Two combined cooling heating power (CCHP) plant layouts are proposed to supply the electricity, heat, and cooling energy demands of textile industries. In the first scenario, natural gas fueled internal combustion engines are integrated with a heat recovery steam generator (HRSG) and a hot water absorption chiller to produce electricity, saturated steam, and chilled water for air conditioning purposes. In the second concept, a linear Fresnel solar field is integrated with the same CCHP to provide fuel economy during the sunny hours. The proposed plants were compared with a base case scenario in which electricity is imported from the grid, saturated steam is provided by a natural gas steam generator (NGSG), and chilled water is provided by electric chillers. Simulations were performed considering mass and energy conservation equations, information provided by equipment manufacturers and typical meteorological year (TMY) data sets for three different locations. The economic performance of plants was evaluated by calculating the net present value (NPV), the internal rate of return (IRR), and the discounted payback period (DPP) of investments. As an important result, a great potential for reducing the fuel consumption and CO 2 emissions of hybrid concept was identified. However, the high investment of Fresnel collectors coupled with low natural gas prices showed the proposed hybrid concept as economically unfeasible. Nevertheless, it is expected that hybrid systems will have an important role once Fresnel technology costs are continuously declining and solar energy appears as a promising alternative for the sustainable transition to a low carbon future.

The concentration ratio of the parabolic dish solar collector (PDSC) is considered to be one of the highest among the concentrated solar power technologies (CSPs); therefore, such system is capable of generating more heat rate. The present paper focuses on the integration of the PDSC with the combined cycle (gas cycle as the toping cycle and steam cycle as the bottoming cycle) along with the utilization of waste heat from the power cycle to drive the single effect lithium bromide/water absorption cycle. Molten salt is used as a heat transfer fluid in the solar collector. The engineering equation solver (EES) is employed for the mathematical modeling and simulation of the solar integrated system. The various operating parameters (beam radiation, inlet and ambient temperatures of heat transfer fluid, mass flow rate of heat transfer fluid, evaporator temperature, and generator temperature) are varied to analyze their influence on the performance parameters (power output, overall energetic and exergetic efficiencies, outlet temperature of the receiver, and as coefficient of performance (COP) and exergy efficiencies) of the integrated system. The results show that the overall energy and exergy efficiencies are observed to be 39.9% and 42.95% at ambient temperature of 27 °C and solar irradiance of 1000 W/m 2 . The outlet temperature of the receiver is noticed to decrease from 1008 K to 528 K for an increase in the mass flow rate from 0.01 to 0.05 kg/s. The efficiency rate of the power plant is 38%, whereas COP of single effect absorption system is 0.84, and it will decrease from 0.87 to 0.79. However, the evaporator load is decreased to approximately 9.7% by increasing the generator temperature from 47 °C to 107 °C.

This paper aims to present the process control laws developed for the concentrated solar power plant in Dhursar India by Areva Solar. The technology (linear Fresnel reflector (LFR), direct steam generation (DSG), once-through) used to produce superheated steam although being the most direct method is also the most challenging regarding the controls. The main control loops presented here are the flow control, the energy input control, and the steady-state optimization. With these control laws, the plant was able to produce 110 MWe in March 2016.

Parabolic trough solar concentrating technology is a new and clean way to replace the conventional fossil fuel technology to generate steam for heavy oil recovery in oilfield. A computational model was constructed with simulated direct normal irradiance from nearby similar climate locations. Different system configurations were analyzed with the model, such as with single- and dual-loop, with and without heat storage system. Finally, several solar field configurations with different collector field layouts were compared by the cost of unit generated steam. Results show that using heat storage can effectively improve the stability of steam production, and in a certain oilfield, an optimum steam production amount and optimum heat storage time (HST) exist for lowest steam cost. The methods and results in the paper provide useful suggestions for the implementation of a solar thermal oilfield steam production system.

