BAGASSE-FIRED BOILERS WITH REFERENCE TO CO-GENERATION

There is growing realisation in the cane sugar industry that, by upgrading steam cycles, surplus bagasse can be burned profitably to generate export power. These higher steam conditions open new opportunities to integrate and rationalise the design of the boiler plant with that of the station as a whole. This paper analyses these possibilities and how they impact upon overall plant performance. Whilst it deals specifically with bagasse fired units, most of the comments apply to wet wood wastes as well.

FUEL CHARACTERISTICS There are many papers dealing with those properties of bagasse and fossil fuels which dictate boiler plant design1, 3, 5. The fuel properties which dictate co-generation station cycle efficiency are: heating value reactivity particle size sulphur content and those other elements which might have a bearing on the fuel's environmental friendliness. The 'as fired' analyses of a typical bagasse, a medium volatile coal, fuel oil and pine wood are scheduled in Table 1. They form the basis of the calculations for this paper.

Table 1 - 'As Fired' Analyses of Typical Fuels   Bagasse (%) Coal (%) Oil (%) Wood (%) PROXIMATE Fixed Carbon 11.1 56.8 99.6 12.1 Volatiles 35.9 25.8 - 36.4 Moisture 50.0 6.0 0.4 50.0 Ash 3.0 11.4 trace 1.5 TOTAL 100.0 100.0 100.0 100.0 Brix 1.2       ULTIMATE Carbon 22.9 70.3 85.8 26.7 Hydrogen 2.8 4.0 10.8 2.8 Sulphur 0.0 0.5 2.8 0.0 Nitrogen 0.0 1.8 0.2 0.1 Oxygen 21.3 6.0 0.0 18.9 Moisture 50.0 6.0 0.4 50.0 Ash 3.0 11.4 0.0 1.5 TOTAL 100.0 100.0 100.0 100.0 GCV kJ/kg 9 177 28 410 43 000 9 700 NCV kJ/kg 7 409 27 385 40 887 7 936 Stoic. CO2 % 20.7 <>18.8 16.1 20.6 GCV of bagasse in accordance with SMRI formula

OPTIMISING BOILER EFFICIENCY Cane sugar factory boilers are usually designed to generate just sufficient steam from the available bagasse to meet factory heat and power requirements. If they are too efficient, surplus bagasse has to be disposed of whilst if they are not efficient enough supplementary fuels have to be burned to make up the energy shortfall. Boilers installed in co-generation stations, on the other hand, must operate at optimal efficiency at all times and on all fuels. Boiler efficiency varies as a function of fuel moisture, fuel reactivity, exhaust gas temperature and the amount of excess air required to complete combustion efficiently. Figure 1 shows how efficiency varies with flue gas temperature, fuel moisture and excess air when burning bagasse. This same relationship applies broadly to timber wastes. Reducing moisture is clearly beneficial. Bagasse can be dried cost effectively down to about 45 to 50 % moisture (on a wet basis) using mechanical methods3. It can be dried thermally and biochemically to lower figures. The cost effectiveness of these methods is being evaluated. Figures 2 and 3 show relationships between flue gas temperature and excess air for coal and fuel oil. The completeness of combustion is measured by the unburned carbon loss and the amount of CO formed. It is difficult to complete the combustion of coal on a spreader stoker with flue gas excess air figures corresponding to more than 13,5 % CO2. Air infiltration through grates designed to burn bagasse makes it difficult to burn oil at CO2 figures higher than 14,5 % even though this is possible on dedicated oil fired units.

   

1. The unburned carbon loss;
2. the excess air ratio; and
3. the flue gas temperature.

When burning coal, unburned carbon loss can be reduced by refiring the coal grits carried over with the flue gases. Depending on the reactivity of these grits, fuel savings of between 1,5 and 2,5 % can be achieved. Refiring bagasse is difficult. The char, which is highly reactive, frequently catches fire in the refiring hoppers forming clinkers which in turn choke the refiring nozzles. Most bagasse refiring systems have been abandoned because of this. Although cumbersome, dual hopper discharges can be used on bagasse/coal fired boilers to obtain the best of both worlds. When firing bagasse, dual hopper discharges allow bagasse char to be removed hydraulically. When burning coal they allow grits to be refired.

In modern water cooled highly rated furnaces it is essential to use hot primary combustion air to burn bagasse having a moisture content of more than 50 %. Below 40 % moisture this fuel burns efficiently and stably without preheated air. Stable combustion can be achieved with cold air with fuels having a moisture content of between 46 and 50 %, but larger grates are required to achieve acceptable results³.

Hot primary air also has a beneficial effect on grate rating and unburnt carbon loss when burning coal.

