant as
possible. While there are complex cycle
gas turbines on the market with recu-
perators and intercooling to improve
efficiency, the simplest, most effective
and most proven way to improve effi-
ciency is to use a combined cycle con-
figuration with energy recovered from
the exhaust of the gas turbine to gen-
erate additional power. Water (steam)
is the obvious choice as a working flu-
id to generate additional power via a
steam turbine, just as in a conventional
large-scale CCGT. However, smaller
gas turbines are not optimised for com-
bined cycle applications, having rela-
tively low exhaust mass flows and ex-
haust gas temperatures, and although
combined cycle efficiencies in excess
of 55 percent can be achieved, the
complexity of the high pressure, high
pressure levels within the steam tur-
bine. This is how a modern CCGT
achieves the high full load efficiencies
quoted, and produces electricity at
competitive prices through economies
of scale.
Smaller gas turbines have lower
exhaust gas temperatures, typically
between 460°C (870°F) and 550°C
(1025°F) as they are optimized for
maximum open cycle efficiency. This
reduces both the volume and tem-
perature of high pressure superheated
steam that can be produced, reducing
cycle efficiency. It is also not cost-effec-
tive to use the same Waste Heat Recov-
ery Unit and Steam
Turbine technology as developed to
go with a 300 MW gas turbine on a 10
MW gas turbine.
Therefore if a power plant is to be
based on multiple small units, effi-
ciency must be sacrificed to ensure
cost-effectiveness, so lower pressure
non-reheat steam systems are used, of-
ten with much simpler Once Through
Steam Generators (OTSGs) that re-
spond much more rapidly to changes
in steam demand. However, at low
pressures, there is a large enthalpy drop
experienced when water is the working
fluid, and a degree of superheat is re-
quired to avoid the risk of condensa-
tion, and associated erosion, inside the
steam turbine.
By changing the working fluid, a low
enthalpy drop can be achieved, the
need for superheating eliminated, as
condensation within the turbine can
be avoided, and the same efficiency
achieved at a lower working pressure.
Improved efficiencies at part-load are
also attainable using ORC turbogene-
rators compared to conventional steam
turbines.
Organic Rankine Cycles for small
gas turbines tend to use a high molecu-
lar weight hydrocarbon (organic) fluid
such as cyclopentane, or silicone oil, as
the working fluid for the turbine. This
SMALL GAS TURBINES
1509PE_30 30 9/9/15 9:16 AM
10Efficiency vs. Load Comparison
Efficiency versus load comparison for a 50-MW class gas turbine and 4 x 12.5 MW class gas turbines in open
cycle, with 4 x 12.5 MW class gas turbines with ORC at 40oC ambient temperature.
4 x 12.5-MW gas turbines with ORC
Effic
ienc
y (%
)
50
40
30
20
10
0
MW
0 10 20 30 40 50
31 www.power-eng.com
turbines are not
optimised for
combined cycle
applications, gen-
erally having low-
er exhaust tem-
peratures than
the utility scale
gas turbines, and
so they have re-
duced high pres-
sure steam raising
capabilities. How-
ever, the lower
exhaust tempera-
tures at both full
and part-load en-
able ORC technol-
ogy to be readily
employed to im-
prove overall plant efficiency while still
enabling multiple units to be installed
to maintain the overall power station
flexibility and operability. This config-
uration also has the additional advan-
tage of being able to be ‘water free’ as
air cooling can be used throughout the
installation.
Returning to our power plant capa-
ble of producing 40 MW at 40°C re-
ferred to in Figure 6, the addition of an
ORC turbogenerator to the smaller gas
allows high efficiency, larger diameter
turbines to be utilized, operating at
lower speeds, typically 3000rpm, with
low mechanical stress – unlike small
steam turbines which operate at speeds
up to around 10000rpm. The combina-
tion of working fluid and turbine speed
leads to much reduced maintenance re-
quirements, as well as eliminating the
need for water in the process.
ORC systems can use either directly
or indirectly heat the working fluid. In
both cases the Waste Heat Recovery
Unit (WHRU) installed in the gas tur-
bine exhaust system is a simple once
through design, but in the indirectly
heated system, heat is transferred from
the gas turbine exhaust to the ORC
working fluid via a secondary closed
loop using a thermal oil. Directly heat-
ed systems offer better efficiency of the
ORC cycle (see Figure 10 below) and
reduce the initial capital cost, while an
indirectly heated system allows for en-
ergy to be recovered from higher tem-
perature heat sources than a directly
heated system.
Combining Gas Turbines + ORC
to Maximize Performance
As mentioned earlier, smaller gas
turbines has quite a considerable im-
pact, as can be seen in Figure 12.
Firstly, it can be seen that the ORC
system adds about 25% additional
power output for the multiple small
units for no additional fuel input. Sec-
ondly, this additional power improves
the plant efficiency so that at full load
the overall net plant efficiency is in
excess of 40%, even on a hot day. This
efficiency improvement makes a nomi-
nal 50MW plant based on multiple gas
turbines more efficient and more flexi-
ble than a plant based on a single open
cycle gas turbine across the whole load
range, and with the ability to achieve
load turn-down to around 10 percent
of rated station power output while
still maintaining an acceptable com-
bustion emissions profile.
Multiple gas turbines can be con-
nected to a single ORC turbogenerator,
providing the maximum output rating
of the ORC turbogenerator is not ex-
ceeded. This helps reduce the cost/kW
of a power plant based on multiple gas
turbines as the cost of the ORC system
is spread across multiple units. In addi-
tion, thanks to ORC working fluid pe-
culiarities, the plant flexibility and ef-
ficiency at part load is not reduced. The
ORC unit can be operated at between
SMALL GAS TURBINES
9Comparison of ORC System
Efficiency for a Direct Heated and
Indirect Heated System
Effic
ienc
y (%
)
25
20
15
10
5
010 30 50
Direct – 2 GTsOil – 2 GTs
Ambient Temperature (oC)
1509PE_31 31 9/9/15 9:16 AM
12Efficiency vs. Load Comparison
Efficiency versus load comparison for a 50-MW class gas turbine in open cycle (blue line) with 4 x 12.5MW class gas turbines with ORC (red line) and a 50MW class gas turbine with ORC (green line) at 40oC ambient temperature
4 x 12.5-MW gas turbines with ORC
Effic
ienc
y (%
)
50
40
30
20
10
0
MW
0 10 20 30 40 50
32 www.power-eng.com
ORC is better. This suggests that for
larger power plant of, say, 200 MW or
250 MW design output, a combination
of 50 MW class and smaller 12.5 MW
class gas turbines would give the opti-
mum plant efficiency across the widest
load range. The gas turbine plus ORC
combination helps maintain a high
output power and high net plant effi-
ciency across a wide temperature range.
10 percent and 110 percent of its nomi-
nal load automatically, while still main-
taining high efficiency even at partial
load - as shown in the Figure 13, at 50
percent of the load, the ORC still has an
efficiency of 90 percent of nominal full
load efficiency).
Obviously it is also possible to add an
ORC system onto the larger gas turbine
considered to improve efficiency but it
is most likely in these cases that a con-
figuration based on each gas turbine
having its own ORC turbogenerator sys-
tem will be needed.
As for the multiple small units, the
addition of the ORC system boosts both
power and efficiency considerably. At
nearly 47 percent net power output on
a 40°C ambient day with all site losses
accounted for, a 50MW class gas tur-
bine with ORC offers a better efficiency
than large (100MW) complex cycle gas
turbines (which are quoted as having
an ISO, zero loss efficiency of 44%). It
is interesting to note that while the ef-
ficiency of the single larger gas turbine
plus ORC is higher for station loads
over 60 percent, at lower loads the effi-
ciency of the multiple small units plus
In the example given in Figure 14, the
ORC system is air-cooled, with the Air
Cooled Condenser (ACC) designed for
an average 30º C ambient temperature.
The shape of the power output and ef-
ficiency curve can be altered by the
design temperature used for the ACC:
designing the ACC for the maximum
ambient temperature will impact plant
performance at lower temperatures, so
it is important to consider and define
the correct design point.
Conclusions
Combining multiple small gas tur-
bines with ORC technology permits
engineers to design a very load flexi-
ble power plant with optimal efficien-
cy and emissions compliance across a
wide load range. With no requirement
for a water supply, such modular pow-
er plant potentially offer a simple way
to meet the demands on the electrici-
ty grid caused by the large amounts of
intermittent renewable power genera-
tion with high power plant reliability,
availability and low maintenance in
a cost-effective manner. By building
such flexible distributed plant close to
the actual load centers, investment in
the power system infrastructure can
also be reduced.
SMALL GAS TURBINES
Efficiency vs. Load 11
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Steam
ORC
Direct comparison in efficiency versus load for similarly-sized steam turbine generator and ORCturbogenerator.
Act
ua
l Effi
cien
cy/N
om
ina
l Effi
cien
cy
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
Actual load/Nominal Load
1509PE_32 32 9/9/15 9:16 AM
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34 www.power-eng.com
ENVIRONMENTAL ISSUES
316(b): One Year LaterBY TIM WOODROW
application of a plant’s National Pollut-
ant Discharge Elimination System
(NPDES) permit. The 316(b) ruling pro-
vides a date (July 14, 2018) that dictates
the timeline of compliance which all
qualifying plants need to follow with re-
gard to the renewal of their NPDES. Per-
mit renewal is required every five years.
Whether a permit is due for renewal be-
fore or after this date (or if it is working on
an administratively extended permit) will
determine the actions a plant must take
over the upcoming period.
