Back-pressure Steam Turbine Research Articles

Model research of the energy efficiency of a cogeneration backpressure steam turbine installation

In the contemporary district heating systems (DHS) heat energy for the customers is generated by cogeneration method, which leads to the saving of primary energy resources compared to the separate production method. The most widespread technology for combined production is based on steam turbine installations with adjustable steam extraction and backpressure steam turbine. In these technologies district heating water is heated to the required temperature either in district heaters in case of steam turbine with adjustable steam extractions or in boiler-condenser in case of backpressure steam turbine installations. The temperature of the district heat water at the inlet of the CHP installation depends on the mode of operation of the DHS. The heat load, distributed to consumers, is regulated at the heat source (CHP installation) by temperature and flow rate of the district heating water, mainly following the change in climatic factors. Current study presents the development of a simulation model of existing CHP backpressure steam turbine. The object studied is a backpressure steam turbine type SST-300 CE2L/V36S. Presented are results from the validation of the simulated model with data from the design documentation. The model has been used to study the energy efficiency of a steam turbine installation based on multivariate simulation calculations. The results obtained relate the energy efficiency indicators of CHP backpressure steam turbine with the factors that characterize the mode of operation of the district heating system.

3-E analyses of a natural gas fired multi-generation plant with back pressure steam turbine

Energetic, exergetic and environmental (3-E) analyses of a natural gas fired multigeneration (NGFMG) plant is carried out in this study. The plant is consisting of a topping gas turbine (GT) block with fixed 30 MWe output, bottoming back pressure steam turbine (ST) block with variable electrical output and utility hot water generation block with variable generation capacity. Variation of topping cycle pressure ratio (rp=2-18) and gas turbine inlet temperature (TIT=750-850 °C) as plant operational parameters on the 3-E performance of the plant of are reported here. Base case performance (at rp=4 & TIT=800°C) of the plant shows that the plant is about 33% electrically efficient at base case with fuel energy savings ratio (FESR) value of 40 %. Electrical efficiency of the plant along with FESR increases with either increase in rp or in TIT. However ST output and hot water production rate decreases with increase in the value of plant operational parameters. Exergy analysis of the plant shows that maximum exergy destruction occurs at the combustion chamber. Exergy analysis also signifies that isentropic efficiency of the GT can also be a plant influencing parameter. From emission point of view it is observed that electrical specific CO2 emission is 0.6 kg/kWeh at base case. Specific CO2 emission rate gets lowered with either increase in rp or in TIT.

Converting Zubair oil field permanent power generation from single cycle into combined-cycle with plant exergy analysis

The combined-cycle power plant is the effective way to increase power and thermal efficiency which can rise thermal efficiency up to 50% corresponding to low heat value of the fuel (LHV). This study focused on converting Zubair Oil Field Gas turbine (ALSTOM GT13E2) from single cycle into a combined cycle power plant. Models suggestion design have been presented with back-pressure steam turbine by Cycle-Tempo (5.1) thermodynamics simulation program, which presents value diagram and exergy flow diagram both are useful to understanding the thermodynamic performance of complicated systems.The result of exergy analysis explicate that huge amount of exergy loss firstly occurs in gas turbine combustor (about 60% due to high irreversibility), and heat recovery steam generation (HRSG) is the second major exergy loss in combined cycle power plant (about 30%) recently apparatus concepts less than 10% of exergy (like compressors and expanders). Also, in this study explained the effect of changing the ambient temperature on the performance of power plant by using four temperature parameters on the four simulation models at constant compression ratio. The results were the increase in gas turbine temperature inlet led to decrease the net power output of the CCPPs. Thermal and exergy efficiencies increase when ambient temperature increase due to growth turbine inlet temperature but this temperature restricted by creep rupture and thermal fatigue for combustor parts and turbine blades metal. Maximum thermal and exergy efficiencies can be reached to 55.74, 53.28% respectively at worst ambient temperature. The calculation results in this study were compared with two previous studies, with considerable differences in input parameters of the gas turbine and steam turbine also, the types of the gas turbine models. finally, the results showed acceptable agreement.

