Igcc

2.2.3.1 Without CO2 Capture

IGCC power generation from coal is illustrated in Fig. 2.9, showing the main process components and stream flows. Oxygen from an air separation unit is used to combust sufficient carbon in the gasifier typically at 500-1,000 psig to increase the temperature to around 1,500°C (2,730°F). For typical coals, the ash melting point is between 1,200°C and 1,450°C. At 1,500°C, the coal ash melts and leaves the bottom of the gasifier as slag. At this temperature, water (steam), which is added with the coal or separately, reacts with the remaining carbon to convert it to

Igcc Power Generation
Fig. 2.9 A representative coal-based IGCC unit showing main process components and streams (Courtesy NETL)

syngas, a mixture mainly of carbon monoxide (CO) and hydrogen (H2) and some CO2, along with impurities such as H2S, NH3 & mercury. The syngas is quenched with water to remove particulate matter, cleaned of impurities, and then burned in a turbine in a combined-cycle power block that is very much like a natural gas combined-cycle (NGCC) unit (see Fig. 2.9). Because all the gases are contained at high pressure, high levels of particulate matter, sulfur, mercury, and other pollutant removal are possible. Air emissions levels from an IGCC unit should be similar to those from a NGCC unit. Coal mineral matter is removed from the gasifier as a solid, relatively dense vitreous slag.

The gasifier is the biggest variable in the system in terms of type (moving bed, fluid bed, and entrained flow), feed approach (water-slurry, dry feed), operating pressure, and the amount of heat removed from it. For IGCC units to date, entrained-flow gasifiers have been the primary choice. For electricity generation, without CO2 capture, radiant and convective cooling sections behind the gasifier that produce high-pressure steam for additional power generation lead to efficiencies that can approach or exceed 40%. The additional heat removal options are illustrated in Fig. 2.10.

Figure 2.11 is a schematic of a 500 MWe IGCC unit summarizing the operating conditions and giving the stream flows for no CO2 capture. The unit is using Illinois #6 coal at rate of 185,000 kg/h or 4,400 tonnes of coal per day. This unit, which employs radiant cooling but not convective cooling, has a generating efficiency of 38% on an HHV basis [10, 13].

Oxygen

I .

Co

al/Water

Slurry

\ <

r

Gasifier

I

Radiant Syngas Cooler

Pressure

High-

Steam

n

Bo

ler Wate

-

/N

>_r

y

V y

Water

Conve

Synga

Fig. 2.10 Heat recovery options for an entrained-flow gasifier. Additional steam produced is used to generate electricity

Slag

Fig. 2.10 Heat recovery options for an entrained-flow gasifier. Additional steam produced is used to generate electricity

Electric Power

Fig. 2.11 Schematic of 500 MWe IGCC unit without CO2 capture. Projected generating efficiency with radiant cooling is 38.4% [10]

Electric Power

Fig. 2.11 Schematic of 500 MWe IGCC unit without CO2 capture. Projected generating efficiency with radiant cooling is 38.4% [10]

2.2.3.2 With CO2 Capture

A block diagram with key material flows for a 500 MWe IGCC unit designed for CO2 capture is shown in Fig. 2.12. To achieve CO2 capture with IGCC, the CO in the syngas must first be converted to CO2 and H2 via the water gas shift reaction (CO+H2O ^ CO2+H2). To do this, two catalytic shift reactors are added just behind the quench to convert H2O and CO to H2 and CO2. The gas clean-up train requires addition of a second gas-scrubbing unit located behind the sulfur-scrubbing unit to remove the CO2. The CO2 capture and recovery is done at high concentration and pressure, involves weak absorption, and recovery of the CO2 is by pressure letdown. As such, it requires less energy and is cheaper than for dilute CO2 capture from flue gas. The estimated generating efficiency for the design and operating parameters is 31-32% [10, 13]. Figure 2.13 illustrates the parasitic energy requirements to capture the CO2 in an IGCC plant; the efficiency loss is about 7 percentage points vs. about 10-11% points for PC with CO2 capture. The largest efficiency reduction is related to generating the steam required for the water gas shift reaction. CO2 compression is second largest but is less than for PC because the compression begins at a higher pressure. After shift and clean up, the resulting gas stream is largely H2, which is then burned in a combustion turbine as part of a combined cycle unit to generate power. Turbines that can burn high concentrations of H2 have not yet been developed. All other technologies are commercial. For example, ammonia production from coal utilizes all the steps up to combustion and is practiced in the US, Europe, and particularly China. However, these technologies have yet to be integrated and

Feed Air 801,000 kg/hr

Nitrogen 604,000 kg/hr

Nitrogen 604,000 kg/hr

Combustion Air 2,890,000 kg/hr

Quench Gasifier

Cooling

Knockout and

Water-Gas

Shift

Sulfur Removal

Combustion Turbine/Heat Recovery Steam Generator/Turbine/ Generators

Electric Power 500 MWe Net

Bottom Slag 29,900 kg/hr

Carbon Dioxide 456,000 kg/hr, 150 atm

Fig. 2.12 500 MW IGCC with CO, capture. Projected generating efficiency with quench gasifier is 31.2% [10]

Efficiency Loss: IGCC Capture

38.4

Water/Gas Shift & Other

38.4

Water/Gas Shift & Other

IGCC No Capture

IGCC No Capture

Fig. 2.13 Typical parasitic energy consumption associated with IGCC for pre-combustion CO2 capture vs. IGCC designed for no CO2 Capture [10]

demonstrated at the scale of operation required for large-scale power generation. Turbines that can burn very high H2 concentrations are under development, but current turbines can only burn H2 with appropriate dilution with N2 from the air separation plant. Turbines designed for hydrogen combustion could provide an additional increase in generating efficiency.

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