Refine Fuel Consumption

Refine Fuel Consumption
from the editor
Refine Fuel
Consumption
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Control combustion and improve
operating efficiencies of fired equipment.
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A single industriAl fAcility
can consume millions of dollars in fuel each year to
generate steam and to heat occupied space, water and
process equipment, making fuel a significant portion
of operating and product costs as well as a major
contributor to environmental impact and carbon
emissions. The bad news for energy, environmental
and sustainability managers is that fuel-consuming
equipment often includes complex burner, heat
exchanger, heat recovery and control systems that
deteriorate over time due to high temperatures and
combustion byproducts. These may require a high level
of expertise and attention to optimize efficiency.
The good news is that much of this equipment could
be a lot more efficient. For example, “Eight out of 10
By Paul Studebaker
boilers are more than 30 years old,” says Steve Connor,
director of marketing and training, Cleaver-Brooks.
“They run less efficiently, often are unreliable and might
even be in violation of U.S. federal pollution standards.”
Most industrial facilities have at least one boiler,
and the principles of boiler efficiency and control
generally apply to other industrial combustion systems,
so that’s where we start our overview. Then we’ll talk
about process heating and steam systems, followed
by opportunities in cogeneration, district energy and
alternative fuels.
Boiler versus steam audits
A steam audit is a comprehensive analysis of energy
used within a facility, process or equipment, including
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recommendations for energy conservation measures.
Connor says there are two types of steam audits: a
simple boiler system audit and a complete facility audit.
In a simple audit, a professional evaluates the boiler
room, boiler and accessory support equipment, possibly
extending the evaluation somewhat into the facility.
With a complete site audit, auditors evaluate the boiler
system as well as components throughout a facility,
including steam traps, piping, valves and steam users.
“A simple boiler system audit costs about $1,000,
whereas a complete site audit, depending on the number
of steam traps, other equipment and the size of the plant,
could cost a few thousand dollars,” Connor says. The
essential steps are:
• Data acquisition: Identify where and how a facility,
process or equipment uses energy, along with costs
and utility issues affecting the energy consumption.
• Data analysis: Identify energy conservation measures
to make energy use more efficient, less expensive and
more environmentally friendly.
• Recommendations: A final report details what was
found, a list of areas that need improvement, and
recommended actions, usually accompanied by some
type of economic justification.
a facility need not shut down
for a steam audit – it’s Better
that it continue as usual so the
auditor can easily spot steam
leaks and other anomalies.
A steam audit can take several days to complete,
depending on the type of audit and the size of the
facility. A facility need not shut down for the procedure;
it’s better that it continue as usual so the auditor can
easily spot steam leaks and other anomalies during daily
operations.
During a boiler room audit, “Your mild-mannered
auditor will check the boiler controls, the boiler,
blowdown and feedwater conditioning to identify
inefficiency issues,” Connor says. “Auditors use their
uncanny abilities to do an inventory of key equipment,
looking for energy-saving methods, areas to implement
better engineering practices, and health and safety
concerns.”
In a complete facility audit, an inspector not only
checks the inventory of key equipment in the boiler
room, but also focuses on potential improvements
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Cogeneration Cuts
CO2 and Energy Costs
Pratt & Whitney’s Middletown, Connecticut, jet engine manufacturing, assembly and test facility faced
a number of operational challenges in its plant powerhouse. The existing boilers burned only #6 fuel oil
and were oversized for current steam requirements,
resulting in inefficiencies. Boiler maintenance and
repair costs were increasing, and it was becoming
more difficult to meet ever-changing environmental
requirements. Electricity and energy prices were
rising, and the state of Connecticut offered opportunities and incentives to help offset capital costs
of “behind the fence” generation. The company also
recognized intrinsic efficiency and security benefits
of cogeneration.
