Combined Cycle Units Research Articles

A stochastic programming model for the optimal electricity market bid problem with bilateral contracts for thermal and combined cycle units

This paper develops a stochastic programming model that integrates the most recent regulation rules of the Spanish peninsular system for bilateral contracts in the day-ahead optimal bid problem. Our model allows a price-taker generation company to decide the unit commitment of the thermal and combined cycle programming units, the economic dispatch of the bilateral contract between all the programming units and the optimal sale bid by observing the Spanish peninsular regulation. The model was solved using real data of a typical generation company and a set of scenarios for the Spanish market price. The results are reported and analyzed.

Carbon capture and storage in China — main findings from China-UK Near Zero Emissions Coal (NZEC) initiative

Abstract The China-UK Near Zero Emissions Coal (NZEC) Initiative examined options for carbon (CO 2 ) capture, transport and geological storage in China. It was developed under the 2005 EU-China NZEC Agreement which aims to demonstrate CCS in China and the EU. Collaborative research activities were conducted jointly by Chinese and UK experts from 30 organisations. China’s energy demand is expected to continue growing significantly; however the share of coal is projected to decrease to around 50% by 2050. For the power generation and energy intensive industrial sectors, all of which remain heavily dependent on coal, CCS is the only option that can ensure a significant reduction in CO 2 emissions. A range of CO 2 capture technologies in coal-fired power generation have been examined. The more promising, near term options are post-combustion capture using Monoethanolamine in a state of the art pulverised coal power plant and pre-combustion capture in an Integrated Gasification Combined Cycle unit. The cost of electricity generation with capture would be 463 and 413 RMB per MWh respectively for these options. Less mature capture technology options offer some potential to lower the overall cost, but this is within the range of uncertainties. Storage assessments were undertaken in two basins in North East China. These have potential to make use of CO 2 for Enhanced Oil Recovery (EOR) although the reservoirs are geologically complex and well integrity may be a significant risk. While CO 2 EOR would provide the opportunity for gaining initial experience with CO 2 injection and storage, the capacity available for EOR in these regions appears insufficient for large scale CCS. It would therefore be necessary to assess and ultimately use saline aquifers for storage. An extensive saline aquifer formation has been identified in the Songliao Basin through the project. The average cost of electricity generation taking account of capture, transport and storage costs (assuming a storage site 200 km from the power plant) would be 470 RMB per MWh for the most mature capture options, an increase of around 200 RMB per MWh compared with a Pulverised Coal reference plant without CCS. This is equivalent to a cost of avoided emissions of about 280 RMB (US $50.0) per tonne of CO 2 . There are several challenges that need to be addressed for CCS in China. These include the extra cost and energy penalty of CCS, the novelty of the technology, the lack of regulations governing the storage of CO 2 underground and the availability of the necessary equipment for deployment of CCS in China. The China-UK NZEC Initiative has shown that CCS could provide a key, low carbon option for coal-based industry in China, particularly for power generation, which would enable the continued use of coal with reduced greenhouse gas emissions. An Memorandum of Understanding was signed by the European Commission and Chinese Ministry of Science and Technology for Phase II of the China-EU NZEC Agreement in November 2009. Phase II will involve the selection of a demonstration project and the completion of a feasibility study. Phase III will involve the construction and operation of a CCS demonstration project in China.

Aeroderivative Gas Turbo engine in CHP Plant. Compatibility Problems

The paper presents the possibilities to develop Combined Cycle Units based on aeroderivative Gas Turbo engines and on existing Steam Turbines. The specific compatibility problems of these components and the thermodynamic performances of the analyzed Combined Cycle Units are also presented.

Complex technical and economic studies of combined-cycle units with flow gasifiers

The method for determining the technical and economical indices of combined-cycle power plants (CCPPs) operating on coal with a low-charged steam generator and with a flow gasifier in combined production of electricity and heat, synthesis gas and hydrogen is considered. The results of analysis are presented and it is shown that such CCPPs have a higher technical and economical efficiency as compared to cogeneration plants (CPs) operating on pulverized coal and reconstructed with a gas-turbine topping. The material of this article is prepared in the framework of the Federal Targeted Program “Scientific and Scientific-Pedagogical Specialists of Innovative Russia for 2009–2013,” application 1.2.2, the program “Research Works on Production of Fuels and Power from Organic Raw Materials.”

