Higman Chris Gasification (Газификация угля)

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Gasification

With flue gas treating instead of fuel gas treating, the sensible heat in the fuel gas,

corresponding to 5–10% of the LHV of the fuel, and the heat of combustion of H

and COS, corresponding to 0.5–1% of the LHV of the fuel gas, can be utilized in the

CC and no COS removal unit is required.

Comparisons of Gas Treating Schemes

We have made some simple comparisons for various configurations so as to investigate

the potential represented by flue gas treatment without, at this stage, the constraint

that all technology must be existent and proven today. All calculations were made

on a consistent basis as described in Appendix E. Before presenting and discussing

the results of these studies, two important aspects need to be discussed, namely the gas

cleaning concept and the effect of flue gas recycle, which are an integral component

of the concept.

Gas Treating

Developing a minimum gas treatment concept for the gas turbine involves removal

of any solid particulate material in the gas and removing any gaseous components

that could become solid under conditions that might be experienced in the turbine or

HRSG. For this reason, particulate removal must take place at a temperature that is

sufficiently low that alkali compounds can be removed as solids and so present no

risk of forming corrosive alkali (hydro-) sulfates. This temperature is about 500°C,

which represents an upper bound for the particulate removal. The lower bound is

governed by the ammonium chloride sublimation temperature and lies at about 280–

300°C. After filtering out the fly ash on which the volatile alkali compounds and

other metal compounds have been deposited (the fly ash acting as a substrate), volatile

sulfur, nitrogen, and arsenic compounds as well as mercury may pass through the

turbine without causing problems. Within this allowable range of 280–500°C it is

preferable to remain close to the upper limit of 500°C for efficiency reasons. Filtering

at a temperature of 500°C is possible with candle filters. Looking purely at the gas

turbine requirements, this represents then the minimum fuel gas cleanup concept. All

other pollutants will require post-combustion removal as in current conventional PC

technologies.

Flue Gas Recycle

The potential of flue gas recycle is a neglected area of cycle design. It has significant

advantages for natural gas-fired gas-turbine–based power generation (including

IGCC) where gaseous components, for example, CO

, have to be removed from the

flue gas as well as in terms of extremely low thermal NO

emissions.

Before discussing its use in syngas applications we will review its effect on a

natural gas-fired combined-cycle plant. The basic concept is to replace most of the

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281

excess air to the burner by recycled fuel gas, which is compressed in the air com-

pressor. A flowsheet is given in Figure 7-26. The mass and energy balances, the gas

compositions, and temperatures and pressures for plants without and with flue gas

recycle are given in Tables 7-11 and 7-12, respectively.

The calculations have been made on basis the 1 kmole of methane fuel, and LHVs

are used throughout. The gas turbine used has a pressure ratio of 32, an inlet tempera-

ture of 1350°C, and an isentropic efficiency of 90%. Neither temperature losses nor

pressure losses have been taken into account. The overall efficiencies are calculated

as follows: it is assumed that 30% of the HRSG duty is converted into power via a

Rankine (steam) cycle, and that there are 2% mechanical losses in the Joule (gas) cycle,

{(794 − 427) × 0.98 + 436 × 0.30}× 100/803 = 61.1% for the classical combined

cycle base case and:

{(764–401) × 0.98 + 440 × 0.30}×100/803 = 60.7% for the cycle with flue gas

recycle.

These figures should, of course, only be used on a comparative basis. What may be

concluded, though, is that the efficiencies are about equal, but that the quantity of

gas to be treated in case of the recycle is only 10.7/25.9 × 100% = 41% of that of the

AIR

FUEL

COMPRESSOR

COMBUSTOR

GAS TURBINE

GENERATOR

RECYCLE GAS

HRSG

CONDENSER

WATER

FLUE GAS

Figure 7-26.

Figure 7-26.Figure 7-26.

Figure 7-26. Flow Scheme Combined Cycle Power Station with Flue Gas Recycle

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Gasification

Table 7-11

Flow Data and Gas Compositions for Methane-Fired Combined Cycle

Flow

Air to

Compr.

