Higman Chris Gasification (Газификация угля)

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340

Gasification

emerged to counter the problem despite the intensive debate over the last 10 or 15

years. Nonetheless, there is no disputing the correlations between global average

temperatures and atmospheric CO

concentrations (as determined from Antarctic ice

cores) over hundreds of thousands of years, and between anthropogenic emissions

and atmospheric CO

concentrations over the last 250 years (Figures 9-5A and 9-5B).

And whether we understand the mechanisms in detail or not, it is certainly wise to

take measures to reduce man-made contributions to global warming.

Before discussing what place gasification could have in any such strategy for CO

emissions reduction, it may be useful to have a look at the overall greenhouse gas

effect as related to the use of fossil fuels.

As can be seen from Figure 9-6, the two biggest contributors to CO

emissions

are the electric power and transport sectors. Given the millions of small moving

emission sources involved in transport, any significant reductions in CO

emissions

is only likely to emerge through the change to a less carbon-intensive fuel such as

natural gas or hydrogen. Although the use of natural gas (at least while it lasts)

would still result in large, even if lower, emissions from millions of individual

sources, the use of hydrogen offers the possibility of bundling CO

emissions at fixed

locations in a manner that would allow fixation or sequestration. Further discussion

of this aspect is discussed after first looking at the largest CO

emitter, the power sector.

A major contribution to lowering CO

emissions in the power industry could be

realized almost immediately simply by increasing the efficiency of the power park.

Replacement of a 30-year-old coal-fired unit operating at, for example, 32%

efficiency by a modern plant (whether with IGCC or ultra-supercritical PC technology)

using the same fuel with an efficiency of 43% would drop the CO

emissions per

produced kilowatt-hour by 25%. The barriers here are not of a technological but of

a financial nature given the limited capital and incentive for such replacement

projects. Again, the reductions offered by cogeneration (or combined heat and power),

although ultimately limited by the available heat sinks, face at present financial

rather than technical hurdles.

1000

7000

6000

5000

4000

3000

2000

ATMOSPHERIC CONCENTRATIONS

ANTHROPOGENIC EMISSIONS

200019501900185018001750

380

360

340

320

300

280

260

150

350

300

200

250

THOUSANDS OF YEARS AGO

050100

ATMOSPHERIC CONCENTRATIONS

TEMPERATURE CHANGE

–6

–2

–4

TEMPERATURE CHANGE [°C]

CONCENTRATIONS [PPMV]

EMISSIONS [MILLION TONS CARBON]

(A) (B)

Figure 9-5.

Figure 9-5.Figure 9-5.

Figure 9-5. (A) Correlation Atmospheric CO

Concentration and Temperature

(Source: Simbeck 2002); (B) Correlation between Anthropogenic CO

Emissions

and Atmospheric CO

Concentrations (Source: U.S. Oak Ridge National

Laboratory)

Economics, Environmental, and Safety Issues

341

Beyond the above, serious consideration is now being given to recovery of the

from the energy conversion process and putting it to use or simply sequestering

it. In such a scenario there are some natural advantages to gasification over combus-

tion technologies. In fact, CO

capture and usage is already standard practice in

almost all gasification-based ammonia plants, where the CO

is recovered from the

synthesis gas and used to manufacture urea.

Another example of CO

recovery from a coal gasification plant is the Great

Plains SNG plant, which sells CO

for enhanced oil recovery (EOR) in the Weyburn

field in Canada. EOR is particularly attractive for CO

usage in that besides the

avoidance of adding to atmospheric CO

, it provides a means of extending the life of

existing energy resources. EOR has been practiced in the Permian basin oil fields in

Texas for over 30 years, although much of the CO

used comes from natural under-

ground CO

reservoirs and therefore does not as such contribute to greenhouse gas

abatement. Nonetheless, it points the way to one potential route for sequestration.

Other alternatives have been or are being investigated as well, such as sequestration

in underground saline aquifers (e.g., Statoil’s Sleipner project in the North Sea),

storage in coal seams, and others (White 2002; Beecy 2002).

As mentioned above, gasification-based processes have a natural advantage over

combustion technologies when it comes to CO

capture. In one study based on using

gasification with total water quench technology at 80 bar, the addition of CO

capture was shown to add only a small increment on capital costs (about 5%) and an

efficiency penalty of only 2% (O’Keefe and Sturm 2002). The block flow scheme is

shown in Figure 9-7.