The facility decided to replace two Erie City Boilers (100,000 pounds per hour) that had been built in
1956 and a Keeler Boiler (150,000 pounds per hour)
installed in 1975 with a Solar Turbine Taurus 70 combined heat and power (CHP) plant and an associated
heat-recovery steam generator. The CHP plant can
produce 7.5 MW. Two quick-start Rentech boilers
(40,000 pounds per hour) also were installed to balance the steam load. “This new line-up of equipment
provides all our steam needs and nearly two-thirds of
our annual electricity requirements of 90 million kWh
at the site,” says Mark Kopera, Pratt & Whitney energy
services manager. Natural gas replaced #6 oil as the
primary fuel, with #2 oil as an alternate. “This environment-friendly solution reduced our greenhouse gas
footprint by over 10% in just one year and has been
operating since January of 2008,” says Kopera.
throughout the energy-using facility. The evaluator
inspects the boiler, steam flow, pressures, temperatures,
air handling, steam trapping, piping ancillaries including
valving and insulation, condensate handling and heat
recovery. Energy savings are sought through:
• Locating steam leaks
• Heat recovery
• Conservation of flash steam
• Return of condensate
start at the fire
One of the first things an auditor needs to determine
is the condition of the boiler system. “The decision to
replace a boiler shouldn’t be based solely on the boiler’s
age,” Connor says. “Some boilers, even at 70 years old,
remain in good condition. However, if the boiler is
leaking, heavily scaled, or has outdated burners and
controls, it’s probably time to replace it.”
Typically, efficiency improvement alone doesn’t justify
a complete boiler replacement. However, coupling that
with spending otherwise necessary for a burner retrofit
or boiler heat exchanger repair may. The specifics of your
existing equipment and your current and future needs
will determine what can be done, what this entails and
the cost.
In many cases a retrofit, that is, modernizing your
current boiler, makes the most economic sense. “Often
it’s easy to justify upgrading the control system with
a state-of-the-art programmable logic controller and
a new servo-based burner-management system,” says
Andy Wales, western regional manager, Clayton
Industries. “Adding an economizer usually is a viable
way to boost efficiency. However, repairing a boiler
that’s too small or inefficient may not be the best use of
your capital budget.”
Efficiency retrofits such as an updated burner or
combustion control system “can save 50% on capital
costs compared to a new boiler unit and provide
significant fuel savings at least equal to the retrofit cost
during the first year,” says Connor.
Auditors also investigate whether the boiler has been
overheating. If the boiler overheats, there might be
problems with either the boiler’s insulation or gasketing,
which could lead to damaged and unsafe equipment.
The cost of repairs to correct these types of problems are
relatively nominal when compared to the consequences
of letting conditions exist that result in serious safety or
mechanical repair issues.
tune out excess air
The auditor will perform a combustion test using stack
gas analysis equipment to quantify boiler efficiency. This
could lead to the recommendation of an oxygen sensor/
transmitter in the exhaust gas.
The sensor/transmitter continuously senses oxygen
content and provides a signal to the controller, which
adjusts the air damper and gas valve, maintaining
a consistent oxygen concentration in the flue. This
minimizes excess air while optimizing the air-to-fuel
ratio. “Oxygen trim systems typically increase efficiency
by 1% to 2%, which, if you’re looking at energy bills in
the millions, means saving $10,000 or more each year.”
Plants typically supply air instead of oxygen for
combustion, which means four parts of nitrogen for each
part of oxygen. The excess nitrogen picks up heat and
leaves the stack at an elevated temperature, contributing
to stack-gas losses.
Minimizing stack gas loss is done by minimizing both
the quantity and the temperature of the gases. “If these
factors are higher than required, stack losses also are
fuel
higher and heater efficiency is reduced,” says Veerasamy
Venkatesan, general manager, VGA Engineering
Consultants. “Controlling the quantity of stack gases is
the most-talked-about savings opportunity for process
heaters. However, at 80% of the process plants I visit no
significant efforts have been undertaken.”
So the first step in process heater optimization is to
control the quantity of excess air supplied to the burner.
Most burner manufacturers recommend about 10%
excess air. Many plants add a further safety margin,
increasing this to 20% or more. “At some sites, either
operators are unaware of excess air levels or burner
control systems are too primitive to make changes,” says
Venkatesan. “In any case, it’s worthwhile to evaluate the
opportunity to trim excess air.”
