Pressurized Fluidized Bed Combined Cycle (PFBC) power generation has been proven in 20 years of robust, trouble-free operation around the world.  Since the first commercial PFBC plant went on line, six widely separated installations have produced efficient, fuel-flexible power for a combined total of more than 250,000 hours of operation.

Abundant fuels

PFBC technology can run on a variety of fuels, including waste coal, coal slurry, or even biomass, producing energy 10 to 25 percent more efficiently than any other solid-fuel power generation process.

How A PFBC System Works

A.  In pressurized fluidized bed combustion, jets of air support a bed of fuel, mixed with sorbent  (dolomite or limestone), as it burns.  Water flowing through the tube bundle that is immersed in the hot, turbulent bed turns to steam, which drives the steam turbine.  Hot flue gases are cleaned, then routed to the gas turbine.  The steam turbine supplies about 80 percent of the system’s electrical output, while the gas turbine provides the remaining 20 percent.

B.  The power plant operator can use either dry coal or slurry. With dry fuel, high-pressure air moves crushed coal and sorbent into the combustor.  With slurry, a high-pressure pump supplies the combustor with wet coal and sorbent.  Calcium in the sorbent captures sulfur released by oxidation, minimizing SO₂ formation.

C.  Combustion air enters the low-pressure compressor, passes through the intercooler, then flows to the high-pressure compressor, which sends it into the pressure vessel.  The cyclone ash cooler preheats the air before it fluidizes the bed.

D.  The fuel in the fluidized bed travels at about 3 ft/sec. Keeping the oxidation temperature at 1562^◦ F ensures high carbon conversion and optimal sulfur capture.

E.  Exhaust gas and suspended ash leave the bed through the freeboard.  Multi-stream two-stage cyclones remove ash particles before the gas enters the gas turbine, which drives the generator and compressors.

F.  Gas-turbine exhaust travels through the economizer and cools to about 285^◦F^. A baghouse filter catches residual fine dust before the exhaust goes up the stacker or to further scrubbing for CO₂ capture.

G.  This design separates fly ash at the baghouse and withdraws bed ash and cyclone ash through a lock hopper system in the bed bottom.

H.  Preheated by the economizer, feedwater enters the pressure vessel, is further heated as it passes through the combustor walls, and then travels through the tube bundle, which includes the evaporator and superheaters.  The resulting steam is sent to a conventional steam turbine.

Fuel and Sorbent

The PFBC unit is designed based on coal as the performance fuel.  Other solid fuels, such as waste coal, petroleum coke, lignite, and a wide range of bituminous and sub-bituminous coals, may also be burned with only slight effects on plant performance.

The sorbent used for the PFBC can be dolomite or limestone.

Description of PFBC Island Systems

In this PFBC process, crushed fuel and a sorbent (limestone or dolomite) are continuously injected into the fluidized-bed combustion chamber contained within a pressure vessel.  Air from the compressor supplies combustion air and fluidizes the bed.  The water-cooled surface of the bed enclosure and boiler tubes submerged in the fluidized bed are used to generate steam, which drives a conventional steam turbine generator. High-pressure flue gases from the combustion process pass through high-efficiency cyclones, which remove nearly all of the particulate.  This cleaned, high-pressure gas passes through a heat recovery generator section for additional steam generation to the steam cycle.

The patented E_SCO₂ interface to the Benfield process cools down the high-pressure flue gas and cleans it from remaining dust particles through a filter before it continues on to the Benfield Potassium Carbonate CO₂ capture process.  The separated CO₂ is led to a compressor for injection into deep sequestration or utilized for enhanced oil recovery and the pressurized cleaned flue gas is led through a gas expander to the stack.  The gas expander is partially driving the variable speed combustion air compressor.

Air from the compressor side of the gas expander is supplied to the combustor vessel.  The air in the vessel flows through the cyclone ash coolers before it enters the boiler through the lower half of the combustor.  The boiler enclosure contains the bed, the in-bed heat transfer surface, and the freeboard above the bed.  The boiler feedwater is preheated through feedwaters located outside the pressure vessel.  Steam generated in the boiler is used to power the steam turbines.

A design feature of this PFBC unit is the use of modularized components.  Modularity tends to reduce project costs and site erection span time.  The combustor internal equipment, such as platforms, boiler, cyclones, and bed reinjection vessels, are prefabricated and shop-assembled into modules for field installation into the pressure vessel to the maximum extent practicable.  Other components, such as instrumentation and insulation, are partially shop-assembled, with the remaining assembly performed at the site.  Service openings and manholes are provided for access during inspection, repair or replacement of equipment that must be carried out during normal maintenance.

