General options for reduction of sulphur emissions are:

i) Energy management measures:

*) Options (i) (a) and (b) are integrated in the energy structure and policy of a Party. Implementation status, efficiency and costs per sector are not considered here.

a) Energy saving

The rational use of energy (improved energy efficiency/process operation, cogeneration and/or demand-side management) usually results in a reduction in sulphur emissions.

b) Energy mix

In general, sulphur emissions can be reduced by increasing the proportion of non-combustion energy sources (i.e. hydro, nuclear, wind, etc) to the energy mix. However, further environmental impacts to be considered.

ii) Technological options:

a) Fuel switching

The SO2 emissions during combustion are directly related to the sulphur content of the fuel used.

Fuel switching (e.g. from high- to low-sulphur coals and/or liquid fuels, or from coal to gas) leads to lower sulphur emissions, but there may be certain restrictions, such as the availability of low-sulphur fuels and the adaptability of existing combustion systems to different fuels. In many ECE countries, some coal or oil combustion plants are being replaced by gas-fired combustion plants. Dual-fuel plants may facilitate fuel switching.

b) Fuel cleaning

Cleaning of natural gas is state-of-the-art technology and widely applied for operational reasons.

Cleaning of process gas (acid refinery gas, coke oven gas, biogas, etc.) is alo state-of-the-art technology.

Desulphurization of liquid fuels (light and middle fractions) is state-of-the-art technology.

Desulphurization of heavy fractions is technically feasible; nevertheless, the crude properties should be kept in mind. Desulphurization of atmospheric residue (bottom products from atmospheric crude distillation units) for the production of low-sulphur fuel oil is not, however, commonly practised; processing low-sulphur crude is usually preferable. Hydro-cracking and full conversion technology have matured and combine high sulphur retention with improved yield of light products. The number of full conversion refineries is as yet limited. Such refineries typically recover 80 to 90% of the sulphur intake and convert all residues into light products or other marketable products. For this type of refinery, energy consumption and investment costs are increased. Typical sulphur content for refinery products is given in table 1 below.

Table 1 Sulphur content from refinery products (S content (%))

Typical present values | Anticipated future values

Gasoline | 0.1 | 0.05

Jet kerosene | 0.1 | 0.01

Diesel | 0.05 - 0.3 | < 0.05

Heating oil | 0.1 - 0.2 | < 0.1

Fuel oil | 0.2 - 3.5 | < 1

Marine Diesel | 0.5 - 1.0 | < 0.5

Bunker oil | 3.0 - 5.0 | < 1 (coastal areas) < 2 (high seas)

Current technologies to clean hard coal can remove approximately 50% of the inorganic sulphur (depending on coal properties) but none of the organic sulphur. More effective technologies are being developed which, however, involve higher specific investment and costs. Thus the efficiency of sulphur removal by coal cleaning is limited compared to flue gas desulphurization. There may be a country-specific optimization potential for the best combination of fuel cleaning and flue gas cleaning.

c) Advanced combustion technologies

These combustion technologies with improved thermal efficiency and reduced sulphur emissions include: fluidized-bed combustion (FBC): bubbling (BFBC), circulating (CFBC) and pressurized (PFBC); integrated gasification combined-cycle (IGCC); and combined-cycle gas turbines (CCGT)

Stationary combustion turbines can be integrated into combustion systems in existing conventional power plants which can increase overall efficiency by 5 to 7 % leading, for example, to a significant reduction in SO2-emissions. However, major alternations to the existing furnace system become necessary.

Fluidized-bed combustion is a combustion technology for burning hard coal and brown coal, but it can also burn other solid fuels such as petroleum coke and low-grade fuels such as waste, peat and wood. Emissions can additionally be reduced by integrated combustion control in the system due to the addition of lime/limestone to the bed material. The total installed capacity of FBC has reached approximately 30.000 MWth (250 to 350 plants), incuding 8,000 MWth in the capacity range of greater than 50 MWth. By-products from this process may cause problems with respect to use and/or disposal, and further development is required.

The IGCC process includes coal gasification and combined-cycle power generation in a gas and steam turbine. The gasified coal is burnt in the combustion chamber of the gas turbine. Sulphur emission control is achieved by the use of state-of-the-art technology for raw gas cleaningfacilities upstream of the gas turbine. The technology also exists for heavy oil residues and bitumen emulsions. The installed capacity is presently about 1,000 MWel (5 plants).

Combined-cycle gas-turbine power stations using natural gas as fuel with an energy efficiency of approximately 48 to 52% are currently being planned.

d) Process and combustion modifications

Combustion modifications comparable to the measures used for NOx emission control do not exist, as during combustion the organically and/or inorganically bound sulphur is almost completely oxidized (a certain percentage depending on the fuel properties and combustion technology is retained in the ash).

In this annex dry additive processes for conventional boilers are considered as process modifications due to the injection of an agent into the combustion unit. However, experience has shown that, when applying these processes, thermal capacity is lowered, the Ca/S ratio is high and sulphur removal low. Problems with the further utilization of the by-product have to be considered, so that this solution should usually be applied as an intermediate measure and for smaller units (table 2).