Low emission flash-binary and two-phase binary geothermal power plants with water absorption and reinjection of non-condensable gases

The power production from geothermal resources with a high content of non-condensable gases (NCG) is concerning an increasing number of regions and may affect the sustainability relating to geothermal projects. The selection of an emission abatement system based on water absorption and reinjection of NCG back to the reservoir could solve the environmental impact, yet it implies significant power output penalty and water demand, as demonstrated in a recent paper by the authors (Manente et al., 2019) focused on the retrofit of existing flash steam power stations. A reconsideration of the plant design could result in a better integration with the absorption and reinjection section and finally reduce the associated requirements. To address this point, two “greenfield” plant layouts are investigated in this paper for utilization of a high enthalpy liquid dominated reservoir, where the single flash steam generation unit is complemented or even totally replaced by air cooled binary cycle units. The first layout is an “integrated flash-binary” plant based on a backpressure steam turbine and a bottoming ORC system, whereas the second layout consists in a “two-phase binary” plant. The performance of the two novel layouts is compared against that of a brownfield layout, first proposed in Manente et al. (2019), based on an existing single flash plant retrofitted with the absorption and reinjection system, using a consistent set of assumptions. The results show that the net power output remains almost unaltered because in the novel layouts the lower parasitic loads for gas compression counterbalance the lower production dictated by the air-cooled system and the irreversibility in the heat transfer between geothermal fluid and organic fluid. Thus, due to the better integration between power block and emission abatement section the net power output penalty of the novel layouts is contained within 2%. On the other hand, the hydrogen sulfide and carbon dioxide abatement efficiencies markedly increase as the removal of the cooling tower eliminates the secondary gaseous emissions and makes the entire steam condensate available for NCG absorption. In the integrated flash-binary plant design the overall H2S and CO2 abatement efficiencies reach 99% and 90%, respectively, without any external water demand, provided that measures are taken for a controlled precipitation of silica and other minerals from the geothermal brine prior to using it for NCG absorption.

Integration of Flow Temperatures in Unit Commitment Models of Future District Heating Systems

The transformation of heat supply structures towards 4th generation district heating (4GDH) involves lower supply temperatures and a shift in technology. In order to assess the economic viability of the respective systems, adequate unit commitment models are needed. However, maintaining the formal requirements, while reducing the computational efforts of these models, often includes simplifications such as the assumption of constant supply temperatures. This study investigates the effect of introducing varying supply temperatures in mixed-integer linear programming models. Based on a case study of a municipal district heating system, how the temperature integration approach affects unit commitment and technology assessment for different temperature levels and scenarios is analyzed. In particular, three supply temperature levels are investigated with both variable and constant temperatures in two scenarios. Results indicate that lower flow temperature levels in the heating network tend to favor internal combustion engines, combined cycle power plants, and heat pumps; while back pressure steam turbines, peak loads, and electric boilers show declining operating hours. Furthermore, the effect of varying versus constant temperatures at the same temperature level is rather small, at least as long as technical restrictions do not come into play. Finally, it is found that the effect of changing temperature on a technology assessment is comparably small as opposed to adaptions in the regulatory framework.

The Experience in Operation and an Efficiency Analysis for the Use of a Backpressure Steam Turbine Generator Unit in a Boiler House