Ultralow-Emission Combustion and Control System Installation Into Mature Power Plant Gas Turbines

The search for power plant sustainability options continues as regulating agencies exert more stringent industrial gas turbine emission requirements on operators. Purchasing power for resale, decomissioning current capabilities altogether, and repowering by replacing or converting existing equipment to comply with emission standards are economic-driven options contemplated by many mature gas turbine operators. One Las Vegas, NV operator, NV Energy, with four natural gas-fired W501B6 combined cycle units at their Edward W. Clark Generating Station, was in this situation in 2006. The units, originally configured with diffusion flame combustion systems, were permitted at 103 ppm NOx with regulatory mandates to significantly reduce NOx emissions to below 5 ppm by the end of 2009. Studies were conducted by the operator to evaluate the economic viability of using a selective catalytic reduction system, which would have forced significant modifications to the exhaust system and heat recovery steam generator, or convert the turbines to operate with dry low-emission combustion systems. Based on life cycle cost and installation complexity, the ultralow-emission combustion system was selected. This technical paper focuses on a short summary of the end user considerations in downselecting options, the ultralow emissions technology, and key features employed to achieve these low emissions, an overview of the conversion scope and a review and description of the control technology employed. Finally, a technical discussion of the low-emission operational flexibility will be provided including performance results of the converted units.

A novel power block for CSP systems

Concentrating Solar Thermal Power (CSP) and in particular parabolic trough, is a proven large-scale solar power technology. However, CSP cost is not yet competitive with conventional alternatives unless subsidized. Current CSP plants typically include a condensing steam cycle power block which was preferably designed for a continuous operation and higher operating conditions and therefore, limits the overall plant cost effectiveness and deployment. The drawbacks of this power block are as follows: (i) no power generation during low insolation periods (ii) expensive, large condenser (typically water cooled) due to the poor extracted steam properties (high specific volume, sub-atmospheric pressure) and (iii) high installation and operation costs. In the current study, a different power block scheme is proposed to eliminate these obstacles. This power block includes a top Rankine cycle with a back pressure steam turbine and a bottoming Kalina cycle comprising another back pressure turbine and using ammonia–water mixture as a working fluid. The bottoming (moderate temperature) cycle allows power production during low insolation periods. Because of the superior ammonia–water vapor properties, the condensing system requirements are much less demanding and the operation costs are lowered. Accordingly, air cooled condensers can be used with lower economical penalty. Another advantage is that back pressure steam turbines have a less complex design than condensing steam turbines which make their costs lower. All of these improvements could make the combined cycle unit more cost effective. This unit can be applicable in both parabolic trough and central receiver (solar tower) plants. The potential advantage of the new power block is illustrated by a detailed techno-economical analysis of two 50 MW parabolic trough power plants, comparing between the standard and the novel power block. The results indicate that the proposed plant suggests a 4–11% electricity cost saving.

Combined Cycle Unit Controllers Modification for Improved Primary Frequency Regulation

During the past few decades the combined cycle unit dynamics and its associated controllers have become an important research subject. It has now become necessary to understand the operation and existing control strategies for such combined cycle units; this of course is if we are to undertake a comprehensive evaluation of their performance under system disturbance status. This paper focuses on the frequency regulation performance. Its main contention is that an improvement of the control strategies will 1) ensure a better dynamic response to typical system contingencies, 2) deliver a better primary frequency regulation, and 3) maintain the internal machine variables within safe operational levels. The proposed control strategies were applied over the IEEE 14-bus system and our readings showed that modifications of the control strategies do influence better primary frequency regulation responses of the combined cycle unit within limits of a safe operation of the electric system and unit alike.

Combined production of hydrogen and power from heavy oil gasification: Pinch analysis, thermodynamic and economic evaluations

Integrated Gasification Combined Cycle (IGCC) represents a commercially proven technology available for the combined production of hydrogen and electricity power from coal and heavy residue oils. When associated with CO 2 capture and sequestration facilities, the IGCC plant gives an answer to the search for a clean and environmentally compatible use of high sulphur and heavy metal contents fuels, the possibility of installing large size plants for competitive electric power and hydrogen production, and a low cost of CO 2 avoidance. The paper describes two new and realistic configurations of IGCC plant fed by refinery heavy residues and including a CO 2 capture section, which are proposed on the basis of the experience gained in the construction of similar plants. They are based on oxygen blown entrained bed gasification and sized to produce a large amount of hydrogen and to feed one or two gas turbines of the combined cycle unit. The main thermodynamic and technological characteristics of the total plants are evaluated focusing on the heat integration between syngas cooling and combined cycle sections. Moreover, the overall performance characteristics and investment cost are estimated to supply a reliable estimate for the cost of electricity, given a value for the hydrogen selling price.

