The Cluster Rule is increasing NCG disposal systems use. Issues and solutions for mills using one disposal option-a dedicated incinerator-are examined

NCG Incinerators Work but Site Specific Problems Often Need to be Solved

A variety of disposal methods for these gases have been tried, including incineration and scrubbing. However, burning in an existing source can negatively impact the operation of this equipment, and logistics of doing so can be a problem due to location. Gases such as hydrogen sulfide (H₂S) can be removed by scrubbing, but problems with this approach can arise if carbon dioxide (CO₂) is present.

Another alternative is a dedicated NCG incineration system. But does use of a dedicated incinerator mean smooth sailing? According to reports from the field, problems still exist. This article provides a brief overview of the different options, followed by a sampling of field problems and the solutions.

BURNING IN AN EXISTING SOURCE. The NCG can be thermally oxidized via high temperature combustion in a recovery furnace, power boiler or lime re-burning kiln. The TRS compounds in the NCG are converted to sulfur dioxide (SO₂), which can be released to atmosphere or alternately absorbed in a downstream scrubber. However, a greater problem from a cost standpoint arises when NCG incineration leads to mill SO₂ emissions in excess of its environmental permit. This can necessitate installation of a scrubber for SO₂ absorption. Since the scrubber has to be designed for the total flue gas volume from the combustion unit, it will thus be disproportionately very large for disposal of a small volume of NCG.

NCG incinerator with SO₂ absorption tower.

The impact of the NCG disposal on the process unit must also be considered. For example, the chemicals added by thermal oxidation of NCG in the lime kiln might adversely affect the causticizing or the liquor composition. The combustion of NCG may also increase corrosion in the recovery furnace or power boiler. Many mills find that operating problems at the lime kiln increase in the form of clinker and ring formation when NCG is introduced.

NCG AND TRS SOURCES. NCG gas streams are normally collected in two separate systems and directed to two different disposal units. High volume, low concentration (HVLC) gases from brown stock washers, etc., are directed to the recovery furnace or power boiler where they replace part of the combustion air. Low volume, high concentration (LVHC) gases from digesters, blow tanks, evaporators, black liquor storage, and oxidation tanks are conveyed to the lime kiln for destruction, where their heating value allows reduction of the normal kiln fuel rate. The type of wood being pulped and type of digester can have significant effect on the amount and concentration of the NCG generated.

The recovery boiler is in some cases a source of TRS, particularly for boilers with direct-contact evaporators. In modern recovery furnaces, the TRS emission problem is generally minimal. However, there are still a number of recovery boilers in operation with direct-contact evaporators. Sodium sulfide in the liquor converts to H₂S in the direct contact evaporator. Here the emission of the malodorous compounds is a challenging problem. The amount of excess air is also a factor in determining release of TRS from the recovery furnace itself. As reported by G.N. Thoen et al.⁽¹⁾ by increasing the excess air and thereby the oxygen content in the flue gas from 1.4% to 3%, a 94% reduction of TRS can be attained (Figure 1).

FIGURE 1: Increasing excess air in the flue gas can cut TRS release from a recovery furnace.

SCRUBBING NCG AND TRS. Hydrogen sulfide (H₂S) can be absorbed with high efficiency in a packed absorber column using a high pH sodium alkali absorbing agent (caustic, soda ash or white liquor). In contrast, mercaptans and the methyl sulfides present in NCG are difficult to absorb. Mercaptans are mildly acidic, and can be absorbed with reasonable efficiency under ideal conditions.

TRS generated from a recovery boiler, however, is not easily removed with caustic scrubbing. The CO₂ in the boiler flue gas is absorbed by the scrubbing reagent and forms sodium carbonate, and will inhibit the reaction between the reagent and the TRS compounds. As long as the pH of the scrubbing liquid is below 6 to 6.5 the CO₂ absorption is minimal, and SO₂ can therefore be scrubbed without problem. High efficiency absorption of H₂S requires a pH of 10 to 11, at which alkalinity most of the reagent will react with CO₂ rather than with the TRS. The end result is an excessive consumption of reagent.