Turbine generators can be used for utilization of the potential of steam lost in pressure-reducing and cooling units of operating boiler houses. This approach brings about an independent source of power the price of which can be much lower than the established tariff. The features in reconstruction of a boiler house in the city of Bratsk, Irkutsk oblast, carried out in 2012 are examined. Steam generated in a KE-50-14-225 boiler is routed to a 0.3–0.5 MPa common header for use in deaerators and steam-water heaters. Considering an increase in the electricity tariffs, a decision was made to install a 500-kW backpressure turbine generator in the boiler house in parallel with the pressure-reducing unit to generate auxiliary power. The criteria for selecting the number and power of turbine generator units depending on the required steam generation, operating conditions of the consumer, the level of electric loads of the boiler house, and the existing heat supply system are shown. The specifics in operation of the turbine generator unit are examined. To ensure safe and reliable operation of the unit, it is advisable to increase the number of monitored parameters through extension of the normal instrumentation system. The discounted payback period for the reconstruction cost and additional costs for installation of a second turbine generator unit are estimated. The boiler house regimes, a change in the prices for fuel and electricity, and the operator’s labor cost are considered. After installation of the turbine generator, the specific fuel consumption for electricity generation amounts to 180 g.c.e /(kW h). In 2017, the electricity generation cost was 1.23 rubles/(kW h) with the average tariff of 2.13 rubles/(kW h). The discounted payback period for the performed reconstruction does not exceed 6 years, and that for further reconstruction is 8 years.

Investigating the efficiency of a steam-turbine heating plant with a back-pressure steam turbine and waste-heat recovery

The article considers a promising steam-turbine heating plant, which includes a steam turbine with back pressure and a steam boiler operating on natural gas, with waste heat recovery. The mathematical model of а steam-turbine heating plant has been developed to perform one design calculation in the nominal mode and several verification calculations in characteristic modes with different thermal loads. Optimization calculations of the unit were carried out for two regions with different climatic conditions and different fuel prices. The optimal design parameters of the equipment, the parameters of the working fluid and coolants at all points of the technological scheme, as well as fuel costs in each characteristic mode of operation have been found by the criterion of the minimum price of electricity. The considered steam-turbine heating plant provides a higher heat utilization coefficient of the fuel than the traditional heating plant.

Optimal design of cogeneration systems in total site using exergy approach

By increasingly demands on the hot and cold utilities in chemical processing industries, application of unified utility systems has extended in recent decades. Through the Total Site, accessibility to hot steam and condensing water has become more convenience. Therefore, cogeneration systems generate key product of total site, power to electricity network as well as steam to heating purposes. Also, it can be considered to consume the cold utilities to cooling destinations. In present work, defining the multiple arrangements of back pressure steam turbines, an optimal design of heat and power cogeneration systems through exergy point of view is determined. The excellent exergy efficiency and also the least amount of exergy destruction was measured to select the optimum system of arrangements. In times of need for extra power, either a condensing turbine or gas turbine system, were meant to generate deficiency of electricity in network. Then, both the extra scenarios were studied by exergy analysis. Consequently, final optimum system of cogeneration system in total site was selected. This ultimate optimal configuration is consisting the optimal steam turbines as well as the appropriate augmented scenario from exergetic viewpoint, between condensing or gas turbine systems. In addition, two case studies of utility systems were employed to confirm the applicability of proposed methodology.

Investigating steam turbine feasibility to improve the sustainability of a biomass boiler using TRNSYS

Adding a turbine to a steam generator plant of a district energy system increases the efficiency of the plant by generating some electricity. This is the method of turning a heating and cooling plant into a combined heating, cooling, and power plant. The district energy plant at University of Idaho, Moscow, Idaho, USA is modeled by using TRNSYS modeling software. Simulation of different models is made to compare the current system configuration to the current plus a small backpressure steam turbine, and adding a double effect absorption chiller. Operating costs, energy, and exergy efficiencies are evaluated at current and maximum steam pressure levels through the boiler and turbine. Primary components in the system include a wood chip fired boiler, steam turbine, 2100 kW single effect and 4100 kW double effect absorption chillers, and campus with associated pumping needs. Results show that installing a turbine and increasing pressure to maximum possible levels improve energy and exergy efficiency by 3–4% and 5%, respectively over current levels. Bringing a double effect chiller in addition to the turbine increases energy and exergy efficiencies further to 20% and 7%. Economic savings are substantial if power can be sold back to the utility at a higher rate.

