Elsevier

Applied Energy

Volume 229, 1 November 2018, Pages 900-909
Applied Energy

Integration of heat recovery unit in coal fired power plants to reduce energy cost of carbon dioxide capture

https://doi.org/10.1016/j.apenergy.2018.08.031Get rights and content

Highlights

  • Direct flue gas heat recovery scheme to reduce solvent regeneration is presented.

  • Silicone oil identified as non-aqueous heat transfer fluid through TGA.

  • No reactions between flue gas/HTF and CO2 rich-amine solvent/HTF observed.

  • 31.2% reduction in reboiler heat duty providing additional 7 MWe from the LP turbine.

Abstract

This work presents the feasibility of utilizing a novel heat recovery unit (HRU) technology, to directly recover thermal energy contained in flue gas utilizing an inert non-aqueous heat transfer fluid (HTF), which can then be utilized to lower CO2 capture costs and increase overall power plant efficiency. Silicone oil was identified as the HTF for use in this direct heat recovery process, as the fluid is thermally stable and resistant to oxidation. Interactions between the HTF and flue gas were investigated with the HTF found to be chemically resistant to SO2 and CO2. The viability of using an HTF as an energy vector between flue gas and CO2 rich-amine solvent was studied via bench-scale experimentation showing distinct phase separation devoid of reactions between the HTF and CO2 rich-amine solvent. Energy savings in reboiler heat duty with HRU integration were estimated using Aspen Plus simulations. Simulation results suggest HRU integration schemes could lower reboiler heat duty between 15.1% and 31.2%.

Introduction

Anthropogenic CO2 emissions are considered to be a key contributor to global warming [1]. The primary source of CO2 emissions is the combustion of fossil fuels, such as coal and natural gas, which are dominant in the current electrical power sector [2]. Carbon capture and sequestration (CCS) is one of the best options to decrease CO2 emissions and allow for sustainable utilization of fossil fuels [3]. Three categories of CO2 capture technologies are being developed to reduce emissions from coal-based power generation including pre-combustion, post-combustion and oxy-fuel combustion [4], [5].

Post-combustion CO2 capture techniques include absorption by chemical solvents such as monoethanolamine (MEA) [6], chilled ammonia [7], [8], and 2-amino-2-methyl-1-propanol (AMP) [9], solid adsorption [10], calcium looping [11], and membrane techniques [12], [13]. Implementing CO2 capture through post-combustion processes appears to be the most promising, as it enables retrofitting of existing power plants. Aqueous amine solvents are regarded as the best option for large-scale CO2 capture from a coal-fired power plant due to the technology’s maturity, cost effectiveness and capability to handle large volume flue gas streams. MEA has been widely recognized as a vital solvent for CO2 capture, due to its fast reaction rate and high CO2 selectivity. Further, MEA-based solvents have been proven at commercial scale, and are usually considered as a baseline for comparison with alternative carbon capture technologies [14], [15].

However, MEA’s regeneration requirements significantly reduce power plant efficiency [16], [17]. MEA’s heat of regeneration for a 90% CO2 capture process from a conventional coal-fired power plant is approximately 3.6–4.0 MJ kg−1 CO2, lowering coal-fired power plant efficiency by 20–40% [16], [18], [19]. To reduce amine solvent regeneration energy, significant efforts have been devoted to developing new amine solvent formulations [20] and blends [21], which have the potential to improve energy efficiency and reduce overall carbon capture costs. Sakwattanapong et al. [22] experimentally studied the stripper heat duty requirement for MEA, diethanolamine (DEA), methyldiethanolamine (MDEA), AMP and blended amine solvents in a bench-scale setup and found that DEA and MDEA require less reboiler heat duty than MEA. Commercial adoption relies heavily upon technical and economic feasibility at a large scale which is dependent upon many properties including CO2 solubility, energy consumption for regeneration, chemical reaction kinetics, mass transfer characteristics, and solvent stability [23].

In addition to solvent choice, process configurations play an important role in stripper reboiler heat duty [24], [25]. Process modification schemes such as rich-solvent splitting [26], overhead condenser bypass [27], or altering the stripping pressure via a multi-pressure stripper [20] have been reported to achieve an energy reduction of 8–20%, compared to a conventional MEA-based capture process. Ahn et al. [26] showed the combination of absorber intercooling, condensate evaporation and lean amine flash modifications results in 37% reduction in terms of low-pressure (LP) steam required. Jung et al. [28] suggested an alternative stripper configuration by combining rich vapor compression and cold solvent split can reduce the solvent regeneration energy requirement to 2.75 MJ kg−1 CO2, 15% lower than the conventional process (3.44 MJ kg−1 CO2). Oh et al. [29] analyzed the overall performance of CO2 capture integrated power plant with several heat integration options and demonstrated power plant net efficiency penalty can be significantly reduced by process modifications along with re-designing of the steam cycle for utilization of waste heat. Furthermore, Le Moullec et al. [24] stated that while there are a large number of possible process modifications to improve the energetic performance of the capture processes, the interactions and synergies between various solvents and process modifications have not been fully investigated and further research is needed to validate plant operability.

