Levelized Cost of CO₂ Captured Using Five Physical Solvents in Pre-combustion Applications

Highlights

• Aspen Plus v8.8 was used to perform techno-economic analysis (TEA) of a CO₂ capture process from a typical fuel gas stream in a 543-MW pre-combustion power plant.

• Five physical solvents (Selexol, PEGPDMS-1, NMP, [aPy][Tf2N] and [hmim][Tf2N]) and two packings, Mellapak 250Y and IMTP50, were used in the simulation.

• The Levelized costs of CO₂ captured (LCOC) were calculated.

• Mellapak 250Y exhibited lower LCOC values than those when using IMTP50 for the five solvents under all conditions employed.

• The CO₂ capture process carried out at low temperatures showed lower LCOC values than those at higher temperatures.

• Comparing the lowest LCOC values for the five solvents, the hydrophobic PEGPDMS-1 solvent was the most promising one.

Abstract

Aspen Plus v8.8 was used to perform techno-economic analysis (TEA) of a CO₂ capture process from a typical fuel gas stream in a 543-MW pre-combustion power plant using five different physical solvents (Selexol, PEGPDMS-1, NMP, [aPy][Tf₂N] and [hmim][Tf₂N]). The process included a countercurrent packed-bed absorber operating under high-pressure over a wide range of temperatures and three pressure-swing flash drums for solvent regeneration. Two packings, Mellapak 250Y and IMTP50, were used and the Levelized costs of CO₂ captured (LCOC) were calculated.

The simulation results indicated that using Mellapak 250Y exhibited lower LCOC values than those when using IMTP50 for the five solvents under all conditions used as it offered better mass transfer. The CO₂ capture process carried out at low temperatures showed lower LCOC values than those at higher temperatures due to the increased CO₂ solubility in the solvents at lower temperatures, requiring smaller absorber diameter and lower solvent circulation rates, which offset the cooling requirements. Comparing the lowest LCOC values for the five solvents, the hydrophobic PEGPDMS-1 solvent was the most promising one compared to the other four solvents, due to its lowest capital and operating costs and noncorrosive, which enabled using less expensive materials for the process equipment.

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.