P200 Pressure Vessel

The P200 combustor assembly consists of the pressure vessel together with the installed internals.  The main internal systems are described separately.  The function of the combustor assembly is to provide the main pressure containment for the boiler, cyclones, bed reinjection, ash coolers, and bed preheating systems.  The combustor assembly also prevents heat losses from the process to the environment, facilitates a good arrangement, and provides support for the internals.

The PFBC pressure vessel is fabricated of 2.875 inch thick SA-533 Gr. B steel plate, and is 36 feet outside diameter and 112 feet overall height.  The vessel is designed, fabricated, and stamped in accordance with the ASME Boiler and Pressure Vessel Code, Section VIII, Division 2.  The vessel has a design pressure of 189 psig and temperature of 700^oF.

Fuel Preparation (Paste)

The fuel preparation system crushed fuel to the required size distribution, mixes it with water for paste production, and delivers the prepared paste to the paste storage tanks.

The fuel is first crushed and Tramp iron is removed on a vibratory feeder preceding the crusher.  The crushed fuel is then conveyed to a screen separator and a set percentage of the crushed fuel is sent to the paste mixer.  The remaining flow of fuel particles is routed to a hammer mill and recrushed.  Recrushing of the fuel is an important step in assuring an adequate fines content in the paste.  If the fines content is too low, the fuel can settle in the paste and pluggage in the pumps or fuel line can result.  This recrushed fuel is then sent to another screen separator and all particles less than ¼ inch are sent to the paste mixer.  Large particles separated in this state are rejected to a reject pile.

The paste mixer is a continuous rotating paddle type.  Water is added to the mixer in an amount required to produce a pumpable paste of 25% total moisture content.

The paste tanks holding the prepared paste contain slow, rotating paddle agitators to prevent the fuel particles from settling out of the paste mixture.  At the bottom of the paste tanks are three outlets through which the prepared fuel is sent to the fuel injection system.  Depending on the amount of sorbent, it will be mixed into the paste.

Boiler

The boiler is a once-through design consisting of a water-cooled membrane wall enclosure and in-bed heat transfer surface.  The water-cooled enclosure contains the combustion process, within a specified gas path geometry, and is designed to withstand the expected pressure differential across the membrane tube wall.  The enclosure is sized to provide (1) the bed area set by gas velocity and flow, (2) a 14.75 foot (4.5 meter) deep bed to achieve the desired residence time affecting combustion efficiency and sulfur capture and (3) sufficient freeboard height to provide residence and allow maintenance of the in-bed platens without requiring removal from the enclosure.  The tube bundle inside the boiler is completely submerged in the fluidized bed at full load.  The in-bed surface is designed in such a manner to evaporate, superheat, and reheat the steam at a required flow, temperature, and pressure for delivery to the steam turbine.

A once-through design requires a minimum boiler flow at low load to protect the boiler circuits.  A boiler circulation system, consisting of a vertical steam separator and boiler circulating pumps, is provided for this purpose.  The boiler circulation system is also used for water clean-up, prior to firing.

Load reduction is accomplished by lowering the bed level and lowering fuel input.  By lowering the bed level, less steam is produced and, because some of the tube bundle is now above the bed level, the gas temperature is reduced.  Bed level is rapidly raised and lowered by using reinjection vessels.  When a load reduction is called for, bed material is withdrawn and stored in the re-injection vessels.  If load is increased, the stored bed material is re-injected back into the bed.  A load change rate of 4% per minute is possible with this system.  More gradual changes are accomplished by changes in fuel feed and ash withdrawal rates.

Fuel Injection System (Paste)

The paste is drawn from the storage tanks by 18 hydraulic piston pumps located directly beneath the paste storage tanks.  Three pumps feed from each paste tank.  Each pump delivers paste to two injection lines for a total of 36 injection points in the bed.

Upon start-up, the pumps begin pumping fuel from the paste tanks.  A three-way valve located near the pressure vessel wall in each fuel line diverts the fuel flow back into the paste tank.  In this way the lines are full up to the combustor vessel and ready for the command to begin fuel injection.  When the bed stabilizes to a temperature high enough to achieve coal ignition, the three-way valves are positioned to inject fuel into the fluidized bed.  The fuel is injected into the bed by water-cooled fuel injection nozzles.

The water cooling is necessary to prevent the paste from drying out in the line and thus plugging the line before entry into the bed.  Paste lump size is controlled by injecting high-pressure splitting air near the fuel nozzle outlet.  By controlling the splitting air flow, the size of the paste lump can be controlled for optimum bed performance.

