Showing papers on "Base load power plant published in 1988"

Aeroderivative Turbines for Stationary Power

Abstract: According to the authors, a revolution is under way in electricity generating technology. It may soon radically transform the power industry in both industrial and developing countries. This revolution involves the upgrading of the familiar but little-used gas turbine. In the electric utility industry the gas turbine has until recently been restricted largely to little-used peaking plants; in cogeneration (simultaneous production of electricity and process heat in the same unit), the gas turbine has been used mainly in applications characterized by steady steam loads. This paper describes how innovations are making it possible for gas turbines to compete in cogeneration markets characterized by variable heat loads, and to compete in central-station applications with conventional baseload and load-following technologies, using low-quality as well as high-quality fuels.

Operating Characteristics of Heavy-Duty Gas Turbines in Utility Service

Abstract: With the increasing utilization of gas turbines in industrial and cogeneration applications, they are taking on a greater role in base load service. Because of their inherent responsiveness, they also offer operating characteristics that can enhance their contribution to utility systems as a generator prime mover. This paper will describe these characteristics, particularly as they relate to the interaction of the gas turbine, the governor, and the temperature control system. Additional features, such as load control, variable inlet guide vanes, peaking operation and other unique characteristics are also discussed from this point of view.Copyright © 1988 by ASME

The concept of demand-side management

Abstract: The pattern of electricity consumption varies in the course of a day, typically reflecting the patterns of human activity — high during the day and low at night. This simple fact has fundamental implications on the electric utilities business. Adequate generating capacity has to be available to serve the demand during the peak periods, even though much of this capacity is idle during the periods of low demand (off-peak). In order to cost-effectively serve this varying demand, with both diurnal and seasonal variations, the utilities use three types of generating facilities: baseload, intermediate load, and peak load plants. Baseload plants serve the portion of the demand which is present most of the time and, as such, they are designed to operate at a constant level for most of the year and use low-cost fuels, such as coal and nuclear, resulting in low operating cost. The capital cost of these plants is, however, high. On the other hand, peaking plants that serve the peak portion of the load and operate for only about 10% of the time, have low capital but high operating costs. They rely primarily on oil- or natural gas-powered units to provide quick start capabilities. Intermediate plants meet the portion of the load that varies daily and, as implied by the term “intermediate,” their sizes and costs fall between those of baseload and peaking units.

Fuel cell air pressurization system and method

Abstract: Pressurization air systems in a multimodule fuel cell power plant are interconnected to provide improved power plant operating efficiency at part load. Each power generation module air pressurization subsystem has its own turbocompressor to provide a compressed air supply to its own power generation subsystem at rated power plant load. When load demand on the power plant is reduced, some of the turbocompressors in the interconnected power generation modules in the plant are shut off. The interconnecting valves are opened so that the remaining turbocompressors can supply all of the compressed air needed by all of the power generation subsystems in the interconnected power generation modules.

Impact of lower oil prices on renewable energy technologies

Abstract: The impacts of reduced oil prices on the economic viability of selected technologies which utilize solar, wind and biomass energy sources are examined The technologies include dendrothermal power plants, bagasse, fuel alcohol, wind electricity, biomass gasifiers, solar water heaters, biogas, photovoltaic pumps and wind pumps Projects in these categories which were established or planned when oil prices were above $ 28 / bbl are reviewed and their economic justifications recalculated at a range of lower oil prices The findings indicate that the economic sensitivity of renewable energy technologies to changing oil prices is mainly a function of scale and location of the project Renewable energy technologies that compete directly in the modern sector as large scale petroleum substitutes, are the most affected by falling oil prices Remote and rural applications are less affected because of their generally smaller sizes Therefore, we find a lower proportion of fuel costs to total costs in the equivalent sized conventional alternative, a reduced availability and higher cost of petroleum fuels as compared to urban areas, and a lower cost of biomass fuels in rural areas

Decentralized load frequency control with load demand prediction in multi-area power systems

Abstract: Discusses the feasibility of a decentralized load frequency control (LFC) system for a multi-area power system based on the state regulator theory. In particular, if the magnitudes of disturbances can be estimated with reasonable accuracy, the state regulator technique will yield no offset errors in the frequencies and tie-line power deviations even for unknown load disturbances. This implies that the state regulator with an estimation algorithm for load disturbances can be an ideal LFC method having a minimum settling time. The feasibility of the proposed approach is shown through numerical simulations on a multi-area power system having different types of LFC generators.

