Shell Gasifier-based Coal Igcc with Co2 Capture: Partial Water Quench vs. Novel Water-gas Shift

We provide a detailed thermodynamic and economic analysis of two novel alternatives to the “standard” Shell coal IGCC with CO2 capture. In the first, the syngas coolers are replaced by a “partial water quench” where the raw syngas stream is cooled and humidified via direct injection of hot water. This design is less costly, but also less efficient. The second approach retains syngas coolers but instead employs a novel WGS configuration, developed at the Energy Research Centre of the Netherlands (ECN), that requires substantially less steam to obtain the same degree of CO conversion to CO2, and thus increases the overall plant efficiency. We investigate how both of these innovations alter the plant’s cost and complexity, and ultimately, the levelized cost of electricity. INTRODUCTION In a world with a rapidly expanding appetite for energy and rising concentrations of greenhouse gases, the use of coal as a primary energy source engenders both heightened interest and concern. Coal is the most abundant and least expensive fossil fuel, but also the most carbon intensive. Various gasification technologies enable the conversion of coal into a synthesis gas that can be further processed into common energy carriers such as electricity and synthetic fuels (e.g. hydrogen, natural gas, and liquid transportation fuels). Gasification also provides some of the least costly methods for large scale CO2 capture for sequestration in deep geologic formations away from the atmosphere. Numerous studies indicate that bituminous coal-based electric power with CO2 capture is less costly using integrated gasification combined cycles (IGCC) instead of standard pulverized coal (PC) steam electric plants [1, 2]. For lower rank subbituminous coals and lignites, which comprise fully half of the world’s coal reserves [3], the relative economics are less clear. To help clarify this issue, we investigate the thermodynamic and economic performance of three different variants of one particular type of coal-based IGCC plants that is likely to be able to economically convert all coals into electricity and other energy carriers: pressurized, entrained-flow, oxygenblown gasification, with coal drying and dry feeding into the gasifier. All plants in this work use bituminous coal; a forthcoming study addresses the effect of coal rank on plant performance and economics. Commercial plants of this type (e.g. that use the Shell Coal Gasification or Siemens Fuel Gasification Process) typically employ high temperature heat exchangers to cool down the hot (~900°C) synthesis gas by generating high pressure steam prior to syngas cleaning and chemical processing. In plants with CO2 venting, the high cost of these “syngas coolers” (SC) is generally offset by significantly increased plant efficiency. However, costly syngas coolers are often not well matched to CO2 capture, which requires a relatively moist syngas; much of the generated steam must be used for syngas humidification required by the downstream water-gas shift (WGS) reaction necessary for high levels of CO2 capture. In this regard, dry feed gasifiers are at a disadvantage relative to coal-water slurry fed gasifiers (e.g. GE Energy and ConocoPhillips E-Gas) which generate a more humid syngas; often, additional steam is not required prior to WGS. To address this issue, Shell recently filed a patent application for a “partial water quench” whereby the hot raw syngas is cooled by 1 Copyright © 20xx by ASME direct water injection [4]. This system both humidifies the syngas and eliminates the costly high temperature SCs. Researchers at ECN have recently developed an advanced WGS design that significantly reduces the flow of steam required for conversion of CO and H2O to CO2 and H2 [5]. This system has recently been implemented at pilot scale at NUON’s Buggenum IGCC plant in the Netherlands. This study compares the thermodynamic and economic performance of a bituminous coal-based IGCC plant using Shell gasification technology – with and without CO2 capture – using either the standard gas quench or the partial water quench as syngas cooling method and either the conventional two-stage sour WGS or the advanced ECN WGS design. Our goal is to understand what the preferred IGCC design is for dry feed, entrained flow gasifiers with CO2 capture. METHODOLOGY We model four cases, three with CO2 capture: SV a Standard (i.e. with syngas coolers) Shell coal gasifierbased IGCC plant with syngas coolers and CO2 Venting, SC – a Standard Shell IGCC plant with CO2 capture that uses a Conventional two-stage WGS unit, SE – a Standard Shell IGCC plant with CO2 capture that uses the advanced ECN WGS design, and QC – a partial water Quench Shell IGCC plant with CO2 capture, using a Conventional two-stage WGS unit. This research entailed seven primary tasks: 1) building a detailed model of the Shell coal gasification process using Aspen Plus chemical process modeling software [6], 2) calibrating the model by matching key component data and process flows to the detailed information provided in refs. 7-9 which describe standard Shelland Prenflo-based IGCC plants using bituminous coal, 3) investigating the optimal design of a partial water quench + wet scrubber + WGS system for Shell IGCC with CO2 capture, 4) building the ECN WGS and coupling it to a standard Shell IGCC plant, 5) simulating the General Electric (GE) 9FB gas turbine (burning H2-rich syngas) using the “Gas/Steam” (GS) simulation code developed at