An economic evaluation has been carried out for the concepts considered. Plant sizes of 80, 400, 1000, and 2000 MWth HHV are evaluated, 400 MWth being the base scale. The scale of the conversion system is expected to be an important factor in the overall economic performance. This issue has been studied for BIG/CC systems (Faaij et al. 1998; Larson et al. 1997), showing that the econ­omies of scale of such units can offset the increased costs of biomass transport up to capacities of several hundreds of MWth. The same reasoning holds for the methanol production concepts described here. It should, however, be realized that production facilities of 1000-2000 MWth require very large volumes of feedstock: 200-400 dry tonne/hour or 1.6-3.2 dry Mtonne per year. Biomass availability will be a limitation for most locations for such large-scale production facilities, especially in the shorter term. In the longer term (2010-2030), if biomass pro­duction systems become more commonplace, this can change. Very large scale biomass conversion is not without precedent: various large-scale sugar/ethanol plants in Brazil have a biomass throughput of 1-3 Mtonne of sugarcane per year, while the production season covers less than half a year. Also, large paper and pulp complexes have comparable capacities. The base scale chosen is comparable to the size order studied by Williams et al. (1995) and Katofsky (1993), 370-385 MWth.

The methanol production costs are calculated by dividing the total annual costs of a system by the produced amount of methanol. The total annual costs consist of:

1. Annual investments.

2. Operating and maintenance.

3. Biomass feedstock.

4. Electricity supply/demand (fixed power price).

The total annual investment is calculated by a factored estimation (Peters et al. 1980), based on knowledge of major items of equipment as found in the literature or given by experts. The uncertainty range of such estimates is up to ±30%. The installed investment costs for the separate units are added up. The unit investments depend on the size of the components (which follow from the

Aspen Plus modelling), by scaling from known scales in literature (see Table 2.5), using Equation 2.8:

with R = scaling factor.

Various system components have a maximum size, above which multiple units will be placed in parallel. Hence the influence of economies of scale on the total system costs decreases. This aspect is dealt with by assuming that the base investment costs of multiple units are proportional to the cost of the maximum size: the base investment cost per size becomes constant. The maximum size of the IGT gasifier is subject to discussion, as the pressurised gasifier would logically have a larger potential throughput than the atmospheric BCL.

The total investment costs include auxiliary equipment and installation labour, engineering and contingencies. If only equipment costs, excluding installation, are available, those costs are increased by applying an overall installation factor of 1.86. This value is based on 33% added investment to hardware costs (instrumen­tation and control 5%, buildings 1.5%, grid connections 5%, site preparation 0.5%, civil works 10%, electronics 7%, and piping 4%) and 40% added installation costs to investment (engineering 5%, building interest 10%, project contingency 10%, fees/overheads/profits 10%, and start-up costs 5%) (Faaij et al. 1998).

The annual investment takes into account the technical and economic lifetime of the installation. The interest rate is 10%.

Operational costs (maintenance, labour, consumables, residual streams dis­posal) are taken as a single overall percentage (4%) of the total installed invest­ment (Faaij et al. 1998; Larson et al. 1998). Differences between conversion concepts are not anticipated.

It was assumed that enough biomass will be available at 2 US$/GJ (HHV). This is a reasonable price for Latin and North American conditions. Costs of cultivated energy crops in the Netherlands amount approximately 4 US$/GJ and thinnings 3 US$/GJ (Faaij 1997), and biomass imported from Sweden on a large scale is expected to cost 7 US$/GJ (1998). On the other hand biomass grown on Brazilian plantations could be delivered to local conversion facilities at 1.6—1.7 US$/GJ (Hall et al. 1992; Williams et al. 1995). It has been shown elsewhere that international transport of biomass and bioenergy is feasible against modest costs.

Electricity supplied to or demanded from the grid costs 0.03 US$/kWh. The annual load is 8000 hours.

