Back-Pressure Power Recovery
· Natural gas Pressure Recovery Turbines
· Pressure Power Recovery
· Organic Rankine Cycle
· Flare Gas Recovery
· Advanced Cogeneration – Iron & Steel Industry
· Cheng Cycle or Steam Injected Gas Turbine
· Gasturbine Process heater
· Gas Turbine – Drying
· Fuels Cells in the Chlorine-Alkaline Industry
· Black Liquor Gasification
· Residue Gasification – Petroleum Refining
· Residue Gasification – Other Industries
· VOC Control (EPSI)
· Anaerobic Digestion - Agriculture
· Anaerobic Digestion - Municipal Wastewater
·
Anaerobic
Digestion - Industrial Wastewater
Landfill
Gas
District Heating – Back-Pressure Power Recovery
District Heating is an established, mature technology, with several large steam systems
having been installed in the latter half of the nineteenth century. The principle of district
heat systems is that a central plant produces steam or high-pressure hot water for
distribution to commercial and large residential customers. As a result of lower capital
and energy costs, modern district heating systems use high-pressure hot water almost
exclusively. Older systems continue to use steam, and are largely locked into this
distribution method because hot water systems require a new set of distribution pipes, and
cannot run the existing steam powered absorption chillers. A typical steam based system
starts with some form of cogeneration of steam and electricity, with the resulting steam at
50 to 200 pounds per square inch gauge (psig) (0.4-1.4 bar). This steam then flows
through the distribution system to locations up to 3 miles away. When the steam enters
the building, the pressure is reduced to 10-15 psig (70-100 mbar) to minimize the stresses
on the building’s internal system. Once the heat has been extracted, the condensate is
returned to the steam generating plant. Typically, the pressure reduction at the building is
accomplished through a pressure reduction valve (PRV). These valves do not recover the
energy embodied in the pressure drop between 150 (1 bar) and 15 psig (100 mbar). This
energy could be recovered by using a micro scale back-pressure steam turbine. Several
manufactures produce these turbine sets, such as Turbosteam and Dresser-Rand.
Industry – Back-Pressure Power Recovery
Industry consumed at least 3,635 TBtu (3.8 EJ) of fuels in 1998 to generate steam. The
steam is generated at high pressures, but often the pressure is reduced to allow the steam
to be used by different processes. Industrial steam distribution pressures are higher than
district energy applications. Steam is generated at a few bar while pressure is reduced for
distribution (high pressure distribution pressures of 800 psig (5.5 bar) are not
uncommon). This steam then flows through the distribution system within the plant. The
pressure is typically reduced to 50 to 200 psig (0.4 – 1.4 bar) and even as low as 10-15
psig (70-100 mbar) for small space heating applications. Once the heat has been
extracted, the condensate is often returned to the steam generating plant. Typically, the
pressure reduction is accomplished through a pressure reduction valve (PRV). These
valves do not recover the energy embodied in the pressure drop. This energy could be
recovered by using a micro scale back-pressure steam turbine.
Natural gas Pressure Recovery Turbines
While it is necessary to transport natural gas at high pressures, end-users
require gas delivery at only a fraction of main pipeline pressure. Pressure is generally
reduced with a regulator, a valve that controls outlet pressure. Expansion turbines can
replace regulators. These turbines offer a way to capture some of the energy contained in
high-pressure gas by harnessing the energy released as gas expands to low pressure, thus
generating electricity. Expansion turbines use the pressure drop when natural gas from
high-pressure pipelines is decompressed for local networks to generate power. Expansion
turbines (also known as generator loaded expanders) actually serve as a form of power
recovery, utilizing otherwise unused pressure in the natural gas grid. Expansion turbines
are generally installed in parallel with the regulators that traditionally reduce pressure in
gas lines. The drop in pressure in the expansion cycle causes a drop in temperature.
While turbines can be built to withstand cold temperatures, most valve and pipeline
specifications do not allow temperatures below –15°C (5°F). In addition, gas can become
wet at low temperatures, as heavy hydrocarbons in the gas condense. Expansion
necessitates heating the gas just before or after expansion. The heating is generally
performed with either a combined heat and power (CHP) unit, or a nearby source of
waste heat. We focus on locations with sufficient low-temperature waste heat available to
preheat the gas, such as power stations (sites where much natural gas is consumed).
