Operational flexibility of combined heat and power plant with steam extraction regulation

This paper evaluates the potential for flexible operation of combined heat and power plants, using previously validated steady-state and dynamic process models. The models compute the change in power and heat generation, as well as the response times of steam turbine extraction regulation. It is found that for small-to-medium sized plants, steam bypass could be a promising solution for regulation of power output, also in combination with boiler load changes. Rise times for load reductions by valve opening are within 30 s, independent of the extracted flow, and steam extractions/bypass can lead to power output reductions of up to 30% of rated power. However, plant specific design aspect may limit the achievable magnitude of load changes and must be considered

Combined heat and power operational modes for increased product flexibility in a waste incineration plant

The expected strong expansion of wind power may cause challenges for the electricity system in terms of grid stability, power balance, and increased electricity price volatility. This paper analyses how the new market conditions impact the operational pattern and revenue of a combined heat and power (CHP) plant. The work focuses on product flexibility that enables varied ratios between products; and thermal flexibility, to shift load in time given the differing timescales of heat and power demand. Product flexibility is given by five operational modes: conventional CHP, heat-only, CHP plus frequency response, condensing, and condensing plus frequency response. Optimization and process modeling are combined to study the plant dispatch in current and future electricity market scenarios and with thermal flexibility. The results indicate that load-shifting of heat generation together with condensing operation can increase revenue up to 4.5 M€ and plant utilization up to 100% for a 50 MWel waste-fired plant; but requires a thermal energy storage to meet hourly heat demand. The electricity price profile impacts both the revenue and operational patterns, with low-price periods favoring increased heat generation and frequency response delivery. High average electricity price and price volatility results in increased profitability of product and thermal flexibility

Flexible operation of a combined cycle cogeneration plant - A techno-economic assessment

The need for flexibility in combined heat and power (CHP) plants is expected to increase due to the strong expansion of wind power in electricity systems. Cost-effective strategies to enhance the flexibility of CHP operation are therefore needed. This paper analyzes three types of flexibility measures for a combined cycle CHP plant and their relative impact on the plant operation and revenue. The types of flexibility are: operational flexibility of the fuel conversion system, product flexibility with variable plant product ratios (heat/electricity/primary frequency response), and thermal flexibility in a district heating network. A modeling framework consisting of steady-state and dynamic process simulation models and optimization model is developed to combine static, dynamic, technical and economic perspectives on flexibility. A reference plant serves as a basis for the process model development and validation, and an energy system model provides input profiles for future electricity price scenarios. The results indicate that product flexibility and thermal flexibility have the highest value for the cogeneration plant (up to 16.5\ua0M€ increased revenue for a 250 MWel plant), while operational flexibility (ramp rate) has a comparatively small impact (<1.4\ua0M€). A wide load span and plant versatility, e.g. electricity and heat generating potential between 0 and 139% of nominal capacity, is beneficial in future energy system contexts, but has a marginal value in the current system. Electricity price volatility is a main driver that increases the value of flexibility and promotes operating strategies that follow the electricity price profile rather than the heat demand

Dynamic modeling for assessment of steam cycle operation in waste-fired combined heat and power plants

As the share of non-dispatchable energy sources in power systems increases, thermal power plants are expected to experience load variations to a greater extent. Waste-fired combined heat and power has multiple products and is today primarily operated for waste incineration and to generate heat. To consider load variations in the power demand at these plants may be a way to provide system services and obtain revenue, however, the transient interaction between power and district heating generation for the type of steam systems used should be studied. This work describes the transient characteristics and timescales of cogeneration steam cycles to discuss the operational interactions between power and district heating generation. A dynamic model of the steam cycle of a 48 MW waste-fired combined heat and power plant is developed using physical equations and the modeling language Modelica. The model is successfully validated quantitatively for both steady-state and transient operation with data from a reference plant and is shown capable of characterizing the internal dynamics of combined heat and power plant processes. Simulations are performed to analyze steam cycle responses to step changes, ramps and sinusoidal disturbances of boiler load changes and variability in district heating inlet temperature and flow. The results give insight on the process timescales for the specific case studied; for example, with the present design a 10% boiler load change requires up to 15 min for responses to settle, while the corresponding time for a 10% change in district heating flow or temperature show settling times within 5 min. Furthermore, increasing the boiler ramp rate from 2 to 4%/min could reduce the rise time of power generation by 42%, which could be of economic significance in day-ahead power markets

Dynamics of large-scale bubbling fluidized bed combustion plants for heat and power production

This paper presents a dynamic model of bubbling fluidized bed (BFB) units for combined heat and power (CHP) production that results from connecting a model of the gas side with a process model of the water-steam side. The model output is validated by comparison with operational data measured in a 130-MWth BFB plant that produces electricity, district heating (DH) water and steam to industrial clients. The validation shows that the model can satisfactorily describe both multi-load steady-state operation as well as load transients. The validated model is here used to compute the inherent process dynamics of the reference plant. The simulation results highlight the fact that the water-steam cycle reaches stabilization faster after changes in the DH line and steam delivered to clients than to changes in the combustor load. The timescales of the plant outputs for different changes have been computed, with stabilization times ranging between 2 and 15 min for the power production versus 2-25 min characterizing the DH production. When comparing these results with the characteristic times of the gas side, it is concluded that the water-steam side is an order of magnitude slower, i.e., limiting the transient operation capabilities of BFB-CHP plants. This in in contrast to earlier findings for circulating fluidized bed plants, where the characteristic times of both sides are in the same order of magnitude

