Fuel Processing Technology 91 (2010) 934–941

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Fuel Processing Technology

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Modelling of an IGCC plant with carbon capture for 2020

Christian Kunze ⁎, Hartmut SpliethoffInstitute for Energy Systems, TU München, Bolzmannstrasse 15, 85748 Garching, Germany

⁎ Corresponding author. Tel.: +49 89 289 16277; faxE-mail address: kunze@es.mw.tum.de (C. Kunze).

0378-3820/$ – see front matter © 2010 Elsevier B.V. Adoi:10.1016/j.fuproc.2010.02.017

a b s t r a c t

a r t i c l e i n f o

Article history:Received 27 August 2009Received in revised form 20 January 2010Accepted 4 February 2010

Keywords:IGCCGasificationCO2 captureAspen Plus modelling

Currently several industrial scale IGCC – carbon capture demonstration plants are being planned.Thermodynamic simulations are a useful tool to investigate the optimal plant configuration. In order todemonstrate the potential of the next generation of IGCC with CCS a thermodynamic model was developedusing conventional but improved technology. The plant concept was verified and simulated for a generichard coal and lignite. The simulation showed a net efficiency (LHV) of 38.5% and 41.9% for hard coal andlignite, respectively.The results are consistent with current studies but also indicate that major simulations were too optimistic.The auxiliary demand of an IGCC plant with carbon capture can be expected with 21 to 24% based on grossoutput. The drop in efficiency compared to the none-capture case is estimated with roughly 11 to 12%-points.During a sensitivity study the impact of process changes on plant efficiency and economics is evaluated.Releasing the captured CO2 without compression is found to be economically favourable at CO2 prices below15€/t and electricity prices above 100€/MWh. Further the impact of carbon capture rate is quantified and anefficiency potential is indicated for lower CO2 quality.

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1. Introduction

IGCC (Integrated Gasification Combined Cycle) is a technologywhich combines the possibilities of gasification with the highlyefficient power production in a combined cycle unit. Within thecarbon capture strategies it is by far the most advanced technologyand is believed to be demonstrated in industrial scale within the next5 years. Currently numerous projects are in progress all over theworld [1–5]. Since the plants are the first generation, their expectedefficiency will be far from the optimum for the benefit of theavailability.

Comprehensive work in the field of IGCC simulation andoptimisation was done by Pruschek et al. [6–8] in particular Kloster[9] and Göttlicher [10]. Simulations of IGCC plants with and withoutCO2 capture for the short term were performed by Meyer et al.especially Korobov [11] and Ogriseck [12], plants with carbon capturefor the scope of the year 2015 were simulated by Gräbner [13] andRieger [14]. Further numerous organisations such as the EPRI, Jacobsor the IEA published various studies on the simulation of IGCC plantswith and without Carbon capture [15–17]. Finally the companiescurrently planning IGCC plants or supplier of the correspondingtechnology published results from their in-house studies [2,18,19].

In order to maintain continuous development towards the secondgeneration of IGCC with CCS the research has to be initiated today.

Within the HotVeGas project the thermodynamic process simulationfocuses on gasification applications for the mid and long term.Therefore this paper deals with the modelling of an IGCC plant withCO2 capture using conventional technology believed to be available inthe time frame of 2020.

2. Main part

Since the performance of IGCC plants depends very much on anumber of relevant parameters, the plant is described and importantprocess assumptions are summarised. After modelling of the variousprocesses the simulation results were comparedwith reference valuessuch as real plant data, supplier or literature information. Finally themodels where combined according to the described configuration andthe plant was simulated for both a generic hard coal and ligniteconsidering 90% CO2 capture.

2.1. Plant description

For better understanding of the configuration the major systemsand material streams are shown in Fig. 1.

The gasification island consists of a dry feed entrained flow gasifierwith full water quench. The coal is dried to 2% and 12 wt.% and milledbelow 100 µm. In case of hard coal a roller mill and hot gas generatoris assumed. For lignite a fine grain WTA drying process is used.

The coal is pressurised via lock hoppers and transported at adensity of 400 kg/m3 by CO2. The coal is fed along with the oxygen,purge gas, support fuel and transport gas to the gasifier. In case of hard

Fig. 1. Simplified scheme of the IGCC plant configuration.