Results

Results of the economic analysis are given in Figure 2.7. The 400 MWth conversion facilities deliver methanol at 8.6-12 US$/GJ. Considering the 30%

TABLE 2.5 Costs of System Components in MUS$20011 Unit Base Investment Cost (fob) Scale Factor Base Scale Overall Installation Factor22 Maximum Size23 Pretreatment2 Conveyers3 0.35 0.8 33.5 wet tonne/hour 1.86 (v) 110 Grinding3 0.41 0.6 33.5 wet tonne/hour 1.86 (v) 110 Storage3 1.0 0.65 33.5 wet tonne/hour 1.86 (v) 110 Dryer3 7.6 0.8 33.5 wet tonne/hour 1.86 (v) 110 Iron removal3 0.37 0.7 33.5 wet tonne/hour 1.86 (v) 110 Feeding system3,4 0.41 1 33.5 wet tonne/hour 1.86 (v) 110 Gasification System BCL5 16.3 0.65 68.8 dry tonne/hour 1.69 83 IGT6 38.1 0.7 68.8 dry tonne/hour 1.69 75 Oxygen plant 44.2 0.85 41.7 tonne O2/hour 1 — (installed)7 Gas cleaning Tar cracker3 3.1 0.7 34.2 m3 gas/s 1.86 (v) 52 Cyclones3 2.6 0.7 34.2 m3 gas/s 1.86 (v) 180 High-temperature heat 6.99 0.6 39.2 kg steam/s 1.84 (v) — exchanger8 Baghouse filter3 1.6 0.65 12.1 m3 gas/s 1.86 (v) 64 Condensing scrubber3 2.6 0.7 12.1 m3 gas/s 1.86 (v) 64 Hot gas cleaning9 30 1.0 74.1 m3 gas/s 1.72 (v) — Synthesis Gas Processing Compressor10 11.1 0.85 13.2 MWe 1.72 (v) — Steam reformer11 9.4 0.6 1390 kmol total/hour 2.3 (v) — Autothermal reformer12 4.7 0.6 1390 kmol total/hour 2.3 (v) — Shift reactor 36.9 0.85 15.6 Mmol CO+H2/hour 1 — (installed)13 Selexol CO2 removal 54.1 0.7 9909 kmol CO2/hour 1 — (installed)14 Methanol Production Gas-phase methanol15 7 0.6 87.5 tonne MeOH/hour 2.1 (v) — Liquid-phase 3.5 0.72 87.5 tonne MeOH/hour 2.1 (v) — methanol16 Refining17 15.1 0.7 87.5 tonne MeOH/hour 2.1 (v) Power isle18 Gas turbine + HRSG3,19 18.9 0.7 26.3 MWe 1.86 (v) —

TABLE 2.5 (CONTINUED) Costs of System Components in MUS$20011 Unit Base Investment Cost (fob) Scale Factor Base Scale Overall Installation Maximum Factor22 Size23 Steam turbine + steam 5.1 0.7 10.3 MWe 1.86 (v) — system3,20 Expansion turbine21 4.3 0.7 10.3 MWe 1.86 (v) —

1 Annual GDP deflation up to 1994 is determined from OECD (1996) numbers. Average annual GDP deflation after 1994 is assumed to be 2.5% for the United States, 3.0% for the EU. Cost numbers of Dutch origin are assumed to be dependent on the EU market, therefore EU GDP deflators are used. 12001 = 0.94 US$2001 = 2.204 M2001.

2 Total pretreatment approximately sums up to a base cost of 8.15 MUS$2001 at a base scale of 33.5 tonne wet/hour with an R factor of 0.79.

3 Based on first-generation BIG/CC installations. Faaij et al. (1995) evaluated a 29-MWe BIG/CC installation (input 9.30 kg dry wood/s, produces 10.55 Nm3 fuel gas/s) using vendor quotes. When a range is given, the higher values are used (Faaij et al. 1998). The scale factors stem from Faaij et al. (1998).

4 Two double-screw feeders with rotary valves (Faaij et al. 1995).

5 12.72 MUS$1991 (already includes added investment to hardware) for a 1650 dry tonne per day input BCL gasifier, feeding not included, R is 0.7 (Williams et al. 1995). Stronger effects of scale for atmospheric gasifiers (0.6) were suggested by Faaij et al. (1998). Technical director Mr. Paisley of Battelle Columbus, quoted by Tijmensen (2000), estimates the maximum capacity of a single BCL gasifier train at 2000 dry tonnes/day.

6 29.74 MUS$1991 (includes already added investment to hardware) for a 1650 dry tonne/day input IGT gasifier, R = 0.7 (Williams et al. 1995). Maximum input is 400-MW^ HHV (Tijmensen 2000).