Compared with recirculation and injection modes, once-through direct steam generation (DSG) parabolic troughs are simpler to construct and require the lowest investment. However, the heat transfer fluid (HTF) in once-through DSG parabolic trough systems has the most complicated dynamic behavior, particularly during periods of moving shadows caused by small clouds and jet contrails. In this paper, a nonlinear distributed parameter dynamic model (NDPDM) is proposed to model the dynamic behavior of once-through DSG parabolic trough solar collector row under moving shadow conditions. Compared with state-of-the-art models, the proposed NDPDM possesses three characteristics: (a) adopting real-time local values of the heat transfer and friction resistance coefficients, (b) simulating the whole collector row, including the boiler and the superheated sections, and (c) modeling the disturbance of direct normal irradiance (DNI) level on DSG parabolic trough solar collector row under moving shadow conditions. Validated using experimental data, the NDPDM accurately predicts the dynamic characteristics of HTF during periods of partial and moving DNI disturbance. The fundamental and specific dynamic process of fluid parameters for a DSG parabolic trough solar collector row is provided in this paper. The results show the following: (a) Moving shadows have a significant impact on the outlet temperature and mass flow rate, and the impact lasts up to 1000 s even after the shadows completely leave the collector row. (b) The time for outlet steam temperature to reach a steady-state value for the first time is independent of the shadow width, speed, and moving direction. (c) High-frequency chattering of the outlet mass flow rate can be observed under moving DNI disturbance and will have a longer duration if the shadow width is larger or the shadow speed is slower. Compared with cases in which the whole system is shaded, partially shading cases have shown a longer duration of high-frequency chattering. (d) Both wider widths and slower speeds of shadow will cause a larger amplitude of responses in the outlet temperature and mass flow rate. When the shadow speed is low, there is a longer delay time of response in the mass flow rate of the outlet fluid. (e) The amplitude of response in the outlet temperature does not depend on the direction of clouds movement. However, if the DNI disturbance starts at the inlet of the collector row, there will be significant delay times in both outlet temperature and mass flow rate, and a larger amplitude of response in outlet mass flow rate.

Today most commercial parabolic trough collector (PTC) solar power plants make use of the well-known LS3/Eurotrough optics. The PTC has a concentration ratio relative to the maximum thermodynamic limit equal to 0.31. In order to improve the competiveness of PTC technology, two well differentiated R&D strategies have been undertaken: (i) developing larger parabolic troughs, which places a higher demand in tracking accuracy and lower tolerances with respect to wind loads, quality of mirrors, control and assembly imprecisions, and (ii) developing secondary concentrators with the aim of bringing the concentration ratio relative to the maximum one as close to 1 as possible. In this paper, a parametric trough collector (PmTC) for a flat receiver designed with the simultaneous multiple surface (SMS) method is proposed. The method assumes zero transmission, absorption, and reflection optical losses and allows for both reflective primary and secondary surfaces (XX-reflective plus reflective) to be simultaneously designed, guaranteeing Etendue matching. The proposed PmTC geometry increases the referred ratio up to 0.59 with a rim angle greater than 100 deg and with the same effective acceptance angle as the PTC. The flat absorber can be replaced with a multitube receiver for application in direct steam generation (DSG).

The objective of this investigation is the comparison between supercritical ethane (s-ethane, C 2 H 6 ) and supercritical carbon dioxide (s-CO 2 ) Brayton power cycles for line-focusing concentrated solar power plants (CSP). In this study, CSP are analyzed with linear solar collectors (parabolic trough (PTC) or linear Fresnel (LF)), direct molten salt (MS), or direct steam generation (DSG) as heat transfer fluids (HTF), and four supercritical Brayton power cycles configurations: simple Brayton cycle (SB), recompression cycle (RC), partial cooling with recompression cycle (PCRC), and recompression with main compression intercooling cycle (RCMCI). All Brayton power cycles were assessed with two working fluids: s-CO 2 and s-ethane. As a main result, we confirmed that s-ethane Brayton power cycles provide better net plant performance than s-CO 2 cycles for turbine inlet temperatures (TITs) from 300 °C to 550 °C. As an example, the s-ethane RCMCI plant configuration net efficiency is ∼42.11% for TIT = 400 °C, and with s-CO 2 the plant performance is ∼40%. The CSP Brayton power plants were also compared with another state-of-the-art CSP with DSG in linear solar collectors and a subcritical water Rankine power cycle with direct reheating (DRH), and a maximum plant performance between ∼40% and 41% (TIT = 550 °C).

This research studied the effects of suction heads on the efficiency of a thermal water pump with steam. In order to save energy, the authors also studied the appropriate amount of air added to a steam working fluid. Cooling time was attempted to be shorten, direct contact cooling was employed. The system comprised feed water tank (FT), liquid piston tank (LT), heat tank (HT), storage tank (ST), well tank (WT), and check valve (CV). It was directly cooled by cooling water. Thermal energy input was supplied by an electric heater as a substitute of heat sources such as firewood. An operation of the pump consisted of five stages: heating, pumping, vapor-flow, cooling, and suction. In conclusion, increasing the suction head raised the pumping efficiency until the maximum was achieved. Using air in conjunction with the steam working fluid could lower the working temperature suitable for solar application. In addition, the simulation of a thermal pump with steam was merely presented. A good agreement between the test and the model was found. The larger pump size was selected to be constructed and tested in order to increase the pump efficiency. Agricultural application of the larger pump could obtain energy source from waste of firewood at no cost.

