In pre-combustion de-carbonization, the carbon content of the fuel is
removed prior to combustion in order to produce a hydrogen rich fuel and a CO2 by-product stream. The concept can be used for both H2 production and electricity generation.
In the first step a synthesis gas has to be produced consisting mainly of CO and H2. When coal is used as the fuel, it is first gasified. Synthesis gas can also be produced from natural gas through steam reforming or partial
oxidation. The CO is then further reacted with steam in a catalytic reactor according to the exothermal water-shift reaction to form more H2 and CO2: CO + H2O CO2 + H2 + 41 kJ/mol
After the shift reaction and removal of condensate, the process gas consists mainly of CO2 and H2. As the resulting CO2 concentration of around 30 % volume fraction is much higher than in a flue gas, the energy effort for CO2
separation is much lower. The partial pressure of the CO2 in this case is significantly higher than in the post-combustion case since the process is pressurized (20-30 bar) in addition to the higher CO2 concentration. The most appropriate H2/CO2 separation process for these conditions is currently physical absorption for CO2 removal. The H2-rich fuel can thereafter be used in a gas turbine combined cycle to produce electricity. In future it will also be possible to extract the H2 from the shifted gas by membranes, leaving the remaining CO2 rich stream to be sent to storage. An IGCC scheme with
pre-combustion decarbonisation including methanol synthesis is shown in Figure 2-4.
Methanol synthesis CO2
(optional) (optional) external H2
Power Heat
Methanol
Figure 2-4 IGCC with pre-combustion decarbonisation 2.4.2 Components and special considerations
In principle, the individual components of the pre-combustion capture concept have been successfully used in the industry for many years.
However, it still remains to be seen if this technology can be applied to power plants with acceptable reliability and availability in parallel with economic operation.
Coal gasification
Coal has been gasified in industrial scale for many years. Principally as the Lurgi moving bed, the Lurgi-British Gas slagging gasifier, the High
Temperature Winkler gasifier, Koppers-Tozek, Texaco and Shell with all being very well established for a multitude of industrial purposes at
atmospheric pressure. Integration in an IGCC scheme requires pressurized operation and intensive gas cleaning.
Natural gas reforming or partial oxidation
For synthesis gas production, natural gas can be reformed at a temperature of around 850°C with the addition of water steam and heat. The heat has to be either supplied by heat exchangers or by internal partial oxidation
following the addition of oxygen. If the reforming process is externally heated, a higher H2 concentration in the syngas can be attained, although this is not necessary. In addition, in a CO2 emission free process, a proportion of the decarbonized fuel is burnt to supply heat and this would have first undergone all of the fuel conversion steps with associated exergy losses. Therefore, direct internal oxidation is to be preferred to avoid these exergy losses, giving much lower efficiency penalties. Both reforming and internal oxidation are well proven commercial processes.
CO Shift (Water gas reaction)
The homogeneous water gas shift reaction (CO shift) is used in the chemical industries to adjust the hydrogen content of synthesis gases at reaction temperatures between 180°C and 500°C in catalytic reactors. By using a two stage catalytic CO shift reactor, a high CO conversion rate can be attained with the addition of steam. Since this is an exothermic reaction, the fuel energy content is reduced and gives rise to an efficiency loss, although this can be mitigated using an energy recovery scheme to preheat the steam.
A further development would be to use ceramic membrane reactors in which the CO shift reaction can be combined with H2 extraction, thereby reducing the additional steam requirement to give a high CO conversion rate. This development would also reduce the efficiency losses due to the CO shift.
Physical CO2 absorption
Physical absorption is used for CO2 separation for pressurised gases, e.g. for synthesis gases and natural gas. The process operates at temperatures of
< 60°C and pressures up to 160 bar. Methanol, n-methyl-2 pyrrolidon (NMP), dimethyl-ether-polyethylene-glycol (DMPEG) and propylene-carbonate are used as absorbents. For regeneration, the solvent is expanded to low pressure at which the CO2 is released. Main internal consumption has to be spent for solvent circulation and eventually refrigeration. The process allows high levels of separation with high CO2 purities. In the case of IGCC with CO shift, the CO2 separation with physical absorption only makes a small
contribution to the additional energy consumption.
CO2 separation by physical absorption is an industrial method for certain chemical processes.
The removal of CO2 simultaneously reduces the volume flow through the turbine and thus causes a power reduction.
H2-separation membranes
An efficient separation process demands high membrane selectivity, a reasonable size of the membrane surface and also compression of the total gas flow. The highest selectivities can be achieved by separating the smallest molecules such as hydrogen. Therefore membrane separation is best suited to separating hydrogen from the gas mixture and retaining CO2. Polymer membranes are generally appropriate for a high mass permeability of H2 if the gas temperature is below 100°C. At higher temperatures, ceramic membranes can be used, although these have the problem of low selectivity.
Apart from the quality of the membrane, which depends on permeability and selectivity, other process parameters, in particular the pressure, determine the gas separation efficiency.
Membranes for specific power plant requirements, such as corrosion resistance and separation behaviour, are still in the technical development stage. A comparison of the membrane processes for separating CO2 from waste gases and the production of carbon-free fuel is shown in Table 2-2.
CO2 separation from waste gases (N2/CO2
-separation) H2/CO2 separation (pre-combustion separation, IGCC)
Development stage
Because of the low selectivity of the membranes, no major technical potential can be foreseen for separating CO2 from waste gases.
The H2 separation from synthesis gases using polymer membranes has reached an advanced research stage.