Also, industrial sites such as steel mills have opportunities to recycle energy
economically because of easier electrical connections and heat rejection.
Pressure Power Recovery
Various processes run at elevated pressures, enabling the opportunity for power recovery
from the pressure in the flue gas. The major current application for power recovery in the
petroleum refining industry is the fluid catalytic cracker (FCC). However, power
recovery can also be applied to hydrocrackers (petroleum refining), dual-pressure nitric
acid plants (chemical industry) and pressurized blast furnaces (iron and steel industry).
Gas holders are another simple and cost effective technology. The volume of gas on site
changes rapidly several times per hour. Boilers and steam turbines cannot change
production levels rapidly enough to capture the surges, requiring the gas to be flared.
Gas holders are big bags supported by a large steel cylinder and can absorb the rapid gas
volume changes, then average out boiler fired gas and eliminate flares.
Refining. Power recovery applications for FCC are characterized by high volumes of
high temperature gases at relatively low pressures, while operating continuously over
long periods of time between maintenance stops (> 32,000 hours). The turbine is used to
drive the FCC compressor or for to generate (additional) power (Worrell and Galitsky,
2005). There is wide and long-term experience with power recovery turbines for FCC
applications. Various designs are marketed, and newer designs tend to be more efficient
in power recovery. Many refineries in the US and around the world have installed
recovery turbines. Valero has recently upgraded the turbo expanders at its Houston and
Corpus Christi (Texas) and Wilmington (California) refineries. Valero’s Houston
Refinery replaced an older power recovery turbine to enable increased blower capacity to
allow an expansion of the FCC. At the Houston refinery the rerating of the FCC power
recovery train led to power savings of 22 MW (Valero, 2003), and will export additional
power (up to 4 MW) to the grid.
Power recovery turbines can also be applied at hydrocrackers. Power can be recovered
from the pressure difference between the reactor and fractionation stages of the process.
In 1993 the Total refinery in Vlissingen, The Netherlands, installed a 910 kW power
recovery turbine to replace the throttle at its hydrocracker (45,653 barrel/calendar day).
The cracker operates at 160 bar. The power recovery turbine produces about 7.3
GWh/year.
Based on the installation at Valero we estimate the total potential for power export in all
U.S. refineries at 170 MW. Our analysis indicates that 50% of the potential FCC capacity
can install power recovery turbines cost-effectively. This will produce 722 GWh of
power annually (8500 hours/year). Based on the installed hydrocracker capacity of
1.47·106 barrels/day, we estimate the additional potential for power recovery for
hydrocrackers at 29 MW, producing 247 GWh/year.
Chemicals. Nitric acid is produced through the controlled combustion of ammonia. The
modern process variant is the dual-pressure process, allowing power recovery between
the two reactors. Also, the single-stage high-pressure process allows for power recovery.
The recovered power can be used to power the compressors or for power generation. The
10
U.S. chemical industry produces about 7 million metric tons (Mt) of nitric acid per year
at multiple locations. Expanders can also be used in the production of ethylene oxide. The
expanders are often used to drive the compressor. Hence, we assume that no additional
power is generated, although the expander may reduce the need for a steam turbine or
electrically driven compressor, potentially reducing electricity use onsite of the chemical
plant.
Iron & Steel. Top pressure recovery turbines are used to recover the pressure in the blast
furnace.1 Although the pressure difference is low, the large gas volumes make the recovery
economically feasible. The pressure difference is used to produce 15-40 kWh/t hot metal
(Stelco, 1993). Turbines are installed at blast furnaces worldwide, especially in areas where
electricity prices are relatively high (e.g. Western Europe, Japan). The standard turbine has
a wet gas cleanup system. The top gas pressure in the U.S. is generally too low for
economic power recovery. A few large blast furnaces (representing about 11 Mt of
production) have sufficiently high pressure (Worrell et al., 1999). We estimate the technical
potential at 325 GWh, or about 40 MW capacity.