Utility-owned distributed photovoltaics systems

Abstract: The potential for PV as a utility service option to customers and for Pacific Gas & Electric Company's (PG&E's) own internal operations applications is examined. The cost of PV power is compared to that of line extensions for customers with remote power requirements. Key factors that influence a utility's decision to install PV for distributed applications are discussed. Preliminary findings show that many remote sites, perhaps several thousand, exist within PG&E's service territory where stand-alone PV power generation is technically feasible and the most economically competitive power source. PV could also have a significant impact on PG&E when used for dispersed grid-connected applications within the utility's electrical distribution system. >

Electrical power system in the UK

Abstract: The Central Electricity Generating Board is responsible for the generation and transmission of electricity in England and Wales. Currently the CEGB has 78 power stations with a net capacity of 52 GW, and about 77% of generation is from coal and about 16% from nuclear power. For the future, 900 MW coal-fired units are under development, and the first PWR is under construction. Wind power and other forms of generation will provide further diversity of energy sources

Firm power and system penetration

Abstract: The author discusses the impact of wind energy on power system operation, and the nature of its contribution to system reliability and firm power, both at low system penetrations and as the installed wind capacity rises. At low penetrations, wind energy can be assessed as firm power both in terms of its contribution to system reliability and in its fuel saving value. The operational penalties at very low levels are negligible, and certainly well under 5% of the ideal fuel savings for the first few thousand megawatts of WECs capacity on the CEGB system. The penalties associated with wind power rise steadily as the penetration increases, but at a fairly slow rate. It seems highly unlikely that wind utilisation in Britain will ever be seriously limited by system problems-the CEGB system can probably accommodate wind energy contributions in the region of 40-50% of demand before losses necessarily become prohibitive.

Long-Term Optimal Operation of Hydrothermal Power Systems

Abstract: The problem treated in the previous chapters was concerned with a pure hydro power system, where we maximized either the total benefits from the system (benefits from the hydro generation plus benefits from the amount of water left in storage at the end of the planning period) or the total firm hydro energy capability for the system. We discussed almost all techniques used to solve these problems. Most of the utility companies have a combination of hydro and thermal power plants to supply the required load on the system, where the hydro power plants are used to supply the base load, since they cost nothing to run (almost all the running costs are very small compared to those of thermal plants), while the thermal plants are used to supply the peak load, since these loads occur for a small period of time with peak demand.

Multiperiod optimal power-plant mix under demand uncertainty

Abstract: MULTIPERIOD OPTIMAL POWER PLANT MIX UNDER DEMAND UNCERTAINTY Byong-Hun Ahn Bo-Woo Nam Korea Advanced Institute oj'Science and Technology (Received June 5,1987; Revised March 3,1988) This paper is concerned with the thermal-based electric utility capacity expansion planning under demand uncertainty. The demand uncertainty is typically represented as a set of likely load duration curves (LDCs) with respective probabilities. Conventional scenario approaches prepare respective capacity expansion plans one for each load curve and synthesize these somehow into a single plan. This paper presents a simple yet justifiable method which combines multiple plans into a single implementable plan guaranteeing the minimum expected total cost. A "horizontal" expected load curve is the key concept in this method. We illustrate this using Korea's data in a realistic multi-period optimal mix problem. It turns out that the recommended baseload capacity expansion (e.g., through construction of nuclear plants) follows closely that of the low-demand case, suggesting the need for conservative commitment to costly baseload plants in the presence of demand uncertainty.