Comp.

Duty

Air ex

Compr. Fuel

Gas to

Turbine

Gas ex

Turbine

Duty

HRSG

Duty

Water ex

Scrubber Stack Gas

kg 762 762 16 778 778 27 751 =25.9 kmol

MJ 0 427 427 803 1230 436 794 436 0 0

Temp. °C 25 556 25 1350 534 25 25

Press. bar 1 32 32 32 1 1 1

mol%

0.03 0.03 3.67 3.67 3.88

O 1.19 1.19 8.43 8.43 100 3.15

20.70 20.70 12.66 12.66 13.39

+A 78.08 78.08 75.24 75.24 79.58

100

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283

Table 7-12

Flow Data and Gas Compositions for Methane-Fired Combined Cycle with Recycle of Flue Gas

Flow

Comp.

Duty

Gas ex

Comp. Fuel

Gas to

Turbine

Gas ex

Turbine

Duty

HRSG

Duty

Water ex

Scrubber Stack Gas Gas to Comp.

Air Rec. gas

kg 331 403 734 16 750 750 33 314 =10.7 kmol

MJ 0 0 401 401 803 1204 440 764 440 0 0

Temp. °C 25 25 539 25 1350 551 25 25

Press. bar 1 1 32 32 32 1 1 1

mol%

0.03 9.41 5.13 8.76 8.76 9.41

O 1.19 3.15 2.26 9.82 9.82 100 3.15

20.70 3.51 11.35 3.27 3.27 3.51

+A 78.08 83.93 81.26 78.15 78.15 83.93

100

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Gasification

base case. Furthermore, the CO

concentration is 9.4 mol% versus 3.9 mol% for the

base case. In other words, it brings the concentration of a natural gas-fired unit up to

that of a conventional boiler or furnace. The cold stack gas after a wash is a problem

that has to be solved in all cases having scrubbing/wash facilities in the stack gas.

The gas may also have to be heated for boyancy reasons.

An important additional advantage is that the SAFT, which is a good indicator for

thermal NO

emissions, is for the recycle case only 1640°C and for the base case

2380°C. This will result in an extremely low thermal NO

formation. As this is in

the case of natural gas firing, the only source of NO

, this means that then the only

gas that may have to be removed is CO

, assuming no sulfur is present in the gas.

Low NO

burners are not required, but standard gas turbine burners probably

have to be modified because of the lower oxygen content in the gas. Furthermore,

good mixing of the air and the recycle gas is required.

Neither the compressor nor the turbine itself need modifications, as the gases they

have to cope with are both in quality and quantity not very different from those in

the base case.

Comparison Results

The results of various calculations are shown in Table 7-13, in which efficiencies

are given for IGCC plants with fuel gas treating and with flue gas treating. In both

cases efficiencies with and without CO

removal are given.

Some comparisons were already made in Section 5.3. The following additional

conclusions can be drawn from these data:

• The penalty in efficiency when including 90% CO

removal as part of fuel gas

treatment is 4–5 efficiency points.

• In all cases, flue gas treating could well be a more attractive means for CO

removal than fuel gas treating. In cases where all acid gases can be removed

together from the flue gas and can then be sequestered together, this would mean a

major advantage in terms of efficiency and in terms of process simplification.

• Apart from flue gas recycle over the gas turbine (to the air inlet), attention should

be paid to the fact that the fuel gas to the gas turbine will have a large volume due

to the presence of inerts and because of the preheat. As a result of the inerts, the

gas has a relatively low heating value.

• Due to the flue gas recycle to the air inlet, the air is diluted and has a low oxygen

content. The dilution of both the fuel gas and the air will require special measures

in the combustion chamber. On the other hand, the fact that both gases will be pre-

heated will make the combustion less difficult. It may be expected that not only

the thermal NO

formation but also the SO

formation will be low.

• Many power station operators are already used to flue gas treating.

• Using nitrogen as quench gas or dilution gas in combination with flue gas treating

may not be attractive, as it lowers the concentration of acid gases in the flue gas.

