Calcination Tutorial

8/12/2019 Calcination Tutorial

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Technological devices and equipment:

1- green coke feed bin;

2- weigh belt;

3- rotary kiln;

4- combustion chamber;

5- burner;

6- primary air fan;

7- secondary air fan;

8- tertiary air fan;

9- transfer chute;

10- rotary cooler;

11- discharge hopper;

12- incinerator;

13- incinerator burners;

14- incinerator primary air fan ;

15- incinerator secondary air fan;

16- shutter;

17 - waste heat boiler;

18- baghouse;

19- fan exhauster;

20- cleaning filter from SO2;

21- stack (operating);

22- emergency or by-pass stack;

23- screw conveyor spray oil;

24- conveying belt;

25- calcined coke stock bin;

26- transport.


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DRY SCRUBBER REDUCES SO2 INCALCINER FLUE GAS02/18/1991

Gordon W. BrownRefining Consulting ServicesEnglewood, Colo.David RoderickWestern Slope Refining Co.

Fruita, Colo.Andrew Nastri

NaTec Resources Inc.

Dallas

Western Slope Refining Co., a subsidiary of Gary Williams Energy Corp., has installed a dry sulfur dioxide scrubberfor an existing petroleum coke calciner at its Fruita, Colo., refinery.The dry scrubbing process was developed by the power industry and the Electric Power Research Institute (EPRI) tohelp cope with the acid rain problem.

NaTec Resources Inc. provided the specific design based upon proprietary knowledge.It is the first application of the process in an oil refinery. The process could also remove SO2 from the flue gas of afluid catalytic cracker, fluid coker, or other refinery sources.

MANDATED REDUCTIONThe U.S. District Court of Colorado approved a consent agreement between Colorado's Air Pollution Control Division(APCD) and Gary Refining Co. The agreement specified that WSRC was to inject a dry sorbent directly into the fluegas duct ahead of the baghouses.The sorbents specified were nahcolite or trona (naturally occurring deposits of sodium bicarbonate and a mixture ofsodium bicarbonate and carbonate). The agreement allowed variations in equipment if mutually approved in advanceby the parties involved.The compliance date required was April 1, 1990. The consent agreement now applies to WSRC as a result of thereorganization of Gary Refining Co. Inc.

PROCESS SELECTIONAlthough the WSRC consent agreement specified the installation of a dry scrubber, there were several alternativeprocesses to consider. A discussion of these processes follows below. One should make sure the scrubbing process

selected has an optimal balance of removal efficiency, capital cost, and operating cost.EPRI and the U.S. Department of Energy sponsored considerable pilot, development, and commercial-scale work forthe removal Of SO2 from flue gas. Several forms of both calcium and sodium compounds will remove SO2 in theprocesses studied. Many publications resulted from this work.WSRC's process selection procedure included a review of certain key documents to use applicable experience(References 1, 2, and 3, including bibliographies). Telephone calls to experts in the field helped the selection processtoo. A brief description of each process considered and available commercial experience follows below.

WET LIME PROCESSThe wet lime process circulates a lime slurry through scrubbers to contact the flue gas for SO2 removal. The limeslurry saturates the flue gas with water vapor, which is not acceptable for the existing baghouse operation. Corrosion,high capital cost, plot plan space, and disposal concerns also negated further review.

LIME SPRAY DRYER PROCESSAt least one refiner uses a lime-spray dryer to remove SO2 from a petroleum coke calciner. The lime-spray dryingprocess removes water by evaporation from a very thick lime slurry. This keeps the flue gas temperature above itsdewpoint as the water evaporates from the slurry.The lime slurry enters a large reactor vessel via special spray nozzles for contact with the flue gas. Dried reactionproducts flow with the flue gas to the baghouse for recovery. This system would add as much as 25 in. of water _P tothe existing boiler-baghouse system, which was unacceptable.The Rawhide power plant of the Platte River Power Authority in northern Colorado employs the lime-spray dryingprocess. Management hosted a visit to see the scrubbing system in operation. The equipment required is bothextensive and large. It does an excellent job for this power station.In addition to the unacceptable _P, the project team rejected the lime-spray drying process because of the followingreasons:

The capital cost would be about three times that for the dry scrubber.


