Advanced Modeling and Simulation of Integrated … Exergetic analysis of the gasification processes...

Advanced Modeling and Simulation of

Integrated Gasification Combined Cycle

Power Plants with CO2-capture

Von der Fakultät für Maschinenbau, Verfahrens- und Energietechnik

der Technischen Universität Bergakademie Freiberg

genehmigte

Dissertation

zur Erlangung des akademischen Grades

Doktor-Ingenieur

(Dr.-Ing)

vorgelegt

von Dipl.-Ing. Mathias Rieger

geboren am 23.04.1978 in Hoyerswerda

Gutachter: Prof. Dr.-Ing. Bernd Meyer, Freiberg

Prof. Dr.-Ing. Michael Beckmann, Dresden

Tag der Verleihung: 17.04.2014

II

Versicherung

Hiermit versichere ich, dass ich die vorliegende Arbeit ohne unzulässige Hilfe Drit‐

ter und ohne Benutzung anderer als der angegebenen Hilfsmittel angefertigt habe;

die aus fremden Quellen direkt oder indirekt übernommenen Gedanken sind als

solche kenntlich gemacht.

Bei der Auswahl und Auswertung des Materials sowie bei der Herstellung des Ma‐

nuskripts habe ich Unterstützungsleistungen von folgenden Personen erhalten:

Prof. Dr.‐Ing Bernd Meyer (Betreuer)

Dr. Ing. Karsten Riedl (Berechnung der GuD‐Investitionskosten; Appendix I5)

Weitere Personen waren an der Abfassung der vorliegenden Arbeit nicht beteiligt.

Die Hilfe eines Promotionsberaters habe ich nicht in Anspruch genommen. Weitere

Personen haben von mir keine geldwerten Leistungen für Arbeiten erhalten, die

nicht als solche kenntlich gemacht worden sind.

Die Arbeit wurde bisher weder im Inland noch im Ausland in gleicher oder ähnli‐

cher Form einer anderen Prüfungsbehörde vorgelegt.

Ort, Datum Dipl.‐Ing. Mathias Rieger

III

Danksagung

An dieser Stelle möchte ich all denen danken, die mich auf vielfältige Weise wäh‐

rend meiner Zeit am Institut für Energieverfahrenstechnik‐ und Chemieingenieur‐

wesen der TU Bergakademie Freiberg unterstützten.

Besonders danken möchte ich Herrn Prof. Dr.‐Ing. Bernd Meyer für die Betreuung

meiner Dissertation. Das in mich und meine Arbeitsweise gesetzte Vertrauen so‐

wie die fortwährende Unterstützung bei der Bewältigung neuer Herausforderun‐

gen haben meine persönliche und berufliche Entwicklung äußerst positiv beein‐

flusst.

Herrn Prof. Dr.‐Ing. Michael Beckmann danke ich für die Übernahme des Zweitgut‐

achtens.

Meinen ehemaligen Arbeitskollegen Hardy Rauchfuß, Robert Pardemann und Mar‐

tin Gräbner danke ich für wertvolle Hinweise und die jederzeit kollegiale und

freundschaftliche Zusammenarbeit.

Meinen lieben Eltern danke ich für die immerwährende und selbstlose Unterstüt‐

zung. Die Leistung meiner Eltern kann nicht mit Dankesworten aufgewogen wer‐

den – sie wird mir bestes Beispiel sein, für die Erziehung unserer eigenen Kinder.

Meiner lieben Ehefrau Franziska danke ich für die vielfältige Unterstützung, das

Verständnis für meine Arbeit und nicht zuletzt ihre Geduld mit mir.

Table of contents

IV

Table of contents

1 Motivation and objective ............................................................................................ 1

2 Literature survey ........................................................................................................... 2

2.1 Plant performance and economics of CC‐IGCC .................................................. 2

2.2 Optimization approaches for IGCC ......................................................................... 7

2.3 Critical review .............................................................................................................. 12

3 Thesis outline................................................................................................................ 15

4 Modeling and Simulation of sub processes for CC‐IGCC ............................ 16

4.1 Basis CC‐IGCC configuration .................................................................................. 16

4.2 Coal gasification system ........................................................................................... 18

4.2.1 The Shell Coal Gasification Process ..................................................................... 19

4.2.2 The Siemens gasifier .................................................................................................. 22

4.2.3 The ConocoPhillips gasifier .................................................................................... 24

4.2.4 The General Electric coal gasifier ......................................................................... 27

4.2.5 Modeling and Simulation of the gasification processes ............................. 29

4.2.6 Exergetic analysis of the gasification processes ............................................ 36

4.3 Carbon monoxide shift ............................................................................................. 39

4.3.1 CO‐shift cycle for the Siemens gasifier and the GE‐R .................................. 41

4.3.2 CO‐shift cycle for the SCGP and the CoP gasifier ........................................... 42

4.3.3 Modeling and Simulation of the CO‐shift cycle .............................................. 44

4.4 Acid gas removal, CO2‐compression and sulfur recovery ......................... 46

4.4.1 Selective acid gas removal and CO2‐compression ........................................ 47

4.4.2 Sulfur recovery and tail gas treatment .............................................................. 51

4.4.3 Modeling and Simulation of acid gas removal and treatment ................. 53

4.5 Gas turbine ..................................................................................................................... 58

4.5.1 Modeling of the gas turbine process ................................................................... 59

Table of contents

V

4.5.2 Gas turbine process simulation ............................................................................ 61

4.6 The water‐/steam cycle ........................................................................................... 67

4.6.1 Modeling and simulation of the water‐/steam cycle ................................... 68

4.7 Air separation unit ...................................................................................................... 72

4.7.1 Fundamentals of air separation and process description ......................... 73

4.7.2 ASU simulation models ............................................................................................. 78

4.7.3 Simulation of ASU operating scenarios ............................................................. 80

5 Thermodynamic evaluation of IGCC‐concepts ............................................... 87

5.1 Benchmark of CC‐IGCCs with different gasifiers ........................................... 87

5.2 Level of integration between the gas turbine and the ASU ...................... 93

5.3 IGCC concepts with different carbon retention rates (CRRs) .................. 96

6 Economic evaluation and optimization .......................................................... 100

6.1 Economics of CC‐IGCC concepts ........................................................................ 100

6.2 Optimized IGCC‐concept with enhanced economics ................................ 108

7 Executive summary ................................................................................................. 112

List of figures

VI

List of figures

Fig. 1 Literature summary for the net efficiency of IGCC‐power plant concepts

with CO2‐capture .............................................................................................................. 3

Fig. 2 Literature summary for the relative efficiency of IGCC‐power plants

dependent on the level of air integration of the air separation unit .......... 8

Fig. 3 Literature summary for the relative efficiency of IGCC power plants

dependent on the level of nitrogen integration of the air separation unit

............................................................................................................................................... 10

Fig. 4 General process arrangement for the investigated CC‐IGCC ...................... 16

Fig. 5 Process flow scheme of the SCGP according to [19; 22] ............................... 19

Fig. 6 Process flow scheme of the Siemens gasifier according to [19; 54] ........ 22

Fig. 7 Process flow scheme of the CoP gasifier according to [22; 26; 63] ......... 25

Fig. 8 Process flow scheme of the GE‐R according to [22; 26; 54] ....................... 28

Fig. 9 Raw gas composition (dry) for different gasifier concepts ......................... 33

Fig. 10 Specific parameters for different gasifier concepts ........................................ 34

Fig. 11 Exergetic efficiency of different gasifier concepts .......................................... 38

Fig. 12 CO‐shift with three reactors for a typical raw gas........................................... 39

Fig. 13 CO‐shift cycle for a CC‐IGCC with Siemens gasifier ......................................... 41

Fig. 14 CO‐shift cycle for a CC‐IGCC with SCGP gasifier ............................................... 43

Fig. 15 Characteristics of the two‐reactor CO‐shift for different raw gases ....... 45

Fig. 16 Flow scheme for the AGR unit with refrigeration plant and CO2‐

compressor ....................................................................................................................... 48

Fig. 17 Flow scheme for the sulfur recovery unit and the tail gas treatment

plant ..................................................................................................................................... 51

Fig. 18 Calculated solubility of gases in methanol ......................................................... 53

Fig. 19 Characteristics of the acid gas removal unit ...................................................... 55

Fig. 20 Flow scheme for the gas turbine in a CC‐IGCC .................................................. 59

List of figures

VII

Fig. 21 Influence of fuel gas dilution and air extraction on gas turbine operation

at constant compressor flow .................................................................................... 62


at controlled compressor flow ................................................................................. 64

Fig. 23 Flow scheme for the water‐/steam cycle in a CC‐IGCC ................................. 67

Fig. 24 Q,t – diagram of the heat recovery steam generator ...................................... 69

Fig. 25 Heat surface area for the HRSG in a CC‐IGCC .................................................... 71

Fig. 26 Process flow diagram of the low pressure air separation unit .................. 74

Fig. 27 Equilibrium composition of boiling oxygen‐nitrogen mixtures ................ 76

Fig. 28 Pressure‐dependent boiling temperatures for nitrogen and oxygen and

determination of pressure levels for the distillation column of the ASU

............................................................................................................................................... 77

Fig. 29 Vapor and liquid composition inside the low pressure column of the

ASU ....................................................................................................................................... 80

Fig. 30 Auxiliary load distribution of air separation units for a CC‐IGCC ............. 83

Fig. 31 Specific auxiliary load consumption of an air separation unit for a CC‐

IGCC dependent on the operating pressure of the air separation unit .. 84

Fig. 32 Evaluation of CC‐IGCCs based on different gasifier concepts ..................... 89

Fig. 33 Impact of ASU and gas turbine integration on the performance of a CC‐

IGCC ..................................................................................................................................... 94

Fig. 34 Case study for IGCC‐concepts with different carbon retention rates ..... 97

Fig. 35 Cost of electricity for IGCC‐concepts with carbon capture ....................... 103

Fig. 36 Impact of realistic improvements to the cost of electricity (CoE) ......... 104

Fig. 37 Cost of CO2‐avoidance for a CC‐IGCC .................................................................. 106

List of tables

VIII

List of tables

Table 1 Major differences between some selected studies ............................................ 4

Table 2 Literature summary for the cost of electricity of CC‐IGCC ............................. 6

Table 3 Coal analysis (retrieved from [37]) ....................................................................... 29

Table 4 Specific parameters for the coal preparation and feeding process ......... 30

Table 5 Boundary conditions for simulation of the coal gasification process ..... 31

Table 6 Cold gas efficiency for the different gasification processes ........................ 35

Table 7 Significant process parameters for raw gas shift catalysts ......................... 44

Table 8 Gas composition after the CO‐shift cycle ............................................................. 46

Table 9 Boundary conditions for AGR process simulation .......................................... 54

Table 10 Parameter adjustment for AGR process simulation ....................................... 54

Table 11 AGR calculation results for different feed gases .............................................. 57

Table 12 Gas turbine calculation results for different fuel gases ................................ 66

Table 13 Performance results of water‐/steam cycle simulation ............................... 72

Table 14 Main differences between the developed ASU‐models ................................. 78

Table 15 Boundary conditions for ASU simulation ............................................................ 82

Table 16 Coefficients for calculation of the specific ASU auxiliary load ................... 85

Table 17 ASU simulation results for the CC‐IGCC based on different gasifiers ..... 86

Table 18 Performance summary for CC‐IGCC concepts ................................................... 88

Table 19 Exergy losses related to the exergy input to the CC‐IGCC ............................ 91

Table 20 Overall project costs for the CC‐IGCC with Siemens gasifier ................... 100

Table 21 Overall project costs for the CC‐IGCCs with different gasifiers .............. 101

Table 22 Other boundary conditions for the economic analysis .............................. 102

Table 23 Capital costs of a CC‐IGCC assigned to the main sub‐systems ................ 108

Table 24 Performance comparison between IGCC and GCC ....................................... 109

Table 25 Cost of electricity (CoE) for a GCC concept ...................................................... 110

List of abbreviations

IX


AGR Acid gas removal

Aheating surface Heat transfer area of the HRSG heating surfaces

ASU Air separation unit

BFW Boiler feed water

C Carbon content (ultimate analysis)

CapEx Capital expenditures

CC‐IGCC IGCC with Carbon Capture

CCPP Combined cycle power plant

CCR Carbon conversion ratio

Cl Chlorine content (ultimate analysis)

CO Carbon monoxide

CO2 Carbon dioxide

CoE Cost of electricity

CoECC‐IGCC Cost of electricity for a CC‐IGCC (including the costs of

CO2‐avoidance)

CoEconv Cost of electricity for a conventional steam power plant

(including the costs of CO2‐avoidance)

COORIVA Project name for the federal funded German research

project investigating CO2‐reduction through integrated

gasification and capture

CoP ConocoPhillips

COP Coefficient of performance for the refrigeration plant at

the AGR

COS Carbonyl sulfide

CO‐shift Carbon monoxide conversion

cp Specific heat capacity


X

CPRH Condensate preheater

CRR Carbon retention rate

CSC Convective syngas cooler

DGAN Diluent gaseous nitrogen

Δ H °C Standard enthalpy of reaction

Δpcomb Pressure loss due to the gas turbines combustion

chamber

Δpcomb Pressure loss due to the gas turbines combustion

chamber at reference (design) conditions

Δtm Mean logarithmic temperature difference

Eco Economizer

EPRI Electric Power Research Institute

eH O Specific exergy flow of the wet gas

E Chemical exergy flow

E Exergy flow the coal

e Specific exergy flow of the dry gas

E Overall exergy flow

E Thermomechanical exergy flow

GAN Gaseous nitrogen

GE General Electric

GE‐Q GE gasifier with full water quench

GE‐R GE gasifier with radiant cooler and water quench

GE‐RC GE gasifier with radiant cooler and convective syngas

cooler

GOX Gaseous oxygen

GSP Gaskombinat Schwarze Pumpe

H Hydrogen content (ultimate analysis)


XI

h Specific enthalpy

h0 Specific enthalpy at reference state

H2 Hydrogen

H2S Hydrogen sulfide

HCL Hydrogen chloride

HCN Hydrogen cyanide

HHV Higher heating value

HP GAN High pressure gaseous nitrogen

HP High pressure

HP‐BFW High pressure boiler feed water

HPC High pressure column

HP‐steam High pressure steam

HRSG Heat recovery steam generator

η Electrical efficiency (net)

ηex,gasifier Exergetic efficiency of the coal gasifier

IEA International Energy Agency

IGCC Integrated Gasification Combined Cycle

IP‐ BFW Intermediate pressure boiler feed water

IP Intermediate pressure

IP‐steam Intermediate pressure steam

k Heat transfer coefficient

KASU, Specific air integration

KASU,DGAN Specific DGAN demand

KASU,HP GAN Specific HP GAN demand

KASU,LP GAN Specific LP GAN demand

Lair,int Level of air integration


XII

LHV Lower heating value

LHV Lower heating value of coal

LP‐ BFW Low pressure boiler feed water

LP GAN Low pressure gaseous nitrogen

LP Low pressure

LPC Low pressure column

LP‐steam Low pressure steam

MAC Main air compressor (of the ASU)

MeOH Methanol

MHE Main heat exchanger

MIT Massachusetts Institute of Technology

m Mass flow rate

mH O Mass flow rate of the wet gas

m Mass flow rate of coal

m , . Compressor mass flow at reference (design) conditions

m Compressor mass flow

N Nitrogen content (ultimate analysis)

N2 Nitrogen

NETL National Energy Technology Laboratory

NH3 Ammonia

NOx Nitrogen oxides

n Molar flow rate

nH Molar flow of H2 in the raw gas at the interface be‐

tween gasifier and CO‐shift

nH O Molar flow of H2O in the raw gas at the interface be‐



XIII

n , Molar flow rate of carbon (coal input)

n , Molar flow rate of unconverted carbon (gasifier out‐

put)

nCO, Molar flow rate of carbon monoxide in the converted

gas (downstream CO‐shift)

nCO, Molar flow rate of carbon monoxide in the raw gas (up‐

stream CO‐shift)

nCO Molar flow of CO in the raw gas at the interface be‐


n Molar flow rate of the dry gas

O Oxygen content (ultimate analysis)

OPC Overall project costs

OpEx Operational expenditures

p Pressure

p0 Pressure at reference state

Pel,aux Electrical auxiliary load

PASU, Electrical auxiliary load for the ASU

PASU, Specific electrical auxiliary load for the ASU

P ,AGR/SRU/TGT Total electrical auxiliary load for the AGR, the SRU and

the TGT process

P ,CO Electrical auxiliary load for the CO2‐compressor

P , Electrical auxiliary load for the refrigeration plant

(AGR)

P , . Gas turbine power output (gross) at reference (design)

conditions

P Gas turbine power output (gross)

preactor Pressure in the gasification reactor


XIV

PRENFLO Pressurized entrained flow

πturb Pressure ratio of the gas turbines turbine section

πturb,ref Pressure ratio of the gas turbines turbine section at

reference (design) conditions

Q Heat flow

Qcooling screen Heat flow through the gasifiers cooling screen

Q ,LHV Heat flow of coal based on the LHV

Q , Heat flow at the evaporator of the refrigeration plant

(AGR)

R Universal gas constant

RC Radiant cooler

s Specific entropy

S Sulfur

s0 Specific entropy at reference state

SCGP Shell Coal Gasification Process

SlurryH2O frac Water faction within the coal/water slurry

SO2 Sulfur dioxide

SRU Sulfur recovery unit

Σ E Sum of exergy efforts

Σ E Sum of exergy losses

t Temperature

t0 Temperature at reference state

t , . Blade (surface) temperature at reference (design) con‐

ditions

t Blade (surface) temperature

TGT Tail gas treatment


XV

t , . Hot gas temperature before cooling air admixture at

reference (design) conditions

t Hot gas temperature before cooling air admixture

TIT Turbine inlet temperature

TIT . Turbine inlet temperature at reference (design) condi‐

tions

treactor Temperature in the gasification reactor

Vexhaust gas Volumetric flow of exhaust gas that is not fed to the

gasification reactor

VHP GAN Volumetric flow of HP GAN

VLP GAN Volumetric flow of LP GAN

VH CO Volumetric flow of H2 and CO

V ,ASU Air demand (volumetric flow) of the ASU

VDGAN Demand of DGAN (volumetric flow)

VGOX Volumetric flow of GOX

VGOX Volumetric flow of GOX produced by the ASU

VGT . Volumetric flow of extraction air from the gas turbine

VHP GAN Demand of HP GAN (volumetric flow)

VLP GAN Demand of LP GAN (volumetric flow)

Motivation and objective

1

1 Motivation and objective

Integrated Gasification Combined Cycle (IGCC) power plants with CO2‐capture are

widely expected as the silver bullet towards CO2‐lean power generation and the

combined chemical and energetic utilization of fossil fuels [24; 34; 52].

Despite of often published thermodynamic benefits (higher efficiency than conven‐

tional pulverized coal fired power plants) and technological advantages (almost

zero‐emission of carbon dioxide, particles and mercury‐, sulfur‐, chlorine‐ or bro‐

mine compounds, etc.) IGCC could not yet be established on the power generation

market.

Nevertheless, IGCC power plants with Carbon Capture (CC‐IGCC) offer a promising

alternative for a considerable reduction of greenhouse gas emissions.

The complex correlations within and between the individual sub‐processes and

their impact on plant operation, performance and economics are so far inadequate‐

ly described and partially misunderstood or even underestimated.

A lot of international studies do not show more than an assembly of calculation

results with a superficial description of individual sub‐processes and for the most

part an overall concept optimization is missing.

The objective of this thesis is an extensive description of the correlations in some

of the most crucial sub‐processes for hard coal fired CC‐IGCC and their influence on

overall plant operation, performance and economics.

The development and description of simulation models for CC‐IGCC sub‐processes

will clarify the most important coherences. The generated findings point out ther‐

modynamic and economic potentials as well as operational limits and therefore

provide the basis for future concept optimization and engineering development

directions.

The derived conclusions and evaluations are helpful and necessary both for engi‐

neering companies and electric utilities either for technological and operational

purposes or for investment and strategy decisions.

Literature survey

2

2 Literature survey

Fossil fuels and especially coals are broadly anticipated to play a dominant role

within the future power generation market worldwide [3; 30]. CO2‐emmissions

that are inherently connected with conventional coal usage and their potential in‐

fluence on the global climate are the key factor for the development of coal based

CO2‐lean power generation concepts. In this context CC‐IGCC power plants are

considered to be a promising alternative.

A great number of international studies investigated the expected IGCC‐

performance and IGCC‐economics. The objective of the present literature survey is

the analysis and assessment of study results for CC‐IGCC.

2.1 Plant performance and economics of CCIGCC

Performance data for CC‐IGCC concepts are extracted from Holt (2000) [24],

Holt (2002) [25], Chen and Rubin [6], Chiesa et al. [7], Cormos [8], Descamps et

al. [9], Gräbner et al. [20], Huang et al. [29], IEA [31], Katzer [34], Klara and

Plunkett [36], Kunze and Spliethoff [39], Martelli et al. [43] and NETL (2002‐

2010) [45‐47].

Fig. 1 shows the efficiency of the investigated IGCC‐concepts allocated to four in‐

dustrial coal gasifier types as there are:

- The Shell Coal Gasification Process (SCGP),

- The Siemens gasifier,

- The ConocoPillips (CoP) gasifier and

- The General Electric (GE) gasifier.

The latter type is commercially available in three configurations:

- With full water quench (GE‐Q),

- With radiant cooler and convective syngas cooler (GE‐RC) and

- With radiant cooler and water quench (GE‐R).

Referring to this, distinctions are also made in the figure.

Literature survey

3

Moreover, Fig. 1 provides some information about the coal‐feedstock for which the

different IGCC‐concepts have been developed. These coals can all be classified as

bituminous. The coal moisture content varies between 5 and 13 % and the lower

heating value between 25 and 30 MJ/kg. Therefore the concepts are comparable.

Fig. 1 Literature summary for the net efficiency of IGCC‐power plant concepts

with CO2‐capture

As it can be seen in Fig. 1 there is a high fluctuation for the expected net efficiency

even for IGCC‐concepts with the same gasifier type.

For a few selected studies, Table 1 provides some explanation where the observed

performance differences arise from.

Literature survey

4

Table 1 Major differences between some selected studies

study Chiesa

et al. [7]

Huang

et al. [29]

Cormos

[8]

NETL(2010)

[47]

Gasifier type GE‐RC GE‐RC CoP CoP

Gas turbine power [MW]

294 286 334 2 x 232

IGCC Gross output [MW] 503 523 528 704

Auxiliary load [MW] 120 129 115 190

IGCC Net output [MW] 383 394 414 514

Coal Input [MW (LHV‐based)]

978 1271 1127 1577

IGCC Gross efficiency [% (LHV based)]

51.4 41.2 46.9 44.6

IGCC Net efficiency [% (LHV based)]

39.1 31.0 36.7 32.6

Gas turbine efficiency [%] a)

39 39 39 39

Gas turbine fuel [MW] b) 753 733 856 2 x 595

Efficiency of fuel gas generation [MW] c)

77 58 76 75

a) assumed gas turbine efficiency b) calculated as follows: Gas turbine power / Assumed gas turbine efficiency c) calculated as follows: Gas turbine fuel / Coal input

By comparing the study results of Chiesa et al. [7] and Huang et al. [29], both inves‐

tigating an almost identical IGCC‐concept based on the GE‐RC, the following can be

noted: Although the gas turbine power output and the selected technologies are

approximately the same, the efficiency of the gas generation part (conversion of

coal to gas turbine fuel) differs by about 20 %‐points when for both concepts the

Literature survey

5

same gas turbine efficiency is assumed. This fact indicates that both studies use

greatly different modeling assumptions for the gas generation part.

In contrast, the studies conducted by Cormos [8] and NETL (2010) [47], both in‐

vestigating an IGCC‐concept based on the CoP gasifier, seem to use almost the

same modeling assumptions for it (as there is no big difference at the efficiency of

the gas generation part). However, the net‐performance difference of about 4 %‐

points is due to disparities at the auxiliary load calculation and at the chosen gas

turbine class (F‐class and G‐class).

With respect to a comparison of all four major gasifier types, only the study con‐

ducted by Cormos [8] can be considered. Therein CC‐IGCC concepts are investigat‐

ed for all mentioned gasifiers on a common basis, so that a realistic technology

comparison can be conducted. According to this study, the highest net efficiency

can be achieved using the SCGP followed by the CoP gasifier: However, a fairly high

difference to the absolute performance data provided by the engineering based

studies as for instance IEA [31], Gräbner et al. [20] or the NETL‐studies [45‐47] is

noted. Moreover, the mentioned NETL‐studies identify an IGCC‐concept based on

the GE‐R as superior to a concept with CoP gasifier or SCGP.

Literature survey

6

The economic analysis of CC‐IGCC concepts (Table 2) shows a quite diverse pat‐

tern.

Table 2 Literature summary for the cost of electricity of CC‐IGCC

Gasifier type Cost of electricity (CoE) Published Reference

GE‐Q 60 $/MWh 2002 [45]

GE‐Q 56 €/MWh 2003 [31]

GE‐Q 96 $/MWh 2009 [6]

GE‐RC 69 $/MWh 2008 [29]

GE‐R 103 $/MWh 2007 [46]

GE‐R 106 $/MWh 2010 [36]

GE‐R 106 $/MWh 2010 [47]

SCGP 63 €/MWh 2003 [31]

SCGP 110 $/MWh 2007 [46]

SCGP 68 $/MWh 2008 [29]

SCGP 97 $/MWh 2009 [43]

SCGP 119 $/MWh 2010 [47]

CoP 56 $/MWh 2000 [24]

CoP 106 $/MWh 2007 [46]

CoP 110 $/MWh 2010 [47]

As shown in Table 2, the cost of electricity (CoE) for a CC‐IGCC was assumed to be

in the range of about 60 $/MWh in the years between 2000 and 2003. At the end of

this decade, the CoE was almost doubled up to more than 105 $/MWh.

For example, the CoE for a CC‐IGCC based on the CoP gasifier varies greatly from

56 $/MWh [24] in the year 2000 to 110 $/MWh [47] ten years later.

Literature survey

7

This increase is mainly caused by three facts, which can be illustrated by a compar‐

ison of the two last‐mentioned studies (in each case for the IGCC based on the CoP

gasifier):

1. The tremendous rise of capital costs of more than 140 %

2. The increase of fuel cost by about 30 %

3. The reduction of the expected net efficiency by about 8 %‐points

2.2 Optimization approaches for IGCC

Most of the optimization approaches for IGCC‐concepts were focused on the inves‐

tigation of the integration influence between the gas turbine and the air separation

unit (ASU). The technological need for ASU‐integration is described in detail by

Smith [57] or Farina and Bressan [13].

In general, it has to be distinguished between air‐ and nitrogen integration. The

level of air integration stands for the amount of gas turbine extraction air in rela‐

tion to the air demand of the ASU. A level of 50 % means that half of the ASUs air

demand is extracted as compressed air out of the gas turbine. The remaining 50 %

have to be compressed by the main air compressor (MAC) of the ASU. The nitrogen

that is generated at the ASU can be admixed to the hydrogen rich gas for the pur‐

pose of NOx‐reduction and to stabilize combustion. Hence, the amount of admixed

nitrogen in relation to the produced nitrogen flow is expressed by the level of ni‐

trogen integration.

Fig. 2 summarizes the relative efficiency for IGCC‐concepts dependent on the level

of air integration for different nitrogen integration rates.

Literature survey

8

Fig. 2 Literature summary for the relative efficiency of IGCC‐power plants de‐

pendent on the level of air integration of the air separation unit

Each of the considered studies gives a clear statement concerning the relation be‐

tween the efficiency and the level of air integration. However, taken a general

view (Fig. 2), these results are partly opposed to each other. Therefore, some of the

studies shall be analyzed in more detail:

1. Different air‐integration ratios; cases without nitrogen integration

Frey and Zhu [16] and Wang et al. [64] for instance conclude that the maximum

IGCC‐efficiency appears at zero air integration and falls at increasing air extrac‐

tion rates. The gradient of the relative efficiency is in both cases almost linear,

but with a quite different slope.

Frey and Zhu [16] investigated different integration options for an IGCC with‐

out carbon capture, based on the GE‐RC. At decreasing air extraction rates, the

compressor inlet flow of the gas turbine was reduced in order to keep the tur‐

bines exhaust gas flow constant. For the ASU, two different pressure levels

(5 bar and 10‐15 bar) were investigated. The highest IGCC‐efficiencies were

Literature survey

9

always achieved with the low pressure ASU. It was found that air compression

in the MAC is more efficient than in the gas turbines compressor since the latter

requires air expansion down to the ASUs operating pressure.

The study conducted by Wang et al. [64] almost used the same approach, but

only a low‐pressure ASU and not a high‐pressure ASU was considered. External

air compression in the MAC was also found more efficient than in the gas tur‐

bine compressor; however the differences between full and zero air integration

were not as broad as found by Frey and Zhu [16].

In contrast to the above summarized articles, Cormos [8] for example pub‐

lished directly opposed characteristics. The author investigated different air in‐

tegration levels for an IGCC with carbon capture, based on the Siemens gasifier.

Within this study, it was found that the IGCC‐efficiency reaches its maximum at

100 % air integration and falls almost linear with decreasing air integration ra‐

tios. The quite low auxiliary load of the ASU indicates that excess nitrogen was

not admixed to the hydrogen rich fuel before combustion in the gas turbine.