935C. Kunze, H. Spliethoff / Fuel Processing Technology 91 (2010) 934–941

coal additional steam is added. The gasifier runs at 1450 °C and 38 bar.A carbon conversion of 98.5 to 99% is assumed.

The oxygen has a purity of 98% and is provided by an air sideindependent low pressure cryogenic air separation unit. Despite thelower efficiency the partial integration was selected to improve theavailability and reduce plant complexity. The products oxygen, purenitrogen and waste nitrogen are pressurised externally via multistagecompressors with intercooling.

The hot gas is quenched with hot water to a temperature below210 °C and is scrubbed to remove trace elements. Once again thesimple solution is preferred over raw gas heat recovery to reducecomplexity on the cost of lower plant efficiency.

The pH of the water is adjusted and part of the water is withdrawnfrom the loop to avoid accumulation. The raw gas is processed in thegas cleaning section. First, CO is converted in a dual stage adiabaticraw gas shift with intercooling. The heat is used to generate HP, IP andLP steam as well as hot water for the quench and fuel gas saturationsection.

The cooled converted gas is now cleaned from sulphur compo-nents and CO2 in a selective physical washing step. The process usescold methanol as solvent and the sulphur off gas is enriched in orderto be suitable for an oxy Claus plant. The necessary cooling is providedby a dual stage ammonia compression refrigeration plant. The tail gasfrom the sulphur recovery unit (Claus plant) is recycled into the shiftsection. The CO2 is pressurised to 110 bar via a 8-stage gearcompressor with intercooling and liquefied for transportation.

The clean gas leaving the washing process is mostly hydrogenwhich needs to be diluted prior to the combined cycle. This isperformed by saturation of the gas with hot water and additionalwaste nitrogen from the air separation unit. In that way the hydrogenfraction is reduced to 50% which is believed to be applicable for futuregas turbines. The fuel gas is preheated to 320 °C and burnt in anadvanced gas turbine. The power output is fixed at approximately340 MWel and the coal input is adjusted in order to satisfy thecorresponding fuel gas demand. The turbine inlet temperature isassumed to be 1320 °C (ISO) which is comparable to the latest H classturbine generation. The hot exhaust from the gas turbine is used in a 3

Table 1Process assumptions for combined cycle plant.

Parameter Unit Value Parameter Unit Value

TIT (ISO) °C 1320 HD steam bar 170π bar 19.2 MP steam bar 40Gas turbine MWel ∼340 LP steam bar 6η gas turbine – 0.895 η HP steam turbine – 0.89T hot exhaust gas °C N600 η MP steam turbine – 0.93η generator % 98.5 η LP steam turbine – 0.92η motor % 96.5 Condenser pressure bar 0.048Δp control valve bar 5.2 T flue gas to stack °C b110Δp steam path K 10–25 Pinch K N9

pressure level HRSG to produce steam and hot water. The steam ismainly used by the steam turbines. It should be noted that there areseveral links between the combined cycle and the gas processingsection where steam/hot water is in- and exported. Finally, the coldflue gas leaves the process with below 110 °C. The major processparameters are summarised in Table 1.

2.2. Plant modelling

For modelling of the plant the commercially available simulationtools Aspen Plus and Ebsilon Professional were used for the gas islandand for the combined cycle, respectively.

The first step of modelling complex processes in Aspen Plus is thedefinition of the important species which occur in the real processesand should be considered in the simulation. The most important forIGCC applications are S, C, H2, CO, CO2, N2, CH4, H2S, COS, HCL, HCN,NH3, H2O, SO2 and O2. Further trace elements such as CS2,mercaptanes, metals (Hg and Se) and alkali components are neglecteddue to their minor amounts and to improve the convergencebehaviour of the plant model.

It should be mentioned that coal or biomass can't be defineddirectly due to its complex structured macromolecules. Therefore thefeed needs to be decomposed in reactive compounds. This is done in ayield reactor in which the feed is characterised by the immediate andelementary analyses as well as the heating value and converted to thecorresponding composition. The resulting material stream can beused by the software.

The next step is the selection of the thermodynamic data set whichshould be used for the simulation. From the numerous choicesprovided by Aspen Plus the Redlich–Kwong–Soave Method wasselected as global method.

However, for several subsystems individual property methodswere used such as NRTL-RK and STMNBS (water/steam table) forapplications where partially or even pure water is involved.