The maximum primary air temperature which can be used is limited by the materials of construction of the grate and the ash fusion temperature characteristics of the fuels. Provided grate materials are suitably selected, temperatures of up to 250 °C and possibly more are beneficial when burning bagasse. Problems of slagging at grate level are frequently experienced when burning coal with air temperatures exceeding 150 °C. The problem can be compounded when burning bagasse and coal on the same grate. Sometimes the ashes combine to form an eutectic with an ash fusion temperature lower than either of the individual fuels. Lowering the primary air temperature helps alleviate this problem. At optimum firing conditions bagasse can be burned at higher grate ratings than coal. As a result, boilers designed to burn both fuels frequently have to be derated by 10 to 20 % on coal. Usually this makes little difference to station output as this fuel is only burned during the offcrop when there is no process steam demand.

Gas to air preheaters and economisers are used to reduce the flue gas temperature to the desired value. Cane sugar factory boilers are normally fitted with air preheaters and sometimes economisers. As explained later co-generation boilers are best fitted with economisers and steam or hot water heated air preheaters. Fig. 4 shows the relative effectiveness of the heating surface components of a typical cane sugar factory bagasse fired boiler and a co-generation bagasse/coal fired boiler. The sugar factory boiler has a flue gas temperature of 270 °C and the co-generation boiler a flue gas temperature of 150 °C. About 25 % more heating surface must be added in the form of economiser surface to the cane sugar factory boiler to reduce its flue gas temperature to 160 °C. This surface will extract 9,5 % more heat from the flue gases The cost of an economiser designed to reduce the flue gas temperature of the co-generation boiler to 150 °C will amount to about 6 to 8 % of the cost of the boiler. If a flue gas temperature of 170 °C is selected instead, the boiler will cost about 1,9 % less and the unit will bum 1,74 % more bagasse and 1,14 % more coal. Fig 5 shows how economiser heating surface and cost varies with flue gas temperature when burning bagasse.

Mild steel plain tube economiser surface has been used in all cases in these analyses. About twice as much extended fin surface is needed to achieve the same results. However, the cost of extended fin surface is usually less than plain tube surface. Finally, an overriding consideration in the design of all boilers is the need to keep metal temperatures above the acid dew point of the flue gases. If metal temperatures fall below this temperature, acids formed in the combustion process will condense on them. These acids are usually corrosive and sticky. They attract fly ash. The deposits inhibit heat transfer and can ultimately become so severe as to choke the gas passes. The acid dew point of the gases generated from burning bagasse is usually below 90 °C. The acid dew point of the gases generated from sulphur bearing fossil fuels depends largely upon the sulphur content of the fuel. It can vary from 105 to 145 °C; the higher the sulphur content the higher the acid dew point. At 1,5 % sulphur, metals should be kept at +128 °C. Dew point problems occur mainly on heat recovery surfaces. In the case of economiser surface the metal temperature will be very close to the feedwater temperature. In the case of a well designed air heater, the metal temperature will be about halfway between the air and gas temperatures.

OPTIMIZING THE THERMAL CYCLE

The efficiency of a condensing steam cycle is largely dependent upon the turbine stop valve conditions and the amount of heat rejected to the condenser. Maximising turbine stop valve conditions and minimizing the heat rejected maximizes efficiency.

A sugar factory uses saturated steam at a pressure of about 2,2 bar absolute. Therefore, any turbine installed in a co-generation station must be equipped with a controlled pressure extraction stage designed to meet this requirement. Unfortunately the condensate returned from a sugar factory is very frequently contaminated. The quality must be carefully monitored and equipment installed to automatically reject unsuitable returns. This problem can be eliminated by introducing a steam transformer between the station and the factory. This is simply a single stage evaporator. For it to work effectively the extraction steam pressure must be raised to at least 2,6 bar absolute (128,7 °C).

Fig. 6 illustrates a typical flow diagram incorporating a boiler with economiser, a turbine with controlled passout capabilities, steam transformer, an LP steam heated deaerator and first stage air preheater, a mud drum located feedwater heater and a hot water heated second stage air preheater. LP steam is used to preheat the primary combustion air from 25 °C to 107 °C. It is also used to heat the deaerator. Hot water from the economiser is used to heat the combustion air to about 200 °C in the second stage air preheater. This temperature is limited by the temperature of the water leaving the economiser. If the fuel moisture content exceeds 50 %, it may be preferable to use a higher air temperature and under these circumstances it is necessary to use hot water from the steam drum as the heating medium. Unfortunately circulating pumps with their concomitant problems are needed for this duty. Although more expensive in first cost, the problem can be sidestepped by using larger grate areas up to a moisture content of 52 %. Beyond this figure it is always preferable to use higher combustion air temperatures (+ 230 °C). Where economiser water is used, the energy to overcome the water side pressure drop across the air preheater is provided by the boiler feed pump.

