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Gasification

oxidant. At this point more carbon is combusted to CO

to maintain the heat

balance, which further reduces the efficiency. Should a particular process require a

minimum amount of steam, for burner protection, for example, the point at which the

make begins to increase will be at a correspondingly higher oxygen content in

the oxidant.

An alternative approach to compensating for the heat absorption by the nitrogen

might appear to be an increase in preheat temperatures. Klosek, Sorensen, and

Wong (1993) discuss this aspect in their paper but point out its limitations. The

required preheat temperatures of about 1200°C become “excessively high and

unacceptable.”

Similarly, the drop in useful syngas (H

+CO) is visible as the oxygen content in

the blast decreases.

Gasification Temperature

At lower gasification temperatures these effects are less but are nevertheless still

present.

Use of Hot Syngas

Reviewing the implications of oxidant quality only on a cold-gas efficiency basis

ignores the fate of the sensible heat contained in the syngas leaving the reactor. In an

IGCC environment, the most efficient use of this heat would be to feed it uncooled

100

020406080100

Oxygen content [mol%]

Cold Gas Efficiency [%]

Cold gas efficiency

kmols O

per 100 kg maf coal

kmols O

per kmole syngas

Figure 6-13. Gasification Parameters as a Function of Oxygen in Oxidant

Practical Issues

221

to the gas turbine, since this has a fundamentally higher efficiency than the steam

cycle (see Section 7.3). This theoretical possibility is, however, only realizable if the

raw syngas quality is acceptable to the gas turbine, which in general is not the case.

In particular, particulates and alkali metals need to be removed prior to the gas

entering the gas turbine. These contaminants can be removed at 500°C using candle

filters (see Section 6.7).

There is still an interest in “hot gas desulfurization,” especially in connection

with air-blown gasifiers. This is not because the gas turbine cannot cope with the

sulfur once the alkali salts have been removed, but because of the environmental

requirements. Improvements in flue gas desulphurization technology provide a

continuously moving target. With double-scrubbing technology, sulfur removal

from the flue gas can also be as high as 99%. However, it should be noted that any

improvement obtained with such technology developments will benefit oxygen-

blown systems as much as they will air-blown systems. So far all attempts at hot

sulfur removal have failed, and there is no indication that a good solution will be

found in the near future. Further details of gas cleaning technologies are described in

Chapter 8.

An effective use of the hot gas, particularly where it is generated in a small-scale

biomass gasifier, is to utilize it as a gaseous fuel in a large utility boiler. This is

particularly effective, because the low efficiency inevitable with small-scale plants

can be avoided by tying into the larger unit. A particularly interesting example is an

air-blown CFB gasifier processing waste wood and firing the gas into a 600 MWe

PC power boiler at Geetruidenberg in the Netherlands.

One other albeit rare case where the full sensible heat of the syngas from an air-

blown gasifier is used in the downstream process is in the production of reducing

gas, for example, for nickel reduction, where the gas is fed from an oil gasifier directly

to the reduction furnaces without any cooling.

6.10.2 Equipment Sizing and Gas Flow Rate

The flow rate of synthesis gas when using air as an oxidant is approximately twice

that of the equivalent oxygen-blown gasifier. This has consequences both for equipment

sizing and for the gas-cleaning technologies.

An air-blown gasifier must either be twice the size of an oxygen-blown one, or two

are required. Whether the design is refractory-lined (e.g., Texaco) or fitted with a

cooling wall (e.g., Shell or Noell), the gasifier is an expensive piece of equipment.

The same goes for the syngas cooler and other downstream equipment such as filters

and gas-cleaning equipment.

Besides the effect on equipment, one also needs to look at the emissions. To achieve

the same absolute sulfur emissions, the sulfur slip from the SRU for an air-blown

unit must be half that of an oxygen-blown gasifier since there is twice as much gas.

This will certainly require additional expenditure in the AGR unit.

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Gasification

6.10.3 Parasitic Power

Parasitic power is usually defined as the electrical energy required for drivers of

auxiliary machines in an IGCC. In connection with an oxygen-blown gasifier, this

includes the air compressor (if any) for the ASU, the oxygen compressor, and the

nitrogen compressor (again, if any). For an air-blown gasifier, the parasitic power

for the provision of oxidant is the air booster compressor (see Figure 6-14). Unfortu-

nately, this definition very quickly creates misunderstandings or confusion, because

it does not include the power used by the air compressor of the gas turbine. Any air

integration included in the cycle removes mechanical energy in the shaft from the

generator, where it can produce electric power. Since the compression energy internal

to the gas turbine is not included in the normal definition of parasitic power, one needs

to be very careful about drawing any conclusions from a single number provided for

any particular project. In practice, finding an optimum integration between the gas-

turbine air compressor and the provision of oxidant is highly dependant on the

characteristics of the air compressor itself, and it should come as no surprise to find

that different optima can be presented by different gas turbine suppliers for the same

project.