Methodology and Continuous Time Mathematical Model to Select Optimum Power of Gas Turbine Set for Dual-Fuel Gas-Steam Combined Heat and Power Plant in Parallel System

This paper contains the results of a study in which a novel approach using continuous time notation was applied in the search for the optimum capacity of a gas turbine designed for a dual-fuel gas-steam combined heat and power plant in a parallel system. As a result of the application of mathematical models of any functions that account for variations in time of all integrand quantities, for example prices of energy carriers, the model that was developed provides a way to analyze complex dependencies. The results of calculations obtained as a result of using this notation provide a rational selection of technologies and equipment designed for the energy industry. The results are based on an analysis involving a combined heat and power plant with an extraction-condensing steam turbine and extraction backpressure steam turbine for a wide range of the variability in energy prices and environmental charges corresponding to the current prices and environmental charges. All the curves were obtained using innovative methodology and mathematical model in which the total, discounted profit is calculated at the given moment and expressed as NPV achieved from the operation of dual-fuel gas-steam combined heat and power (CHP) plant.

Energy-exergy-economic (E3) analysis of stand-alone solar thermal cogeneration power plant

Concentrating solar power (CSP) based solar cogeneration plants are more energy efficient compared to single purpose power plants. In this paper, energy, exergy and economic analysis have been carried out for the stand-alone solar thermal co-generation power plant (SASTCPP), which is based on Rankine cycle. Both direct and indirect steam generation is adopted for the comparative E3 analysis. To achieve high energy efficiency, back pressure steam turbine with regenerative feed water heating is incorporated in power block. Reference cogeneration power plant has a capacity of 50 MWth. levelised cost of electricity (LCOE) associated to SASTCPP is calculated with three different cost allocation approach – direct, equivalent fuel consumption, and exergy approach. The observed exergy efficiency (33–35%) is comparatively less than energy efficiency (62–70%) and the maximum exergy destruction takes place within the solar field. Minimum LCOE calculated as Indian rupees (INR) 5.46 with direct steam generation (DSG).

Influence of inter nal relative efficiency of steam turbine compartments on the performance of steam turbine cogeneration plant

The paper considers a steam turbine cogeneration plant that includes a back-pressure steam turbine and a natural gas-fired steam boiler that enables exhaust gas heat recovery, which is rather promising for the isolated heat and electricity consumers. A design and verification mathematical model of the steam turbine plant was developed. The focus is made on the optimization studies into the effect of the relative efficiency of turbine compartments on the performance indices of the steam turbine cogeneration plant with an installed electric capacity of 50 MW that uses the heat of steam contained in the combustion products of the boiler for heating the feed-water of the heat network.

Vinasse concentration and juice evaporation system integrated to the conventional ethanol production process from sugarcane – Heat integration and impacts in cogeneration system

In the ethanol production process one of the most polluting residues is the vinasse, which is the bottom product of distillation column. Vinasse is produced in the range of 10–15 L per litre of ethanol, and is currently used to irrigate sugarcane fields because of the presence of macronutrients (N, P, K) in its composition. However, because of the large amount produced, its disposition in sugarcane fields involves high transport costs and does not allow an adequate application, thus causing damage to soil and groundwater due to its high content of organic components. In this context, vinasse concentration with multiple-effect evaporator systems not only allows to reduce significantly its volume through the increase of its initial solids concentration, that is generally between 2 and 5%, which reduces the costs of disposal; but also allows to consider alternative ways of energetic usages, for instance, its incineration or anaerobic biodigestion. Thus, the aim of this study is to accomplish an energy evaluation of the heat integration of a juice evaporation system and a vinasse concentration system in the conventional ethanol production process by analysing three different configurations of multiple-effect evaporator systems. The energy and mass balances were solved using the EES® software while heat integration, using the Pinch Method, was applied in order to minimize the utility consumption. A simulation of the cogeneration system was also performed in order to evaluate bagasse and electricity surplus. Two configurations for the cogeneration system were studied: i) using back-pressure steam turbines and ii) using condensing-extracting steam turbines. Additionally, an economic assessment was performed in order to estimate the capital and operating costs, aiming to identify the most appropriate configuration. The results show that it is necessary to project the integration of these concentration systems taking into account the overall process. Furthermore results show that an appropriate integration of evaporation systems (Case2) could achieve steam consumption at the range of 345 kg/t cane and electricity surplus for sale of 91 kWh/t cane.