Retrofitting the Strogino district heat supply station with construction of a 260-MW combined-cycle power plant (Consisting of two PGU-130 combined-cycle power units)

The retrofitting carried out at the Strogino district heat supply station and the specific features of works accomplished in the course of constructing the thermal power station based on a combined-cycle power plant at the station site are described; the layout solutions for the main building and turbine building are presented, and a comparison of the retrofitted station with the Kolomenskoe and Vnukovo gas turbine-based power stations is given.

Using renewables and the co-production of hydrogen and electricity from CCS-equipped IGCC facilities, as a stepping stone towards the early development of a hydrogen economy

In this paper, specific cases for the interaction between the future electricity-generation mix and a newly-developing hydrogen-production infrastructure is modelled with the model E-simulate. Namely, flexible integrated-gasification combined-cycle units (IGCC) are capable of producing both electricity and hydrogen in different ratios. When these units are part of the electricity-generation mix and when they are not operating at full load, they could be used to produce a certain amount of hydrogen, avoiding the costly installation of new IGCC units for hydrogen production. The same goes for the massive introduction of renewable energies (especially wind), possibly generating excess electricity from time to time, which could then perhaps be used to produce hydrogen electrolytically. However, although contra-intuitive, the interaction between both ‘systems’ turns out to be almost negligible. Firstly, it is shown that it is more beneficial to use IGCC facilities to produce hydrogen with, rather than (excess) wind-generated electricity due to the necessary electrolyser investment costs. But even flexible IGCC facilities do not seem to contribute substantially to the early development of a hydrogen economy. Namely, in most scenarios – which are combinations of a wide range of fuel prices and carbon taxes – one primary-energy carrier (natural gas or coal) seems to be dominant, pushing the other, and the corresponding technologies such as reformers or IGCCs, out of the market.

Optimizing the technology for starting a PGU-450 combined-cycle power unit

Matters concerning selecting the optimal sequence of procedures for starting a PGU-450 combined-cycle power unit are considered. A theoretical substantiation is given of the economic advisability of optimizing the startup of this power installation according to the criterion of reducing the time taken for carrying out startup operations subject to constraints on the reliability of equipment operation.

Component and Mode Models for the Short-Term Scheduling of Combined-Cycle Units

We propose a component model for the scheduling of combined-cycle gas turbine (CCGT) units by mixed-integer programming (MIP) in which combustion turbines (CTs) and steam turbines (STs) are modeled as individual units. The hourly schedule of CCGT based on the component model is compared with that of the mode model. The modeling of modes, which includes a combination of CTs and STs, would require certain approximations for representing fuel input-power output curves, ramping rate limits, minimum operating time limits, etc. The approximations can result in sub-optimal schedules. Furthermore, the commitment and dispatch of CCGTs based on the mode model will require a real-time dispatch to individual CT and ST components of CCGT. In comparison, the mode modeling approximations will no longer be required in the component model as individual CTs and STs are modeled and dispatched. The enhancement tools such as duct burners, foggers, and peak firing for increasing the CCGT output can be easily modeled in the component model. Case studies show that the proposed component model is effective for representing CCGTs, and verify that the proposed component model can potentially save CCGT operating costs. Numerical simulations in this paper also demonstrate the application of the component model of CCGT to schedule a cogeneration unit.

Damage to steam-generating tubes of low-pressure circuit of drum-type heat recovery boiler used in the PGU-450 combined-cycle unit at Severozapadnaya cogeneration plant

The results of investigation into the nature of damage to tube bends of the low-pressure evaporator of the P-90 heat recovery boiler installed at the Severozapadnaya cogeneration plant are presented. It has been found that damage was caused by cavitation wear due to action of steam-water flow.

Use of combined-cycle power units at cogeneration plants

Indices of reconstructed and new cogeneration plants (CPs) using combined cycle units (CCPUs) are considered. The conclusions that follow from the necessity of retention of the heat capacity of a CP under reconstruction and limited possibilities of CCPUs as to heat output are given.