As expected, the gas turbine power output increases at falling air integration

levels. But surprisingly, the steam turbine power output falls at an increasing

gas turbine output. This is not typical for combined cycle processes – an expla‐

nation for this behavior would have been helpful, but was not provided by the

author. Moreover, it is not clear, why the power output of the air expander

(which expands the gas turbine extraction air to the required ASU operating

pressure) keeps at a constant value at different air extraction rates.

2. Different air‐integration ratios; cases with full nitrogen integration

Frey and Zhu [16] and Wang et al. [64] also investigated the impact of air inte‐

gration to the IGCC efficiency at full nitrogen integration levels.

Frey and Zhu [16] came to the result that the highest IGCC‐efficiency again can

be achieved at zero air integration. In contrast to the analysis without nitrogen

integration, the concepts with a high pressure ASU are always found superior

to those with a low‐pressure ASU. This is a consequence of the higher product

(essentially nitrogen) pressure which can be achieved at ASUs that operate at

an elevated pressure. The higher product pressure reduces the pressure ratio

for nitrogen compression and therefore the specific work for compression.

Literature survey

10

Wang et al. [64] identifies a slight efficiency maximum at a level of 50 % air in‐

tegration upon a sharp efficiency increase between zero and 50 % air‐side in‐

tegration. Unfortunately, this study only presents the results – an explanation is

missing, so that one can only speculate about the reasons of this behavior: The

gas turbine power output has a clear maximum at 50 % air integration and de‐

creases with almost the same slope to both sides of this value. The decrease of

gas turbine power in the range between 50 and 100 % air integration is due to

the decreasing flow through the turbine. The reason for power decrease be‐

neath 50 % air integration is not clear. If the gas turbine would have reached its

maximum flow or mechanical limit, a constant power output from 50 % down

to zero air integration would have been expected.

Fig. 3 Literature summary for the relative efficiency of IGCC power plants de‐

pendent on the level of nitrogen integration of the air separation unit

Literature survey

11

3. Different nitrogen‐integration ratios; cases without air integration

Again Frey and Zhu [16] and Wang et al. [64] investigated these scenarios and

got to opposed results: The former study claims that the highest efficiency can

be expected at full nitrogen integration. Due to the application of two different

ASU pressure‐concepts, the following could be observed:

Elevated‐pressure ASUs are superior to conventional low‐pressure ASUs when

the level of nitrogen integration exceeds the 50 % line. The change of the ASU

pressure‐concept is indicated by the discontinuity of the respective graph in

Fig. 3.

In contrast, Wang et al. [64] reports an almost constant efficiency between zero

and 30 % nitrogen integration. From there on a sharp efficiency decrease with

a steady slope is shown for increasing nitrogen integration rates. The used gas

turbine has its power maximum at 30 % nitrogen integration. Again, the gas

turbine power output decreases with almost the same slope to both sides of the

maximum. Same as mentioned above, the missing background information for

the gas turbines operating behavior complicates the confirmability of the re‐

sults.

4. Different nitrogen‐integration ratios; cases with full air integration

The publications of Lee et al. [42] and Wang et al. [64] present contradictory

results.

Wang et al. [64] reports a slight maximum at zero nitrogen integration and a

small efficiency decrease with a rising nitrogen integration rate. The gas tur‐

bine power output increases continuously over the complete range. So it is as‐

sumed, that the gas turbine does not reach its full capacity with the given

100 % air integration.

The analysis presented by Lee et al. [42] stands out due to the sophisticated

modeling of the gas turbines operating behavior. Amongst others, this is

achieved by using a compressor map and the consideration of the compressor

surge margin as well as the firing temperature. So the authors came to the re‐

sult that the IGCC‐power output increases more rapidly than the fuel consump‐

tion at increasing nitrogen integration rates. Consequently, the IGCC‐efficiency

increases in this direction, too.

Literature survey

12

A few studies investigate the CO2‐capture rate as an optimization parameter. Chen

and Rubin [6] report that a CO2‐capture rate of 90 % yields to the lowest costs of

CO2‐avoidance. Descamps et al. [9] vary the CO2‐capture rate for a CC‐IGCC be‐

tween 80 and 98 % and identify the highest efficiency at 80 % CO2‐capture, which

is reported to be 7.5 % higher than the efficiency at 98 % CO2‐capture.

An IGCC concept with 60 % CO2‐capture is compared to an IGCC‐concept with 80 %

CO2‐capture by Ordorica‐Garcia et al. [49], where an efficiency advantage of about

4.5 % and an advantage for the CoE of about 6.5 % are found for the IGCC with

60 % CO2‐capture.

Future technologies as processes with ion transport membranes, hot gas clean up,

advanced gas turbines, advanced gasifiers and others that are not defined as prov‐

en technology are disregarded in the literature survey, since the state of the art

technology will most likely provide the basis for the first of its kind CC‐IGCC appli‐

cation.

2.3 Critical review

As the literature data presented in Chapter 2.1 and 2.2 show either high fluctuation

(efficiency, CoE) or even contrary behavior (air and nitrogen integration) a con‐

cluding assessment of CC‐IGCC concepts and optimization approaches seems not

possible yet.

Moreover, for some study results a high level of uncertainty is assumed since the

evolutionary history of them cannot be reconstructed [4; 6; 29; 64].

The extensive studies conducted by the International Energy Agency (IEA) [31],

the Electric Power Research Institute (EPRI) [24; 25] and the National Energy

Technology Laboratory (NETL) [45; 46] have room for improvement as process

modeling is inadequately described. Consequently, the calculation results are hard

to reconstruct. For this reason the cause determination for the observed data fluc‐

tuation is hindered or even not possible. Also for Bohm et al. [2], Chen et al. [6],

Gräbner et al. [20], Kim et al. [35], Lee et al. [41] and Martelli et al. [43] results as‐

sessment and concept comparison suffer from the low level of modeling details

provided.

Literature survey

13

The study “The future of coal” [34] prepared by the well‐known Massachusetts

Institute of Technology (MIT) reports a fairly big lack of knowledge with regard to

process modeling tools and defines this as a major problem for a reliable assess‐

ment of complex power generation cycles as CC‐IGCC. Furthermore, therein an

“urgent need to develop modeling and simulation capability and tools” (ibid, p.

103) is stated, as the basis for secure concept comparison.

The literature review for IGCC optimization scenarios reveals a very diverse pic‐

ture. In the following some shortcomings and doubts about the investigated stud‐

ies concerning the ASU‐integration aspect are pointed out:

- According to Smith [57], the maximum hydrogen content within the gas turbine

fuel can be realized at 45‐50 vol. % which means that fuel gas dilution below

this value is not required. As a consequence the investigations conducted by

Frey and Zhu [16], Farina and Bressan [13], Lee et al. [42] and Maurstad [44]

concerning the effect of nitrogen dilution have become obsolete.

- Spliethoff [58] claims that air “integration of 100 % will always yield the maxi‐

mum efficiency” (ibid, p. 612) since the “better compression efficiency of the gas

turbine helps to reduce the energy demand for the compression as a whole”

(ibid, p. 611). In contrast to the gas turbine compressor, the main air compres‐

sor (MAC) of the ASU operates with intercooling and pressurizes the air only to

the necessary pressure level. Hence, the compression efficiency within the MAC

should be superior to the gas turbine compression.

- Within the summary of the federal funded German COORIVA‐project, Gräbner et

al. [20] mentioned that the maximum IGCC‐efficiency is reached at full air and

nitrogen integration. Unfortunately, modeling and simulation details which

could have been used to prove this statement are not published.

- Incomprehensible conclusions are found in Emun et al. [10] as there is stated

that increasing nitrogen dilution, yields to growth of thermal efficiency, ”due to

a decrease in the slurry (coal) requirement, as more N2 is used to drive the tur‐

bine” (ibid, p. 335).

- Wang et al. [64] also presents only calculation results. Explanations of the es‐

sential gas turbine characteristics as well as information about modeling details

Literature survey

14

fail to appear. Consequently, the reader is forced to speculate about the reasons

for the presented results.

- In accordance with Geosits and Schmoe [17] the maximum IGCC‐efficiency can

be reached at 50 % air integration. However, no details and boundary condi‐

tions are presented to prove this statement, but it is mentioned that the gener‐

ated findings are “likely to change with improving gasification plant, ASU and

gas turbine performance and, therefore, should be evaluated for each project.”

(ibid, p. 3).

At this point it has to be mentioned that the publications of Frey and Zhu [16] and

Lee et al. [42] present some good approaches that are taken into consideration

within this thesis. In detail, these approaches are the investigation of different

ASU‐ pressure levels and the sophisticated modeling of the gas turbines operating

behavior.

Literature reviewed in terms of the optimum CO2‐capture rate showed the follow‐

ing weak points:

- The carbon monoxide conversion rate (CO‐conversion rate) within the carbon

monoxide shift (CO‐shift) cycle is varied in Descamps et al. [9] by a change of in‐

termediate pressure (IP) steam supply to the CO‐shift in order to investigate dif‐

ferent CO2‐capture rates. The mentioned approach is not realistic, as the reduc‐

tion of IP‐steam supply primarily causes the catalyst to overheat.

- There are reasonable doubts about the results found by Ordorica‐Garcia et

al. [49] as the calculated auxiliary load share of the acid gas removal (AGR) sys‐

tem differs greatly from the AGR auxiliary load share presented within the ex‐

tensive engineering‐based studies as [20] or [31].

To sum it up, it can be stated that proper process description, modeling and simu‐

lation are often missing within the reviewed literature. Very diverse results have

been found so that clear tendencies could not be derived.

Thesis outline

15

3 Thesis outline

As a consequence of the literature review, the development and proper description

of sophisticated process modeling tools for the major CC‐IGCC sub‐processes are

defined as one of the main tasks of this thesis.

More precisely, simulation models for the gasification process, the ASU, the carbon

monoxide conversion (CO‐shift) cycle, the AGR unit with CO2‐compression, the sul‐

fur recovery unit (SRU), the tail gas treatment (TGT) process, the gas turbine and

the water steam cycle of the combined cycle power plant (CCPP) are developed.

Special emphasis is laid on the substantial description of global coherences in or‐

der to clarify the correlations within and between the individual sub‐processes. So,

the simulation models are used for instance to investigate the influence of integra‐

tion between the gas turbine and the ASU for a CC‐IGCC.

Furthermore, CC‐IGCC concept routes for four types of industrial coal

gasifiers (CoP gasifier, GE‐R, SCGP and Siemens gasifier) are designed and simulat‐

ed using the developed process calculation models, so that a comprehensible tech‐

nology and concept assessment can be conducted. The results of the thermody‐

namic calculations provide the basis for an economic evaluation and the analysis of

critical points.

The generated findings represent the starting point for CC‐IGCC concept optimiza‐

tion. Thereby different optimization scenarios are investigated so that amongst

others the thermodynamic and economic influence of the CO2‐capture rate is clari‐

fied.

Finally, the generated knowledge yields to the development of an advanced gasifi‐

cation based power plant configuration which improves the economic results.

Modeling and simulation of sub‐processes for CC‐IGCC

16

4 Modeling and Simulation of sub processes for CCIGCC

In this chapter the main sub‐processes of CC‐IGCC power plants are investigated in

detail. For a given overall CC‐IGCC configuration, the individual processes are de‐

scribed and the thermodynamic and technical correlations are clarified extensive‐

ly. Sophisticated process simulation models are developed and implemented for

the simulation of selected scenarios. The generated results are in turn the basis for

a performance assessment and an illustration of the operating behavior.

4.1 Basis CCIGCC configuration

The basis configuration for the investigated CC‐IGCC concepts includes the typical

components which are necessary to achieve approximately 90 % CO2‐capture by

using a hard coal fed gasification process.

The chosen process arrangement (simplified expressed in Fig. 4) is briefly de‐

scribed in the following. References therefore can be found in [31] or [21].

A deepening investigation of the sub‐processes is given in the subsequent chapters.

Fig. 4 General process arrangement for the investigated CC‐IGCC

Gasifier [2](inclusive coal preparation)

Chapter 4.2

Air separation unit [1]

Chapter 4.7

coal

air

oxygen

rawgas

convertedgas

CO-shift [3](inclusive heat

recovery)

Chapter 4.3

sulfur

carbondioxide

AGR [4]

Chapter 4.4

nitrogen (at dry entry)

SRU + TGT [5]

Chapter 4.4

CLAUSgas

tailgas

cleangas

nitrogen

GTexhaust

flue

AGR … Acid gas removalSRU … Sulfur recovery unitTGT … Tail gas treatmentGT … Gas turbine

Cooling system

[9]

Water treatment

[10]

CO2-compression [6]

Chapter 4.4

LP CO2 IP CO2

Combined Cycle Power Plant (CCPP)

Water steam cycle [8]

Chapter 4.6

Gas turbine [7]

Chapter 4.5


17

The individual concepts for the four different types of gasifiers somewhat differ

however the general layout displays a lot of similarities.

For the gasification processes with a dry entry system (SCGP and Siemens gasifier)

the coal feedstock is first grinded, dried and pneumatically pressurized while for

the remaining (GE‐R and CoP gasifier) a coal/water slurry is prepared and pressur‐

ized after coal pulverization. The individual coal gasification processes mainly dif‐

fer in matters of reactor cooling and raw gas cooling.

Downstream gasification, the generated raw gas enters the two stage (sour gas)

CO‐shift unit where the main part of the carbon monoxide is catalytic converted

with steam to carbon dioxide and hydrogen. As the concept with sour gas shift has

been found advantageous compared to the sweet shift concept [31], the former has

been chosen. A good portion of the released reaction heat is recovered for internal

use as for instance steam generation, quench water preheating or clean gas satura‐

tion. The CO‐shift cycles also vary depending on the gasification process as the

generated raw gases contain different amounts of steam.

Leaving the CO‐shift cycle, the converted gas enters the AGR which is a physical

absorption unit using methanol as solvent. Hence, the selected AGR‐system should

show similar characteristics as the industrial Rectisol® process. While the separat‐

ed CO2 is compressed to the desired pressure, the sulfur containing components

(mostly H2S and COS) are converted to elementary sulfur within the SRU. For sul‐

fur recovery the CLAUS‐process running on oxygen‐enriched air has been chosen.

The remaining tail gas is treated in the TGT‐unit and recycled back to the AGR.

The clean, dry and hydrogen‐rich gas escaping the AGR is then diluted with excess

nitrogen from the ASU and saturated with steam using low temperature heat from

the CO‐shift cycle. Nitrogen and steam dilution are necessary operational measures

in order to realize secure combustion in the gas turbine with low emissions of ni‐

trogen oxides (NOx).

Finally, the conditioned fuel gas is preheated within the water steam cycle of the

CCPP and burned in the gas turbine for electricity generation purposes. The gas

turbine exhaust is used for steam generation in the heat recovery steam generator

(HRSG) of the water steam cycle before it is discharged to the ambient. The gener‐

ated steam is used in a steam turbine for additional electricity production. Moreo‐


18

ver, the water steam cycle of the CCPP usually features a couple of interfaces to

other sub‐processes as it operates for instance as heat source (e.g. for solvent re‐

generation within the AGR) or as a supplier of process streams (e.g. gasification

agent for the gasifier).

The ASU acts not directly within the process chain but supplies necessary process

media as gaseous oxygen (GOX) to the gasification process and to the SRU. Fur‐

thermore, it also delivers high pressure gaseous nitrogen (HP GAN) and low pres‐

sure gaseous nitrogen (LP GAN) for the pneumatic coal feeding system as well as

diluent gaseous nitrogen (DGAN) for dilution of the hydrogen rich fuel gas.

The cooling system and the water treatment section are not investigated in detail

but are considered for the sake of completeness.

According to Fig. 4 each subsystem has been numbered in order to advance clarity

for the interface configuration.

In anticipation of the flow schemes presented in the following chapters, the no‐

menclature for the process streams between the individual sub‐processes is ex‐

plained in Appendix A.

4.2 Coal gasification system

In the following, four types of industrial coal gasifiers (GE‐R, CoP gasifier, SCGP,

and Siemens gasifier) are investigated in detail. Simulation models for the individ‐

ual gasification processes are developed based on fundamental system descrip‐

tions. It should be mentioned that the presented process schemes and models do

not exactly reflect the industrial processes. A couple of assumptions and simplifica‐

tions have been defined in order to realize a comparative study.

More detailed information concerning the gasification systems can be found in [19;

22; 54] where especially the boundary conditions for process modeling and simu‐

lation are taken from.


19

4.2.1 The Shell Coal Gasification Process

The Shell Coal Gasification Process (SCGP) and the very similar PRENFLO (Pressur‐

ized Entrained Flow) process are oxygen blown entrained flow gasification pro‐

cesses with a dry entry system. Between 2002 and 2008 both processes were joint‐

ly merchandized by Shell and Uhde as SCGP. At the moment, both processes are

again competing on the market [26].

As illustrated in Fig. 5 the SCGP can be described as follows: Raw coal is grinded

and dried before pressurization (typically with nitrogen) in a lock hopper system.

The gasification agents (GOX and steam) are introduced to the pressurized coal

close to the burner entry in the reactor. Usually four burners are applied in an op‐

posite arrangement in order to realize steady fuel supply and ignition as well as an

enhanced particle residence time through recirculation within the reactor [19].

Fig. 5 Process flow scheme of the SCGP according to [19; 22]


20

Coal gasification takes place at reactor temperatures between 1400 and 1700 °C

and reactor pressures of 30 to 41 bar. The gasification reactor itself is designed as

a vertical cylindrical pressure vessel with an integrated membrane wall. The re‐

fractory lined membrane wall which protects the pressure vessel from direct radi‐

ation and liquid slag exposure is designed as heating surface for IP‐steam genera‐

tion. Through heat removal by the cooled membrane wall a solid slag layer is es‐

tablished at the reactor surface and acts as a thermal barrier. Upon the solid layer a

liquid slag film flows down through a centric hole and drops into a water bath. In

here the slag immediately granulates to a glassy material before it is discharged

through a lock hopper system which is often supported by a slag crusher unit [22;

26; 54].

The generated raw gas flows upwards and drags some of the molten slag along. A

cold recycle gas is introduced immediately above the reactor in order to solidify

the molten slag before entering the heat recovery system. The amount and the

temperature of the recycle gas are adjusted to ensure complete slag consolidation.

Depending on the coal and ash properties, the raw gas temperature behind the gas

quench varies between 700 and 900 °C while the amount of recycle gas is typically

in the same range as the amount of raw gas leaving the overall gasification sys‐

tem [19].

Downstream the cold gas quench, the raw gas enters the convective syngas cool‐

er (CSC) which is typically designed as a water tube boiler. Depending on the indi‐

vidual application, the CSC may contain economizer, evaporator and superheater

surfaces. However, for the cause of simplicity and economics frequently only evap‐

orator surfaces are applied. Generation of high pressure steam (HP‐steam) and

intermediate pressure steam (IP‐steam) takes place in order to cool the raw gas

down to approximately 250 °C. The generated IP‐steam is sent to the downstream

CO‐shift cycle as necessary reaction partner and temperature moderator. The satu‐

rated HP‐steam is superheated and expanded within the water/steam cycle of

CCPP.

Adjacent the CSC, fly ash removal is realized by a cyclone (for bulk removal) and

ceramic candle filters (for fine removal). At low ash contents in the coal (< 8 ma.‐

%) a fly ash recycle has to be applied to guarantee a sufficient slag layer on the

membrane wall [11]. The same has to be established when insufficient gasification


21

enlarges the carbon content within the fly ash. Downstream fly ash removal, the

recycle gas for the gas quench is extracted and recompressed in the quench gas

fan. Final removal of soluble trace compounds as NH3, HCN or HCl is realized by a

water wash unit.

The produced raw gas normally consists mainly of carbon monoxide

(about 60 mol. %) and hydrogen (about 30 mol. %) and is virtually free of higher

hydrocarbons [22]. Typical for the SCGP are carbon conversion ratios of more than

98 % and cold gas efficiencies between 80 and 83 % whereby the two parameters

are defined as follows:

Carbon Conversion Ratio CCR 1 ‐ ncarbon,unconvertedncarbon, coal (1)

Cold Gas Efficiency m raw gas LHVraw gasm coal LHVcoal

(2)

The overall thermal efficiency which considers the chemical as well as the recov‐

ered thermal energy is specified to about 95 % where the appeared losses accord‐

ing to [54] are made up as follows:

- 0.8 to 2 % heat loss due to reactor wall losses and slag discharge,

- 0.2 to 1 % due to unconverted carbon,

- 2 % heat loss at the heat recovery steam generators.


22

4.2.2 The Siemens gasifier

The Siemens gasifier was originally designed for salty brown coal under the name

GSP (Gaskombinat Schwarze Pumpe) process in East Germany in the 1980s. The

developed flow scheme for the subsequent process description is shown in Fig. 6.

Fig. 6 Process flow scheme of the Siemens gasifier according to [19; 54]

Such as the SCGP, the Siemens gasifier also features a dry coal entry system with a

milling and drying section and a pneumatic feeding system. In contrast to the SCGP,

the burners are placed at the top of the reactor so that the direction of flow is in‐

verted. Up to a thermal input of 500 MW one centrally arranged burner that com‐

bines the ignition and pilot flame with the coal dust nozzles is applied. At higher

thermal input rates a four‐burner‐design will be applied so that a central pilot and

ignition burner is surrounded by three coal dust nozzles arranged in a 120 ° offset

pattern [54].

LockHopper

Bunker

Feedervessel

LP GAN1-2-GAN-2

HP GAN1-2-GAN-1

Fuel gas4-2-gas-2

Raw coal0-2-coal-1

Coal milling and drying

Air0-2-air-1

Exhaust gas2-0-eg-1

Gaseous oxygen (GOX)1-2-GOX-1

IP steam 8-2-st-1

IP steam2-8-st-5

Gasifier

GOX Pre-heater

quench

Slag2-0-slag-1

Quench water3-2-wa-2

IP BFW8-2-BFW-1

Coolingscreen

Scrubber 1

Scrubber 2

Partialcondenser

Waste water2-10-ww-1

Make up water10-2-mu-1

LP BFW8-2-BFW-2

LP steam2-8-st-6

Raw gas2-3-gas-1


23

The reactor itself is offered in two different designs: The reactor design with cool‐

ing screen similar to the membrane wall of the SCGP is applied for coals that con‐

tain a sufficient amount of mineral matter so that an adequate slag layer can be

established as thermal barrier at the cooling screen. In contrast, a refractory lined

reactor design is applied for feedstock with low mineral contents. The design with

a cooling screen is preferred whenever possible since it has demonstrated long

term successful operation at high availability rates [54]. Therefore, the refractory

design is not considered in the following since the observed feedstock contains a

sufficient amount of mineral matter.

Caused by the original design feedstock (salty brown coal) the application of a

convective syngas cooler was a priori excluded since salt deposits on the heating

surfaces would occur. Different water quench designs were investigated. Of these,

one configuration has proved reliable operation where the quench water nozzles

are annularly placed in one single or multiple levels. The quench area is completely

free of installed equipment in order to avoid fine slag disposal. The granulated slag

is discharged by a lock hopper system similar the SCGP [54]. The quench water is

supplied at a temperature of about 200 °C [21] in order to increase the steam con‐

tent within the quenched raw gas. The high steam content in turn is advantageous

since it avoids or reduces the steam demand for the downstream CO‐shift.

The saturated raw gas which leaves the quench section at temperatures between

170 and 240 °C is routed to a series of two Venturi scrubbers where soluble trace

compounds and fine particles are removed. Downstream the scrubbers a partial

condenser cools the raw gas by a few centigrade. Thereby the volatile salt particles

will be enclosed in the condensed vapor droplets before the raw gas leaves to the

downstream processes [54].

The operating conditions within the reaction chamber and the raw gas composi‐

tion at the outlet of the gasification zone are very similar to the SCGP. It has to be

mentioned, that the reaction chamber can be operated at approximately 50 K low‐

er temperature than at the SCGP (at the same boundary conditions). This differ‐

ence is due to the concurrent flow direction of gas and slag which compensates a

part of the heat losses.


24

Due to the water quench a partial conversion of carbon monoxide and water to

hydrogen and carbon dioxide is reported by Schingnitz and Görz [53] so that the

final raw gas composition should be slightly different compared to the SCGP.

4.2.3 The ConocoPhillips gasifier

The ConocoPhillips (CoP) process is a two‐stage entrained flow gasifier where the

feedstock is introduced to the reactor as coal/water slurry. So far, the CoP technol‐

ogy has been realized only once in the Wabash River IGCC power plant (Indi‐

ana/USA). Compared to a dry entry system, the slurry feed is on the one hand

mainly beneficial through its less complexity (no lock hoppers and coal dryers) and

the unproblematic feedstock pressurization up to 80 bar [22; 54]. On the other

hand a higher oxygen demand has to be accepted compared to a dry entry system,

since the additional slurry water fraction has to be evaporated and heated up to

reactor temperature.

According to Fig. 7 the process can be described as follows: The raw coal is grinded

by the addition of water to the same particle size as necessary for pulverized coal

combustion power plants. The coal/water suspension features a coal fraction of

about 50 to 70 ma. %. In any case the lowest possible water content has to be as‐

pired in order to minimize the heat load necessary for water evaporation within

the reactor [54]. A slurry composition of about 65 ma. % coal and 35 ma. % water

counts as typical for the CoP gasifier. Originally a slurry split of 70 % to the first

stage and 30 % to the second stage was envisioned [19].


25

Fig. 7 Process flow scheme of the CoP gasifier according to [22; 26; 63]

After pressurization by the slurry pump the suspension is indirectly preheated

with steam and fed together with oxygen to the first stage of the reactor. Here, the

partial oxidization takes place at temperatures between 1320 and 1500 °C consid‐

ering the ash melting behavior of the individual coal. The two burners are placed

within the horizontal cylindrical vessels in an opposite arrangement. The chosen

layout of the first stage enables efficient mixing of the reaction partners so that a

high carbon conversion can be realized [19; 26; 63].

The reactor itself is completely refractory lined and can be operated at pressures

up to 41 bar. The coal ash accumulates as liquid slag at the reactor wall of the first

stage and is continuously discharged (lock hopper free) after granulation in a wa‐

ter bath. Carbon particles which are discharged through the water bath are fed

back to the slurry preparation after sedimentation [26; 63].

At the second stage of the reactor the remaining coal/water slurry (without oxy‐

gen) is brought into the upwards flowing hot raw gas. Through water evaporation

and endothermic reactions the raw gas cools down to about 1000 to 1050 °C. The

second stage therefore acts as a so called chemical quench which is a unique fea‐

ture of the CoP gasifier. Due to the chemical quench the generated raw gas contains

unconverted carbon and ash. The amount of unconverted carbon increases with a


26

decreasing coal reactivity. Therefore the actual slurry split ratio of 70/30 % has

been changed to 80/20 % since the CoP gasifier at the Wabash River IGCC is oper‐

ated on low reactive petrol coke. A higher feed ratio to the second stage would in

fact require an additional cyclone in front of the convective syngas cooler

(CSC) [19].

To ensure the desired quench effect the raw gas passes a residence vessel down‐

stream the reactor [19]. Thereafter the particle loaded gas is cooled down to about

350 to 400 °C in the CSC which is designed as a vertical fire tube boiler. The gener‐

ated saturated HP‐steam is sent to the CCPP for steam superheating and expansion.

Downstream the CSC, final dust removal takes place in cyclone and candle filters

achieving separation ratios of 99.9. The separated carbon and fly ash is pneumati‐

cally recycled (with nitrogen or syngas) to the first stage slurry [22; 26; 63]. The

almost dust free raw gas is further cooled down in a low temperature heat recov‐

ery section for low pressure steam (LP‐steam) generation. The generated LP‐steam

is also routed to the CCPP for superheating and expansion. Downstream the LP‐

CSC approximately 20 % of the raw gas are recycled back to the second stage of the

gasification reactor to adjust the desired temperature. The remaining raw gas is

finally directed to a water wash for removal of soluble trace compounds [46].

Due to the slurry entry and the chemical quench the raw gas might contain consid‐

erable amounts of the undesirable components carbon dioxide (about 16 mol. %)

and methane (about 4.5 mol. %), respectively [46]. On the other hand, these disad‐

vantages are partly compensated by an improved oxygen consumption and cold

gas efficiency. In fact, the cold gas efficiency is specified to values between 70 and

80 %. Further enhancement can be achieved through an increased slurry feed ratio

to the second stage as described and analyzed by Gräbner [19].


27

4.2.4 The General Electric coal gasifier

The General Electric coal gasification process is characterized by a completely re‐

fractory lined entrained flow reactor where the feedstock is handled as coal/water

slurry. In general, GE offers three technologies which mainly differ in methods of

raw gas cooling:

- The GE gasifier with a full water quench (GE‐Q)

- The GE gasifier with a radiant and a convective syngas cooler (GE‐RC)

- The GE gasifier with a radiant cooler and a water quench (GE‐R)

The latter one combines the reliable water quench with a highly efficient heat re‐

covery so that an acceptable performance penalty and a superior availability

(compared to the GE‐RC layout) shall be achieved. Therewith it is expected to

overcome the problems with fly ash deposits in the convective coolers as observed

at the GE‐RC in the Tampa Electric Polk Power Station IGCC [28].

In fact, the GE‐R is the chosen technology for the Edwardsport IGCC which was

supposed to start commercial operation in 2012 [66]. For this reason, the technol‐

ogy with radiant cooler and water quench is exclusively pursued within this thesis

for process description as well as for modeling and simulation of the GE gasifier.

