Dr. Michael Heisel, Dr. Paul Kummann,
Linde AG, Germany
UBE Industries, Japan
The gasification of refinery residues in IGCC plants is becoming an increasingly viable option for refineries, especially as power markets deregulate. Yet IGCC is still a relatively new technology whose economics could be further improved.
Integrated gasification combined cycle (IGCC) is becoming an increasingly popular option for refineries because it helps to solve the problem of residues. Environmental legislation now dictates that levels of sulphur in fuels used for power generation and other applications be kept low. This means that refineries must increase the levels of desulphurization, and the resulting high sulphur residues left behind are difficult to sell and dispose of.
Gasification is an appealing option for overcoming this problem as:
- Gasification produces hydrogen (H2) that can be used in the desulphurization process.
- The gasification gas, which contains H2 and carbon monoxide (CO) can be used as a synthesis gas (syngas) for methanol synthesis.
- An IGCC plant, fuelled by the syngas, can supply the refinery with electricity and steam.
The IGCC option is further enhanced by the liberalization of the power market, which creates incentives for industrial operators such as refineries to become power producers. They can make use of synergetic effects to competitively generate power that can be used on-site or sold into the wholesale market.
However, the economy of this option is strongly influenced by the gas cleaning process. Getting the most value out of a gasifier feed by properly choosing the gas purification is therefore essential to successful IGCC operation in a competitive environment.
Figure 1 shows a typical block diagram of an IGCC plant and the integration of gas cleaning, which entails several processes:
LTGC, COS/HCN conversion: The first step in gas cleaning is low temperature gas cooling (LTGC). The inlet gas is typically at 150à‚°C and water saturated. Downstream is the COS/HCN hydrolysis. This step is necessary for two reasons:
- Amine scrubbing processes cannot tolerate HCN other than in trace amounts.
- All conventional scrubbing processes remove only part of the COS. Since typically 5-10 per cent of the total sulphur in the syngas is COS, the sulphur specification in the gas fuelling the gas turbine cannot be met without COS hydrolysis.
Desulphurization: Either chemical wash processes, such as amine scrubbing, or physical wash processes, such as ‘Rectisol’ or ‘Selexol’ can be applied. An amine wash is best suited for low H2S contents of up to 0.1 vol per cent. In refineries, however, gasification of heavy residues produces a gas containing usually more than 1 vol per cent of H2S. In such highly concentrated streams, physical scrubbing is the best option.
The desulphurization process concentrates the H2S for use in a Claus plant to recover sulphur.
Sulphur recovery: The work horse for sulphur recovery is the Claus process. For reliable operation it requires a stable flame in the Claus furnace which can be achieved only if the H2S content in the acid gas is more than 30 vol per cent. With oxygen used in the Claus furnace, rather than air, the H2S concentration may be as low as approximately 20 vol per cent. For even lower acid gas concentration, direct oxidation processes are applicable, such as the ‘Clinsulf-Do’ process. All these processes recover 90 to 97 per cent sulphur. If that is not sufficient to meet environmental protection regulations, a tail gas treatment has to follow downstream.
IGCC is still a new technology. Therefore not all the process steps typically chosen to purify the fuel gas from the gasifier are suitable – some process steps are just transferred from other applications. The different process steps have an impact on the overall economy of the process, and so process selection is important.
In the gas cleaning section, energy losses will affect IGCC economics (see Figure 2).
COS/HCN hydrolysis: Fuel gas from gas cooling is cooled in E1 raising low pressure (LP) steam. To avoid pore condensation of liquid water, the gas is reheated in E2 by approximately 20-30à‚°C against medium pressure (MP) steam. The reheated gas enters the catalytic hydrolysis reactor R1 where most of the COS is converted to H2S and HCN decomposed. In E3 the gas is further cooled raising LP steam.
The COS/HCN hydrolysis consists of two heat exchangers and one catalytic reactor. It is a very simple process, but can cause a number of problems:
- The catalyst must be operated 20-30à‚°C above the water dew point to avoid condensation of water in the catalyst pores. This means inlet gas has to be reheated from 150à‚°C to 180à‚°C using MP steam. This reduces overall economy.
- The gas still contains some catalyst poisons, such as HCl, which reduces the service life of the catalyst.
- The pressure drop in LTGC adds up to typically 2.5 bar. This is lost energy.
Overall, the hydrolysis step adds to operating and maintenance costs and reduces availability of the gas cleaning system.
Desulphurization scrubber: The operating cost of the scrubbing step is substantial. Three major effects contribute to it:
- Removal of water vapour, CO2 plus some H2 and CO from the process gas constitutes a loss of product.
- Consumption of utilities such as steam for regeneration, electric power for pumps, and consumption of make-up solvent.
- Energy loss.
The loss of gas components in particular reduces the efficiency of an IGCC plant. The scrubber removes H2S, but at the same time it also removes CO2, H2 and CO which all should remain in the product gas.
H2S has to be removed to meet both the requirements of environmental law and of the gas turbine. Virtually 100 per cent removal must be achieved.
Reliable control of the flame temperature is of high importance in a power plant. A higher temperature means higher efficiency, and therefore the flame temperature should be as high as the turbine blades allow. But temperature moderation is mandatory to avoid thermal damage to the turbine.
The heat capacity of CO2 is approximately 50 per cent higher than that of air. Furthermore the CO2 is pressurized and can be expanded for energy generation, while air has to be compressed for the purpose of consuming energy.
Unfortunately most of the H2S removal technologies presently available have been developed for other applications where the selectivity between H2S and CO2 removal is not of such high priority as in IGCC. The result is that quite substantial percentages of the CO2 are removed in the H2S scrubber.