Organic Rankine Cycle
Organic Rankine Cycle (ORC) is the same process as a steam turbine system with the
driving fluid being an organic fluid instead of steam. The standard Rankine Cycle
requires superheated steam above 600°C. ORC can work with lower temperature fluids in
the range of 100°C to 400°C. Lower temperature operation uses lower quality heat, often
residual, that would otherwise be wasted to generate electricity. The efficiency is around
10-20% depending on the temperature of the fluid. Fluids used in ORC are CFCs, Freon,
isopentane and ammonia. The range for heat recovery capacities of ORC turbines is 400
to 1500 kW. A proposed large ORC project in The Netherlands had a simple payback of
6.5 years and capital costs of about $950 per kW.
Flare Gas Recovery
In oil and gas production methane-containing gases are vented and flared throughout the
production cycle. In natural gas production methane is vented and leaking from storage
facilities and pipelines. In oil production, methane is vented from oil tanks and may leak
from refineries. Furthermore, oil refineries flare methane and hydrocarbon containing
gases. Flares are used for both background and upset (emergency) use. In all cases the
methane can be recovered and used for local power production. The recovery and use for
power generation will not only offset power generation but also reduce methane
emissions, a potent greenhouse gas, leading to double benefits. Companies like BP have
shown that it is possible to reduce the leaks and recover methane from oil and gas
production facilities at a profit
Advanced Cogeneration – Iron & Steel Industry
All plants and sites that need electricity and heat (i.e. steam) in the steel industry are
excellent candidates for cogeneration. Conventional cogeneration uses a steam boiler and
steam turbine (back pressure turbine) to generate electricity. Steam systems generally
have a low efficiency and high investment costs. Current steam turbine systems use the
waste fuels, e.g. at Inland Steel and US Steel Gary Works. Modern cogeneration units are
gas turbine based, using either a simple cycle system (gas turbine with waste heat
recovery boiler), or a combined cycle integrating a gas turbine with a steam cycle for
larger systems.
Integrated steel plants produce significant levels of off-gases (coke oven gas, blast
furnace gas, and basic oxygen furnace-gas). Specially adapted turbines can burn these
low calorific value gases at electrical generation efficiencies of 45% (LHV) but internal
compressor loads reduce these efficiencies to 33% (Mitsubishi, 1993). Mitsubishi Heavy
Industries has developed such a turbine and it is now used in several integrated steel
plants around the world, e.g. Kawasaki Chiba Works (Japan) (Takano et al., 1989) and
Corus (IJmuiden, The Netherlands) (Anon., 1997). These systems have low NOx
emissions (20 ppm) (Mitsubishi, 1993).
Cheng Cycle or Steam Injected Gas Turbine
This type of turbine uses the exhaust heat from a combustion turbine to turn water into
high pressure steam. This steam is then fed back into the combustion chamber to mix
with the combustion gas. This technology is also known as a steam injected gas turbine
(STIG). The advantages of this system are (Willis and Scott 2000):
· Added mass flow of steam through turbine increases power by about 33%;
· Simplifies the machinery involved by eliminating the additional turbine and
equipment used in combined cycle gas turbine;
· Steam is cool compared to combustion gasses helping to cool the turbine interior;
· Reaches full output more quickly than combined-cycle unit;
· Applicable for DER applications due to smaller equipment size.
Additional advantages are that the amounts of power and thermal energy produced by a
turbine can be adjusted to meet current power and thermal energy (steam) loads. If steam
loads are reduced then the steam can be used for power generation, increasing output and
efficiency (Ganapathy 2003).
Drawbacks include the additional complexity of the turbine’s design. Additional
attention to the details of the turbine’s design and materials are needed during the design
phase. This may result in a higher capital cost for the turbine compared to traditional
models.
Combined cycles (combining a gas turbine and a back-pressure steam turbine) offer
flexibility for power and steam production at larger sites, and potentially at smaller sites
as well. STIG can absorb excess steam, e.g. due to seasonal reduced heating needs, to
boost power production by injecting the steam in the turbine. The size of typical STIGs
starts around 5 MWe. STIGs are found in various industries and applications, especially
in Japan and Europe, as well as in the U.S. International Power Technology (CA), for
example, installed a STIG at Sunkist Growers in Ontario (CA) in 1985.