In case of reactive systems such as the gasifier or the shift section,the Gibbs reactormodel is used. The corresponding reaction equations

Table 2Overview verification sources.

Subsystem Verification source

Coal drying Supplier, literature [12,20,21]Coal mills Supplier [22]Coal transport Supplier, literature [11,12,23,24]Air separation unit Supplier, literature [12,25–31]Gasifier Supplier, literature [23,24,32–35]Shift stage Literature [36–39]Acid gas wash Supplier, literature [40–47]Compressors Supplier [48]Claus unit Literature [12,32,36,49]Combined cycle Supplier, literature [50–55]

Fig. 2. Schematic of the gasifier model.

Table 4Gasifier verification results [23].

Parameter Reference Simulation

H2 mol% 24.74 24.52CO mol% 63.17 63.21CO2 mol% 10.45 10.55N2 mol% 1.07 1.15Gas flow kg/h 149,618 149,120LHV kJ/kg 10,350 10,309

936 C. Kunze, H. Spliethoff / Fuel Processing Technology 91 (2010) 934–941

are entered and the deviation from equilibrium is taken into accountvia approach temperatures.

In applications involving distillation either at hot or cryogenicconditions, Radfrac columns are used. They can be used for any type ofmultistage vapour–liquid interaction, are able to handle solids, internalcooling as well as heating and assume equilibrium at the single stage.

The clean gas composition after the mixing with nitrogen ismanually transferred along with the other interacting streams to thecombined cycle which is modelled in Ebsilon Professional.

3. Results and discussion

3.1. Model verification

The verification step is essential for the validity of the simulationresults especially when modelling complex processes. Since theconfiguration of the process is often not public and the simulationsbased on extrapolated property data, the comparison of the results

Table 3Gasifier input data.

Parameter Lignite

Power MW 538C conversion % 99O2/C (mol) – 0.422Support fuel kg/h 358Temperature °C 1450Pressure Bar 40Cooling MW 8

with real process data is required in order to quantify the error.Despite its importance this process is rarely mentioned in theliterature.

For this IGCC model all major subsystems were verified indepen-dently and afterwards combined to the configuration visualised inFig. 1. The reference sources are summarised in Table 2. The results forthe major systems are discussed below.

3.1.1. The gasifier modelIn order to take losses into account a number of phenomenas of the

real process such as heat and pressure losses, limited conversion,deviation from equilibrium and slag melting energy were considered.Fig. 2 shows the gasifier model and in Table 3 the verification inputdata is summarised. The cold gas efficiency of the gasifier model wascalculated with 83% and 80.3% for hard coal and lignite, respectively.The model provided a specific synthesis gas (CO+H2) yield of 2200and 1644 m3 (STP)/kg coal which is consistent with the literature [32].Further, as shown in Table 4, the gas composition as well as gas massflow showed good agreement with the reference [23].

3.1.2. Air separation unitThe ASUmodel was compared with reference data [12] for a similar

low pressure plant with the same O2 purity of 98%. The model wasadjusted in order to reflect the mentioned power consumption of0.27 kWh/kg O2. The model showed a power consumption of approx-imately 0.273 kWh/kg O2 at a selected columnpressure of roughly 6 barand 1.5 bar for the high and low pressure columns, respectively. Itshould be mentioned that the range of published specific powerconsumption for ASU differs greatly. However, the mentioned value isbelieved to be in conjunction with several sources [29–31].

3.1.3. Shift conversionThe CO conversion unit was verified using literature references

(Table 2). Therefore a 3 stage system was modelled and the COconversion rate was compared.

As shown in Fig. 3, the model successfully reflected the behaviourof the shift unit. Only slight differences regarding the temperatureoccurred. In order to reach a 90% CO2 capture rate in the plant theconversion rate should be at least 95 to 96%. Since this was alreadyreached after two stages, a dual stage adiabatic system was used for

Fig. 3. Verification of the CO shift unit [36].

Fig. 4. Simplified scheme of the acid gas removal section.

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the IGCC model. It should be mentioned that the maximum processtemperature is limited to roughly 500 °C and a sufficient H2O/CO ratiois used to avoid sintering and carbon formation, respectively.