According to Fig. 8 the GE‐R technology can be described as follows:

The slurry preparation proceeds in an analog manner as at the CoP technology

with a specified solid fraction of about 65 to 74 % [54].


28

Fig. 8 Process flow scheme of the GE‐R according to [22; 26; 54]

After preheating, the slurry suspension and gaseous oxygen are introduced at the

top of the reactor so that a downward flow direction is set up. The molten slag ac‐

cumulates at the reactor wall and drops down in a water bath which is placed un‐

derneath the radiant cooler (RC). The duct between the reactor and the RC is de‐

signed in a way that a contact between molten slag and the heating surfaces of the

RC is avoided.

As the hot raw gas still contains sticky and corrosive slag droplets it has to be

cooled down in the RC to a temperature at which the slag loses its adhesive charac‐

ter [54]. Intermediate pressure boiler feed water (BFW) extracted from the CCPP is

pressurized and fed to the RC where saturated HP‐steam is generated through heat

exchange with the hot raw gas. Downstream the RC the raw gas is quenched until

complete saturation using preheated quench water.

Slurrytank

Raw coal0-2-coal-1

Gaseous oxygen (GOX)1-2-GOX-1

Gasifier

Slag2-0-slag-1


HP steam2-8-st-4

Scrubber


Raw gas2-3-gas-1

Coal milling andslurry preparation

Slurry water10-2-wa-1

Slurrypreheater

LP steam8-2-st-2

Condensate2-8-cond-1

Radiantcooler

quench

Lockhopper

Slagscreen

Clarifier


Solids recycle

GOX Pre-heater

IP steam8-2-st-3

BFWpump

BFW8-2-BFW-5

Refractory


29

As reported by Gräbner [19] only partial carbon conversion of about 90 % per cy‐

cle can be achieved at the given boundary conditions. Therefore the unconverted

carbon has to be separated from the granulated slag and then fed back to the slurry

tank. Thus, an overall carbon conversion ratio similar to the other discussed gasifi‐

cation processes can be achieved.

Finally, the raw gas is routed to a scrubber unit for the removal of soluble trace

components and fine particles before it leaves the gasification unit to the CO‐shift.

Due to the slurry entry the generated raw gas contains considerable amounts of

carbon dioxide. This fact and the low carbon conversion are the reasons for a rela‐

tively low cold gas efficiency which is expected in the lower 70 % area [19].

4.2.5 Modeling and Simulation of the gasification processes

A typical world market coal was selected as feedstock for the comparative investi‐

gation. Table 3 shows the appropriate coal analysis.

Table 3 Coal analysis (retrieved from [37])

Parameter Unit Value Parameter Unit Value

Proximate analysis

Fixed carbon ma. % 50.15 Moisture ma. % 5.50

Volatile mat‐ter

ma. % 36.98 Ash ma. % 7.37

Ultimate analysis

C ma. % 72.35 Cl ma. % 0.05

H ma. % 4.97 S ma. % 2.84

O ma. % 5.56 Moisture ma. % 5.50

N ma. % 1.36 Ash ma. % 7.37

Heating value (according to DULONG)

LHV MJ/kg 29.888 HHV MJ/kg 31.107


30

The process simulation models were developed according to the above discussed

process schemes and descriptions.

The characteristic parameters for the coal preparation and feeding process as well

as the electrical auxiliary load strongly depend on the properties of the individual

feed stock and the chosen systems and machineries. Since this approach demands

a lot of manufacturer know‐how and experiences, it was decided to use literature

data in order to receive the same basis for the process evaluation. Table 4 shows

the corresponding parameters and their related literature sources.

Table 4 Specific parameters for the coal preparation and feeding process

Parameter Unit CoP GER SCGP Siemens

Pel, aux kWh/tcoal 30a) [46] 21 [46] 43a) [21] 26 [21]

VLP GAN Sm³/Sm³ GOX ‐ 0.16 [21]

VHP GAN Sm³/Sm³ GOX ‐ 0.30 [21]

Vexhaust gas % of input GAN ‐ 83 [31]

SlurryH2O‐frac

ma. % 35 [19] ‐

a) … auxiliary load for recycle gas fan included

Table 5 shows the defined boundary conditions for process simulation. The reactor

pressures of the SCGP, the Siemens gasifier and the CoP gasifier were selected in

order to supply a gas turbine fuel at an adequate pressure level. At the same time

the chosen pressure represents the upper end of the nowadays technical possible

level [22]. Since the GE gasification process has been found more competitive at

higher pressures [31], an elevated gasifier pressure was selected. The gasification

temperatures were defined in order to keep a sufficient distance to the flow tem‐

perature (about 1300 °C [37]) of the coal ash. The heat losses have been selected in

accordance to Gräbner [19].


31

Table 5 Boundary conditions for simulation of the coal gasification process


preactor bar 40 60 40 40

treactor °C 1450b)/1000c) 1450 1450 1450

CCR % 99b)/42c) 90 99.5 99.5

Wall loss % of coal heat input

0.5 1.2 1.0 1.0

Qcooling screen ‐ ‐ 2.0 2.0

b) … 1st stage; c) … 2nd stage

The reactors itself are simulated by setting the reaction equations and the appro‐

priate temperature approaches to the equilibrium state (refer to Appendix C2)

which were retrieved from Gräbner [19]. The defined carbon conversion ratios and

the reactor temperatures are adjusted by the oxygen flow. For the processes with a

dry entry system, the moderator steam flow represents an additional parameter to

conform the overall heat balance. Some assumptions that have not been mentioned

up to now are considered below.

At the SCGP, about 57 % of the raw gas is recycled so that a temperature of 825 °C

is adjusted at the entry of the CSC. Saturated HP‐steam is generated by raw gas

cooling assuming a pinch point of 88 K and 2 % heat loss within the CSC. Final raw

gas cooling down to 274 °C is realized by IP‐steam generation with an IP pinch

point of 10 K. The Pinch point of the HP‐CSC was found in order to provide enough

heat to generate the necessary amount of IP‐steam required at the downstream

CO‐shift. The pulse gas flow for the ceramic candle filters is fixed at 0.5 % of the

raw gas flow (in accordance to Gräbner [19]).

For the CSC of the CoP gasifier the pinch points were selected to 10 K both for the

high and the low pressure steam generator. Concerning the heat loss and the pulse

gas demand, the same conditions were defined as at the SCGP. About 21 % of the

raw gas is extracted downstream the LP‐CSC and recycled back to the second

gasifier stage after cooling down to 30 °C.


32

Due to the water excess within the raw gas (caused by the slurry entry) and the

realized residence time within the reactor, the gas composition at the GE‐R match‐

es to an equilibrium temperature far below the actual reactor temperature [19].

This temperature has been determined by Gräbner [19] to about 993 °C. It is used

in the simulation model for calculation of the final raw gas composition by an addi‐

tional equilibrium reactor. Adjacent, the hot raw gas is cooled in the RSC down to

816 °C by HP‐steam generation before final water quench cooling down to com‐

plete saturation takes place (in accordance to Gräbner [19]).

The developed CHEMCAD flow sheets and the individual heat and material balanc‐

es for the simulation cases can be found in the Appendixes B2 to B9. For the calcu‐

lation of the thermodynamic properties the Soave‐Redlich‐Kwong equation of state

was used.

Fig. 9 shows the calculated raw gas composition for the four different gasifier con‐

cepts. As expected, the raw gas of the processes with a dry feed system is very

similar. There are only slight differences at the carbon dioxide and nitrogen con‐

tent due to the partial CO‐conversion during the water quench and the pulse gas

for the candle filters respectively. The raw gases of the processes with slurry entry

look similar whereas the methane content at the CoP case marks the slight differ‐

ence. The noticeable methane content is caused by the relatively low reaction tem‐

perature (about 1000 °C) prevailing at the second gasifier stage of the CoP gasifier.

Since the methane will slip through the CO‐shift unit and the AGR as well, higher

CO2‐emissions are expected at the IGCC concept with a CoP gasifier.


33

Fig. 9 Raw gas composition (dry) for different gasifier concepts

For evaluation and comparison of the different gasification processes the following parameters have been defined:

GOX demand VGOXQcoal,LHV

Sm³ GOXGJ coal

(3)

Syngas yield VH2 CO

Qcoal,LHV Sm³ H2 CO

GJ coal (4)

H2 to CO ratio H2CO

nH2nCO

‐ (5)

Steam to CO ratio H OCO

H O

CO (6)

The above mentioned parameters are visualized in Fig. 10 for a comparison of the

different gasifier concepts.


34

The GAN‐demand for the different processes was not visualized here, since it is an

input parameter for the simulation as shown in Table 4.

Fig. 10 Specific parameters for different gasifier concepts

The second gasifier stage at the CoP process, where no additional oxygen is re‐

quired for coal gasification, overcompensates the drawback of the slurry entry so

that the CoP gasifier exhibits the lowest specific oxygen demand (refer to Fig. 10a).

The very similar gasification principle of the Siemens gasifier and the SCGP yields

to the same specific oxygen demand which is roughly 6 % higher than at the CoP

gasifier. In contrast, the GE‐R shows a 14 % higher oxygen demand compared to

the Siemens gasifier and the SCGP and a 21 % higher demand as the CoP gasifier,


35

all caused by the incomplete carbon conversion per pass combined with the slurry

entry system.

Since the carbon monoxide and hydrogen fraction within the raw gas accumulates

to more than 90 mol. % at the Siemens gasifier and the SCGP (refer to Fig. 10a), the

syngas yield shows the highest values out of the four concepts (refer to Fig. 10b).

Due to the higher carbon dioxide content within the raw gas the syngas yield at the

GE‐R is 9 % lower than at the aforementioned concepts. The CoP concept shows an

additional reduction of the parameter by about 5 % caused by the methane frac‐

tion which does not appear at the other three principles.

The hydrogen to carbon monoxide ratio of the raw gas shows a value of about 3:4

for the gasifiers with slurry entry and about 1:2 for the gasifiers with a dry entry

system (refer to Fig. 10c). As a consequence the necessary carbon monoxide con‐

version is higher for the latter ones when a common chemical synthesis would be

considered as downstream process.

The steam to carbon monoxide ratio illustrated in Fig. 10d indicates a high steam

content for the raw gasses of the water quench gasifiers (GE‐R and Siemens

gasifier) and a relatively low steam content for the gasifiers with dry raw gas cool‐

ing (CoP gasifier and SCGP). Consequently, the last mentioned gasifiers will require

additional steam as reaction partner and temperature moderator at the down‐

stream CO‐shift while the raw gas out of the GE‐R and Siemens gasifier contains

probably enough of it.

The cold gas efficiency is presented in Table 6 for the observed gasifier concepts.

As expected the concepts with a dry entry system show superior values compared

to the gasifiers with a slurry entry system. However, the chemical quench at the

CoP gasifier yields to a noticeable improvement compared to the GE‐R process.

Table 6 Cold gas efficiency for the different gasification processes

Gasifier CoP GER SCGP Siemens

Cold gas efficiency 78.7 % 72.7 % 80.5 % 80.1 %


36

4.2.6 Exergetic analysis of the gasification processes

The fundamentals of exergetic analyses are extensively described by Fratzscher et

al. [15]. According to their remarks, the exergy of process streams has to be calcu‐

lated under consideration of:

- The thermomechanical exergy (as an expression of temperature and pressure

differences between the individual state and a reference state),

- The chemical exergy (as an expression of the reaction potential compared to the

pure environmental components), and

- The concentration exergy (as an expression of differences between the composi‐

tion of the individual process stream and the ambient).

The concentration exergy is not included at the presented analysis, since the con‐

centration difference to the ambient is not considered as a useful benefit.

The reference state for all exergy calculations has been set to 25 °C and

1.01325 bar. The ambient air has been defined to contain 78.1 mol. % of nitrogen,

21 mol. % of oxygen and 0.9 mol. % of argon.

Hence, the overall exergy of process streams is calculated as

E E E . (7)

The thermomechanical exergy is regarded as a mixture of a dry and a water phase

so that it can be calculated as follows:

E n e mH O eH O (8)

where

e c t t T c ln TT R ln J (9)

eH O h h T s s . J (10)


37

The chemical exergy of the gaseous process streams is calculated using the molar

reaction exergy of the pure components according to equation (11). Those and the

related method of calculation are excellent described by Gräbner [19].

E n ∑ x e . (11)

Finally, the exergy of coal is calculated through the following statistical formula

that has been proposed by Baehr [1]:

E m 0.967 LHV 2.389 . LHV in MJ/kg (12)

The exergetic efficiency has been defined as evaluation criteria between the four

gasifier concepts according to the following:

η , f 1 E E

. (13)

The exergy loss is calculated as the difference between incoming and outgoing

exergy streams.

The four different gasification processes are evaluated considering all interface

streams to and from the individual process according to the appropriate flow

schemes (Fig. 5 to Fig. 8) and to the heat and material balances (Appendixes B3,

B5, B7, B9).

Fig. 11 shows the calculated exergetic efficiencies for the four different gasifier

concepts. As the generated raw gas and the recovered heat (steam generation)

represent the only benefit out of the gasification processes, the individual exergy

shares of the raw gas and the heat recovery system are pointed out in the graphic

below. Moreover, the chemical raw gas exergy as well as the thermomechanical

raw gas exergy (consisting of the dry phase and the water phase) are related to the

overall exergy effort.


38

Fig. 11 Exergetic efficiency of different gasifier concepts

As it can be seen the chemical raw gas exergy is almost even at the CoP gasifier, the

Siemens gasifier and the SCGP. Only the GE‐R shows a chemical raw gas exergy that

is about 10 % lower than that of the aforementioned concepts.

Since the raw gas pressure and the raw gas temperature after gas cooling are with‐

in the same range at all concepts, the share of the thermomechanical exergy of the

dry raw gas is also nearly equal. Due to the water quench at the GE‐R and the Sie‐

mens gasifier, the thermomechanical exergy fraction of the raw gas increases in

comparison to the remaining two concepts.

Caused by the raw gas heat recovery system at the CoP gasifier and the SCGP, a

considerable exergy amount is transferred to the generated steam. Therefore the

exergetic efficiency reaches a slightly better value as the Siemens gasifier. The ra‐

diant cooler in combination with the water quench at the GE‐R is responsible for

the highest exergy recovery out of the four concepts so that the overall efficiency

drawback to the other three concepts is reduced to roughly 4 %.


39

4.3 Carbon monoxide shift

Within a CC‐IGCC the carbon monoxides shift (CO‐shift) cycle represents the sub‐

sequent process step downstream the gasification system. The intention of the CO‐

shift is to convert the carbon monoxide contained in the raw gas to hydrogen and

carbon dioxide according to the following equilibrium reaction:

CO H2O H2 CO2 ΔH25°C ‐41 kJ/mol (14)

The catalytic reaction takes place in one single or in a series of adiabatic reactors

(normally two or three) whereas the individual number of reactors depends on the

maximum allowable carbon monoxide slip. Fig. 12 visualizes the temperature pro‐

file and the carbon monoxide content for a three‐stage CO‐shift using a typical raw

gas from an entrained flow coal gasifier.

Fig. 12 CO‐shift with three reactors for a typical raw gas

As illustrated, the first reactor realizes the lion’s share of CO‐conversion. However,

due to the sharp temperature increase within the reactor bed, the minimum reach‐

able CO‐content in the first reactor is limited by the thermodynamic equilibrium to

relatively high values. On the other hand, the third reactor just slightly reduces the


40

carbon monoxide slip, so that for a CC‐IGCC a two reactor configuration with inter‐

coolers in between typically delivers acceptable carbon monoxide conversion rati‐

os so that an overall CO2‐cature rate of about 90 % can be realized. Therefore a

two‐stage configuration has been chosen for the investigated CC‐IGCC concepts.

The above mentioned CO‐conversion ratio is defined as follows:

CO‐conversion ratio 1‐ nCO, converted gasnCO, raw gas

*100 (15)

The catalysts for the raw gas shift consist mainly of cobalt and molybdenum and

attain their full activity only when enough sulfur compounds (100 to 1500 ppm)

are present in the feed gas. The catalysts favor also the parallel conversion of car‐

bonyl sulfide (COS) to hydrogen sulfide (H2S) so that the COS content in the shifted

gas reaches low levels close to the thermodynamic equilibrium [60]. Occasionally,

also a catalyst guard bed for Cl‐ and HCN is applied. Further information to raw gas

shift catalysts, operating conditions and experiences are provided by Frank [14].

The maximum process temperature is influenced by the temperature resistance of

the catalyst in order to avoid catalyst sintering. For this reason the feed gas has to

contain enough steam for temperature moderation, especially at high carbon mon‐

oxide contents. At the same time, the feed gas temperature to the reactor has to be

determined so that a sufficient margin to the saturation temperature is given and

the catalyst activity is high enough to promote the reaction.

The above described fundamentals have been used to develop CO‐shift cycles for

the CC‐IGCC concepts based on the four different gasifiers. Thereby the following

requirements have to be considered:

- High carbon monoxide conversion rates,

- Efficient heat recovery (steam generation; quench water preheating),

- Saturation of the clean and diluted fuel gas.

In the following the layout and the performance of the developed cycles are de‐

scribed in detail.


41

4.3.1 CO‐shift cycle for the Siemens gasifier and the GE‐R

As the raw gases of the Siemens gasifier and the GE‐R already contain a sufficient

amount of steam, the released reaction heat can be used to a good portion for

steam generation. Concurrently a large amount of quench water has to be preheat‐

ed up to 200 °C in order to realize a high vapor pressure within the raw gas at the

gasifier outlet. The process flow scheme for the CO‐shift of the CC‐IGCC with Sie‐

mens gasifier is presented in Fig. 13.

Fig. 13 CO‐shift cycle for a CC‐IGCC with Siemens gasifier

The incoming raw gas is first preheated to 280 °C against the converted gas leaving

the second CO‐shift reactor at about 320 °C. The hot exhaust of the first CO‐shift

reactor is cooled down in two consecutive gas/water heat exchangers. Thus, the

high temperature heat is recovered through preheating and evaporating of high

pressure boiler feed water (HP‐BFW) which is then sent as saturated steam to the

combined cycle. The temperature differences between the HP‐BFW and the hot gas

are adjusted in order to realize a feed gas temperature to the second CO‐shift reac‐

tor of again 280 °C.

CO-shiftreactor 1

CO-shiftreactor 2

Raw gas 2-3-gas-1

steamdrum

HP steam3-8-st-8


BFWpump

BFW8-3-BFW-3

Shifted gas3-4-gas-3

Cooling water3-9-cw-2



condensate

Clean gas4-3-gas-4

Clean gassaturator

DGAN1-3-DGAN-1


GT fuel3-8-gas-5


42

The low temperature heat is recovered within a series of gas/water heat exchang‐

ers in which the quench water and the BFW are preheated and the heat losses of

the clean gas saturator are compensated. The process condensate contributes a big

portion to the required amount of quench water so that only minor amounts of

make up water are necessary. After final gas cooling the converted gas leaves to

the AGR and the discharged condensate to the waste water treatment in order to

avoid undesired accumulations within the process.

Typically, part of the raw gas can be bypassed to the first reactor for the purpose of

process control. Since this is not within the scope of this thesis, the raw gas bypass

was not considered.

The requirements and boundary conditions of the CO‐shift cycle for the CC‐IGCC

with GE‐R are very similar to the case with Siemens gasifier. The only exception is

due to the necessary clean gas expansion in front of the clean gas saturator. Hence,

an additional heat exchanger (for clean gas heating) and an expansion turbine are

added to the cycle. The corresponding process flow diagram can be found in Ap‐

pendix C1.

4.3.2 CO‐shift cycle for the SCGP and the CoP gasifier

Due to the dry gas cooling system at the SCGP and the CoP gasifier, the correspond‐

ing raw gases contain only minor amounts of steam (refer to Fig. 10d). Conse‐

quently the raw gas has to be moisturized in order to achieve acceptable CO‐

conversion rates. The so called cooler/saturator cycle with additional external

steam supply is a common CO‐shift application for “dry” raw gases so that it is cho‐

sen for the aforementioned gasifiers. For both gasifier types the same CO‐shift lay‐

out is used with the only difference that the external steam at the SCGP case is de‐

livered by the convective syngas cooler while the water/steam cycle of the CCPP

supplies the steam at the case with CoP gasifier.

According to the developed layout for a raw gas generated by the SCGP (Fig. 14;

Appendix C2 shows the corresponding process flow diagram for the CoP case) a

good portion of the released reaction heat is transferred to an internal water flow

which is used in a saturator to moisturize the incoming raw gas. Thus the H2O/CO

ratio in the gas is raised to about 1.3. Additionally, external IP‐steam is mixed to

the raw gas leaving the saturator for the purposes of CO‐conversion enhancement


43

and temperature moderation within the first CO‐shift reactor. The additional

steam has to be introduced right after the saturator so that the mixture can be pre‐

heated to the desired temperature. The hot exhaust of reactor 1 is initially cooled

in a feed/effluent heat exchanger and subsequently in a gas/water heat exchanger

against the circulating water flow so that the same feed gas temperature as at the

first CO‐shift reactor can be realized. The circulating flow rate is adjusted in order

to achieve a water inlet temperature to the saturator of 230 °C. The exhaust of the

second CO‐shift reactor is used to preheat the circulating water before it is cooled

and dehumidified in a direct cooler. The bottom product of the saturator becomes

the top feed of the direct cooler after exchanging heat to the clean gas saturator

cycle and the cooling water. Downstream the direct cooler, the most part of the

remaining steam in the converted gas is condensed and discharged before the gas

leaves to the acid gas removal section.

Fig. 14 CO‐shift cycle for a CC‐IGCC with SCGP gasifier

CO-shiftreactor 1

clean gas4-3-gas-4

Clean gassaturator

DGAN1-3-DGAN-1


GT fuel3-8-gas-5

Saturator

Raw gas 2-3-gas-1

IP steam2-3-st-7

CO-shiftreactor 2

Direct cooler

Condensate8-3-wa-3

Condensate3-8-wa-4






44

4.3.3 Modeling and Simulation of the CO‐shift cycle

The process simulation models for the CO‐shift cycle were developed in CHEMCAD

according to the above described flow schemes and descriptions. Same as at the

gasifier simulations, the Soave‐Redlich‐Kwong equation of state is used for the cal‐

culation of the thermodynamic properties. Table 7 provides the typical tempera‐

ture bandwidth and the approach to the thermodynamic equilibrium for raw gas

shift catalysts as well as the chosen boundary conditions for process simulation.

Table 7 Significant process parameters for raw gas shift catalysts

Parameter Unit Literature data

Reference Chosen

tReactor inlet °C 200 … 290 [14; 60] 280

tReactor outlet °C < 500 [60] < 500

Equilibrium approach

K 0a) … 40b) [60] 20

a) Start of run; b) End of run

The simulation results and the corresponding CHEMCAD flow sheets are presented

in the Appendixes C3 to C10.

As mentioned before, the reactor temperature and the CO‐conversion rate are the

most crucial parameters during the process. Since both strongly depend on the

steam content within the raw gas, calculations for different H2O/CO ratios have

been performed. The individual influence is clarified in Fig. 15 for the four differ‐

ent raw gases.


45

Fig. 15 Characteristics of the two‐reactor CO‐shift for different raw gases

As illustrated, the water content within the raw gases of the GE and the Siemens

gasifier is already high enough to achieve comparable CO‐conversion rates and to

avoid process temperatures of more than 500 °C. For the other two raw gases the

steam content has to be raised by internal steam generation (saturator) and exter‐

nal steam addition so that the same level of CO‐conversion can be reached. While

at the SCGP case steam addition is also necessary for temperature moderation, no

temperature restrictions are expected at the CoP case due to the lower CO‐content

within the raw gas leaving the gasifier (refer to Fig. 9).


46

Finally the composition of the gas leaving the CO‐shift cycle to the AGR is provided

in Table 8. Due to the almost same CO‐conversion rate, the gas composition varies

only slightly between the four concepts. Due to the final cooling step, the converted

gases are almost free of steam/water.

Table 8 Gas composition after the CO‐shift cycle

Component

Unit CoP GER SCGP Siemens

H2 mol. % 53.4 54.7 55.9 56.4

CO mol. % 2.0 2.4 2.4 2.4

CO2 mol. % 39.3 40.5 37.5 37.8

Residual mol. % 5.3 2.4 4.2 3.4

4.4 Acid gas removal, CO2compression and sulfur recovery

Physical absorption processes are widely considered as the preferred method for

acid gas removal in a CC‐IGCC [20; 24; 31; 45; 46]. Hence, the acid gas removal unit

investigated in this thesis follows the principle of physical absorption. A process

simulation model based on the industrial Rectisol® technology is developed and

used to investigate the influence of different boundary conditions.

The Rectisol® process using methanol (MeOH) as solvent is chosen due to its supe‐

rior technical characteristics compared to other absorption processes. Kohl and

Nielsen [38] mention the following amenities of the Rectisol® process:

- The considerably higher solubility of acid gases due to possible operating tem‐

peratures of less than ‐60 °C ,

- “the demonstrated ability to separate troublesome impurities that are produced

in the gasification of coal or heavy oil, including hydrogen cyanide, aromatics,

organic sulfur compounds, and gum‐forming hydrocarbons” (p. 1215),

- “The ability to achieve very sharp separations, with H2S concentrations of typi‐

cally 0.1 ppm and CO2 concentrations of just a few ppm in the treated gas” (p.

1216),


47

- A low solvent viscosity even at extreme operating temperatures so that mass

and heat transfer are not significantly impaired,

- The supply of dry and essentially sulfur free carbon dioxide,

- And the generation of a concentrated H2S‐stream suitable for a conventional

CLAUS‐plant.

To get access to the full technical potential, a relative complex process flow scheme

is necessary. This and the need of low level refrigeration leads to high plant costs

so that the Rectisol® technology is mostly applied at difficult gas treating condi‐

tions where other processes are not possible [38].

As the separated CO2 leaves the Rectisol® process essentially free of water and sul‐

fur, it is pressurized without further pretreatment in a multistage compressor.

The CLAUS‐process operated with oxygen enriched air is chosen for sulfur recov‐

ery. The remaining sulfur dioxide containing tail gas is hydrogenated (using hy‐

drogen extracted from the AGR) to hydrogen sulfide and recycled back to the AGR.

In the following the mentioned processes and the developed simulation models are

described in detail. The fundamentals of gas purification are not enlarged herein.

The interested reader is therefore referred to [38; 60; 65]. The developed process

flow schemes take into account the information provided by [23; 38; 48; 60].

4.4.1 Selective acid gas removal and CO2‐compression

According to Fig. 16 the developed acid gas removal process can be described as

follows: At first, the feed gas (a mixture of the shifted gas and the tail gas from the

TGT unit) is cooled against the products in a gas/gas heat exchanger (HE1) before

it is externally cooled (in Ch1) to about 5 °C with cooling energy delivered by the

refrigeration plant. To avoid freezing of the contained water, a minor amount of

methanol is added to the feed gas before it enters the second heat exchanger

(HE2). There it is cooled to sub‐zero temperatures (typically between minus 20

and minus 30 °C) until it enters the pre‐wash stage located at the bottom of the

absorption column. Here the feed gas is exposed to a small quantity of cold, CO2‐

loaded solvent so that troublesome impurities as water, benzene, HCN, NH3, naph‐

thalene and part of the sulfur compounds are absorbed and further routed to the

MeOH/H2O column.


48

Fig. 16 Flow scheme for the AGR unit with refrigeration plant and CO2‐

compressor

The pretreated feed gas flows upwards to the H2S‐absorption level where it is also

faced to the cold and CO2‐loaded methanol. Sulfur compounds as H2S and residual

COS are primarily and almost completely removed due to the good solvent selec‐

tivity caused by the already high CO2‐content. Adjacent, the sulfur free gas runs up

to the CO2‐absorption section where it is charged with methanol at different grades

of purity. While flash regenerated methanol is introduced within the upper third of

the column, ultra‐pure solvent out of the hot regenerator purifies the gas to its re‐

quired CO2‐content at the top of the absorption column. The released heat of ab‐

sorption causes the solvent temperature to increase and therefore the absorption

capacity to decrease. Consequently, an intercooler (Ch2) has been placed in the

lower third of the column in order to enhance the absorbable amount of CO2. Am‐

monia acts as the cooling agent provided by the refrigeration plant. The cold,

desulfurized and CO2‐lean gas leaves the AGR after heat exchange (in HE2 and

HE1) for clean gas dilution and saturation to the CO‐shift unit.

The CO2‐loaded methanol leaving the CO2‐absorber is split so that one part acts as

the solvent for the H2S‐absorber and the pre‐wash stage as already explained. In‐


49

ternal cooling is realized (in HE3) for the purpose of absorption capacity en‐

hancement. The remaining CO2‐loaded solvent is depressurized in the upper part

of the IP‐flash column (Fl 2) in order to release valuable gases. The same is done

with the H2S‐loaded solvent leaving the H2S‐absorber in the lower part of the IP‐

flash column (Fl 1). The valuable gases can either be recompressed (Compr2), wa‐

ter cooled (in Co1) and recycled to the H2S‐absorber or used for hydrogenation in

the TGT process. In the latter case further treatment is necessary (in the absorber)

in order to reabsorb the also released CO2. Depending on the operating pressure of

the system, stepwise flashing and recompression might be advantageous in order

to optimize the auxiliary load consumption.