Sorbent Injection System

In case a dry feed of sorbent would be required, the sorbent injection system is comprised of lock hopper style pneumatic conveying systems.  For this reference plant design, granular limestone is continuously fed to the fluidized bed by four separate lock hopper systems.  Each system operates independently of the other and feeds two injection lines for a total of eight injection points into the fluidized bed.

Each lock hopper receives sorbent material from independent dedicated storage vessel outlets, isolated by automated inlet isolation valves, designed for sever service.  Both shut-off material flow and seal against the lock hopper internal pressure.  Upstream of the automated inlet isolation valves are manual slide gates for maintenance isolation.

Each lock hopper/feed assembly consist of a fill tank (upper chamber), feed tank (lower chamber), rotary feeder, and the appropriate isolation valves.  The fill tank and feed tank have a ring header around the hopper cone to inject fluidizing air into the hopper.  The fluidizing air prevents material buildup that can cause pluggage and ensures a steady flow of sorbent to the feeders.  During operation the fill tank is depressurized, opened to the storage vessel for filling, sealed, and pressurized to the feed tank pressure.  Upon low level in the feed tank, the isolation valve between the two vessels is opened to recharge the feed tank with solids.  This process allows the feed tank to continuously operate at the required transport pressure during the refilling process.  Since the feed tank is always equalized with the conveying line pressure and not depressurized, it can continuously supply sorbent material to the pneumatic transport lines for subsequent transport to the fluidized bed.  A fee tank equalization with the conveying line pressure is required to limit pressure differentials across the feeder.

Bed Ash Removal System

The bed ash is removed through the boiler bottom by gravity to L-valves, where it is transported to a complement of 12 cycling lock hoppers.  When a lock hopper is full, the air to the associated L-valve is turned off, an isolation valve to the lock hopper is closed, and the hopper is depressurized and emptied to a conveyor for transport to storage.

Cooling of the ash takes place in the boiler bottom hopper before entry into the L-valve.  Cooling air is injected into the hopper countercurrent to the downward flow of the ash.  The velocity of the air is kept below the fluidization velocity of the bed material so that the ash can maintain its downward flow direction.  This direct contact between the ash and air cools the ash to approximately 350^o F.  The heated air flows up into the fluidized bed where it is mixed with the combustion air in the bed.

Bed Ash Re-Injection System

Load changes are accomplished by raising or lowering the bed level.  At maximum load, the tube bundle is completely submersed in the fluidized bed.  At this condition, the maximum steam production is obtained, as well as the maximum gas temperature and flow to the gas turbine.  When the bed level is lowered, the steam production is also lowered, and because there is now part of the tube bundle exposed in the gas stream, the gas temperature is also lowered.

The ability to raise or lower bed level is accomplished by storing or injecting hot bed material.  Re-injection vessels are located inside the combustor.  These vessels are internally lined to minimize heat loss from stored material.  When a load reduction is called for, the re-injection vessels depressurize, allowing bed material to flow upward through a transport line into the vessel.

The level of material in the vessels is monitored by change in weight of the vessels detected by load cells.  The re-injection vessel hopper is open to an L-valve.  When a load increase is called for, high-pressure nitrogen is pulsed into the L-valve to begin sending material back into the fluidized bed.  A load changing rate of 4% per minute can be obtained with this system.

Ash Removal System (Example)

The fly ash is collected in a baghouse and conveyed to the fly ash storage silo.  A pneumatic transport system using low-pressure air from a blower provides the transport mechanism for the fly ash.  Fly ash is discharged through a wet unloader, which conditions the fly ash and conveys it through a telescopic unloading chute into a truck for disposal.

The cyclone ash is conveyed pneumatically from the two storage hoppers to the storage silo.  The cyclone ash is discharged by gravity to a truck for transport offsite and disposal.

Steam Turbine Generator (Example)
(Could Vary Depending on Application)

The turbine consists of an HP section, IP section, and one double flow LP section, all connected to the generator by a common shaft.  Main steam from the boiler passes through the stop valves and control valves and enters the turbine at 2600 psig/1050^oF.

The steam initially enters the turbine near the middle of the high-pressure span, flows through the turbine, and returns to the boiler for reheating.  The reheat steam flows through the reheat stop valves and intercept valves and enters the IP section at 585 psig/1050^oF.  After passing through the IP section, the steam enters a crossover pipe, which transports the steam to the LP section.  The steam divides into two paths and flows through the LP sections exhausting downward into the condenser.

Turbine bearings are lubricated by a closed-loop, water-cooled, pressurized oil system.  The oil is contained in a reservoir located below the turbine floor.  During start-up or unit trip, the oil is pumped by an emergency oil pump mounted on the reservoir.  When the turbine reaches 95% of synchronous speed, oil is pumped by the main pump mounted on the turbine shaft.  The oil flows through water-cooled heat exchangers prior to entering the bearings.  The oil then flows through the bearings and returns by gravity to the lube oil reservoir.