7 Air Separation Unit: Plant investment costs are given by Van Dijk (van Dijk et al. 1995): I = 0.1069C08508 in MUS$1995 installed, C = Capacity in tonne 02/day. The relation is valid for 100 to 2000 tonne 02/day. Williams et al. (1995) assume higher costs for small installations, but with a stronger effect of scale: I = 0.260C0712 in MUS$1991 fob plus an overall installation factor of 1.75 (25% and 40%). Larson et al. (1998) assume lower costs than Van Dijk, but with an even stronger scaling factor than Williams: 27 MUS$1997 installed for an 1100 tonne O2 per day plant and R=0.6. We have applied the first formula (by Van Dijk) here. The production of 99.5% pure O2 using an air separation unit requires 250-350 kWh per tonne O2 (van Dijk et al. 1995; van Ree 1992).

8 High-temperature heat exchangers following the gasifier and (in some concepts) at other locations are modelled as HRSGs, raising steam of 90 bar/520°C. A 39.2-kg steam/s unit costs 6.33 MUS$1997 fob, overall installation factor is 1.84 (Larson et al. 1998).

9 Tijmensen (2000) assumes the fob price for hot gas cleaning equipment to be 30 MUS$2000 for a 400-MWth HHV input. This equals 74.1 m3/s from a BCL gasifier (T = 863°C, 1.2 bar). There is no effect of scaling.

10Katofsky (1993) assumes compressors to cost 700 US$1993 per required kWmech, with an installation factor of 2.1. The relation used here stems from the compressor manufacturer Sulzer quoted by (2000). At the indicated base scale, total installed costs are about 15% higher than assumed by Katofsky. Multiple compressors, for synthesis gas, recycle streams, or hydrogen, are considered as separate units. The overall installation factor is taken 1.72 because the base unit matches a 400-MWth plant rather than a 70-MWth plant.

TABLE 2.5 (CONTINUED) Costs of System Components in MUS$20011 Base Overall Investment Scale Installation Maximum Unit Cost (fob) Factor Base Scale Factor22 Size23

investments for steam reformers vary from 16.9 MUS$^3, for a throughput of 5800 kmol meth — ane/hour with an overall installation factor of 2.1 (Katofsky 1993) to 7867 k$^5 for a 6.2 kg methane/s (1390 kmol/hour), overall installation factor is 2.3 (van Dijk et al. 1995). These values suggest a strong effect of scaling R = 0.51, while Katofsky uses a modest R = 0.7. Here, we use the values of Van Dijk in combination with an R factor of 0.6. The total amount of moles determines the volume and thus the price of the reactor.

12 Autothermal reforming could be 50% cheaper than steam reforming (Katofsky 1993), although higher costs are found as well (Oonk et al. 1997).

investment for shift reactors vary from 9.02 MU$^5 for an 8819 kmol CO+H/hr reactor, and an overall installation factor is 1.81 (Williams et al. 1995) to 30 MUS$^ installed for a 350000 Nm3/hr CO+H2/hr (15625 kmol/hr) reactor (Hendriks 1994). Williams assumes an R = 0.65, but comparison of the values suggest only a weak influence of scale (R = 0.94). Here, we use the the values from Hendriks, with R set at 0.85. A dual shift is costed as a shift of twice the capacity.

14Costs for CO2 removal through Selexol amounts 14.3 MUS$^3 fob (overall installation factor is 1.87) for an 810 kmol CO2/hr unit, R = 0.7 (Katofsky 1993) up to 44 MUS$^ installed for a 9909 kmol CO2/hour unit (Hendriks 1994). The value from Hendriks is assumed to be right, since his research into CO2 removal is comprehensive.

15Van Dijk et al. (1995) estimate that a methanol reactor for a 2.1 ktonne methanol per day plant costs 4433 kUS$1995 (fob) or 9526 kUS$1995 installed (overall installation factor is 2.1). The total plant investment in their study is 138 MUS$1995, or 150 MUS$2001. Katofsky (1993) estimates the costs for a 1056 tonne methanol/day plant to be 50 MUS$1995 fob, this excludes the generation and altering of synthesis gas, but includes make-up and recycle compression and refining tower. A 1000 tpd plant costs about 160 MUS$2001, and a 2000 tpd plant 200 MUS$2001, which suggests a total plant scale factor of 0.3 (Hamelinck et al. 2001). These values come near the ones mentioned by Katofsky. This implies that the values given by Van Dijk are too optimistic and should be altered by a factor 1.33. It is therefore assumed that the base investment for the methanol reactor only is 7 MUS$2001, the installation factor is 2.1. The influence of scale on reactor price is not assumed to be as strong as for the complete plant: 0.6.

