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• Integration of carbon capture in city electricity and district heating system. • Combined heat and power plants retrofitted with MEA and HPC CO 2 capture processes. • Energy system optimization model with detailed carbon capture representation. • With heat recovery, both processes are efficiently integrated in the heat sector. • Low impact on marginal costs of electricity and district heating from CO 2 capture. The capture and storage of biogenic CO 2 emissions from large point sources, such as biomass-combusting combined heat and power (CHP) plants, can contribute to climate change mitigation and provide carbon-negative electricity while supplying district heating in urban areas. This work investigates the impact of retrofitting CO 2 capture processes to CHP plants in a city energy system context. An energy system optimization model is applied to a case study of the city Västerås, Sweden, with scenarios involving two existing CHP plants in the city, retrofitted with either a heat-driven (MEA) or an electricity-driven (HPC) carbon capture process. The results show that the CHP plants might be retrofitted with either option without significantly impacting the district heating system operation or the marginal costs of electricity and district heating in the city. The MEA process mainly causes a reduction in district heating output (up to 30% decrease on an annual basis), which can be offset by heat recovery from the capture unit. The electrified HPC process does not impact the CHP plant steam cycle but implies increased import of electricity to the city (up to 44% increase annually) compared to a reference scenario. [Display omitted] [ABSTRACT FROM AUTHOR]

• Process modeling and integration of CCS technologies with respect to a reference bio-CHP plant. • Key technology performance indicators for the carbon capture technologies are quantified. • The possibility of integrating heat pumps into the BECCS plant is investigated. • Case-specific exergy performance of the BECCS plant at the plant and DH system levels. • BECCS plant with higher power preservation preferable from a local DH system perspective. Installing carbon capture and storage (BECCS) capability at existing biomass-fired combined heat and power (bio-CHP) plants with substantial emissions of biogenic CO 2 could achieve significant quantities of the negative CO 2 emissions required to meet climate targets. However, it is unclear which CO 2 capture technology is optimal for extensive BECCS deployment in bio-CHP plants operating in district heating (DH) systems. This is in part due to inconsistent views regarding the perceived value of high-exergy energy carriers at the plant level and the extended energy system to which it belongs. This work evaluates how a bio-CHP plant in a DH system performs when equipped with CO 2 capture systems with inherently different exergy requirements per unit of CO 2 captured from the flue gases. The analysis is based upon steady-state process models of the steam cycle of an existing biomass-fired CHP plant as well as two chemical absorption-based CO 2 capture technologies that use hot potassium carbonate (HPC) and amine-based (monoethanolamine or MEA) solvents. The models were developed to quantify the plant energy and exergy performances, both at the plant and system levels. In addition, heat recovery from the CO 2 capture and conditioning units was considered, as well as the possibility of integrating large-scale heat pumps into the plant or using domestic heat pumps within the local DH system. The results show that the HPC process has more recoverable excess heat (∼0.99 MJ/kgCO 2,captured) than the MEA process (0.58 MJ/kgCO 2,captured) at temperature levels suitable for district heating, which is consistent with values reported in previous similar comparative studies. However, using energy performance within the plant boundary as a figure of merit is biased in favor of the HPC process. Considering heat and power, the energy efficiency of the bio-CHP plant fitted with HPC and MEA are estimated to be 90% and 76%, respectively. Whereas considering exergy performance within the plant boundary, the analysis emphasizes the significant advantage the amine-based capture process has over the HPC process. Higher exergy efficiency for the CHP plant with the MEA capture process (∼35%) compared to the plant with the HPC process (∼26%) implies a relatively superior ability of the plant to adapt its product output, i.e., heat and power production, and negative-CO 2 emissions. Furthermore, advanced amine solvents allow the BECCS plant to capture well beyond 90% of its total CO 2 emissions with relatively low increased specific heat demand. [ABSTRACT FROM AUTHOR]

The energy system can be subdivided into interconnected structural levels with differing boundary conditions and objectives. For heat and power generation, these levels may be the: electricity price area (regional); heat price area (city); and production site (power plant). This work presents a multi-system modeling approach for the analysis of investments and operation of combined heat and power (CHP) plants, as optimized on a regional, city, or production site energy system level. The modeling framework, comprising three energy system optimization models at the respective levels, is applied to a case study of Sweden, electricity price area SE3. The modeling levels are optimized separately but linked through electricity and heat prices. The results show that optimized CHP plant investments and operation on the three levels can both align and differ, depending on conditions. With a low biomass price and moderate congestion in transmission capacity into the city, the results from the three levels generally align. Differences arise if the biomass price is increased, which impacts the competitiveness of CHP plants in the region, while city-level CHP investments are mainly determined by the local heat demand and less-sensitive to external changes. The differences indicate a risk for diverging expectations between system levels. • Analysis of heat and power system optimization at regional-, city- and plant-level. • Comparing the role of combined heat and power (CHP) plants at the three levels. • CHP incentives at each level align for low biomass price and moderate congestion. • CHP investments on the city level are robust and governed by the heat demand. • Risk for diverging expectations between the levels on CHPs role in energy system. [ABSTRACT FROM AUTHOR]

• Modeling framework for process and system integration of CCS. • Impact of CCS on electricity and heat production in co-generation plants. • Marginal abatement cost curve for CCS from Swedish co-generation plants. • Around 10 MtCO 2 /year available in Sweden at a capture cost of <100€/ton. The need to reduce global CO 2 emissions is urgent and might be facilitated by carbon capture and storage (CCS) technologies. Sweden has a goal to reach net-zero emissions by 2045. Negative emissions and bio-CCS (BECCS) have been proposed as important strategies to reach this target at the lowest cost. The Swedish district heating sector constitutes a large potential for BECCS, with biogenic point sources of CO 2 in the form of combined heat and power (CHP) plants that burn biomass residues from the forest industry. This study analyzes the potential of CO 2 capture in 110 existing Swedish biomass or waste-fired CHP plants. Process models of CHP steam cycles give the impacts of absorption-based CCS on heat and electricity production, while a district heating system unit commitment model gives the impact on plant operation and the potential for CO 2 capture. The results provide a cost for carbon capture and transport to the nearest harbor by truck: up to 19.3 MtCO 2 /year could be captured at a cost in the range of 45–125 €/tCO 2 , corresponding to around 40% of the total fossil fuel-based Swedish CO 2 emissions. This would be sufficient to meet a proposed target of 3–10 Mt/year of BECCS by 2045. [ABSTRACT FROM AUTHOR]

• A dynamic model of a cogeneration steam cycle is developed and validated. • The effects of boiler load changes on power and heat generation are analyzed. • Operational impacts of district heating disturbances are characterized. 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. [ABSTRACT FROM AUTHOR]