The H2S‐loaded solvent streams are throttled and fed to the lower section of the IP‐

reabsorber where a part of the contained CO2 is released. As also some of the con‐

tained H2S desorbs out of the solvent, the H2S‐free methanol is introduced to the

top of the reabsorber after external recooling (Ch3) through the refrigeration

plant. There it reabsorbs the released sulfur compounds and therefore keeps the

CO2 essentially sulfur free. Flash regenerated methanol is extracted at the upper

part of the IP‐reabsorber and sent as solvent to the CO2‐absorber. Thus, energy can

be saved at the hot regenerator as not the full solvent stream has to be hot regen‐

erated. The bottom product of the IP‐reabsorber is throttled and fed to the lower

section of the LP‐reabsorber where the remaining CO2 is finally released at the top.

Reabsorption of the released sulfur compounds is realized in the same way as de‐

scribed for the IP‐reabsorber. The released IP‐ and LP‐CO2 is first used for feed gas

cooling (in HE1 and HE2) before it is pressurized in an intercooled multi‐stage

compressor (cooled with cooling water) up to supercritical conditions (100 bar,

30 °C).

The deep temperatures appearing at the desorption process are used to cool the

hot regenerated solvent (in HE4) to its lowest process temperature before entering

the CO2‐absorber.

The flash regenerated solvent leaving the LP‐reabsorber still contains a high

amount of carbon dioxide and nearly all sulfur compounds that were brought in

with the feed gas. As a consequence the cold solvent has to be heated in order to

decrease its absorption capacity for the contained acid gases. In a first step, the

solvent exchanges heat (in HE3) to the CO2‐loaded stream entering the H2S‐


50

absorber and the pre‐wash stage before it is heated to about 70 °C against the hot

regenerated methanol and some volatile gases (in HE5). During this heat exchange

the most part of the contained acid gases already desorb so that they can be

recompressed and recycled after a slight pressure reduction within the hot flash.

This recycling is one possible measure to provide a concentrated H2S‐stream suit‐

able for a conventional CLAUS‐process.

Final solvent purification takes place in the hot regenerator which is heated with

LP‐steam from the combined cycle and with condensing heat from the MeOH/H2O

column. The hot regenerated solvent leaves at the bottom of the column and is

cooled to deep temperatures as already described. One part of the hot regenera‐

tor’s top product (CLAUS‐gas recycle) is routed back to the reabsorber for acid gas

enrichment. The remaining is fed to a scrubber where the contained methanol is

washed out using demineralized water and process condensate so that the CLAUS‐

gas reaches its final quality. The methanol containing water streams are fed to the

MeOH/H2O column where they are thermally separated so that a methanol rich gas

can be withdrawn at the top of the column. The liquid bottom product is send to

the water treatment section while the discharged gas is burned at the SRU.

The deep temperature cooling load (for Ch1, Ch2, and Ch3) is provided by a refrig‐

eration plant based on the vapor‐compression technology.

Ammonia as the chosen refrigeration agent is compressed in a multistage com‐

pressor with intercooling up to about 10 bar. The upper process pressure is de‐

termined by the cooling water temperature at the condenser. After ammonia con‐

densation and heat removal to the cooling water, the process pressure is reduced

in two steps. The lower process pressure has to be defined so that the ammonia

evaporates at a temperature lower than required for internal recooling in Ch1,

Ch2, and Ch3.

The necessary ammonia flow is found depending on the required cooling load after

the process pressures and temperature differences are fixed.


51

4.4.2 Sulfur recovery and tail gas treatment

As mentioned above, the CLAUS‐process operated with oxygen enriched air and a

hydrogenation process are chosen for sulfur recovery and tail gas treatment, re‐

spectively.

Fig. 17 shows the developed flow scheme for the corresponding processes.

Fig. 17 Flow scheme for the sulfur recovery unit and the tail gas treatment plant

The modeled CLAUS‐process consists of a thermal stage (CLAUS‐burner) and two

consecutive catalytic stages with intercoolers in between. According to Schrein‐

er [55] a maximum desulfurization rate of 95 % for the CLAUS‐process itself can be

expected. Furthermore, Schreiner [55] mentioned that the overall sulfur recovery

rate (which comprises the AGR, the SRU and the TGT process) can be as high as

99.8 % when the treated tail gas is recirculated back to the AGR.

The methanol discharge from the AGR unit is incinerated with ambient air at very

high temperatures in the central muffle of the CLAUS‐burner. The CLAUS‐gas itself

reacts with oxygen at temperatures between 950 and 1200 °C according to the fol‐

lowing gross reaction:

10 H2S 5 O2 2 H2S SO2 7 S 8 H2O . (16)


52

The stoichiometry given by Schreiner [55] clarifies that about 70 % of the con‐

tained hydrogen sulfide is converted to elementary sulfur already in the thermal

stage. Leaving the CLAUS‐oven, the hot flue gas is cooled below the sulfur condens‐

ing temperature so that the liquid sulfur can be discharged. Gas cooling is realized

in a heat recovery steam generator (HE1) using boiler feed water extracted from

the combined cycle plant. A part of the hot gas is passed by the steam generator

and used to adjust the inlet temperature to the first catalytic reactor by mixing

with the cooled gas. Further sulfur recovery takes place in two catalytic fixed bed

reactors where the remaining hydrogen sulfide and sulfur dioxide are converted

according to the following:

2 H2S SO2 3 S 2 H2O. (17)

Carbonyl sulfides and carbon disulfides which are primarily generated at the

thermal stage are effectively hydrolyzed at temperatures of about 350 °C in the

first catalytic reactor [55]. Heat recovery and sulfur removal is realized in the same

manner as explained for the thermal stage (in HE2 and HE3). The tail gas is indi‐

rectly heated by IP‐steam condensation in front of the second catalytic rector to

avoid catalyst wetting.

Due to an incomplete H2S‐conversion (caused by the limiting thermodynamic equi‐

librium) and practical restrictions occurring at the sulfur condensation process

(sulfur nebula, [55]) the remaining tail gas still contains considerable amounts of

hydrogen sulfide and sulfur dioxide. Therefore the tail gas is first heated by a

burner to about 200 °C and then fed to the hydrogenation reactor where the fol‐

lowing reaction is promoted by a cobalt‐molybdenum catalyst:

SO2 3 H2 H2S 2 H2O. (18)

Additionally, the contained sulfur vapor is also hydrogenated while the carbon sul‐

fides (COS, CS2) are hydrolyzed so that the remaining tail gas essentially contains

only hydrogen sulfide as sulfur compound. The necessary hydrogen for the hydro‐


53

genation process is supplied by the fuel gas extracted from the AGR. Finally, the

contained water is separated from the tail gas in a scrubber unit and during the

recompression process in the intercooled compressor.

4.4.3 Modeling and Simulation of acid gas removal and treatment

The simulation model for the AGR process was developed in CHEMCAD according

to the above described flow scheme and description. The thermodynamic proper‐

ties were calculated taking into account the work of Chang et al. [5] that extends

the Soave‐Redlich‐Kwong equation of state to methanol systems with light gases

and/or water. The implemented absorption behavior of gases in methanol (visual‐

ized in Fig. 18 for the key gas components) builds the basis for process simulation.

Fig. 18 Calculated solubility of gases in methanol

As an initial examination, the influence of the CO2‐partial pressure in the feed gas is

investigated in order to illustrate the characteristic performance of the AGR pro‐

cess. Therefore calculations are performed using a typical feed gas at different op‐

erating pressures. Specific parameters are introduced for the auxiliary load and the

regenerator steam demand as evaluation criteria. Table 9 shows the boundary

conditions that are defined in order to generate comparable results.


54

Table 9 Boundary conditions for AGR process simulation

Parameter Value

Sulfur compounds within clean gas < 0.1 ppm(v)

Sulfur compounds within CLAUS‐gas ≈ 62 mol. %

Sulfur compounds within removed CO2 < 12 ppm(v)

CO‐content within removed CO2 ≈ 250 ppm(v)

Only a few simulation parameters have to be adjusted in order to comply with the

above given boundary conditions. While the amount of LP‐steam for the hot regen‐

erator is responsible for the clean gas sulfur content, the CLAUS‐gas recycle rate is

used to regulate the sulfur content within the CLAUS‐gas. The CO2‐quality regard‐

ing the sulfur compounds is influenced by the split ratio of the CO2‐loaded metha‐

nol leaving the CO2‐absorber and the split ratio of the H2S‐free solvent to the IP‐

flash. Since the amount of co‐absorbed carbon monoxide increases at higher oper‐

ating pressures, the chosen IP‐flash pressure level strongly affects the CO‐content

within the captured CO2. Therefore it was also found advantageous to realize a

staged IP‐flash expansion (and recompression of the valuable gases) at higher op‐

erating pressures. Table 10 shows the adjusted simulation parameters for the dif‐

ferent investigated operating pressures.

Table 10 Parameter adjustment for AGR process simulation

CO2partial pressure in feed gas 9.5 bar 13.5 bar 19 bar 28.5 bar

Ratio of CO2‐loaded MeOH (out of CO2‐absorber) to the H2S‐absorber

45 % 45 % 45 % 40 %

Ratio of H2S‐free solvent (out of Fl2) to the IP Reabsorber

60 % 60 % 70 % 72 %

CLAUS‐gas recycle rate 42 % 30 % 18 % 0 %

(staged) IP‐flash level [bar] 8.8 11.8 27/15 49/31/20


55

The calculation results for the partial pressure study visualized in Fig. 19a and b

show an increase of the specific auxiliary load consumption and the specific steam

demand at falling CO2‐partial pressures in the feed gas.

Fig. 19 Characteristics of the acid gas removal unit

The curve progression for these parameters can be well expressed by a power

function so that the results are in good agreement with the information provided

by Prelipceanu et al. [51] for an industrial Rectisol® process.

In addition, Fig. 19a shows that the auxiliary load fraction caused by the refrigera‐

tion plant decreases at higher CO2‐partial pressures. This is caused by a reduced


56

solvent flow (as a consequence of higher solubility rates; cf. Fig. 18) and by the en‐

hanced coefficient of performance (COP) for the refrigeration process.

The latter one stands for the quality of the refrigeration plant and is defined as fol‐

lows:

Coefficient of performance COP Q ,

P , . (19)

The COP typically rises at increasing evaporator temperatures (evaporator pres‐

sures) as the pressure ratio for vapor compression decreases. As a consequence of

the higher acid gas solubility, the necessary chiller temperature can be reduced at

increasing CO2‐partial pressures. Hence, the evaporator temperature (evaporator

pressure) of the refrigeration plant can also be increased which yields to an en‐

hanced COP (cf. Fig. 19c and d) and finally to a declining auxiliary load share for

the refrigeration plant.

Further investigations showed that neither the CO/CO2‐rate within the feed gas

nor the CO2‐capture rate influence the specific auxiliary load and the specific steam

demand as long as the CO2‐partial pressure and the above mentioned boundary

conditions (cf. Table 9) are kept constant.

Finally the AGR process including CO2‐compression and the SRU and TGT process

are simulated for the shifted gases that are originally generated by the four differ‐

ent gasifier types. Since the feed gas composition differs only slightly (cf. Table 8),

major distinctions between the individual concepts may only occur due to the

higher feed gas pressure of the gas generated by the GE‐R. The corresponding cal‐

culation results are summarized in Table 11.


57

Table 11 AGR calculation results for different feed gases

CCIGCC based on gasifier: CoP GER SCGP Siemens

CO2‐partial pressure bar 14.1 22.9 13.4 13.4

CO2‐capture rate 99 %

Paux,AGR/SRU/TGT kWh/ kg CO2

0.042 0.034 0.043 0.043

Paux,CO2‐compression kWh/ kg CO2

0,081 0,070 0,081 0,081

Clean gas: H2‐content mol. % 87.7 91.7 89.2 90.4

Clean gas CO‐content mol. % 3.3 4.0 3.9 3.8

Clean gas CO2‐content mol. % 0.5 0.5 0.5 0.5

Clean gas CH4‐content mol. % 4.5 0.3 0 0

Clean gas (N2+Ar)‐content mol. % 4.0 3.5 6.4 5.3

As expected, the higher CO2‐partial pressure favors the feed gas generated by the

GE‐R with regard to the specific auxiliary load. Moreover, the higher operating

pressure allows an elevated reabsorber pressure so that the CO2‐ compression can

start at an enhanced level. Hence, the specific auxiliary load for the CO2‐

compressor is also improved in comparison with the other three gases that have

almost the same CO2‐partial pressure. The detailed results and modeling assump‐

tions can be found in the Appendixes D1 – D15.


58

4.5 Gas turbine

The lion’s share of electric power production in a CC‐IGCC is realized by the gas

turbine as part of the combined cycle power plant. The gas turbine process itself

can be expressed by the Joule‐ or Brayton‐cycle. The thermodynamic fundamentals

are commonly known and described (e.g. [40]) so that they are not reiterated here‐

in.

A hydrogen‐rich gas as it is generated in a CC‐IGCC has a much smaller volumetric

calorific value and a much lower density than natural gas for which power plant

gas turbines are designed for. Therefore, the combustion is characterized by signif‐

icantly higher stoichiometric flame temperatures and a much higher risk of pre‐

ignition and flashback. Hence, the NOx emissions will exceed the natural gas values

and the increased volumetric fuel flow rate will require modifications at the gas

turbine fuel handling system. Operational measures as fuel gas dilution (with

steam and/or nitrogen from the ASU) reduce the adiabatic flame temperature (and

hence the NOx emissions) as well as the flame speed and consequently also the risk

of pre‐ignition and flashback [57].

On the other hand, fuel gas dilution yields to a mass flow mismatch between the

compressor and the turbine section. Consequently, the gas turbine power output

will increase (and may reach the mechanical limit) and compressor surge prob‐

lems can occur (caused by the enlarged pressure ratio). As a result, compressor

mass flow reduction realized by the variable inlet guide vanes and/or air extrac‐

tion for the ASU may avoid these problems [57].

The presented investigations focus on the challenges that arise when a common

power plant gas turbine is fired with hydrogen‐rich fuel instead of natural gas.

Therefore, a generic gas turbine simulation model was developed and used to

study the influence of different boundary conditions to gas turbine performance

and operation.


59

4.5.1 Modeling of the gas turbine process

Reliable gas turbine performance calculations require the consideration of turbine

and combustion chamber cooling as well as the limitations that are caused by this.

The generic gas turbine program is based on a turbine cooling model presented by

Horlock et al. [27] and developed in CHEMCAD. The thermodynamic properties are

calculated using the Soave‐Redlich‐Kwong equation of state.

As indicated in Fig. 20, gas turbine cooling is considered so that the required cool‐

ing air flow is completely extracted after the last compressor stage and introduced

to the hot gas in front of the first turbine vane. This simplification is commonly

accepted and yields to the standardized turbine inlet temperature (TIT; T9 in Fig.

20) [32] which is the decisive factor for the gas turbines level of technology.

Fig. 20 Flow scheme for the gas turbine in a CC‐IGCC


60

The applied cooling model uses a semi‐empirical formula for an estimation of the

required cooling air fraction to avoid turbine material overheating. The derivation

of this equation is extensively described by Horlock et al. [27].Therein two essen‐

tial effects of turbine cooling are carried out:

- The reduction of gas stagnation temperature at the entry to the first turbine row

and

- A pressure loss resulting from mixing the cooling air to the hot gas.

The aerodynamic losses that are expressed by the latter one yield to a degradation

of the polytropic expansion efficiency in contrast to a not cooled turbine.

Jonsson et al. [33] presented an application of the mentioned cooling model to a

commercially available gas turbine for the purpose of performance predictions for

novel cycles. The developed generic model is based on the therein described ap‐

proach. Specific modeling parameters have been adjusted so that the calculated gas

turbine performance matches with published performance data [56] for the Sie‐

mens gas turbine SGT5‐4000F. Detailed information for this reference point calcu‐

lation with natural gas fuel can be found in Appendix E1.

In contrast to Jonsson et al. [33], the gas turbine model shall not be used for design

point calculations but for off‐design calculations with hydrogen‐rich fuel. There‐

fore the model has to be extended so that the turbines swallowing capacity, which

affects the inlet pressure to the turbine section at non‐design conditions, can be

reproduced. According to Traupel [59], the turbine inlet pressure for a fixed gas

turbine only depends on the particular turbine mass flow and the turbine inlet

temperature so that the following equation can be applied:

p9 m9m9,ref

T9T9,ref

1‐πturb,ref2

1‐πturb2 p9,ref (20)

The reference parameters correspond to the natural gas reference case discussed

above. They are summarized in Appendix E2.


61

The available cooling air flow is fixed by the turbine design (reference). Hence, the

cooling air fraction only depends on the compressor end pressure and the losses in

the cooling air ducts. Pardemann [50] therefore suggests and verifies a simplified

method to estimate the cooling air flow for off design calculations as follows:

m8 ∆pcomb∆pcomb,ref

m8,ref (21)

Implementing these correlations qualifies the generic model for off‐design perfor‐

mance calculations and for blade temperature predictions.

4.5.2 Gas turbine process simulation

As mentioned above, fuel gas dilution and compressor air extraction are most like‐

ly necessary in a CC‐IGCC because of the difficulties of hydrogen combustion.

Hence, the generic model is used in a first step to investigate the principle behavior

of some crucial gas turbine parameters at different fuel gas dilution and compres‐

sor air extraction rates. In this context, the blade temperature, the gas turbine

power output and the compressor pressure ratio have been calculated at different

turbine inlet temperatures.

Fig. 21 shows the relative deviation of these parameters from the reference values

at natural gas operation for four different compressor air extraction rates. The

compressor inlet flow has been kept constant at the reference value to suppose full

load operation. The calculations are performed with the purified fuel gas originally

generated by the Siemens gasifier (cf. Table 8) assuming steam (maximum

10 mol. %) and nitrogen dilution in order to adjust a fuel gas hydrogen content

between 45 and 90 mol. %.


62


at constant compressor flow

Considering the results presented in Fig. 21 the following can be noticed: - For a constant TIT, the blade temperature, the compressor pressure ratio and

the gas turbine power output increase at rising fuel gas dilution rates (decreas‐

ing fuel gas hydrogen content).

- Without compressor air extraction and TIT‐reduction, the aforementioned gas

turbine parameters are significantly higher than at reference conditions (natu‐

ral gas fuel).


63

- Without compressor air extraction, the TIT has to be drastically reduced in or‐

der not to exceed the reference values. For clarification refer to Fig. 21a – as‐

suming a possible fuel gas hydrogen content of 67 mol. %:

o The TIT has to be reduced by about 18 K in order not to exceed the refer‐

ence blade temperature (point A),

o the TIT has to be reduced by about 39 K in order not to exceed the reference

compressor pressure ratio (point B),

o the TIT has to be reduced by about 90 K in order not to exceed the reference

gas turbine power output (point C),

- Compressor air extraction reduces the necessary TIT‐reduction to reach the

same values for compressor pressure ratio, power output and blade tempera‐

ture as at reference conditions.

The observed behavior is a consequence of the increased hot gas flow through the

turbine section in comparison to the natural gas reference case. The enlarged hot

gas flow yields to an increase of the compressor pressure ratio, the gas turbine

power output and the blade temperature. The increase of the blade temperature is

a consequence of the almost unchanged cooling air flow in relation to the design

(reference) value. As mentioned above, the cooling air flow is limited through the

turbine design. An increased hot gas flow and an unchanged cooling air flow inevi‐

tably involve an increase of the blade temperature.

Concluding it can be stated that the IGCC‐performance would suffer from the tre‐

mendous TIT‐reduction that is necessary when the gas turbine is operated accord‐

ing to the assumed principle.

For this reason, compressor mass flow reduction is identified as an additional op‐

erational measure. In this way, the hot gas flow through the turbine section is re‐

duced so that the crucial gas turbine parameters can be kept at an acceptable level.

As indicated above, compressor flow control can be technically realized by the var‐

iable inlet guide vane at the entry of the compressor.

Assuming the same boundary conditions, the influence of fuel gas dilution and air

extraction on gas turbine operation is investigated again but now considering the

compressor part load, too. The compressor mass flow is chosen to control the gas

turbine power output so that the reference value may not be exceeded. The hot gas

temperature (T7 in Fig. 20) that can be adjusted via the individual fuel mass flow


64

also acts as a variable but for blade temperature control and TIT control. For all

three temperatures the maximum is defined at the reference value (natural gas).

Fig. 22 illustrates the corresponding results.


at controlled compressor flow


65

As shown, the compressor has to be operated in part load for the complete possi‐

ble fuel gas hydrogen range when air extraction is not applied and the gas turbine

power output must not exceed the reference value. Due to the reduced hot gas

flow, the blade temperature and the TIT are always below the reference value alt‐

hough the hot gas temperature is kept at the maximum.

In the case of 84 000 Sm³ extraction air, the compressor mass flow has to be re‐

duced for power output control at fuel gas hydrogen contents below 79 mol. %.

Additionally, the hot gas temperature has to be derated at this corner point to

avoid a higher blade temperature as at reference conditions. Below this hydrogen

content, the hot gas temperature can be kept at the maximum as the blade temper‐

ature and the TIT stay below the reference. This behavior is also caused by the de‐

creasing hot gas flow.

The behavior at the other two air extraction rates is similar to the latter one with

the difference that the compressor flow has to be reduced only at fuel gas hydro‐

gen contents below 62 mol. % (at 168 000 Sm³/h extraction air) and 51 mol. % (at

252 000 Sm³/h extraction air), respectively. For both cases, the hot gas tempera‐

ture has to be derated at the individual corner point by about 6 K in order to keep

the blade temperature within the limit. Furthermore, a slight hot gas temperature

reduction is necessary within the corner point area to avoid a higher TIT as at ref‐

erence conditions.

In general it can be noticed, that the highest blade temperature is achieved at that

fuel gas hydrogen content where the gas turbines mechanical limit is reached and

its compressor is barely operated at full load flow. The highest TIT is also obtained

within the area of this corner point and its maximum shifts with decreasing air

extraction rates to higher hydrogen contents. The gas turbine efficiency is not illus‐

trated as it makes only sense to consider it in one context with the ASU auxiliary

load. Nevertheless, the range where a high TIT is achieved indicates an optimal gas

turbine performance. The influence to the overall IGCC performance will be clari‐

fied in one of the subsequent chapters.

In a continuative investigation, the gas turbine model and the generated findings

are used to carry on the comparison of the IGCC cycles that are based on the four

different gasifier types.


66

Therefore the individual gases are conditioned so that a fuel gas hydrogen content

of 45 mol. % is adjusted (described in previous chapters). Nowadays this value

represents the upper limit for the fuel gas hydrogen content of advanced power

plant gas turbines (cf. Gräbner [21] and Smith [57]).

Gas turbine operation is simulated considering compressor air extraction of

252 000 Sm³/h for all cases.

Same as above, the compressor mass flow and the hot gas temperature are used to

control the power output and the TIT, respectively so that the reference values are

reached (power output) or not exceeded (temperatures).

Table 12 summarizes some calculation results.

The complete heat and material balances as well as the CHEMCAD flow schemes

can be found in Appendixes E3 to E7.

Table 12 Gas turbine calculation results for different fuel gases


Δmcompressor % 99 94 94 94

ΔThot gas K ‐3 0 0 0

ΔTIT K 0 0 ‐1 ‐1

ΔTblade K 0 ‐3 ‐4 ‐4

As it can be seen, gas turbine operation is very similar for all of the investigated

concepts. The sole noticeable difference is observed at the CoP case where the

compressor mass flow has to be derated only by about one percent compared to

the reference value (instead of 6 % at the other cases). This is caused by the fact

that the fuel gas generated by the CoP gasifier contains a considerable amount of

methane which in turn involves a higher LHV than at the other three cases. As a

consequence the necessary fuel gas mass flow decreases so that the compressor

inlet mass flow can be enlarged to reach the reference power output of 292 MW.

The higher blade temperature at the CoP case is again caused by the augmented

hot gas flow.


67

4.6 The water/steam cycle

The water‐/steam cycle of the CCPP represents the final major sub process within

the direct IGCC process chain. It is powered by the gas turbine exhaust gas and

connected to all of the upstream processes.

Fig. 23 shows the developed flow scheme for the water‐/steam cycle of the CC‐

IGCC. The mayor elements are the heat recovery steam generator (HRSG) and the

steam turbine with condenser. Cooling water heat removal is realized by a conven‐

tional wet cooling tower which however is not part of the further investigation.

The HRSG has three different pressure levels (HP, IP, LP) with one reheat stage and

represents therefore the state of the art design for CCPPs driven by advanced F‐

class gas turbines [21]. Consequently, the steam turbine is characterized by a high

pressure section, an intermediate pressure section and a low pressure section.

Fig. 23 Flow scheme for the water‐/steam cycle in a CC‐IGCC

The arrangement of the HRSG heating surfaces is a result of thermodynamic simu‐

lations aiming at exergy loss minimization. Each pressure level contains economiz‐

er, evaporator and superheater segments which are individually placed so that

they fit optimally to the temperature range of the exhaust gas.

HPEco 3

IP ST

IPRHHP SH


IP EvapCPRH

LP EvapLP SHExhaust gas7-8-eg-2

HP steam3-8-st-8

Exhaust gas to stack8-0-eg-3

G

HP Evap

IP-steam8-2-st-1


LP steam8-2-st-2

LP BFW8-2-BFW-2


GT fuel3-8-gas-5

Fuelpreheater

HP ST

HPEco 2

LP steam2-8-st-6

IP steam8-2-st-3




BFW8-3-BFW-3

LP BFW8-5-BFW-4

LP steam5-8-st-11

IP steam8-5-st-12

LP-steam8-4-st-10

GT fuel8-7-gas-9

Heat recovery steam generator (HRSG)

IP SH

HP steam2-8-st-4

IP BFW8-2-BFW-1

HP/IPEco 1

IP steam2-8-st-5

IP-steam8-3-st-9

Extraction air7-8-air-4

Extraction air8-1-air-5 Air cooler

(LP-evaporator)

LP ST

Condensate (to external CPRH)8-3-wa-3

Condensate (from external CPRH)8-3-wa-4


68

As indicated above, the water‐/steam cycle serves the heat demand of the up‐

stream processes via numerous interfaces. At the same time, it also acts as the

supplier of boiler feed water and superheater for saturated steam which is gener‐

ated for instance at the raw gas cooling section. Furthermore, fuel gas preheating

and cooling of the air that is extracted from the gas turbines compressor are real‐

ized within the cycle.

4.6.1 Modeling and simulation of the water‐/steam cycle

A process simulation model is developed in CHEMCAD according to the above giv‐

en flow sheet. The thermodynamic properties for all gaseous process streams are

calculated by the use of the Soave‐Redlich‐Kwong equation of state. Water and

steam properties are considered corresponding to international standards.

Water‐/steam cycle simulations for CCPPs are common practice in the power plant

business. The ambitious part is always the design of the HRSG. This in turn is pro‐

foundly affected by the chosen temperature differences at the individual pinch

points and approach points. These temperature definitions and the basics of HRSG

design are perfectly described by Lechner [40].

The Q,t ‐ diagram of the HRSG is predestinated to explain the process of boiler de‐

sign. Fig. 24a shows one of a HRSG in a conventional, natural gas fired CCPP.

For a given exhaust gas flow and a chosen HP evaporator pressure, boiler design

takes place as follows:

- First, the temperature difference at the pinch point of the HP evaporator and the

temperature difference between the gas turbines exhaust gas and the tempera‐

ture of live steam and reheat steam have to be chosen.

- Once this is done, the amount of heat available for HP evaporation, superheating

and reheating is fixed.

- Then, heat balance calculations give the HP steam flow as soon as the grade of

sub cooling at the HP evaporator inlet is chosen. The necessary HP feed water is

preheated in staged heating surfaces so that it enters the steam drum just slight‐

ly sub cooled.

- The producible amounts of IP and LP steam are achieved in the same way.


69

As it can be seen in Fig. 24a, the HP path consumes the lion’s share of the exhaust

gas energy. The other two pressure levels are subordinated and preserve only that

heat which is not required at the HP level. Nevertheless, they are necessary in or‐

der to minimize the exhaust gas losses. The quantity of IP steam and LP steam is

directly influenced by the temperature difference at the HP pinch point. It can only

be augmented by an increase of the HP pinch point which however goes at the ex‐

pense of efficiency.

Fig. 24 Q,t – diagram of the heat recovery steam generator

Although HRSG design for a CC‐IGCC follows the same principles, the Q,t – diagram

looks somewhat different. Fig. 24b shows the diagram for the concept based on the

SCGP. As it can be seen, the superheater and the IP reheater consume about 30 %


70

more exhaust gas energy as at the conventional HRSG. At the same time, the heat

flow to the HP evaporator is reduced by this amount. This is caused by the addi‐

tional steam flow received from the CSC which has to be superheated in the HRSG.

Consequently, less energy remains for the HP evaporator and the therein generat‐

ed steam flow decreases. Hence, the heat demand of the HP economizers 2 and 3

also drops, which in turn shifts more exhaust gas energy to the IP evaporator. This

process yields to an increased flow of IP steam and feed water so that the HP/IP

economizer and the LP evaporator consume about the same exhaust gas energy as

at the conventional case. Since the boiler feed water for the CSC is warmed within

the condensate preheater (CPRH), the overall condensate flow is markedly in‐

creased in comparison to the conventional HRSG. A part of the condensate is ex‐

ternally preheated within the CO‐shift cycle as shown in Fig. 14.

With regard to the temperature differences, especially the IP reheater and the

CPRH show considerably lower values in comparison to the conventional HRSG.

This again is a result of the mass flow mismatch caused by the strong integration of

the water‐/steam cycle with the upstream processes.