Membranes for specific power plant requirements, such as corrosion resistance and separation behaviour, for example, are in the technical
separation from waste gases; from 0.78 to 0.51 kg/kWh)
Reduction of CO2 emissions from pressurised gases by approximately 75 % (IGCC process; from 0.63 kg/kWh to 0.16 kg/kWh)
Efficiency of the Process
With high levels of separation and high CO2
purities at the same time, the energy consumption for compressing the waste gas is extremely high.
The efficiency is about the same level as when the absorption process is used.
Advantages
There are no evident advantages compared with absorption technology.
Disadvantages
The process requires high pressure.
The selectivity between N2 and CO2 that can be achieved is too small.
The process is more suited for the separation of low molecular gases, such as H2 for example.
The remaining carbon-rich retentate still has a considerable calorific value and should be burned separately with the addition of oxygen.
Polymer membranes are expensive. Ceramic membranes only have a low selectivity.
Table 2-2 Comparison of the membrane processes for separating CO2 from waste gases and the production of a carbon-free fuel
Gas turbine combustor for H2 combustion
The major remaining technical development in the power train, aside from the gasifier and the syngas train optimization, is to modify the gas turbine
combustor to accommodate hydrogen rich fuel. H2 has different flame properties than conventional gas turbine fuels. In particular, flame speed is higher than for natural gas which may preclude the use of a lean premix concept for NOx control.
Methanol production
Apart from exporting hydrogen as a chemical base material or fuel, methanol or other chemicals can be synthesized from the produced hydrogen. An integration of such a methanol plant in an IGCC scheme is also shown schematically in Figure 2-4.
IGCC development
Since the IGCC concept was only feasible when highly efficient and
economic combined cycles had emerged, its development does not have a long history. For example, in Europe, there have been only few IGCC demonstration projects to date (e.g., 170 MWe Kellermann IGCC, Lünen, Germany 1969-1977; 250 MWe Buggenum IGCC, NL since 1993, efficiency 43 %; 300 MWe Puertollano IGCC, Spain 1997, efficiency 45 %; 500 MWe ISAB SpA refinery IGCC, Italy 1997).
U.S. IGCC plants with state-of-the-art technology are called
'Second-Generation'-IGCC (93 MWe Cool Water is considered as 'First-Generation' in 1986 at an efficiency of 31 %). The intention is to demonstrate 40 - 45 % (HHV) for green-field plants and 36 - 40 % (HHV) for retrofit plants before 2000. In the long-term, R&D programs funded by the US-DOE are aimed at developing the 'Third-Generation'-IGCC, due to be commercially available before 2010.
Tracking of the developments from the Buggenum IGCC towards the Puertollano IGCC shows that there is rapid progress with each new IGCC plant. Studies even predict efficiencies of up to 51.7 %, with current gas turbine technology, at a competitive investment (European Commission, 1998; Baumann (“IGCC...”), 1998).
However, with limited operational experience, IGCC systems have not yet demonstrated sufficient availability which has impeded a commercial break through. The reasons for the failure are manifold. The process complexity and the efforts to achieve high efficiency have led to a very integrated and complicated design. This has resulted in poor availability and high cost. The trade-off between efficiency and complexity of design is a little different between the European units and the American ones but neither has promised a successful commercial continuation due, in large part, to the small number of projects which has led to limited operating experience and little opportunity to develop operational improvements. Whilst there is still a large learning curve to be tackled in relation to gasifier slagging, raw gas heat recovery and gas turbine combustion, there is still a large development
potential for this young technology if a higher availability could be proven in further demonstration projects.
2.4.3 Technology status and R&D needs
For over 50 years, H2 has been produced using gasification or reforming and the water-shift reaction for production of chemicals and fertilisers. For power generation IGCC power plants are considered to be clean and efficient options for utilising coal. However, although demonstrated at a commercial scale, they have not had their commercial break through, for reasons
described above. Confidence has yet to be gained from technology
development and capital costs are greater than for other currently available options.
However, the CO2 separation process per se (absorption through physically active solvents) is a technique frequently practised in industry. In an
industrial scale demonstration plant belonging to Rheinbraun, positive experience has been gained over a number of years with HTW
(Hochtemperatur Winkler) gasifiers with downstream CO shift and CO2
separation with reprocessing of the synthesis gas to methanol. Therefore the technical feasibility of the process is proven but, up to now, availability has mainly been dictated by the coal gasification process.
Table 2.3 shows the data for an IGCC plant with CO2 removal based on the gas turbine technology available in 1998. The base power plant, with a Siemens V94.3A and a PRENFLO gasification process, was the result of a development study based on the Puertollano IGCC and a predicted final efficiency of 51.7 % (European Commission, 1998).
IGCC, state of 1995 IGCC '98
reference case with CO2
removal reference case Gross power output gas turbine
(V94.3A) 238.8 MW 234.1 MW 301.4MW 277.1MW
Table 2-3 Salient data of IGCC with CO2 removal compared to the reference case (Pruschek et al., 1998)
However when CO2 is assigned a value (or a penalty) the capture of CO2, which in principle is easier in a gasification concept, will perhaps make IGCC more competitive.
It is however anticipated that the present gasification concept, which is
optimized to give as high a generating efficiency as possible for the produced gas, will evolve into a concept where syngas is the preferred product. This requires a different gasification train but the technical solutions are well established. The question remains, can the concept become commercially competitive and the reliability and flexibility improved to fulfill the needs of a base load power plant?
R&D needs
• Improved availability of gasifier island
• Catalyst for shift reaction
• Integration of air separation unit
• Novel methods for air separation (high temperature ceramic membranes)
• Improved solvents for physical absorption
• Novel methods for CO2/H2 separation (membrane, both ceramic and polymer)
• Gas turbine modified for combustion of H2-rich fuel (including prevention of NOx-formation)
2.5 O2/CO2 recycle combustion (Oxyfuel combustion)