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A plot plan space was not available.

The installation downtime required would be unacceptable.

Additional manpower would be required.

These disadvantages overrode the benefits of the lower lime cost.

DRY LIME SCRUBBING

The potential low cost for dry lime injection is attractive. The process would be similar to dry sodium injection withonly minor modifications to existing equipment.Maximum utilization of the lime or lime hydrate sorbent is about 50%, depending upon flue gas temperatures.Utilization peaks at three temperature levels.Two of these temperatures are about 2,200 F. and 1,000 F. These temperatures are not compatible withtemperatures available in the flue gas train except in the boiler firebox. Maximum dry lime utilization also occurs atthe flue gas dewpoint, but it is not acceptable for the baghouse operation.The optimum temperatures required may not last long enough in the boiler firebox to provide the necessary kinetics.Commercial tests could provide the answer; however, the risk of failure was too high and time was not available forsuch tests.

DRY SODIUM SCRUBBINGPublic Service Co. of Colorado installed facilities for dry sodium flue gas desulfurization at its Cherokee station inDenver. The technical staff was very helpful in showing its facility to the project team, as well as responding toquestions.The project team selected sodium bicarbonate over the alternative sodium compounds, trona and sodium

sesquicarbonate, for the following reasons:Suppliers do not provide trona or sesqui in the pulverized form, so their use requires additional equipment. Also, theremay be additional handling problems with sesqui in powder form. Both alternate compounds produce more spentmaterial for disposal because of lower utilization.WSRC awarded the design and construction of the dry sodium scrubber to NaTec because of its experience andproprietary know-how. Also, WSRC contracted with NaTec for an assured supply of sodium bicarbonate with flow aidand a DENOx agent (if required). The supply agreement included operating know-how and routine technical service.

COMMERCIAL EXPERIENCEReferences 1, 2, and 3 discuss some of the commercial power plant dry scrubber demonstrations. Bibliographies inthese references provide a source of other commercial experience.More recently NaTec conducted full scale power plant demonstrations with both electrostatic precipitators (ESP) andbaghouses (fabric filters). The first of these tests (November 1987) involved a 107 mw generating unit burning lignitefuel and equipped with an ESP. At high SO2 removal rates, the inlet particulate loading doubled with no decrease inESP efficiency. Improved dispersion of sorbent in the flue gas stream helped SO2 removal and sorbent utilization.NaTec also tested the dry sodium scrubber process in July 1989 at the Port Washington power plant, Unit No. 3.5This test demonstrated the ability to control automatically SO2 emissions at various loads while maintaining highsorbent utilization. At 86% sorbent utilization, the process removed 74% of the SO2 during an extended test.

TECHNICAL BASIS OF PROCESSTwo chemical reactions occur in the dry sorbent process. In the first reaction, pulverized sodium bicarbonatedecomposes thermally to sodium carbonate as shown below.[SEE FORMULA]The decomposition is both time and temperature dependent. It is critical to the efficiency of SO2 removal as well asthe utilization of sorbent. The ideal flue gas temperature for sorbent injection is above 300 F. where decompositionstarts to occur in 0.4 sec.The release of reaction product gases during decomposition causes particles to increase in surface area. This largesurface area of unreacted carbonate improves SO2 removal efficiency. Injection at flue gas temperatures below 250F. greatly reduces sorbent utilization because thermal decomposition is slow and incomplete.The rate of decomposition to sodium carbonate and the flue gas flow rate determine the distance downstream fromthe injection point where reaction with SO2 occurs.