Klosek, Sorensen, and Wong (1993) point out that the parasitic power demand

for an oxygen-blown IGCC without nitrogen integration can be significantly

lower than that of an air-blown unit. This initially surprising result can be attrib-

uted to two facts. First, the air-blown unit must handle much more air, and second,

the air must all be compressed to the gasifier inlet pressure, which is in the current

designs significantly higher than the turbine combustor pressure. Reducing the

pressure drop over the gasifier and treating could well change some of the above

conclusions.

FEEDSTOCK

GAS CLEAN-

GT COMBUSTOR

GASIFIER

HRSG

GT AIR

COMPRESSOR

AIR

GENERATOR

AIR BOOSTER

COMPRESSOR

GAS

TURBINE

FLUE GAS

HEAT

RECOVERY

Figure 6-14. Typical Air-Blown IGCC

Practical Issues

223

6.10.4 Deductions

Essentially, the reasons why most real IGCCs have been built using oxygen as

oxidant are economic, and the technical background to these economics has

been described in the preceding sections. These plants, whether demonstration

(e.g., Buggenum, Puertollano, Wabash, and Tampa at 250–300 MW) or commercial

(e.g., Sarlux at 500 MW), are, however, all large projects. There is no disguising the

fact that the favorable economics of oxygen-blown technology has an entry price,

which is the investment cost of the ASU. At this scale, the entry price is well worth

paying.

For small plants, smaller than say 50 MW, which is largely the realm of biomass

and waste fuels, the initial investment in an ASU is less attractive. Savings on the

much smaller equipment and the improved efficiency of oxygen operation is no longer

able to pay for this investment. This is why many gasification projects in this size

range use air-blown gasifiers. It is, however, not possible to provide any hard-and-fast

guidelines for determining the break-even point between the two technologies. The

number of variables, which include feedstock pricing and supply, gas turbine

characteristics as discussed, and the potential for synergies in oxygen supply (see

Section 8.1), make a project-specific evaluation inevitable.

6.11 CORROSION ASPECTS

Gasification takes place at high temperatures, depending on the process, anywhere

between about 900 and 1500°C. Processes have been developed with the capability

of operating at pressures of over 100 bar, although commercial experience is limited

to about 80 bar (oil) or 40 bar (coal). Other processes operate at atmospheric pressure.

The synthesis gas produced contains CO

, CO, H

, CH

, N

, H

O, and almost invariably

sulfur compounds, mostly H

S. This gas is usually cooled down to ambient tempera-

tures, and in doing so the temperature range imposed on the containing equipment is

very wide and includes sub-dewpoint temperatures. It is not surprising, therefore,

that particular attention has to be paid to material selection in a potentially corrosive

environment. Some of the corrosion mechanisms that can arise under these circum-

stances are well known from other circumstances. The purpose of this section is not

to address these, however, but to highlight those potential problems that might be

less familiar to those with little prior experience of gasification, and to point to suitable

literature where more information may be obtained.

6.11.1 Sulfur

The metal temperatures of evaporator sections of syngas coolers is determined primarily

by the temperature and thus by the pressure of the steam side. With typical high-

pressure steam conditions of 100 bar, this implies metal temperatures between 300

224

Gasification

and 350°C. EPRI and KEMA have conducted corrosion tests specifically to determine

corrosion rates by sulfiding in this temperature range, and they found a clear

dependency between corrosion rate and partial pressure of H

S (van Liere, Bakker,

and Bolt 1993). According to these results, in an atmosphere with 1 mol% H

S at 40

bar and 300°C, a corrosion rate of 1.5 mm/y can be expected with low alloy steels,

with which they specifically include alloy T22 (10CrMo910). The investigation was

made primarily with coal gasification in mind, so it is unclear from the published

results what other trace components were in the gas. In our experience with gasification

of heavy petroleum residues at 60 bar where 1 mol% H

S is by no means uncommon,

any corrosion rate must be at least an order of magnitude lower than this, since

evaporator coil lifetimes of 60,000 hours are common (Higman 1994). It is unclear

what protection mechanism exists in the latter case to explain this apparent contra-

diction.