Gasturbine Process heater
Modern turbine designs allow higher inlet and outlet temperatures. The makes it possible
to use the flue gas of the turbine to heat a reactor in the chemical and petroleum refining
industries. One option is the so-called “re-powering” option. In this option, the furnace is
not modified, but the combustion air fans in the furnace are replaced by a gas turbine.
The exhaust gases still contain a considerable amount of oxygen, and can thus be used as
combustion air for the furnaces. The gas turbine can deliver up to 20% of the furnace
heat. The re-powering option is used by a few plants around the world. Another option,
with a larger CHP potential and associated energy savings, is “high-temperature CHP.”
In this case, the flue gases of a CHP plant are used to heat the input of a furnace. Zollar
(2002) discusses various applications in the chemical and refinery industries. The study
found a total potential of 44 GW. The major candidate processes are atmospheric
distillation, coking and hydrotreating in petroleum refineries and ethylene and ammonia
manufacture in the chemical industry. The simple payback period is estimated at 3 to 5
years, depending on the electricity costs. The additional investments compared to a
traditional furnace were estimated at 630 $/kW (1997) (Worrell et al., 1997; Onsite,
2000). Excessive costs for adaptation of an existing furnace are additional to the given
investment costs. This cycle has nearly 100% efficiency since the fuel is either converted
into power or waste heat, all of which is used in the boiler. This greatly influences power
generation costs and reduces sensitivity to fuel price
Gas Turbine – Drying
CHP Integration allows increased use of CHP in industry by using the heat in more
efficient ways. This can be done by using the heat as a process input for drying. The
fluegas of a turbine can often be used directly in a drier. This option has been used
successfully for the drying of minerals as well as food products. Although NOx emissions
of gas turbines vary widely, tests in The Netherlands have shown that, depending on the
type of gas turbine selected, the flue gases do not negatively affect the drying air and
product quality(Buijze, 1998). To allow continuous operation, bypass of the gas turbines
makes it possible to maintain the turbine and run the drying process (Buijze, 1998). A
cement plant in Rozenburg, The Netherlands, uses a standard industrial gas turbine to
generate power and to dry the blast furnace slags used in cement making. The Kambalda
nickel mine in Australia uses four gas turbines of 42 MW each to dry nickel concentrate.
The mine currently produces around 300,000 tons per year, saving 0.9 GJ/ton (0.77
MBtu/short ton) of concentrate. Another project in The Netherlands demonstrated the use
of the flue gases from a gas turbine to dry protein rich cattle feed by-product. The excess
flue gas is mixed with air and used directly for the drying process.
Fuels Cells in the Chlorine-Alkaline Industry
Fuel cells generate direct current electricity and heat by combining fuel and oxygen in an
electrochemical reaction. This technology avoids the intermediate combustion step and
boiling water associated with Rankine cycle technologies, or efficiency losses associated
with gas turbine technologies. Fuel to electricity conversion efficiencies can theoretically
reach 80-83% for low temperature fuel cell stacks and 73-78% for high temperature
stacks. In practice, efficiencies of 50-60% are achieved with hydrogen fuel cells while
efficiencies of 42-65% are achievable with natural gas as a fuel (Martin et al., 2000). The
main fuel cell types for industrial CHP applications are phosphoric acid (PAFC), molten
carbonate (MCFC) and solid oxide (SOFC). Proton exchange membrane (PEM) fuel cells
are less suitable for cogeneration as they only produce hot water as byproduct. PAFC
efficiencies are limited and the corrosive nature of the process reduces the economic
attractiveness of the technology. Hence, MCFC and SOFC offer the most potential for
industrial applications.
Black Liquor Gasification
In standard integrated Kraft mills, the spent liquor produced from de-lignifying wood
chips (called black liquor) is normally burned in a large recovery boiler in which the
black liquor combustion is used to recover the chemicals used in the delignification
process. Because of the relatively high water content of the black liquor fuel, the
efficiency of existing recovery boilers is limited. Gasification allows not only the
efficient use of black liquor, but also of other biomass fuels such as bark and felling rests
to generate a synthesis gas that after cleaning is combusted in a gas turbine or combined
cycle with a high electrical efficiency. This increases the electricity production within the
pulp mill. The technology is called black liquor gasification-combined cycle (BLGCC).