As the temperature differences and the transferred heat strongly affect the heating

surface area, a comparison of the four CC‐IGCC concepts is conducted. Therefore,

the individual water‐/steam cycles are simulated considering all interfaces to the

other processes. The heating surface areas are calculated according to the follow‐

ing:

A Q ∆

(22)

where k represents the heat transfer coefficient and Δtm the mean logarithmic

temperature difference. In accordance to VDI‐Wärmeatlas [61] a value of

50 W/m²K seems to be a good approximation for the heat transfer coefficient. For

the purpose of concept comparison, this k‐value is kept constant for all heating

surfaces and all compared concepts.

Fig. 25 shows the calculated heating surface areas for the different CC‐IGCC con‐

cepts in comparison to a conventional HRSG. As supposed, the HP superheater and


71

the IP reheater are significantly larger and the HP evaporator and HP economizer

considerably smaller than at the reference boiler. As a result, the IP evaporator and

IP economizer surfaces are sized larger. The heating surface areas for the IP su‐

perheater, the LP evaporator and the CPRH just slightly differ from the reference.

All in all, the GE‐R case shows the highest deviations as the water‐/steam cycle has

to handle the largest amount of saturated HP steam (generated at the RSC and at

the CO‐shift as well).

Fig. 25 Heat surface area for the HRSG in a CC‐IGCC

The overall results are helpful, especially when CCPP operation on back up fuel

(natural gas) has to be considered. For natural gas operation, the heating surfaces

are either too small (e.g. the HP evaporator) or too large (e.g. the IP reheater)

which in fact entails efficiency penalties, caused for instance by a required water

injection to the superheated steam. A detailed economic analysis based on the

planned operating regime (expected operating hours on coal and natural gas as

well as the corresponding fuel prices) is necessary to optimize the HRSG‐design. As

a result the design of the individual heating surfaces might be adjusted. However,

this analysis goes beyond the scope of the presented investigation.


72

At the end, the performance results of the water‐/steam cycle simulations are

summarized in Table 13. In accordance to [21], the auxiliary load of the combined

cycle process is estimated to be 2.2 % of the CCPPs gross power output. The

boundary conditions, the CHEMCAD flow schemes and the heat and material bal‐

ances for the individual cycles can be found in the Appendixes F1 to F9.

Table 13 Performance results of water‐/steam cycle simulation


Psteam turbine, gross MW 175.1 200.7 176.7 169.4

PCCPP, aux MW 10.3 10.8 10.3 10.2

4.7 Air separation unit

Since the air separation unit is the by far biggest auxiliary load consumer of a CC‐

IGCC, special interest is laid on its process description as well as on modeling and

simulation in order to detect optimization potential. As already mentioned, the

ASU not only supplies oxygen to the gasifier and the SRU but also nitrogen to the

pneumatic coal feeding system (only for the SCGP and Siemens gasifiers) and for

fuel gas dilution purposes. The considerable amounts of the diluent nitrogen as

well as the need for gas turbine air integration are responsible for special bounda‐

ry conditions compared to a conventional ASU for chemical processes. Conven‐

tional units usually are designed for quite low operating pressures (approximate‐

ly 5‐6 bar). For CC‐IGCC, an elevated pressure concept might be superior.


73

In the following the cryogenic air separation process is described based on a com‐

mon ASU flow sheet applying the classical double‐column arrangement. Building

on that, a process simulation model is developed and used for simulation of a wide

range of operating scenarios. The specific auxiliary load consumption is calculated

and illustrated dependent on the level of air and nitrogen integration. Based on

that, a decision can be made if a low or an elevated pressure ASU should be ap‐

plied.

The sophisticated three‐column distillation ASU which is supposed to be energeti‐

cally advantageous at operating pressures higher than 12 bar [21] is not consid‐

ered, since there is only one reference unit operating worldwide (AVESTA, Fin‐

land). Therefore, this technology does not represent the state of the art. Moreover,

this configuration is much more complex and inflexible to load changes (ibid, page

77‐78 in AP2001) so that it is rather not qualified for nowadays electricity grid

requirements.

4.7.1 Fundamentals of air separation and process description

The subsequently described process represents one out of a multiplicity of possi‐

ble configurations [21]. It is used to clarify the fundamental coherences while it is

not claimed that the chosen process represents the optimum configuration for

each CC‐IGCC.

Referring to Fig. 26 a conventional cryogenic air separation process can be de‐

scribed as follows: First, the ambient air is compressed in the Main Air Compressor

(MAC) and then cooled and purified from dust, water, carbon dioxide, and other

unwanted impurities.


74

Fig. 26 Process flow diagram of the low pressure air separation unit

In case of gas turbine air integration a part or all of the required air is extracted

from the gas turbine. As air extraction takes place downstream the gas turbine

compressor, the extracted air needs to be expanded (due to the higher pressure

level of common gas turbines) in the hot air turbine to the required operating

pressure of the ASU.

Thereafter, one part of the air is cooled down close to its condensing temperature

(ca. 1 K superheated) within the main heat exchanger (MHE) before it is fed to the

last stage of the high pressure distillation column (lower column). The remaining

part of the air is compressed up to approximately 70 bar in a booster unit with in‐

tercoolers, then liquefied within the MHE and depressurized in the liquid air tur‐

bine for energy recovery and concurrent sub cooling. Subsequently, the liquid air is

split so that one part is throttled (by taking advantage of the Joule‐Thomson‐effect)

and fed to the lower column. The remaining liquid is sub cooled, throttled and fed

to the low pressure distillation column (upper column).


75

The split‐distribution of gaseous and liquid air as well as the specific feed and ex‐

traction stages are optimization parameters that are individually found in order to

compensate the heat losses and fulfill the energy balance.

Within the high pressure column the pre‐separation of air takes place. Due to the

fact that the evaporation temperature of nitrogen is lower than that of oxygen (ar‐

gon is in between), an oxygen‐enriched liquid (about 35 mol. %) accumulates at

the bottom while a nitrogen‐rich vapor rises to the top of the column. After lique‐

faction within the condenser of the high pressure column, one part of the nitrogen‐

rich stream can be extracted as an ultraclean product. Another part is used as re‐

flux for the lower column while the remaining is sub cooled and fed as reflux to the

upper column.

The oxygen‐enriched stream leaving the high pressure column is sub cooled, throt‐

tled and fed to the low pressure column where the final separation takes place. So,

the oxygen product with its desired purity is distilled at the bottom of the upper

column and subsequently pumped to the required pressure before it is evaporated

in the MHE.

At the top of the upper column diluent gaseous nitrogen (DGAN) and a few stages

below a residual gas can be taken off. The individual amount of the latter one af‐

fects the DGAN‐purity and is therefore used for DGAN purity‐adjustment, especial‐

ly at higher operating pressures of the ASU.

Pure liquid nitrogen is extracted at the top of the lower column before it is evapo‐

rated in the MHE. After compression to the required pressure levels it is used as

gaseous nitrogen (GAN) for the coal preparation and feeding process.

Inside the distillation column an intensive contact between liquid and vapor is re‐

alized where both intend to reach the equilibrium state. To achieve this, the rising

vapor needs to lower its oxygen content which is realized by partial condensation

of oxygen. The released condensing enthalpy yields to an evaporation of nitrogen

out of the liquid phase so that the liquid also approaches its equilibrium condition.

Fig. 27 shows the equilibrium composition of boiling oxygen‐nitrogen mixtures at

different pressure levels. The equilibrium data are an integral part of the database

implemented in CHEMCAD. As it can be seen, the dew point curve and the bubble

point curve approach each other at rising operating pressures. Hence, air separa‐


76

tion at higher pressures is hampered and requires a higher number of separation

stages as well as a higher reflux ratio.

Fig. 27 Equilibrium composition of boiling oxygen‐nitrogen mixtures

The pressure difference between the upper and the lower distillation column is a

fundamental factor which significantly influences the operating conditions of the

ASU. is the pressure level is determined so that the nitrogen vapor at the top of the

lower column condensates at a slightly higher temperature (2 … 3 K) as the tem‐

perature of boiling oxygen at the bottom of the upper column. In doing so, the re‐

leased condensing enthalpy can be transferred to the upper column and realize the

heat supply for evaporation. As a consequence, the upper and the lower column

are thermally coupled which means that the condenser of the lower column acts as

the reboiler of the upper one. The determination of pressure levels for the high and

low pressure column is visualized for two different examples in Fig. 28.


77

Fig. 28 Pressure‐dependent boiling temperatures for nitrogen and oxygen and

determination of pressure levels for the distillation column of the ASU

As it can be seen the evaporation temperatures of oxygen and nitrogen depart

from each other with rising pressures. Therefore the necessary pressure difference

(pressure loss) between upper and lower column increases at higher operating

pressures. Fig. 28 illustrates an increase of pressure loss from roughly 4 bar to ap‐

proximately 8 bar when the operating pressure in the lower column is increased

from 5 to 11 bar. Consequently the compression energy for the MAC increases at

higher column pressures. Nevertheless an elevated pressure ASU might be superi‐

or (especially at high DGAN‐demands) since the pressure ratio for DGAN‐

compression is considerable reduced compared to a conventional low pressure

concept.


78

4.7.2 ASU simulation models

For ASU simulation, two different models are developed in CHEMCAD. While the

first model is used for the simulation of a low pressure concept, the second is used

to simulate an elevated pressure one. Both models adopt a similar configuration

and differ only in detail.

The simulation model for the low pressure concept is based on the process ar‐

rangement (Fig. 26) and the description given in 4.7.1.

For the elevated pressure concept, the differences result from the higher distilla‐

tion pressure and influence the necessary compressor and column stages as well

as the compensation of heat losses. To enhance the oxygen yield, a part or the

compressed DGAN is recycled, liquefied and used as reflux for the lower column.

Therefore the air supply to the lower column is omitted. Table 14 summarizes the

main differences between the low and the elevated pressure concept.

Table 14 Main differences between the developed ASU‐models

Component Low pressure ASU Elevated pressure ASU

MAC 3 stages (to 5.8 bar) 4 stages (to 12 bar)

Hot air turbine Expansion to 5.8 bar Expansion to 12 bar

Lower column

35 theoretical stages 45 theoretical stages

5.1 bar pressure 11.3 bar pressure

Upper column

25 theoretical stages 45 theoretical stages

1.3 bar pressure 3.5 bar pressure

GAN compressor 4 stages 3 stages

DGAN compressor 6 stages 4 stages

Residual gas expander No (not possible) Yes (from 3 to 1 bar)

The process flow diagram for the elevated pressure concept can be found in Ap‐

pendix G1. The developed CHEMCAD flow sheets for the low pressure ASU and the

elevated pressure ASU are shown in the Appendixes G2 and G3.


79

The developed process models simulate an interconnection of turbo machineries,

heat exchangers and distillation columns. The first two elements are simply speci‐

fied by setting the efficiency and the pressure ratio and the temperature differ‐

ences respectively. The distillation columns are calculated using the principle of

equilibrium stage. That is to say, that the equilibrium state for each component (air

can be considered as a mixture of nitrogen, oxygen and argon) at each stage is cal‐

culated by solving the so called MESH‐equations (MESH: Material balance, Equilib‐

rium condition, Summation condition, Heat balance) [18]. The equilibrium stage is

also known as the theoretical stage since the practical necessary number of stages

is achieved by considering the stage efficiency. Cubic equations are proved for cal‐

culation of vapor‐liquid equilibriums. Out of these equations, the Peng‐Robinson

equation of state delivers reliable data especially at very low temperatures and is

therefore preferred for the calculation of cryogenic processes. Hence, it has been

chosen for the calculation of thermodynamic properties. Special care has to be tak‐

en for the placement of the feed and extraction stages of the distillation columns. A

steady curve progression for the vapor and liquid composition indicates the cor‐

rect position of the feed streams, as the compositions of the feed streams have to

coincide with the vapor or liquid composition at the corresponding column stage.

In Fig. 29 the vapor and liquid compositions inside the upper column are illustrat‐

ed for the low pressure concept as an example. The steady curve progression indi‐

cates the correct placement of the feed streams.


80

Fig. 29 Vapor and liquid composition inside the low pressure column of the ASU

4.7.3 Simulation of ASU operating scenarios

The auxiliary load for an ASU within a CC‐IGCC mainly depends on the level of air

integration and the DGAN demand for fuel gas dilution. Therefore, the developed

ASU models are used for simulations covering a widespread operating area for

these two factors. The following parameters are defined for process assessment:

Specific auxiliary load: PASU, PASU,VGOX

WS GOX

(23)

Level of air integration: VGT . V ,ASU

% (24)

Specific air integration: KASU, VGT . VGOX

S .S GOX

(25)


81

Specific DGAN demand: KASU,DGANVDGANVGOX

S ³ DGANS ³ GOX

(26)

Specific HP GAN demand: KASU,HP GANVHP GANVGOX

S ³ HP GANS ³ GOX

(27)

Specific LP GAN demand: KASU,LP GANVLP GANVGOX

S ³ LP GANS ³ GOX

(28)

The air demand for the separation process and the available amount of DGAN

slightly vary for the different ASU operating pressures. Hence, the levels of air and

nitrogen integration are ambiguous parameters when comparing air separation

units since they stand for different absolute amounts of extraction air and DGAN.

Therefore, the aforementioned parameters KASU,air and KASU,DGAN are introduced as

alternative expressions.

For ASU processes that have to supply GAN for the coal preparation and feeding

process, the GOX‐specific HP and LP GAN demand have to be considered as well.

The GAN and DGAN demands are not physically influenced by the amount of GOX.

They are only referred to the amount of GOX in order to simplify concept assess‐

ment.

A series of simulations have been conducted for various air integration levels and

specific DGAN demands, both for the low pressure and the elevated pressure con‐

cept as well. The calculations were carried out for an ASU that produces oxygen

and nitrogen for a dry feed entrained flow gasification process in a CC‐IGCC power

plant. The underlying boundary conditions are summarized in Table 15.


82

Table 15 Boundary conditions for ASU simulation

Stream Parameter Value

GOX

Purity 95 mol. %

Conditions 50 bar; 60 °C

HP GAN

Purity < 0.1 mol. % O2


KASU,HP GAN 0.30 Sm³ HP GAN/Sm³ GOX

LP GAN Purity < 0.1 mol. % O2

Conditions > 9 bar (extraction at suitable stage); 30 °C

KASU,LP GAN 0.16 Sm³ LP GAN/Sm³ GOX

DGAN

Purity < 1 mol. % O2

Conditions 34 bar; ≈ 100 °C (as received after last stage)

Ambient air Conditions 15 °C, 1013.25 mbar, 60 % relative humidity

Composition 77.316 mol. % N2, 20.735 mol. % O2, 1.009 mol. % H2O, 0.907 mol. % Ar, 0.033 mol. % CO2

GT extraction air


Composition Same as ambient air

The specific demands of HP GAN and LP GAN are chosen in accordance to Gräbner

et al. [21] and therefore represent typical values for a dry feed entrained flow gasi‐

fication process in a CC‐IGCC.

Fig. 30 exemplifies the calculated auxiliary load distribution for four comparable

operating points.


83

Fig. 30 Auxiliary load distribution of air separation units for a CC‐IGCC

As illustrated, the MAC and the booster consume the main part of the necessary

auxiliary load when extraction air is not used and DGAN is not required (Fig. 30a).

Although DGAN is not necessary, auxiliary load induced by the DGAN compressor

is shown at the elevated pressure concept. This is due to the nitrogen recycle as it

is explained in Chapter 4.7.2.

At the elevated pressure concept, energy can be recovered by the residual gas ex‐

pander since the remaining nitrogen occurs at about 3 bar. As a consequence both

pressure concepts end up at an equal level for the specific auxiliary load.


84

If a high amount of extraction air is used and DGAN is still not required (Fig. 30c),

the booster and the DGAN‐compressor (only at the elevated pressure concept) will

become the major auxiliary load consumer. At this case a considerable amount of

energy can be recovered by the hot air turbine which expands the extraction air to

the operating pressure of the lower column. For this operating point the elevated

pressure concept has already been superior to the low pressure one which is main‐

ly caused by the lower pressure ratio for the booster.

As it can be seen in Fig. 30b and Fig. 30d, a high DGAN demand clearly favors the

elevated pressure concept. The lower pressure ratio for DGAN compression is re‐

sponsible for the auxiliary load advantage. Additionally it has to be mentioned that

at these high DGAN demands the residual nitrogen cannot be used at the expansion

turbine since it is needed to regenerate the molecular sieves.

The overall calculation results are presented in Fig. 31.

Fig. 31 Specific auxiliary load consumption of an air separation unit for a CC‐IGCC

dependent on the operating pressure of the air separation unit


85

The tabulated calculation results can be found in Appendix G4. For the given

boundary conditions, the elevated pressure concept is superior or at least equiva‐

lent to the low pressure concept within the entire operating range. Therefore the

low pressure concept will not be considered for further investigations.

The auxiliary load for the simulated air separation units can be calculated using

equation (29). The corresponding coefficients are summarized in Table 16.

PASU, Z A KASU, B KASU,DGAN W

S GOX (29)

where A, B and Z are simple coefficients.

Table 16 Coefficients for calculation of the specific ASU auxiliary load

Coefficient Unit Low pressure ASU Elevated pressure ASU

Z kWh/Sm³ GOX 0.56654 0.57189

A kWh/Sm³ GOX ‐0.10236 ‐0.11061

B kWh/Sm³ DGAN

0.13809 0.11103

Based on the previous examinations and findings, the ASUs auxiliary load was cal‐

culated for the CC‐IGCC with the four different gasifier types. Table 17 summarizes

the individual boundary conditions and the received simulation results.


86

Table 17 ASU simulation results for the CC‐IGCC based on different gasifiers

Demand & supply Unit CoP GER SCGP Siemens

GOX 103 Sm³/h 74.9 97.2 78.5 78.5

DGAN 103 Sm³/h 165.7 171.5 202.1 195.4

GAN (HP+LP) 103 Sm³/h 1.6 0 38.8 35.5

Extraction air 103 Sm³/h 251.7

Results

Air demand 103 Sm³/h 357.3 449.9 371.4 368.3

Specific air demand Sm³/Sm³ GOX 4.77 4.63 4.73 4.69

Lair,int % 70 56 68 68

KASU,air Sm³/Sm³ GOX 3.4 2.6 3.2 3.2

PASU,aux MW 29.2 39.9 40.1 38.7

PASU,spec kWh/Sm³ GOX 0.39 0.41 0.51 0.49

As shown in Table 17, the ASU for the IGCC power plant with a CoP gasifier re‐

quires the least specific auxiliary load closely followed by the GE‐R case. This dif‐

ference is due to the slightly higher DGAN demand and the higher GOX pressure for

the GE‐R. The other two cases are characterized by a roughly 25 % higher specific

auxiliary load. In turn this is a consequence of the GAN extractions which are not

necessary (or at least at a minor amount) for the GE‐R and the CoP gasifier. These

extractions out of the high pressure column reduce the available reflux to the low

pressure column. The losses can only be outbalanced by the mentioned nitrogen

recycle which in fact is responsible for the higher specific auxiliary load. The minor

differences between the SCGP and the Siemens case are caused by the slightly

higher DGAN and GAN demand at the CC‐IGCC with SCGP.

The heat and material balances for the discussed concepts is provided in the Ap‐

pendixes G5 – G8.

Thermodynamic evaluation of IGCC‐concepts

87

5 Thermodynamic evaluation of IGCCconcepts

Within this chapter, selected IGCC‐concepts are evaluated with respect to their

thermodynamic performance. Therefore, the developed process simulation models

are used to analyze the thermodynamic behavior of different IGCC configurations.

In the first part, a comparative benchmark of the CC‐IGCC concepts based on the

four different gasifier types is accomplished. Subsequently, a study is conducted to

clarify the effects of integration between the gas turbine and the ASU on the overall

IGCC performance. The chapter closes with a survey analyzing the performance

and the CO2‐emissions of IGCC‐concepts designed for different carbon retention

rates (CRR).

5.1 Benchmark of CCIGCCs with different gasifiers

One central goal of this thesis is a comprehensible evaluation of CC‐IGCC concepts

based on four industrial coal gasifiers. The overall concept arrangement and the

individual sub‐processes have already been extensively described in Chapter 4.

The simulation results and the thermodynamic analysis for each of the IGCC sub‐

processes are presented there as well. Therefore, the results only have to be sum‐

marized in the following.

Table 18 shows the most important performance results for the four different con‐

cepts. The thermal heat input to the gasifier is adjusted, so that the gas turbine

generates 292 MW which at the same time represents the defined mechanical shaft

limit.


88

Table 18 Performance summary for CC‐IGCC concepts


Pgas turbine MW 292.0 292.0 292.0 292.0

Psteam turbine MW 175.1 200.7 176.7 169.4

Pexpansion turbine MW ‐ 3.3 ‐ ‐

PIGCC,gross MW 467.1 496.1 468.7 461.4

Pauxiliary load MW 88.4 98.3 103.2 99.4

PIGCC,net MW 378.7 397.8 365.5 362.0

Qcoal MW 1049.1 1129.0 1035.1 1037.8

ηIGCC,gross % 44.5 43.9 45.3 44.5

ηIGCC,net % 36.1 35.2 35.3 34.9

The steam turbine power output at the GE‐R‐concept is about 12 to 15 % higher

than at the other three configurations. This is mainly caused by the concurrent HP‐

steam generation in the radiant cooler and in the CO‐shift cycle. At the other con‐

cepts this kind of heat recovery is only possible either at the gasifier (SCGP and

CoP gasifier) or at the heat recovery section of the CO‐shift cycle (Siemens

gasifier). Hence, the CC‐IGCC with GE‐R also shows the highest net power output

which is roughly 5 % higher than at the CoP‐IGCC and 9 to 10 % higher than at the

configurations based on the other two gasifiers.

The best net efficiency is expected for the concept with CoP gasifier which exhibits

a clear advantage over the other three configurations. Despite of its significantly

better gross efficiency, the SCGP‐concept only reaches a net efficiency which lies

about 0.8 %‐points below the leading value. Fig. 32 illustrates this behavior.


89

Fig. 32 Evaluation of CC‐IGCCs based on different gasifier concepts

As seen in Fig. 32c, the markedly lower auxiliary load fraction for the CoP‐IGCC is

the reason for the highest of all net efficiencies. This is mainly due to the lower

share for the ASU which in turn is achieved by the significant lower demand of gas‐

eous nitrogen for the gasification process (as explained in Chapter 4.7.3).

The concept with GE‐R also shows a clearly lower auxiliary load fraction in com‐

parison with the SCGP‐concept so that the net efficiency for both configurations

ends up at the same level. In spite of a 14 % higher oxygen demand compared to

the SCGP, the ASU for the GE‐R consumes a lower auxiliary load share. This again is

due to the missing demand of gaseous nitrogen for the coal feeding process. Addi‐

tionally, the higher operating pressure at the GE‐R concept results in a lower auxil‐


90

iary load for the AGR and the CO2‐compressor so that the efficiency gap to the

SCGP‐ and the Siemens‐configuration is reduced or even compensated.

The Siemens‐IGCC shows a similar auxiliary load distribution in comparison with

the SCGP case. The slightly different auxiliary load fractions for the ASU and the

gasifier are caused by the different demand of gaseous nitrogen (GAN and DGAN)

and the necessary power for the quench gas recycle compressor at the SCGP. As a

consequence the Siemens‐IGCC shows the weakest of all net efficiencies. However

there is only a small distance to the efficiencies of the CC‐IGCC with SCGP and GE‐R.

An exergetic analysis for the overall IGCC‐concepts is conducted according to the

fundamentals described in chapter 4.2.6. The results are provided inTable 19.

The analysis identifies the gasifier and the gas turbine as the main cause for exergy

destruction. These losses are inevitable since they are caused by the irreversibility

of chemical fuel conversion. While the other sub‐processes contribute only minor

exergy losses, the water‐/steam cycle is responsible for the third largest amount of

exergy destruction. This is basically owed to the necessary temperature differ‐

ences in the HRSG and the irreversibility of energy conversion within the steam

turbine.


91

Table 19 Exergy losses related to the exergy input to the CC‐IGCC

IGCC sub process Unit CoP GER SCGP Siemens

ASU % 2.3 2.7 2.5 2.5

Gasifier % 22.3 25.7 22.1 22.8

CO‐shift % 3.5 2.1 3.7 2.5

AGR/SRU/TGT % 4.4 4.2 4.3 4.3

CO2‐compressor % 2.2 2.0 2.3 2.3

Gas turbine % 21.1 19.7 21.4 21.4

Water‐/steam cycle % 8.3 8.7 8.5 9.4

Residual % 0.8 0.8 0.8 0.8

Exergetic efficiency % 35.1 34.2 34.4 34.0

The exergetic efficiency shows the same differences between the concepts as the

energetic efficiency. These overall distinctions are caused by the individual ones in

the particular sub‐processes. The presented analysis identifies the major causes

for exergy destruction and therefore provides the basis for an exergetic optimiza‐

tion.

Some differences between the four concepts shall be explained in more detail:

- ASU: The CC‐IGCC based on the CoP gasifier shows the least exergy loss which is

due to the lowest demand of GOX. In contrast, the CC‐IGCC with GE‐R has the

highest demand of GOX which accordingly causes the highest of all

exergy losses. Please also see Fig. 10a for clarification.

- Gasifier: The exergetic analysis is already provided in chapter 4.2.6.

- CO‐shift: There are slight advantages for the IGCC‐concepts based on the Sie‐

mens gasifier and the GE‐R. On the one hand, this is due to the lower tempera‐

ture differences at the heat recovery section (with steam generation). On the

other hand, the missing IP‐steam demand (for temperature moderation at the

first CO‐shift reactor) has a positive impact, too.


92

- AGR/SRU/TGT/CO2‐compressor: There are no noteworthy advantages for none

of the four concepts.

- Gas turbine: The CC‐IGCC with GE‐R shows the least (relative) exergy losses. At

a closer look all four concepts have almost the same absolute exergy loss at the

gas turbine process. The lower relative exergy loss is caused by the fact that the

concept with GE‐R needs about 8 to 9 % more coal in comparison to the other

concepts (due to the higher exergy loss at the gasifier).

- Water‐/steam cycle: The differences between the four concepts are caused by

the individual HRSG‐design and the need to apply different tempera‐

ture differences.

With respect to the CO2‐emissions, an equal level can be reached for the IGCC con‐

figurations based on the GE‐R, the SCGP and the Siemens‐gasifier (see Fig. 32d).

Due to the methane content in the gas turbine fuel (see Fig. 32a), the CoP‐IGCC

comes out with a 60 % higher specific CO2‐emission and a five percent lower car‐

bon retention rate (CRR). The latter one is defined as the ratio of carbon atoms in

the captured CO2 related to that in the coal.

As a conclusion of this study, a theoretical efficiency potential of about 1.6 %‐

points can be identified for the SCGP‐IGCC when the gasifier would operate on an

enhanced pressure level (like the GE‐R) and without gaseous nitrogen for the coal

feeding system (assuming a solid feed pump). In this case the higher operating

pressure would cause the auxiliary load fraction of the CO2‐compressor and the

AGR to decline, so that the values of the GE‐R‐case could be reached (each will

bring a rise of 0.3 %‐points for the net efficiency). Additionally, the ASU auxiliary

load fraction would drop to the level of the CoP‐case (as a consequence of the omit‐

ted gaseous nitrogen demand for the coal entry system) which would bring anoth‐

er 1 %‐point increase of the net efficiency.


93

5.2 Level of integration between the gas turbine and the ASU

A further goal of this thesis is to clarify the influence of integration between the gas

turbine and the air separation unit on the overall IGCC performance. The technical

need for air and nitrogen integration and the impact on gas turbine operation have

already been described in Chapter 4.5. The effects of different rates of air extrac‐

tion and nitrogen dilution (DGAN demand) on the performance of the air separa‐

tion process were demonstrated in Chapter 4.7.3. Based on these investigations,

the other sub‐processes of a CC‐IGCC were simulated for four different air extrac‐

tion rates and a range of different nitrogen dilution rates (to adjust a certain fuel

gas hydrogen content). The CC‐IGCC with Siemens gasifier is selected for the study.

The results are presented in Fig. 33.

The operating behavior of the gas turbine as shown in Fig. 22 is decisive. The gas

turbine power output (Fig. 33a) is restricted by the defined mechanical shaft limit

which is kept by controlling the compressor inlet flow.

The steam turbine power output (Fig. 33b) is mainly influenced by the gas turbines

exhaust gas flow which reaches its maximum for a given air extraction rate at the

point where the highest blade temperature is attained. With reference to Chap‐

ter 4.5.2, this point is reached at a fuel gas hydrogen content where the gas turbine

operates at the mechanical shaft limit and its compressor barely runs at full load

flow. At increasing air extraction rates, the amount of steam generated in the ex‐

traction air cooler also increases, which in fact, is the cause for the absolute differ‐

ences between the maxima of the steam turbine power outputs at different air ex‐

traction rates.

The trend of the plants gross efficiency (Fig. 33c) is the same as that for the gas

turbines efficiency. The highest gross efficiency is logically achieved without air

extraction and at the highest of the investigated nitrogen dilution rates. At the

same time, this operating point requires the highest of all auxiliary loads (Fig. 33d).

This is mainly caused by the necessary power for the main air compressor and the

DGAN‐compressor of the ASU. For a given air extraction rate, the auxiliary load

fraction stays about constant within a fuel gas hydrogen range between 79 and

90 mol. %. Within this range the fuel gas is only diluted with steam so that no

DGAN‐compressor load is required. For lower fuel gas hydrogen contents, DGAN

compression causes the auxiliary load fraction to a steady increase.


