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Advanced cogeneration research study. Survey of cogeneration potential
Fifty-five facilities that consumed substantial amounts of electricity, natural gas, or fuel oil were surveyed by telephone in 1983. The primary objective of the survey was to estimate the potential electricity that could be generated in the SCE service territory using cogeneration technology. An estimated 3667 MW sub e could potentially be generated using cogenerated technology. Of this total, current technology could provide 2569 MW sub p and advanced technology could provide 1098 MW sub e. Approximately 1611 MW sub t was considered not feasible to produce electricity with either current or advanced cogeneration technology.
Cogeneration computer model assessment: Advanced cogeneration research study
Cogeneration computer simulation models to recommend the most desirable models or their components for use by the Southern California Edison Company (SCE) in evaluating potential cogeneration projects was assessed. Existing cogeneration modeling capabilities are described, preferred models are identified, and an approach to the development of a code which will best satisfy SCE requirements is recommended. Five models (CELCAP, COGEN 2, CPA, DEUS, and OASIS) are recommended for further consideration.
Survey of cogeneration: Advanced cogeneration research study
The consumption of electricity, natural gas, or fuel oil was surveyed. The potential electricity that could be generated in the SCE service territory using cogeneration technology was estimated. It was found that an estimated 3700 MWe could potentially be generated in Southern California using cogenerated technology. It is suggested that current technology could provide 2600 MWe and advanced technology could provide 1100 MWe. Approximately 1600 MWt is considered not feasible to produce electricity with either current or advanced cogeneration technology.
Cogenerating and pre-annihilating dark matter by a new gauge interaction in a unified model
Grand unified theories based on large groups (with rank ≥6) are a natural context for dark matter models. They contain Standard-Model-singlet fermions that could be dark matter candidates, and can contain new non-abelian interactions whose sphalerons convert baryons, leptons, and dark matter into each other, “cogenerating' a dark matter asymmetry comparable to the baryon asymmetry. In this paper it is shown that the same non-abelian interactions can “pre-annihilate' the symmetric component of heavy dark matter particles χ, which then decay late into light stable dark matter particles ζ that inherit their asymmetry. We derive cosmological constraints on the parameters of such models. The mass of χ must be <3000 TeV and their decays must happen when 2×10{sup −7}<T{sub dec}/m{sub χ}<10{sup −4}. It is shown that such decays can come from d=5 operators with coefficients of order 1/M{sub GUT} or 1/M{sub Pℓ}. We present a simple realization of our model based on the group SU(7).
Cogeneration Technology Alternatives Study (CTAS). Volume 5: Cogeneration systems results
The use of various advanced energy conversion systems is examined and compared with each other and with current technology systems for savings in fuel energy, costs, and emissions in individual plants and on a national level. About fifty industrial processes from the largest energy consuming sectors were used as a basis for matching a similar number of energy conversion systems that are considered as candidate which can be made available by the 1985 to 2000 time period. The sectors considered included food, textiles, lumber, paper, chemicals, petroleum, glass, and primary metals. The energy conversion systems included steam and gas turbines, diesels, thermionics, stirling, closed cycle and steam injected gas turbines, and fuel cells. Fuels considered were coal, both coal and petroleum based residual and distillate liquid fuels, and low Btu gas obtained through the on site gasification of coal. The methodology and results of matching the cogeneration energy conversion systems to approximately 50 industrial processes are described. Results include fuel energy saved, levelized annual energy cost saved, return on investment, and operational factors relative to the noncogeneration base cases.
Microcombustion for micro-tubular flame-assisted fuel cell power and heat cogeneration
Not Available
Prospects of hydrogen cogeneration and carbon dioxide utilization in electrochemical refineries for ethylene production via oxidative coupling of methane: A techno-economic assessment
Ethylene is recognized as one of the most significant chemicals globally. The projected ethylene production for 2023 stands at 227.6 million tonnes, with expectations of continued demand growth. The primary use of ethylene, accounting for over 76%, lies in the production of plastics such as polyethylene, polyvinyl chloride, and polystyrene. Despite the enduring carbon retention potential of plastics themselves, traditional ethylene feedstock production from fossil resources contributes substantially to greenhouse gas emissions, ranging from 0.29 to 2.29 kg CO2 /kg Ethylene depending on various factors like feedstock and process design. Various decarbonization strategies, including the utilization of hydrogen as a primary heat source, have been proposed to reduce the carbon footprint of ethylene production, but their efficacy remains limited, offering at best a 0–30% reduction in on-site CO 2 emissions.
