Higman Chris Gasification (Газификация угля)

Подождите немного. Документ загружается.

130

Gasification

Process Description

The oil feedstock is mixed with the moderating steam and preheated in a fired

heater. The Texaco burner (Figure 5-24) is of a water-cooled design in which steam

and oil are fed together through an annular slit surrounding the central oxygen pipe.

The process steam is used to atomize the oil, and mixing is ensured by imparting a

counter-rotating vortex motion to the two streams (Pelofsky 1977; Brejc 1989).

The reactor itself is an empty, refractory-lined vessel. The soot make is 1–2wt%

based on feed flow (Appl 1999).

Syngas Cooling

Texaco offers two different syngas cooling options: one by direct quenching with

water, and another by using a syngas cooler to generate steam (see Figure 5-25).

In the quench mode the hot, raw syngas leaves the bottom of the reactor via a dip-

tube into the quench section. The quenched syngas is saturated with water and

leaves the quench section with a temperature of about 250°C. At an operating pres-

sure of, say, 80 bar, this corresponds to water loading in the gas of about 2 kg H

per Nm

of gas. This high water loading makes the quenched gas suitable for CO

shift conversion without further steam addition. The quench mode of syngas cooling

is, therefore, Texaco’s preferred mode for hydrogen and ammonia manufacture.

The quench removes the bulk of the solids in the gas, and these are extracted from

the quench vessel as a soot-water slurry or “black water.”

Texaco usually uses the syngas cooler mode in applications where a high CO con-

tent is required (e.g., oxo synthesis gas) and where the high steam loading of a

quenched gas is of no advantage. For intermediate requirements in the H

/CO ratio,

such as methanol synthesis gas, a combination of quench and waste-heat boiler cool-

ing is possible (Jungfer 1985).

COOLING COILS

FEED ORIFICE

FEED & STEAM

COOLING

WATER

Figure 5-24.

Figure 5-24.Figure 5-24.

Figure 5-24. Texaco Oil Burner (With permission: ChevronTexaco)

Gasification Processes

131

Carbon Removal

Following the flowsheet in Figure 5-26, which shows the quench configuration, the

gas leaves the quench vessel and is then scrubbed with water twice, first in a Venturi

scrubber and then in a packed column, to remove final traces of soot. The raw gas

is then suitable for subsequent treatment in downstream units, such as CO shift and

acid gas removal.

OXYGEN

SOOT

QUENCH

WATER

RAW

SYNGAS

FEED/

MODERATOR

OXYGEN

FEED/

MODERATOR

RAW

SYNGAS

BFW

SATURATED

STEAM

Figure 5-25.

Figure 5-25.Figure 5-25.

Figure 5-25. Texaco Reactors with Quench Cooling and Syngas Cooler (With

permission: ChevronTexaco)

FLARE

SEPARATOR

C.W.

NAPHTHA

BFW

CONDENSATE

VENTURI

SCRUBBER

DECANTER

SOOT

WATER

STEAM

RESIDUE

FEED

GASIFIER

OXYGEN

DEGASIFIER

SCRUBBER

RAW

SYNGAS

NAPHTHA,

S, CO

C.W.

OIL

SOOT OIL

FUEL OIL

NAPHTHA

SEPARATION

COLUMN

Figure 5-26.

Figure 5-26.Figure 5-26.

Figure 5-26. Typical Texaco Oil Gasification Flow Scheme (With permission:

ChevronTexaco)

132

Gasification

Carbon Management

In the Texaco process, soot is extracted from the carbon-water mixture with naphtha

and recycled with the feedstock to the reactor where it is gasified to extinction. The

black water from the quench and the scrubbing section is cooled and contacted with

the naphtha in the decanter. In this vessel the naphtha extracts the soot from the

water leaving much (but not all) of the ash present in the water phase (gray water).

The soot-naphtha mixture is drawn off the top of the decanter and mixed with fresh

feed oil. The naphtha is recovered in a distillation tower and recycled to the

decanter, leaving the soot-oil mixture as a bottoms product for feeding to the gasi-

fier. Traces of naphtha remain in the tower bottoms and are gasified as well. This

naphtha slip has to be made up with fresh naphtha to the system.