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285

• Flue gas treating with recycle opens the possibility of applying high-efficiency

air-blown fluid-bed gasifiers in power generation schemes because of the relatively

low temperature difference between the gasifier and the high-temperature filtering

step. The combination of fluid-bed gasification and flue gas treating will be only

attractive when the capital costs are low and the efficiency is not lower than that of

most entrained-flow slagging oxygen-blown gasifiers.

• Gasification-based power stations have the potential of about 5 percentage points

better efficiencies than a conventional coal-fired power station featuring a super-

critical steam cycle.

When CO

must be removed from the flue gas, an additional complication is intro-

duced. One solution is to shift all the CO to hydrogen and remove the CO

from the

fuel gas. This removes 7–10% of the LHV of the fuel gas from the CC. Altogether,

fuel gas treating loses between 10 and 25% of the LHV in the raw gas and transfers

it to the steam cycle, which has an efficiency of 40% as opposed to the 60% of the

Table 7-13

Efficiencies of Various IGCC Power Stations with and without

Removal Facilities

Process Fuel Gas Treating Flue Gas Treating

Feed

Gasifier

conditions

(bar/°C)

Syngas

cooling

Without

removal

With

removal

Without

removal

With

removal

Slurry 64/1500 Water

quench

37.8 35.5 43.0 39.7

Slurry 64/1500 Gas

quench

43.6 39.4 43.1 39.8

Extreme

preheat

slurry

64/1500 Gas

quench

48.8 43.7 49.6 46.3

Dry 32/1500 Gas

quench

50.0 44.5 50.6 47.3

Dry 32/1500/1100 Coal

quench

50.9 45.5 51.5 48.2

Dry 32/1100 Water

quench

– – 51.5 48.2

Supercritical steam power plant 45 41.7

Note: Efficiencies based on standardized, idealized conditions of Appendix E.

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Gasification

CC. This corresponds to a penalty of 2–5% in station efficiency when compared with

flue gas treating. However, where CO

has to be removed, more than half of the

energy gain for flue gas treating will be lost due to the additional CO

compression

required.

Additional Observations

Although flue gas treating has advantages, the following should be observed:

• Flue gas treating is only a possible option in power generation schemes. In the

case of syngas production, fuel gas treating is always the way to go.

• Flue gas recycle is mandatory for flue gas treating as otherwise the concentrations

of the components to be removed are too low and the amount of gas to be treated

is too high.

• Thermal NO

production can be made extremely low by flue gas recycle or quasi-

isothermal compression. The NO

production originating from organic nitrogen in

the feed that has been converted into HCN, or NH

, which yield NO

upon com-

bustion is low and may be acceptable in some cases. Research, for example, using

CFD may show how the formation of HCN and NH

during gasification can be

reduced. Moreover, it is worth exploring whether the conversion of these compounds

into NO

can be reduced by lower SAFTs in the gas-turbine combustors. CFD

may help to solve this problem as well.

• Flue gas treating will become easier if there is no NO

to be removed.

• Flue gas treating for sulfur removal is as yet generally not better than 95%, but

this may be acceptable in many cases. It should be kept in mind that the SO

emis-

sions per kWh with 95% removal by stack gas scrubbing of an internationally

traded coal having a sulfur content of 1% is about the same as for fuel gas treating

with a 4% sulfur coal of which 99% of the sulfur is removed by fuel gas treating.

• In case of CO

sequestering, it is important to explore the possibility to remove

and sequester all contaminants together.

• Mercury, arsenic, and antimony are present in coals having a high pyrite/cinnabar

content. To date these compounds can only be removed by fuel gas treating. In

feedstocks with a low pyrite/cinnabar, these compounds may not result in unaccept-

ably high concentrations in the flue gas. This is certainly the case for heavy

petroleum-based residues.

Gas Turbine Improvements

In this section on advanced cycles, we have sketched out a number of possibilities

through which IGCC efficiencies could be improved. It must, however, be stated

that their realization is dependant on changes being made to the design of existing

gas turbines, whether it be in the use of quasi-isothermal compression or accommo-

dating a flue gas recycle. This will require considerable research and development

effort and investment by the manufacturing organizations.

