Three cofiring alternatives are analyzed in this study. Case A corresponds to the full displacement of natural gas for biomass in combined cycle power plants. Case В concerns a partial use of biomass, complementing natural gas in combined cycle power plants. Finally, Case C regards the use of biomass only to increase steam production, which is then used in the bottoming cycle (Rankine cycle) of a combined cycle.

All results presented here are based on computational simulations. For the purpose of simulation, some characteristics of the GE PG6101(FA) (a machine developed to operate continuously with low-heating-value fuel) were considered. Only one com­plementary result regarding Case В is based on GE Frame 7 class gas turbines, for which some characteristics of the GE PG9171(E) were taken.

The BIG-CC system considered in Cases A and В is based on an atmospheric air-blown gasifier. The gasification technology taken into account here — as well as the subsequent low-pressure gas cleaning system — is similar to that proposed by the Swedish company TPS (Termiska Processer AB). Some of the biomass projects that are aimed at the provision of electricity and are under development at pre­sent are based on atmospheric gasification technology. BIG-CC systems based on pressurized gasification are also an alternative and possibly would be more feasible for the range of capacities considered here. Atmospheric systems will probably present a lower biomass to electricity conversion efficiency but, on the other hand, in the short term, fewer problems can be expected with syngas production and its cleanup.

BIG-GT technology (generally speaking, gas turbine cycles integrated to bio­mass gasification) is still under development. The main technological issues in the demonstration of BIG-GT are concerned with (i) scaling-up the gasifier and gas­cleaning technologies and (ii) gas turbine adaptation to low-heating-content fuel. However, the main problems with the current demonstration projects seem to be the initial costs of first generation plants and the difficulties of arranging a reliable fuel supply for the lifetime of the project at a reasonable cost (Walter et al., 2000).

The simulation of BIG-CC systems is based on the schemes and hypothesis presented by Consonni and Larson (1996). Design conditions considered for the bagasse drying result in a moisture content of 15 per cent by weight at the gasifier entrance, the gas being used for drying is the HRSG flue gas. Gasification takes place with air injection, and the syngas leaves the gasifier at about 870°C.

Raw syngas composition was evaluated based on previous results of gasifier simulation performed by ASPEN® — Advanced System for Process Engineering (Walter et al., 1998b). As proxy, it was considered that sugarcane trash has the same ultimate analysis as bagasse. Bagasse and syngas compositions (raw and clean) considered in this study are presented in Table 9.1.

A code was used to evaluate gas turbine off-design performance, i. e. the gas turbine operation with syngas. Details of the procedure can be seen in Walter et al. (1998a). To avoid very high compressor pressure ratio that could dangerously reduce compressor surge margin, gas turbine derating was considered. The rise of pressure ratio under certain limits can be eventually accepted for the compressor of some industrial gas turbines (Corman and Todd, 1993) but, in general, high-pressure ratio imposes unacceptable problems concerned with the increase of shaft torque and thermal loads on airfoils, making this option very aggressive to the equipment (Johnson, 1990). For syngas burning, it was assumed that the maximum GT com­pressor pressure ratio is 16.4, while its nominal pressure ratio at ISO basis is 14.9.

A common way to derate gas turbines, i. e. to reduce their output power, is through the reduction of the maximum temperature, which is accomplished with the reduction of fuel flow. The term derating is used here to indicate a strategy for gas turbine control to avoid machine operation with a high pressure ratio. In fact,

gas turbine derating is one of the possible strategies that would allow machine conversion from natural gas to syngas. Other strategies are (i) reducing compressor air flow through control of inlet guide vanes — IGVs, (ii) enlarging the expander cross-sectional area in a permanent change, and (iii) promoting blast-air extraction after the compressor. From the viewpoint of the whole system performance, and consequently from the viewpoint of electricity generating costs, derating is the worst solution (Rodrigues et al., 2003a). However, owing to its simplicity, for the first generation of BIG-CC systems, this is most probably the way gas turbines would be converted to syngas firing.

To simplify the modeling procedure, it was considered that steam is produced in an unfired HRSG at just one pressure level, without reheating. This is a reasonable hypothesis for stand-alone BIG-CC cycles due to the requirement of a minimum temperature for HRSG exhaust gases (Consoni and Larson, 1996), but it is not the case for combined cycles burning natural gas. Indeed, it is well known that high efficiency combined cycles require two or three steam pressure levels besides reheat­ing (Bathie, 1996). For instance, for the combined cycle based on PG6101(FA), when natural gas is burned, three steam pressure levels and reheating at the intermediate pressure level is recommended. It is considered that the steam pressure at the turbine entrance is 100 bar. Steam temperature is a function of the GT exhaust gases tem­perature, while the maximum steam temperature was assumed to be 538°C. Steam is extracted from the steam turbine at 0.48 MPa to feed the deaerator, while the remaining flow is condensed at 9.6 kPa. The temperature of the HRSG feed water is assumed to be constant in all the simulated cases (120°C).