Once-through direct steam generation (DSG) plants convert water into superheated steam suitable for a steam turbine with a single pass of the fluid through the receiver. The control problem in such a plant is to set a feed-water mass flow that maintains a desired steam condition (e.g., temperature) while rejecting the disturbance effect of variable direct normal irradiance (DNI). A mass flow control strategy preserves the simplicity of the plant, but is challenging to implement from a control perspective, as the disturbance effect is nonlinear and difficult to measure, due to the complex physical nature of two-phase flow and the receiver geometry. A model of the receiver behavior can be incorporated into the controller design in the form of a state observer, to estimate the internal behavior of the receiver during operation. This paper presents the design, testing an experimental implementation of full state linear feedback controller for the steam temperature for a once-through DSG system. The system consists of a 500 m2 paraboloidal dish concentrator and a monotube cavity receiver at the Australian National University. The controller manipulates the feed-water mass flow at the receiver inlet to maintain a predetermined specific enthalpy at the receiver outlet, compensating for variations in DNI and other ambient conditions. The controller features three separate regulation mechanisms: a feedforward (FF) law to anticipate changes in DNI; a full state feedback (FSF) loop with a state observer for the receiver; and an additional integrator loop for robustness. Experiments on the Australian National University (ANU) system show that the linear controller maintains steam temperatures to within 3% of a set reference of 500 °C during clear sky conditions, subject to adequate controller tuning. These results show that it is possible to control the ANU system with an FSF loop and state estimator, opening the possibility to test more advanced state based controllers.

The heating process of melting margarine requires a vast amount of thermal energy due to its high melting point and the size of the reservoir it is contained in. Existing methods to heat margarine have a high hourly cost of production and use fossil fuels which have been shown to have a negative impact on the environment. Thus, we perform an analytical feasibility study of using solar thermal power as an alternative energy source for the margarine melting process. In this study, the efficiency and cost effectiveness of a parabolic trough collector (PTC) solar field are compared with that of a steam boiler. Different working fluids (water vapor and Therminol-VP1 heat transfer oil (HTO)) through the solar field are also investigated. The results reveal the total hourly cost ($/h) by the conventional configuration is much greater than the solar applications regardless of the type of working fluid. Moreover, the conventional configuration causes a negative impact to the environment by increasing the amount of CO2, CO, and NO2 by 117.4 kg/day, 184 kg/day, and 74.7 kg/day, respectively. Optimized period of melt and tank volume parameters at temperature differences not exceeding 25 °C are found to be 8–10 h and 100 m3, respectively. The solar PTC operated with water and steam as the working fluid is recommended as a vital alternative for the margarine melting heating process.

This work proposes and analyses several integration schemes specially conceived for direct steam generation (DSG) in megawatt (MW) range central receiver solar thermal power plants. It is focused on the optical performance related to the heliostat field and the arrangement of receiver absorbers, and the management of steam within a Rankine cycle in the range between 40–160 bar and 400–550 °C at design point. The solar receiver is composed of one single element for saturated steam systems or two vertically aligned separated units, which correspond to the boiler and the superheater (dual-receiver concept), for superheated steam solar thermal power plants. From a fixed heliostat field obtained after layout optimization for the saturated steam solar plant the heliostat field is divided in two concentric circular trapezoids where each of them independently supplies the solar energy required by the boiler and the superheater for the different steam conditions. It has been observed that the arrangement locating the boiler above the superheater provides a slightly higher optical efficiency of the collector system, formed by the solar field and the receiver, compared with the reverse option with superheater above boiler. Besides, two-zone solar fields provide lower performances than the entire heliostat layout aiming at one absorber (saturation systems). Optical efficiency of two-zone solar fields decreases almost linearly with the increment of superheater heat demand. Concerning the whole solar collector, heliostat field plus receiver, the performance decreases with temperature and almost linearly with the steam pressure. For the intervals of steam pressure and temperature under analysis, solar collector of saturated steam plant achieves an optical efficiency 3.2% points higher than the superheated steam system at 40 bar and 400 °C, and the difference increases up to 9.3% points when compared with superheated system at 160 bar and 550 °C. On the other hand, superheated steam systems at 550 °C and pressure between 60 and 80 bar provide the highest overall efficiency, and it is 2.3% points higher than performance of a saturated steam solar plant at 69 bar. However, if saturated steam cycle integrates an intermediate reheat process, both would provide similar performances. Finally, it has been observed that central receiver systems (CRS) producing saturated steam and superheated steam at 500 °C operating at 40 bar provide similar performances.

