8.2. Typical IGCC Configuration

Major Commercial Examples of IGCC Plants
While there are many coal gasification plants in the world producing electricity, fuels, chemicals and/or steam, the following are seven notable, commercial-size IGCC plants for producing electricity from coal and/or coke.

Tampa Electric, Polk County	250 MW	Startup in 1996	GE Gasifier
Wabash, West Terre Haute	265 MW	Startup in 1995	CB&I E-Gas™ Gasifier
Nuon, Buggenum	250 MW	Startup in 1994, shutdown in 2013*	Shell Gasifier
Elcogas, Puertollano	300 MW	Startup in 1997	Prenflo Gasifier
Edwardsport IGCC Station, Indiana	618 MW	Commercial operations in 2013	GE Gasifier
Nakoso IGCC, Japan	250 MW	Experimental demo startup 2007, commercial operations in 2013	MHI Gasifier

Figure 1: Tampa Electric IGCC Process Flow

Figure 2 shows a simplified block flow diagram (BFD) illustrating the major process sub-systems included in an IGCC plant. The BFD shows an elevated-pressure (EP) air separation unit (ASU) integrated to the gas turbine (GT) operation by extracting some of the GT air compressor discharge as feed to reduce the ASU air compressor size and power consumption. The six operating IGCC plants cited, with the exception of the Wabash plant and Nakoso plant, all have EP ASU integration with the GT. The Buggenum and the Puertollano IGCC plants were designed with EP ASU/GT integration while the Tampa IGCC was modified in 2005 for EP ASU/GT integration; Edwardsport IGCC closely follows current Tampa IGCC design. Oxygen-depleted nitrogen from the EP ASU is compressed back to the GT as diluents for nitrogen oxide (NOx) control, and to maintain mass flow through the GT. Kemper County IGCC is to utilize air-blown transport gasification and Nakoso IGCC is also air-blown, and therefore do not incorporate an ASU.

A more detailed process description of each of the processing units within an IGCC complex is presented in the discussion on IGCC process system sections.

* Closure of the 250 MW IGCC located in Buggenum, The Netherlands dictated by changing power market in the European Union.

Effect of CO₂ Capture
The flow scheme of Figure 2 represents a typical process arrangement of a near-term commercial IGCC design without CO₂ capture. CO₂ capture and sequestration (CCS) significantly impacts the overall IGCC efficiency, and the effects are addressed in the discussion Designs for CO₂ Capture.

Advanced IGCC

DOE’s R&D program is targeting advances in technologies that will improve upon the conventional IGCC technology discussed above. Cumulatively, the technology advances will produce electric power more efficiently and significantly lower the COE. An IGCC cycle including carbon capture that incorporates these advanced technologies is depicted in Figure 3. The impact of each technology on both process performance and cost are being evaluated, and by way of summary the following technological advances and their benefits are expected¹:

Advanced hydrogen turbine (AHT): The AHT replaces the state-of-the-art F-class turbine (F-class is currently used at Tampa, Wabash River, and is depicted in the baseline IGCC in Figure 2). Its higher firing temperature (~2650°F) both improves the process efficiency and results in ~45% increase in gas turbine output, mandating increased flow rates such as coal input and significantly boosting power capacity. Plant units are larger to accommodate the increases, resulting in economies of scale which deliver unit capital cost reductions. Quantitatively, upgrading the turbine decreases COE 14.5% and increases process efficiency by 3 percentage points.
Ion transport membrane (ITM) for oxygen production: The ITM-based oxygen unit replaces the conventionally used cryogenic ASU. The ITM provides more energy efficient separation than the ASU, but the auxiliary duty for compression of the inlet air and low-pressure oxygen results in net power consumption similar to the ASU. The significant advantage of the ITM is that the targeted cost is approximately two-thirds of the ASU, which significantly reduces the capital costs and results in a 3% reduction in COE. Configurations including air-side integration with the turbine are anticipated to further increase the efficiency and COE benefits of the ITM.
Warm gas clean up (WGCU): This system replaces the desulfurization Selexol stage, mercury removal process, water-gas shift reactor and Claus plant, performing all of these operations at elevated temperatures which allows for the syngas to be cleaned without the associated decrease in efficiency from cooling and reheating the fuel gas stream. Implementing the WGCU process train results in a 2 percentage point increase in net plant efficiency, which is mostly the result of increased power generation from the steam turbine via increased heat recovery from the process. A 4% decrease in COE is also realized.
H ydrogen membrane for pre-combustion capture: Palladium-based 100% hydrogen-selective membrane replaces the Selexol stage for CO2 capture from the syngas. Use of the palladium membrane improves plant efficiency by 1.4 percentage points mostly from the lower compression costs of CO₂. The COE is further reduced by 3%, again mostly due to lower compression costs. NETL is also performing analysis of alternative advanced pre-combustion technologies such as low cost polymer-based membranes and solid sorbents, which would benefit from pairing with WGCU and production of CO₂ at elevated pressure.

Figure 3 : Advanced IGCC Plant incorporating DOE/NETL-supported advanced technologies1

Successful implementation and integration of all these advanced technologies allows for an estimated increase of 7.0 percentage points in efficiency, as shown in Figure 4. Coupled with increased availability and improved financing structure, a reduction of 28% in COE relative to the state-of-the-art carbon capture IGCC plant has also been estimated.

Figure 4. Cumulative Impact of advanced IGCC technology on net plant efficiency and COE1

1. "Current and future power generation technologies: pathways to reducing the cost of carbon capture for coal-fueled power plants” Kristin Gerdes, Robert Stevens, Timothy Fout, James Fisher, Gregory Hackett, Walter Shelton, Energy Procedia 63 (2014) 7541 – 7557.

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