The gray water is degassed to recover naphtha and recycled for use in the quench

and scrubbing sections. When operating in quench mode the overall water balance is

negative because of the large amount carried out with the syngas. Nonetheless, a

bleed stream of gray water is bled from the circuit to remove ash. This is necessary

to limit the buildup of ash in the circuit. This is by no means trivial, and a soot-oil

gasifier feed metals content of about ten times that of the fresh feedstock has been

reported. A device was developed that reduced this buildup factor to about 2.5

(Czytko, Gaupp, and Müller 1983).

When operating in the syngas cooler mode there is little water in the raw syngas,

so that the bleed stream is necessary in any case to maintain the water balance.

Equipment Performance

The equipment for the process has proved reliable in service, and in a study on operation

and maintenance aspects of the process, the data in Table 5-10 have been published.

Process Performance

Typical process performance for different feedstocks is shown in Table 5-11.

Table 5-10

Maintenance Intervals for Texaco Oil Gasifier

Component Frequency

Time required for

intervention

Burner every six months 6–10 hrs

Quench every two years 156–180 hrs

Refractory every three years 680–760 hrs

Source: Bressan and Curcio 1997

Gasification Processes

133

5.4.2 The Shell Gasification Process (SGP)

The Shell gasification process (SGP) was developed in Shell’s research center in

Amsterdam during the early 1950s primarily as a means of manufacturing synthesis

gas from fuel oil. The first gasifier, using heavy fuel oil as feedstock, was brought

on stream in 1956.

Some 140–150 units have been installed worldwide with a processing capacity of

some 7 million t/y of residue. One typical reference plant processes about 240,000

t/y of residues of varying quality, which are bought on the open market, for the

production of ammonia. Another, which was started up in 1972, produces a mixed

product slate of ammonia, methanol, and hydrogen and is fed with about 350,000 t/y

residue directly out of a visbreaker. An interesting reference includes a reduction

Table 5-11

Performance Data for the Texaco Oil Gasification Process

Feedstock Type

Natural

Gas Naphtha

Heavy

Fuel Oil

Tar (from

Bituminous

Coal)

Feedstock composition

C, wt% 73.41 83.8 87.2 88.1

H, wt% 22.8 16.2 9.9 5.7

O, wt% 0.8 0.8 4.4

N, wt% 3.0 0.7 0.9

S, wt% 1.4 0.8

Ash, wt% 0.1

Raw gas composition

Product gas (25 bar, quench)

Carbon Dioxide, mol% 2.6 2.7 5.7 5.7

Carbon Monoxide, mol% 35.0 45.3 47.4 54.3

Hydrogen, mol% 61.1 51.2 45.8 38.9

Methane, mol% 0.3 0.7 0.5 0.1

Nitrogen +Argon, mol% 1.0 0.1 0.3 0.8

Hydrogen Sulfide, mol% 0.3 0.2

Soot, kg /1000 Nm

1.8 10 6.1

Consumption figures per

1000 Nm

CO + H

Feedstock, kg 262 297 323 356

Oxygen, Nm

248 239 240 243

Steam, kg 74 148 186

With permission: ChevronTexaco

134

Gasification

gas plant for nickel furnaces, one of the few air-blown units in commercial opera-

tion. Operating capability covers pressures up to about 65 bar and unit reactor sizes

up to 1.8 million Nm

/d syngas capacity.

Process Description

The noncatalytic partial oxidation of hydrocarbons by the Shell gasification process

(Figure 5-28) takes place in a refractory-lined reactor (Figure 5-27) that is fitted

with a specially designed burner. The oxidant is preheated and mixed with steam

prior to being fed to the burner. The burner and reactor geometry are so designed

that this mixture of oxidant and steam is intimately mixed with the preheated feed-

stock. Originally, a pressure atomizing burner was used, but during the mid-1980s

an improved co-annular design using blast atomizing was developed. This burner is

capable of handling residues of up to 300 cSt at the burner (Weigner et al. 2002).

Waste Heat Recovery

The product of the partial oxidation reaction is a raw synthesis gas at a temperature

of about 1300°C that contains particles of residual carbon and ash. The recovery of

the sensible heat in this gas is an integral feature of the SGP process.

Primary heat recovery takes place in a syngas cooler generating high-pressure steam

(up to 120 bar) steam in which the reactor effluent is cooled to about 340°C. The

syngas cooler is of a Shell proprietary design discussed in more detail in Section 6.6.

Secondary heat recovery takes place in a boiler feed-water economizer immedi-

ately downstream of the syngas cooler.