Plants will have to sub-
mit a host of reports to state
agencies, including section
122.21 (r2-8) among others. For permit
applications after July 14, 2018, plants
that withdraw more than 125 MGD must
submit application with the appropriate
reports (section 122.21 (r9-12)).These re-
ports will enable the permit director to
understand both the social and economic
costs and benefits that a selected solution
may have. If renewal is due before July
14, 2018, a plant will negotiate a separate
timeline for compliance.
SCREEN OPTIONS
In all likelihood, installing and opti-
mizing traveling fish protection screens
will be the lowest cost option for the ma-
jority of power plants. However, there
is concern that operating traveling water
screens whenever drawing water will dra-
matically increase operational and me-
chanical costs. This is where the industry
may be missing an opportunity. While
plants are preparing to submit their per-
mit applications with the required data,
they must ensure that they have studied
the various BTA options from a mechani-
cal performance perspective.
Currently, power plants operate their
We are rapidly ap-
proaching the
one year anni-
versary of the
publication of
the U.S. Environmental Protection Agen-
cy’s (EPA) new regulations under Section
316(b) of the Clean Water Act for Ex-
isting Facilities and New Units at Ex-
isting Facilities. According to the EPA,
the final rule affects 544 existing power
generating facilities that withdraw more
than 2 million gallons of water per day
(MGD) from U.S. waters and use at least
25 percent of the water they withdraw
for cooling purposes. The rule requires
that the location, design, construction,
and capacity of cooling water intake
structures reflect the Best Technology
Available (BTA) for minimizing negative
environmental impacts.
Compliance with the rule requires all
permit applicants to select an impinge-
ment compliance approach from seven
options. Applicants with actual intake
flows exceeding 125 MGD must first
complete and file several study reports
(§122.21(r9-12)) that will provide permit
directors with the engineering, biological,
and economic information necessary for
an entrainment BTA determination.
Following this determination, these
applicants will then select their cho-
sen impingement compliance approach
from the BTA compliance options. The
required studies, as well as the timely
selection of a compliance option, will
be a challenge for the industry, requiring
the latest information on fish protection
technologies (cost and performance); bi-
ological sampling methods and interpre-
tation of results; and practical approaches
and supporting information for assessing
economic social costs and benefits.
WHERE ARE WE NOW?
One of the fundamental requirements
of the final rule is the parameters under
which a plant must select a BTA to reduce
the impact of impingement and entrain-
ment. The timing of compliance also rep-
resents another major change from the
draft rule.
Compliance is tied to the renewal
Hydrolox traveling water screens like the one in operation at
Xcel Energy’s Wilmarth Station, Mankato, Minnesota, have very
low associated O&M costs. Photo courtesy: Hydrolox.
Author
Tim Woodrow is the U.S. Commercial
Manager for Hydrolox, a manufacturer of
traveling water screens.
1509PE_34 34 9/9/15 9:16 AM
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ENVIRONMENTAL ISSUES
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solution. Another streamlined option
requires facilities to achieve an actual
through screen velocity of 0.5 ft/s by in-
creasing the screening area or via unit re-
tirements. Additionally, the two stream-
lined options above can be combined
to create an additional option for the
streamlined approach.
The final BTA option requires facilities
to maintain less than 24 percent mortal-
ity in aquatic life as a result of impinge-
ment. This option would require a plant
to install modified traveling screens, as
well as monitor and report their impinge-
ment mortality every month for the life
of the plant—an option so tedious and
expensive that most will not consider it.
316(B) IMPACT ON POWER PLANTS
Power plants have been approaching
316(b) in different ways. First and fore-
most, plants are assessing where they
screens two to three times a day, about
20 minutes at a time, for a total of about
an hour a day. Even with this reduced
usage, they are still spending anywhere
from $20,000 to $50,000 a year to keep
the screens operating. Under the new
rule, any time a plant turns on its water
circulation pumps, it must also rotate its
screens. In order to comply with the rule,
then, these plants must now operate their
screens up to 24 hours a day, seven days a
week; this has many plant operators wor-
ried about costs.
The total cost of a screen is not entire-
ly accounted for by its up-front capital
expenditure. Operational and main-
tenance costs must also be added into
this equation. Traditional screens are
driven by large side chains which repre-
sent a large maintenance burden. A new
screen technology has made it possible to
eliminate this chain, making the screen
nearly maintenance-free, which can
dramatically lower maintenance costs,
even when screens must run 24/7.
There are pros and cons related to each
BTA, pre-approved and streamlined, and
their associated costs and benefits.
Pre-approved BTA options include the
use of an existing closed-cycle cooling
system, or the installation of a new one.
This can be very expensive to retrofit with
costs ranging from $50 million to $300
million. Another pre-approved option
involves the design of a cooling wa-
ter intake structure that has an actual
through screen velocity lower than 0.5
feet per second (ft/s), which would in-
volve increasing the surface area of the
screening system by a factor of two- to
five-fold, an undertaking with signifi-
cant associated costs.
The streamlined approach has a few
options. The first option involves the
installation of modified traveling water
screens, perhaps the lowest capital-cost
1509PE_36 36 9/9/15 9:16 AM
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are on the NPDES timeline to determine the urgency of
compliance and whether their facilities fall in the impinge-
ment or entrainment category. Plants with permit renewal
deadlines that fall before July 14, 2018 will negotiate a sep-
arate compliance timeline, but those with permits due for
renewal after July 14, 2018 will need to submit their data/
reports and select one of the approved BTA technologies, as
well as their entrainment solutions, if applicable.
After reviewing data from studies and analysis, some plants
have already proactively installed fish screens and tested them
for both aquatic protection and operating costs so that they
have a clear understanding of the costs and work associated
with living with traveling fish screens in a post-316(b) envi-
ronment.
316(B) IMPACT ON STATE REGULATORY AGENCIES
Just as power companies and individual plants are assessing
their positions and the workloads ahead of them, so too are
state agencies. State agencies have been tasked with enforc-
ing numerous new EPA regulations, including MATS and the
Clean Power Plan under the Clean Power Act. Section 316(b)
is just another regulation to be considered in this mix.
Response from state regulators has been mixed. Some reg-
ulators are only just getting up to speed on the regulation,
while some are even proactively writing 316(b) regulation
into their current NPDES permits. Others are asking the EPA
for an extension beyond July 14, 2018. For the majority of
states, the expectation is that the state permit writer will fol-
low the guidelines as laid out in the rule. The relationship that
a plant has with their local state permit writer will be crucial
in determining the smoothness of the compliance process.
WHERE DO WE GO FROM HERE?
Plants are currently engaging in contracts with inde-
pendent consultants to prepare the paperwork and con-
duct the studies necessary to submit their applications at
the appropriate times.
As mentioned, the compliance schedule for facilities is
driven by where their NPDES permit renewal date falls
in relation to the July 14, 2018 deadline. All facilities are
required to comply with one of the seven standards of im-
pingent mortality.
Proactive plants will install test equipment ahead of
their submission timeline to determine the most cost ef-
fective and reliable compliance option. With the modern
technology available, plants will actually have the oppor-
tunity to reduce their operation and maintenance costs
while meeting 316(b) compliance guidelines, depending
on the BTA they choose.
For info. http://powereng.hotims.com RS#12
1509PE_37 37 9/9/15 9:16 AM
TURBINE OILS: A Key Factor in System Reliability
38 www.power-eng.com
Temperature fluctuation in the turbine oil
can result in oxidation and thermal deg-
radation initially caused by elevated tem-
peratures of the oil, followed by the depo-
sition of varnish on critical valves as the
oil cools to lower temperatures. Resulting
stuck valves can in turn cause unplanned
downtime, added maintenance costs, and
lower productivity.
The survey also indicated that end us-
ers are interested in extended oil drainage
service intervals to reduce maintenance.
In addition, the oil must provide adequate
In a recent Shell global survey,
turbine oil end users indicated
that their biggest concern was
unplanned downtime during
turbine operation. The cost of
downtime can be significant if a power
company is unable to provide power. To-
day’s turbine systems are operating under
increasingly severe conditions including
wider temperature variances due to stop/
start cyclic operation, which has resulted
in some instances in varnish formation
on critical turbine component surfaces.
Pearl GTL Plant located in Qatar manufactures
GTL base oils. Source: Shell
BY ROB PROFILET, PH.D.
rust and corrosion inhibition, separate
water quickly, be compatible with seals,
not foam, and be readily filterable. These
challenging operating requirements and
the desire to extend the lifetime of the
turbine oil require robust turbine oil tech-
nology in combination with a good oil
maintenance program.
Turbine oil formulations must possess
very specific properties if the oil is to
provide adequate protection for the tur-
bine. To prevent metal-to-metal contact,
oils need to have the correct viscosity for
1509PE_38 38 9/9/15 9:16 AM
39 www.power-eng.com
Author
Rob Profilet has 22 years of experience
in the field of industrial lubricants. He
serves as Shell’s Product Application
Specialist for industrial products for the
Americas.
a given application in order to provide
a good oil film for bearings. Oils must
release air rapidly to help prevent cavi-
tation, but must also not cause excessive
foaming. Rust and corrosion inhibition is
a necessity to ensure all key components
of a system are protected. In steam tur-
bines, or in other systems where water
contamination can be a concern, the tur-
bine oil must separate water very rapidly.
If water cannot separate from the oil, an
oil-in-water emulsion can form which
will interfere with the oil film needed to
support loads carried by the bearings.
The oil must also act to some degree as a
coolant. The internal surfaces inside a tur-
bine become very hot, and the oil must
absorb this heat without thermally de-
grading or oxidizing prematurely.