Burners firing natural gas typically require about
1% excess oxygen (or about 5% excess air) to achieve
complete combustion. So, if the level exceeds 2%, the
first step is to reduce it. If a heater already is maintained
at 2% oxygen in stack gas, it still may be possible to
trim further. For some heaters, you can reduce excess air
without significant capital investment.
Field-tune each major heater to meet a target operating
level: combustion efficiency exceeding 80% with 1%
to 2.5% oxygen and near 0% combustibles in the flue
gas. “This target range is neither new nor unrealistic,”
Venkatesan says. “The tough part of the task is
convincing plant operators to shift from their comfort
zone to the optimum operating zone.
“The results usually are measurable at the end of the
first year — and can add up to significant savings if
the annual purchased fuel bill exceeds $25 million,”
Venkatesan adds. “Typically, the first year payoff is five
times more than the cost of the first year efforts.”
soak up wasted heat
It’s very common to see stack temperatures above 400°F
in process heaters that were designed prior to 1980. More
recent designs may operate with stack temperatures of
around 250°F. “Approximately 1% additional fuel is
consumed for every 40°F rise in the stack temperature
at the same process heating load,” Venkatesan says. To
bring down those temperatures:
• Always keep the process heater’s heat recovery
surfaces clean. Add soot blowers or improve
maintenance of existing soot blowers.
Soot can be mechanically removed with a flue brush.
“Once the soot is gone, a professional will be needed to
recalibrate the burner,” Connors says. “The return on
your investment to reduce stack temperature is quick,
usually in less than one year.”
On boilers, another cause of elevated stack
temperature is scale formation on the waterside surfaces
caused by improper water treatment. The remedy might
be either acid cleaning or tube replacement, depending
on the severity of the scaling condition. “In either case,
the fix, though more expensive than cleaning the fireside,
is often paid back through energy savings in a year or
less, depending on boiler size,” Connors adds.
• Look for heat sinks in nearby processes. If the inlet
process temperature is limiting how low you can get
the stack temperature, consider pinch technology,
where multiple heat sources and heat sinks are
integrated to recover more heat.
“In one of the heaters at a client site, we replaced
its low pressure (LP) steam generating coil with an
economizer coil to preheat the fresh makeup water
from ambient to moderate temperatures before sending
it to the deaerator,” says Venkatesan. “The stack
The High Price of Escape
Equivalent
orifice diameter
Steam loss (lbs/yr)
Steam cost per 1,000 lbs
$5.00
$7.50
$10.00
115,630
$578
$867
$1,156
1/8 in.
462,545
$2,313
$3,469
$4,625
1/4 in.
1,848,389
$9,242
$13,863
$18,484
1/2 in.
7,393,432
$36,967
$55,451
$73,934
1/16 in.
At 100 psig. Cost multipliers for other steam pressures:
16 psig: 0.26
200 psig: 1.87
50 psig: 0.56
300 psig: 2.74
150 psig: 1.43
600 psig: 5.35
fuel
temperature of the heater dropped from 400°F to about
310°F. Also the deaerator’s reduced LP steam use more
than compensated the LP steam generation loss from
the old coil.”
• Explore options for alternative use of low-level
heat. If you can’t find additional heat recovery
opportunities, consider using an adsorption chiller to
provide chilled water for cooling.
“In a Wyoming refinery, we came across a situation
where process condensers cooled by tower water were
insufficient to recover all the light ends from the
refinery fuel gas stream — especially in the summer.
Our recommendation to install an absorption chiller to
complement the condenser cooling was well received,”
Venkatesan says. “In that refinery, LP steam is generated
by additional heat recovery from the process heaters,
and the excess LP steam is used to run the absorption
chiller.” Absence of critical non-moving parts in
absorption chillers keeps their maintenance costs low.
if steam pressure can Be
reduced, fewer Btus per
hour will Be used in the
process, saving the facility
those energy dollars.
examine the steam circuits
Moving outside the boiler room, an auditor will
determine what the steam is used for, how it’s applied
and if it’s possible to lower the system pressure to
reduce the heat required to produce a pound of steam.