installed costs for a 456 tonne per day liquid-phase methanol unit, are 29 MU$^7, excluding generation and altering of synthesis gas, but including make-up and recycle compression, and refining tower. R = 0.72 (Tijm et al. 1997). Corrected for scale and inflation this value is about half the cost of the conventional unit by Katofsky and the corrected costs of Van Dijk. It is therefore assumed that the price of a liquid-phase methanol reactor is 3.5 MUS$2001 for a 2.1 ktonne per day plant, installation factor is 2.1.

17Cost number for methanol separation and refining is taken from Van Dijk, increased with 33% as described in note 15.

18For indication: A complete combined cycle amounts to about 830 US$^7 per installed kWe. Quoted from Solantausta et al. 1996 by Oonk et al. 1997.

19Scaled on gas turbine size.

system consists of water and steam system, steam turbine, condenser and cooling. Scaled on steam turbine size.

21 Expansion turbine costs are assumed to be the same as steam turbine costs (without steam system). 22Overall installation factor. Includes auxiliary equipment and installation labor, engineering and contingencies. Unless other values are given by literature, the overall installation factor is set 1.86 for a 70-MWth scale (Faaij et al. 1998). This value is based on 33% added investment to hardware costs (instrumentation and control 5%, buildings 1.5%, grid connections 5%, site preparation 0.5%, civil works 10%, electronics 7%, and piping 4%) and 40% added installation costs to investment (engineering 5%, building interest 10%, project contingency 10%, fees/overheads/profits 10%, and start-up costs 5%). For larger scales, the added investments to hardware decreases slightly.

23 Maximum sizes from Tijmensen (2000).

uncertainty range, one should be careful in ranking the concepts. Methanol 4 and 6 perform somewhat better than the other concepts due to an advantageous combination of lower investment costs and higher efficiency. The lowest methanol production price is found for concepts using the BCL gasifier, having lower investment costs. The combination of an expensive oxygen fired-IGT gasifier

with a combined cycle seems generally unfavorable, since the efficiency gain is small compared to the high investment.

Investment redemption accounts for 42-76% of the annual costs and is influ­enced by the unit investment costs, the interest rate and the plant scale. The build­up of the total investment for all concepts is depicted in Figure 2.8. It can be seen that the costs for the gasification system (including oxygen production), synthesis gas processing and power generation generally make up the larger part of the investment. For autothermal reforming higher investment costs (Oonk et al. 1997) would increase the methanol price from considered concepts by about 1.5 US$/GJ. Developments in gasification and reforming technology are impor­tant to decrease the investments. On the longer term, capital costs may reduce due to technological learning: a combination of lower specific component costs and overall learning. A third plant built may be 15% cheaper leading to an 8-15% product cost reduction.

The interest rate has a large influence on the methanol production costs. At a rate of 5% methanol production costs decrease with about 20% to 7.2-9.0 US$/GJ. At a high-interest rate (15%), methanol production costs become 9.9-14 US$/GJ. Going to 1000 and 2000 MWth scales, the methanol production costs reach cost levels as low as 7.1-9.5 US$/GJ.

Feedstock costs account for 36-62% of the final product costs for the men­tioned technologies. If a biomass price of 1.7 US$/GJ could be realized (a realistic price for, e. g., Brazil), methanol production costs would become 8.0-11 US$/GJ for 400 MWth concepts. On the other hand, when biomass costs increase to 3 US$/GJ (short term Western Europe), the production cost of methanol will increase to 10-16 US$/GJ.

FIGURE 2.9 Optimistic view scenario. Different cost reductions are foreseeable: (1) biomass costs 1.7 US$/GJ instead of 2 US$/GJ, (2) technological learning reduces capital investment by 15% and (3) application of large scale (2000 MWth) reduces unit investment costs.

If the electricity can be sold as green power, including a carbon neutral premium, the fuel production costs for power coproducing concepts drops, where the green premium essentially pays a large part of the fuel production costs. A power price of 0.08 US$/GJ would decrease methanol costs to -0.6-9.5 US$/GJ. Of course the decrease is the strongest for concepts producing more electricity. A green electricity scenario, however, may be a typical western Euro­pean scenario. As such it is unlikely that it can be realized concurrent with biomass available at 1.7 US$/GJ.