Another method to reduce CO2 capture energy requirement is to integrate available heat of sufficient temperature within the power plant cycle to reduce LP steam load for regeneration. A location within the power plant where thermal energy of a sufficient temperature can be found is in the hot flue gas upstream of the desulfurization unit, which varies in temperature up to 180 °C [30], [31]. This heat has been a target for many heat integration schemes to be used within the power plant [32]. Over the years, there have been several studies on recovering heat and water from flue gas of coal-fired power plants including gas-gas heat exchanger, compact heat exchanger, low pressure economizer and transport membrane condenser [33], [34]. Very few studies were performed on utilizing the waste heat to reduce the solvent reboiler heat duty. Reddick et al. [35], showed that ejector driven waste heat upgrading can reduce reboiler steam load by 10–25%, depending upon the point of steam injection into the stripper. However, these previous heat recovery schemes are indirect in nature, i.e., heat from flue gas was transferred across a conductive metal wall to a secondary heat transfer media. Such indirect heat transfer systems are capital intensive and have significant pressure drop associated with their design making them infeasible as a practical heat integration solution. Our efforts to reduce the reboiler energy consumption include an advanced heat recovery methodology, which utilizes a Heat Recovery Unit (HRU) for direct heat transfer from the flue gas to and HTF for solvent regeneration.

The HRU design is shown in Fig. 1a. This novel direct contact heat exchanger consists of vertical columns made of a permeable polymeric cordage material (such as a polypropylene rope or a fiber mat) which is capable of operating at relatively high temperature, chemically resistant, strong, and relatively inexpensive. The process is capable of waste heat recovery, and scrubbing criteria pollutants, including particulate matter, acid mist and mercury [36]. In the heat recovery configuration, an appropriate HTF is delivered at the top of a header of vertical sleeves set across the flue gas flow. The HTF flows down the sleeves as a thin film directly recovering heat from the cross-flowing flue gas. The hot HTF is then transferred to heat exchange with rich amine solvent. Heat transfer from HTF to rich amine is also direct in nature via mixing, providing a portion of heat of regeneration. A process flow diagram of the coal-fired power plant integrated with HRU and CO2 capture process is shown in Fig. 1b.

In this study, bench-scale experimentation was completed to validate the concept of directly recovering heat from flue gas using HRU technology and utilizing the captured heat to lower reboiler heat duty. Non-aqueous HTFs for direct heat recovery were identified and flue gas/HTF interactions and CO2 rich-amine solvent/HTF interactions were assessed. Further, process modeling simulations were completed to determine reduction in reboiler heat duty to assess HRU potential in decreasing parasitic losses associated with post-combustion CO2 capture in coal-fired power plants.

Section snippets

Thermogravimetric analysis (TGA)

Thermo-gravimetric analysis (TGA) was performed using a TGA Q500 (TA instruments). HTF samples of 15–20 mg were analyzed using a platinum pan from 25 to 250 °C in 30 ml min−1 N2/flue gas mixture. The flue gas mixture composition was CO2 – 16.2 vol%, N2 – 80.0 vol%, O2 – 3.5 vol% and SO2 – 2700 ppm obtained from Praxair. Each sample was analyzed at least twice in order to ensure measurement reproducibility. HTF mass loss was evaluated as a function of time under isothermal conditions at

Heat transfer fluid selection and thermal stability analysis

In determining the best suited HTF for any application, numerous factors such as thermal stability, environmental friendliness, etc., must be considered. Non-aqueous HTFs are best suited for this HRU application, as these liquids possess higher boiling points than aqueous fluids and are likely non-miscible with leading aqueous-based amine solvents. Commercially available conventional and synthetic petroleum oils are not suitable in this application as oxidation occurs when hot flue gas

Conclusions

Silicone oil was identified as the non-aqueous heat transfer fluid (HTF) for use in the novel direct heat recovery methodology assessed in this study, which is thermally stable and resistant to oxidation. The interactions of HTF with flue gas were investigated using TGA and stirred reactor system under various conditions and the HTF was found to be chemically resistant to flue gas components including CO2 and SO2. The viability of using HTF for direct heat transfer to CO2-rich amine solvent was

Acknowledgements

This work was financially supported by the Ohio Coal Development Office Consortium Program (R-15-09).

Declarations of interest

None.

References (45)

  • M. Wang et al.

    Post-combustion CO2 capture with chemical absorption: a state-of-the-art review

    Chem Eng Res Des

    (2011)
  • A. Giuffrida et al.

    Amine-based post-combustion CO2 capture in air-blown IGCC systems with cold and hot gas clean-up

    Appl Energy

    (2013)
  • N. Rodríguez et al.

    Optimization of post-combustion CO2 process using DEA–MDEA mixtures

    Chem Eng Res Des

    (2011)
  • S. Bishnoi et al.

    Absorption of carbon dioxide into aqueous piperazine: reaction kinetics, mass transfer and solubility

    Chem Eng Sci

    (2000)
  • Y. Le Moullec et al.

    Process modifications for solvent-based post-combustion CO2 capture

    Int J Greenhouse Gas Control

    (2014)
  • M. Wang et al.

    Process intensification for post-combustion CO2 capture with chemical absorption: a critical review

    Appl Energy

    (2015)
  • H. Ahn et al.

    Process configuration studies of the amine capture process for coal-fired power plants

    Int J Greenhouse Gas Control

    (2013)
  • M. Karimi et al.

    Investigation of the dynamic behavior of different stripper configurations for post-combustion CO2 capture

    Int J Greenhouse Gas Control

    (2012)
  • S.-Y. Oh et al.

    Process integration and design for maximizing energy efficiency of a coal-fired power plant integrated with amine-based CO2 capture process

    Appl Energy

    (2018)
  • G. Xu et al.

    A novel flue gas waste heat recovery system for coal-fired ultra-supercritical power plants

    Appl Therm Eng

    (2014)
  • S. Zhao et al.

    Simultaneous heat and water recovery from flue gas by membrane condensation: Experimental investigation

    Appl Therm Eng

    (2017)
  • C. Reddick et al.

    Energy savings in CO2 (carbon dioxide) capture using ejectors for waste heat upgrading

    Energy

    (2014)
  • Cited by (0)

    View full text