Advanced Cogeneration Technology Economic Optimization Study (ACTEOS)
The advanced cogeneration technology economic optimization study (ACTEOS) was undertaken to extend the results of the cogeneration technology alternatives study (CTAS). Cost comparisons were made between designs involving advanced cogeneration technologies and designs involving either conventional cogeneration technologies or not involving cogeneration. For the specific equipment cost and fuel price assumptions made, it was found that: (1) coal based cogeneration systems offered appreciable cost savings over the no cogeneration case, while systems using coal derived liquids offered no costs savings; and (2) the advanced cogeneration systems provided somewhat larger cost savings than the conventional systems. Among the issues considered in the study included: (1) temporal variations in steam and electric demands; (2) requirements for reliability/standby capacity; (3) availability of discrete equipment sizes; (4) regional variations in fuel and electricity prices; (5) off design system performance; and (6) separate demand and energy charges for purchased electricity.
Performance and operational economics estimates for a coal gasification combined-cycle cogeneration powerplant
A performance and operational economics analysis is presented for an integrated-gasifier, combined-cycle (IGCC) system to meet the steam and baseload electrical requirements. The effect of time variations in steam and electrial requirements is included. The amount and timing of electricity purchases from sales to the electric utility are determined. The resulting expenses for purchased electricity and revenues from electricity sales are estimated by using an assumed utility rate structure model. Cogeneration results for a range of potential IGCC cogeneration system sizes are compared with the fuel consumption and costs of natural gas and electricity to meet requirements without cogeneration. The results indicate that an IGCC cogeneration system could save about 10 percent of the total fuel energy presently required to supply steam and electrical requirements without cogeneration. Also for the assumed future fuel and electricity prices, an annual operating cost savings of 21 percent to 26 percent could be achieved with such a cogeneration system. An analysis of the effects of electricity price, fuel price, and system availability indicates that the IGCC cogeneration system has a good potential for economical operation over a wide range in these assumptions.
Cogeneration of electricity and liquid fuels using an HTGR as the heat source - 18698
A high temperature gas-cooled reactor (HTGR) used for cogeneration of electricity and liquid transportation fuels was modeled. The model consisted of two HTGRs, each transferring heat through: - a steam generator (SG) to a supercritical Rankine Cycle (SCRC) producing electricity, and - an intermediate heat exchanger (IHX) to a biomass gasifier and Fischer-Tropsch (FT) process producing gasoline, jet fuel, diesel, liquefied petroleum gas (LPG) and/or naphtha. The individual systems and components in the cogeneration model are mature technologies and commercially available, because minimizing the need for additional innovation increases the overall probability of success for a new and unique hybrid system. Technical evaluations of cogeneration on the island of Oahu in the State of Hawaii, using eucalyptus and sugarcane as the biomass feedstock, indicated that high thermal efficiency was achievable and that the concept is technically viable. Economic evaluations of cogeneration, based on construction and finance costs and current electricity and liquid fuel prices, indicated that the cogeneration plant is economically viable. Additional analyses quantified the potential number of jobs created in the state and the reduction in carbon emissions. Further analyses indicated that cogeneration would significantly enhance Hawaii's energy security. (authors)
An assessment of advanced technology for industrial cogeneration
The potential of advanced fuel utilization and energy conversion technologies to enhance the outlook for the increased use of industrial cogeneration was assessed. The attributes of advanced cogeneration systems that served as the basis for the assessment included their fuel flexibility and potential for low emissions, efficiency of fuel or energy utilization, capital equipment and operating costs, and state of technological development. Over thirty advanced cogeneration systems were evaluated. These cogeneration system options were based on Rankine cycle, gas turbine engine, reciprocating engine, Stirling engine, and fuel cell energy conversion systems. The alternatives for fuel utilization included atmospheric and pressurized fluidized bed combustors, gasifiers, conventional combustion systems, alternative energy sources, and waste heat recovery. Two advanced cogeneration systems with mid-term (3 to 5 year) potential were found to offer low emissions, multi-fuel capability, and a low cost of producing electricity. Both advanced cogeneration systems are based on conventional gas turbine engine/exhaust heat recovery technology; however, they incorporate advanced fuel utilization systems.
Advanced cogeneration research study: Executive summary
This study provides a broad based overview of selected areas relevant to the development of a comprehensive Southern California Edison (SCE) advanced cogeneration project. The areas studied are: (1) Cogeneration potential in the SCE service territory; (2) Advanced cogeneration technologies; and (3) Existing cogeneration computer models. An estimated 3700 MW sub E could potentially be generated from existing industries in the Southern California Edison service territory using cogeneration technology. Of this total, current technology could provide 2600 MW sub E and advanced technology could provide 1100 MW sub E. The manufacturing sector (SIC Codes 20-39) was found to have the highest average potential for current cogeneration technology. The mining sector (SIC Codes 10-14) was found to have the highest potential for advanced technology.