Carbon Removal

The partial-oxidation reactor-outlet gas contains a small amount of free carbon. The

carbon particles are removed from the gas together with the ash in a two-stage water

wash. The carbon formed in the partial oxidation reactor is removed from the system

as a carbon slurry together with the ash and the process condensate. This slurry is

subsequently processed in the ash-removal unit described in the following. The product

syngas leaves the scrubber with a temperature of about 40°C and is essentially free of

carbon. It is then suitable for treatment with any commercial desulfurization solvent.

Carbon Management

Over the course of its development SGP has gone through three distinct stages in its

approach to management of the carbon produced in the gasification section.

The early plants were equipped with the

Shell Pelletizing System

, an extraction pro-

cess using fuel oil as extraction medium. The fuel oil was put in contact with the car-

bon slurry in the pelletizer where carbon pellets of about 5–8mm were formed leaving

a clear water phase. These pellets were separated from the water on a vibrating screen.

Gasification Processes

135

Figure 5-27.

Figure 5-27.Figure 5-27.

Figure 5-27. Shell Reactor and Syngas Cooler (Source: de Graaf et al. 2000; With

permission: Shell)

136

Gasification

The pellets could be burned directly or mixed in with fuel oil to make a liquid fuel

known as carbon oil. The carbon oil could in part be used as feedstock for the gasifier,

thus providing partial recycle of the carbon. This process had the advantage of being

cheap and simple to operate. However, in the extraction process with fuel oil, the sep-

aration of soot from the heavy metals (vanadium and nickel) from the gasifier feed-

stock was poor so that any attempt at 100% carbon recycle brought an unacceptable

buildup of metals in the system. Furthermore, there was some water slip with the pel-

lets in the carbon oil, so the carbon oil mixing process could not be operated above

100°C without causing foaming. This limitation meant that this process became unus-

able with the increasingly heavier feedstocks appearing on the market.

The next development was therefore to substitute the fuel oil with naphtha as

extraction medium. This development was known as the

Naphtha Soot Carbon

Recovery

process. The principle of extraction in a mixer to increase the size of the

agglomerates as well as mechanical sieving was maintained so as to achieve a low

naphtha/slurry ratio. The equipment was now operated under pressure, however.

The naphtha-soot pellets are mixed with the main feedstock at whatever temperature

is required to achieve the desired viscosity. The naphtha is then distilled off from the

feed and recycled to the extraction stage leaving the soot behind in the feed (Brejc

1989). The use of naphtha as an intermediate allows the use of heavier, more viscous

feedstocks than in the case of pelletizing with fuel oil. Also, an improvement in the

separation between carbon and ash allows 100% carbon recycle. Nonetheless, an ash

buildup factor of about 3:1 can be observed under 100% recycle conditions. These

improvements are bought, however, at a cost in investment and operating expense.

Furthermore, the ash buildup still places a limit on ash content in the feedstock.

SUPERHEATED

STEAM

SOOT

SCRUBBER

SOOT

QUENCH

SYNGAS

EFFLUENT

COOLER

OXYGEN

HEATER

OXYGEN

GASIFIER

SYNGAS

PRODUCT

FEED

PUMP

RESIDUE STEAM

SOOT

SEPARATOR

HP BFW

TO AND FROM

SOOT SLURRY

PROCESSING

FEED

VESSEL

Figure 5-28.

Figure 5-28.Figure 5-28.

Figure 5-28. Residual Oil-Based SGP Units (Source: de Graaf and Magri 2002;

With permission: Shell)

Gasification Processes

137

The third generation of soot management now employed by Shell is based on

filtration of the carbon slurry and subsequent handling of the soot-ash filter cake and

goes under the name of

Soot-Ash Removal Unit

(SARU; Figure 5-29). The carbon

slurry leaves the SGP under pressure at a temperature of some 125°C and is flashed

into an intermediate slurry storage tank at atmospheric pressure. Thence it is cooled

before water and filtrate are separated in a membrane filter press. The clear filtrate is

mostly recycled to the SGP scrubber as wash water. The overall water balance

produces a surplus, however, which is treated in a sour water stripper to remove

dissolved gases such as H

S, HCN, and ammonia before being sent to a biotreater.