Part of the H2 and CO is removed in the desulphurization scrubber even though their solubility is low in most solvents. Typically the removal is in the range of 0.1-0.5 per cent depending on total pressure, type of solvent and scrubber temperature. All the H2 and CO removed appears in the acid gas to the sulphur recovery unit where they are also used to generate steam. Therefore only minor energy losses result.
Sulphur recovery unit: The Claus process converts toxic sulphur compounds to harmless elemental sulphur. The heat of reaction of this conversion is used to raise steam and contributes to the efficiency of the power plant. The Claus tail gas treatment, however, is a different story. Two basic types are presently applied:
- Hydrogenation of the Claus tail gas to convert all the sulphur species, such as SO2, COS and sulphur vapour to H2S, and recompression to the desulphurization scrubber. The recompression consumes a lot of power, but since the recycled gas contributes to power generation, not all this power is lost.
- Conventional tail gas treatments and release of the purified gas to the atmosphere. Alternatively, all the Claus tail gas treatment processes may be applied, increasing the sulphur recovery rate to the desired level.
These tail gas treatment processes save the power required for recompression. But in exchange the off-gas cannot generate power. Therefore the efficiencies of both routes are similar.
Options to optimize
The requirements for an ideal gas cleaning section in an IGCC plant are:
- It contains no COS/HCN hydrolysis.
- The desulphurization scrubber is highly selective between H2S and CO2, i.e. leaves most CO2 in the purified gas while scrubbing off H2S to the trace level.
- The high selectivity leads to an acid gas fraction to the Claus plant that is highly concentrated, so that the lower operability limit of minimum 20 vol per cent H2S is safely avoided.
A scrubber which comes close to these requirements is the novel ‘Polar-1′ process developed especially for the priorities in an IGCC environment. Polar-1 is a physical scrubbing process using an organic solvent. It has been tested extensively in a pilot plant for about four years at UBE Industries’ ammonia plant, downstream of a Texaco coal gasifier.
Polar-1’s flow scheme is the same as for Selexol, shown in Figure 3. However, compared to Selexol, the Polar-1 solvent removes only about half as much CO2, i.e. it is much more selective between H2S and CO2. And Polar-1 can convert and scrub off COS so that the catalytic hydrolysis step can be omitted. These are important
features because they allow a simpler process configuration as shown in Figure 4.
The effects on the IGCC economy when using Polar-1 rather than Selexol are listed in Table 1 and include:
Power plant: The difference between Polar-1 and the glyme scrubber in power generation results from the different removal of gases. Polar-1 leaves more H2 and CO in the fuel gas. Polar-1 also leaves more CO2 in the gas so that less air for moderation of the flame temperature is required. The difference is higher power generation.
The higher energy content of the purified gas from Polar-1 allows more steam to be generated on all levels and more heated boiler feed water. This energy can be utilized in the combined cycle section of the power plant, increasing the annual value of power generation.
Scrubber: The operating cost of the scrubbers includes the pumping and regeneration energies. Not included is the solvent make-up because it depends on so many parameters that are hard to quantify. The pumping and regeneration energies for both scrubbers, Polar-1 and glyme are similar.
COS hydrolysis: For Polar-1 this step is not needed. This increases the difference in the annual value of the power generated.
Claus plant and Claus tail gas treatment: The Claus plant receives acid gas from the scrubber regeneration. Since Polar-1 is more selective, its acid gas fraction is richer in H2S than in the glyme scrubber case. In the example case the H2S content is 57.0 per cent versus 36.6 per cent for the glyme scrubber. That means the Claus plant downstream glyme has to be designed for more inert gas throughput.
When comparing Claus plants downstream of Polar-1 and glyme, there is less tail gas from the Polar-1 Claus. In the example it is 70.2 mol/s versus 109.4. When hydrogenating and recompressing the tail gas there is a substantial difference in compression energy. The plant therefore has to treat about 40 per cent less tail gas in the case of Polar-1 compared to glyme. That means less capital and operating costs.
Capital cost: To find the total cost one has to combine operating and capital cost. While the operating cost is continuous, capital cost is a one-time expenditure. Therefore a depreciation time of five years was assumed. The investment cost for the process steps was calculated and resulted in the figures listed in Table 1.
The delta % row demonstrates the difference in net cash flow between an IGCC with Polar-1 and the glyme scrubber. The difference resulting from operating cost is 0.86 per cent. The capital cost for the scrubber reduces the difference slightly in the example from 0.86 per cent to 0.82 per cent, the COS hydrolysis adds a substantial 0.69 per cent, and the Claus plant increases this by 0.63 per cent to 2.13 per cent overall difference.
Since the typical overall efficiency of an IGCC plant with quench mode gasifier is presently about 42 per cent, an improvement of the annual revenue by 2.13 per cent resulting from Polar-1 is commercially equivalent to an increase of the thermal efficiency from 42 per cent to 42.9 per cent.
IGCC is still a new concept and the process units need to be adjusted. State-of-the-art processes have been transferred from other applications to IGCC.
Processes especially developed for IGCC have proved to be superior to transferred processes, both economically and in terms of efficiency. Simply by replacing the solvent of an IGCC desulphurization scrubber, the gas cleaning section can increase the economic performance of an IGCC power plant by 2.13 per cent.
The increase is coupled with a decrease in capital cost, as a number of process steps can either be decreased in size or omitted entirely. These savings amount to about half the scrubber cost: whatever is not there, cannot go wrong, needs no maintenance, no repair and no supervision from the control room.
The only problem with these new processes is that they cannot yet look back on as many years of compounded operating experience as their predecessors.