Comparative Analysis of Natural Gas Cogeneration Incentives on Electricity Production in Latin America
An analysis to assess the influence of country-dependent variables and incentives on the feasibility of natural gas cogeneration projects in Latin America is presented in this work. The analysis is performed using a hypothetical industrial plant, where the cogeneration solution consists in the recovery of waste heat from the power generation for steam production. The feasibility is evaluated by calculating the Return of Investment (ROI) and the Internal Rate of Return (IRR) of the project. Eight Latin American countries are studied considering their specific natural gas markets, regulation, and macroeconomic variables. Two scenarios, electricity production for self-consumption and electricity production with power surplus sale, are independently analyzed considering the effects of available incentives. In the countries where the project is feasible, the application of incentives leads to a significant reduction in the ROI and, consequently, to an increment in the IRR. The effect of the interest rate and environmental impact were also analyzed. In general terms, along the region, the regulation for cogeneration is incipient while incentives are very standard and similar respect to lowering of import, Value-Added Tax (VAT), and income taxes, which seems to be designed purely to promote capital investment. Following the results from this study, it is of paramount importance to create new policy instruments in the future to advance the regulatory framework for cogeneration in Latin America.
Comparison of Integrated Gasifier-Combined Cycle and AFB-steam turbine systems for industrial cogeneration
In the cogeneration technology alternatives study (CTAS) a number of advanced coal fired systems were examined and systems using a integrated coal gasifier IGCC or a fluid bed combustor AFB were found to yield attractive cogeneration results in industrial cogeneration applications. A range of site requirements and cogeneration sizing strategies using ground rules based on CTAS were used in comparing an IGCC and an AFB. The effect of time variations in site requirements and the sensitivity to fuel and electricity price assumptions are examined. The economic alternatives of industrial or utility ownership are also considered. The results indicate that the IGCC system has potentially higher fuel and emission savings and could be an attractive option for utility ownership. The AFB steam turbine system has a potentially higher return on investment and could be attractive assuming industrial ownership.
Advanced technology cogeneration system conceptual design study: Closed cycle gas turbines
The results of a three task study performed for the Department of Energy under the direction of the NASA Lewis Research Center are documented. The thermal and electrical energy requirements of three specific industrial plants were surveyed and cost records for the energies consumed were compiled. Preliminary coal fired atmospheric fluidized bed heated closed cycle gas turbine and steam turbine cogeneration system designs were developed for each industrial plant. Preliminary cost and return-on-equity values were calculated and the results compared. The best of the three sites was selected for more detailed design and evaluation of both closed cycle gas turbine and steam turbine cogeneration systems during Task II. Task III involved characterizing the industrial sector electrical and thermal loads for the 48 contiguous states, applying a family of closed cycle gas turbine and steam turbine cogeneration systems to these loads, and conducting a market penetration analysis of the closed cycle gas turbine cogeneration system.
Expanding market opportunities: cogeneration strategies for integrated PWR and thermal energy storage systems
We assess the economic viability of nuclear cogeneration by investigating three different modes—fixed dispatch, fully flexible dispatch, and flexible dispatch with minimum heat supply requirements. The analysis focuses on an existing pressurized water reactor (PWR) integrated with thermal energy storage (TES). Heat production costs are estimated under these modes for two U.S. electricity markets: the Electric Reliability Council of Texas (ERCOT) and the Pennsylvania–New Jersey–Maryland Interconnection (PJM). A sensitivity analysis examines profitability at varying heat market prices. Results indicate that fixed heat dispatch inflates heat production costs, often rendering projects economically feasible only at higher heat price levels. Fully-flexible dispatch lowers heat production costs by an average of 43 % compared to fixed dispatch. However, the current 30 % thermal dispatch limit may be insufficient to serve high baseline industrial demands cost‐effectively; higher maximum dispatch rates could enhance project economics. Markets with higher and more volatile electricity prices (e.g., ERCOT) offer greater total energy sales potential (i.e., heat and electricity), but also increase opportunity costs when heat production scheduling restrictions are imposed. In contrast, lower-price, less volatile markets (e.g., PJM) experience smaller impacts from such constraints and provide greater flexibility in accommodating varying cogeneration modes. In conclusion, these findings provide a framework to guide nuclear plant operators in aligning cogeneration strategies with industrial process requirements and electricity market conditions.
Results from the European NC2I-R project on nuclear cogeneration with high temperature reactors - 18617
This paper delivers key results from the European project NC2I-R (Nuclear Cogeneration Industrial Initiative Research) supporting the development of an industrial initiative to demonstrate nuclear cogeneration of heat and power with High Temperature Reactors as an effective low-carbon technology for industrial market applications. The NC2I-R project was run from 2013 to 2015 by a consortium of 20 companies. It was co-financed by the European Commission and was an 'executive' project of the European nuclear stakeholder platform SNETP, specifically one of its pillars, the Nuclear Cogeneration Industrial Initiative (NC2I). (authors)