A model predictive control (MPC) system for a solar-thermal reactor was developed and applied to the solar-thermal steam-gasification of carbon. The controller aims at rejecting the disturbances in solar irradiance, caused by the presence of clouds. Changes in solar irradiance are anticipated using direct normal irradiance (DNI) forecasts generated using images acquired through a Total Sky Imager (TSI). The DNI predictor provides an estimation of the disturbances for the control algorithm, for a time horizon of 1 min. The proposed predictor utilizes information obtained through the analysis of sky images, in combination with current atmospheric measurements, to produce the DNI forecast. The predictions of the disturbances are used, in combination with a dynamic model of the process, to determine the required control moves at every time step. The performance of the proposed DNI predictor-controller scheme was compared to the performance of an equivalent MPC that does not use DNI forecasts in the calculation of the control signals. In addition, the performance of a controller fed with perfect DNI predictions was also evaluated.

In this paper, a hybrid solar and coal-fired steam power plant with secondary air preheating is proposed, which has much higher thermal efficiency than existing hybrid solar and coal-fired power generation systems. Five cases in total are modeled using GateCycle™. The simulation indicates that the solar-to-power efficiency of the new system is 5.5–6.5% points higher than solar-feedwater (HP) systems. The performance of the base case is compared with other cases to identify the potentials of the new system. Thermodynamic analysis is carried out and bleed steam heat-to-power conversion ratios are calculated for comparison. In addition, boiler operating parameters are investigated and fuel saving mode and power boost mode are compared.

The cost reduction potential of solar power towers (SPT) is an important issue concerning its market introduction. Raising the steam process temperature and pressure can lead to a cost reduction due to increased overall plant efficiency. Thus, for new receiver configurations, a supercritical steam cycle operated at 300 bar/600 °C/610 °C live steam conditions was assumed. The considered systems include innovative direct absorption receivers, either with conventional or beam down heliostat field layouts. For the beam down option, the receiver is assumed to be a cylindrical vessel with a flow-through porous absorber structure at the internal lateral area of the cylinder. The direct absorption receiver option consists of a cylindrical barrel with downwards oriented aperture, whose absorber structure at the internal lateral area is cooled by a molten salt film. For the assessment, CFD based methods are developed and able to examine the receiver efficiency characteristics. Based on the receiver thermal efficiency characteristics and the solar field characteristics, the annual performance is evaluated using hourly time series. The assessment methodology is based on the European Concentrated Solar Thermal Roadmap (ECOSTAR) study and enables the prediction of the annual performance and the levelized cost of electricity (LCOE). Applying appropriate cost assumptions from literature, the LCOE are estimated for each considered SPT concept and compared to tubular receiver concepts with molten salt and liquid metal cooling. The power level of the compared concepts and the reference case is 200 MWel. The sensitivity of the specific cost assumptions is analyzed. No detailed evaluation is done for the thermal storage, but comparable storage utilization and costs are assumed for all cases. At optimized plant parameters, the results indicate a LCOE reduction potential of up to 0.5% for beam down and of up to 7.2% for the direct absorption receiver compared to today's state of the art molten salt solar tower technology.

In a solar hybrid system, the intermittent solar radiation seriously effects the solar-to-electricity conversion. In this paper, the energy-level mechanism between the concentrated solar heat and the thermal cycle was discussed. The system analysis was taken on a 200 MW coal-fired power plant hybridized with solar heat at approximately 300 °C, where the middle-temperature solar thermal energy was used to preheat the feed water before entering the boiler. With changing solar radiation in typical days, the solar share, the work output and the net solar-to-electricity efficiency of this solar hybrid system were evaluated. The net solar-to-electricity efficiency would be increased by 3–7% points compared to that in a solar-only power plant. An off-design parallel configuration of this hybrid system was proposed, achieving the net annual solar-to-electricity efficiency of 18%. It would expected to be an attractive approach to develop the scale-up mid-temperature solar thermal power technology in the short and midterm.