CCS on Offshore Oil and Gas Installation - Design of Post-Combustion Capture System and Steam Cycle

Most of the released CO2 on offshore oil and gas installation originates from the gas turbines that power the installations. For certain offshore installations, CO2 capture and storage (CCS) could be an alternative to decrease the CO2 emissions. When opting for a chemical absorption CO2 capture system, a heat source for the stripper reboiler is needed. Since most offshore installations are powered by simple cycle GTs, there is typically no steam available that could be used for stripper reboiler heat. A compact steam bottoming cycle could, in addition to providing the reboiler steam, partly or fully provide power from a steam turbine generator to the equipment in the CCS system, including CO2 compressors, pumps, and flue gas booster fan. Three different steam cycle configurations were designed, modeled, and simulated. The design of the post-combustion CO2 capture system is also presented but the main focus in the paper is on the steam cycle design. In addition to the energy and mass balance results, a weight assessment of the major equipment was done with the objective to come up with a simplified weight relationship for changes in the oil and gas installation size in terms of changes in total mass flow from the gas turbines. A steam cycle with a back-pressure steam turbine was ultimately selected. The back-pressure option was able to provide all necessary steam and power (with some margin) to the CO2 capture and compression system.

Lifetime Assessment of Combined Cycles for Cogeneration of Power and Heat in Offshore Oil and Gas Installations

The utilization of combined cycles for offshore cogeneration of power and heat is an attractive option to reduce the CO2 emissions directly related to the oil and gas sector. Main challenges for their efficient implementation are the potentially large heat-to-power ratios and the variability of power and heat requirements throughout the different stages of a field’s lifetime. This paper aimed to provide the first elements for an assessment of the technology. Two combined cycle configurations were evaluated (backpressure and extraction steam turbine cycle), as well as different scenarios of power and heat requirements. The optimum design approach was firstly investigated. Designing the combined cycle at the end-life conditions, rather than at peak conditions, demonstrated to return better overall performance, when the entire plant’s lifetime is considered. A comparative analysis between the defined optimum designs was then carried out. Although the backpressure steam turbine cycle demonstrated to be feasible in all the cases analyzed, it showed to be effective only for offshore installations characterized by low temperature large process heat demands. On the other hand, the extraction steam turbine cycle could not meet large process heat demands but it was very attractive when the heat requirements were more limited, irrespective of the temperature at which this heat was requested.

Effect of external conditions and steam parameters on performance of combined-cycle power plants with back-pressure steam turbine

The cogeneration combined-cycle gas turbine plant with back-pressure steam turbine is considered. A simple circuit of the plant increases its reliability, and the use of optimal temperatures of the heating and return water allows obtaining the highest thermal efficiency of the plant taking into account the ratio of its electric and heat power. The technical and economic efficiency of the combined-cycle plant with back-pressure steam turbine is studied to estimate the capital investment. The parameters and conditions to maximize the net present value growth relative to the base version are determined.

Technical and economic analysis of the combined-cycle plant with back-pressure steam turbine

The cogeneration combined-cycle gas turbine plant with back-pressure steam turbine is considered. A simple circuit of the plant increases its reliability, and the use of optimal temperatures of the heating and return water allows obtaining the highest thermal efficiency of the plant taking into account the ratio of its electric and heat power. The technical and economic efficiency of the combined-cycle plant with back-pressure steam turbine is studied to estimate the capital investment. The parameters and conditions to maximize the net present value growth relative to the base version are determined.