The filter cake contains typically about 75–85% moisture, but nonetheless

behaves for most purposes as a solid. It is then subjected to thermal treatment in a

multiple hearth furnace (Figure 5-30). The carbon is burnt off under conditions that

prevent the formation of liquid vanadium pentoxide, which has a melting point at

about 700°C. In this type of furnace, which is used extensively in the vanadium

industry, the filter cake is fed from the top of the furnace in counter-current to the

combustion air/flue gas. Rakes, mounted to the central air-cooled shaft, rotate slowly

drawing the solid material to downcomers, which are located on alternate hearths at

the center and the periphery of the furnace. In the upper hearths the rising flue gas

dries the filter cake. In the lower hearths the filter cake is gently burnt off. The

bottom product has less than 2 wt% carbon and, depending on the metals in the SGP

feedstock, can contain typically 75% V

. The soot combustion is under the prevail-

ing conditions not quite complete, so that the off-gas contains not only the water

vapor from the moisture in the filter cake but also carbon monoxide. In addition it

contains traces of H

S contained within the filter cake. This off-gas is incinerated

either as part of the SARU facility or centrally depending on the site infrastructure.

WASTE WATER

STRIPPER

SLURRY

TANK

RETURN WATER

VESSEL

FILTER

MULTIPLE

HEARTH

FURNACE

WASTE

WATER

STRIPPER OFF-

GASTO SRU

MHF OFF-GAS TO

INCINERATOR

SLURRY FLASH

GAS TO SRU

CARBON SLURRY

FROM SGP

RETURN WATER

TO SGP

VANADIUM

CONCENTRATE

Figure 5-29.

Figure 5-29.Figure 5-29.

Figure 5-29. Shell Soot-Ash Removal Unit (SARU) (Source: Higman 1993)

138

Gasification

Equipment Performance

SGP is a reliable process that has been proved in many applications worldwide. This

reliability is based on the use of proven equipment in critical duties. Typical life-

times are listed in Table 5-12 (Higman 1994).

FEED IN OFF-GAS OUT

RAKES

HEARTHS

VANADIUM CONCENTRATE

ROTATING SHAFT

Figure 5-30.

Figure 5-30.Figure 5-30.

Figure 5-30. Multiple Hearth Furnace

Table 5-12

Typical SGP Equipment Lifetimes

Burners (Co-annular Type)

• Inspection intervals ~4000 hrs

• Repair intervals 8000–12,000 hrs

Refractory

• dome repairs ~16,000 hrs

• wall 20,000–40,000 hrs

Syngas Cooler

• coil inlet section ~60,000 hrs

Thermocouples

• replacement intervals 2500–8000 hrs

Source: Higman 1994

Gasification Processes

139

SGP employs a sophisticated automatic start-up and shutdown system. Since But-

zert’s description of the main characteristics (Butzert 1976), further developments

include, for example, automated reactor heat-up and a system for minimizing flaring

of sulfur-containing gases during start-up.

Process Performance

Table 5-13 provides some information on typical process performance with differ-

ent feedstocks.

Table 5-13

SGP Process Performance with Different Feedstocks

Feedstock Type Natural Gas

Heavy

Fuel Oil

Vacuum Flash

Cracked Residue

Feedstock properties

Specific gravity (15/4) 0.99 1.10

C/H ratio, wt. 3.17 7.90 9.50

Sulfur, %wt 3.50 4.50

Ash, %wt 0.10 0.15

Feedstock preheat, °C 400 290 290

Oxygen, (t, 99:5%, 260°C) 1154 1103 954

Process steam, t(380°C) – 350 350

Naphtha, t – 4 4

Product gas (40°C, 56 bar, dry)

Carbon Dioxide, mol% 1.71 2.75 2.30

Carbon Monoxide, mol% 34.89 49.52 52.27

Hydrogen, mol% 61.40 46.40 43.80

Methane, mol% 1.00 0.30 0.30

Nitrogen +Argon, mol% 1.00 0.23 0.25

Hydrogen Sulfide, mol% – 0.77 1.04

Carbonyl Sulfide, mol% – 0.03 0.04

Quantity, tmol 158 134 128

/CO ratio, mol/mol 1.76 0.95 0.84

Product steam (92 bar sat’d),

gross t 2182 2358 2283

Note: The above data for heavy fuel oil and vacuum flash cracked residue is based on

the use of naphtha soot carbon recovery. When using SARU minor changes will be

observed.