R.W. Hohlfeld ⁽²⁾ describes a patent, held by Dow Chemical Co., for selective absorption of H₂S from gases containing CO₂. The method is based on the fact that the reaction between H₂S and a strong alkali solution is virtually instantaneous, while the absorption of CO₂ is a much slower reaction. Therefore, if the gas is allowed to contact the liquid for a very short time the absorption of CO₂ can be significantly reduced.

To achieve this selective absorption of H₂S the required contact time between gas and liquid must thus be extremely short. This may be difficult to attain in industrial scale systems. It appears that the only possible scrubber to be used would be a Venturi scrubber followed by a gas/liquid separator. A packed tower will have many times longer contact time.

It is recommended that the pH in the liquid effluent be kept between 9 and 12. The effluent will then primarily consist of sodium bisulfide. If the pH falls below 9, the equilibrium shifts from sodium bisulfide to hydrogen sulfide, due to the fact that the alkali is too weak to absorb the acid gas. If the pH rises above 12 the equilibrium shifts from bisulfide to sodium sulfide, which compound requires twice as much caustic to form. Proper pH control (ideally 10-11) is therefore imperative.

As can be expected it is much easier to remove H₂S from a gas containing 20,000 ppm, than it is to remove H₂S at 200 ppm concentration. Figure 2 shows the relative caustic consumption for various H₂S concentrations. Caustic consumption 1 means the stoichiometric amount, and 2 being twice the stoichiometric amount.

FIGURE 2: If Co₂ is present, a short contact time is best for H₂S absorption without high caustic demand.

Dr. E.A. Trauffer ⁽³⁾ reports that the absorption of CO₂ can be prevented or reduced by adding an aminic solution to the scrubbing liquid. To our knowledge this has only been demonstrated in pilot scale and not been proven under actual conditions. There is probably no way of scrubbing out NCG from boiler flue gases in industrial scale without exorbitant caustic consumption. It is therefore important to ensure that the TRS be thermally oxidized to the highest possible degree, and to avoid trying to scrub these compounds when CO₂ is present.

When CO₂ is not present H₂S can be scrubbed out with high efficiency in exhausts from smelt dissolving tanks, and from other LVHC streams. The smelt tank exhaust also contains particulate, and the scrubber typically consists of a venturi for control of the particulate matter, followed by a packed tower for absorption of TRS gases. For this application H₂S is normally at least 70% to 80% of the TRS. Weak wash or caustic is used as scrubbing medium and the pH is maintained at 12+.The scrubbing efficiency on mercaptans, and methyl sulfides is also poor in this case.

DEDICATED INCINERATORS. A dedicated incinerator represents additional cost to the mill, but allows separation of the NCG treating requirements from the main business of the mill—producing pulp. The components of such an incinerator and a series of problem reports, and solutions to these, are covered below based on existing installations.

In mills where other methods are currently working on part of the NCG streams, an incinerator may serve as the “back-up.” This type of incinerator is subject to very rapid startups and must be designed to take abuse. For instance, hard refractory lining the combustion chamber (brick or castable) is replaced by ceramic fiber blanket products, or else stainless steel construction and external cooling are used to eliminate all refractory requirements. In some mills the use of a simple enclosed flare to handle temporary NCG flow has been very successful. Normally backup incinerators (Figure 3) or flares are not equipped with SO₂ scrubbers and the temporary flow of SO₂ to atmosphere must be factored into the mill’s overall emission inventory.

FIGURE 3: Back-up incinerators, used when other NCG control methods are used, typically lack SO₂ scrubbers.

In mills where NCG control has not been implemented, or where the use of existing combustion devices has proven troublesome, a dedicated incinerator system (Figure 4) may be used as the primary treatment device. The lime kiln, power boiler or stand-by flare can serve as back-up. A full time incinerator can use the more durable hard refractory and is equipped with a scrubber for SO₂ removal.

FIGURE 4: Dedicated incinerator systems have SO₂ scrubbers, and other existing sources serve as backup.

Incinerator Components. The incinerator can be separated into the following components:

Safety Considerations. Steps must be taken to prevent static electricity in the ducting or the flame present in the incinerator from causing a flashback or explosion. Detonation arrestors and high velocity passages built into the incinerator system are normally required.