Carbon Capture and Storage for Enhanced Oil Recovery: Integration and Optimization of a Post-Combustion CO2-Capture Facility at a Power Plant in Abu Dhabi

Summary Masdar has initiated the Abu Dhabi Carbon-Capture and -Storage Project, with the objective to develop a carbon-capture network in Abu Dhabi capable of creating large reductions of carbon dioxide (CO2) emissions and with the capacity to increase oil recovery by use of CO2 for enhanced oil recovery (EOR). Because Siemens (henceforth referred to as the Technology Owner) has developed, tested, and piloted a proprietary post-combustion CO2-capture technology (PostCapTM) for the removal of CO2 from the flue gas of coal- and gas-fired power plants suitable for the project, both parties decided to cooperate in executing a front-end engineering and design (FEED) study. The technology is based on an aqueous amino-acid-salt solution. The Technology Owner and Masdar have completed a FEED study for capturing 1,800,000 tons of CO2 annually from a natural-gas-fired power plant in Abu Dhabi by application of the PostCapTM technology. Various opportunities and challenges were encountered during the design of the retrofit capture plant. Challenges were often specific to the region, including local climate, water availability, and flue-gas quality. Design and optimization of the plant were influenced by local energy and labor prices. Further opportunities included integration with the power plant and with a local industrial facility. The power plant had to supply the capture plant with steam and power without reducing the original electricity-production capacity. To accomplish this, several heat- and power-integration concepts were evaluated with respect to their feasibility, including the application of a backpressure steam turbine and the retrofit of a simple-cycle gas turbine to combined-cycle gas turbine. Various cooling options were considered in view of climate and resource challenges. Cooling water had to be extracted from a reflux stream produced by an adjacent industrial facility. Drawing on the results of the FEED study, this paper presents the manner in which PostCapTM technology can be applied for capturing CO2 at a power plant in Abu Dhabi for the purpose of EOR, while satisfying specific local needs, and the way utility supply and power plant integration can be facilitated.

Surplus electricity production in sugarcane mills using residual bagasse and straw as fuel

The cogeneration system is one of the most important parts of sugarcane mills which use the bagasse as fuel. In the recent years, modern equipments and energy efficiency measures made possible to the sugarcane industry, the production of surplus electricity which become, besides the sugar and ethanol, a third product from the same renewable source, the sugarcane. This work analyses the surplus electric power systems for three different schemes of cogeneration system in the sugarcane industry through the simulator Thermoflow®. The analysis is made considering both the available bagasse and sugarcane straw recovery as fuel in three different scenarios for the industrial process energy requirements. The results show that the CEST (Condensing Extraction Steam Turbine) system can have a surplus of electricity of up to four times higher than the BPST (Backpressure Steam Turbine) system. The system CEST can have an increase in surplus power above 23% and 102% for the rate of 10% and 50% of cane straw recovery in the field respectively. The BPST-C (Backpressure and Condensing Turbines) system can produce similar values of surplus electricity when compared with the system CEST, but may represent an opportunity of flexible operation of the cogeneration systems in harvest and off-seasons.

Thermodynamic and economical analysis of the ORC module application to an existing combined heat and power unit with the backpressure turbine

This paper presents the results of the thermodynamic and economic analyses of two variants of integration of a CHP unit with ORC modules. The first variant consists in an integration of a CHP unit with a single ORC module. The module is installed on one of the steam outlets from the asymmetric part of a back-pressure steam turbine. The second variant assumes installation of modules on two outlets of this part of the steam turbine. An argument for the integration of a unit with ORC modules is the ability to obtain in the summer period additional electric power based on the use of heat, which in the period of lower demand for heat is dissipated in the environment. For these two variants, the thermodynamic analysis was carried out, which allowed to determine the electrical power that can be generated by ORC modules. Analyses were performed for various low-temperature boiling fluids. Economic analyses were also performed, which allowed to determine the net present value and the internal rate of return for the two variants of integration. Assumptions required to perform economic analyzes were adopted. As a part of the economic analysis, sensitivity analysis of the selected economic effectiveness indicators on the relative change of the investment cost and electricity prices was performed. The influence of changes of working time of the integrated unit within a year and the discount rate was also examined. The obtained results indicate a high potential of the proposed integrations. Supplying of ORC modules by steam leaving the backpressure steam turbine can allow for economically justified extension of the period of operation of many CHP units. Appropriate modernizations in the case of switched off post-industrial CHP units can contribute to the restoration of their ability to generate profit.