To provide protection against dew point corrosion of the economiser, the feedwater is preheated by means of a heat exchanger located in the mud drum.

Table 2 - Stage Improvements in Energy Output per Ton of Fuel CONFIGURATION BAGASSE (%) COAL (%) 32 bar Boiler with gas/air preheater Base Base 32 bar Boiler with gas/air preheater and economiser 8.96 5.86 62 bar Boiler with gas/air preheater and economiser 11.26 19.60 62 bar Boiler with steam/air preheater 2.70 2.25

Medium pressure steam at say 13 bar can be extracted from the turbine to heat both the second stage air preheater and the feed water. The benefit of extracting at this pressure on the cycle energy balance will depend on the turbine characteristics. It is important to note that the bleed point need not be controlled. The extraction pressure can be allowed to decay with load as lower air temperatures can be tolerated at lower loads; i.e. lower grate ratings. In fact the limit on turndown will be dictated not by air preheater performance but rather by the need to maintain feedwater heater performance when burning sulphur bearing fossil fuels. The stage improvements in thermal cycle efficiency which increasing steam conditions and passout can provide are scheduled in Table 2. The results for oil firing are approximately the same as for coal.

Turbine manufacturers are comfortable with stop-valve conditions of 60 bar absolute 480 °C on machines of 10 - 25 Megawatt. On larger machines a case can be made for increasing these conditions to 80 bar, 520 °C. Fig. 7 shows how energy per ton fuel at the generator terminals varies with turbine stop-valve pressure and temperature conditions for the cycle illustrated in Figure 6. The curve applies broadly to all the fuels scheduled in Table 1.

       

Fig. 8 shows how energy per ton fuel with stop-valve conditions of 60 bar absolute 480 °C varies with load; whilst Fig. 9 shows how energy per ton fuel for the same machine varies with condenser pressure.

To arrive at saleable energy values, in-house energy consumption (7 to 10 % of generator terminal output) must be deducted from these figures. Corrections must be made for adverse wet bulb temperature conditions, plant deterioration factors and operating load cycles. Taken together, these factors can reduce the output energy available for sale by as much as 20 to 25 %. In addition, during the crop process energy consumption (steam and power) must also be deducted.

To provide steam at 520 °C at the turbine stop valve it must be generated at a minimum of 525 °C at the boiler stop valve to cater for heat lost along the line. Codes of construction typically require the superheater tubing to be designed to withstand the final steam temperature plus 50 °C. This translates into a design metal temperature of 575 °C. If factors such as variation in steam flow between elements and variations in gas temperature due to unstable combustion conditions or furnace fouling are taken into account the design metal temperature may well exceed 600 °C. At these temperatures tube metal quality selection becomes critical. Allowable stress levels fall rapidly with increasing temperature even if austenitic steels are selected.

The problem is compounded by two other factors. Firstly, if bagasse and coal have to be burned in the same furnace, the steam temperature when burning coal will normally be 20 - 30 °C lower than when burning bagasse. This means that to meet the required final steam temperature on coal, the superheater must be designed to give a steam temperature on bagasse of at least 555 °C. Secondly, to limit the fall off in station efficiency the steam temperature must be kept constant over a wide turndown range. As steam temperature normally falls with load the superheater must be significantly over-designed to cater for this condition.

Whilst interstage de-superheating can accommodate a wide range of conditions, it is questionable whether this can be done effectively with a two-stage superheater or whether a three-stage superheater is required. In either event consideration must be given to the desirability of commercially operating a plant at this high risk level.

The problem is not as severe when burning bagasse and oil in the same furnace. The difference between the steam temperature on bagasse and oil can be limited by placing the burners fairly high up in the furnace. In all cases automatic controls must be included to restore safe conditions in the event of a de-superheater failure.

PRACTICAL BOILER DESIGN

As the factors affecting the design of bagasse fired boilers used in conventional sugar factories are well documented, only those factors which have to be taken into account to accommodate a commercial power generation program are dealt with below. These are:

1. the design of the heat recovery equipment
2. the design of the superheater.

