Gordon W. Brown
Refining Consulting Services
Englewood, Colo.
David Roderick
Western 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 scrubber for 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) to help 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 a fluid catalytic cracker, fluid coker, or other refinery sources.
MANDATED REDUCTION
The 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 flue gas duct ahead of the baghouses.
The sorbents specified were nahcolite or trona (naturally occurring deposits of sodium bicarbonate and a mixture of sodium bicarbonate and carbonate). The agreement allowed variations in equipment if mutually approved in advance by the parties involved.
The compliance date required was April 1, 1990. The consent agreement now applies to WSRC as a result of the reorganization of Gary Refining Co. Inc.
PROCESS SELECTION
Although the WSRC consent agreement specified the installation of a dry scrubber, there were several alternative processes 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 for the removal Of SO2 from flue gas. Several forms of both calcium and sodium compounds will remove SO2 in the processes 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 process too. A brief description of each process considered and available commercial experience follows below.
WET LIME PROCESS
The wet lime process circulates a lime slurry through scrubbers to contact the flue gas for SO2 removal. The lime slurry 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 PROCESS
At least one refiner uses a lime-spray dryer to remove SO2 from a petroleum coke calciner. The lime-spray drying process removes water by evaporation from a very thick lime slurry. This keeps the flue gas temperature above its dewpoint 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 reaction products flow with the flue gas to the baghouse for recovery. This system would add as much as 25 in. of water _P to the existing boiler-baghouse system, which was unacceptable.
The Rawhide power plant of the Platte River Power Authority in northern Colorado employs the lime-spray drying process. Management hosted a visit to see the scrubbing system in operation. The equipment required is both extensive 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 following reasons:
- The capital cost would be about three times that for the dry scrubber.
- 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 with only 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 with temperatures available in the flue gas train except in the boiler firebox. Maximum dry lime utilization also occurs at the 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 for such tests.
DRY SODIUM SCRUBBING
Public Service Co. of Colorado installed facilities for dry sodium flue gas desulfurization at its Cherokee station in Denver. The technical staff was very helpful in showing its facility to the project team, as well as responding to questions.
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, there may be additional handling problems with sesqui in powder form. Both alternate compounds produce more spent material for disposal because of lower utilization.
WSRC awarded the design and construction of the dry sodium scrubber to NaTec because of its experience and proprietary know-how. Also, WSRC contracted with NaTec for an assured supply of sodium bicarbonate with flow aid and a DENOx agent (if required). The supply agreement included operating know-how and routine technical service.
COMMERCIAL EXPERIENCE
References 1, 2, and 3 discuss some of the commercial power plant dry scrubber demonstrations. Bibliographies in these references provide a source of other commercial experience.
More recently NaTec conducted full scale power plant demonstrations with both electrostatic precipitators (ESP) and baghouses (fabric filters). The first of these tests (November 1987) involved a 107 mw generating unit burning lignite fuel and equipped with an ESP. At high SO2 removal rates, the inlet particulate loading doubled with no decrease in ESP 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. 3.5 This test demonstrated the ability to control automatically SO2 emissions at various loads while maintaining high sorbent utilization. At 86% sorbent utilization, the process removed 74% of the SO2 during an extended test.
TECHNICAL BASIS OF PROCESS
Two chemical reactions occur in the dry sorbent process. In the first reaction, pulverized sodium bicarbonate decomposes 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 as the utilization of sorbent. The ideal flue gas temperature for sorbent injection is above 300 F. where decomposition starts to occur in 0.4 sec.
The release of reaction product gases during decomposition causes particles to increase in surface area. This large surface area of unreacted carbonate improves SO2 removal efficiency. Injection at flue gas temperatures below 250 F. 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 from the 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 remove SO2.
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-based DENOx agent with the sorbent will suppress NO2 formation.6
PROJECT PROCESS DESCRIPTIONS
The existing petroleum coke calcining unit processes anode-grade "green coke" to remove volatiles and water. The aluminum and steel industries use calcined anode-grade coke to make electrodes.
A fuel-fired rotary kiln heats the raw green coke by countercurrent flow. Hot calcined coke flows through a cooler before storage and shipment.
DRY SCRUBBER
A settling chamber downstream of the rotary kiln green coke inlet provides time for larger entrained coke particles to settle 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 for particulate 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. Each baghouse has six modules with fabric filters that collect recovered fines in hoppers below the bags. Piping conveys the 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 ADDITIONS
Newly installed equipment functions to unload, store, transport, and inject the dry sodium bicarbonate sorbent into the calciner 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 air blowers, dust collectors, an SO2 analyzer, a flue gas flow instrument, a programmed logic controller, and associated piping (Fig. 1).
The new dry scrubber will increase the quantity of fines handled significantly, depending upon coke feed rate and sulfur content. For a typical 20 ton/hr calciner coke feed rate, the fines silo could contain 3.7 days of fines production.
FRESH SORBENT HANDLING
Bulk 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 rotary feeder. A pulsating-type bin activator on the bottom of the silo can break up the sorbent if it becomes packed. High and low level switches in the volumetric feeder hopper control the flow from the rotary feeder to the volumetric feeder hopper.
The SO2 control system sets the volumetric feeder speed to control the sorbent injection rate. The volumetric feeder outlet 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 of the waste heat boiler, where the temperature is 350-390 F. Here the sodium bicarbonate reacts with the SO2 in the flue gas to form sodium sulfate. The baghouse recovers the sorbent along with the calciner coke fines.
FINES TRANSPORT
A steam eductor moves air through the fines-conveying system piping to transport the fines from the baghouse hoppers 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 small fabric filter.
FINES STORAGE, SHIPPING
The stored fines mixture remains in the fines silo until a convenient time to ship the material to an approved disposal site. 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 mixture contains 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 to empty 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 it required 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's diagram). In fact, NaTec adds a flow aid to improve its flow properties. One could not predict in advance if the mixture of 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 the silo 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 will optimize 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 wet mixture flows into a water-tight roll-off bin. The water of hydration reaction with the sodium sulfate content requires a considerable 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 rolloff bin for dry shipment. The displaced volume of air from the bin vents back to the silo (dust free) as the bin fills. The roll-off bin is airtight, so there can be no spillage during transit to the approved disposal site.
TEST RESULTS
Upon completion of the WSRC system, NaTec performed warranty testing with WSRC observation. NaTec provided its 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 for EPA 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 calciner operation. Table 1 shows data for three tests to illustrate the dependency of sorbent utilization upon percent SO2 removal.
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 appeared from the stack. Therefore, the tests used no NOx reducing DENOx agent.
REFERENCES
- Muzio, L. J., and Sonnichsen, T. W., Dry SO2 Particulate Removal for Coal Fired Boilers Vol. 2: "22-MW Demonstration Using Nahcolite, Trona and Soda Ash," EPRI CS-2894, June 1984.
- Keeth, R. J., et al., Economic Evaluation of Dry-injection Flue Gas Desulfurization Technology," EPRI CS-4373. Final Report, January 1986.
- Hammond, J. J., et al.. "Full Scale Demonstration of Dry Sodium Injection Flue Gas Desulfurization at City of Colorado Springs Ray D. Nixon Power Plant, presented at the Joint Symposium on Dry SO2 and Simultaneous SO2/NOx Control Technologies. Raleigh, N.C. Nov. 2-6, 1986.
- Geldart, D., Gas Fluidization Technology, John Wiley & Sons, 1986.
- 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.
- U.S. Patent 4,844,915.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.