FORMULATION
OF TURBINE OILS
So how is turbine oil formulated? Un-
like motor oils, which may contain 20 to
30 percent additives, typical turbine oil
formulations contain approximately 99
percent base fluid and only one percent
additive. Both the base oil and additive
play very critical roles in the performance
of the lubricant. The additive itself is a
delicate balance of antioxidants, rust and
corrosion inhibitors, demulsifiers, de-
foamants, and pour point depressant. In
the case of turbine systems with gears, an
anti-wear additive is often present as well.
The right combination of additives and
base oil is critical to minimize the impact
of oxidation and thermal degradation
which can lead to the formation of sludge
and varnish.
The most common lubricants used in
gas, steam, and combined-cycle turbines
today are based on formulations utilizing
mineral oils in combination with an ad-
ditive system. The mineral base oils uti-
lized are API Group I, II, or III. The base
oil can have a significant impact on the
performance of the turbine oil. When
combined with appropriate additive tech-
nology, Group II and III base oils exhibit
extended oxidation life compared to tur-
bine oils formulated with Group I base
oils. Turbine oils formulated with Group
III base oils have an advantage over those
formulated with Group II base oils be-
cause they have a naturally higher viscosi-
ty index. This higher viscosity index helps
maintain the thickness of the oil film at
the bearing during times of elevated tem-
peratures. Group III oils also help provide
enhanced surface properties in the fin-
ished lubricant.
GAS TO LIQUID BASE OILS
Base oil technology has evolved re-
cently to help improve turbine oil perfor-
mance. Shell recently introduced Gas to
Liquid (GTL) base oil which is considered
an API Group III base oil. The use of Shell
GTL technology represents an exciting
step change in technology for turbine oils.
Shell GTL technology involves the con-
version of natural gas into high-quality
products including transport fuels, wax-
es, chemicals, and lubricants. Research
into GTL for Shell began in Amsterdam
in 1973, and now after many patents, is
produced in Qatar. Shell GTL base oil
has been shown to enhance motor oil for-
mulations with better volatility control,
better low temperature performance, and
enhanced oxidation stability.
The benefits of GTL technology are a
natural fit for turbine oil formulations.
Enhanced oxidation protection helps the
turbine oil last longer and resist the for-
mation of oxidation byproducts which
ultimately lead to the formation of var-
nish. Rapid air release properties of GTL
base oils also enable the turbine oil to
operate more efficiently by minimizing
the chance for the oil film to be broken,
which is critical in the lubrication of the
bearings. GTL base oils also have a higher
viscosity index, which helps maintain the
optimum viscosity and film thickness re-
quired for the bearings in a turbine across
a wider range of temperatures. Maintain-
ing film thickness and reducing the for-
mation of varnish can help reduce bear-
ing temperatures.
OIL ADDITIVES
Although small in quantity, the addi-
tive used in turbine oils has a big job to
do. Turbine oil additive systems are de-
signed to minimize foam, provide rust
1509PE_39 39 9/9/15 9:16 AM
40 www.power-eng.com
A severe method to measure thermal
stability is the MAN Thermal Stability
Test. The test is conducted by heating
the test oil in a static oven at 180°C
for a period of two days. The amount
of sludge formed is then measured,
which helps to assess the thermal sta-
bility and short-term deposit resistance
when the oil is exposed to very high
temperatures.
IN THE FIELD
After laboratory testing is complet-
ed, turbine oil suppliers will often
conduct field demonstrations of their
product. Field demonstrations allow
for careful monitoring of the fluid in
real-world applications. The fluid is
introduced and monitoring is conduct-
ed on a scheduled basis that is agreed
upon with the end user.
All turbine oils should be subjected
to a proactive oil analysis monitoring
system. There are many published tur-
bine oil condition monitoring guide-
lines available from industry bodies
such as ASTM and ISO. Original equip-
ment manufacturers (OEM) also publish
guidelines to help the end user monitor
the turbine oil and get the most efficient
performance. Lubricant suppliers will
also provide guidance to help suggest a
schedule for testing.
Test schedules will often include vis-
cosity, total acid number (TAN), water
and corrosion protection, and help sep-
arate water very quickly so it can be re-
moved. Because turbine oils are expected
to last a long time (7+ years for gas tur-
bines and up to 20+ years for steam tur-
bines) the additive must contain a robust
antioxidant system.
THE PERILS OF VARNISH
Due to the high operating tempera-
tures found in turbine systems, im-
properly formulated oils can thermally
degrade, oxidize, and form varnish.
Varnish is found on critical turbine
surfaces and starts as a soft film, grad-
ually hardening into a lacquer which
is not easily removed. The lacquer can
act as an insulating film that interferes
with heat transfer. It can also trap par-
ticulates such as wear metals. In ad-
dition, the varnish can cause valves to
stick, causing the turbine not to start.
The varnish layer which forms on bear-
ings takes up critical clearance space
for the oil film, which can result in
higher temperatures and the formation
of more varnish.
Varnish precursors form when polar
long chain acids, aldehydes, and ke-
tones form in the oil from oxidation
and thermal degradation of the lubri-
cant. These precursors eventually com-
bine or react with each other and form
longer chain polymeric species. The oil
will hold this material in solution until
a saturation point is reached and the
resulting “sludge” drops out on cooler
parts of the system (often during shut-
down). Overtime, the sludge turns
into varnish and eventually a lacquer
as temperatures increase.
IN THE LAB
Once a fluid has been developed,
several tests are conducted in the lab-
oratory to assess the performance of a
product. Common physical property
tests such as viscosity, flash point, pour
point, and density are measured along
with performance tests. Performance
tests include water separation proper-
ties, resistance to rust and corrosion,
air release, filtration performance,
foaming tendencies, and thermal and
oxidation stability tests.
A common method used to measure
resistance to oxidation is the ASTM
D943 Turbine Oxidation Stability Test.
This test is commonly listed on suppli-
er Technical Data Sheets. In this test,
a mixture of oil and water is heated
to 95°C in the presence of a catalyst
and bubbling oxygen to expedite the
oxidation process. The oil is moni-
tored by total acid number, and the
test is stopped when oils reach 2.0 mg
KOH/g. The more hours in this test the
better; long life turbine oils will have a
value of >10,000 reported hours.
There are other oxidation tests which
can also assess turbine oil performance.
These include ASTM D4310 (1000 hour
TOST) which measures sludge forma-
tion, ASTM D2272 Rotating Pressure
Vessel Oxidation Test (RPVOT), and
the Dry TOST Test (ASTM D7873).
The Dry TOST Test (ASTM D7873)
promotes the oxidation of the turbine
oil in the presence of heat (120°C),
metals (steel and copper coils), but no
water. The test is conducted for a pe-
riod of 1008 hours, and is designed to
measure the sludging tendency of the
fluid by measuring the RPVOT reten-
tion and insoluble oxidation products.
The test is a useful method to predict
turbine oil performance in the field.
Thermal stability in turbine oils can vary
based on results of the MAN LTAT thermal
stability test. Source: Shell Global Solutions
1509PE_40 40 9/9/15 9:16 AM
41 www.power-eng.com
used to help remove varnish precursors
from turbine oils or other lubricating
oils. Popular methods include the use
of electrostatic filters, balanced charge
agglomeration systems, electro-phys-
ical separation processes (ESP), depth
filtration, and filters which minimize
electrostatic discharge.
The best route to minimize varnish
formation involves a two-pronged
strategy. First, a high-quality turbine
oil should be selected. The oil should
not only have excellent oxidation re-
sistance, but should also be resistant to
deposit formation. Second, a proactive
oil monitoring program can go a long
way in minimizing problems resulting
from oil degradation, extending the life
content, elemental analysis by ICP, oil
cleanliness (particle count), RPVOT, de-
mulsibility, foam performance, RULER
Test, and either MPC (membrane patch
colorimetry) or QSA (quantitative spec-
trophotometric analysis) to assess var-
nish potential in the fluid.
Varnish potential screening meth-
ods have been successful in identifying
a system with a high potential to var-
nish by isolating insoluble oxidation
products and measuring their concen-
tration in the system. By assigning a
rating system, an end user can take dif-
ferent courses of action to help protect
their system.
If a high rating is observed, there are
many systems available which can be
of the oil, and providing a higher level
of protection for the system. Down-
time and unplanned maintenance can
be reduced or eliminated.
CONCLUSION
Shell recently introduced a new line
of turbine oils which provide a very
high level of performance for steam,
gas, and combined-cycle turbines. The
technology is based on the use of Shell
GTL Group III base oils in combination
with a specially developed additive sys-
tem. Testing in the laboratory and in
the field has shown that these products
have a very high resistance to oxidation
and thermal breakdown, minimizing
the formation of sludges and varnish on
critical turbine surfaces. These products
have very rapid air release and are low
foaming, helping to improve the overall
efficiency of the turbine operation. The
use of Shell Turbo S4 X or Shell Turbo S4
GX (for turbines requiring protection of
gears) in combination with a suitable
oil-monitoring program can help to ex-
tend the life of critical turbine compo-
nents and help extend the life of the tur-
bine oil. This can result in lower costs,
less unplanned downtime, and higher
efficiency.
Predicting the Onset of Varnish 2
MPC
Normal<15
Monitor15-29
Abnormal30-40
Critical >40
Turbine oils can be tested using the MPC test to help predict the onset of varnish. Increasing varnish potential results in a darker filter patch.
