Flue Gas Treatment
The loss of efficiency involved in cycling of gas temperatures between hot and cold parts of an IGCC have been pointed out on many occasions, and has been one of the principle driving forces behind the so far unsuccessful attempts at a hot, or at least warm, fuel gas clean-up. All current development efforts are based on performing all the gas clean up on the fuel gas side of the gas turbine, not least because many of these techniques are available from chemical applications. In this section we wish to review the possibilities for reducing the fuel gas treatment to the absolute minimum required by the gas turbine—which after all can operate on (sulfur-containing) fuel oil—and perform the rest of the gas clean-up as flue gas treatment as in the rest of the power industry.
The ideal process for power generation from fossil fuels using combustion would feature a steady rise followed by a steady drop in temperature and pressure in such a way that little heat and pressure energy is wasted. An open Joule cycle with heat recuperation comes close to this ideal. A conventional IGCC is, however, very far from this situation as, on the one hand, part of the gas stream has to be cooled to -190°C in the ASU, and on the other hand, the gas leaving the high temperature gasifier has to be cooled for desulfurization before being heated for the second time in the gas turbine combustor.
Figure 7-25 shows the temperature profile as encountered in a conventional IGCC with fuel gas treatment (front profile) and in an IGCC with flue gas treatment for an entrained-flow bed gasifier (middle profile). For comparison, an air-blown fluid-bed gasifier with flue gas treatment is also shown (back profile). The temperature scale is logarithmic, because it reflects somewhat better the thermodynamic repercussions of the temperature cycling, since the ratios between the various temperatures are more important than the absolute temperature differences.
Each kink in the diagram refers to the process unit mentioned along the abscissa. Straight lines between kinks imply that the units in between are not present. It is clear that flue gas treating gives a temperature pattern with fewer temperature swings. It should be noted, however, that the cryogenic temperature applies only to the air going to the ASU, whereas the high gas inlet temperature of the turbine applies to a gas mass flow that is about a factor 5 higher.
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Temperature profiles for gas in IGCCs Figure 7-25. Temperature Profiles of a Various Types of IGCC Power Stations |
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 H2S 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.
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.
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, C02, have to be removed from the flue gas as well as in terms of extremely low thermal NOx 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 excess air to the burner by recycled fuel gas, which is compressed in the air compressor. 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 temperature 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) x 0.98+436 x 0.30}x 100/803 = 61.1% for the classical combined cycle base case and:
{(764-401)x0.98+440×0.30}x 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 x 100%=41% of that of the
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FUEL Figure 7-26. Flow Scheme Combined Cycle Power Station with Flue Gas Recycle |
base case. Furthermore, the C02 concentration is 9.4 mol % versus 3.9mol% 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 NOx emissions, is for the recycle case only 1640°C and for the base case 2380°C. This will result in an extremely low thermal NOx formation. As this is in the case of natural gas firing, the only source of NOx, this means that then the only gas that may have to be removed is C02, assuming no sulfur is present in the gas.
Low NOx 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.
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 C02 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% C02 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 C02 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 preheated will make the combustion less difficult. It may be expected that not only the thermal NOx formation but also the S03 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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Table 7-13 |
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Efficiencies of Various IGCC Power Stations with and without |
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C02 Removal Facilities |
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Process |
Fuel Gas Treating |
Flue Gas Treating |
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Gasifier |
Without |
With |
Without |
With |
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conditions |
Syngas |
co2 |
co2 |
co2 |
co2 |
|
|
Feed |
(bar/°C) |
cooling |
removal |
removal |
removal |
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 |
64/1500 |
Gas |
48.8 |
43.7 |
49.6 |
46.3 |
|
preheat slurry |
quench |
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|
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 |
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Supercritical steam power plant |
45 |
41.7 |
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Note: Efficiencies based on standardized, idealized conditions of Appendix E. |
• 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 supercritical steam cycle.
When C02 must be removed from the flue gas, an additional complication is introduced. One solution is to shift all the CO to hydrogen and remove the C02 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
CC. This corresponds to a penalty of 2-5% in station efficiency when compared with flue gas treating. However, where C02 has to be removed, more than half of the energy gain for flue gas treating will be lost due to the additional C02 compression required.
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 NOx production can be made extremely low by flue gas recycle or quasi — isothermal compression. The NOx production originating from organic nitrogen in the feed that has been converted into HCN, or NH3, which yield NOx upon combustion is low and may be acceptable in some cases. Research, for example, using CFD may show how the formation of HCN and NH3 during gasification can be reduced. Moreover, it is worth exploring whether the conversion of these compounds into NOx 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 NOx 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 SOx emissions 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 C02 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 unacceptably high concentrations in the flue gas. This is certainly the case for heavy petroleum-based residues.
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 accommodating a flue gas recycle. This will require considerable research and development effort and investment by the manufacturing organizations.