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287

7.3.5 Miscellaneous

Fuel Cells

Another approach that has received a lot of attention is the combination with fuel

cells that can convert the chemical energy in pure hydrogen directly into electricity.

The gas produced by gasification is especially suitable for this purpose, as the main

additional treatment required is a CO shift that will convert all CO in the gas to add-

itional hydrogen. Much development work has still to be done on fuel cells. Several

types of fuel cell are being developed, including solid oxide, molten carbonate,

phosphoric acid, and proton exchange membranes. At this stage of development it

appears that the higher-temperature solid oxide and molten carbonate systems

would best integrate with gasification-based systems for central station power pro-

duction. The problem is that the gas for the fuel cells must be extremely pure. The

target for natural gas is 70% efficiency, but our expectation is that at the time this

can be realized the same efficiency can be reached with more advanced IGCC or

similar cycles.

7.3.6 Energy Storage

Following the fluctuating grid demand for electricity is a problem as old as power

stations. In principle, there are two solutions to cope with this problem: frequent

shutting down and starting up, or storing energy in such a way that the power station

can run continuously while following the demand pattern. In both cases, additional

equipment is required that stands idle for part of the time. Even in the extreme case

that electricity could be stored as such, additional equipment would be required.

When low capital cost power stations with a high efficiency can be built that can

be started up and shut down within minutes, then in most cases no energy storage

would be required. Topping units using only gas turbines and diesel generators are

relatively low cost but have a low efficiency of about 40%. The Tophat cycle

discussed in Section 7.3.3, with an efficiency of about 60% comprising only a gas

turbine, could be a possible candidate in case fast start-up gas turbines such as

aero-derivatives are used. But even in this case it is more advantageous to run the

gas turbine proper continuously and opt for energy storage.

Of the various options for energy storage, such as flywheels, magneto-hydrody-

namic rings, reversible chemical reactions, pressurized air in underground strata,

and hydro, only the latter has become commercially successful. All the other options

appear to have severe drawbacks that make them at least in the short- and medium-

term unlikely candidates to solve the problem of efficient large-scale energy storage.

On a smaller scale as required for IGCC power stations there are a number of options

that are discussed below. These can be divided into the production of intermediate

peak shaving fuels, methanol, and storage of liquid oxygen.

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Gasification

Peak Shaving Fuels

In the past it has been suggested to produce methanol, Fischer-Tropsch liquids, or

dimethyl-ether from synthesis gas during the off-peak hours, and then to use these

clean fuels as additional gas turbine fuels during the peak hours. It should be real-

ized, though, that all these options are capital intensive, and that the “battery” effi-

ciency of all these options is low and at best 70–80%. Moreover, these options

require very pure synthesis gas and hence additional gas-treating facilities and CO

shifting. All these conversion processes mean that the overall efficiency of the fuel

conversion train will be negatively affected.

Methanol

Of these options methanol is still the most attractive, as this product can be made

with an almost 100% conversion of the synthesis gas in a single-stage reactor and

has the lowest heat of reaction and hence the highest conversion efficiency. Fuel-

grade methanol can be used that will reduce the capital cost and increase slightly the

process efficiency. Further, methanol may be reformed into synthesis gas with low-

level heat of 300–350°C that will increase the efficiency of the overall fuel conversion

train. The battery efficiency of methanol is over 80%.

Liquid Oxygen Storage

Some storage of liquid oxygen is always required in IGCC power stations in

order to cope with sudden changes in demand. In order to use the oxygen for

peak shaving, generally a much larger storage capacity is needed. This does

increase the capital cost of the plant, but it has the advantage that the ASU does

not have to be designed for the peak demand but for the average daily demand.

So it is a matter of balancing these two cost items against each other. It should

be mentioned that apart from the additional storage capacity required for liquid

oxygen, means also have to be installed to recuperate the cold generated by

evaporation of the oxygen.

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