Material Balance Mghr

Mass In

Wood to plant 50.245

C.T. Compressor air 680.653

Boiler feed water 9.659

Dolomite __0.893.

Total 741.451

Mass Out

Fuel prep moisture losses 1.607

Fuel prep fines 0

Fuel prep ferrous metal 0

Ash and char from gasifier 2.620

Air sep plant effluent 16.472

Solids from hot gas filter 0.026

Flue gas from combustion turbine 715.990

Blowdown __4_737

Total 741.451

Performance Summary

Annual capacity factor, % 80%

Net kJ/kWh 10000

Thermal Efficiency, % 36.0%

Figure 4. Material and energy balance for the 1997 base case.

reasonable. DeLong [1] also estimates availability to be between 82% and 88% based on experience with the Tampella gasification pilot facility. Based on these data, a plant capacity factor of 80% is assumed.

The cost and performance for the 1997 case are expected to be those for a first plant. All costs are expressed in constant 1997 dollars. A 30-year project life is assumed, after a two year construction period. The electrical substation is part of the general plant facilities, and is not separated out in the factor analysis. The convention followed is tha t used in the EPRI TAG [6], specifically "It also includes the high-voltage bushing of the generation step-up transformer but not the switchyard and associated transmission lines. The transmission lines are generally influenced b y transmission system-specific conditions and hence are not included in the cost estimate."

Cost reductions and performance improvements through 2010 are expected to be largely the result of replication of , and minor technical improvements to, the 1997 case plant. The largest cost reductions occur in the least commercially mature plant sections, i.e. gasification and hot gas cleanup. The first plant costs for these sections normally includ e very substantial process contingencies and reflects an aggressive equipment "sparing" strategy to guarantee high on -stream factors. As experience is gained with these processes, design details will improve and appropriate maintenance schedules will be developed that minimize the need for large contingencies and spare equipment. Cost reductions also occur in the balance of plant equipment (BOP). In the base, first-of-a-kind case, the BOP cost, taken as a percentag e of the other equipment cost, is a very high 35% which again reflects the uncertainties involved in pioneer plants. This is gradually reduced to a more common value of 21% in the mature 2010 case. Overall, these capital costs are reduced by roughly 30% during progression from pioneer plant to mature technology. A similar progression is represented i n the EPRI TAG [6] (p. 8-5). Operating labor costs are similarly reduced as more activities can be brought unde r automated control and operating labor is reduced to a practical minimum.

The gasifier technology is assumed to be largely mature by the 2010 time frame. The fully mature (2010) system costs correlate well with mature plant costs projected by those demonstrating coal gasification combined cycle at a larg e scale. For example, the $2,400/kW first plant cost for the Demkolec plant is projected to be $1,500/kW on a matur e technology basis [22]. Similarly, the $1,646/kW cost for the Puertollano plant declines to $1,000/kW for the nth plant

[22]. The 2010 cost is also consistent with cost data on natural gas fired combined cycle systems. Gas Turbine World

[23] reports a turnkey price for a natural gas fired combined cycle plant using the 251B12 turbine of $713/kW. Adding to this the cost for biomass feed handling and gasification yields a capital cost of approximately $1,200/kW. This i s the lower bound of the nth plant cost posited in Turnure et al. [24] Additional cost reductions beyond 2010 are largely due to improvements in system efficiency which reduce the amount of biomass required (and therefore equipment size) for each megawatt of power generated.

Performance increases from 2000-2010 are the result of gradual improvements to the technology and, in the 2005 case, adoption of more advanced turbine technology using higher firing temperatures (1,288°C, or 2,350°F) and improve d steam cycle conditions. The efficiency gains in the 2000 case are assumed to result from improved system integratio n and the continuing improvement of gas turbine technology. Gas turbines in this size range have increased output an d efficiency by 2-4% since 1991 [23].

The ATS program is a $700 million effort funded by DOE and gas turbine manufacturers that has a target of 60 % efficiency (LHV basis) for utility gas turbine combined cycle plants by the year 2000. The industrial turbine portio n of the program targets efficiency improvements of at least 15% (from 29 to at least 34% simple cycle efficiency) in the same time period. The ATS program includes in its goals the criteria that the turbines developed be suitable for coa l or biomass fuels. It is assumed that this technology will have penetrated the biomass market after the 2010 time frame. As an upper limit, the 60% combined cycle efficiency (LHV basis) goal on natural gas fuel translates into roughly 50% efficiency (HHV basis) on biomass fuel. The higher firing temperatures being utilized by these advanced turbines (up to 1,426°C or 2,600°F) can result in up to 5 basis points improvements in turbine efficiencies. Additional benefits from advanced turbines include the use of STIG technology. STIG turbines are commercially available today for natura l gas fuels up to approximately 50 MWe output at FOB costs of approximately $280/kW. Increased efficiency, and therefore power output should reduce this cost on a dollar per kilowatt basis. These turbines further reduce system cost by eliminating the need for a steam cycle while still maintaining high specific power output. The 2010 and beyon d systems assume that this innovation is available for advanced turbine systems. The 2020-2030 cases utilize cost an d efficiency data from Turnure et al. (1995) for early and mature gas turbines utilizing ATS and CAGT technology.

Feed costs in this characterization are expressed in 1997 dollars and represent an update of the DOE feedstock goal for dedicated feedstocks of $2.50/GJ. If residue feeds are used instead, then feed costs are approximately $18.7/tonne ($0.95/GJ; $1/MMBtu). Depending on the particular application, the use of residue cannot be ruled out even for systems as large as 75 MWe. Some pulp and paper and sugarcane mills produce residues within the range of feedstock requirements for systems of this scale. Utilities and others are also examining the use of residues for power production as a service to their customers in need of residue disposal options. The Overview of Biomass Technologies provide s a discussion of the sustainability of dedicated feedstock supplies which are assumed to be used in the system s characterized here.

Solar Stirling Engine Basics Explained

Solar Stirling Engine Basics Explained

The solar Stirling engine is progressively becoming a viable alternative to solar panels for its higher efficiency. Stirling engines might be the best way to harvest the power provided by the sun. This is an easy-to-understand explanation of how Stirling engines work, the different types, and why they are more efficient than steam engines.

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