Transferring electrical power between utilities

Abstract: The factors that favor the transfer of electrical power, as opposed to generating it, when and where needed, namely economics and reliability, are discussed. The tie lines that connect utilities, transferring high-voltage AC or DC power, and the control of the interchange, are described. Problems and risks, particularly blackouts, are examined. >

Compact Systems For Power Generation And Nitrogen Injection

Abstract: A 50 year old power system has merit offshore. Featuring a semi-combined 44% thermal efficiency, the power density exceeds gas turbines by a factor of two. A 625 MW version has been proposed installed at Halten, Norway. The 4600 ton plant, using associated gas as fuel, transfers the power ashore as 400 kV DC. Combustion at 14.3 barg, 207 psig, reduces size and heat transfer surfaces. The concept competes with pipelining and power stations ashore. Electrical component developments and the elimination of the bulk of the oil process compressors give offshore an edge. A slightly smaller version of this power plant is the basis for a 600 million SCFD nitrogen injection plant, proposed for the North Sea. The plant simply compresses its own flue gas.

The connection of one large power station to the main grid

Abstract: The authors compare the methods used by EDF, ENEL and CEGB for the connection of one large power station to the main system. Two major issues are discussed: the principles of planning and site selection, and the connection of the new station to the main grid. For each utility the authors discuss the procedures used for siting, grid connection which includes power export considerations and security of supply to the auxiliaries. An example is given for each utility.

Comparative costs of coal- and nuclear-generated electricity

Abstract: The US nuclear program has been halted by a confluence of unfortunate circumstances that include unpredictable regulation, overcapacity, an uncertain economic outlook, and various financial constraints. This paper describes the methodology, assumptions, and results of a study of the first-year costs and lifetime revenue requirements for generating electricity from yet-to-be-constructed coal-fired and uranium-fueled electric plants, using schedules actually followed in the United States for custom-designed plants. Lifetime generating costs have been developed for plants with achievable, shorter-than-current lead times and demonstrably efficient plant design, construction, and operation. Such conditions have been experienced recently in many nations throughout the world as well as in the United States in spite of a difficult regulatory environment. The most important conclusions of the study described in this paper is that nuclear appears to have a clear economic advantage. Coal is favorable only when it is assumed that the units will operate at very low capacity factors and/or when the capital cost differential between nuclear and coal is increased far above the recent historical level. Nuclear is therefore a cost-competitive electric energy option for utilities and should be considered as an alternative to coal when large baseload capacity is again required.

Comparative costs of coal and nuclear-generated electricity in the United States

Abstract: This paper compares the future first-year operating costs and lifetime levelized costs of producing baseload coal- and nuclear-generated electricity under schedules shorter than those recently experienced at US plants. Nuclear appears to have a clear economic advantage. Coal is favorable only when it is assumed that the units will operate at very low capacity factors and/or when the capital cost differential between nuclear and coal is increased far above the recent historical level. Nuclear is therefore a cost-competitive electric energy option for utilities and should be considered as an alternative to coal when large baseload capacity is required.

Short-Term Load Forecasting

Abstract: Some of the decision and control functions discussed in this book require knowledge of future load behavior. In unit commitment, for example, hourly system loads for the next 24–72 hours are required. Some unit commitment programs even require knowledge of future loads for the next week, i.e., 168 hours. At the other extreme, although present forms of AGC do not utilize any forms of forecasting, some convincing research has shown that knowledge of load trends in the next few minutes can help in designing better AGC control strategies. In security assessment, future knowledge of all bus loads for the next 1–24 hours can be used to check for those periods of potential system vulnerability and to plan maintenance outages for lines, transformers, and generators. Table 9.1 provides a summary of existing and potential uses of short-term load forecasting.

Power quality load management for large spacecraft electrical power systems

Abstract: In December, 1986, a Center Director's Discretionary Fund (CDDF) proposal was granted to study power system control techniques in large space electrical power systems. Presented are the accomplishments in the area of power system control by power quality load management. In addition, information concerning the distortion problems in a 20 kHz ac power system is presented.