Dynamics of large-scale bubbling fluidized bed combustion plants for heat and power production

Bubbling fluidized bed combustion (BFBC) plants for combined heat and power (CHP) production have traditionally been dispatched under slow load changes. As the amount of variable renewable electricity increases in energy systems worldwide, knowledge regarding the transient capabilities of the gas and water-steam sides of BFBC plants is required. The aim of this work is to investigate the dynamic performance of large-scale BFBC plants when accounting for both the gas and water-steam sides. To do so, this paper presents a dynamic model of BFB-CHP plants that result from connecting a model of the gas side to a process model of the water-steam side. The plant model output is validated by comparisons with operational data measured in a 130-MWth\ua0BFBC plant that produces electricity, district heating (DH) water and steam for industrial clients. The validation shows that the model can satisfactorily describe both multi-load steady-state operation and load transients. The simulation results highlight the fact that the water-steam cycle achieves stabilization more rapidly after changes in the DH line and steam delivered to customers, as compared to changes in the combustor load. The timescales of the plant outputs for different changes have been calculated, with stabilization times ranging from 2 to 15\ua0min for the power production versus 2–25\ua0min characterizing the DH production. Compared to the stabilization times of the gas side, the water-steam side is an order of magnitude slower, thereby limiting the transient operation capabilities of BFB-CHP plants

Dynamics and control of large-scale fluidized bed plants for renewable heat and power generation

As the share of variable renewable electricity increases, thermal power plants will have to adapt their operational protocols in order to remain economically competitive while also providing grid-balancing services required to deal with the inherent fluctuations of variable renewable electricity. This work presents a dynamic model of fluidized bed combustion plants for combined heat and power production. The novelty of the work lays in that (i) it provides an analysis of the transient performance of biomass-based fluidized bed combustion plants for combined heat and power production, (ii) the dynamic model includes a description of both the gas and water- steam sides and (iii) the model is validated against operational data acquired from a commercial-scale plant. The validated model is here applied to analyze the inherent dynamics of the investigated plant and to evaluate the performance of the plant when operated under different control and operational strategies, using a relative gain analysis and a variable ramping rate test.The results of the simulations reveal that the inherent dynamics of the process have stabilization times in the range of 5–25 min for all the step changes investigated, with variables connected to district heating production being the slowest. In contrast, variables connected to the live steam are the fastest, with stabilization times of magnitude similar to those of the in-furnace variables (i.e., around 10 min). Thus, it is concluded that the proper description of the dynamics in fluidized bed combustion plants for combined heat and power production requires modeling of both the gas and water sides (which is rare in previous literature). Regarding the assessment of control strategies, the boiler-following and hybrid control (combined fixed live steam and sliding pressure) strategies are found to be able to provide load changes as fast as 5%-unit/s, albeit while causing operational issues such as large pressure overshoots. The relative gain analysis outcomes show that these control structures do not have a steady-state gain on the power produced, and therefore it is the dynamic effect of the steam throttling that triggers the rapid power response. This study also includes the assessment of a turbine bypass strategy, the results of which show that it enables fast load-changing capabilities at constant combustion load, as well as decoupling power and heat production at the expense of thermodynamic losses

Dynamics of large-scale bubbling fluidized bed combustion plants for heat and power production

This paper presents a dynamic model of bubbling fluidized bed (BFB) units for combined heat and power (CHP) production that results from connecting a model of the gas side with a process model of the water-steam side. The model output is validated by comparison with operational data measured in a 130-MWth BFB plant that produces electricity, district heating (DH) water and steam to industrial clients. The validation shows that the model can satisfactorily describe both multi-load steady-state operation as well as load transients. The validated model is here used to compute the inherent process dynamics of the reference plant. The simulation results highlight the fact that the water-steam cycle reaches stabilization faster after changes in the DH line and steam delivered to clients than to changes in the combustor load. The timescales of the plant outputs for different changes have been computed, with stabilization times ranging between 2 and 15 min for the power production versus 2-25 min characterizing the DH production. When comparing these results with the characteristic times of the gas side, it is concluded that the water-steam side is an order of magnitude slower, i.e., limiting the transient operation capabilities of BFB-CHP plants. This in in contrast to earlier findings for circulating fluidized bed plants, where the characteristic times of both sides are in the same order of magnitude

Sustainable energy technologies for the Global South: challenges and solutions toward achieving SDG 7

The United Nations (UN) expectations for 2030 account for a renewable, affordable, and eco-friendly energy future. The 2030 agenda includes 17 different Sustainable Development Goals (SDGs) for countries worldwide. In this work, the 7th SDG: Affordable and Clean Energy, is brought into focus. For this goal, five main challenges are discussed: (i) limiting the use of fossil fuels; (ii) migrating towards diversified and renewable energy matrices; (iii) decentralizing energy generation and distribution; (iv) maximizing energy and energy storage efficiency; and (v) minimizing energy generation costs of chemical processes. These challenges are thoroughly scrutinized and surveyed in the context of recent developments and technologies including energy planning and supervision tools employed in the Global South. The discussion of these challenges in this work shows that the realization of SDG 7, whether partially or in full, within the Global South and global contexts, is possible only if existing technologies are fully implemented with the necessary international and national policies. Among the key solutions identified in addressing the five main challenges of SDG 7 are a global climate agreement; increased use of non-fossil fuel energy sources; Global North assistance and investment; reformed global energy policies; smart grid technologies and real time optimization and automation technologies