Burner. The burner always contains an ignition device (usually a natural gas or propane fired pilot burner) as well as an auxiliary fuel gun. The gun is for initial heating of the furnace and maintenance of furnace temperature when the NCG streams are too lean to provide self-sustained combustion. Since the burner flame is the primary source of any NOx formed, control of fuel/air mixing may be important in certain areas of the country. The fuel can be natural gas, fuel oil, turpentine or any similar stream. Natural gas is the most common fuel.

Furnace. Today the generally accepted furnace conditions are 1,600°F with 0.75-sec. retention time for full TRS combustion. Refractory life must be long enough to allow maintenance only at the regular mill turnarounds. NCG incinerators typically handle gaseous wastes, but various waste liquids may also be fed.

Flue gas quench. If the incinerator flue gas must be scrubbed (SO₂ levels usually force this) then some method of cooling the gas prior to scrubbing is necessary. A boiler could be used for part of the cooling, but usually water sprays are used to cool the flue gas. The rapid temperature change at this stage can cause corrosive and thermal expansion problems.

SO₂ scrubber. Passing the cooled flue gas through a wet scrubber will remove part of the SO₂ generated in the furnace. Removal of about 99% of the SO₂ is usually required to meet permit requirements and this means the recirculated scrubber water has to be kept alkaline. Most systems inject caustic (NaOH) for this reason. Minerals in the scrubber feed water plus sodium sulfite and sodium bisulfite formed by the NaOH can build up during operation. Part of the scrubber liquid is therefore discharged and replaced by fresh feed water in order to avoid mineral deposits within the scrubber.

Stack. The cleaned incinerator exhaust is discharged at a point above adjacent structures, since traces of TRS and SO₂ will still be present. In addition the flue gas is usually saturated with water vapor and will form a steam plume in most weather conditions.

Controls. The control system is designed primarily for safety. Since the incinerator is a combustion device there is the potential for excessive temperature, loss of combustion (discharge of untreated TRS) and flashback into the NCG ducts under certain conditions. Thus flame scanners and temperature switches are interlocked with the fuel and NCG feed valves. Certain conditions of temperature and oxygen content are needed for minimum TRS destruction and are carefully controlled. Likewise, proper water flow and scrubber pH are needed for good SO₂ removal, adding to the system control package.

SO₃ removal (optional). Most of the sulfur in the NCG forms SO₂, but a small fraction, as much as 5% to 10% depending on furnace conditions ^{(4, 5)}, oxidize to SO₃.The SO₃ tends to form aerosol droplets so small they are largely are unaffected by packed bed treatment. Thus, a high efficiency mist eliminator (sulfuric acid plant type “candles”), wet electrostatic precipitator or high energy venturi scrubber are required, adding both cost and energy consumption to the incinerator system.

CASE HISTORY REPORTS. A number of dedicated NCG incinerators are currently in service. Most systems have some history of problems (and solutions), beginning with the installation of equipment and continuing during day-to-day operation as the hardware ages. Since each mill generates NCG streams with unique properties, depending on wood supply, pulping method and other factors, there is really no such thing as a “standard” NCG incinerator.

Installation problems. These problems normally consist of misalignment at equipment flanges or anchor bolts, and are solved after a certain amount of grumbling by all parties. Both project cost and schedule may be affected, but in the end a functioning system normally results.⁽⁶⁾

Capacity and control problems. Variations in NCG flow and composition are to be expected. Even if the NCG streams are already being collected, careful monitoring of the flows and compositions is necessary in order to gather accurate data for system sizing.⁽⁷⁾

For example, in a Michigan mill the sour water stripper was operating at non-typical conditions during initial data collection, which led to inaccurate stripper off gas (SOG) design data. The SOG is a relatively high BTU stream, demanding considerable combustion air for incineration. In this case additional air was needed to control the furnace temperature when the SOG was particularly rich (high furnace temperature can cause refractory damage and exceed quench system capacity.) But the existing air fan couldn’t supply the additional air needed. The extra air needed also increased the flue gas volume and residence time was therefore compromised, leading to emissions of unburned TRS. This particular incinerator is mounted in a building and space for expansion is limited, so furnace enlargement created quite a problem. Unless the NCG flows and compositions are well understood, specifying reasonable “fat” into the system can pay future dividends.

