The selected systems were modeled in Aspen Plus, a widely used process simu­lation program. In this flowsheeting program, chemical reactors, pumps, turbines, heat exchanging apparatuses, etc. are virtually connected by pipes. Every com­ponent can be specified in detail: reactions taking place, efficiencies, dimensions of heating surfaces, and so on. For given inputs, product streams can be calculated, or one can evaluate the influence of apparatus adjustments on electrical output. The plant efficiency can be optimized by matching the heat supply and demand. The resulting dimensions of streams and units and the energy balances can subsequently be used for economic analyses.

The pretreatment and gasification sections are not modelled, their energy use and conversion efficiencies are included in the energy balances, though. The models start with the synthesis gas composition from the gasifiers as given in Table 2.1

The heat supply and demand within the plant is carefully matched and aimed at maximizing the production of superheated steam for the steam turbine. The intention was to keep the integration simple by placing few heat exchangers per gas/water/steam stream. Of course, concepts with more process units demanding more temperature altering are more complex than concepts consisting of few units. First, an inventory of heat supply and demand was made. Streams matching in temperature range and heat demand/supply were combined: e. g., heating before the reformer by using the cooling after the reformer. When the heat demand is met, steam can be raised for power generation. Depending on the amount and ratio of high and low heat, process steam is raised in heat exchangers or drawn from the steam turbine: if there is enough energy in the plant to raise steam of 300°C, but barely superheating capacity, then process steam of 300°C is raised directly in the plant. If there is more superheating than steam-raising capacity, then process steam is drawn from the steam cycle. Steam for gasification and drying is almost always drawn from the steam cycle, unless a perfect match is possible with a heat-supplying stream. The steam entering the steam turbine is set at 86 bar and 510°C.

Table 2.4 summarizes the outcomes of the flowsheet models. In some concepts still significant variations can be made. In concept 4, the reformer needs gas for firing. The reformer can either be entirely fired by purge gas (thus restricting the recycle volume) or by part of the gasifier gas. The first option gives a somewhat higher methanol production and overall plant efficiency. In concept 5, one can choose between a larger recycle and more steam production in the boiler. A recycle of five times the feed volume, instead of four, gives a much higher

TABLE 2.4

Results of the Aspen Plus Performance Calculations for 430-MWth Input HHV Systems (equivalent to 380 MWth LHV for biomass with 30% moisture) of the Methanol Production Concepts Considered

HHV Output (MW)

1 IGT — Max H2, Scrubber, Liquid-Phase Methanol

Reactor, Combined Cycle

2 IGT, Hot Gas Cleaning, Autothermal Reformer,

Liquid-Phase Methanol Reactor with Steam Addition, Combined Cycle

3 IGT, Scrubber, Liquid Phase Methanol Reactor

with Steam Addition, Combined Cycle

4 BCL, Scrubber, Steam Reformer, Liquid-Phase

Methanol Reactor with Steam Addition and Recycle, Steam Cycle

5 IGT, Hot Gas Cleaning, Autothermal Reformer,

Partial Shift, Conventional Methanol Reactor with Recycle, Steam Turbine

6 BCL, Scrubber, Steam Reforming, Partial Shift,

Conventional Methanol Reactor with Recycle, Steam Turbine

1 Net electrical output is gross output minus internal use. Gross electricity is produced by gas turbine and/or steam turbine. The internal electricity use stems from pumps, compressors, oxygen separator, etc.

2 The overall energy efficiency is expressed as the net overall fuel + electricity efficiency on an HHV basis. This definition gives a distorted view, since the quality of energy in fuel and electricity is considered equal, while in reality it is not. Alternatively, one could calculate a fuel only efficiency, assuming that the electricity part could be produced from biomass at, e. g., 45% HHV in an advanced BIG/CC (Faaij et al. 1998), this definition would compensate for the inequality of electricity and fuel in the most justified way, but the referenced electric efficiency is of decisive importance. Another qualification for the performance of the system could use exergy: the amount of work that could be delivered by the material streams.

methanol production and plant efficiency. Per concept, only the most efficient variation is reported in Table 2.4.

Based on experiences with low calorific combustion elsewhere (Consonni et al. 1994; van Ree et al. 1995), the gas flows in the configurations presented here are expected to give stable combustion in a gas turbine. Table 2.4 only includes the advanced turbines. Advanced turbine configurations, with set high compressor and turbine efficiencies and no dimension restrictions, give gas turbine efficiencies of 41-52% and 1-2% point higher overall plant efficiency than conventional configurations. Based on the overall plant efficiency, the methanol concepts lie in a close range of 50-57%. Liquid-phase methanol production preceded by
reforming (concepts 2 and 4) results in somewhat higher overall efficiencies. After the pressurized IGT gasifier hot gas cleaning leads to higher efficiencies than wet gas cleaning, although not better than concepts with wet gas cleaning after a BCL gasifier.

Several units may be realized with higher efficiencies than considered here. For example, new catalysts and carrier liquids could improve liquid-phase meth­anol single-pass efficiency up to 95% (Hagihara et al. 1995). The electrical efficiency of gas turbines will increase by 2-3% points when going to larger scale

(Gas Turbine World 1997).