Turbine shafts are sealed against air in-leakage of steam blowout using a labyrinth gland arrangement connected to a low-pressure steam seal system.  During start-up, seal steam is provided from the main steam line.  As the unit increases load, HP turbine gland leakage provides the seal steam.  Pressure regulating valves control the gland leader pressure and dump any excess steam to the condenser.  A steam packing exhauster maintains a vacuum at the outer gland seals to prevent leakage of steam into the turbine room.  Any steam collected is condensed in the packing exhauster and returned to the condensate system.

Condensate

The function of the condensate system is to pump condensate from the condenser hotwell, through the gland steam condenser, and the LP feedwater heaters to the deaerator.

Each system consists of one main condenser; three 50% capacity, motor-driven vertical condensate pumps; one gland steam condenser; three LP heaters; and one deaerator with storage tank.

Condensate is delivered to a common discharge header through two separate pump discharge lines, each with a check valve and a gate valve.  A common minimum flow recirculation line discharging to the condenser is provided to maintain minimum flow requirements for the gland steam condenser and the condensate pumps.

Each LP feedwater heater is provided with inlet/outlet isolation valves and a full capacity bypass.  LP feedwater heater drains cascade down to the next lowest extraction pressure heater and finally discharge into the condenser.  Normal drain levels in the heaters are controlled by pneumatic level control valves.  High heater level dump lines discharging to the condenser are provided for each heater for turbine water induction protection.  Dump line flow is controlled by pneumatic level control valves.

Feedwater

The function of the feedwater system is to pump feedwater from the deaerator storage tank to the boiler economizer.  Two 50% capacity motor-driven boiler feed pumps are provided to pump feedwater through the HP feedwater heaters.  The pumps are provided with inlet and outlet isolation valves, outlet check valves, and individual minimum flow recirculation lines discharging back to the deaerator storage tank.  The recirculation flow is controlled by pneumatic flow control valves.  In addition, the suctions of the boiler feed pumps are equipped with start-up strainers, which are utilized during initial start-up and following major outages or system maintenance.

Each HP feedwater heater is provided with inlet/outlet isolation valves and a full capacity bypass.  Feedwater heater drains cascade down to the next lowest extraction pressure heater and finally discharge into the deaerator.  Normal drain level in the heaters is controlled by pneumatic level control valves.  High heater level dump lines discharging to the condenser are provided for each heater for turbine water induction protection.  Dump line flow is controlled by pneumatic level control valves.

Main and Reheat Steam (Example)

The function of the main steam system is to convey main steam from the boiler superheater outlet to the high-pressure turbine stop valves.  The function of the reheat system is to convey steam from the HP turbine exhaust to the boiler reheater and from the boiler reheater outlet to the turbine reheat stop valves.

Main steam at approximately 2700 psig/1054^oF exits the HP turbine, flows through a motor-operated isolation gate valve and a flow control valve, and enters the boiler reheater.  Hot reheat steam at approximately 600 psig/1054^oF exits the PFBC boiler reheater through a motor-operated gate valve and is routed to the steam turbine reheat valve chest.  A branch line from the cold reheat steam line is routed to feedwater heater.

Two Proved Technologies

PFBC CO2 Capture Process

Benfield Process Background

The Hot Potassium Carbonate Process (HPC) originated from research work done by the US Bureau of Mines (USBM), between about 1940 and 1960.  The original justification was to determine how to convert coal to gaseous and/or liquid fuels.  If the coal could be gasified, followed by the removal of CO₂ and sulfur compounds, then the result would be a basic hydrocarbon gas.  This treated gas could be used as a chemical plant feedstock, a substitute for natural gas, or processed further to produce synthetic gasoline.  While gasifying the coal is relatively easy, treating the resulting hot gas is more difficult.  Scrubbing this gas while hot is more desirable than cooling it down because behavior hydrocarbons and tar-like compounds can condense at cooler temperatures.  The solvents available at that time for acid gas removal were water, MEA, and some other amines.  Because of the natural volatility of most amine chemicals, most require operating temperatures below ~125^oF (50C).  Water could be used to remove CO₂, but it is very inefficient and does not give an acceptable purity.  Caustic solutions, either NaOH or KOH could remove the acid gases very effectively, but could not be regenerated.  Using a solution of KOH to first pick up CO₂ would generate potassium carbonate in solution, which could absorb still more acid gases.  Thus, the “Hot Potassium Carbonate” process was born.