In the long term, different cost reductions are possible concurrently (Tij — mensen 2000). Biomass could be widely available at 1.7 US$/GJ, capital costs for a third plant built are 15% lower, and the large (2000 MWth) plants profit from economies of scale. These reductions are depicted in Figure 2.9: methanol concepts produce between 6.1-7.4 US$/GJ. The influence of capital redemption on the annual costs has strongly reduced and the fuel costs of the different concepts lie closer together.

Previous analyses on short-term methanol production by Katofsky (1993) and Williams et al. (372 MWHHV, 3.4 US$/GJHHV feedstock, 0.07 US$/kWhe (Williams 1995; Williams et al. 1995)) yielded similar energy efficiencies (54-61% by HHV), but significantly higher methanol production costs: 14-17 US$/GJHHV. The largest difference is in the higher capital costs: higher TCI and higher annuity give 25-50% higher annual capital costs. The ADL/GAVE study (Arthur D. Little 1999) reports 13 US$/GJ methanol (feed 2 US$/GJ, 433 MW input) largely using input parameters from Katofsky. Komiyama et al. (2001) instead give much lower costs than presented here: 5 US$/GJHHV for methanol at 530 MWHHV biomass
input. However, in that study, process efficiencies and biomass cost are not given and a significant amount of energy is added as LPG.

In these long-term scenarios, methanol produced from biomass costs consid­erably less than methanol at the current market, which is priced about 10 US$/GJ (Methanex 2001). For application as automotive fuel, comparison with gasoline and diesel is relevant. Their production costs vary strongly depending on crude oil prices, but for an indication: 2003 gasoline market prices were about 7 US$/GJ at oil prices of 25-30 US$/bbl (BP 2004). DOE/EIA projects the world oil price in 2013 to amount between 17 and 34 US$, crude oil prices may decline as new deepwater oil fields are brought into production in the Gulf of Mexico and West Africa, new oil sands production is initiated in Canada, and OPEC and Russia expand production capacity (DOE/EIA 2005). In 2004 the average oil price was some 35 US$/bbl and currently even higher prices of about 50 US$/bbl are paid.

CONCLUSIONS

Methanol can be produced from wood via gasification. Technically, all necessary reactors exist and the feasibility of the process has been proven in practice. Many configurations are possible, of which several have been discussed in this chapter. The configurations incorporated improved or new technologies for gas processing and synthesis and were selected on potential low cost or high-energy efficiency. Some configurations explicitly coproduced power to exploit the high efficiencies of once-through conversion. The overall HHV energy efficiencies remain around 55%. Accounting for the lower energy quality of fuel compared to electricity, once-through concepts perform better than the concepts aiming at fuel only production. Also hot gas cleaning generally shows a better performance. Some of the technologies considered in this chapter are not yet fully proven/commer — cially available. 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. At larger scales, conversion and power systems (especially the combined cycle) may have higher efficiencies, but this has not been researched in depth.

The methanol production costs are calculated by dividing the total annual costs of a system by the produced amount of methanol. Unit sizes, resulting from the plant modelling, are used to calculate the total installed capital of methanol plants; larger units benefit from cost advantages. Assuming biomass is available at 2 US$/GJ, a 400 MWth input system can produce methanol at 9-12 US$/GJ, slightly above the current production from natural gas prices. The outcomes for the various system types are rather comparable, although concepts focussing on optimized fuel production with little or no electricity coproduction perform some­what better.

The methanol production cost consists of about 50% of capital redemption, of which the bulk is in the gasification and oxygen system, synthesis gas proc­essing and power generation units. Further work should give more insight into investment costs for these units and their dependence to scale. The maximum possible scale of particularly the pressurized gasifier gives rise to discussion. The operation and maintenance costs are taken as a percentage of the total investment, but may depend on plant complexity as well. Long-term (2020) cost reductions mainly reside in slightly lower biomass costs, technological learning, and application of large scales (2000 MWth). This could bring the methanol production costs to about 7 US$/GJ, which is in the range of gasoline/diesel.

Methanol from biomass could become a major alternative for the transport sector in a world constrained by greenhouse gas emission limits and high oil prices.