The selection of a profile of the PGU-400T combined-cycle cogeneration unit for the TETs-25 cogeneration power plant of the mosenergo power utility

The selection of a profile of a heat-recovery combined-cycle cogeneration plant of 400- to 420-MW capacity for the expansion of the TETs-25 Mosenergo cogeneration plant is substantiated. It is shown that the most preferable version is a two-shaft arrangement with a gas turbine installed at a zero elevation level and a steam turbine mounted on a frame foundation, with cogeneration equipment located in the basement.

Making the tube system’s fitting parts of the low-pressure evaporators used in the heat-recovery boilers of combined-cycle units more resistant to erosion-corrosion wear during operation

We present the results of calculation-analytical investigations into the effect of various parameters and factors on the rate of wear in the tube system elements of low-pressure evaporators used in the heat-recovery boilers of combined-cycle plants. Factors causing damage to these elements are established, and the dominating mechanism through which this damage occurs (erosion-corrosion) is determined. Measures for making the tube systems of combined-cycle plants more resistant to erosion-corrosion wear are proposed.

World experience with development of combined-cycle and gas turbine technologies and prospects for employing them in the thermal power engineering of Russia using the capacities of the country’s industry producing power machinery and equipment

World experience gained from using combined-cycle and gas-turbine technologies in power engineering is analyzed. The technical and production capacities of the Russian industry constructing power machinery and equipment are analyzed from the viewpoint of its capability of producing up-to-day gas-turbine and combined-cycle units for the country’s thermal power engineering and developing advanced domestically produced new-generation gas-turbine and combined-cycle units.

Fuzzy Predictive Supervisory Control Based on Genetic Algorithms for Gas Turbines of Combined Cycle Power Plants

This work presents a novel design and development of a fuzzy predictive supervisory controller, based on genetic algorithms (GA), for gas turbines of combined cycle units. The control design is based on an objective function that represents the economic and regulatory performance of a gas turbine by using a dynamic optimal set-point for the regulatory level. A fuzzy model is considered in order to characterize the nonlinear behavior of the gas turbine, which is used in two supervisory control systems. The first fuzzy supervisory control design includes a fuzzy model, where its parameters are held constant for the successive predictions. For the second fuzzy supervisory control design, its parameters are updated in each prediction and its nonlinear optimization problem is solved using GAs. The proposed fuzzy supervisory controllers are compared against a supervisory controller based on linear models and a regulatory controller with constant optimal set-points. Results indicate that the fuzzy GA predictive supervisory controller captures adequately the nonlinearities of the process, which, in turn, provides a promising approach to improve the performance of the combined cycle unit.

Experiences in modelling the performance of generating plant for frequency response studies on the British transmission grid

Significant changes to the generation mix on the British transmission system have occurred in the past 10 years, and this trend is expected to continue in the future with an increase in renewable generation. This change, in conjunction with market changes, has driven the need to establish suitable generator models for thermal plant used in dynamic response studies. These studies are presently used to quantify the dynamic requirement that secures the transmission system against large instantaneous losses of power. This paper provides an account of the experiences gained in modelling the performance of generators based in Great Britain. Established governor models to represent the behaviour of traditional coal and oil fired plant already exist and comments are made on their performance against system incidents. Models of combined cycle units using traditional open cycle gas turbine models have shown poor correspondence with monitored grid data in simulations. A gas and steam turbine governor model to represent combined cycle plant was developed, and is presented, with results from validation trials against recorded test data. Improvements in simulating grid frequency have been demonstrated using the developed models in a full network simulation of a recent generator loss event.

Scenario planning for the electricity generation in Indonesia

The long-term planning of a future electricity supply system requires data about future demand. Planners who use the conventional planning method forecast future demand by observing past trends or alternatively by developing scenarios and then selecting the scenario considered to be the most likely to occur. This method, however, fails to include future uncertainties. To consider such uncertainties, the scenario planning method may be used. This study uses this method to devise a long-term electricity supply plan for the Java–Madura–Bali electricity system. It was found that the scenario planning method could save up to US$3.5 billion over a 15-year period if the method was applied right at the beginning of the period. In the case of the Java–Madura–Bali system, which currently has excess installed capacity, the scenario planning method does not provide such large benefits. It was also found that introducing integrated coal gasification combined cycle and advanced gas combined cycle units would reduce greenhouse gas emissions from the Java–Madura–Bali system by approximately 230 million tonnes or 15% compared to a business-as-usual (BAU) scenario over a15-year planning timeframe. The abatement cost was found to be US$4 per tonne of CO 2.