[SEE FORMULA]This second reaction shown above occurs rapidly in the gas stream. The baghouse then removes the end product,sodium sulfate, from the flue gas. Additionally, any unreacted carbonate in the filter cake will continue to removeSO2.

An additional benefit of the sodium bicarbonate desulfurization process is the simultaneous partial removal of NOx.Also, some conversion of NO to NO2 may occur at either high SO2 removal rates or low flue gas temperatures.NO2 concentrations above 30 ppm can produce El visible brown plume. However, the addition of a urea-basedDENOx agent with the sorbent will suppress NO2 formation.6

PROJECT PROCESS DESCRIPTIONSThe existing petroleum coke calcining unit processes anode-grade "green coke" to remove volatiles and water. Thealuminum and steel industries use calcined anode-grade coke to make electrodes.


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A fuel-fired rotary kiln heats the raw green coke by countercurrent flow. Hot calcined coke flows through a coolerbefore storage and shipment.

DRY SCRUBBERA settling chamber downstream of the rotary kiln green coke inlet provides time for larger entrained coke particles tosettle out of the flue gas. Then the flue gas splits into two parallel trains.Each train includes an auxiliary fuel-fired boiler followed by a waste heat steam generator and baghouse forparticulate recovery. Boilers provide refinery steam, and fans supply combustion air for incompletely burned kiln

gases, coke fines, and auxiliary fuel.Fans after the baghouses control draft on the system with louvers regulated by fired boiler firebox draft. Eachbaghouse has six modules with fabric filters that collect recovered fines in hoppers below the bags. Piping conveysthe fines from the hoppers to the fines collectors and silo by use of a steam eductor.The original design included a provision for the additional load imposed by the dry sorbent.

DRY SCRUBBER ADDITIONSNewly installed equipment functions to unload, store, transport, and inject the dry sodium bicarbonate sorbent into thecalciner flue gas upstream of the baghouses.Included for each train are a 100 ton storage silo, two rotary airlocks, a volumetric feeder, fluidizing and transport airblowers, dust collectors, an SO2 analyzer, a flue gas flow instrument, a programmed logic controller, and associatedpiping (Fig. 1).The new dry scrubber will increase the quantity of fines handled significantly, depending upon coke feed rate andsulfur content. For a typical 20 ton/hr calciner coke feed rate, the fines silo could contain 3.7 days of fines production.

FRESH SORBENT HANDLINGBulk hopper trucks pneumatically unload dry sorbent into a storage silo. It contains a dust collector to prevent any

particulates from reaching the atmosphere.The silo has a fluidized bottom operated with an aeration blower to aerate the stored sorbent for entry into a rotaryfeeder. A pulsating-type bin activator on the bottom of the silo can break up the sorbent if it becomes packed. Highand low level switches in the volumetric feeder hopper control the flow from the rotary feeder to the volumetric feederhopper.The SO2 control system sets the volumetric feeder speed to control the sorbent injection rate. The volumetric feederoutlet flow enters a second rotary feeder for entry to the transport line.Transport air conveys the metered flow of sorbent to the calciner flue gas duct injection point. It is just downstream ofthe waste heat boiler, where the temperature is 350-390 F. Here the sodium bicarbonate reacts with the SO2 in theflue gas to form sodium sulfate. The baghouse recovers the sorbent along with the calciner coke fines.

FINES TRANSPORTA steam eductor moves air through the fines-conveying system piping to transport the fines from the baghousehoppers to the fines silo. This whole conveying system operates automatically with programmed logic control.On the top of the fines silo, two collectors in series remove the conveyed fines and drop them into the silo. The

primary collector employs a cyclonic design to remove the major portion of the fines, and the secondary uses a smallfabric filter.