3.1.4. Acid gas removalAfter the shift unit the converted gas is treated in a methanol wash

in order to remove selectively the acid gases. The verification of themethanol wash stage was realised using data from different literaturesources (Table 2). The model was compared regarding its auxiliarydemands and the model behaviour at varying system pressure. Asshown in Fig. 4 the plant uses a high and low pressure flashregeneration where CO2 is released at two different pressure levels of2.5 and 1.1 bar. The process was already described in previous work[55,56] therefore only a scheme (Fig. 4) and results are shown.

The model was able to reproduce both the power and refrigerationdemand with an acceptable deviation of approximately 2.5% and 1%,respectively. Although the composition of the product streams showedhigher deviation regarding the trace elements, the concentration of themajor gas species and their distribution among the product streamswere in accordance with the literature references [47].

It is important to mention that the power demand depends verymuch on CO2 partial pressure and the removal rate. Therefore themodel was tested at various system pressures and compared withsupplier references.

Fig. 5 provides the results from the sensitivity analysis of themodel regarding the system pressure. The model was found to followthe trend mentioned in the literature. Due to the physical absorption

Fig. 5. Verification of acid gas removal section [43].

principle the process showed a reduced power demand at higherpartial pressure of the component to be absorbed.

3.1.5. Gas compressorsThe evaluation of the compression steps in the model is important

since the oxygen needs to be compressed to gasifier pressure,nitrogen to fuel gas pressure and CO2 to the transportation pressure.Therefore the models were verified by reference data provided bysupplier [48]. The results are demonstrated for the CO2 compressor. Inthis case an 8 stage gear compressor with intercooling to 40 °C wasmodelled. The CO2 is compressed to 110 bar and liquefied at 30 °C.The model is able to achieve a deviation in power consumption ofapproximately 0.5%. The specific power demand can be assumed inthe range of 0.09 kWh/kg CO2.

3.1.6. Combined cycleAs it is the intention to model an IGCC plant for 2020 an H class

turbine is assumed with advanced TIT and efficiency. Although thisturbine class started its commercial operation in 2009 it is assumedthat there are no special synthesis gas turbines in the midterm.Therefore adjustments need to be done on state of the art machineswhich restricts the newest generation for IGCC plants. The TIT wasestimated for natural gas from published data [57], especially thepressure ratio, flue gas temperature and mass flow. It should bementioned that it is assumed that in the midterm premixing burners

Fig. 6. Q–T diagram of the plant HRSG.

Table 5Simulation results of the base cases.

Parameter Hard coal Lignite

Gasifier thermal power 1071 MW 1102 MWOutput net 421.3 MW 408.2 MWη gross LHV 49.0% 55.5%η net LHV 38.5% 41.9%η net HHV 37.0% 35.0%Specific emission CO2 77 g/kWh 90 g/kWh

Fig. 8. Results from the sensitivity analysis.

938 C. Kunze, H. Spliethoff / Fuel Processing Technology 91 (2010) 934–941

for hydrogen rich fuels are available. Therefore the same turbineefficiency was assumed for combustion of syngas. However, the TITwas reduced by 20 °C compared to natural gas combustion.

The HRSG was reviewed by the supplier [50] and incorporatesadvanced heat exchanger, realistic pressure losses, improved steamturbines and steam parameters mentioned to be optimal for IGCCapplications [58] (Fig. 6).

3.2. Simulation results

After the verification the individual models were combinedaccording to the configuration in Fig. 1. The system was optimisedaccording to previous publications [59] and simulated for a generichard coal as well as lignite. Based on the assumed parameter andboundary conditions a plant net efficiency of 38.5% and 41.9% can beexpected on a LHV basis for hard coal and lignite, respectively. Theresults are summarised in Table 5.

This is an increase of about 7%-pts compared to the efficiencypublished by RWE for their IGCC planned to be in operation in 2015[19]. The significant deviation is mainly due to the major gas turbineand the optimisation of the RWE plant for availability.

Compared to the current studies for IGCC plants to be built in 2015the efficiency is only 3.5%-pts higher for hard coal and 1%-pts forlignite [13]. In case of hard coal the difference is mostly explained bythe improved gas turbine. In case of lignite the concepts can't becompared due to the use of a different type of gasifier andmuch lowerCO2 capture.

All the results above are in contradiction with the results publishedin the late 90s from Pruschek [6–8]. In their calculations of a hard coalIGCCplant in 1998, they received a net efficiency of roughly 51%and 47%for a none-capture and capture case, respectively. In their calculationmuch lower ambient conditions are assumed and the CO2 is delivered atgaseous state instead of liquefied state. But even more importantly theplants auxiliary consumption is only half compared to the currentsimulations, other studies as well as existing plants [13,60].