94

Fig. 33 Impact of ASU and gas turbine integration on the performance of a CC‐

IGCC


95

For fuel gas hydrogen contents between 45 and 65 mol. %, the resulting net effi‐

ciency (Fig. 33e) shows just a marginal difference (max. 0.2 %‐points) among the

various rates of compressor air extraction. Over the full fuel gas hydrogen range a

slight efficiency maximum is noticed for each air extraction rate. This maximum is

found at that point where the turbine inlet temperature for the individual air ex‐

traction rate reaches its maximum, too.

The net power output (Fig. 33f) follows the trend of the steam turbine power out‐

put and shows a clear optimum for each air extraction rate. This optimum also

shifts to the right side of the diagram with decreasing air extraction rates. The

maximum is found at that fuel gas hydrogen content where the gas turbine has al‐

ready operated at the mechanical shaft limit while the compressor barely runs at

full load flow. From Fig. 33f it can be concluded that a higher net power output and

also a higher net efficiency could be reached at a fuel gas hydrogen content of

45 mol. % when a higher compressor air extraction rate would have been consid‐

ered. However, this has not been done since compressor air extraction of

252 000 Sm³/h gives about 7 % air integration which should not be exceeded to

enable a proper start‐up process of the CC‐IGCC [21].

The presented investigation illustrates the influence of the level of integration be‐

tween the gas turbine and the ASU on the performance of a CC‐IGCC under given

boundary conditions. As the generated results are based on generic process simu‐

lation models and special assumptions, they should not be considered as universal‐

ly valid. The investigation should rather be comprehended as a particular case

study presenting an approach to analyze and optimize the integration aspect be‐

tween the gas turbine and the ASU in a CC‐IGCC. Nevertheless, the following find‐

ings are stated to be valid for every other CC‐IGCC application with respect to the

gas turbine and ASU integration:

- The gas turbines operating behavior and limitations are decisive for the identifi‐

cation of the optimal level of integration between the gas turbine and the ASU.

- High levels of air integration are only thermodynamically advantageous at high

levels of nitrogen integration. The thermodynamic benefit of air integration dis‐

appears as soon as higher maximum fuel gas hydrogen contents can be realized

than possible with the nowadays state of the art technology.


96

- For a given compressor air extraction rate, the maximum of net efficiency and

net power output is achieved at that nitrogen integration rate (fuel gas hydro‐

gen content) where the gas turbine is operated at the mechanical shaft limit

while its compressor barely runs at full load flow.

5.3 IGCC concepts with different carbon retention rates (CRRs)

At the end of the thermodynamic assessment, a case study was conducted to clarify

the influence of different CRRs to the IGCC‐performance and the specific CO2‐

emissions. Therefore, four different operating scenarios were defined based on the

overall configuration developed for the concept with Siemens gasifier.

The following measures were found suitable for a reduction of the CRR in a given

overall configuration:

- Capture and compression of the high pressure CO2 while the low pressure CO2 is

vented to the atmosphere; all other things are equal to the reference case,

- Reduction of the CO2‐capture rate in the AGR through a derated solvent flow,

- CO‐shift cycle with just one reactor instead of two while nearly all CO2 is cap‐

tured in the AGR,

- CO‐shift cycle with just one reactor instead of two with a concurrently reduced

CO2‐capture rate in the AGR through a derated solvent flow.

Corresponding to the above mentioned measures, four different IGCC‐cases are

developed and simulated. Fig. 34 shows the generated results in comparison to the

chosen reference case (IGCC‐with Siemens gasifier).


97

Fig. 34 Case study for IGCC‐concepts with different carbon retention rates

The first measure (case 2) does not affect the main process flow since the captured

CO2 is not internally used. Hence, the gross plant performance is identical to the

reference case. Venting the LP‐CO2 stream involves that only the remaining HP‐CO2

has to be compressed. Therefore, the specific auxiliary load demand as well as the

absolute power consumption for the CO2‐compressor decreases in comparison to

the reference case. Consequently, the net power output increases by about 10 MW


98

which implies a 1 %‐point higher net efficiency. At the same time the CO2‐

emissions increase so that a CRR of roughly 60 % is reached.

With respect to case 3, the solvent flow in the AGR is reduced so that about

18 mol. % of CO2 remain in the clean gas. As a consequence, a CRR of about 60 % is

achieved while the auxiliary load fraction for the CO2‐compressor and the AGR de‐

crease. Additionally, the auxiliary load share for the ASU is also lowered since less

nitrogen dilution is necessary to adjust a fuel gas hydrogen content of 45 mol. %.

The auxiliary load savings and the different fuel gas composition are responsible

for an increase of the net power output of about 24 MW and a 2 %‐points efficiency

enhancement, all in comparison to the reference case.

Case 4, characterized by a one‐reactor CO‐shift and a bulk CO2‐removal within the

AGR shows nearly the same performance results as case 2 but features a clear ad‐

vantage with respect to the CRR and the resulting CO2‐emissions. The better per‐

formance compared to the reference case is caused by the reduced auxiliary load

for the ASU, the CO2‐compressor and the AGR. Due to the different arrangement of

the CO‐shift cycle (see Appendix H1 for the corresponding CHEMCAD process

model), more steam can be brought in the gas turbine fuel gas. Therefore, the ASU

auxiliary load fraction is actually lower than at case 3 since the nitrogen dilution

rate can be reduced even more.

The last of the considered measures (case 5) can be seen as a combination of case 3

and case 4. The CRR of 60 % is achieved with a one‐reactor CO‐shift and a concur‐

rent reduction of the solvent flow within the AGR. In doing so, the net efficiency

and the net power output can be increased by about 2.2 %‐points and 26 MW, re‐

spectively, in comparison to the reference case. The ASUs auxiliary load share

brings a 1 %‐point lower efficiency decrease than at the base concept. This is due

to the considerable amounts of CO, CO2 and H2O in the fuel gas which reduce the

necessary quantity of DGAN provided by the ASU. Although the specific auxiliary

load demand for the AGR increases as a cause of the lower CO2‐partial pressure,

the absolute value declines through the reduced solvent flow.


99

The previous case study illustrated the thermodynamic performance for concept

alternatives with a CRR between roughly 60 and 80 %. The lower border for the

CRR was chosen since it marks the level that is common for state of the art com‐

bined cycle power plants driven on natural gas. A configuration with a one‐reactor

CO‐shift cycle and a concurrently reduced CO2‐capture rate within the AGR offers

the best values for efficiency and output when aspiring 60 % carbon retention. A

concept with a two‐reactor CO‐shift cycle and the same CRR exhibits a slightly infe‐

rior performance. A CRR of nearly 80 % is the maximum that can be achieved with

a one‐reactor CO‐shift cycle. Capturing only the HP‐CO2 stream while the LP‐CO2 is

vented to the atmosphere only makes sense when peak load capacity has to be

raised in an already designed plant.

Nevertheless, a final assessment of the reviewed alternatives is only possible in

coherence to an economic evaluation which will be conducted in the following

chapter.

Economic evaluation and optimization

100

6 Economic evaluation and optimization

6.1 Economics of CCIGCC concepts

This chapter illustrates a simplified economic analysis both for the CC‐IGCC con‐

cepts based on different gasifier‐types and for the conducted case study examining

various CRRs. The analysis is based upon the discounted cash flow method and the

procedure as it is applied by Gräbner et al. [21] to several IGCC concepts that use a

world market hard coal and German lignite as feedstock.

The overall project costs (OPC) for the investigated CC‐IGCC concept with Siemens

gasifier are assumed to be the same as those for the hard coal fired IGCC concept

with CO2‐capture in the aforementioned study (OPC = 3,450 €/kW). Hence, the

OPC for the CC‐IGCC with Siemens gasifier come up to 1,249 Mio € considering the

net power output of 362 MW.

The individual OPC‐portions originated by the main subsystems and several other

capital expenditures (CapEx) are also derived from Gräbner et al. [21].

Table 20 summarizes these values.

Table 20 Overall project costs for the CC‐IGCC with Siemens gasifier

Investment cost (price level 2008) for % of OPC Mio €

Gas generation (coal handling, gasification, water treat‐ment)

25.0 312

Gas treatment (CO‐shift/AGR/SRU/TGT) 11.5 144

CO2‐compressor 2.5 31

Combined Cycle 29.0 362

ASU 7.0 87

Infrastructure and utilities 13.0 162

Main spare parts and architect engineer (AE) 3.0 37

Miscellaneous 9.0 112

Sum 100.0 1,249


101

These reference data are used in combination with the individual calculation re‐

sults and a few literature sources to estimate the OPC for the other three CC‐IGCC

concepts. The respective calculation is shown in appendix I1.

Table 21 summarizes the corresponding results.

Table 21 Overall project costs for the CC‐IGCCs with different gasifiers

Investment cost for Unit CoP GER SCGP Siemens

Gas generation Mio € 335 352 419 312

Gas treatment Mio € 137 145 144 144

CO2‐compressor Mio € 30 34 31 31

Combined Cycle Mio € 367 389 368 362

ASU Mio € 84 109 87 87

Direct investment costs Mio € 953 1,029 1,050 936

Infrastructure and utili‐ties

Mio € % of OPC

165 13

179 13

182 13

162 13

Main spare parts and architect engineer

Mio € % of OPC

38 3

42 3

42 3

37 3

Miscellaneous Mio € % of OPC

114 9

124 9

126 9

112 9

Overall project costs (OPC)

Mio € €/kW(net)

1,271 3,357

1,373 3,453

1,400 3,830

1,249 3,450

As it can be seen, the CC‐IGCC with CoP gasifier is expected to have the lowest spe‐

cific OPC while the concept based on the SCGP shows the worst specific OPC (ap‐

proximately 14 % higher than at the CoP‐case).

Table 22 shows the remaining boundary conditions that are necessary to calculate

the cost of electricity (CoE) as the decisive evaluation parameter.


102

Table 22 Other boundary conditions for the economic analysis

Parameter Value Parameter Value

Interest Rate 10 % Maintenance costs 1 % of OPC

Useful life 25 a Costs for taxes and insurances 0.5 % of OPC

Fuel costs 2.6 €/GJ CO2‐transport and storage costs 8 €/t

Miscellaneous costs

10 % of fuel cost

CO2‐emission certificate price 30 €/t

Availability 7315 h/a (= 83.5 %)

Labor costs (60 persons x 65 000 €/a)

3.9 Mio €/a

The above provided data are chosen in accordance to Gräbner et al. [21] represent‐

ing a good basis for a realistic concept assessment. In concordance to Gräbner et

al. [21], the payment dates for the capital expenditures are distributed over the

expected construction period of 5 years. The complete procedure for the CoE‐

determination is explained in the Appendixes I2 and I3.

Fig. 35a illustrates the resulting CoE for the IGCC‐concepts based on the different

gasifiers types. As it can be seen, the concept with CoP gasifier shows slight ad‐

vantages in comparison to the concept with Siemens gasifier and this with GE‐R.

Although to name a clear favorite out of these three concepts seems to be daring

especially when the uncertainties of cost estimation are considered. However, the

concept based on the SCGP is most likely the worst economic choice out of the con‐

sidered concepts since a 7 to 10 % higher CoE has to be expected.

Furthermore, Fig. 35a clarifies the dominant impact of the capital costs to the CoE.

Roughly 60 % of the CoE is owed to the CapEx while the second largest cost driver

(fuel) only takes responsibility for less than a quarter of the CoE. The other cost

components are from minor influence.


103

Fig. 35 Cost of electricity for IGCC‐concepts with carbon capture

Fig. 35b shows the CoE for the concept alternatives with different carbon retention

rates (refer to Chapter 5.3) calculated for a range of CO2‐emission penalties.

Due to the high carbon retention rate, the CoE response to a changing CO2‐

emission penalty is only marginal for the reference case.

The concepts with a reduced CO2‐capture rate are only expected to be markedly

advantageous if no or minor CO2‐emission penalties have to be paid. Under the

given boundary conditions the break‐even‐price for the CO2‐emission penalty is

found to be at about 30 €/t.


104

With respect to the results of case 3 and case 5 it can be summarized, that it does

not matter if the IGCC is equipped with a one‐reactor CO2‐shift or a two‐reactor

CO2‐shift as long as the same CRR is adjusted at the AGR. The capital costs assumed

for the CRR‐analysis can be found in Appendix I4.

The investigation of concept economics closes with a sensitivity study analyzing

the influence of certain cost drivers to the CoE. Fig. 36 visualizes the relative CoE

assuming realistic improvements (target values) for the net efficiency, the plant

availability, the interest rate and the capital expenditures.

Fig. 36 Impact of realistic improvements to the cost of electricity (CoE)

The CapEx reduction promises the highest potential for CoE reduction as the un‐

derlying investment costs are provided with an uncertainty range of ± 30 % [21].

The figure also clarifies the minor influence of efficiency and availability enhance‐

ments (at least in a realistic bandwidth) to the CoE. In contrast, a 20 %lower inter‐

est rate would strongly reduce the CoE. However, the interest rate is driven by the

financial market and a reduced rate would also have to be applied to competing

technologies.


105

In the following, the cost of CO2‐avoidance is introduced as an additional evalua‐

tion parameter. The definition is:

cost of CO2‐avoidanceCoECC‐IGCC,a ‐ CoEconv,a

CO2 emissionconv ‐ CO2 emissionCC‐IGCC

(30)

where

- CoECC‐IGCC,a is the CoE for a CC‐IGCC (excluding the costs for CO2‐penalties),

- CoEconv,a is the CoE for a conventional steam power plant (excluding the costs for

CO2‐penalties),

- CO2 emissionCC‐IGCC are the specific CO2‐emissions for a CC‐IGCC and

- CO2 emissionconv stands for the specific CO2‐emissions for a conventional steam

power plant.

The following example shall illustrate the meaning of the cost of CO2‐avoidance.

Bearing in mind the herein presented simulation results and the aforegoing eco‐

nomic assessment, the following is assumed:

CoECC‐IGCC,a = 108 €/MWh

CoEconv,a = 50 €/MWh

CO2 emissionCC‐IGCC = 65 kg/MWh

CO2 emissionconv = 710 kg/MWh

According to equation (30) the

cost of CO2‐avoidance 108 ‐50710 ‐65

€

MWhkg

MWh 90 €

t .


106

Accordingly, the CoE including the cost of CO2‐avoidance are calculated as

follows:

CoECC‐IGCC 108 €MWh

65kgMWh

* 90€t 114 €

MWh

CoEconv 50 €MWh

710kgMWh

* 90€t

114 €MWh

.

Hence, the calculated cost of CO2‐avoidance gives the price for the CO2‐emission

penalty that is necessary to achieve the same CoE for the CC‐IGCC and the conven‐

tional steam power plant without carbon capture.

Fig. 37 illustrates the so calculated cost of CO2‐avoidance for a CC‐IGCC in compari‐

son to a conventional hard coal fired steam power plant.

Fig. 37 Cost of CO2‐avoidance for a CC‐IGCC

The shaded area in Fig. 37 provides the CoE‐range for state of the art steam power

plants in Germany [62]

The upper (blue) graph applies to the simulated CC‐IGCC with Siemens gasifier

achieving a CRR of about 93 %. The graph shows that the CO2‐emission penalty for

this concept would have to assume 120 €/t (= cost of CO2‐avoidance) to be com‐

petitive with a conventional steam power plant having a CoE (without CO2‐


107

emission penalty) of 30 €/MWh. If this conventional steam power plant only had a

CoE (without CO2‐emission penalty) of 50 €/MWh, the CO2‐emission penalty

would have to assume 90 €/t in order to get CoE‐parity amongst the CC‐IGCC and

the conventional plant.

The middle (red) graph represents a 26 % lower CoE as it would appear if the im‐

provements for efficiency, availability and CapEx (as demonstrated in Fig. 36)

could be realized. Accordingly the CO2‐emission penalty would have to be between

50 and 80 €/t to make this concept competitive to a conventional steam power

plant without CO2‐capture.

The lower (green) curve in Fig. 37 shows that the CoE for a CC‐IGCC has to be re‐

duced by over 50 % (in comparison to the calculated reference value) in order to

be competitive to a state of the art steam power plant without carbon capture. On‐

ly if this CoE‐reduction can be achieved, the CO2‐emission penalties could range

between 0 and 30 €/t. Present day prizes for the CO2‐emission certificate range

between 5 and 15 €/t [12] so that CC‐IGCC for power generation are today far

away from economic feasibility.

Summing up, the following conclusions can be taken from of the economic analysis:

- At present day boundary conditions, CC‐IGCC will only be superior to state of

the art steam power plants if the prices for the CO2‐emission certificates will be

markedly higher than 110 €/t or when the CoE for the CC‐IGCC can be reduced

by more than 50 % in comparison to the calculated values.

- The high Capital Expenditures are the key cost driver for the CoE of CC‐IGCC.

- CC‐IGCC based on the four investigated gasifier technologies show only a slight‐

ly different cost of electricity, especially when the distance to the CoE for state

of the art steam power plants is considered.

- A reduced carbon retention rate (60 %) is only favorable (in comparison to a

CRR of 93 %) at low prices for the CO2‐emission certificate. Since CC‐IGCC can

only be superior to present day steam power plants at high CO2‐emission certif‐

icate prices, a reduced CO2‐capture rate seems to be not an option at all.


108

6.2 Optimized IGCCconcept with enhanced economics

As pointed out in the latter chapter, capital cost reduction is the key to enhance the

economic feasibility of a CC‐IGCC. The economic analysis identified the gas genera‐

tion section and the combined cycle plant as the main CapEx producers as both of

them are responsible for more than 70 % of the direct investment costs.

Table 23 shows the individual shares of the direct investment costs for the five

major subsystems of the CC‐IGCC based on the Siemens gasifier. The provided spe‐

cific costs in €/kW (gross) include the costs for “infrastructure and utilities”, “main

spare parts and architect engineer” and “miscellaneous” as they are originally cal‐

culated as fraction of the overall project costs.

Table 23 Capital costs of a CC‐IGCC assigned to the main sub‐systems

IGCCsubsystem Capital Expenditures

% of direct investment costs €/kW (gross)

Gas generation 33 902

Gas treatment 15 415

CO2‐compressor 3 90

Combined Cycle 39 1,047

ASU 9 253

As it can be seen in Table 23, the Combined Cycle is responsible for the biggest

share of the capital expenditures. Moreover, the calculated specific costs were

found to be markedly higher than for a conventional natural gas fired combined

cycle power plant (NG CCPP). A reference calculation was carried out for a com‐

mon NG CCPP using the software “Thermoflow” which includes a vendor proved

cost library (see Appendix I5). The thereby achieved specific cost of 684 €/kW

confirmed the assumption and showed that the Capital Expenditures for a CCPP in

a CC‐IGCC are roughly 50 % higher in comparison to a common NG CCPP.

These findings initiate the idea to decouple the CCPP from the upstream processes

so that a standardized combined cycle power plant with considerable lower capital


109

expenditures can be applied. To realize this, all interfaces between the water‐

/steam cycle and the other sub‐processes of the CC‐IGCC had to be cut. At the same

time it had to be investigated how the complete water and steam supply for the

consuming processes can be ensured. Heat balance calculations prove that the heat

recovery section of the CO‐shift cycle is able to serve all water and steam consum‐

ers so that a decoupled CCPP can be realized. The modified flow sheet of the CO‐

shift cycle can be found in Appendix I6.

Now, process simulations will show the impact on the performance of the de‐

integrated power plant, henceforth called gasification combined cycle (GCC). The

GCC concept is based on the Siemens gasifier since there is the lowest quantity of

excess steam expected (out of the four gasifier types). The excess steam is that

amount of steam generated in the CO‐shift which is not necessary for the other

sub‐processes of the GCC. Hence, it is expanded in an additional small steam tur‐

bine for power production. Table 24 shows the performance comparison between

the IGCC and the GCC both based on the Siemens gasifier.

Table 24 Performance comparison between IGCC and GCC

Parameter Unit IGCC GCC

Pgas turbine MW 292.0 292.0

Psteam turbine MW 169.4 129.8

Padditional turbine MW ‐ 16.9

PIGCC,gross MW 461.4 438.7

Pauxiliary load MW 99.4 113.8

PIGCC,net MW 362.0 324.9

Qcoal MW 1037.8 941.6

ηIGCC,gross % 44.5 46.6

ηIGCC,net % 34.9 34.5


110

As illustrated in Table 24 the net power output and the net efficiency decrease for

the investigated GCC in comparison to the reference IGCC. On the one hand this

behavior is caused by the omitted ASU integration (refer to Chapter 5.2) and on the

other hand by the lower steam parameters at the heat recovery section of the CO‐

shift cycle. But as pointed out in Chapter 6.1, the achieved performance penalties

will not noticeably influence the CoE.

Table 25 shows the cost of electricity for the investigated GCC concept. In addition

to the reduced expenditures for the CCPP also different CapEx reduction rates are

assumed for the gas island (all sub‐processes except the CCPP).

Table 25 Cost of electricity (CoE) for a GCC concept

CCIGCC (reference)

GCCconcept

CapEx reduction for the gas island

0 % 15 % 50 %

CoE [€/MWh] 110 96 90 76

Relative CoE 100 % 88 % 82 % 69 %

The actual possible CoE‐savings that can be reached by a GCC configuration with

optimized CCPP costs are about 12 % in comparison to the reference IGCC.

If the GCC concept also caused CapEx reductions for the gas island (by the devel‐

opment of standardized sub‐processes with a reduced number of interfaces), addi‐

tional CoE‐savings could be achieved. The CoE could be reduced by 18 % (in com‐

parison to the reference CC‐IGCC) if the CapEx for the decoupled gas island

dropped by about 15 %.

The procedure of CoE‐calculation is identical to the one explained in the Appendix‐

es I1 to I3.


111

Concluding, the following can be noticed with respect to the investigated GCC con‐

cept:

- It is possible to decouple the CCPP from the subsequent processes without ma‐

jor performance penalties.

- The CoE is expected to be markedly lower than for the reference IGCC.

- It is supposed to be easier to realize CapEx‐reductions for a decoupled gas is‐

land than for a highly integrated process (e.g. by standardization and reduction

of the construction time)

- A GCC concept will tremendously reduce financing and risk if the decoupled,

standardized gas island is erected at an existing CCPP.

Executive summary

112

7 Executive summary

Integrated Gasification Combined Cycle (IGCC) power plants are a promising alter‐

native to conventional power generation technologies. Especially the capability to

accomplish almost zero‐emissions of carbon dioxide and hazardous substances is a

unique feature for the IGCC‐technology in a fossil fuel based power generation

market. Nevertheless, IGCC power plants with Carbon Capture (CC‐IGCC) could not

be established on the market so far.

The complexity and the entirely different process technology of CC‐IGCC are sup‐

posed to deter electric utilities from project realization. Indeed, previous descrip‐

tions of the complex correlations within and between the individual sub‐processes

of CC‐IGCC have room for improvement. Moreover, there is a high level of uncer‐

tainty with respect to the economic feasibility of CC‐IGCC.

The objective of this thesis is to provide an extensive description of the correla‐

tions in some of the most crucial sub‐processes for hard coal fired CC‐IGCC. For

this purpose, process simulation models are developed and used to clarify the in‐

fluence of certain boundary conditions on plant operation, performance and eco‐

nomics.

In the beginning, recent studies for IGCC‐concepts are summarized. A closer look is

taken to the published plant performance and the expected cost of electricity

(CoE). Distinctions are made with respect to four different coal gasification tech‐

nologies. These are the Shell Coal Gasification Process (SCGP), the Siemens gasifier,

the ConocoPillips gasifier (CoP) and the General Electric (GE) gasifier. Moreover,

different approaches for concept optimization are analyzed. Most of them investi‐

gated the influence of integration between the gas turbine and the air separation

unit (ASU). A smaller number of studies proposed measures to achieve the opti‐

mum CO2‐capture rate.

The published results show a high fluctuation for the efficiency and the CoE even

for IGCC‐concepts with the same gasifier type. A detailed analysis is carried out for

a few selected studies in order to clarify the cause for these differences. It is found

that some of the studies use greatly different assumptions for process modeling

Executive summary

113

which are not adequately described. The CoE‐fluctuations mainly appear as a re‐

sult of different underlying costs for investment and fuel.

Each of the considered studies that investigate the influence of integration be‐

tween the gas turbine and the ASU provide a clear statement for the correlation

between the efficiency and the level of integration. However, the results of the in‐

dividual studies are partly opposed to each other so that a clear tendency cannot

be derived. The same has to be noticed for the studies investigating the optimal

CO2‐capture rate. Again, a detailed analysis of selected studies is conducted in or‐

der to find the reason for the different results. Same as above, no final clarification

can be derived since different assumptions are used and modeling details are rare.

However, a weak point breakdown provides some basic ideas for the subsequent

adaptation.

In general, the most part of the reviewed literature is criticized since the descrip‐

tions of the individual processes are often inadequate and modeling details are

mostly not provided or rather given in a short deepness. Due to this lack of infor‐

mation, the analysis of results is hindered and general conclusions cannot be de‐

rived. Same as argued by the Massachusetts Institute of Technology [34], the lack

of published modeling details is considered to be a serious handicap for reliable

assessment of complex CC‐IGCC.

As a consequence, the following scope of work is defined for this thesis:

- Process flow diagrams for CC‐IGCC concepts based on the four above men‐

tioned gasifier types have to be designed.

- Sophisticated process simulation models for the main sub‐processes of a

CC‐IGCC have to be developed and applied. Moreover, a substantial descrip‐

tion of global coherences is to be aimed at so that the correlations within

and between the individual sub‐processes can be clearly illustrated.

- The concepts have to be ranked on the basis of an energetic and economic

assessment.

- The influence of integration between the gas turbine and the ASU, under

consideration of thermodynamic and operational aspects, has to be ana‐

lyzed.

Executive summary

114

- Finally, the optimal CO2‐capture rate for a CC‐IGCC has to be identified.

Within the main part of this thesis, process flow diagrams for CC‐IGCC concepts

and sophisticated process simulation models are developed and described. The

concepts based on the four gasifiers are slightly different to each other but on a

common basis. The developed models proof successful simulation for the gasifica‐

tion processes, the CO‐shift cycle, the acid gas removal unit, the sulfur recovery

process, the gas turbine, the water‐/steam cycle and the ASU. Based on this, the

coherences within and between the mayor sub‐processes are extensively dis‐

cussed and described. As a consequence of the achieved high level of detail, model

validation is not possible. However, the plausibility check of results does not indi‐

cate any reasonable doubts on the developed models. Beyond that, the efficiency

for one comparable concept published by Gräbner et al. [20] shows conformity to

the herein presented results.

The comparative benchmark of the CC‐IGCC concepts based on the four different

gasifier types adds up the following:

- The highest net efficiency is expected for the concept with CoP gasifier

(ηIGCC,net = 36.1 %).

- The concepts with the SCGP and the GE‐gasifier with radiant cooler turn out

to reach the same level of efficiency (ηIGCC,net = 35.3 % and 35.2 %, respec‐

tively).

- The concept based on the Siemens gasifier achieves the weakest of all four

efficiencies (ηIGCC,net = 34.9 %). However, there is only a small distance to

the two last mentioned concepts.

- All concepts but the one with CoP‐gasifier can achieve CO2‐emissions as low

as about 65 g/kWh which corresponds to a carbon retention rate of 93 %.

Due to the methane content produced by the CoP‐gasifier, this concept

reaches only about 104 g/kWh (88 % carbon retention rate).

- The concept based on the SCGP is expected to be the worst economic choice

under given boundary conditions. The calculated CoE is 7 to 10 % higher

than at the other three concepts. However, a clear favorite technology out of

these three cannot be named, since the achieved CoE are quite contiguous

(108 – 110 €/MWh).

Executive summary

115

The economic analysis also clarifies the dominant impact of the investment costs.

Roughly 60 % of the CoE is owed to the investment costs while the second largest

cost driver (fuel) only takes the responsibility for less than a quarter of the CoE. In

addition, a sensitivity study brings out that investment cost reduction promises the

highest potential for CoE enhancement. On the other hand, the improvements of

efficiency and availability only have a minor influence to the achievable CoE. Final‐

ly, the cost of CO2‐avoidance compared to a conventional pulverized coal power

plant without CO2‐capture is calculated to be between 90 and 120 €/t of CO2. This

means, that CC‐IGCC at nowadays conditions will only be superior to state of the

art steam power plants if the prices for the CO2‐emission certificates will be mark‐

edly higher than 90 €/t of CO2. Otherwise the CoE for a CC‐IGCC needs to be re‐

duced by over 50 % in order to be economic feasible at present day prices for the

CO2‐emission certificates.

Furthermore, a case study illustrates the thermodynamic performance for concept

alternatives with reduced CO2‐capture rates. The economic analysis shows that a

reduced CO2‐capture rate is only favorable (in comparison to the reference CC‐

IGCC) at low prices for the CO2‐emission certificate. However, economic feasibility

at the present day power generation market is also not given at all.

The analysis of the influence of integration between the gas turbine and the ASU

delivers the following results:

- The gas turbines operating behavior and limitations are decisive for the

identification of the optimal level of integration between the gas turbine

and the ASU.

- High levels of air integration are only thermodynamically advantageous at

high levels of nitrogen integration. The thermodynamic benefit of air inte‐

gration disappears as soon as higher maximum fuel gas hydrogen contents

can be realized than possible with the nowadays state of the art technology.

Executive summary

116

- For a given compressor air extraction rate, the maximum of net efficiency

and net power output is achieved at that nitrogen integration rate (fuel gas

hydrogen content) where the gas turbine is operated at the mechanical

shaft limit while its compressor barely runs at full load flow.