Because the technology was developed by the U.S. government, the basic process remained the property of the U.S. government.  Several U.S. citizens further developed the technology and started a business of assisting industry to use the technology.  One early result was a partnership formed by Benson, Field, and Epes, former employees of USBM.  This partnership was started to help design some 150 units for use in producing Town Gas from coal at locations throughout Europe, mostly in the United Kingdom before the advent of North Sea gas.  Eventually this partnership found patentable improvements to the technology and started designing and licensing their improved versions and this became known as The Benfield^TM Process.  The improvements and process developments included the addition of small amounts of amines/other proprietary additives to the carbonate solution to increase the rate of reaction with CO₂, and using corrosive inhibitors to permit the use of carbon steel for construction of much of the unit.

Benfield Advantages

The BenfieldTM Process is one of the most widely used solvent based aid gas removal processes available today.  Over 750 units have been licensed, and many of these units have been in operation for over 30 years, showing the reliability of the technology.

Compared with other available CO₂ removal process technologies, the BenfieldTM Process gives a balance between economics of capital investment in a new unit, and operating costs in that the energy consumption to regenerate the solvent can be tailored with the LoHeatTM version to suit almost any available energy form and availability.  One further advantage is that because the CO₂ is removed by direct chemical reaction, there is almost complete separation of the product gas (to levels of about 0.1% CO₂) and full recovery of the CO₂ at concentrations of typically 99%, or higher.  Many non-solvent based purification units cannot yield both a good quality product gas and a good quality CO₂ byproduct gas.  This may become even more important in the future, as governments around the world address the problems of global warming, acid rain, and the need for CO₂ sequestration.

Some general comparisons can be made between BenfieldTM HPC and other “wet-scrub” process systems for removal of CO₂.  For example, if MEA is compared with HPC, the strongly reactive solvent MEA will reduce the CO₂ of a process gas lower than HPC while requiring a shorter contact time and smaller absorber (which runs cooler).  However, a larger lean/rich solution-to-solution heat exchanger and a higher reboiler heat duty are required to break the chemical bond and regenerate the solvent.  Also, many MEA units require a continuous reclaiming process to purify the solvent, which is subject to degradation.

When comparing the BenfieldTM Process to other HPC processes, several additional things become apparent.  BenfieldTM has considerably more experience in designing and licensing units and is well accepted by contractors and clients alike.  In addition, Benfield’s ACT-1 activator has been proven to reduce CO₂ levels by about half that of other HPC units, and when used in combination with the newest packings and internals for designing new units can reduce tower packed volumes by up to 25%.  Even retrofitting 30 year old units with newer packings and with ACT-1 activated solution, gas scrubbing capacity can be increased while CO₂ slip is reduced.

In summary, the BenfieldTM Process is usually the best compromise for effective and economic scrubbing of acid gases from large volume industrial gas streams.  UOP’s Benfield ACT-1 activator is a proprietary promoter for the absorption of carbon dioxide (CO₂) by hot potassium carbonate solution.

Shovel-Ready Clean Coal Power Generation Technology for CO2 Capture

A merger of the commercially available Pressurized Fluidized Bed Combustion (PFBC) Boiler technology and the Benfield CO₂ capture technology, which each have over 20 years of successful commercial operation.

PFBC

• PFBC-EET has the license and the design ready for the PFBC technology
• Commercial available equipment
• Demonstrated high-cycle and combustion efficiency even at smaller sizes (over 40% cycle efficiency for 100 MW possible)
• Demonstrated fuel flexibility; waste coal, high-moisture coal, biomass, petcoke and more
• Compact size suitable for retrofit applications
• Meets present environmental requirements with minimal air pollution control equipment
• Demonstrated environmentally-friendly, commercially-usable ash (for concrete, etc.)
• Demonstrated quick start-up suitable for peaking applications (1 hour from 0 to 100% load from hot condition)

Benfield CO2 Capture Process

• Well proven CO₂ absorption process with potassium carbonate
• Commercially available equipment
• UOP, a Honeywell Company, has the license for the Benfield process and is ready to design the commercial unit for the PFBC application with performance guarantees
• The high partial pressure produces optimal conditions for capture and absorption of CO₂ of high purity (99%+)

PFBC and Benfield Technology Merger

• PFBC-EET has an interface design ready for the merger of the two processes
• PFBC-EET owns a PFBC Process Test Facility (PTF) where the PFBC/CO₂ capture process combination has been demonstrated with biomass for a negative carbon footprint
• PFBC-EET has developed the process application of combining the Alstom PFBC technology with the Honeywell/UOP/Benfield CO₂ capture technology