Heat Recovery Equipment Fig. 10 shows the arrangement of a typical industrial cane sugar industry bagasse-fired water tube boiler. The unit comprises a furnace, superheater, single-pass convection bank and gas to air preheater. It is designed to generate steam at 32 bar absolute, 405 °C. The gas temperature leaving the convection bank is 380 °C. The gas temperature leaving the air preheater is 270 °C. At this flue gas temperature, the efficiency of the boiler will be adequate to meet the steam demand of a conventional well balanced factory. Normally an economiser would be added only if there was a demand for surplus bagasse or steam for by-product manufacture. The saturation temperature of the water in the steam drum will be between 238 and 240 °C. If an economiser is fitted to reduce the flue gas temperature to 170 °C, the temperature of the water leaving the economiser will be about 172 °C. The difference between, these two temperatures is large enough to ensure that steaming in the economiser will only occur under severe upset operating conditions. Steaming should be avoided where it is possible for the feedwater to contain solids, as these can precipitate out in the economiser resulting in poor heat transfer characteristics and ultimately tube chokages. In a power station, as described previously, where steam extracted from the turbine can be used to preheat the air, it is only necessary to install economiser surface. Here the advantages of reducing the flue gas temperature to a low figure is clear-cut. For a final gas temperature of 150 °C the temperature of the water leaving the economiser will be 234 °C on bagasse. This is still well below the saturation temperature in the steam drum when operating at 60 bar.

Superheater Normally a superheater designed for a bagasse-fired industrial boiler will be partly shielded from direct furnace radiation by means of a furnace "nose". It may be shielded completely by means of a set of screen tubes. In both cases heat will be transferred to the superheater predominantly by means of non-luminous gas radiation and convection. By optimizing tube pitching the superheater can be designed to produce a relatively flat characteristic over a fairly large turndown ratio. To achieve power generation cycle temperatures of 480 - 520 °C a considerable part of the superheater has to "see" direct furnace radiation. Frequently this is done by means of platens in the furnace chamber. As mentioned above controlling steam temperature will be fraught with difficulties. Fig. 11 shows a typical co-generation style boiler with two-stage superheater with interstage de-superheating. De-superheating can be achieved either by means of direct water injection into the interstage line or by directing some of the steam through non-contact de-superheaters located either in the mud drum or steam drum. Whether it is desirable to use a third stage of de-superheating will depend entirely upon the uncontrolled characteristics of the design.

CONCLUSIONS

Steam power station cycle efficiencies can be improved by bleeding steam from the turbine for feedwater and combustion air preheating. In a cane sugar factory co-generation steam at the process extraction pressure can be used to preheat the feedwater in a deaerator and the combustion air in a primary air preheater. Hot water from the economiser or from the steam drum can be used to further preheat the combustion air. To prevent dew point corrosion, the feedwater can be heated by means of an exchanger located in the mud drum. Alternatively, steam at about 13 bar absolute can be bled from the turbine to further preheat the combustion air and feedwater.

Using bled steam to heat the combustion air steers the designer towards using economiser heat recovery surface instead of conventional gas/air heater recovery surface. It is possible at the higher steam conditions and hence the higher saturation temperatures to avoid steaming the economiser.

Interposing a steam transformer between the power station and the process plant prevents contaminated condensate being returned to the boiler plant. If the passout pressure is 2,6 bar the penalty paid for this safeguard will reduce output per ton bagasse by about 2,1 % . The cost of a steam transformer will add about 1,5 % to the cost of the station. On the other hand its operating costs are negligible. Increasing the passout pressure to 3,0 bar in order to reduce the cost of the transformer by about 40 % will reduce output by a further 1,1 %.

While char refiring is not recommended for conventional bagasse fired boilers, the gain in efficiency when burning coal warrants complicating dust hopper designs to accommodate refiring coal grits. Turbine stop valve conditions of 80 bar, 520 °C can be accommodated in boilers designed to bum bagasse and coal. Differences in heat transfer characteristics associated with these fuels complicates superheater design particularly if high turndown ratios are required These problems, although still difficult to resolve, are not as severe with boilers designed to bum bagasse and fuel oil.

When this paper was being prepared in 1994 it was based on work in hand for a real power station project which was, at that stage, in the conceptual design phase. Since then basic engineering has been completed and further enhancements to the efficiency of the thermodynamic cycle have been evaluated. Some of these new refinements have proved to be very attractive.

Clearly each project is unique and the findings for this project cannot be taken as absolute but they do demonstrate the importance of optimising the cycle before processing to detailed design.

Acknowledgments

I thank my colleagues, John Whitchurch and Dr Mike INKSON of Biotherm Ltd, London for their assistance in the preparation of this paper.

1. Magasiner: Proc. 15th Congr. ISSCT, 1974.

2. Magasiner et al.: Proc. 61st Ann.Congr. S. African Sugar Tech. Assoc., 1987

3. Magasiner & de Kock: Energy World, 1987.

4. Payne: "Cogeneration in the Cane Sugar Industry" Elsevier, Sugar Series 12, Arnstersdarn, 1991.

5. Magasiner: Journal of Energy in Southern Africa, 1993, 4, (1)

---