Source: Shell Global Solutions
Test Steam Turbine Gas Turbine Suggested Limits
Viscosity Quarterly/Bi-annual Quarterly +/- 5% of fresh oil value
Total Acid Number (mg KOH/g) Quarterly/Bi-annual QuarterlyCaution: 0.1-0.2 over new oil value; Warning 0.3-0.4 over new oil value
Water Content (KF, ppm) Quarterly Quarterly<0.1% for steam; <0.05% for gas
Elemental Analysis (ICP) Quarterly Quarterly Check contamination
Oil Cleanliness (ISO 4406) Quarterly/Bi-annual Quarterly Follow OEM Limits
RPVOT (min) Annual Quarterly <25% of fresh oil
Demulsibility (ASTM D1401) Annual --->40-37-3(40 minutes)
MPC or QSA (varnish formation) --- Quarterly <40 MPC; <60 QSA
Foaming (mL-mL) Annual Annual 450/10 max
Turbine oils should be tested on a regular basis to help extend the life of the fluid and the system.
Typical Testing Schedule for Turbine Oils 1
Source: Shell Global Solutions
1509PE_41 41 9/9/15 9:16 AM
42 www.power-eng.com
Maintaining Maximum Efficiency in Power Generation UnitsBY BRAD BUECKER, CONTRIBUTING EDITOR
QB = heat input to the steam generator
QC = heat extracted in the condenser
WP = work done by the feedwater pump
(usually negligible in this particular cal-
culation)
The diagram also indicates a key com-
ponent of the second law; for any pro-
cess that produces work, not all of the
heat input can be utilized for work, some
heat must be extracted as waste energy.
We will later examine how this thermo-
dynamic aspect makes condensers, and
proper operation of them, so important
for power generation.
In the meantime, let’s consider anoth-
er important issue from Figure 1. If the
steam from this simple system were to
be immediately injected into a turbine,
very little work would occur, as the steam
would immediately begin condensing to
water upon passage through the blades.
For this reason among others, all utility
steam generators include superheaters to
raise the steam temperature well above
saturation and allow much more work
from the turbine. Even so, the net effi-
ciency of Rankine-cycle only plants rang-
es from 1/3 in the least efficient plants Virtually everyone in the
power, chemical pro-
cess, and other indus-
tries is no doubt aware
of the greatly expanded
efforts to lower carbon dioxide emis-
sions from industrial sources. This con-
cern continues to lead increased efforts
into maximizing plant efficiency both
through good operating principles and
through design improvements. This arti-
cle examines several of these issues with
regard to steam-generating facilities.
AN OVERVIEW OF THE
RANKINE CYCLE
Power production via steam generation
to drive a turbine is based on the Ran-
kine cycle, whose fundamental outline is
shown below.
Even this simple diagram (Figure 1)
clearly illustrates several fundamental
aspects from the first and second laws of
thermodynamics. First, and for the time
being ignoring entropy increases due to
heat losses, friction, and other mecha-
nisms, the theoretical work available from
the turbine (WT) can be approximated by
the following straightforward equation.
WT = m(h
2 – h
1) Eq. 1, where
m = mass flow rate of steam through
the turbine
h1 = enthalpy of turbine exhaust steam
h2 = enthalpy of turbine inlet steam
POWER PLANT OPTIMIZATION Author
Brad Buecker is a process specialist with
Kiewit Engineering and Design Company
in Lenexa, Kansas.
A Basic Rankine Cycle
WP
WP
QB
QC
Boiler
CondenserCondensate
High-PressureSteam
Turbine
TurbineexhaustFeedwater
FWPump
1
1509PE_42 42 9/9/15 9:17 AM
43 www.power-eng.com
to keep condensers and heat exchangers
clean from chemical and biological de-
posits, and also operating properly from
a mechanical perspective to avoid costly
impacts. We will examine heat transfer
issues below, starting with a non-con-
densing steam turbine.
Equation 1 approximates the heat
transfer in an ideal steam turbine, while
in actuality turbines are typically 80 to
90 percent efficient. To simplify the dis-
cussion, we will consider an isentropic
(no energy losses) turbine, as this exam-
ple is still quite sufficient to outline the
principles intended. Conditions for the
non-condensing steam turbine example
are:
Main Steam (Turbine Inlet) Pressure –
2000 psia
Main Steam Temperature – 1000oF
Turbine Outlet Steam Pressure – Atmo-
spheric (14.7 psia)
The steam tables show that the enthal-
py of the turbine inlet steam is 1474.1 Btu
per pound of fluid (Btu/
lbm). Thermodynamic
calculations indicate that
the exiting enthalpy from
the turbine is 1018.4 Btu/
lbm (steam quality is
86%). Per Equation 1
the maximum unit work
available from this ideal
turbine is (1474.1 Btu/
lbm – 1018.4 Btu/lbm)
= 455.7 Btu/lbm. To put
this into practical per-
spective, assume steam
flow to be 1,000,000 lb/hr. The overall
work is then 455,700,000 Btu/hr = 133.5
megawatts (MW).
At this point, if the exhaust steam were
transported for co-generation or CHP
purposes, excellent efficiency would be
possible. However, in the power industry
steam condensation is a very important
step. Therefore, consider a second exam-
ple, where the unit has a condenser that
reduces the turbine exhaust pressure to
to perhaps a bit above 2/5 for the most
efficient plants. The primary reason re-
garding this seemingly low efficiency is
that the usable energy is contained in the
superheat of the steam, perhaps 500 to
600 Btu/lbm is not as large as the steam
latent heat, approximately 1000 Btu/lbm.
We will examine several examples short-
ly, when examining condenser and heat
exchanger cleanliness.
This then is one aspect, among sever-
al, that is driving industry towards higher
efficiency machines. The two processes
that stand out are combined-cycle power
generation and combined heat and power
(CHP) or co-generation. We will consider
CHP/co-generation first.
The previous example from the Ran-
kine cycle showed that much heat is lost
during the condensation process in the
condenser. This lost energy represents the
latent heat of the exhaust steam. Howev-
er, if in place of the condenser which sim-
ply exhausts the heat to a cooling tower
or other heat sink, the steam is transport-
ed to heat exchangers to drive chemical
processes or even simply to warm water
for district heating systems, much of the
latent heat is productively utilized. Con-
sider 100,000 lbm/hr of saturated steam
flowing to a heat exchanger with water
as the process fluid, say for building heat.
Energy transfer from condensation alone
could warm approximately 3,000,000
lbm/hr of the water from 70oF to 100oF.
On the flip side, heat is a requirement for
such devices as absorption-refrigeration
chillers, which are common devices for
cooling large office buildings. Again, la-
tent heat is a potential source of energy for
these systems.
Net efficiencies of up to 80 percent
have been reported for co-generation pro-
cesses. The power industry continues to
see steady installation of combined-cycle
power plants, which also offer increased
efficiency. These plants, of course, use
combustion turbines for partial power
production with heat recovery steam gen-
erators (HRSG) for additional power gen-
eration from a steam turbine or turbines.
This is truly a combined cycle process, as
the HRSGs operate on the Rankine cycle
while the combustion turbines operate
on the Brayton cycle. Maximum efficien-
cies in some units have now topped 60
percent, which is immensely better than
efficiencies for some of the old coal plants
that are still operating. From a combus-
tion turbine aspect, the key limiting factor
to efficiency is the para-
sitic power requirement
for the inlet air compres-
sor. But much energy is,
of course, regained by
converting the combus-
tion turbine exhaust heat
into steam for Rankine
cycle power generation.
But, even with these de-
sign efficiency improve-
ments, it is still very im-
portant to maintain top
efficiency from an oper-
ating standpoint. This is particularly true
when it comes to proper cooling water
and steam generator cleanliness.
KEEP THE HEAT
EXCHANGERS CLEAN
A thread through all of the technol-
ogies mentioned above is that the ex-
haust heat from the steam generation
process must be transferred in one or
more heat exchangers. It is paramount
Fouled Condenser Tubes 2
“This is truly a combined cycle process, as the HRSGs operate on the Rankine cycle while the combustion turbines operate on the Brayton cycle.”
1509PE_43 43 9/9/15 9:17 AM
44 www.power-eng.com
DON’T FORGET ABOUT
THE STEAM GENERATOR
Although we have focused upon
methods to maximize heat extraction
from the steam generation process,
it is important to remember that heat
input efficiency should be maximized
as well. Poor makeup water treatment
and water/steam chemistry programs
can lead to deposition and corrosion
in steam generators. While boiler tube
failures often result from poor chem-
istry, even in units with seemingly
good treatment programs, problems
can arise. The most common deposit
on steam generator tubes and internals
consists of iron oxide particulates that
are generated in the condensate/feed-
water system. (The concentration can
be very large in systems equipped with
air-cooled condensers.) So, it is abso-
lutely vital to operate with the proper
feedwater chemistry, and to have the
ability to immediately detect impurity
ingress from a leaking condenser tube
or other source. [2] For units with
ACCs, a condensate particulate filter is
an absolute must.
Periodic removal of boiler tube de-
posits by chemical cleaning is often a
necessary procedure to improve heat
transfer. Not only will deposits reduce
heat transfer in general, they will also
cause an increase in tube metal tem-
peratures which can lead to accelerated
metal deformation known as “creep.”
Finally, and often most important, is
that some deposits, and most notably
transported iron oxides, are porous and
can allow impurities in the bulk boiler
water to concentrate underneath the de-
posits. Local and rapid corrosion may
be the result. In fact, the Electric Power
Research Institute (EPRI) now recom-
mends a normal (and very low) limit
of 2 parts-per-billion for chloride and
sulfate in condensate, precisely because
these impurities, and chloride in partic-
ular, can generate severe under-deposit
corrosion in the steam generator.