This should be compared with the impact of CO

capture on a ultra supercritical

PC combustion technology power block. This is extremely heavy even if one

assumes the prior existence of FGD and SCR flue gas treatment, which are a prereq-

uisite for CO

recovery from the flue gas, for which at present amine scrubbing is

Commercial

Industrial

21%

Residential

Transport

31%

Electric utilities

37%

Figure 9-6.

Figure 9-6.Figure 9-6.

Figure 9-6. Share of U.S. CO

Emissions by Sector (Source: U.S. EPA 2002)

342

Gasification

universally proposed. The key fact is that the volume of gas from which the CO

has

to be extracted is in the case of combustion technology 150–200 times larger than is

the case in an IGCC plant. The add-on capital cost has variously been estimated at

60–80%. The steam requirement for amine regeneration is lost to the final turbine

stages, and this causes a drop in efficiency of some 9.5–14 percentage points

(Simbeck 2002; Koss and Meyer 2002).

Clearly there is an incentive to find some use for the CO

and “recycle” it. Although

there may be local markets where this is possible on a small scale, a review of the

data in Table 9-5 will show that the “chemical” scope for such a solution on a global

scale is very limited. Apart from oxygen and hydrogen, there are no potential reactants

with relative mass flows approaching that of carbon. Even iron usage is an order of

magnitude smaller. It is further observed that the only mass in the world that is of

the same order of magnitude as fossil fuels is waste biomass flow (though this is not

valid for the energy, which is an order of magnitude less) (Shell 2002).

The only major application of waste CO

is for the enhanced recovery of oil and

gas, but most of the CO

will have to be sequestered underground in depleted gas

fields, in aquifers, and in deep-sea basins (van der Burgt, Cantle, and Boutkan

1992).

An alternative option for removing CO

from flue gases from power stations that

has been proposed is combustion with pure oxygen. The flue gas will then contain

only water and CO

, and in the case of coal and heavy oil fractions, also SO

, NO

and other contaminants such as mercury. The advantage is that in this case all

contaminants can be sequestered together, and apart from the ASU, no gas separations

are required. However, with the present cryogenic separation of air, this solution is

unlikely become attractive for both economic and efficiency reasons. Moreover, in

ASU

CLAUS

GASIFIER

SATURATOR

EXPANDER

SULFUR

FEED

OXYGEN

AIR

LEAN

FLUE GAS

ELECTRIC

POWER

COMBINED

CYCLE UNIT

SELECTIVE

AGR

RAW GAS

CO SHIFT

WATER

QUENCH

Figure 9-7.

Figure 9-7.Figure 9-7.

Figure 9-7. IGCC with CO

Capture

Economics, Environmental, and Safety Issues

343

the case of CC power stations, this route would require the development of gas turbines

that is optimized to handle pure tri-atomic gases.

It should be noted that the IGCC variant provides a source of hydrogen that, with

a combination of membrane and PSA technologies, can be extracted during periods

of low electric power demand and stored for onward sale into the transport sector.

The importance of this possibility is discussed further in Chapter 10.

Methane. On a mole for mole basis, methane contributes 20 to 25 times more to the

greenhouse effect than CO

. Anthropogenic methane from fossil sources enters the

atmosphere in the form of vented or incompletely combusted associated gas, leaks

in natural gas pipelines, and methane emissions related to coal mining.

The largest source of methane emissions resulting from fossil fuel production

and refining derives from the associated gas. On average about 10% of the energy

leaving an oil well is in the form of associated gas, and assuming that 5% of this gas

is not combusted either because people do not want to see flares or because flares

are not working properly, it is conservatively estimated that about 8% of the green-

house gas effect related to the use of crude oil is due to methane emissions during

production. Adding to this the effect of the CO

from the 95% of the associated gas

that is properly combusted in operating flares, this figure increases to 15%. Schaub

and Unruh (2002) have estimated that the quantity of associated gas flared in

Nigeria alone would be sufficient to supply 30% of Germany’s natural gas supply.

Clearly, there is potential here for a reduction in greenhouse gas emissions, to which

synfuels production via partial oxidation of the gas and subsequent Fischer-Tropsch

synthesis could make a significant contribution. Global application of such a solution

Table 9-5

Important Mass Flows in the World

Ton/y Relative Mass

Flow

Fossil fuels 10 ×10

100

Carbon 8 ×10

emissions 30 ×10

300

Chemicals 3 ×10

Ceramic building materials 10−15 ×10

10–15

Iron 5 ×10

Carbon for iron ore reduction 3 × 10

Carbon for SiO

reduction, 100,000 MW

peak/year new installed (1 mm thick wafers) 1 ×10

0.01

Waste biomass 5–10 × 10

50–100

Source: Shell 2002

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Gasification

could reduce the 15% of the greenhouse gas effect related to the use of crude oil to

a mere 2–3%.