Capacity problems can be dealt with through burner changes, blower modifications, furnace extensions and other measures—all of which are cheaper than putting in a whole new system (as finally was done at the Michigan mill.) Selecting a site for the system occurs early in the project and should be approached with an eye to future capacity increases. Blowers can be selected such that the housing will accommodate a larger wheel. Fortunately scrubber packings are available in many formats and can be replaced with higher capacity types (more expensive, though.)

As another example, a Mississippi mill was experiencing rapid changes in chip bin level. This can affect the turpentine content of the NCG stream, resulting in rapid changes in furnace air demand. For an interesting discussion see Reference.⁽⁸⁾ The combustion air supply system wasn’t able to respond quickly enough to prevent furnace temperature spikes, which cause nuisance shutdowns at the high temperature trip point.

At the same mill black liquor can be entrained in the SOG if process upsets cause the stripper to flood. Black liquor can also flow into the incinerator if the chip bin level declines to the point of “blow through”. Accidental injection of black liquor into the incinerator has resulted in partial combustion and carryover of unburned TRS compounds.

At a New Hampshire mill turpentine spikes apparently occur in the LVHC stream, making furnace temperature control a problem. Air is added to the LVHC before sending it to the incinerator, making it in effect an HVLC stream. The mill monitors the lower explosive limit (LEL) of this stream and has had operation and maintenance problems with several of the instruments used. A Control Instruments Corp. analyzer has proven to work very well. At this mill flame arrestors are located at each source of LVHC and at the incinerator, both before and after the transfer blower which sends the stream to the incinerator. Flame arrestors are not used on the actual HVLC sources.

Refractory problems. Typically refractory materials are used to line the interior of the incinerator furnace and flame impingement areas of the burner, as well as parts of the flue gas quench system in some designs. Burner refractory is normally the roughest service and routine replacement should be expected—maybe every year or so. Furnace refractory protects the gas tight furnace shell from the high flue gas temperatures and is usually brick or a hard castable held in place on the shell with specialized stainless steel anchors. To handle quick startups a ceramic fiber type refractory (blanket or board) can be used.

As the Michigan mill cited above, corrosion of the blanket attachment clips lead to replacement with castable refractory. If selected and applied correctly, furnace refractory may well last the life of the system (10+ years.)

At a Mississippi mill the refractory brick around the chip bin vent gas entry has been lost and replaced at least once. The mill engineer believes the damage was due to rapid changes in the composition of the NCG stream (changes in heating value can alter the TRS light-off point and affect local refractory temperatures).

Refractory problems—Flue gas quench system. Quench refractory must tolerate hot dry conditions (1,600°F) where the flue gas enters, and wet cool conditions (180°F) at the outlet end. The key is proper selection, installation and steady operation. Failure of the water supply hardware can result in early damage to the quench refractory, so the use of low flow and low pressure trips is recommended. Better yet would be a quench device incorporating no refractory at all—some all stainless (alloy 316) designs are available which seem to have good operating histories.

At an Alabama mill the flue gas quenching was accomplished in the refractory lined base of the packed bed SO₂ scrubber. Water in the scrubber sump and water falling from the packing support plate accomplished the flue gas quenching, but improper design or installation of the brick work led to early failure. Loss of brick in the scrubber inlet nozzle required immediate shutdown and repair. The system is now working well.

At a Michigan mill, water spray guns mounted in a vertical downflow stainless steel duct with partial refractory lining has worked well except for mysterious deposits which form about 10 ft. above the spray guns and occasionally detach, falling on the guns. The deposits dissolve in plain water and are thought to come from material entrained in the furnace combustion products, although no source has been identified. The guns have been structurally reinforced and operating problems have ceased. The duct lining was originally brick, but was changed to castable, which has given good life. The mill engineer observes that experienced masons should be used for any refractory lining to insure long life.

At a Texas mill the flue gas flows downward past a stainless steel overflow weir and through a stainless duct for quenching. The flue gas is only 600°F to 800°F, having passed through an NCG preheater arrangement for fuel savings. Water from the SO₂ scrubber is pumped to the weir and flows down the inside wall of the duct, cooling it. The same water is pumped to atomizing guns in the tube, quenching and saturating the gas. No operating problems have been encountered.