9.4. SIMULATION AND FEASIBILITY RESULTS Case A

Simulation results considering combined cycle operation using only natural gas or biomass-derived gas are presented in Table 9.2. A detailed information about this alternative can be found in Walter et al. (1998b). These simulation results correspond to combined cycle operations under the ISO basis. As can be seen, despite derating, the thermal efficiency of a gas turbine operating with syngas is higher than with natural gas, owing to the increase on gas mass flow and to the higher GT compressor pressure ratio. With syngas firing, more power is also produced by the steam bottoming cycle due to the increase of GT exhaust gas flow, but steam is produced at a lower temperature (lower exhaust gas temperature). Albeit more power production both at the gas turbine and at the steam cycle, the system net power is lower when syngas is burned due to high power consumption of plant auxiliaries (mainly the syngas compressor). As mentioned before, the simulation results for natural gas combined cycle are not optimized as it is considered that steam is generated at just one pressure level at the HRSG. A single combined cycle unit (one gas turbine, one HRSG and one steam turbine) of the same capacity can operate with efficiency as high as 53 per cent (Gas Turbine World, 2000).

For current commercial natural gas combined cycles (NG-CC), data of unit capital costs were taken from the literature (Gas Turbine World, 2000). The turnkey unit capital cost of a combined cycle based on PG6101(FA) is estimated at 680US$/kW. The levelized electricity generating cost was calculated considering the following assumptions: 30-year life, 12 per cent real pretax discount rate, capacity factor 0.85,

O&M (operation and maintenance) costs at 0.4 cents/kWh, and natural gas cost equivalent to 2.5 S/MMBTU. All costs in this study are presented in 1999 US$.

For BIG-CC systems based on atmospheric air-blown gasifiers, the installed investment cost was estimated using Eq. (1). This equation is primarily based on estimates available in the literature for the first commercial plant and incorpo­rates “learning effects” (progress ratio 0.80 and the 5th similar commercial unit). Estimates given by this equation are very close to the estimates presented by other authors for BIG-CC systems of the same net capacity.

kA igcc = 5612 (MW)’0’2953 [$/kW] (1)

For BIG-CC systems, the nonfuel operation and maintenance cost was estimated at 8.2 US$/MWh. The average cost of biomass (bagasse and trash) was estimated at 8 US$/t. To assure a proper comparison with NG-CC results, some assumptions are common in both cases as, for instance, plant-year life, real discount rate and plant capacity factor.

Estimated levelized electricity generating costs are presented in Table 9.3. The feasibility analysis is based on the evaluation of the internal discount rate (IDR) of the investment. Besides the aforementioned assumptions, it was also considered that (i) the plant construction time is two years in all cases, and 80 per cent of the investment is made during the first year, (ii) taxes are evaluated over the net revenue (as a simplification, a 15 per cent duty was considered), and (iii) the depreciation was calculated along 10 years, using a linear model. Revenues were calculated consi­dering that all electricity can be sold at 45 US$/MWh. Actually, this assumption does not correspond to the reality of the electricity market post deregulation since, in a competitive environment, investors need to define their prices either based on their actual generating costs or on their own profit expectation.

The cofiring case presented in Table 9.3 corresponds to the substitution of fuel, from natural gas to biomass. It was considered that the investment leading to this

substitution starts after four years of operation with natural gas. After the sixth year of operation, just syngas is burned at the gas turbine. The investment required for the substitution was estimated as the difference of the installed unit capital cost for both the options.

The feasibility analysis also includes the evaluation of the impact of credits based on avoided emissions of carbon dioxide. These credits could be paid, for instance, by international funds on the context of the Clean Development Mechanism to boost projects aimed at reducing carbon dioxide emissions. It was considered that these credits are free of tax duties. Simplifying the analysis, it was also considered that sugarcane has a nil carbon balance. As can be seen in Table 9.3, each dollar earned per ton of carbon dioxide not released could imply an increment on the IDR of about 0.2 per cent. The results considered two options for the natural gas combined cycle — 46 per cent, that is the simulation result, and 53 per cent, that is the expected thermal efficiency of a single combined cycle unit based on a Frame 6(FA) gas turbine (steam produced at three pressure levels, with reheating).