9.2.3 Liquid Effluents

Whether a gasification complex is a net water consumer or producer will depend on

the feedstock and the downstream operation. In general, when coal or petroleum

residues are used as feedstock, there is always a net consumption of water, whereas

with natural gas–based plants, there can be a net production of water. Similarly, the

application, chemicals or power, will have an influence over the overall water

balance of the plant.

Most gasification plants have a water wash at some part of the syngas treatment.

For coal gasifiers, its main purpose is to remove ammonia and chlorides, though

many other constituents of the gas are also captured. Whether this process water is

acidic or basic will depend on the amounts of nitrogen and chlorine in the coal.

Whatever the pH of this water, it will almost certainly require to be adjusted during

the flocculation step of the overall water treatment. In oil gasification plants, the

main objective is removal of soot, but the water also contains ammonia, hydrogen

cyanide, and H

In practice, with appropriate design, an IGCC can be made with zero liquid

discharge, whether using a dry feed technology as in Buggenum (Coste, Rovel, and

George 1993) or a slurry feed as in Polk (U.S. Department of Energy 2000). In both

these plants the final water treatment stage is a brine concentration and evaporation

unit producing a solid waste salt.

Oil gasification units generally do not recycle the excess process water. In those

applications, where the plant is located in a refinery, the water treatment is generally

integrated into that of the overall refinery after ammonia, HCN, and H

S have been

removed in a sour water stripper. Typical emission limits and performance for

a stand-alone plant are given in Table 9-6

Specific aspects of water treatment are addressed in the following sections.

Table 9-6

Emission Limits and Oil-Based IGCC Performance

Pollutant Emission Limits Oil-IGCC Regulation

Vanadium (mg/l) 2 <2 City of Hamburg

Nickel (mg/l) 0.5 <0.5 Rahmen Abwasser

VwV 1992

BOD

(mg/l) 25 <20 Rahmen Abwasser

VwV 1992

Economics, Environmental, and Safety Issues

345

Fluorine. Fluorine in the gas will dissolve in the wastewater from the water wash,

from which it can be removed by adding calcium ions that will precipitate the fluorine

as CaF

. This salt will eventually end up in the same settler/filter cake as the heavy

metal-containing precipitate from the flocculation unit.

Cyanide and Cyanometallates. A significant portion of the HCN produced in the

gasifier is contained in process condensate. In any plant gasifying heavy oil, the

excess water from the gasification section is usually stripped to remove free ammonia,

S, and HCN. Typically, residual HCN values of 10–20 mg/l can be achieved in

a single-stage stripper. The residual HCN can be reduced to below 1 ppm in a

biological treatment unit.

An alternative approach to cyanide and cyanometallates is to oxidize them. This

is particularly appropriate when recycling all the process condensate for a zero-

discharge system. Although aeration in a closed vessel is possible and has been

employed, the required contact times are long and require large volumes. A more

economic approach is the use of ozone as an oxidant, since this reacts rapidly with

the cyanides (Coste, Rovel, and George 1993).

Heavy Metals Precipitation. Whether gasifying coal or heavy residues, there are heavy

metals contained in the process condensate. Typically, these are subjected to treatment

by flocculation and precipitation. The choice of flocking agent is determined by the

metals to be removed, but is typically ferric chloride. The metals sludge from the

precipitation stage is then thickened prior to filtration.

The excess water so treated would be “free of fluorides, cyanides and heavy

metals and contain only dissolved soluble salts” (Coste, Rovel and George 1993).

Sand filtration may be required to remove traces of metal hydroxides from the

flocking step.

9.2.4 Solid Effluents

Solid effluents from gasification plants are essentially related to the ash in the feed-

stock, the quantities of which can vary from as much as 40 wt% in some coals to under

1 wt% for petroleum feeds. In many cases gasification plants are able to make the solid

residue available in a form that can be used as a raw material in other industries.

In contrast to a PC boiler, gasification has no FGD sludge or gypsum disposal

problem because the sulfur is all captured as elemental sulfur in the Claus plant. At

present this is a saleable product, although one should be aware that, were a large

part of the power industry to switch to gasification-based processes, this together

with increasing sulfur production from oil refineries would oversaturate the market.