For a better understanding of the auxiliary demand and to pointout the major consumer the drop of efficiency for the individualsystems is shown in Fig. 7.

The figure shows clearly the significant impact of the air separationas well as CO2 removal and compression. In case of lignite the vapour

Fig. 7. Impact of the subsystems aux

compressor of the coal drying is another considerable powerconsumer. The compressor is used to raise the heat of condensationof the coal water vapour to a higher level. In that way this heat can beused to heat up the process again. It should be mentioned that this isthe reason for the much higher efficiency on a LHV basis compared tohard coal.

Altogether the auxiliary consumption can be expected in the rangeof 21 to 24%-points of the gross power output which is in conjunctionwith the literature [12,13]. This is much higher compared to none-capture plants where 10%-points are more likely [13,60].

Even more interesting and discussed in public is the drop ofefficiency for a capture compared to the corresponding none-capturecase. Despite the fact, that a comparison is difficult since theconfiguration of a low emission plant is optimised for its purposeand has to change almost completely for none-capture applications,an estimation was performed. In this estimation for the none-capturecase the raw gas heat is used for steam production and the sulphurremoval is performed using an amine based wash. The estimationshowed a gap of 11 to 12%-points compared to the verified capturecase. This is consistent with published results of RWE (12%-points[19]) as well as other studies for short term concepts where 10 to 11%-points are expected [13]. In case of the IGCC 1998 study [6–8] 4.2%-points are calculated for atmospheric CO2 which compares toapproximately 7%-points for liquefied CO2. Once again the majorstudy seems to be too optimistic. The reason might be the alreadymentioned much lower auxiliary demand. The study used a specificpower consumption for their Rectisol process of 0.35 kWh/kg CO2 atraw gas pressure of approximately 25 bar. This is much lower than theassumed demand in the current model. Another reason for thedifferences might be the degree of purity of the CO2. In the currentstudy the CO2 is releasable to the atmosphere. The impact of CO2

purity is investigated more closely in the sensitivity analysis.Basedon theperformed simulations and latest literature references a

more realistic net efficiency for a hard coal IGCC plant with an F classturbine could be expected in the range of 46% and 35% for the none-capture and the capture case, respectively [13]. The use of an advancedgas turbine like the H class would result in roughly 50% and 39% netefficiency (LHV). In case of lignite, approximately 54% and 42% can be

iliary power on plant efficiency.

Fig. 9. Impact of the release of captured CO2 on plant economics.

939C. Kunze, H. Spliethoff / Fuel Processing Technology 91 (2010) 934–941

expected for the corresponding capture case. Since the plant configu-ration, ASU integration, fuel composition and CO2 requirements havesignificant impact on the efficiency the values can differ in the range of1%-point and should be understood only as approximate values.

3.3. Sensitivity analysis

In order to evaluate this impact on the net efficiency due to changesof process parameters and/or configuration a sensitivity analysis wasperformed. The results are expressed as specific deviation from theefficiencies mentioned in Table 5 and summarised in Fig. 8.

In the first variation the carbon dioxide removal rate was variedbetween 80% and the maximum reachable for the two concepts. Themodels achieved a maximum CO2 capture of roughly 93% for hard coaland 95% for lignite. The difference is caused by improved CO conversionin the shift section due to the higher H2O/CO ratio in case of lignite. Itwas found that the capture rate is important for the comparison ofdifferent plant concepts. Especiallywhen targeting lowest emissions theeffort in the shift and acid gas removal section increases disproportion-ally. Therefore the sensitivity analysis provides an impression of theimpact on efficiency at a different capture rate.

Another influencing factor is the purity of the CO2. In case of amethanol based acid gas removal stage the CO2 is dry and of very highpurity of above 99%. In the simulated plant there are basically twooptions to reduce the auxiliary demand by the reduction of the purity.

First, the compression of the Claus tail gas along with the CO2 andthe increase of the flash pressure in the gas recycle section of the acidgas removal plant (Fig. 4). In the later option the recovery of co-absorbed valuable components is reduced which reduces the massflow through the absorber columns. Although the impact of CO2 purity

Fig. 10. Impact of maximum CO2

is low, there is a potential for improvements at higher tolerable traceelement concentration in the CO2.