“The heated process is reviewed along with the piping
to see whether the diameters of the piping, controls,
steam traps and control valves allow operation at
lower pressure, knowing velocities and pressure
differentials will be changing,” Connors says. “If it’s
concluded that the pressure can be reduced, fewer
BTUs per hour will be used in the process, saving the
facility those energy dollars.”
Survey the steam piping for energy losses through
radiation and steam leaks. “More than half of process
plants lack pipe insulation or the insulation has
deteriorated to the point of uselessness,” Connors says.
The larger the pipe diameter and greater the length, the
more insulation can help in saving energy.
Reducing steam leaks caused by piping corrosion
and compromised flanging can be another significant
energy saver. He adds, “The leaks appear as wisps
of condensed steam, and, once secured, result in
considerable dollars saved.”
Steam traps are typically part of a complete facility site
audit. Look for traps that blow through, pressurizing the
condensate line and causing waterlogging and inefficient
process performance. Traps are normally checked using
heat-sensitive or ultrasonic instrumentation. A steam
trap audit will gather information on the number of
steam traps in the facility, test and tag the steam traps,
record findings, and calculate energy-saving measures
and potential ROI.
condensate and feedwater
Boiler feedwater should be free of dissolved gases such as
oxygen and carbon dioxide, which can cause destructive
corrosion to the boiler and condensate lines. If you’re
using a water softener, be sure it’s working properly.
“Without a water softener, scale builds up in the heat
exchanger, and it doesn’t take much scale to cause fuel
usage to skyrocket,” Connor says. “A quarter-inch of
scale increases fuel use as much as 15%.”
Condensate should not be dumped down the drain.
Along with raising concerns about wastewater quality,
the practice discards treated water that contains a
significant amount of energy.
Steam contains two types of energy: latent and
sensible. When steam is supplied to a process application
(heat exchanger, coil, tracer, etc.) the steam vapor
releases the latent energy to the process fluid and
condenses to a liquid condensate. “The condensate
retains the sensible energy the steam had,” says Kelly
Paffel, technical manager, Swagelok Energy Advisors and
a member of the U.S. Department of Energy’s (DOE)
Steam Best Practices and Steam Training Committees.
“The condensate can have as much as 16% of the total
energy in the steam vapor, depending on the pressure.”
Condensate is hot, so it takes far less heat and fuel
to turn it back into steam than it would to produce
steam from an equal quantity of cold water. “Reusing
condensate can lead to hundreds of thousands of dollars
in savings, depending on the size of the boiler and its
operating hours,” Connors says.
You can also save energy by raising the temperature of
feedwater with recovered heat. “An auditor will probably
suggest an economizer if your facility hasn’t already
invested in one, because an economizer can reduce the
steam boiler’s fuel requirements by transferring heat
from the flue gas to incoming feedwater,” Connor says.
“An economizer can often reduce fuel requirements by
5% to 10%, and if you’re looking at $1 million to $3
million in annual energy costs, this retrofit can save
$50,000 to $300,000 a year.”
fuel
it doesn’t take much heat
exchanger scale to cause fuel
usage to skyrocket – a quarterinch of scale increases fuel
use as much as 15%.
cogeneration is a hot topic
Defined here as generating both heat and electric power
from a single combustion event, cogeneration is a hot
topic in North America due to the recent relatively low
price of natural gas, and everywhere because it offers a
practical way to significantly improve total energy yields.
Cogeneration typically uses internal combustion
engines or gas turbines to drive electric power generators,
with the exhaust and/or cooling system heat recovered to
produce steam and/or process heat. “For diesel generators
using natural gas or diesel fuel, absorption chillers
capture the energy available in exhaust and the jacket
water for heating and cooling,” says Farhad Ghahremani,
P.E., president and founder, Cogeneration Planners.
“Alternatively, the exhaust heat recovery system of a gas
turbine generator can produce steam.”