Nonetheless, even in this case the amounts of material would be substantially

smaller than with gypsum.

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Gasification

Dry Coal Ash. Dry ash from nonslagging gasifiers is essentially the same material

as the product of a PC boiler processing the same feed. This ash can often be utilized

in the cement or building industry. If this option is not available due to the nature of

the ash or due to transport problems, the ash can become a major environmental

liability that can be aggravated if the ash is leachable or caustic in nature. The ash is

then often stored in large ponds, which have become more and more unacceptable.

This problem can be largely avoided by selecting a slagging gasifier from which the

quantity of dry ash waste is one to two orders of magnitude lower than from a dry

ash gasifier.

Slag. Slagging gasifiers have in general an advantage over dry ash processes in that

most of the ash components leave the gasifier as molten slag, which on being

quenched turns into a fine inert gritty material that can be used as a replacement for

sand and aggregate in concrete, for example. Van Liere, Bakker, and Bolt (1993)

give the particle size of water-quenched slag as being about 78–80% in the range

0.5–4 mm in a paper in which they describe usage trials in Dutch road construction.

Data from Geertsema, Groppo, and Price (2002) generally supports this size data

for the actual slag component, although the material analyzed contained consider-

able quantities of unreacted carbon, which after separation are recycled to the gasi-

fier or used as fuel in a PC boiler. They report the slag as being used for blasting

grit and roofing granules. Amik and Dowd (2001) provide an analysis for slag

produced at the Wabash River plant (Table 9-7), which essentially mirrors the ash

content of the coal used. The slag contains trace metals such as lead, arsenic,

selenium, chrome, antimony, zinc, vanadium, and nickel, which is captured in the

nonleachable glassy matrix. The results of some leachability tests are included in

the paper. They report marketing for asphalt, construction backfill, and landfill

cover applications.

Table 9-7

Slag Analysis

SiO

51.8 %

18.7%

TiO

0.9%

20.3%

CaO 4.2%

MgO 0.8%

O 1.0%

O 1.9%

Source: Amik and Dowd 2001

Economics, Environmental, and Safety Issues

347

Heavy Metals. The nature of any heavy metals leaving the plant as solid effluent

will depend heavily on the feedstock. With a coal feed, most heavy metals will end

up in the slag or fly ash of a gasifier. Heavy metals that are not removed together

with the fly ash and slag will eventually end up in the wastewater from the water wash.

As described on page 345 the heavy metals are removed from the water as a filter

cake after treatment by flocculation and precipitation. With coal feeds this filter

cake may contain such elements as arsenic, antimony or selenium. Unlike the slag,

this concentrate is not inert and has to be considered as chemical waste.

In the case of oil feeds, the main heavy metals are vanadium, nickel, and iron.

There are a number of processes available for recovering the ash for use in the

metallurgical industry (see Section 5.4). The economics of such processes depends

very much on the vanadium content in the ash.

Salt. All coal gasifiers will have dissolved salts in the treated wastewater. When this

water cannot be disposed of, the water has to be evaporated and a salt mix is

obtained that consists of over 98% NaCl. This product is often not suitable as road

salt and may have to be considered as chemical waste.

9.2.5 Waste Gasification

For reasons that are mostly historical, emissions regulations for thermal treatment of

waste are generally much more stringent than for, say, a coal-based power plant.

Waste gasification plants, particularly slagging units, have the potential to provide

a viable alternative to incineration. The current review in the United States on

removing refinery wastes that are processed to syngas from the hazardous classification

is, however, typical of the moving targets in this field. A number of plants, such as

Schwarze Pumpe, provide a local or regional waste disposal center in which waste is

gasified and the syngas used for production of methanol and electricity. Here the solid

slag is nonleachable and meets the German municipal waste standards “Siedlungsabfall

class 1” (Greil et al. 2002).

9.3 SAFETY

Issues of safety are associated with practically all industrial technologies, and under-

standing the appropriate measures for safety management is an important part of

understanding the technology itself. In this respect, gasification is no different from

many other technologies. The purpose of this section is to make those unfamiliar

with gasification aware of those issues that may be considered specific to the tech-

nology. It is certainly no substitute for a project-specific safety manual and does not

address issues common to any large-scale industrial plant. It does, however, point to

other sources, which may help the reader develop his or her own ideas for a particular

project in more detail.