Table 2 Emissions of sulphur oxides obtained from the application of technological options to fossil-fuelled boilers

Uncontrolled emissions | Additive injection | Wet scrubbinga) | Spray dry absorption b)

Reduction efficiency (%) Energy efficiency (kWel/10m3m3/h) | | up to 60 0.1-1 | 95 6-10 | up to 90 3-6

Total installed capacity (ECE Eur)(MWth) Type of by-product | | | Mix of CA salts and fly ashes | 194,000 Gypsum (sludge/waste water) | 16,000 Mix of CaSo3 * 1/2 H2O and fly ashes

Specific investment (cost ECU (1990)(kWel) | | | 20-50 | 60-250 | 50-220

mg/m3c) | g/kWhel | mg/m3c) | g/kWhel | mg/m3c) | g/kWhel | mg/m3c) | g/kWhel

Hard coald) | 1,000-10,000 | 3.5-35 | 400-4,000 | 1.4-14 | <400 (<200, 1% S) | <1.4 <0.7 | <400 (<200, 1% S) | <1.4 <0.7

Brown coald) | 1,000-20,000 | 4.2-84 | 400-8,000 | 1.7-33.6 | <400 (<200, 1% S) | <1.7 <0.8 | <400 (<200, 1% S) | <1.7 <0.8

Heavy oil d/ | 1,000-10,000 | 2.8-28 | 400-4,000 | 1.1-11 | <400 (<200, 1% S) | <1.1 <0.6 | <400 (<200, 1% S) | <1.1 <0.6

Ammonia scrubbing b/ | Wellman Lord a/ | Activated carbon a/ | Combined catalytic a)

Reduction efficiency (%) Energy efficiency (kWel/103 m3/h) | up to 90 3-10 | 95 10-15 | 95 4-8 | 95 2

Total installed capacity (ECE Eur)(MWh) Type of by-product | 200 Ammonia fertilizer | 2,000 Elemental S Sulphuric acid (99 vol.%) | 700 Elemental S Sulphuric acid (99 vol.%) | 1,300 Sulphuric acid (70 wt.%)

Specific investment (cost ECU(1990)/kW el) | 230-270e) | 200-300e) | 280-320e) f) | 320-350e) f)

mg/m3 c) | g/kWhm | mg/m3 c) | g/kWhel | mg/m3 c) | g/kWhel | mg/m3 c) | g/kWhel

Hard coal d/ | <400 (<200, 1%S) | <1.4 <0.7 | <400 (<200, 1%S) | <1.4 <0.7 | <400 (<200, 1%S) | <1.4 <0.7 | <400 (<200, 1%S) | <1.4 <0.7

Brown coal d/ | <400 (<200, 1%S) | <1.7 <0.8 | <400 (<200, 1%S) | <1.7 <0.8 | <400 (<200, 1%S) | <1.7 <0.8 | <400 (<200, 1%S) | <1.7 <0.8

Heavy oil d/ | <400 (<200, 1%S) | <1.1 <0.6 | <400 (<200, 1%S) | <1.1 <0.6 | <400 (<200, 1%S) | <1.1 <0.6 | <400 (<200, 1%S) | <1.1 <0.6

a) For high sulphur content in the fuel the removal efficiency has to be adapted. However, the scope for doing so may be process-specific. Availability of these processes is usually 95%.

b) Limited applicability for high-sulphur fuels.

c) Emission in mg/m3 (STP), dry, 6% oxygen for solid fuels, 3% oxygen for liquid fuels.

d) Conversion factor depends on fuel properties, specific fuel gas volume and thermal efficiency of boiler (conversion factors (m3 kWhel, thermal efficiency: 36%) used: hard coal: 3.50; brown coal: 4.20; heavy oil: 2.80).

e) Specific investment cost relates to a small sample of installations.

f) Specific investment cost includes denitrification process.

The table was established mainly for large combustion installations in the public sector. However, the control options are also valid for other sectors with similar exhaust gases.

e) Flue gas desulphurization (FGD) processes

These processes aim at removing already formed sulphur oxides, and are also referred to as secondary measures. The state-of-the-art technologies for flue gas treatment processes are all based on the removal of sulphur by wet, dry or semi-dry and catalytic chemical processes.

To achieve the most efficient programme for sulphur emission reductions beyond the energy management measures listed in (i) above a combination of technological options identified in (ii) above should be considered.

In some cases options for reducing sulphur emissions may also result in the reduction of emissions of CO2, NOx and other pollutants.

In public power, cogeneration and district heating plants, flue gas treatment processes used include: lime/limestone wet scrubbing (LWS); spray dry absorption (SDA); Wellman Lord process (WL); ammonia scrubbing (AS); and combined NOX/SOX removal processes (activated carbon process (AC) and combined catalytic NOx /SOx removal).

In the power generation sector, LWS and SDA cover 85% and 10% respectively, of the installed FGD capacity.

Several new flue gas desulphurization processes, such as electron beam dry scrubbing (EBDS) and Mark 13A, have not yet passed the pilot stage.

Table 2 above shows the efficiency of the above-mentioned secondary measures based on the practical experience gathered from a large number of implemented plants. The implemented capacity as well as the capacity range are also mentioned. Despite comparable characteristics for several sulphur abatement technologies, local or plant-specific influences may lead to the exclusion of a given technology.

Table 2 also includes the usual investment cost ranges for the sulphur abatement technologies listed in sections (ii) (c), (d) and (e). However, when applying these technologies to individual cases it should be noted that investment costs of emission reduction measures will depend amongst other things on the particular technologies used, the required control systems, the plant size, the extent of the required reduction and the time-scale of planned maintenance cycles. The table thus gives only a broad range of investment costs. Investment costs for retrofit generally exceed those for new plants.