1 psia (approximately 2 inches of mer-
cury). Again assuming an ideal turbine,
the enthalpy of the turbine exhaust is
904.9 Btu/lbm. The unit work output
equates to 1474.1 – 871.0 = 603.1 Btu/
lbm. At 1,000,000 lb/hr steam flow,
the total work is 603,100,000 Btu/hr =
176.7 MW. This represents a 32 percent
increase in available work from the
previous example. Obviously, conden-
sation of the steam has an enormous
effect upon turbine efficiency.
One can also look at this example
from a physical perspective. Calcula-
tions indicate that the steam quality
at the turbine exhaust pressure of 1
psia is 77 percent. (In actuality, this
would be excessive moisture that could
damage low-pressure turbine blades.
Techniques such as steam reheating are
common for reducing moisture in the
low-pressure turbine.) This means that
23 percent of the steam has condensed
to water. However, the remaining
steam takes up a specific volume of 257
ft3/lbm. The corresponding volume of
water in the condenser hotwell at sat-
uration temperature is 0.016136 ft3/
lbm. Thus, the condensation process
reduces the fluid volume nearly 16,000
times. The condensing steam generates
the strong vacuum in the condenser,
which actually acts as a driving force
to pull steam through the turbine.
(The strong vacuum also pulls in air
from outside sources, where excessive
air in-leakage can seriously affect heat
transfer.)
In the next example, we can see why
it is important to maintain proper
cleanliness in condensers and heat ex-
changers. Consider again a condensing
turbine, but where waterside fouling or
scaling (or excess air in-leakage) caus-
es the condenser pressure to increase
from 1 psia to 2 psia.
Thermodynamic calculations show
that the work output of the turbine
drops from 603.1 to 569.2 Btu/lbm.
So, at 1,000,000 lb/hr steam flow, a
rise from 1 psia to 2 psia in the con-
denser backpressure equates to a loss
of 33,900,000 Btu/hr or 9.9 MW of
work. This is a primary reason why
proper cooling water chemical treat-
ment and condenser performance
monitoring are very important. Severe
fouling may require a reduction in unit
load. If this occurs on a hot summer
day with emergency power pricing in
effect, the financial consequences can
be enormous. Techniques continue
to emerge to improve condenser, heat
exchanger, and cooling tower perfor-
mance. These include more effective
biocides, improved cooling tower film
fill, more rugged condenser tube ma-
terials, and enhanced instrumentation
for monitoring physical and chemical
operating parameters.
Similarly, for co-generation and CHP
facilities it is important to keep heat ex-
changers free of deposits and corrosion
to ensure maximum efficiency and
equipment availability.
Often, cooling towers are neglected
because they may be isolated from the
main equipment. Improper chemistry
control in chillers and building heat
systems may lead to severe corrosion.
The list goes on.
POWER PLANT OPTIMIZATION
Fouled Cooling Tower Film Fill
3
1509PE_44 44 9/9/15 9:17 AM
For info. http://powereng.hotims.com RS#13
1509PE_45 45 9/9/15 9:17 AM
www.power-eng.com46
WHAT WORKS
allowed a larger Combustion/Explosion
Hazard Area (CEHA) that would likely
meet worst-case requirements. (We used
applicable Jamaican fire codes that were
based on standards of the U.S. National
Fire Prevention Association (NFPA)
Code, Sections 57 through 59, for han-
dling of LPG and LNG.) The relatively
congested areas adjacent to the Bogue
Plant, on the other hand, would likely
require double-walled tank construction
as a safety precaution. Using a double-
walled tank would both lengthen the
construction timeline and increase cost.
The use of portable ISO LNG contain-
ers is common but not at this scale. In
addition, transporting them overland
presented significant safety risk. Staging,
filling, transporting, unloading, purging
and inspecting a proposed fleet of 350
ISO containers – based on consumption
of 22 containers per day – would likely
constitute a ‘fatal flaw.’
We investigated the market for deliv-
ering relatively small quantities of bulk
LNG in the Caribbean and found it to be
still in the early stages of development.
We did identify two suppliers that are pre-
paring to offer such service to the region
in the near term, but found no companies
currently able to deliver bulk LNG at this
small a scale. Although it lay outside the
scope of this review, we advised the cli-
ent to complete a thorough financial and
technical due diligence of potential sup-
pliers – and sign a firm supply agreement
with a credit-worthy supplier – before
moving ahead with any plan that relied
on bulk LNG delivery.
OUR RECOMMENDATION
AND LOGIC
While we advised the client that ei-
ther plan was feasible as proposed, we
recommended significant modifications
to both. For the LNG solution, we rec-
ommended relatively small-scale LNG
import; extensive due diligence before
contracting with any supplier; port-side
storage; and overland transport of the
As many who work in the Ca-
ribbean energy markets know,
Jamaica has been trying for
years to import liquefied natural gas
(LNG). Unfortunately, suppliers have
deemed the Jamaican market too small
to support a full-scale LNG storage and
regasification facility, so the need has
remained unmet.
To answer the call, Marubeni, a stake-
holder in the Caribbean power-generat-
ing industry asked our Engineering Ser-
vices team to review the technical and
safety risks of two alternate plans for re-
fueling the Bogue Power Station, a light
distillate oil-fired, combined-cycle
facility near Montego Bay, Jamaica.
(Note: As one of several investors in
Jamaica Public Service Co. Ltd. (JPS),
Marubeni engaged NAES for an inde-
pendent study and does not speak for
the other investors or for JPS.)
Designed for a net capacity of 120
MW, the refueled Bogue plant is
equipped with two GE MS6001B gas
turbines, two HRSGs and a single
steam turbine. Although it did not af-
fect the scope of this review, Marubeni
elected to retain the capability to oper-
ate on oil as a backup in the event of
disruption to the LNG supply chain.
Option 1: Small-Quantity LNG Ship
Delivery and ISO Container Overland
Transport
This plan would be based on small-
scale ship delivery of LNG with overland
transport via a fleet of small-volume
ISO containers. Once the LNG was
pumped from the ship to the containers,
the containers would then be loaded
onto flatbed tractor-trailers using truck-
mounted cranes, and transported two ki-
lometers inland to the plant. They would
be stockpiled plant-side, and the LNG va-
porized to a gaseous state by skid-mount-
ed electric vaporizers. Once the contain-
ers were empty, they would be sent back
to the port to be refilled. While this solu-
tion would present obvious operational
challenges, it would likely be the quickest
way to repower the plant and would also
reap the financial and environmental
benefits of burning LNG.
Option 2: Large-Quantity LPG De-
livery and Refrigerated Tank Storage
This solution would be based on un-
loading liquefied petroleum gas (LPG)
from a large-volume refrigerated ves-
sel into a large, stationary, refrigerated
tank(s) located at the port-side terminal
– or transported to a plant-side tank(s)
via a cryogenic pipeline. In addition to
comparing the merits of the LNG and
LPG solutions, we were asked to advise
on which LPG tank location – port-side
or plant-side – presented less technical,
financial and safety risk.
A UNIQUE SET OF
CHALLENGES
The geographical complications – an
island location with an inland plant re-
quiring both port-side and plant-side
facilities – in addition to the regional
market conditions and economics made
this an interesting assignment. The port-
side area offered a fair amount of vacant
property for siting of storage tanks. This
Risk Review Leads to Alternative Plan for Jamaica Fuel ConversionBY ANDREW MARKLE, P.E.
Author
Andrew Markle is Senior Engineer for
NAES Engineering Services
1509PE_46 46 9/9/15 9:17 AM
www.power-eng.com 47
and gravel foundation, and moisture
barrier to improve protection from fire,
hurricanes and earthquakes. While this
installation would have a larger footprint
than the single large tank, we believe the
CEHA would still be confined to the va-
cant property and adjacent water at port-
side, although a more detailed engineer-
ing investigation would be required to
verify this.
To confirm feasibility of the bullet-
tank solution, we researched a similar
installation currently under construc-
tion on the island of St. Thomas in the
U.S. Virgin Islands, and forwarded our
findings to the client. We also noted
that larger bullet tanks are available –
up to 5,000 m3 capacity with dimen-
sions of 40 x 160 feet. However, we
have not seen tanks this large used on
land and do not know of many shops
that have the capability to roll steel for
a 40-foot-diameter pressure vessel.
THE CHOSEN SOLUTION
Ultimately, the client elected to go
with an LNG solution, which was likely
prompted by fuel-pricing analysis that
lay outside the scope of NAES’ investi-
gation. Based on small-quantity ISO-
container shipment, the fuel would be
vaporized at the terminal and trans-
ported to the plant via a pressurized,
ambient-temperature pipeline. To facil-
itate the supply, Marubeni has contract-
ed with a vendor to transport the ISO
containers weekly from its small-scale
liquefaction facility in Florida.
fuel to the plant in a gaseous state via
pressurized pipeline. For the LPG option,
we favored the large-volume, refrigerated,
port-side LPG tank(s) with a port-side va-
porization facility that would also trans-
port the fuel to the plant in gaseous form
via pressurized pipeline.
Our modification of the LNG option
called for replacement of overland trans-
port in ISO containers with a pressur-
ized, ambient-temperature pipeline. ISO
containers at the scale required to supply
Bogue would introduce substantial safety
risk to personnel as well as considerable
operational complexity. While the in-
frastructure for delivering and receiving
bulk shipments of LNG in the quantities
required to operate Bogue could be erect-
ed in the near term, no vendor we con-
tacted was able to make such shipments
to the port of Montego Bay at the time of
inquiry. However, if a suitable small-scale
supplier could be found, we advised that
keeping the LNG terminal facility small
would reduce the construction schedule
from an estimated two-year duration to
a single year.