Finally, the previous findings are used to develop an advanced plant configuration

with improved economics. The idea is to decouple the combined cycle power plant

(CCPP) from the upstream processes so that a standardized CCPP with considera‐

ble lower CapEx can be applied. As a consequence of de‐integration, the net effi‐

ciency decreases slightly by about 0.4 %‐points which however does not noticea‐

bly increase the CoE. On the other hand the CoE is expected to decrease by about

18 % through the use of standardized sub‐processes. Moreover, the proposed con‐

cept is expected to be less financially venturous for a first time application of a gas‐

ification based power plant with CO2‐capture.

In summary, IGCC power plants with CO2‐capture are not found to be an economi‐

cally efficient power generation technology at present day boundary conditions.

The field of application is rather assumed to be the combined production of chemi‐

cals and power or the utilization of challenging coals that cannot be handled at

conventional fired power plants. In this regard, the unique features of IGCC‐

technology can be better accentuated.

Appendix

117

Appendix

Appendix A – Nomenclature of the process streams used in the flow schemes

The nomenclature of the process streams has to be interpreted as follows:

source process – target process – fluid – serial number.

The source and target processes were numbered as follows:

0 Battery Limits / Ambient

1 Air Separation unit (ASU)

2 Gasifier

3 CO‐shift

4 Acid gas removal (AGR)

5 Sulfur recovery unit (SRU)

6 CO2‐compression

7 Gas turbine

8 Water steam cycle

9 Cooling system

10 Water treatment

The following abbreviations were used for the fluids:

Coal Coal

GOX Gaseous oxygen

GAN Gaseous nitrogen

DGAN Diluent nitrogen

Gas Flammable gas

eg Exhaust gas

st Steam

BFW Boiler feed water

Slag Slag

wa Process water / process condensate

cond Condensate (from clean steam)

Appendix

118

mu Make up water

ww Waste water

cw Cooling water

CO2 Carbon dioxide

met Methanol

S Sulfur

Example: 2‐3‐st‐7 means:

From Gasifier – To CO‐shift – Fluid: Steam – ongoing steam stream

number in the overall IGCC flow scheme: 7

Appendix B1 – Deviation from the equilibrium temperatures in K

Reaction SCGP Siemens GE CoP

1st stage 2nd stage

C + O2 ↔ CO2 0 0 0 ‐150 ‐50

C + CO2 ↔ 2 CO ‐330 ‐310 0 ‐150 ‐50

CO + 3 H2 ↔ CH4 + H2O 10 0 ‐320 ‐150 ‐50

CO + H2O ↔ H2 + CO2 ‐280 0 0 ‐150 ‐50

H2 + S ↔ H2S 0 0 0 ‐150 ‐50

CO + S ↔ COS ‐45 0 24 ‐150 ‐50

N2 + 3 H2 ↔ 2 NH3 0 0 0 ‐150 ‐485

N2 + H2 +2 C ↔ 2 HCN 0 0 0 ‐150 ‐50

Cl2 + H2 ↔ 2 HCl 0 0 0 ‐150 ‐50

Appendix

119

Appendix B2 – CHEMCADflow sheet for the model of the SCGP

1

2 31

H2O

_raw

coa

l

coal

_waf

ash_

raw

coa

l

2

4

3

air

4

5

7ra

w c

oal

burn

er

fan

drye

r

1113

6

8

8

10

9

6

10

7

5

1617

LP G

AN

fuel

gas

16

20 15

21

9

3317

28ex

haus

t gas

32

11

26

HP

GA

N

drie

d co

al

12

14

21

12

13

14

1518

24 25

27

29

30

19

22

23

34

36

3719

31

35 41

56

40

GO

X mod

. ste

am

2425

HP

CSC

26

27

28IP

CSC

4346

49

31

51

29 30

32

47

33

34

38

3961

35

GO

X PR

H

3663

64

65

37

52

42

57

HP

stea

m

54

53

IP B

FW

IP s

team

66

HP

BFW

pum

p

38

50

20

23

2239

40

18

69

70

68

58

59

67

55

44

recy

cle

fan

4148 71 slag

42

73

4456

72

43

74

45

76

75

77

46

78

79

4780

81 scru

bber

mak

e up

wat

e

was

te w

ater

raw

gas

4849

83

cool

scr

een

IP B

FWIP

ste

am

ID

1 T

15.

0 C

P 1

.0 b

ar W

104

950

kg/h

ID

2 T

15.

0 C

P 1

.0 b

ar W

887

7 kg

/h

ID

3 T

15.

0 C

P 1

.0 b

ar W

662

5 kg

/h

ID

4 T

15.

0 C

P 1

.0 b

ar W

120

452

kg/h

ID 1

1 T

400

.4 C

P 1

.10

bar

W 4

8029

kg/

h M

190

3 km

ol/h

ID

8 T

101

9.5

C P

9.6

6 ba

r W

160

56 k

g/h

M 5

89 k

mol

/h

ID

5 T

15.

0 C

P 1

.00

bar

W 1

3763

kg/

h M

477

km

ol/h

ID

6 T

10.

0 C

P 3

3.38

bar

W 4

27 k

g/h

M 8

5 km

ol/h

ID

9 T

30.

0 C

P 9

.66

bar

W 1

4933

kg/

h M

533

km

ol/h

ID 3

3 T

30.

0 C

P 9

.66

bar

W 1

866

kg/h

M 6

7 km

ol/h

ID 2

8 T

75.

1 C

P 1

.10

bar

W 5

4716

kg/

h M

206

6 km

ol/h

ID 3

7 T

43.

3 C

P 4

8.0

bar

W 1

2354

9 kg

/h

ID 1

4 T

107

.0 C

P 1

.10

bar

W 3

1973

kg/

h M

131

4 km

ol/h

ID 3

4 T

60.

0 C

P 5

0.00

bar

W 1

0714

1 kg

/h M

333

1 km

ol/h

ID 4

1 T

412

.6 C

P 5

1.00

bar

W 1

9440

kg/

h M

107

9 km

ol/h

ID 3

1 T

43.

3 C

P 4

8.0

bar

W 1

2354

9 kg

/h

ID 3

6 T

200

.0 C

P 4

9.00

bar

W 1

0714

1 kg

/h M

333

1 km

ol/h

ID 4

6 T

424

.7 C

P 3

9.75

bar

W 5

6611

0 kg

/h M

278

48 k

mol

/h

ID 6

3 T

153

.4 C

P 5

1.00

bar

W 2

4193

0 kg

/h ID

65

T 1

53.4

C P

51.

00 b

ar W

603

47 k

g/h

ID 6

4 T

153

.4 C

P 5

1.00

bar

W 1

8158

3 kg

/h

ID 5

1 T

153

.4 C

P 5

1.00

bar

W 6

0347

kg/

h

ID 3

8 T

265

.2 C

P 5

1.00

bar

W 6

0347

kg/

h

ID 5

2 T

100

.0 C

P 5

0.00

bar

W 6

144

kg/h

ID 4

5 T

336

.2 C

P 1

39.5

0 ba

r W

181

583

kg/h

ID 3

9 T

265

.2 C

P 5

1.00

bar

W 6

144

kg/h ID

42

T 1

449.

9 C

P 4

0.00

bar

W 2

5012

7 kg

/h M

120

49 k

mol

/h

ID 5

4 T

156

.3 C

P 1

43.0

0 ba

r W

181

583

kg/h

ID 6

1 T

265

.2 C

P 5

1.00

bar

W 6

144

kg/h

ID 5

8 T

274

.2 C

P 3

9.50

bar

W 3

2508

3 kg

/h M

159

66 k

mol

/h

ID 6

8 T

274

.2 C

P 3

9.50

bar

W 5

7001

1 kg

/h M

279

87 k

mol

/h

ID 7

1 T

15.

0 C

P 4

0.00

bar

W 9

100

kg/h

ID 4

4 T

274

.2 C

P 3

9.50

bar

W 6

90 k

g/h

ID 6

9 T

15.

0 C

P 3

9.50

bar

W 6

90 k

g/h

ID 7

0 T

49.

9 C

P 1

.10

bar

W 1

1625

1 kg

/h

ID 6

7 T

70.

0 C

P 7

0.00

bar

W 3

902

kg/h

M 1

39 k

mol

/h

ID 5

6 T

274

.2 C

P 3

9.50

bar

W 2

4423

9 kg

/h M

119

95 k

mol

/h

ID 8

1 T

109

.8 C

P 4

5.00

bar

W 1

2325

9 kg

/h M

683

5 km

ol/h

ID 7

3 T

138

.2 C

P 3

9.00

bar

W 2

5822

2 kg

/h M

127

77 k

mol

/h

ID 7

9 T

15.

0 C

P 5

0.00

bar

W 3

6000

kg/

h M

199

8 km

ol/h

ID 7

7 T

149

.3 C

P 3

9.00

bar

W 2

2016

kg/

h M

121

6 km

ol/h

ID 7

4 T

147

.8 C

P 3

9.00

bar

W 1

0907

4 kg

/h M

604

6 km

ol/h

ID 7

8 T

147

.8 C

P 3

9.00

bar

W 8

7259

kg/

h M

483

7 km

ol/h

ID 5

7 T

825

.0 C

P 4

0.00

bar

W 5

6611

0 kg

/h M

278

48 k

mol

/h

ID 5

3 T

153

.4 C

P 5

1.00

bar

W 1

8158

3 kg

/h ID

62

T 1

54.8

C P

52.

60 b

ar W

235

786

kg/h

ID 6

0 T

264

.7 C

P 5

0.60

bar

W 5

4203

kg/

h

ID 6

6 T

100

.0 C

P 5

1.00

bar

W 6

144

kg/h

ID 5

0 T

275

.2 C

P 3

9.50

bar

W 5

6611

0 kg

/h M

278

48 k

mol

/h

ID 2

0 T

70.

0 C

P 7

0.00

bar

W 3

1901

kg/

h M

113

9 km

ol/h

ID 1

8 T

50.

0 C

P 1

.1 b

ar W

115

561

kg/h

ID 5

9 T

319

.7 C

P 5

0.00

bar

W 3

2508

3 kg

/h M

159

66 k

mol

/h

ID 5

5 T

274

.2 C

P 3

9.50

bar

W 5

6932

2 kg

/h M

279

61 k

mol

/h

ID 8

2 T

154

.8 C

P 5

2.60

bar

W 3

3688

kg/

h

ID 8

4 T

264

.7 C

P 5

0.60

bar

W 3

3688

kg/

h

63

6210

3

64

104

60

65

45

105

66

82

106

67

84 107

Appendix

120

Appendix B3 – Heat and material balance for the model of the SCGP

stream ID 0‐2‐coal‐1 0-2-air-1 1-2-GOX-1 1-2-GAN-1 1-2-GAN-2 4-2-gas-2 8-2-st-1 8-2-BFW-1 10-2-mu-1 2‐0‐eg‐1 2‐0‐slag‐1 2‐3‐gas‐1 2-3-st-7 2‐8‐st‐4 2‐10‐ww‐1name raw coal air GOX HP GAN LP GAN fuel gas IP steam IP BFW make up water exhaust gas slag raw gas IP steam HP steam waste watert °C 15.0 15.0 60.0 70.0 30.0 10.0 412.6 154.8 15.0 73.8 138.2 264.7 336.2 149.3p bar 1.0 50.0 70.0 9.7 33.4 51.0 52.6 50.0 1.1 39.0 50.6 139.5 39.0m kg/s 34.634 3.957 30.807 9.173 4.294 0.123 5.590 76.091 10.351 15.733 2.616 74.248 24.924 51.167 6.330n kmol/s 0.137 0.958 0.327 0.153 0.024 0.310 4.224 0.575 0.594 3.674 1.384 2.840 0.350V Nm³/h 11,067 77,281 26,415 12,365 1,974 47,928 296,445LHV kJ/kg 29,887 45,142 11,226HHV kJ/kg 31,116 53,031 11,862h kJ/kg -99 22 38 3 -1,333 -12,757 -15,328 -15,919 -1,531 -4,373 -13,190 -13,324 -15,161s J/kgK 128 -873 -1,141 -656 -4,664 -2,729 -7,522 -9,184 4 1,634 -3,447 -4,056 -7,495M kg/kmol 28.85 32.16 28.02 28.02 5.02 18.01 18.01 18.01 26.49 20.21 18.01 18.01 18.10

Σ mol % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mol % 89.15 0.00 28.11 0.01CO mol % 3.85 0.00 54.55 0.02CO2 mol % 0.03 0.50 0.19 1.95 0.00N2 mol % 77.31 1.94 99.91 99.91 5.54 79.59 4.07 0.00Ar mol % 0.91 3.06 0.03 0.03 0.92 0.27 0.80 0.00CH4 mol % 0.03 0.00 0.03 0.00O2 mol % 20.74 95.00 0.06 0.06 0.00 2.91 0.00 0.00H2O mol % 1.01 0.00 100.00 100.00 100.00 17.05 9.67 100.00 100.00 99.32H2S mol % 0.00 0.00 0.76 0.01COS mol % 0.00 0.00 0.07 0.05SO2 mol % 0.00 0.00 0.00 0.00S mol % 0.00 0.00 0.00 0.00HCN mol % 0.00 0.00 0.00 0.00NH3 mol % 0.00 0.00 0.00 0.40CH3OH mol % 0.00 0.00 0.00 0.04HCl mol % 0.00 0.00 0.00 0.14

Σ mass % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 0.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mass % 0.00 0.00 0.00 35.78 0.00 2.80 0.00CO mass % 0.00 0.00 0.00 21.49 0.00 75.61 0.03CO2 mass % 0.05 0.00 0.00 0.00 4.39 0.31 4.24 0.00N2 mass % 75.06 1.69 99.89 99.89 30.90 84.18 5.64 0.00Ar mass % 1.26 3.80 0.04 0.04 7.31 0.40 1.58 0.00CH4 mass % 0.00 0.00 0.00 0.09 0.00 0.02 0.00O2 mass % 23.00 94.51 0.07 0.07 0.00 3.51 0.00 0.00H2O mass % 5.50 0.63 0.00 0.00 0.00 0.00 100.00 100.00 11.60 8.62 100.00 100.00 98.84H2S mass % 0.00 0.00 0.00 0.00 0.00 1.28 0.02COS mass % 0.00 0.00 0.00 0.00 0.00 0.20 0.18SO2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.01HCN mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.60NH3 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.04CH3OH mass % 0.00 0.00 0.00 0.03 0.00 0.00 0.00HCl mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.28coal mass % 87.13 0.00 0.00 0.00 0.00 0.00 0.00 0.00ash mass % 7.37 0.00 0.00 0.00 0.00 0.00 97.58 0.00 0.00C mass % 0.00 0.00 0.00 0.00 0.00 2.42 0.00 0.00solids mass % 94.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 100.00 0.00 0.00 0.00 0.00

Appendix

121

Appendix B4 – CHEMCADflow sheet for the model of the Siemens gasifier

1

2 31

H2O

_raw

coa

l

coal_

waf

ash_

raw

coal

2

4

3

air

4

5

7ra

w co

al

burn

er

fan

drye

r

1113

6

8

8

10

9

6

10

7

5

1617

LP G

AN

fuel

gas

16

20 15

21

9

3317

28ex

haus

t gas

32

11

26

HP G

AN

dried

coa

l

12

14

21

12

13

14

1518

24 25

27

29

30

19

22

23

36

3719

31

35 41

56

GO

X

mod

. ste

am

GO

X PR

H

20

23

22

4849

83

cool

scre

en

IP B

FW

18

24

25

26

27

29

30

31

33

34

36

3738

40

4142

4344

45

4750

55

6667

60

40

42

89

39

56

59

quen

ch w

ater

IP s

team

68

57 61

filter

cak

e

58

90

59

43

52

58

63

44

69

46

scru

bber

1scru

bber

2

54

48

49

70

73

raw

gas

wast

e wa

ter

ID

1 T

15.

0 C

P 1

.0 b

ar W

104

950

kg/h

ID

2 T

15.

0 C

P 1

.0 b

ar W

887

7 kg

/h

ID

3 T

15.

0 C

P 1

.0 b

ar W

662

5 kg

/h

ID

4 T

15.

0 C

P 1

.0 b

ar W

120

452

kg/h

ID

11 T

399

.6 C

P 1

.10

bar

W 4

7644

kg/

h M

188

7 km

ol/h

ID

8 T

101

9.3

C P

9.6

6 ba

r W

160

61 k

g/h

M 5

89 k

mol

/h

ID

5 T

15.

0 C

P 1

.01

bar

W 1

3765

kg/

h M

477

km

ol/h

ID

6 T

10.

0 C

P 3

3.05

bar

W 3

96 k

g/h

M 8

4 km

ol/h

ID

9 T

30.

0 C

P 9

.66

bar

W 1

4884

kg/

h M

531

km

ol/h

ID

33 T

30.

0 C

P 9

.66

bar

W 1

900

kg/h

M 6

8 km

ol/h

ID

28 T

73.

8 C

P 1

.10

bar

W 5

4570

kg/

h M

206

1 km

ol/h

ID

37 T

43.

4 C

P 4

8.0

bar

W 1

2283

6 kg

/h

ID

14 T

104

.0 C

P 1

.10

bar

W 3

1584

kg/

h M

129

8 km

ol/h

ID

34 T

60.

0 C

P 4

9.96

bar

W 1

0678

8 kg

/h M

332

0 km

ol/h

ID

41 T

412

.6 C

P 5

1.00

bar

W 1

9008

kg/

h M

105

5 km

ol/h

ID

31 T

43.

4 C

P 4

8.0

bar

W 1

2283

6 kg

/h

ID

36 T

200

.0 C

P 4

8.96

bar

W 1

0678

8 kg

/h M

332

0 km

ol/h ID

39

T 2

65.2

C P

51.

00 b

ar W

612

3 kg

/h

ID

20 T

70.

0 C

P 7

0.00

bar

W 2

7908

kg/

h M

996

km

ol/h

ID

82 T

154

.8 C

P 5

2.60

bar

W 2

6899

kg/

h

ID

42 T

144

9.7

C P

40.

00 b

ar W

248

628

kg/h

M 1

1996

km

ol/h

ID

84 T

265

.2 C

P 5

1.00

bar

W 3

3022

kg/

h

ID

18 T

50.

0 C

P 1

.1 b

ar W

115

561

kg/h

ID

62 T

200

.9 C

P 4

8.00

bar

W 2

6645

7 kg

/h ID

56

T 2

00.0

C P

48.

00 b

ar W

252

000

kg/h

ID

38 T

100

.0 C

P 5

0.00

bar

W 6

123

kg/h

ID

61 T

15.

0 C

P 3

9.45

bar

W 1

6862

kg/

h

ID

90 T

218

.9 C

P 3

9.45

bar

W 4

9801

8 kg

/h M

261

75 k

mol/

h ID

43

T 2

17.0

C P

39.

35 b

ar W

923

04 k

g/h

M 5

123

kmol/

h

ID

52 T

217

.0 C

P 3

9.35

bar

W 1

8461

kg/

h M

102

5 km

ol/h

ID

69 T

217

.2 C

P 4

5.00

bar

W 7

3843

kg/

h M

409

9 km

ol/h

ID

46 T

187

.8 C

P 4

5.00

bar

W 8

7343

kg/

h M

484

8 km

ol/h

ID

47 T

216

.5 C

P 3

9.35

bar

W 4

9305

8 kg

/h M

258

99 k

mol/

h

ID

89 T

216

.6 C

P 4

9.00

bar

W 1

4457

kg/

h

ID

73 T

188

.7 C

P 4

5.00

bar

W 9

1807

kg/

h M

509

6 km

ol/h

ID

60 T

214

.5 C

P 3

9.00

bar

W 4

7683

0 kg

/h M

249

99 k

mol/

h

ID

70 T

15.

0 C

P 5

0.00

bar

W 1

3500

kg/

h M

749

km

ol/h

ID

64 T

15.

0 C

P 5

0.00

bar

W 1

3500

kg/

h M

749

km

ol/h

ID

49 T

216

.6 C

P 4

5.00

bar

W 7

8307

kg/

h M

434

7 km

ol/h

ID

67 T

150

.0 C

P 3

9.00

bar

W 3

3936

kg/

h M

187

9 km

ol/h

ID

50 T

216

.4 C

P 3

9.25

bar

W 9

7883

kg/

h M

543

3 km

ol/h

ID

54 T

216

.4 C

P 3

9.25

bar

W 1

9577

kg/

h M

108

7 km

ol/h

64

79

32

4551

ID

45 T

215

.8 C

P 3

9.25

bar

W 4

8698

1 kg

/h M

255

62 k

mol/

h

ID

79 T

15.

0 C

P 5

0.00

bar

W 2

7000

kg/

h M

149

9 km

ol/h

62

28

53

35 39

84

ID

53 T

144

.8 C

P 5

1.00

bar

W 3

3022

kg/

h

ID

71 T

264

.7 C

P 5

0.60

bar

W 2

6899

kg/

h

46

38

65

72

ID

65 T

265

.2 C

P 5

1.00

bar

W 6

123

kg/h

34

4750

part.

cond

.

75LP

BFW

ID

74 T

154

.2 C

P 1

4.00

bar

W 9

299

kg/h

ID 1

07 T

164

.5 C

P 6

.90

bar

W 9

299

kg/h

mak

e up

wat

er

77

93

81

66

7410

467

8210

5

68

7110

6IP

ste

am

69

107

76

LP s

team

Appendix

122

Appendix B5 – Heat and material balance for the model of the Siemens

gasifier

stream ID 0-2-coal-1 0-2-air-1 1-2-GOX-1 1-2-GAN-1 1-2-GAN-2 3-2-wa-2 4-2-gas-2 8-2-st-1 8-2-BFW-1 8-2-BFW-2 10-2-mu-1 2-0-eg-1 2-0-slag-1 2-3-gas-1 2-8-st-5 2-8-st-6 2-10-ww-1name raw coal air GOX HP GAN LP GAN quench water fuel gas IP steam IP BFW LP BFW make up water exhaust gas filter cake raw gas IP steam LP steam waste watert °C 15.0 15.0 60.0 70.0 30.0 200.0 10.0 412.6 154.8 154.2 15.0 73.8 214.5 264.7 163.4 150.0p bar 1.01 50.0 70.0 9.7 48.0 33.0 51.0 52.6 14.0 50.0 1.1 39.0 50.6 6.6 39.0m kg/s 34.722 3.968 30.783 8.045 4.291 72.643 0.114 5.479 7.599 2.681 7.783 15.731 4.861 137.454 7.599 2.681 9.782n kmol/s 0.138 0.957 0.287 0.153 4.032 0.0242 0.304 0.422 0.149 0.432 0.594 7.206 0.422 0.149 0.542V Nm³/h 11,097 77,223 23,166 12,355 1,954 47,929 581,466LHV kJ/kg 29,887 48,741 6,049HHV kJ/kg 31,116 57,267 6,418h kJ/kg -99 22 38 3 -15,124 -1,415 -12,757 -15,328 -15,330 -15,919 -1,535 -8,492 -13,190 -13,221 -15,243s J/kgK 124 -873 -1,141 -656 -7,080 -5,021 -2,729 -7,522 -7,528 -9,184 4 -472 -3,447 -2,681 -7,529M kg/kmol 28.85 32.16 28.02 28.02 18.02 4.71 18.01 18.01 18.01 18.01 26.48 19.07 18.01 18.01 18.06

Σ mol % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mol % 0.00 0.00 0.00 0.00 0.00 90.35 0.00 0.00 0.00 0.00 0.00 15.40 0.00 0.00 0.00CO mol % 0.00 0.00 0.00 0.00 0.00 3.83 0.00 0.00 0.00 0.00 0.00 26.78 0.00 0.00 0.00CO2 mol % 0.03 0.00 0.00 0.00 0.01 0.50 0.00 0.00 0.00 0.00 0.19 2.03 0.00 0.00 0.00N2 mol % 77.31 1.94 99.91 99.91 0.00 4.35 0.00 0.00 0.00 0.00 79.53 1.52 0.00 0.00 0.00Ar mol % 0.91 3.06 0.03 0.03 0.00 0.93 0.00 0.00 0.00 0.00 0.27 0.41 0.00 0.00 0.00CH4 mol % 0.00 0.00 0.00 0.00 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.02 0.00 0.00 0.00O2 mol % 20.74 95.00 0.06 0.06 0.00 0.00 0.00 0.00 0.00 0.00 2.92 0.00 0.00 0.00 0.00H2O mol % 1.01 0.00 0.00 0.00 99.99 0.00 100.00 100.00 100.00 100.00 17.10 53.43 100.00 100.00 99.62H2S mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.39 0.00 0.00 0.00COS mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.04 0.00 0.00 0.00SO2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCN mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NH3 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.26CH3OH mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.03HCl mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.09

Σ mass % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mass % 0.00 0.00 0.00 0.00 0.00 38.66 0.00 0.00 0.00 0.00 0.00 1.63 0.00 0.00 0.00CO mass % 0.00 0.00 0.00 0.00 0.00 22.77 0.00 0.00 0.00 0.00 0.00 39.32 0.00 0.00 0.00CO2 mass % 0.05 0.00 0.00 0.00 0.01 4.67 0.00 0.00 0.00 0.00 0.31 4.67 0.00 0.00 0.00N2 mass % 75.06 1.69 99.89 99.89 0.00 25.88 0.00 0.00 0.00 0.00 84.13 2.23 0.00 0.00 0.00Ar mass % 1.26 3.80 0.05 0.05 0.00 7.88 0.00 0.00 0.00 0.00 0.40 0.85 0.00 0.00 0.00CH4 mass % 0.00 0.00 0.00 0.00 0.00 0.12 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00O2 mass % 23.00 94.51 0.07 0.07 0.00 0.00 0.00 0.00 0.00 0.00 3.52 0.00 0.00 0.00 0.00H2O mass % 5.50 0.63 0.00 0.00 0.00 99.98 0.00 100.00 100.00 100.00 100.00 11.63 44.72 50.46 100.00 100.00 99.39H2S mass % 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.70 0.00 0.00 0.00COS mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.12 0.00 0.00 0.01SO2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01HCN mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.39NH3 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.03CH3OH mass % 0.00 0.00 0.00 0.00 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCl mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.18coal mass % 87.13 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00ash mass % 7.37 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 52.65 0.00 0.00 0.00 0.00C mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2.63 0.00 0.00 0.00 0.00solids mass % 94.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 55.28 0.00 0.00 0.00 0.00

Appendix

123

Appendix B6 – CHEMCADflow sheet for the model of the CoP gasifier

1

2

31

H2O

_raw

coa

l

coal

_waf

ash_

raw

coa

lra

w c

oal

14

22

23

GO

X

slur

ry w

ater

GO

X P

RH

2

41

4

4

731

3

9

LP s

team

LP c

ond

5

Slu

rry P

RH

IP s

team

IP c

ond

18

42 43

46

47

79

80

81

20

30

32

33

21

4329

raw

gas

was

te w

ater

62

mak

e up

wat

er

77

5

6

37

7

35

8

8 11

9

13

10

1514

16

11

16

19

stag

e 1

slag

12

17

13

10

21H

P G

AN

15

17

19

28

27

26

22

18

23

27

2425

28

29

30

31

49

stag

e 2

32

50

2534

IP B

FW

35

38

33

36

36

5556

5352

HP

CS

C

6

HP

ste

am

37

44

73

57

47

51

12

48

char

39

40

syng

asre

cycl

e

42

46

ID

1 T

15.

0 C

P 1

.0 b

ar W

104

950

kg/h

ID

2 T

15.

0 C

P 1

.0 b

ar W

887

7 kg

/h

ID

3 T

15.

0 C

P 1

.0 b

ar W

662

5 kg

/h

ID

34 T

60.

0 C

P 5

0.00

bar

W 1

0071

8 kg

/h M

312

9 km

ol/h

ID

41 T

15.

0 C

P 5

0.00

bar

W 6

4859

kg/

h M

360

0 km

ol/h

ID

4 T

15.

0 C

P 1

.0 b

ar W

120

452

kg/h

ID

31 T

120

.0 C

P 4

8.00

bar

W 1

8531

1 kg

/h

ID

62 T

164

.5 C

P 6

.90

bar

W 1

9215

kg/

h

ID

71 T

15.

0 C

P 4

0.00

bar

W 9

448

kg/h

ID

8 T

120

.0 C

P 4

8.00

bar

W 1

4454

3 kg

/h

ID

10 T

120

.0 C

P 4

8.00

bar

W 4

0769

kg/

h

ID

21 T

70.

0 C

P 7

0.00

bar

W 1

948

kg/h

ID

82 T

264

.7 C

P 5

0.60

bar

W 5

766

kg/h ID

37

T 1

20.0

C P

48.

00 b

ar W

185

311

kg/h

ID

18 T

144

8.7

C P

40.

00 b

ar W

245

896

kg/h

M 1

1899

km

ol/h

ID

56 T

156

.0 C

P 4

9.20

bar

W 2

0200

7 kg

/h

ID

45 T

336

.2 C

P 1

39.5

0 ba

r W

202

007

kg/h

ID

38 T

100

0.2

C P

40.

00 b

ar W

353

499

kg/h

M 1

7276

km

ol/h

ID

36 T

200

.0 C

P 4

9.00

bar

W 1

0071

8 kg

/h M

312

9 km

ol/h

ID

42 T

346

.2 C

P 3

9.75

bar

W 3

4341

4 kg

/h

ID

57 T

174

.5 C

P 3

9.50

bar

W 3

4341

4 kg

/h

ID

12 T

174

.5 C

P 3

9.50

bar

W 2

7061

0 kg

/h

ID

47 T

30.