In the next variation the influence of the CO2 pressure isinvestigated. It is shown, that the further compression after theliquefaction reduces only slightly the efficiency of the plant onlyslightly. On the other side the efficiency gain by releasing the CO2 atlower pressure is higher than 2.5%-points. Since the CO2 should bevery pure, there is a possibility of releasing the CO2 to increase the netoutput of the plant. Therefore the plant economics can be improved intimes when high electricity prices overcompensate the correspondingadditional emission costs. In our case the net efficiency (LHV) can beimproved to 41.4% and 45.3% with additional net output of 30.8 and32.8 MW for hard coal and lignite, respectively. Based on the powergain and the corresponding CO2 emission of 825 and 884 g/kWh forthe hard coal and lignite case the impact of releasing the captured CO2

is shown in Fig. 9. It should be mentioned that only revenue ofelectricity production is compared with emission costs.

It was found that there is only an economic advantage in case ofvery low CO2 prices. Already at a price of 20€/t CO2, the cost ofelectricity should be higher than 200€/MWh to overcompensate thecorresponding emission costs. In the range of 10 to 15€/t a positiveeffect can be achieved at electricity prices between 100 and 150€/MWh. However, since prices above 30€/t are expected in the future,the profitable release of CO2 at low pressure is unlikely and restrictedto peak electricity prices. Indeed, Fig. 9 probably indicates aneconomic gain when avoiding as much as CO2 as possible at lowelectricity and higher emission prices. Therefore the maximumcapture cases mentioned above were compared with the standard90% CO2 capture cases. The results are shown in Fig. 10.

It was found, that in case of hard coal the increase of the capture rateis favourable at CO2 prices above 25€/t. At this level the reduced power

capture on plant economics.

940 C. Kunze, H. Spliethoff / Fuel Processing Technology 91 (2010) 934–941

output due to increased capture effort is overcompensated by reducedemission costs. In the lignite case this already happens at a CO2 price of20€/t and below 80€/MWh. So a variable capture rate at least to someextent has a potential of improving plant economics considerably.

In the last three variations the consumption figures of the acid gaswash and ASU were varied to evaluate the impact of deviations of themodels or improvements of these conventional systems. In accor-dance with Fig. 7 it was found that improvements of the ASU wouldhave a much greater impact. Since all the systems are proven pieces oftechnology, significant improvements are not likely to expect.However, recent publications mentioned a significant reduction inASU power consumption for O2 purity of 95% [28]. This is mostly dueto reduced separation efforts and lower column pressure. Thereduction in column pressure consequently also results in lowerproduct stream pressure. Since these products are required at highpressure the majority of the power gain will at least partly becompensated by additional compression efforts of the productstreams [59]. Therefore advanced systems based on hot gas clean upand membranes should be investigated. Within the HotVeGas projectsimulations will be carried out to investigate this potential. In order toformulate requirements for the usage in IGCC plants those systemswill be simulated and implemented in the existing model. The plantmodel described above will provide the base case and comparison todemonstrate the potential of this future technology.

4. Conclusion

During this paper the developed and verification of a reliablethermodynamic IGCC model is described. The model incorporatesimproved technology and achieved an efficiency of 38.5 and 41.9% forhard coal and lignite, respectively. While the results are consistentwith current studies, major studies are pointed out as too optimistic.Compared to the corresponding none-capture plant the efficiencydrop is estimated with approximately 10 to 12%-points.

A sensitivity analysis demonstrates the impact of process mod-ifications on plant efficiency. Finally, an economic potential isdemonstrated regarding the CO2 capture. In times of high electricityprices of above 100€/MWh and CO2 prices below 15€/t the release ofcaptured CO2 to the atmosphere without any compression enablesprofit improvements of up to 5%. In times of higher emission costs anincrease of the CO2 capture rate up to the plants maximum improvesplant economics up to 4% compared to the standard case with 90%capture.

Acknowledgments

This work is part of a project supported by the Federal Ministry ofEconomics and Technology and industry partners (E.ON, RWE, EnBW,Vattenfall and Siemens Fuel Gasification) under the contract number0327773A. The author would like to thank the all partners for theirvaluable input and discussions, especially Mr. Hannemann, Dr.Schingnitz, Dr. Riedl and Mr. Karkowski.

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