As for the proposed LPG plan, the
established supply chain for delivering
LPG in bulk quantities to the Caribbean
market eliminates much of the risk posed
by an LNG solution, at least in the near
term. By opting for the port-side stor-
age tank location, the client could likely
achieve compliance (pending a more
detailed engineering investigation) with
a single-walled tank design due to the
larger expanse of available CEHA. This
would also shorten the construction
timeline and substantially reduce capital
expense. Vaporizing the fuel port-side
would eliminate the need for a cryogenic
pipeline with all of its attendant capital
and O&M expenses.
AN ALTERNATIVE
LPG SOLUTION
In response to our recommendations,
the client requested an estimated end-to-
end construction time to fabricate, erect
and bring online a 13,000 m3 refriger-
ated, vertical-cylinder LPG tank based on
three possible configurations: single-wall,
double-wall and full-containment. Our
estimates were to reflect current market
conditions and any existing bottlenecks
that could impact construction time.
Based on our consultation with three
tank suppliers (one of which is currently
doing business in the Caribbean market)
and our own experience, we proposed a
third alternative: a port-side installation
of 10 cylindrical, horizontally erected
bullet tanks measuring 21 x 180 feet,
each with a capacity of 1,400 m3 at 80
percent full. The estimated construction
time would compare very favorably with
estimates for a vertical cylinder of single-
wall, double-wall or full-containment
construction:
• Refrigerated bullet tanks: 10 x 1,400
m3 = 8 to 12 months
• Single-wall vertical cylinder: 1 x
13,000 m3 = 18 months
• Double-wall vertical cylinder: 1 x
13,000 m3 = 24 months
• Full-containment vertical cylinder: 1
x 13,000 m3 = 24 months
With the bullet-tank solution, the
foundation-building and tank fabrica-
tion could proceed concurrently, which
would substantially reduce construction
time. In addition, several tank fabricators
located on the U. S. Gulf Coast could ship
directly to Jamaica.
We also recommended mounding the
bullet tanks with an engineered soil, sand
Mounding of LPG bullet tanks (as shown in this example) to further reduce risk from fire, hurricanes and earthquakes.
A portside tank location, where the surrounding Combustion/Explosion Hazard Area encompasses uninhabited property and water.
1509PE_47 47 9/9/15 9:17 AM
48 www.power-eng.com
PRODUCTS
Battery thermal protection
TE Connectivity’s business unit, TE Circuit
Protection, introduced the new MHP-TAM series.
The MHP-TAM device features an ultra-low-profile (L:
5.8mm x W: 3.85mm x H: 1.15mm max.) package
and a high (9VDC)
rating. The devices
in the series offer
a choice of two
different levels of
current-carrying
capacity and multi-
ple cut-off temperature ratings. The device provides
a space-efficient thermal cutoff (TCO) solution that
helps designers meet the demanding peak-current
requirements of consumer products.
Utilizing innovative metal hybrid PPTC technol-
ogy, the MHP-TAM device combines a bimetal pro-
tector in parallel with a PPTC (polymeric positive
temperature coefficient) device. In battery applica-
tions, the MHP-TAM device helps provide resetta-
ble over-temperature protection to shut down the
battery when a fault is detected. The device rests
when the fault is removed. The devices in the MHP-
TAM series feature different open temperatures,
ranging from 72°C to 90°C (typical), which are ap-
propriate for the battery market. They also offer two
levels of hold currents: low-current (approximately
6A at 25°C) and high-current (approximately 15A
at 25°C).
TE Circuit Protection Info http://powereng.hotims.com RS# 400
Film capacitor series
AVX Corp. launched the new FRC Series me-
dium power DC-link film capacitors, which
feature a wide range
of capacitance and
voltage values in ad-
dition to self-healing
properties.
Designed for use
in DC filter circuits,
power supplies, in-
dustrial inverters, UPS
systems, motor drives, power converters, and solar
inverters, the capacitors are available in nine volt-
ages spanning 400V-1500V, two tolerances (±5%
and ±10%), two lead lengths (4mm and 8mm),
and with capacitance values spanning 4.7µF to
producing highly accurate and reliable cryogenic
flow measurement, a direct result of the emphasis
they put on extensive research and development.
Turbines Inc.
Info http://powereng.hotims.com RS# 403
Front-end power supply
Tectrol announce the availability of their TFE-
1800-48 1800W output power, 48VDC out-
put front-end power supply designed in a sub-1U
horizontal package for integration into a Tectrol
power shelf or other end-user system. The power
supply includes secondary isolation from chassis
>1500VRMS with output adjustable to 54VDC for
PoE (Power over Ethernet) requirements and is
suitable for ATCA (Advanced Telecommunications
Computing Architecture) applications. This high reli-
ability power supply features universal AC input, ac-
tive PFC and I2C Interface for advanced status and
control functions.
The Tectrol TFE-1800-48 offers a very compact
footprint of just 1.60-inch x 4.00-inch x 11.00-inch
(40.64 x 101.60 x 279.40 mm), provides full power
output of 1800W over the range 180-264VAC and
1000W over the range 90-180VAC and offers high
efficiency of 85 percent minimum at 90 VAC.
Tectrol
Info http://powereng.hotims.com RS# 404
Compact digital thermocouple gauge
The Sensor Connection expanded its line of tem-
perature measurement and control instrumenta-
tion with the addition of the model DPG-SD-2 series
dual channel digital Type
K thermocouple tem-
perature gauge.
This microproces-
sor-based gauge is
packaged in a compact
52mm O.D. round hous-
ing with an IP65 rated face ideal for use in harsh
industrial environments. The dual line bright red LED
numeric display is easy to read, even at a distance.
During a high temperature alarm condition the dis-
play flashes and an internal 2 Amp relay circuit is
activated. Programming of the gauge is quick and
easy using the front panel membrane keypad.
The Sensor Connection
Info http://powereng.hotims.com RS# 405
35µF. Housed in size A cylindrical cases measuring
54mm (L) x 36mm (OD) x 5.1mm (P1), the RoHS-
compliant series is rated for operating tempera-
tures spanning -40°C to +105°C and exhibits long
lifetime performance of 100,000 hours at rated
voltage and 70°C.
AVX Corp.
Info http://powereng.hotims.com RS# 401
Corrosion protection
Cortec Corp. introduces environmentally safe
BioCortec range of corrosion control products.
BioCortec is a green response to hazardous oil
derived corrosion preventatives and offers eco-ef-
ficient, compostable and biodegradable solutions
made from sustainable materials. Utilizing new
technologies, Cortec is continuously developing
biobased chemicals.
These products do not destroy the natural bal-
ance of the environment, are functionally superior
to conventional petroleum derived products as well
as cost efficient making them a far more econom-
ical solution.
Cortec Corp.
Info http://powereng.hotims.com RS# 402
Turbine flow meter
Turbines Inc. expands its comprehensive cryo-
genic monitoring capabilities with the availability
of its cryogenic turbine flow meter for bulk and mi-
cro-bulk transports.
Turbines Inc.’s
cryogenic flow
meters for bulk
and micro-bulk
transports appli-
cations feature
the same advanced technology of their liquid flow
measurement products, but are specifically built
for low-temperature requirements. The compa-
ny’s cryogenic flow meters are widely known for
1509PE_48 48 9/9/15 9:17 AM
49 www.power-eng.com
radiation environments at extra cost.
Alliance Sensor Group
Info http://powereng.hotims.com RS# 408
Infrared surveillance system
HGH Infrared Systems offers their latest Spynel
model, the Spynel-M. With dimensions of
less than 12x20 cm and weight of only 1.8 kg,
the Spynel-M is a cost-effective, rugged, and
compact solution for wide area surveillance. One
single Spynel-M sensor effectively replaces up to
16 traditional infrared cameras and is able to per-
form 24/7 early human intrusion alerts over a 1.5
km-diameter area.
The Spynel-M
continuously cap-
tures full panoram-
ic, high-resolution
infrared images
every second to
provide real-time
security against
conventional and asymmetrical threats including
hardly detectable targets such as UAVs, RHIBs,
or crawling men. Easily transportable, it can be
carried in a backpack and quickly deployed on
a light mast or fixed atop a building for superior
wide area surveillance. While requiring only 8
watts of power, Spynel-M can also be operated
with solar or alternate power supply systems to
allow for a remote operation. Unlike radar, the
system is completely passive, requires no addi-
tional light source and cannot be jammed. The
intuitive advanced intrusion detection software,
Cyclope, automatically tracks and detects an
unlimited number of targets from any direction at
any time of day or night and under any type of
weather conditions. As versatile as it is mobile,
the system can also be paired with other systems
such as radars and PTZs for data integration and
target identification.
HGH Infrared Systems
Info http://powereng.hotims.com RS# 409
Thermal flow meter
Magnetrol has released of the Thermatel TA2
thermal dispersion mass flow meter with
FOUNDATION fieldbus digital output communi-
cations. This addition signifies the growth of the
THERMATEL TA2 mass flow technology offering
Refractometers
Eriez HydroFlow Refractometers are simple yet
rugged instruments that give users the ability
to quickly determine the concentration of metal-
working coolants and cleaners, heat-treating flu-
ids, water-based hydraulic fluids and plating baths.
Portable Refractometers require no batteries.
They feature a large, easy-to-read scale that is
available in two ranges: 0-10° Brix and 0-32°
Brix. Automatic Temperature Compensating
Refractometers provide an ideal solution for sit-
uations in which the temperature of certain fluids
can affect the refractive index reading of the mix.
