Levelized Cost of CO2 Captured Using Five Physical Solvents in Pre-combustion Applications
Introduction
In Integrated Gasification Combined Cycle (IGCC) power generation facilities, schematically depicted in Fig. 1, the coal and/or biomass is gasified under controlled conditions in the presence of steam (H2O) and O2 (or air) to produce raw syngas (H2 + CO). The solid particulates are removed from the raw syngas before it enters a water-gas-shift (WGS) reactor, wherein CO reacts with H2O to increase the syngas H2/CO ratio, however, for each mole of H2 produced, one mole of CO2 is also produced. The shifted fuel gas is then cooled, and the sulfur-containing compounds are removed before CO2 capture. It should be noted that the WGS step could be configured to control the H2/CO ratio in the fuel gas for use in either power generation or in the manufacture of clean transportation fuels and/or high-value chemicals (Kohl and Nielsen, 1997; Moulijn et al., 2013; NETLa). Depending on the type of gasifier used, the shifted fuel gas could be under high pressures (up to 70 bars) (Kohl and Nielsen, 1997), and could contain high concentrations of CO2 ranging from 5 to 50 vol.% (Maroto-Valer, 2010).
Physical solvents are well suited for CO2 capture from fuel gas streams, especially because CO2 partial pressure is high and there is a large physical contrast between the molecules being separated, such as CO2 and H2. Also, they typically have high CO2 loading capacities, thus enabling low solvent recirculation rates. Table 1 lists several conventional physical solvents used in Acid Gas Removal (AGR) processes (Mumford et al., 2015; Spigarelli and Kawatra, 2013). Also, Ionic Liquids (IL) were reported to have favorable properties for CO2 capture from pre-combustion applications (Aghaie et al., 2018; Brennecke and Gurkan, 2010; Ramdin et al., 2012; Zhang et al., 2012). It should be noted, however, there remain significant problems associated with using physical solvents, such as difficulty in meeting product gas specifications and high solvent viscosities. Therefore, ongoing research efforts are focusing on the development of physical solvents with extremely low vapor pressure, high chemical/thermal stability, low corrosivity, low flammability, low toxicity and high CO2/H2 selectivity.
In the NETL bituminous coal study by Black (2010), the baseline acid gas removal solvent for IGCC-CCS (Carbon Capture and Sequestration) power plants was Selexol™ (UOP, 2009), which is a hydrophilic, anti-freeze-like solvent used commercially at near room temperature to remove acid gases and water from natural gas before it enters the pipelines. It is important to note that Selexol™ was the solvent chosen for pre-combustion CO2 capture at the Kemper County IGCC-CCS power plant because of its high H2S/CO2 and CO2/H2 selectivities, high CO2 capacity and ease of regeneration. The higher viscosity of Selexol™ compared with most common physical and even chemical solvents, however, is problematic as it decreases the mass transfer rate and increases solvent pumping cost and packing requirements.
Moreover, while hydrophilicity is an ideal quality for a solvent used in the natural gas industry, it is not ideal for IGCC-CCS applications. In fact, the hydrophilic nature of Selexol™ solvent means that the fuel gas must be cooled to quite low temperatures (10 - 40 °C) in order to remove the water vapor from the fuel gas. When this is coupled with its fairly high vapor pressure at high temperatures (Spigarelli and Kawatra, 2013), Selexol™ was reported to be quite limited in its operating temperature, and hence it is not the most ideal solvent for IGCC-CCS applications. Therefore, the ideal physical solvents for pre-combustion CO2 capture applications should possess the following: (1) high CO2 uptake, (2) extremely high H2S uptake, (3) low H2/CO/N2/CH4 uptake, (4) low H2O uptake, (5) high CO2 diffusivity, (6) low vapor pressure, (7) low tendency to foam/aerosolize, (8) high mass density, and (9) high thermal and chemical stabilities. Other important properties include low starting materials cost, relatively simple synthesis, and environmentally benign impact.
As reported by Gerdes et al. (2014), one major area for improvement in the baseline IGCC-CCS process is the reduction of the energy penalty associated with cooling the fuel gas to room temperature in order to remove CO2 and H2S prior to combustion. Gerdes et al. (2014) reported that the electrical efficiency of an IGCC-CCS power plant could increase by three basis points, and the levelized cost of electricity could decrease by 20% when implementing warm gas clean-up of both pollutants. Over the past few years, NETL and the University of Pittsburgh have developed and used numerous physical solvents for CO2 capture (Siefert et al., 2016), with the aim of overcoming Selexol’s disadvantages described above. However, despite their potential at lab-scale, additional testing is required at large-scale to further assess the physical solvents’ performance and stability.