FINES STORAGE, SHIPPINGThe stored fines mixture remains in the fines silo until a convenient time to ship the material to an approved disposalsite. The shipping of the spent fines mixture must be done with a system so no soluble chemical reaches the ground.This will prevent soluble sulfate and carbonate from entering the water table.The refinery is on the Colorado River flood plain where salinity of the river is a long-term concern. The fines mixturecontains no materials classified as hazardous waste under the Resource Conservation and Recovery Act.Depending upon the disposal facility, the spent fines mixture is shipped either wet or dry; however, the handling toempty the silo must be dry or the system will plug completely.Before the dry scrubber installation, the flow of coke fines from the silo cone was slow and intermittent. Sometimes itrequired tedious manual intervention by operators. The coke fines were subject to bridging in the silo cone.The sodium bicarbonate sorbent is about 15 m particle size, which classifies it as a cohesive powder (Geldart'sdiagram). In fact, NaTec adds a flow aid to improve its flow properties. One could not predict in advance if the mixtureof coke fines and spent chemicals would be easier or more difficult to handle than the coke fines alone.

A literature source shows that aeration may solve the flow problem.4 Very simple lab tests show that aeration in thesilo cone area could improve the flow rate from the cone.Installation of aeration taps confirmed such improvement. Flow rate and aeration parameters from full scale tests willoptimize the system design. A closed system cannot accept any plugging or bridging.For the wet spent fines disposal system at WSRC, the silo dry fines flow into the water mixing device. Then the wetmixture flows into a water-tight roll-off bin. The water of hydration reaction with the sodium sulfate content requires aconsiderable amount of water.

A contractor transports the wet mix to an approved disposal site.A closed system design for dry disposal includes piping from the silo cone equipped for quick connection to a rolloffbin for dry shipment. The displaced volume of air from the bin vents back to the silo (dust free) as the bin fills. Theroll-off bin is airtight, so there can be no spillage during transit to the approved disposal site.


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TEST RESULTSUpon completion of the WSRC system, NaTec performed warranty testing with WSRC observation. NaTec providedits mobile laboratory to make flue gas analyses for an acceptance test run. The lab measures SO2, NO, NO2, CO,CO2, and O2.The installed SO2 emission control system gave the flue gas flow rate from an S-type Pitot tube (the standard forEPA certification) and the SO2 content.With this information, testers calculated the SO2 emission rate in pounds per hour as well as the percent SO2

reduction.The dry scrubbing system removed 74-86% of the SO2 with corresponding high sorbent utilization for normal calcineroperation. Table 1 shows data for three tests to illustrate the dependency of sorbent utilization upon percent SO2removal.Sorbent utilization decreased noticeably during lower flue gas flows resulting from turndown of the calciner.This caused some sorbent to drop out of the flue gas and reduced overall sorbent utilization.Flue gas measurements during the test run showed negligible NO conversion to NO2. No brown plume appearedfrom the stack. Therefore, the tests used no NOx reducing DENOx agent.

REFERENCES

1. Muzio, L. J., and Sonnichsen, T. W., Dry SO2 Particulate Removal for Coal Fired Boilers Vol. 2: "22-MWDemonstration Using Nahcolite, Trona and Soda Ash," EPRI CS-2894, June 1984.

2. Keeth, R. J., et al., Economic Evaluation of Dry-injection Flue Gas Desulfurization Technology," EPRI CS-4373. Final Report, January 1986.

3. Hammond, J. J., et al.. "Full Scale Demonstration of Dry Sodium Injection Flue Gas Desulfurization at City ofColorado Springs Ray D. Nixon Power Plant, presented at the Joint Symposium on Dry SO2 andSimultaneous SO2/NOx Control Technologies. Raleigh, N.C. Nov. 2-6, 1986.

4. Geldart, D., Gas Fluidization Technology, John Wiley & Sons, 1986.5. Coughlin, Terry, et al., "Injection of Dry Sodium Bicarbonate to trim Sulfur Dioxide Emissions," paper

presented at the EPRI/EPA 1990 SO2 Control Symposium, New Orleans, May 8-11, 1990.6. U.S. Patent 4,844,915.

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