The black liquor gasifier technology will produce a surplus of energy from the pulp
process and opens the possibility to generate several different energy products for
external use, i.e. electricity, heat and fuels. Gasifiers can use air or pure oxygen to
provide the oxygen needed for the chemical conversions. We assume a (more expensive)
oxygen-blown gasifier. The richer synthesis gas produced in an oxygen-blown gasifier
allows easier combustion in a gas turbine. Furthermore, the process provides a natural
separation of sulfur from sodium is provided that allows for advanced pulping, making it
possible to enhance pulp productivity
Residue Gasification – Petroleum Refining
Because of the growing demand for lighter products and increased use of conversion
processes to process a ‘heavier’ crude, refineries will have to manage an increasing
stream of heavy bottoms and residues. Gasification of the heavy fractions and coke to
produce synthesis gas can help to efficiently remove these by-products. The state-of-theart
gasification processes combine the heavy by-products with oxygen at high
temperature in an entrained bed gasifier. The synthesis gas can be used as feedstock for
chemical processes, hydrogen production and generation of power in an Integrated
Gasifier Combined Cycle (IGCC). Entrained bed IGCC technology was originally
developed for refinery applications, but is also used for the gasification of coal. Hence,
the major gasification technology developers were oil companies like Shell and Texaco.
The technology was first applied by European refineries due to the characteristics of the
operations in Europe (e.g., coke was often used onsite). IGCC is used by the Shell
refinery in Pernis (The Netherlands) to treat residues from the hydrocracker and other
residues to generate 110 MWe of power and 285 metric tons of hydrogen for the refinery.
Residue Gasification – Other Industries
Various industries produce low-grade fuels as a by-product of the production process.
Currently, these low-grade fuels are combusted in boilers to generate steam or heat, or
disposed of through landfilling. Often, this results in relatively less efficient use.
Gasification offers opportunities to increase the efficiency of using low-grade fuels. In
gasification, the hydrocarbon feedstock is heated in an environment with limited oxygen.
The hydrocarbons react to form synthesis gas, a mixture of mainly carbon monoxide and
hydrogen. The synthesis gas can be used in more efficient applications like gas turbinebased
power generation or as a chemical feedstock. The technology not only allows the
efficient use of by-products and wastes, it also allows low-cost gas cleanup (when
compared to flue gas treatment). Various industries are pursuing the development of
gasification technology, and are at different stages of development. Furthermore,
gasification technology can also lead to more efficient and cleaner use of coal, biomass
and wastes for power generation. Besides the pulp and paper and petroleum refining
industries other industries with sufficient production of by-products that can be gasified
are found in the food industry (e.g. bagasse in the sugar industry, nutshells, rice husk).
The technology can also be used to process municipal solid waste with a higher
efficiency than offered by incineration
VOC Control (EPSI)
In many plants VOCs are generated. VOCs contribute to ozone formation and VOC
controls are installed by virtually at any source of VOC emissions. In small-scale systems
carbon filters can be used to capture VOCs. In large-scale systems, generally regenerative
thermal oxidizers (RTO) are used. In a RTO the VOC-containing flue gas (e.g. from a
paint booth) is mixed with natural gas to a combustible mixture. The mixture is
combusted in the RTO and the VOCs are destroyed.
Environmental and Power Systems International (EPSI) has developed an alternative
pollution control technology for handling VOC emissions. The technology has the ability
to generate electricity and useful thermal heat with a gas turbine, using the VOCcontaining
gases enriched with natural gas. The EPSI system is an alternative VOC
abatement technology to RTOs with the following advantages over standard RTOs (GTI
2003):
· Shorter initial cold start-up time (5 minutes versus 1 to 8 hours);
· Recoverable heat for use by end-user (RTOs use their heat in the VOC abatement
process);
· Electrical power generation;
· Higher combustion temperature (which in combination with high residence time,
assures more complete destruction of VOC);
· Smaller equipment footprint;
· Lower major overhaul cost.
Anaerobic Digestion - Agriculture
Biogas systems are a waste management technique that can provide multiple benefits:
· removal of manure waste;
· reduction of odor;
· reducing disposal truck traffic and costs;
· reduction in spreading disposal costs;
· pathogen control and destruction, and;
· protection of groundwater.
