Utility systems, capital cost estimate

Table IV. Capital Cost Estimate Utility Systems for a 330-Mw Plant Using 3.5% Sulfur Coal...

Another key factor for successful cost targeting is capital cost estimation. Capital costs for heat recovery systems include costs for heat exchangers, heaters, and coolers. Improper estimates of capital cost can lead to suboptimal trade-offs between capital and utility costs. One important aspect is good estimates of heat transfer coefficients for individual process streams since heat transfer coefficients determine the size and surface area of heat exchangers. A second consideration for accurate capital costs is realistic cost calculation for process furnaces and cooling towers in the targeting phase of work— these are much more expensive than heat exchangers. 

The PCO system can operate basically unattended, resulting in extremely low operation and maintenance costs (D12104Q, p. 25). Over a 10-year life cycle, the Los Alamos National Laboratory estimates that operating costs will make up only 17% of total costs. Capital costs account for 43%, utilities for 14%, and maintenance for 26% of the total costs (D12104Q, p. 26). 

A thorough analysis of the capital and operating economics was made for the system described above. The basis for this estimate is shown in Table III, and relatively conservative assumptions have been made for the cost of the various utilities, maintenance, operating supplies, overhead, and capital charge rate. The analysis was based on designing the plant for the equivalent of 7000 hr/yr of full load operation. The capital costs, broken down into the gas interface loop and the regeneration system, are shown in Table IV. The cost for the scrubber loop and its asso-... 

The cost of hydrogen was estimated by considering the capital costs, capital recovery factor, the operating expenses of the refueling station, the cost of utilities (fuel and electricity), and the cost of catalysts. The natural gas cost was assumed to be 5/ GJ on a higher heating value (HHV) basis, and the electricity cost was assumed to be 70/kWhr. The efficiency of the system (75% on a LHV basis) was used to determine the required amount of natural gas. A capacity factor of 90% for plant utilization was used. The capital recovery factor was determined as 13.1%, assuming 10% interest rate over 15 years. 

APPROACH The project team conducted literature and vendor surveys to gather information on the technology, environmental performance, and utility applications of coal gasification-based systems. They compiled this information into a guidebook and published it in three-ring-binder form to facilitate timely updates as new information becomes available. (Economic analysis of specific applications and capital and operating cost estimates will be published separately.)... 

The immediate impact of the 1970 Act was to enforce FGD in a very short time scale (Kyte, 1989). Costs for the utilities have risen accordingly. The overall cost of all air pollution control in the UShas been estimated to exceed 35 billion each year (Edison Electric Institute, 1989), and air pollution costs can account for more than one-third of a new coal-fired power plant s cost. A single FGD system or scrubber may cost 100 million or more, and capital costs for adding scrubbers on older plants can equal or exceed the original plant investment. All this investment has obviously had an impact upon emissions. The ERA calculate that from the peak year of 1973, total SO2 emissions were down nearly 21 per cent by 1987, while... 

The total capital investment for a generalized 500 MW limestone dual alkali system is estimated at 51.7 million (1980 ), which is equivalent to 103.4/kW (3). This generalized system is assumed to be designed for a 95% SO2 removal efficiency when burning coal containing 3.5% sulfur. The estimated annual operating costs (raw materials, utilities, labor and maintenance, overhead and waste disposal) are estimated at 10.7 million (1980 ) or 3.1 mills/kWh. 

Table VIII summarizes the investment and operating requirements for the H-Oil unit and its attendant facilities, and Table IX compares investment and operating costs for the naphtha and crude oil based facilities. Data on the ethylene plant investment and operating costs were taken from the paper by Freiling, Huson, and Tucker (I). Offsite investments have been taken at 30% of process investment for the naphtha case, as well as for the ethylene plant portion of the crude oil case. For the H-Oil unit and its associated units offsites have been estimated at one-half of this rate—15%. This lower value has been used since the H-Oil system will add little to the storage requirements, and all utilities have been priced to cover the capital requirements for their production.

EPA/600/S7-90/022 (Maibodi et al., 1991) presents a computer model developed by the U.S. Envirorunental Protection Agency to estimate costs and perfonnance of coal-fired utility boiler emission control systems. The model, which is based on user suppUed data, generates a material balance and an equipment list from bich capital investment and revenue requirements are estimated. The model covers a number of conventional and emerging technologies. 

Separation processes in gas (vapour) - liquid systems, like absorption, desorption and rectification, are estimated to account for 40%-70% of both capital and operating costs in process industry [1]. A significant part of the costs are connected with the packed bed columns used for these processes. The employment of these apparatuses also for direct heat transfer between gas and liquid, including utilization of waste heat from flue gases, enlarges their importance. 

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