The CO2 capture from pre-combustion and post-combustion facilities using liquid solvents is normally carried out in a countercurrent packed-bed absorber followed by a series of solvent regeneration steps (Aaron and Tsouris, 2005). Often, the fuel gas or flue gas enters the packed-bed from the bottom, while a physical or chemical liquid solvent enters from the top of the absorber. The absorber contains solid packing to increase the physical interactions between the gas (containing CO2) and the solvent. The CO2-rich solvent is then sent to a regenerator to release most of the CO2 absorbed (via pressure and/or temperature swing), and the CO2-lean solvent is recycled back to the absorber. The design, modeling and scale up of countercurrent packed-bed absorbers require, among other parameters, precise knowledge of the hydrodynamics and mass as well as heat transfer parameters under actual operating conditions.
The purpose of this study is to use Aspen Plus v8.8 to simulate a CO2 capture process from a typical fuel gas stream in a 543-MW IGCC power plant using five different physical solvents in a countercurrent, high-pressure packed-bed absorber and to perform techno-economic analyses of the capture process under a wide range of operating temperatures. The five physical solvents used were: (1) Selexol (dimethylether of polyethylene glycol), (2) PEGPDMS-1 (polyethylene glycol of polydimethylsiloxane) (3) [aPy][Tf2N] (allyl-pyridinium bis(trifluoromethylsulfonyl)imide), (4) NMP (n-methyl-2-pyrrolidone), and (5) [hmim][Tf2N] ionic liquid (1-hexyl-3-methyl-imidazolium bis(trifluoromethylsulfonyl)imide. Two different packings, structured Sulzer Mellapak 250Y and random Koch IMTP50 were used in the absorber. The constraints imposed on the CO2 capture process were (1) minimum 90% CO2 capture, (2) no flooding in the absorber, (3) minimum irrigated pressure loss and (4) minimum water concentration (< 600 ppm) as well as minimum loss (≤ 0.5 mol%) of fuel gases (H2, CO, CH4) in the CO2 stream destined for sequestration.
Section snippets
Research Approach
The flowchart of the LCOC calculations of the CO2 capture process shown in Fig. 2 follows these steps:
- 1
Obtain the fuel gas flow rate, composition, pressure and temperature based on the power plant MW. Make sure fuel gas stream is sulfur-free because sulfur compounds could be removed using a bed of zinc oxide sorbent (Siriwardane et al., 2002).
- 2
Select the packing type (structured or random) to be used in the absorber and obtain its specifications, (voidage, specific surface area, etc.).
- 3
Select a
Absorber Required and Solvent Flow Rate
Table 13 shows that the diameters of the absorber and accordingly the packing height and wall thickness start to increase at 30 °C and again at 50 °C for Mellapak 250Y and at 35 °C for IMTP50, respectively.
Fig. 18 shows that the solvent flow rate required to achieve a CO2 capture efficiency of 90% increases with temperature. This behavior is because the solubility of CO2 in Selexol decreases with increasing temperature. In addition, using IMTP50 requires greater solvent flow rate than the
Conclusions
Aspen Plus v8.8 was used to simulate a CO2 capture process from a typical fuel gas stream in a 543-MW pre-combustion plant using five different physical solvents (Selexol, PEGPDMS-1, NMP, [aPy][Tf2N] and [hmim][Tf2N]) in a countercurrent high pressure packed-bed absorber under a wide range of operating temperatures. Three pressure-swing flash drums were used in the process for solvent regeneration. The constraints implemented in the process simulation were (1) no flooding in the absorber, (2)
Disclaimer
This work was funded by the Department of Energy, National Energy Technology Laboratory, an agency of the United States Government, through a support contract with Leidos Research Support Team (LRST). Neither the United States Government nor any agency thereof, nor any of their employees, nor LRST, nor any of their employees, makes any warranty, expressed or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus,
Declaration of Competing Interest
The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.
Acknowledgements
This technical effort was performed in support of the US Department of Energy’s ongoing research in Carbon Capture. The research was executed through the NETL Research and Innovation Center’s Transformational Carbon Capture FWP under the RSS contract 89243318CFE000003. The authors would like to thank Dr. Randall Gemmen, Associate Deputy Director for Energy Conversion at NETL, and Mr. Walter Shelton, Engineer in the Systems Engineering & Analysis group at NETL, for their meticulous internal
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