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Gasification

Gasification plants are complex plants that produce a high-pressure toxic gas that

is inflammable or even explosive in the presence of oxygen and an ignition source.

Furthermore, the presence of pure oxygen, as is the case in most gasification pro-

cesses, requires additional precautions. Generally, all these dangers are well taken

care of in the process designs. Handled correctly during construction, operation, and

maintenance, they pose no more problems to personnel or environment than many

other industrial plants.

9.3.1 Start-Up

One of the potentially dangerous moments during start-up is the ignition of the coal

or oil burners. The problem is much more complex than in regular atmospheric

pressure furnaces, as ultimately the burners have to work at pressures ranging from

20–70 bar, and there are no burners that can operate properly over this whole pressure

range. Where membrane walls are used, which cool very quickly in the absence of

a flame, start-up burners often have to be used to cover part of this pressure range.

At all times the situation should be avoided in which a mixture of a combustible gas

and oxygen is present in the reactor.

9.3.2 Shutdown

After shutdown the gasifier is often nitrogen blanketed to avoid corrosion. When

repairs have to be carried out inside the gasifier, one has to make sure that there are

no other gases than air present. Drawing a good vacuum and breaking this with air is

the best way to ensure that only air is present. This operation may have to be

repeated several times to ensure that all noxious gases are removed from insulating

materials, bricks, and dead ends in the plant. Even with all these precautions, air

masks may be required under certain conditions.

9.3.3 Spontaneous Combustion

As in a conventional PC power plant, safety precautions in coal storage and hand-

ling are essential to avoid spontaneous combustion. This applies equally well to

other feedstocks such as biomass and certain types of waste. The key in particular is

to prevent fines from drying out, so that a first-in first-out inventory policy must be

part of the safety procedures.

Besides the fuel itself, there are other potential sources of spontaneous combustion.

Particular attention must be paid to FeS which may form as a product of corrosion.

Another potential source is incorrect handling of catalysts, particularly unloading spent

catalyst, which may not have been adequately oxidized in situ. Acting in strict

conformity with the catalyst vendors' procedures is important.

Economics, Environmental, and Safety Issues

349

9.3.4 Toxic and Asphyxiating Materials

Apart from the main syngas component, carbon monoxide, there are many other toxic

gases present in a gasification complex, particularly if the end product is a chemical.

Typical toxic gases present in synthesis gas can include compounds such as H

S and

COS as well as ammonia and HCN. The design of a plant must take account of this,

and personnel must be trained in their safe handling. There are many public sources of

safety information available on material safety data sheets. Many of these are

available from Internet sources such as www.ilpi.com/msds, which has links to many

international source sites. An up-to-date data sheet should always be available with

the safety officer or other member of staff responsible for safety training.

Nitrogen. It may come as a surprise, but a large part of the accidents occurring in

gasification plants are due to nitrogen that is produced as a (by-)product from oxygen

plants and used for blanketing and transport of coal and further as a diluent for the

fuel gas. In this latter function it reduces the stoichiometric adiabatic flame temperature

and as a result the thermal NO

The problem with nitrogen is that contrary to the fuel gas it has no smell, and

even more problematic, it leads very fast to unconsciousness. Good ventilation of

the plant is a very efficient precaution. Building a gasifier inside a closed structure

because it may look better from a distance can be dangerous. Not only because of

nitrogen, but also because we deal with pressurized gases containing CO, H

S, COS,

HCN, and NH

. If the plant has to be visually enclosed, the best alternative is to

have louver walls that guarantee good ventilation.

. Where concentrated CO

streams are present, one should be aware of its

asphyxiating properties and the fact that it is heavier than air. The potential danger is

not only because of leaks and open valves. Also, the gas in the stacks through which

the CO

is vented should have sufficient buoyancy by ensuring elevated tempera-

tures. For all large quantities, dispersion calculations should be made.

9.3.5 Oxygen

Oxygen makes up about 21% of our atmosphere and is essential to life. It is also an

essential ingredient for combustion in which fuels are oxidized in an extremely

exothermic reaction. If oxygen is present in concentrations significantly above 21%,

then the combustion becomes much more vigorous, and materials such as metals

that normally oxidize in a slow manner without fire risk (e.g., rusting of iron) can

behave as fuels for fire. When handling oxygen it is therefore essential to take the

necessary precautions to prevent oxygen fires.

The precautions necessary for safe operation of oxygen systems are well codified.

Not only do all the leading industrial gas supply companies and gasification techno-