At a New Hampshire mill the refractory lining the quench section has failed and been replaced. Mill personnel believe this was due to rapid heat-up requirements (this incinerator is a “quick start” type used as backup to the lime kiln, which is the primary NCG combustion source). In “warm up” mode on this incinerator the flue gas flow is much lower than during normal operation and quench performance is hampered. Sometimes the “quenched” flue gas flows to the scrubber at 400°F to 500°F during this period.

SO₂ scrubber problems. Most SO₂ scrubbers use a packed bed for gas/liquid contact. Venturis, spray towers and other types may also be used, although energy requirements (pressure drop) or capital cost may be excessive. If the scrubber is sized correctly for the degree of SO₂ removal needed to meet permit requirements, few maintenance problems occur. However, since the minerals dissolved in the scrubber feed water or added for pH control tend to concentrate in the scrubber/quench system, a continuous blow down to the mill water treatment plant is necessary. Failure to control the blowdown rate can result in mineral deposits in the scrubber, which cause pressure drop and efficiency problems.

The New Hampshire mill noted above has had problems with insoluble white crystalline solids forming in the scrubber water instrument lines. The makeup water at this mill is relatively “soft” with low levels of dissolved minerals, but by minimizing blow down the mill can also minimize caustic usage. Careful attention to blow down control is necessary to prevent problems.

At one Mississippi mill, fouling of the packing with calcium minerals is a problem. Acid washing has been tried with limited success. The mill is considering removal of the packing and conversion to a spray scrubber with easily removable spray headers. The same mill conserves chemicals by feeding the scrubber blow down back into the mill liquor system. At times back flow has occurred, sending black liquor into the scrubber.

At a Michigan mill scrubber neutralization is via soda ash (Na₂CO₃). Water hardness has created problem mineral deposits in the packing but addition of a water softener on the makeup water line has eliminated this.

Continuing problems with damage to 316 SS strainer baskets in an Alabama mill’s scrubber liquid circuits has resulted in removal of the baskets. Thus far no problems with plugging of the water distributor orifices which irrigate the bed of packing has been seen.

SO₃ removal problems. Only one incinerator system was located where the SO₃ aerosol generated by the furnace is being removed. At this mill the flue gas is first quenched and scrubbed using caustic in a packed bed scrubber. The “clean” flue gas then passes through a high efficiency mist eliminator vessel and to the stack. This arrangement adds about 10 in. water column pressure drop to the system. After resolution of installation issues, the only problem has been that the concentrated H₂SO₄ collected by the unit corroded the 316 SS drain pipe. Part of the scrubber circulating liquid was diverted through the mist eliminator sump and the problem was solved.

REFERENCES

1. G.N. Thoen, G.G. DeHass, R.G. Tallent, A.S.Davis, “The Effect of Combustion Variables on the Release of Odorous Sulfur Compounds from a Kraft Recovery Unit” TAPPI Annual Meeting, 1968

2. R.W. Hohifeld “Selective Absorption of H₂S from Sour Gas” Paper presented before Society of Petroleum Engineers, February 1979

3. Dr. E.A. Tauffer, Quaker Chemical Corporation Private Consultations May 1995

4. Robert D. Reed “Furnace Operation”p.56.

Gulf Publishing Company, Houston ,TX

5. J. E. Ward and A. P. Ting “Waste Incineration”

EnvironmentalTechnology, 1(1):35,1982

6. D. Banks, H. Ladner, J. Howe, and C. Connally

“Evolutionary NCG Incineration System Installed at Mead Coated Board, Mahrt, Alabama” TAPPI 1996 Engineering Conference and Trade Fair

7. G. Lloyd, A. Farr, and R. Tembreull

“Design and Installation of a Replacement Thermal Oxidizer for Odor Abatement” TAPPI 1997 Environmental Conference

8. H. Ohman, R. Lammi, J. Kivivasara, M. Jarvensivu, and T. Maenpaa “Diagnosis of the Non-condenible Gas Collection System Operation” TAPPI 1998 Environmental Conference

Jorgen Hedenhag is with AirPol Inc. and Banks with Banks Engineering.