Solar heat at moderate temperatures around 200 °C can be utilized for augmentation of conventional steam-injection gas turbine power plants. Solar concentrating collectors for such an application can be simpler and less expensive than collectors used for current solar power plants. We perform a thermodynamic analysis of this hybrid cycle, focusing on improved modeling of the combustor and the water recovery condenser. The cycle's water consumption is derived and compared to other power plant technologies. The analysis shows that the performance of the hybrid cycle under the improved model is similar to the results of the previous simplified analysis. The water consumption of the cycle is negative due to water production by combustion, in contrast to other solar power plants that have positive water consumption. The size of the needed condenser is large, and a very low-cost condenser technology is required to make water recovery in the solar STIG cycle technically and economically feasible.

A new concept for control of the flow field, and thus particle yield, in an aerosol reactor designed for the hydrolysis of Zn in the two-step Zn/ZnO solar thermochemical cycle for hydrogen production is described and evaluated. For the hydrolysis step, much attention has been given to Zn nanoscale reacting aerosols for their potential to increase conversion to ZnO and because they enable a continuous, controllable process. The success of this continuous process depends on achieving high particle yields in the reactor. A key challenge is to control the flow field in aerosol reactors to keep the particles entrained in the flow without deposition on the reactor wall. The ability of a new reactor concept based on transverse jet fluid dynamics to control the flow field and rapidly cool the Zn vapor is investigated. In the transverse jet reactor, evaporated Zn entrained in an Ar carrier gas issues vertically into the horizontal tubular reactor through which cooler H2O and Ar flow. Particles are formed in the presence of steam at ~450 K. The trajectory of the jet is controlled via the effective velocity ratio, R, which is the square root of the ratio of the kinetic energy of the jet to that of the cross-flow. A computational fluid dynamics (CFD) model indicates that the trajectory of the jet can be controlled so that the majority of the Zn mass is directed down the center of the reactor, not near the reactor walls for R = 4.25 to R = 4.5. Experimentally, maximum particle yields of 93% of the mass entering the reactor are obtained at R = 4.5.

This paper presents arguments for the use of direct steam generation (DSG) in preference to other forms of generation in particular locations according to the prevailing environmental and economic conditions. In addition, the paper describes the development of a software tool based on Microsoft Excel and Visual Basic for Applications (VBA), which draws upon established physical relationships in the heat transfer literature to perform plant capacity calculations in a fast and convenient manner. The results of the VBA program determine the solar fraction of the plant, assuming that the plant is in operation for 10 h per day (07:30–17:30 hours), the solar fraction is shown to be 76% and the DSG plant achieves a 76% reduction in emissions. Construction costs are also estimated based on formulae from previous work.

This paper investigates the feasibility of a solar cogeneration system, as a solution to reduce fossil fuel consumption and greenhouse gas emissions in a tissue mill, located in the industrial district of Lucca (North Italy). Although the paper sector has a high theoretical potential for the use of solar energy, the implementation of a solar thermal plant may not be economically sustainable, due to the expensive investment of such a system and to the uncertainty of future benefits. These issues are even more relevant in a moderate climate, where the high variability of the direct normal irradiance can prevent the technical feasibility of the plant. To demonstrate the possible use of solar energy in paper mills, a concentrating solar power plant with thermal storage, based on parabolic trough technology, has been chosen as a feasible solution for combined heat and power generation and its technical and economical performances have been evaluated through an extensive simulation analysis. The results obtained prove the feasibility of the proposed system and assure a good economic profitability. Results also show how the possibility of benefiting from economic incentives for renewable electric power generation is fundamental to reduce the payback period and to assure the profitability of the investment.

This paper deals with the development and testing of an innovative code for the performance prediction of solar trough based concentrated solar power (CSP) plants in off-design conditions. Off-design calculation starts from data obtained through the on-design algorithm and considers steady-state situations. The model is implemented in flexible software, named patto (parabolic trough thermodynamic optimization): the optical-thermal collector model can simulate different types of parabolic trough systems in commerce, including a combination of various mirrors, receivers and supports. The code is also flexible in terms of working fluid, temperature and pressure range, and can also simulate direct steam generation (DSG) plants. Solar plant heat and mass balances and performance at off-design conditions are estimated by accounting for the constraints imposed by the available heat transfer areas in heat exchangers, as well as by the characteristic curve of the steam turbine. The numerical model can be used either for single calculation in a specific off-design condition or for complete year simulation, by generating energy balances with an hourly resolution. The model is tested with a view to real applications and reference values found in literature: results show an overall yearly efficiency of 14.8% versus the 15% encountered in the Nevada Solar One. Moreover, the capacity factor is 25%, i.e., equal to the value predicted by sam ® . Code potential in the design process reveals two different aspects: it can be used not only to optimize plant components and layout in feasibility studies but also to select the best control strategy during individual operating conditions.