When superheating is included in the syngas cooler, then much higher metal

temperatures must be expected, and they are likely to be in the range 300 to 600°C. Van

Liere, Bakker, and Bolt’s results indicate clearly that an austenitic steel is required for

this service, typically SS310, which interestingly performs better than alloy 800.

Corrosion during shutdowns, particularly on the ingress of oxygen, requires careful

attention. Appropriate operation and maintenance procedures have been published

(National Association of Corrosion Engineers 1993).

6.11.2 Hydrogen

A typical oil gasifier may have a pressure of 60 to 80 bar and a hydrogen content of,

say, 30% (wet basis). In other words, a hydrogen partial pressure of 20 bar or more

may prevail. The equivalent figures for a coal gasifier will probably be lower. For

partial oxidation of natural gas there may be over 50% hydrogen, although for most

applications the absolute pressures may be somewhat lower than for oil. The shell of

a refractory-lined gasifier will have a normal operating temperature of around

250°C, but it will probably have a design temperature of 350°C to allow for a small

amount of bypass gas streams through cracks in the refractory, or in the case of coal

gasifiers, simple refractory wear. Materials in the equipment immediately downstream

the gasifier will be subjected to similar conditions, which are well into the range

where hydrogen embrittlement can occur. Attention must be paid to the selection of

hydrogen tolerant alloys, which typically may be chrome-molybdenum steels or

higher alloys, depending on actual hydrogen partial pressure and temperature. The

best guide to material selection for this service is API 941 (API 1990), which

contains the well-known Nelson curves.

6.11.3 Chlorides

In the reducing environment of a gasifier, a significant portion of any chlorine in the

feed is converted to HCl. The most important corrosion aspect to consider is that at

Practical Issues

225

temperatures below the water dewpoint the condensate can cause pitting or stress

corrosion cracking of the commoner austenitic steels. Good plant design can take

care of exchangers and piping containing process condensate. It is an important

matter for operations and maintenance procedures to avoid cold bridges through the

insulation of warmer equipment (e.g., at pressure gauges), which can cause local

condensation. Another point where operational care is required is during shutdown,

when it would be necessary to avoid condensate formation.

6.11.4 Metal Dusting

Metal dusting is a particularly aggressive form of high-temperature (mostly) CO

corrosion, which has received particular attention in connection with the manu-

facture of CO-rich synthesis gases using steam reforming or catalytic partial

oxidation.

Although certain details of the mechanism of metal dusting, and particularly the

potential for countermeasures, remain the subject of some debate, the essentials

have been understood for many years (Hochmann 1972; Grabke, Brach-Troconis,

and Müller-Lorenz 1994). Under gasification conditions, the Boudouard reaction

(2-4) oxidizes carbon with CO

to form carbon monoxide. However, during

syngas cooling a point is reached where the equilibrium favors the reverse

reaction. At sites on the surface of materials containing particularly iron or nickel,

the reverse Boudouard reaction is catalyzed. The carbon thus formed destroys the

matrix, and the surface metal is lost as a “dust” into the gas phase. The tempera-

ture range in which metal dusting can occur is from a lower limit of about 450°C,

where the reaction kinetics cause the corrosion to slow down to a rate that may be

considered acceptable, up to the Boudouard equilibrium temperature of the syngas

(Hohmann 1996). A typical sign of metal dusting during process operation is the

appearance of the products of corrosion as a “magnetic soot” in the process

condensate.

Metal dusting is unusual in gasification plants, because sulfur is an excellent

inhibitor for this type of corrosion (Gommans and Huurdeman 1994) and most gasifier

feeds contain some sulfur. Where a desulfurized natural gas is used to manufacture

syngas for Fischer-Tropsch products, however, the potential for metal dusting is

very high, since the CO partial pressures will tend to be considerably higher than in

a steam reformer plant. Furthermore, the corrosion product, which is very fine and

has a large surface area, provides an ideal catalyst for the very exothermic methanation

of the CO in the syngas.

There is still a consensus that although careful choice of metallurgy can slow

down the effects of metal dusting, there is no real metallurgical solution. The best

way to avoid this form of corrosion is to avoid gas-metal contact in the endan-

gered temperature range. For a reformer tube outlet, Hohmann (1996) determined

the area of the material at risk and introduced a purge gas at this location with

success.

226

Gasification

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