They have a large, easy-to-read scale available in
two ranges: 0-20° Brix and 0-30° Brix.
Extremely accurate, hand-held Digital
Refractometers are also available. They feature an
easy-to-read LCD readout with a 0-52° Brix range.
Eriez HydroFlow
Info http://powereng.hotims.com RS# 406
Position sensors
Alliance Sensors Group expanded its in-cylin-
der position sensor product line to include the
MHP series
linear induc-
tive sensors.
These com-
pact inductive
linear sensors
were de-
signed to be
installed into
the rear end-
cap of hydraulic cylinders for operation at pres-
sures up to 5000psig. Their 1-inch hex aluminum
or stainless steel housing are ideal for oil and gas
exploration equipment, and mount to the cylinder
with a standard male o-ring port thread.
The MHP series sensors are based on a pro-
prietary contactless inductive sensing technology
with a short stroke to length ratio. They employ
a 7 mm diameter probe inserted into an 8 mm
(5/16 inch) gun-drilled hole in the cylinder rod to
measure position rather than a ring magnet or pot
contact spool. They are offered in ranges from 50
to 600mm (2 to 24 inches) full scale with a wide
variety of on analog I/Os and either connector
and cable terminations.
The MHP series also includes the MR and ME
series for larger cylinders and actuators.
Alliance Sensors Group
Info http://powereng.hotims.com RS# 407
Linear position sensors
The Alliance Sensors Group PG Series LVDT
linear position sensors are designed and en-
gineered specifically for valve position sensing
applications for steam turbine control systems in
electric power generation plants.
Alliance Sensors Group’s approach to their
PG series LVDT design for the power generation
industry started with the premise that the LVDT
must be extremely rugged, so these units feature
a large diameter housing with a very thick wall
and a versatile mounting configuration. A PG se-
ries LVDT’s 3/8 inch diameter operating rod cap-
tivates the LVDT’s core so that it can never come
out or vibrate loose. This rod is offered with either
a rigid coupling or a ball joint coupling that can be
helpful in installations where there is a minor mis-
alignment with the attachment mechanism on
the steam valves. PG series LVDTs utilize materials
and manufacturing processes that can be certi-
fied for use in mild radiation environments found
in boiling water reactor nuclear power plants.
Alliance Sensors Group PG Series LVDTs are
available in five full scale ranges from 0-to-3 to
0-to-15 inches (75 to 380 mm). Models include
the PGHD Heavy Duty series LVDT with a 1-1/16
inch body diameter and the PGSD Super Duty se-
ries LVDT with a 1-5/16 inch body diameter. Either
series is available certified for operation in mild
1509PE_49 49 9/9/15 9:17 AM
50 www.power-eng.com
and the MAGNETROL
commitment to con-
tinued development in
flow measurement and
control solutions. The
THERMATEL TA2 with
FOUNDATION fieldbus
offers all of the advan-
tages of the standard TA2
model.
Magnetrol
Info http://powereng.hotims.com RS# 410
HART flow meters protocol option
Universal Flow Monitors, Inc. now offers a HART
protocol option on all of its variable area and
piston style flowmeters designed to perform in
cha l leng ing
l u b r i c a t i o n
environments.
These meters
are optimized
for specific
lubrication flu-
ids. There is an additional option of a mechanical
switch to back up the transmitted signal.
HART is a digital communication signal super-
imposed on top of the 4–20 mA standard analog
signal that provides additional digital information
to the controller.
The HART option is offered on all variable area
vane and piston style flowmeters. These simple
low maintenance meters come in 12 sizes and
go up to 2000 PSI pressure for flow ranging up
to 500 GPM. They have CSA and CE certifications.
Universal Flow Monitors Inc.
Info http://powereng.hotims.com RS# 411
Terminal blocks
Due to their compact size and ease of use,
WAGO Corp.’s new 2059 SMT PCB terminal
blocks offer a cost-effective alternative to solder-
ing leads.
With a height of merely 2.7 mm, the extremely
compact 2059 reduces the space required for the
connection technology. Designed for the smallest
installation spaces, the light color and low profile
of the PCB terminal block substantially reduce on-
board LED shadowing. The 2059 Series features
a PUSHWIRE connection of solid or pre-bonded
conductors, with a tool-operated release slot, en-
abling a high-quality and maintenance-free connec-
tion between drivers and LED modules. Wire remov-
al capability (in case of wiring errors or at the end of
module life) is an exclusive feature in this size.
Surface-mount terminal blocks are especially
suited for solid state lighting applications that
often utilize metal-core PCBs, including compact
or miniaturized LED modules and LED ‘bulbs’.
Available in 1-,
2- and 3-pole
configurations,
group arrange-
ment is also
possible without
losing any poles. Offering similar functionality as
the field-proven 2060 Series, the 2059 accom-
modates conductors 26-22 AWG with pin spacing
of 3 mm, and is available in tape-and-reel pack-
aging for automated assembly. The 1-pole variant
is rated for 3A/600V; the 2- and 3-pole variants
are rated for 3A/250V.
Wago Corporation
Info http://powereng.hotims.com RS# 412
Diesel mobile generators
Kohler Power Systems is adding two new mod-
els to its line of diesel-powered mobile gen-
erators. The two new units Kohler’s 145REOZT4
and 175REOZT4 diesel mobile generators offer
quiet and reliable operation while delivering de-
pendable power wherever it’s needed and meet
all emissions standards.
Kohler Power Systems offers mobile generators
for any application from industrial power to public
events. The company’s 145REOZT4 and 175REOZT4
are EPA-emission certified for non-road use and
come equipped with a rugged DOT-certified trailer
and durable enclosure. Both units utilize John Deere
Tier 4 Final 6.8L engines that help lower operating
costs with efficient performance and fuel savings.
Kohler Power Systems
Info http://powereng.hotims.com RS# 413
Input-Output modules
Industrial automation manufacturer Opto 22 has
released the SNAP-AIMA-iH and SNAP-AOA-23-
iH two-channel analog input and output modules,
each with HART communications. Both SNAP I/O
modules use the HART communications protocol
to extract sta-
tus, diagnos-
tics, and other
i n f o r m a t i o n
from smart de-
vices such as
field-mounted
process trans-
mitters and analyzers. This information can be used
by the automation system and/or the asset manage-
ment system to increase uptime, improve productivi-
ty and enhance safety.
The SNAP-AIMA-iH analog input module has two
isolated 4-20 mA input channels, and the SNAP-
AOA-23-iH output module has two isolated 4-20 mA
output channels. Each channel features an integrat-
ed HART modem that allows the channel to commu-
nicate digitally with the HART frequency-shift keying
signal imposed on the 4-20 mA current loop, en-
abling communication with the target smart device.
Opto 22
Info http://powereng.hotims.com RS# 414
Chip resistor with Kelvin 4 wire
The CSSK Series from Stackpole offers a 0612
size chip resistor with Kelvin 4 wire connec-
tion. The robust all metal construction withstands
pulses and environmental stresses with mini-
mal resistance shift. The low resistance values
down to 0.75 milliohms and the terminations on
the long side of the part handle high currents
with relatively low self-induced heating for high
efficiency.
The CSSK0612 is available in resistance values
from 0.75 milliohms to 2 milliohms in 1 percent, 2
percent, and 5 percent tolerances. Pricing varies
with tolerance and resistance and ranges from
$0.25 to $0.40 each in full package quantities.
Stackpole Electronics Inc.
Info http://powereng.hotims.com RS# 415
1509PE_50 50 9/9/15 9:17 AM
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Handling a World of Materials
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Demolition/Decommissioning
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For Classified
Advertising
Rates & Information
Contact
Jenna Hall
Phone:
918-832-9249
1509PE_52 52 9/9/15 9:09 AM
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The Board of Directors of Sho-Me Power Electric Cooperative is seeking qualifed
candidates for the position of General Manager. The General Manager reports to a nine-
member Board of Directors that sets policy and approves electric rates for both members
and non-members of Sho-Me Power. Sho-Me Power Electric Cooperative is a generation
and transmission electric cooperative owned by nine distribution cooperatives who serve
over 200,000 retail customers in southern Missouri. Sho-Me’s power requirements are
supplied by Associated Electric Cooperative, Inc. (AECI), created by Sho-Me and fve other
G&T cooperatives in 1961.
Sho-Me Technologies, a wholly owned subsidiary of Sho-Me Power, provides fber optic
broadband communication services to rural Missouri. Headquartered in Marshfeld,
operations personnel are strategically located at 3 crew facilities to minimize emergency
response times. Facilities include Marshfeld, Cuba and Willow Springs, Missouri.
The cooperative has 150 employees, operating and maintaining over 1,800 miles of electric
transmission line, operated at voltages from 69 kV to 345 kV, connecting 22 transmission
and 133 distribution substations throughout south central Missouri. In 2014, the G&T had
consolidated annual operating revenues of $207,058,927, total operating expenses of
$201,091,540 and a total net utility plant of $265,717,000. Thirty-seven of the
cooperatives’ 150 employees are assigned to its subsidiary Sho-Me Technologies which
operates over 5,000 miles of fber optic communication equipment and provides services
to cell towers, educational institutions, medical facilities, government, and fnancial
institutions in Missouri.
Candidates should have a minimum of ten years of electric utility experience, preferably
within the rural electric program and at least fve years senior management experience.
Candidates must have broad electric utility experience encompassing the areas of
operations, fnance, engineering, technology, marketing, power supply, strategic planning,
union relations, member communications and board relations. Excellent communication
skills, proven leadership ability and a strong commitment to cooperative principles is
required. A bachelor’s degree in an appropriate feld is required.