Cogeneration offsets other forms of energy
production, such as power grid generation and localized
firing of natural gas or oil in a boiler. According to
the DOE, if cogeneration were to supply 20% of U.S.
electricity generating capacity by 2030, the projected
increases in carbon dioxide emissions would be cut
by 60%. Overall emissions of carbon dioxide, oxides
of nitrogen and sulfur dioxide from grid-provided
electrical production are reduced as more onsite
cogeneration systems are installed.
The advantages don’t stop with efficiency and
emissions. “Power reliability is cogeneration’s
greatest benefit,” says Tim Baur, P.E., senior program
manager, Vericor Power Systems. “No plant can afford
blackouts from storm damage, poor utility operation
or transmission line failures. Onsite cogeneration
systems equipped with sufficient redundancy, such as
standby grid connection and uninterruptible power
supply systems, can far exceed the reliability of some
local utilities.”
consider alternative fuels
The current low price of natural gas in the United States
makes it a tough competitor, but where you’re using oil
or coal, or in parts of the world where natural gas isn’t
cheap, and in the future, most likely everywhere, waste
streams and renewable fuels offer viable and economical
alternative fuels.
Renewables such as biogas from landfills and organic
waste streams, and biomass as a byproduct or end
product of agriculture and forestry are reducing the
carbon footprints of many facilities.
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Scottish distilling icon William Grant & Sons
(Grant’s) uses a combined heat and power system at
the Grant’s Girvan Distillery in Girvan, Scotland.
Operating on biogas from residual malt materials
used in distillation to produce alcohol, a set of four
gas engines can generate about 7 MW. The engines’
exhaust provides heat to produce steam used in the
distilling process.
Located in Whittlesey, Peterborough, the UK’s largest
French fry factory produces a wastewater output rich
in potato starch, which must be cleaned and treated
before it’s properly discharged from the site. A covered
anaerobic lagoon (CAL) is the first stage in the site’s
wastewater treatment process and produces biogas
(which has a high methane content) as a by-product. The
biogas qualifies as a renewable fuel.
Large, integrated facilities such as paper mills, steel
mills and chemical plants have long used waste product
streams as alternative fuels. The advance there is making
more intelligent choices about which fuel to use when.
Today, this is done based on availability, demand and
spot prices, but it’s easy to envision a future where
certain products’ carbon footprint specifications will call
for renewable fuel, where others’ might not.
Tata Steel’s plant in Port Talbot, Wales, recently
upgraded the controls on its largest steam boiler using
new energy-management principles, technologies and
services by Emerson Process Management. However,
unlike most run-of-the-mill boiler upgrades, these new
principles and controls are enabling Tata to increase its
energy efficiency, maximize waste fuels, cut emissions
and reduce its reliance on purchased fuels.
The heart of the system is control technology that
calculates and adjusts burners for the actual BTU values
of fuel sources. “Our True BTU combustion control
platform reinvents the current model of combustion
management, which has been around since the 1920s
and is still in practice today,” says Chip Rennie, director
of Emerson’s Industrial Energy Group. “This brings
about nothing short of a reinvention of combustion
models, which will make the prevalent use of low-cost
fuels like biomass achievable and sustainable.”
At Tata Steel, “The boiler upgrades are helping
us make better use of indigenous waste fuels, such
as blast furnace gas, BOS gas and coke oven gas, which
are byproducts of our manufacturing process,” says
Andrew Rees, manager of the mill’s upgrade project.
“The improved controls are part of a comprehensive
energy management project that’s expected
to reduce powerhouse energy consumption by 3%
to 5% and help us achieve our vision of becoming energy
self-sufficient.”
Access a set of resources referenced in and related to this article at
bit.ly/SustainablePlantCombustion.
Paul Studebaker, CMRP, is Editor in Chief of Sustainable Plant and
SustainablePlant.com.
Reprinted with permission from Sustainable Plant, Fall/Winter 2012. On the Web at www.sustainableplant.com.
© PUTMAN. All Rights Reserved. Foster Printing Service: 866-879-9144, www.marketingreprints.com.
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