Furthermore biogas digester systems can generate electricity and thermal energy to serve
heating and cooling needs while providing financial profits. The byproducts of the
digester system also include high-quality compost that can be used for crop fertilizer.
Biogas systems are most suitable for farms that handle a large amount of manure as a
liquid slurry or semi-solid with little or no bedding added. The type of digester should be
matched to the type, design, and manure characteristics of the farm. There are five types
of manure collection systems characterized by the solids content: raw, liquid, slurry,
semi-solid, or solid (often left in pasture and not suitable). There are three types of
digester systems: covered lagoon (used to treat and produce biogas from liquid manure),
complete mix digester (heated engineered tanks for scraped and flushed manure), and
plug flow (treat scraped dairy manure in 11% to 13% solids range). Swine manure does
not have enough fiber to treat in plug flow digester. The products of anaerobic digestion
are biogas and effluent. The effluent needs to be stored in a suitable sized tank.
Recovered gas is 60-80% methane with heating value of 22-30 MJ (600-800 Btu/ft3)
(AgSTAR Handbook). This gas can be used to generate electricity or serve heating and
cooling loads.
Anaerobic Digestion - Municipal Wastewater
Wastewater treatment plants release biogas through the decomposition of organic matter.
The biogas (mostly methane) can be captured and used to provide energy services either
by direct heating or through the generation of electricity. Anaerobic digestion destroys
pathogens and this method is used to generate biogas in many treatment plants. Typically
the biogas is burned to produce heat to maintain the temperature of the digester process.
Excess gas is then flared (Oregon State Energy Office 2004). This process destroys
pathogens resulting in cleaner water and more benign solids.
Anaerobic Digestion - Industrial Wastewater
Industrial wastewater is typically treated by aerobic systems that remove contaminants
prior to discharging the water. These aerobic systems have a number of disadvantages
including high electricity use by the aeration blowers, production of large amounts of
sludge, and reduction of dissolved oxygen in the wastewater which is detrimental to fish
and other aquatic life. The decomposition of organic materials without oxygen results in
the production of carbon dioxide and methane from the presence of anaerobic bacteria.
This gas is called biogas and contains 50% methane (CH4) and a powerful greenhouse
gas (21 times more potent of a greenhouse gas than CO2). This process is called
anaerobic digestion and takes place in an airtight chamber called a digester. Biogas
systems are a waste management technique with numerous benefits including: lower
water treatment cost, reduction in odor, reduction in material handling and wastewater
treatment costs, and protection of local environmental groundwater and other resources.
In addition the biogas can be used as a supplemental energy source for thermal energy
loads and the generation of electricity.
Any type of biological waste from plant or animals is a potential source of biogas. Some
example industries include: pharmaceutical fermentation, pulp and paper wastewaters,
fuel ethanol facility, brewery and yeast fermentation wastewater, coal conversion
wastewater. Anaerobic digester biogas is comprised of methane (50%-80%), carbon
dioxide (20%-50%), and trace levels of other gases such as hydrogen, carbon monoxide,
nitrogen, oxygen, and hydrogen sulfide. The most widely used technology for anaerobic
wastewater treatment is the Upflow Anaerobic Sludge Blanket (UASB) reactor, which
was developed in 1980 in The Netherlands. Industrial wastewater is directed up through
the UASB reactor, passing through a “blanket” that traps the sludge. Anaerobic bacteria
break down the organic compounds in the sludge, producing methane in the process. This
type of anaerobic wastewater treatment is currently used predominantly in the paper and
food industries, but some industries such as chemical and pharmaceuticals have also used
this technology and its use is growing for municipal wastewater treatment.
Landfill Gas
The decomposition of organic materials without oxygen in landfills results in the
production of carbon dioxide and methane from the presence of anaerobic bacteria. In a
non-controlled landfill, this would generate methane, a powerful greenhouse gas.
Therefore, the landfill gas is often collected and flared, in which case the energy is not
utilized. However, the gas can also be used for energy generation. The more common
uses are: fuel gas for industrial boilers and electricity generation.
At many landfills, however, the gas is not recovered or flared. There are numerous
barriers to economically utilizing landfill gas (EIA 1996): fluctuating gas prices,
technology prices and performance risks, transportation costs of energy (when
transported), air permits and changing regulations, as well as obtaining power contracts
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