Politecnico di Milano [10,11], 6) configuring and optimizing the layout of the heat recovery steam cycle (HRSC) for each plant using a new method developed by Martelli [12] that maximizes the power output of the steam cycle, and 7) adding the cost framework required for a full techno-economic comparison between cases. SYSTEM DESIGN OVERVIEW Gasifier Island. The basic IGCC design is illustrated in Fig. 1; calculation details are given in Appendix Table A1. East Australian bituminous coal (Table 1) is milled, dried to a moisture level of 2%wt, and fed into the gasifier via lockhopper pressurization using N2 as a transport gas. The coal is gasified in the presence of medium pressure (MP) steam and 95% oxygen from a stand-alone cryogenic air separation unit (ASU). Gasification is modeled using full chemical equilibrium at 38.5 bara and 1390°C. Steam to oxidant flows are set by maximizing the LHV of the raw synthesis gas (SG) exiting the gasifier while fixing the heat loss to the membrane wall at 1.4% of the input coal HHV. The single-pass carbon conversion is 97.3%; with recycled fly ash (minus 5% bleed), the overall carbon conversion is 99.8%. Much of the input mineral matter (34.5%) exits the bottom of the gasifier as a vitreous slag; the remainder is captured as fly ash (after syngas cooling) by a ceramic filter Fig. 1. Plant schematic for case SC, the standard Shell IGCC+CO2 capture with a conventional WGS. 2 Copyright © 20xx by ASME and recycled back to the coal milling/drying unit. Heat for drying is provided by burning 1% of the scrubbed syngas. All gasifier island parameters (Table A1) were “tuned” in order to closely match the detailed data on syngas flow and composition from the gasification island provided by Shell [9]. Case SV. In the standard Shell IGCC plant, the raw syngas exiting the gasifier is first quenched to 900°C (to solidify molten ash) by a stream of recycled, cooled, ash-free syngas and is then cooled to 250°C in syngas coolers that economize and evaporate high pressure (HP) feedwater to generate HP steam for the bottoming cycle. Dry particulate filters remove fly ash from the syngas, which is then divided (~45% is sent to the recycle compressor for the gas quench) and sent to a countercurrent flow wet scrubber that removes trace particulate matter and water soluble contaminants. Scrubbed syngas is then warmed to 200°C and passed through a COS hydrolysis unit that converts COS to H2S, and HCN to NH3. The syngas is cooled to 40°C and sent to a Sulfinol M acid gas removal (AGR) system that strips out virtually all of the H2S (and 16% of the CO2) which is sent to an O2-blown Claus unit for conversion to elemental sulfur. The Claus tailgas is hydrogenated and recycled to the AGR. The sweet syngas exiting the AGR is heated to 350°C and burned in two GE 9FB gas turbines (GT). NOx emissions from the GT are limited to ~25 ppmv (15% O2) by diluting the syngas with all the available N2 and some steam in order to lower the stoichiometric flame temperature to 2027°C [14]. Heat is efficiently recovered from the turbine exhaust in a 3 pressure level (plus reheat) heat recovery steam generator (HRSG) coupled to a single steam turbine. A high degree of heat integration is employed between the syngas train and the steam cycle, and design is optimized to achieve maximum efficiency [12]. Case SC. Our design for the standard Shell IGCC with CO2 capture (Fig. 1) mirrors that of ref. 8 to facilitate model calibration and verification; however, we adopt a somewhat higher minimum input steam-to-CO (S/CO) ratio of 2.5 in order to avoid carbon formation on the WGS catalysis [13] and also to achieve an “overall carbon capture fraction” of 93.1%. The scrubbed syngas is preheated, combined with a large flow of superheated MP steam bled from the steam turbine, and sent to a conventional two-stage sour WGS unit (with sulfur-tolerant Co-Mo catalysts) that converts 98% 1 In case SV, the most efficient method of syngas dilution involves using all of the available N2 and a small amount of steam. In all CO2 capture cases we first saturate the syngas using low temperature heat that is not otherwise well utilized in the bottoming cycle, and then add N2 as needed to control NOx. 2 Defined here as the fraction of the carbon in the input coal that is retained either as carbon in the gasifier slag/flyslag or as CO2 stored underground. of CO to CO2 and H2. The syngas enters/exits the high temperature (HT) WGS reactor at 250/ 466°C; it is then cooled and enters/exits the low temperature (LT) WGS reactor at 250/276°C. The shifted syngas is cooled to 38°C, sent to the Selexol process for H2S and CO2 selective removal, saturated with water, diluted with N2, heated to 200°C, and burned in the gas turbines. The Selexol AGR [9] captures 96.54% of the inlet CO2, 0.53% of H2 and 0.44% of CO. Thus, the overall carbon capture fraction is 93.0% for the cases with 98% CO conversion and 90.4% for the cases with 95% CO conversion. The captured CO2 stream is dehydrated and compressed from 1.8 to 150 bar for pipeline transport and storage in geologic formations; the H2S rich stream is treated in a conventional Claus unit followed by a Shell Claus Offgas Treating (SCOT) process. In the cases with only 95% CO conversion, 19.3% of the syngas is split off from the primary flow, bypasses the HT-WGS reactor (still operating at S/CO 2.5), and is fed directly into the LT-WGS reactor. As a consequence, the second reactor has a higher reaction heat and outlet temperature (321 C), suitable for raising both MP and LP steam. Moisture