Interested candidates should include a resume, cover letter and a minimum of three (3)
professional references or letters forwarded to: Andereck, Evans, Widger, Johnson & Lewis,
LLC, ATTN: Rodric A. Widger, 3816 South Greystone Court, Suite B, Springfeld, Missouri,
65804, 417-864-6401. Electronic copies should be forwarded to
[email protected]. Applications will be accepted from September 1 through
October 1, 2015. All inquiries and applications are confdential.
Sho-Me Power Electric Cooperative is an equal opportunity provider and employer.
All qualifed applicants will receive consideration for employment without regard to race, color, religion, sex, sexual
orientation, gender identity, national origin, disability status, protected veteran status, or any other characteristic
protected by law.
EOE AA M/F/Vet/Disability
General Manager
Sho-Me Power Electric Cooperative, Marshfeld, Missouri
For info. http://powereng.hotims.com RS# 450
1509PE_53 53 9/9/15 9:09 AM
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REACH YOUR AUDIENCE
ADVERTISE your career opportunities, equipment, services,
and training programs in Power Engineering’s Classif ed Section.
GET RESULTS
Put your message in front of North
America’s most qualif ed circulation
with Power Engineering’s classif eds.
CALL NOW FOR DETAILS: JENNA HALL
Phone: 918.832.9249 | Email: [email protected]
GEORGE H. BODMAN, INC.Chemical cleaning advisory services for
boilers and balance of plant systems
George H. BodmanPres / Technical Advisor
P.O. Box 5758 Office (281) 359-4006Kingwood, TX 77325-5758 1-800-286-6069email: [email protected] Fax (281) 359-4225
For info. http://powereng.hotims.com RS# 452
For info. http://powereng.hotims.com RS# 451
Tell Us What You Have For Sale
WE BUY
Help Us
“Sniff Out”
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For info. http://powereng.hotims.com RS# 453
POWER PROFESSIONALS
Opportunities in Operations and Maintenance,
Project Engineering and Project Management.
Business and Project Development.
First-line Supervision to Executive Level Positions.
Employer pays fee. Send resumes to:
P.O. BOX 87875,
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email: [email protected]
(360) 260-0979 • (360) 253-5292
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For info. http://powereng.hotims.com RS# 454
1509PE_54 54 9/9/15 9:09 AM
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For Classified Advertising Rates & Information
Contact Jenna Hall
Phone - 918-832-9249, [email protected]
CONDENSER & HEAT EXCHANGER TOOLS
CLEANERS, PLUGS, BRUSHES
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PH # 800-726-1026 e-mail: [email protected]
www.johnrrobinsoninc.com
For info. http://powereng.hotims.com RS# 456
24 / 7 EMERGENCY SERVICE
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444 Carpenter Avenue, Wheeling, IL 60090
wabash
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ESI Boi ler Rentals, LLCRENTAL EQUIPMENT
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CONDENSER OR GENERATOR AIR COOLER TUBE PLUGS
THE CONKLIN SHERMAN COMPANY, INC.
Easy to install, saves time and money.ADJUSTABLE PLUGS - all rubber with brass insert.
Expand it, install it, reverse action for tight fit.
PUSH PULL PLUGS - are all rubber, simply push it in.
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Just Plugging Along
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1319 Macklind Ave., St. Louis, MO 63110 Ph: (314) 781-6100 / Fax: (314) 781-9209
www.ampulverizer.com / E-Mail: [email protected]
Quality and Service Since 1908
Ring Granulators, Reversible Hammermills,
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For info. http://powereng.hotims.com RS# 459
Get a thorough mix with:
Pugmill Systems, Inc.P.O. Box 60
Columbia, TN 38402 USA
Ph: 931-388-0626 Fax: 931-380-0319
www.pugmillsystems.com
For info. http://powereng.hotims.com RS# 458
For info. http://powereng.hotims.com RS# 460
1509PE_55 55 9/9/15 9:09 AM
www.power-eng.com56
INDEX
RS# COMPANY PG# SALES OFFICERS# COMPANY PG#
1421 S. Sheridan Rd., Tulsa, OK 74112 Phone: 918-835-3161, Fax: 918-831-9834 e-mail: [email protected]
Sr. Vice President North American Power Group Richard Baker
Reprints Foster Printing Servive 4295 Ohio Street, Michigan City, IN 46360 Phone: 866-879-9144 e-mail: [email protected]
National Marketing Consultant Rick Huntzicker Palladian Professional Park 3225 Shallowford Rd., Suite 800 Marietta, GA 30062 Phone: 770-578-2688, Fax: 770-578-2690 e-mail: [email protected] AL, AR, DC, FL, GA, KS, KY, LA, MD, MO, MS, NC, SC, TN, TX, VA, WV
Regional Marketing Consultant Dan Idoine 806 Park Village Drive, Louisville, OH 44641 Phone: 330-875-6581, Fax: 330-875-4462 e-mail: [email protected] CT, DE, IL, IN, MA, ME, MI, NH, NJ, NY, OH, PA, RI, VT, Quebec, New Brunswick, Nova Scotia, Newfoundland, Ontario
Regional Marketing Consultant Natasha Cole 1455 West Loop South, Suite 400 Houston, Texas 77027 Phone: 713.499.6311; Fax: 713.963.6284 e-mail: [email protected] AK, AZ,CA,CO,HI,IA,MN,MT,ND,NE,NM,NV,OK,OR,SD,UT,WA,WI,WY,AB,BC,SK, Manitoba, Northwest Territory, Yukon Territory
Regional Brand Manager Kelly Balaskovits 1421 S. Sheridan Rd., Tulsa, OK 74112 Phone: 918-831-9129; Fax: 918.831.9834 e-mail: [email protected] AK, AZ,CA,CO,HI,IA,MN,MT,ND,NE,NM,NV,OK,OR,SD,UT,WA,WI,WY,AB,BC,SK, Manitoba, Northwest Territory, Yukon Territory
International Sales Mgr Tom Marler The Water Tower Gunpowder Mills Powdermill Lane Waltham Abbey, Essex EN9 1BN United Kingdom Phone: +44 1992 656 608, Fax: +44 1992 656 700 email: [email protected] Belgium, Czech Republic, Denmark, Finland, France, Germany, Hungary, Norway, Poland, Portugal, Slovenia, Spain, Slovakia, Sweden
International Sales Mgr Roy Morris The Water Tower Gunpowder Mills Powdermill Lane Waltham Abbey, Essex EN9 1BN United Kingdom Phone: +44 1992 656 613, Fax: +44 1992 656 700 email: [email protected] UK, Austria, Africa, Holland, India, Italy, Ireland, Israel, Russia, Australia & New Zealand, Singapore, Scotland, Switzerland, Turkey, Greece, UAE/SAUDI and Iran
Classifieds/Literature Showcase Account Executive Jenna Hall 1421 S. Sheridan Rd., Tulsa, OK 74112 Phone: 918-832-9249, Fax: 918-831-9834 email: [email protected]
Rentech Boiler Systems, Inc. DIGITAL EDITION-COVER
www.rentechboilers.com
9 Roxul Inc 33 www.roxul.com
12 Sealeze, A Unit 37 of Jason, Inc
www.sealeze.com
8 Structural Integrity 21 Associates
www.structint.com/power-eng
Sulzer Management Ltd DIGITAL EDITION-BELLY BAND
www.sulzer.com
10 Sulzer Turbo Services 35 www.sulzer.com
Advertisers and advertising agencies assume liability for all contents (including text repre-sentation and illustrations) of advertisements printed, and also assume responsibility for any claims arising therefrom made against the publisher. It is the ad-vertiser’s or agency’s responsibil-ity to obtain appropriate releases on any items or individuals pic-tured in the advertisement.
3 Brand Energy and 5 Infrastructure Services
www.beis.com
6 Buckman 15
14 Cleaver-Brooks Inc C3 www.cleaverbrooks.com
4 Haldor Topsoe Inc 7 www.topsoe.com
2 Indeck Power Equipment 3 www.indeck-keystone.com
7 Lapeyre Stair 17 www.lapeyrestair.com
5 Magnetrol International 9 www.magnetrol.com
1 Mitsubishi Power C2 Systems Americas Inc
www.mhpowersystems.com
11 PennWell Corporation 36 www.power-eng.com/webcasts
13 POWER-GEN 45 International
www.power-gen.com
15 ProEnergy Services LLC C4 www.proenergyservices.com
1509PE_56 56 9/9/15 9:17 AM
To find your nearest representative,
visit cleaverbrooks.com or call 800.250.5883.
When you need BIG POWER,total integration generates bigger and better results.
No matter the business — refi nery, utility, manufacturing or petrochemical — if you are in an industry that
demands big power, you’ll want to check out the complete range of boiler systems from Cleaver-Brooks.
For more than 80 years, we have set the industry standard in the design and production of boiler systems
that continually maximize effi ciency and deliver uncompromising reliability and the lowest possible emissions.
Our total integration is that every component — from gas inlet to stack outlet — is designed, engineered and
manufactured by just one company.
©2015 Cleaver-Brooks, Inc.
Visit Stand F18 at the 2015 Power-Gen Middle East Show
For info. http://powereng.hotims.com RS#14
1509PE_C3 3 9/9/15 9:17 AM
US Corporate Office | 660.829.5100 proenergyservices.com
Accelerate your next power project with ProEnergy’s EPC FastTrack.
With ProEnergy’s full inventory of equipment, including turbine and generator
packages, auxiliary skids, transformers and compressors, all of the pieces you need
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For info. http://powereng.hotims.com RS#15
1509PE_C4 4 9/9/15 9:17 AM