0 C

P 3

9.00

bar

W 7

2804

kg/

h

ID

6 T

100

.0 C

P 4

9.20

bar

W 5

766

kg/h

ID

48 T

52.

1 C

P 4

8.00

bar

W 6

4887

kg/

h M

307

3 km

ol/h

ID

39 T

346

.2 C

P 3

9.75

bar

W 3

5349

9 kg

/h

ID

40 T

346

.2 C

P 3

9.75

bar

W 1

0085

kg/

h

ID

73 T

152

.3 C

P 3

9.00

bar

W 2

7227

6 kg

/h

ID

79 T

15.

0 C

P 5

0.00

bar

W 1

0800

kg/

h

ID

77 T

150

.0 C

P 3

9.00

bar

W 1

7051

kg/

h

ID

51 T

30.

0 C

P 3

9.00

bar

W 7

917

kg/h

ID

46 T

174

.5 C

P 3

9.50

bar

W 7

2804

kg/

h

34

2438

LP B

FW

ID

26 T

154

.2 C

P 1

4.00

bar

W 2

3160

kg/

h

39

58

61

40

63

ID

60 T

163

.4 C

P 6

.60

bar

W 2

3160

kg/

h

ID

61 T

164

.5 C

P 6

.90

bar

W 1

9215

kg/

h

ID

63 T

129

.8 C

P 6

.90

bar

W 4

2375

kg/

h

ID

55 T

157

.6 C

P 5

2.10

bar

W 1

9624

1 kg

/h

71

54

ID

59 T

100

.0 C

P 6

.90

bar

W 1

9215

kg/

h

49

2669

54

60

70LP

ste

am

55

59

72

56

82 74

57

45

75

Appendix

124

Appendix B7 – Heat and material balance for the model of the CoP gasifier

stream ID 0-2-coal-1 10-2-wa-1 1-2-GOX-1 1-2-GAN-1 8-2-st-3 8-2-BFW-1 8-2-BFW-2 10-2-mu-1 2-0-slag-1 2-3-gas-1 2-8-st-4 2-8-st-6 2-10-ww-1name raw coal slurry water GOX HP GAN IP steam IP BFW LP BFW make up water slag raw gas HP steam LP steam waste watert °C 15.0 15.0 60.0 70.0 264.7 157.6 154.2 15.0 152.3 336.2 163.4 150.0p bar 50.0 50.0 70.0 50.6 52.1 14.0 50.0 39.0 139.5 6.6 39.0m kg/s 35.101 18.901 29.351 0.568 1.680 57.187 6.749 3.147 2.753 79.345 58.867 6.749 4.969n kmol/s 1.049 0.912 0.020 0.093 3.174 0.375 0.175 3.832 3.268 0.375 0.275V Nm³/h 73,575 1,635 309,164LHV kJ/kg 29,887 10,402HHV kJ/kg 31,116 11,193h kJ/kg -15,919 22 38 -13,190 -15,315 -15,330 -15,919 -5,803 -13,324 -13,221 -15,276s J/kgK -9,184 -873 -1,143 -3,446 -7,493 -7,528 -9,184 932 -4,056 -2,681 -7,548M kg/kmol 18.01 32.19 28.02 18.01 18.01 18.01 18.01 20.71 18.01 18.01 18.05

Σ mol % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mol % 0.00 28.98 0.00CO mol % 0.00 39.77 0.00CO2 mol % 0.00 11.44 0.00N2 mol % 0.00 1.74 99.98 1.38 0.00Ar mol % 0.00 3.26 0.01 0.78 0.00CH4 mol % 0.00 3.56 0.00O2 mol % 0.00 95.00 0.01 0.00 0.00H2O mol % 100.00 100.00 100.00 100.00 100.00 13.28 100.00 100.00 99.63H2S mol % 0.00 0.76 0.00COS mol % 0.00 0.05 0.00SO2 mol % 0.00 0.00 0.00S mol % 0.00 0.00 0.00HCN mol % 0.00 0.00 0.00NH3 mol % 0.00 0.00 0.01CH3OH mol % 0.00 0.00 0.18HCl mol % 0.00 0.00 0.18

Σ mass % 100.00 100.00 100.00 100.00 0.00 0.00 0.00 0.00 100.00 100.00 100.00 100.00 100.00H2 mass % 0.00 2.82 0.00CO mass % 0.00 53.80 0.00CO2 mass % 0.00 24.31 0.00N2 mass % 0.00 1.52 99.97 0.00 0.00 0.00 0.00 1.87 0.00Ar mass % 0.00 4.04 0.01 0.00 0.00 0.00 0.00 1.50 0.00CH4 mass % 0.00 2.76 0.00O2 mass % 0.00 94.44 0.01 0.00 0.00 0.00 0.00 0.00 0.00H2O mass % 5.50 100.00 11.55 100.00 100.00 99.45H2S mass % 0.00 1.26 0.00COS mass % 0.00 0.14 0.00SO2 mass % 0.00 0.00 0.00S mass % 0.00 0.00 0.00HCN mass % 0.00 0.00 0.01NH3 mass % 0.00 0.00 0.17CH3OH mass % 0.00 0.00 0.00HCl mass % 0.00 0.00 0.36coal mass % 87.13 0.00 0.00 0.00ash mass % 7.37 0.00 93.96 0.00 0.00C mass % 0.00 6.04 0.00 0.00solids mass % 94.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 100.00 0.00 0.00

Appendix

125

Appendix B8 – CHEMCADflow sheet for the model of the GER

1

2

31

H2O

_raw

coa

l

coal

_waf

ash_

raw

coal

raw

coa

l

1419

22

23

34

3635

56

GO

X

slur

ry w

ater

26

GO

X P

RH

2

41

6

8

13

9

10

1811

12

4

4

731

3

9

LP s

team

537

Slu

rry

PRH

IP s

team

IP c

ond

reac

tor

10

7

11

5R

adia

nt C

ool13

15

25

HP

BF

W p

ump

HP

ste

am

quen

ch w

ater

15

16

19sl

ag17

20

21

char

rec

ycl

e

18

42 43

46

47

79

80

24

81

20

73

30

32

33

2116

24

17

43

44

29

raw

gas

was

te w

ater

ID

1

T 1

5.0

C P

1.0

bar

W 1

0495

0 kg

/h

ID

2

T 1

5.0

C P

1.0

bar

W 8

877

kg/h

ID

3

T 1

5.0

C P

1.0

bar

W 6

625

kg/h

ID

3

4 T

60.

0 C

P 6

9.96

bar

W 1

2189

0 kg

/h M

378

5 km

ol/h

ID

3

6 T

200

.0 C

P 6

8.96

bar

W 1

2189

0 kg

/h M

378

5 km

ol/h

ID

4

1 T

15.

0 C

P 5

0.00

bar

W 6

4800

kg/

h M

359

7 km

ol/h

ID

4

T 1

5.0

C P

1.0

bar

W 1

2045

2 kg

/h

ID

3

1 T

120

.0 C

P 8

0.00

bar

W 1

8525

2 kg

/h

ID

3

7 T

120

.0 C

P 8

0.00

bar

W 1

8525

2 kg

/h

ID

6

T 1

00.0

C P

47.

00 b

ar W

705

6 kg

/h

ID

2

3 T

41.

3 C

P 1

8.00

bar

W 1

5069

5 kg

/h

ID

1

3 T

200

.0 C

P 7

0.00

bar

W 1

6560

0 kg

/h M

919

0 km

ol/h

ID

2

1 T

120

.0 C

P 8

0.00

bar

W 8

698

kg/h

ID

7

9 T

15.

0 C

P 5

0.00

bar

W 1

0800

kg/

h M

600

km

ol/h

ID

1

1 T

146

5.5

C P

60.

96 b

ar W

315

839

kg/h

ID

8

1 T

215

.8 C

P 6

5.00

bar

W 1

5478

5 kg

/h M

859

1 km

ol/h

ID

7

3 T

228

.4 C

P 6

0.00

bar

W 4

5675

6 kg

/h M

231

66 k

mol

/h

ID

1

6 T

229

.6 C

P 6

0.71

bar

W 4

6209

9 kg

/h M

234

60 k

mol

/h

62

ID

8

2 T

264

.0 C

P 4

8.00

bar

W 7

056

kg/h

ID

6

2 T

278

.7 C

P 6

.10

bar

W 1

7243

kg/

h

25

82

623

8

ID

8

T 4

3.9

C P

18.

00 b

ar W

157

750

kg/h

ID

6

T 1

00.0

C P

47.

00 b

ar W

705

6 kg

/h

mak

e up

wat

er

57

28

42

ID

4

7 T

145

0.0

C P

60.

96 b

ar W

315

838

kg/h

ID

5

7 T

816

.0 C

P 6

0.71

bar

W 3

1583

9 kg

/h I

D

28

T 2

29.5

C P

60.

71 b

ar W

481

439

kg/h

71 ID

7

1 T

15.

0 C

P 6

0.71

bar

W 9

311

kg/h

45

26

ID

4

5 T

342

.0 C

P 1

50.0

0 ba

r W

157

750

kg/h

60

ID

6

0 T

100

.0 C

P 6

.10

bar

W 1

7243

kg/

h

77 ID

7

7 T

150

.0 C

P 6

0.00

bar

W 1

7473

kg/

h

47

40

BFW

Appendix

126

Appendix B9 – Heat and material balance for the model of the GER

stream ID 0-2-coal-1 10-2-wa-1 1-2-GOX-1 8-2-st-3 8-2-st-2 8-2-BFW-5 3-2-wa-2 10-2-mu-1 2-3-gas-1 2-0-slag-1 2-8-st-4 2-8-cond-1 2-10-ww-1name raw coal slurry water GOX IP steam LP steam BFW quench water make up water raw gas slag HP steam LP cond waste watert °C 15.0 15.0 60.0 264.0 278.7 41.3 200.0 15.0 228.4 342.0 100.0 150.0p bar 50.0 70.0 48.0 6.1 18.0 70.0 50.0 60.0 150.0 6.1 60.0m kg/s 37.776 20.322 38.227 2.213 5.408 47.261 51.935 3.387 143.247 2.920 49.473 5.408 5.480n kmol/s 1.128 1.187 0.123 0.300 2.623 2.882 0.188 7.265 2.746 0.300 0.303V Nm³/h 95,789 586,234LHV kJ/kg 29,887 0 5,731HHV kJ/kg 31,116 0 6,146h kJ/kg -15,919 19 -13,177 -12,965 -15,809 -15,122 -15,919 -8,638 -13,336 -15,562 -15,209s J/kgK -9,184 -970 -3,403 -2,125 -8,822 -7,078 -9,184 -608 -4,110 -8,105 -7,513M kg/kmol 18.01 32.20 18.01 18.01 18.01 0.00 18.01 19.72 18.01 18.01 18.08

Σ mol % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 17.73 0.00 0.00 0.00CO mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 23.58 0.00 0.00 0.00CO2 mol % 0.00 0.00 0.00 0.00 0.00 0.01 0.00 7.42 0.00 0.00 0.00N2 mol % 0.00 1.64 0.00 0.00 0.00 0.00 0.00 0.51 0.00 0.00 0.00Ar mol % 0.00 3.36 0.00 0.00 0.00 0.00 0.00 0.55 0.00 0.00 0.00CH4 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.12 0.00 0.00 0.00O2 mol % 0.00 95.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00H2O mol % 100.00 0.00 100.00 100.00 100.00 99.98 100.00 49.62 100.00 100.00 99.48H2S mol % 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.43 0.00 0.00 0.00COS mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.03 0.00 0.00 0.00SO2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCN mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NH3 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.29CH3OH mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.04HCl mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.18

Σ mass % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.81 0.00 0.00 0.00CO mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 33.50 0.00 0.00 0.00CO2 mass % 0.00 0.00 0.00 0.00 0.00 0.02 0.00 16.56 0.00 0.00 0.00N2 mass % 0.00 1.43 0.00 0.00 0.00 0.00 0.00 0.73 0.00 0.00 0.00Ar mass % 0.00 4.17 0.00 0.00 0.00 0.00 0.00 1.11 0.00 0.00 0.00CH4 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.10 0.00 0.00 0.00O2 mass % 0.00 94.40 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00H2O mass % 5.50 100.00 0.00 100.00 100.00 100.00 99.96 100.00 45.34 100.00 100.00 99.15H2S mass % 0.00 0.00 0.00 0.00 0.00 0.02 0.00 0.75 0.00 0.00 0.00COS mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.10 0.00 0.00 0.01SO2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.01HCN mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.43NH3 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.04CH3OH mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCl mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.36coal mass % 87.13 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00ash mass % 7.37 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 95.35 0.00 0.00 0.00C mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 4.65 0.00 0.00 0.00solids mass % 94.50 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 100.00 0.00 0.00 0.00

Appendix

127

Appendix C1 – Process flow diagram for the COshift cycle (CCIGCC / GER)

Appendix C2 – Process flow diagram for the COshift cycle (CCIGCC / CoP gasifier)

CO-shiftreactor 1

clean gas4-3-gas-4

Clean gassaturator

DGAN1-3-DGAN-1


GT fuel3-8-gas-5

Saturator

Raw gas 2-3-gas-1

IP steam8-3-st-9

CO-shiftreactor 2

Direct cooler

Condensate8-3-wa-3

Condensate3-8-wa-4





Appendix

128

34

5

1

2

3

4

7

reac

tor

1

reac

tor

2

HE1

11

13

25

23

25

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gas

mod

erat

or s

t

satu

rate

d ga

s

shift

ed g

as

76

77

79

80

98

117

116 24

clean

gas

DGA

N

115

15

96

35

26

9

42

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20

29

6

17

10

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mak

e up

97

5

7

ID

3 T

214

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P 3

8.8

bar

W 4

8139

9 kg

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251

78 k

mol/

h

ID

4 T

280

.0 C

P 3

8.7

bar

W 4

8139

9 kg

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251

78 k

mol/

h ID

98

T 9

1.2

C P

32.

4 ba

r W

545

313

kg/h

M 3

0270

km

ol/h

ID

99 T

15.

0 C

P 5

0.0

bar

W 3

9630

kg/

h M

220

0 km

ol/h

ID 1

17 T

48.

3 C

P 3

3.4

bar

W 3

0117

4 kg

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199

62 k

mol/

h

ID 1

16 T

95.

6 C

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4.0

bar

W 2

4467

2 kg

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871

3 km

ol/h

ID

24 T

10.

0 C

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3.4

bar

W 5

6502

kg/

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112

49 k

mol/

h

ID 1

15 T

86.

2 C

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8.0

bar

W 5

8494

3 kg

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324

70 k

mol/

h

ID

35 T

86.

1 C

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2.4

bar

W 5

8494

3 kg

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324

70 k

mol/

h

ID

26 T

135

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2.4

bar

W 3

4078

6 kg

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221

61 k

mol/

h

ID

29 T

203

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P 3

8.8

bar

W 3

9471

0 kg

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203

66 k

mol/

h

ID

97 T

148

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324

69 k

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264

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2 km

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kg/h

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59 k

mol/

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180

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138

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1 kg

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127

78 k

mol/

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500

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425

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472

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ID

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280

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3 kg

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ID

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323

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240

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7 kg

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6

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M 7

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108

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W 7

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2 kg

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388

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h

ID

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80.

0 C

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388

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15.

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1654

kg/

h M

175

7 km

ol/h

ID

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77.

2 C

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W 7

3271

6 kg

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406

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h

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19 T

97.

8 C

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6.0

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W 3

6231

4 kg

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185

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mol/

h

ID

13 T

193

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6.1

bar

W 4

8140

4 kg

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251

78 k

mol/

h

ID

9 T

175

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P 4

4.0

bar

W 8

5180

7 kg

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472

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mol/

hco

nddi

scha

rge

ID

16 T

79.

5 C

P 3

5.9

bar

W 2

2580

kg/

h M

125

2 km

ol/h

HE2

HE3

HE8

ID

21 T

158

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P 3

8.8

bar

W 7

1537

0 kg

/h M

396

91 k

mol/

h

ID

25 T

148

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P 3

6.0

bar

W 5

8492

5 kg

/h M

324

69 k

mol/

h

20

3028

14

22

99

19

227

22

4331

HE1

0

Appendix C3 – CHEMCAD COshift model for the CCIGCC / SCGP

Appendix

129

Appendix C4 – Heat and material balance for the COshift model (CCIGCC /

SCGP)

stream ID 1-3-DGAN-1 2-3-gas-1 2-3-st-7 4-3-gas-4 9-3-cw-1 10-3-mu-2 3-4-gas-3 3-8-gas-5 3-9-cw-2 3-10-ww-2name DGAN raw gas IP steam clean gas cooling water make up water shifted gas GT fuel cooling water waste watert °C 95.6 138.2 264.7 10.0 20.0 15.0 30.0 136.8 30.0 80.3p bar 34.0 39.0 50.6 33.4 6.0 50.0 35.9 32.4 4.0 35.9m kg/s 70.351 74.249 24.926 16.246 155 20.997 101.821 98.611 155 6.337n kmol/s 2.505 3.674 1.384 3.235 8.627 1.166 5.205 6.407 8.627 0.352V Nm³/h 202,147 296,453 260,995 419,963 516,955LHV kJ/kg 11,226 45,147 7,426HHV kJ/kg 12,073 53,037 8,712h kJ/kg 70 -4,386 -13,190 -1,329 -15,898 -15,919 -7,708 -1,633 -15,856 -15,629s J/kgK -814 1,604 -3,446 -4,654 -9,113 -9,184 -946 -925 -8,974 -8,321M kg/kmol 28.07 20.20 18.00 5.01 18.00 18.00 19.59 15.38 18.00 18.01

Σ mol % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mol % 0.00 28.11 0.00 89.15 0.00 0.00 55.92 45.01 0.00 0.01CO mol % 0.00 54.55 0.00 3.85 0.00 0.00 2.42 1.95 0.00 0.01CO2 mol % 0.00 1.95 0.00 0.50 0.00 0.00 37.48 0.25 0.00 0.02N2 mol % 98.93 4.07 0.00 5.54 0.00 0.00 2.87 41.48 0.00 0.00Ar mol % 0.31 0.80 0.00 0.92 0.00 0.00 0.56 0.59 0.00 0.00CH4 mol % 0.00 0.03 0.00 0.03 0.00 0.00 0.02 0.01 0.00 0.00O2 mol % 0.76 0.00 0.00 0.00 0.00 0.00 0.00 0.30 0.00 0.00H2O mol % 0.00 9.67 100.00 0.00 100.00 100.00 0.14 10.41 100.00 99.93H2S mol % 0.00 0.76 0.00 0.00 0.00 0.00 0.56 0.00 0.00 0.02COS mol % 0.00 0.07 0.00 0.00 0.00 0.00 0.03 0.00 0.00 0.01CS2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SO2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCN mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NH3 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CH3OH mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Σ mass % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mass % 0.00 2.80 0.00 35.78 0.00 0.00 5.76 5.89 0.00 0.00CO mass % 0.00 75.61 0.00 21.50 0.00 0.00 3.47 3.54 0.00 0.02CO2 mass % 0.00 4.24 0.00 4.38 0.00 0.00 84.32 0.72 0.00 0.06N2 mass % 98.69 5.64 0.00 30.91 0.00 0.00 4.11 75.50 0.00 0.00Ar mass % 0.44 1.58 0.00 7.31 0.00 0.00 1.15 1.52 0.00 0.00CH4 mass % 0.00 0.02 0.00 0.09 0.00 0.00 0.02 0.02 0.00 0.00O2 mass % 0.87 0.00 0.00 0.00 0.00 0.00 0.00 0.62 0.00 0.00H2O mass % 0.00 8.62 100.00 0.00 100.00 100.00 0.12 12.18 100.00 99.85H2S mass % 0.00 1.28 0.00 0.00 0.00 0.00 0.97 0.00 0.00 0.04COS mass % 0.00 0.20 0.00 0.00 0.00 0.00 0.08 0.00 0.00 0.03CS2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SO2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCN mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NH3 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CH3OH mass % 0.00 0.00 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00

Appendix

130

1

2

34

5 6

1

2

3

4 5 6

7

7

8

8

13

9

10

12

HP

evap

reac

tor

1

reac

tor

212

HE2

HE3

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15

9

16

17

18

21

19 HE4

11

20

23

13 25

20

22

24

27

23

41

25

26 HE5

HE6

29

44

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28

31

33

38

37

43

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10

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2846

17

22

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47

45

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raw

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476

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km

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2

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64.7

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50.

6 ba

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0 k

g/h

M 0

km

ol/h

ID

3

T 2

14.5

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39.

0 ba

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476

834

kg/h

M 2

4999

km

ol/h

ID

4

T 2

80.0

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38.

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476

834

kg/h

M 2

4999

km

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ID

6

T 4

92.9

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37.

8 ba

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476

839

kg/h

M 2

4999

km

ol/h

ID

7

T 3

62.5

C P

37.

6 ba

r W

476

839

kg/h

M 2

4999

km

ol/h

ID

8

T 2

80.0

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37.

5 ba

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476

839

kg/h

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4999

km

ol/h

ID

12

T 3

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143

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109

292

kg/h

M 6

067

kmol

/h

ID

14

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139

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109

292

kg/h

M 6

067

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/h

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15

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143

.0 b

ar W

109

292

kg/h

M 6

067

kmol

/h

ID

9

T 3

21.7

C P

36.

4 ba

r W

476

839

kg/h

M 2

4999

km

ol/h

ID

23

T 1

14.3

C P

35.

8 ba

r W

433

069

kg/h

M 2

2569

km

ol/h

ID

20

T 1

66.7

C P

35.

9 ba

r W

433

069

kg/h

M 2

2569

km

ol/h

ID

21

T 1

66.7

C P

35.

9 ba

r W

232

38 k

g/h

M 1

290

kmol

/h

ID

27

T 1

13.6

C P

35.

8 ba

r W

365

118

kg/h

M 1

8798

km

ol/h

ID

31

T 8

0.8

C P

35.

7 ba

r W

365

118

kg/h

M 1

8798

km

ol/h

ID

33

T 8

1.4

C P

35.

7 ba

r W

113

12 k

g/h

M 6

27 k

mol

/h

ID

29

T 1

10.5

C P

33.

7 ba

r W

231

692

kg/h

M 1

2859

km

ol/h

ID

44

T 1

66.7

C P

35.

9 ba

r W

456

307

kg/h

M 2

3859

km

ol/h

ID

28

T 1

13.6

C P

35.

8 ba

r W

679

51 k

g/h

M 3

772

kmol

/h

ID

38

T 9

9.5

C P

33.

7 ba

r W

140

502

kg/h

M 7

798

kmol

/h

ID

37

T 2

0.4

C P

35.

7 ba

r W

140

502

kg/h

M 7

798

kmol

/h

ID

39

T 1

5.0

C P

50.

0 ba

r W

129

190

kg/h

M 7

171

kmol

/h

ID

41

T 3

0.0

C P

35.

5 ba

r W

349

635

kg/h

M 1

7940

km

ol/h

ID

43

T 3

0.0

C P

35.

5 ba

r W

353

806

kg/h

M 1

8171

km

ol/h

ID

48

T 1

65.4

C P

31.

7 ba

r W

251

999

kg/h

M 1

3987

km

ol/h

ID

46

T 1

74.8

C P

36.

0 ba

r W

205

32 k

g/h

M 1

140

kmol

/h

ID

45

T 1

64.6

C P

31.

7 ba

r W

231

467

kg/h

M 1

2847

km

ol/h

ID

47

T 1

74.8

C P

36.

0 ba

r W

456

307

kg/h

M 2

3859

km

ol/h

ID

42

T 3

0.0

C P

35.

5 ba

r W

417

1 kg

/h M

231

km

ol/h

ID

10

T 2

50.2

C P

36.

3 ba

r W

476

839

kg/h

M 2

4999

km

ol/h

ID

16

T 2

00.0

C P

48.

0 ba

r W

251

999

kg/h

M 1

3987

km

ol/h

ID

17

T 2

09.0

C P

36.

2 ba

r W

476

839

kg/h

M 2

4999

km

ol/h

ID

22

T 1

95.0

C P

16.

0 ba

r W

109

292

kg/h

M 6

067

kmol

/h

ID

18

T 1

99.1

C P

145

.0 b

ar W

109

292

kg/h

M 6

067

kmol

/h

ID

19

T 1

74.8

C P

36.

0 ba

r W

476

839

kg/h

M 2

4999

km

ol/h

ID

30

T 1

66.0

C P

50.

0 ba

r W

251

999

kg/h

M 1

3987

km

ol/h

ID

51

T 3

0.0

C P

4.0

bar

W 1

0207

67 k

g/h

M 5

6662

km

ol/h

ID

49

T 2

0.0

C P

6.0

bar

W 1

0207

67 k

g/h

M 5

6662

km

ol/h

ID

98

T 1

00.7

C P

32.

4 ba

r W

663

148

kg/h

M 3

6812

km

ol/h

ID

99

T 1

0.0

C P

5.0

bar

W 4

9999

kg/

h M

277

5 km

ol/h

ID

100

T 1

1.0

C P

38.

0 ba

r W

499

99 k

g/h

M 2

775

kmol

/h

ID

117

T 4

7.8

C P

33.

0 ba

r W

288

031

kg/h

M 1

9490

km

ol/h

ID

116

T 9

5.6

C P

34.

0 ba

r W

235

802

kg/h

M 8

400

kmol

/h

ID

97

T 1

56.7

C P

36.

0 ba

r W

713

212

kg/h

M 3

9591

km

ol/h

ID

24

T 1

0.0

C P

33.

0 ba

r W

522

28 k

g/h

M 1

1090

km

ol/h

ID

115

T 9

4.6

C P

38.

0 ba

r W

713

147

kg/h

M 3

9588

km

ol/h

ID

35

T 9

4.4

C P

32.

4 ba

r W

713

147

kg/h

M 3

9588

km

ol/h

ID

34

T 9

4.6

C P

38.

0 ba

r W

713

212

kg/h

M 3

9591

km

ol/h

ID

11

T 3

9.3

C P

18.

0 ba

r W

109

292

kg/h

M 6

067

kmol

/h

ID

32

T 8

1.4

C P

35.

7 ba

r W

353

806

kg/h

M 1

8171

km

ol/h

97

26

ID

26

T 1

44.1

C P

32.

4 ba

r W

338

094

kg/h

M 2

2269

km

ol/h

39

42

14

71

HP

stea

m

Appendix C5 – CHEMCAD COshift model for the CCIGCC / Siemens gasifier

Appendix

131


Siemens gasifier)

stream ID 1-3-DGAN-1 2-3-gas-1 4-3-gas-4 8-3-BFW-3 9-3-cw-1 10-3-mu-2 3-2-wa-2 3-4-gas-3 3-8-gas-5 3-8-st-8 3-9-cw-2 3-10-ww-2name DGAN raw gas clean gas BFW cooling water make up water quench water shifted gas GT fuel HP steam cooling water waste watert °C 95.6 214.5 10.0 39.3 20.0 15.0 200.0 30.0 144.1 336.2 30.0 30.0p bar 34.0 39.0 33.0 18.0 6.0 50.0 48.0 35.5 32.4 139.5 4.0 35.5m kg/s 67.974 137.455 15.056 31.505 294.252 51.654 72.643 100.788 97.461 31.505 294.252 1.202n kmol/s 2.421 7.206 3.197 1.749 16.334 2.867 4.032 5.171 6.419 1.749 16.334 0.067V Nm³/h 195,383 581,470 257,958 417,276 517,979LHV kJ/kg 6,049 48,759 7,510 7,532HHV kJ/kg 7,656 57,288 8,813 9,213h kJ/kg 70 -8,493 -1,413 -15,817 -15,898 -15,919 -15,124 -7,797 -1,968 -13,324 -15,856 -15,835s J/kgK -817 -473 -5,012 -8,849 -9,113 -9,184 -7,080 -957 -964 -4,056 -8,974 -8,956M kg/kmol 28.06 19.06 4.69 18.00 18.00 18.00 18.00 19.51 15.17 18.00 18.00 18.02

Σ mol % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mol % 0.00 15.40 90.35 0.00 0.00 0.00 0.00 56.38 45.00 0.00 0.00 0.00CO mol % 0.00 26.78 3.83 0.00 0.00 0.00 0.00 2.39 1.91 0.00 0.00 0.00CO2 mol % 0.00 2.03 0.50 0.00 0.00 0.00 0.01 37.79 0.25 0.00 0.00 0.07N2 mol % 99.12 1.52 4.37 0.00 0.00 0.00 0.00 2.12 39.56 0.00 0.00 0.00Ar mol % 0.28 0.41 0.91 0.00 0.00 0.00 0.00 0.57 0.56 0.00 0.00 0.00CH4 mol % 0.00 0.02 0.03 0.00 0.00 0.00 0.00 0.02 0.02 0.00 0.00 0.00O2 mol % 0.59 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.22 0.00 0.00 0.00H2O mol % 0.00 53.43 0.00 100.00 100.00 100.00 99.99 0.14 12.48 100.00 100.00 99.90H2S mol % 0.00 0.39 0.00 0.00 0.00 0.00 0.00 0.59 0.00 0.00 0.00 0.03COS mol % 0.00 0.04 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CS2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SO2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCN mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NH3 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CH3OH mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Σ mass % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mass % 0.00 1.63 38.67 0.00 0.00 0.00 0.00 5.83 5.97 0.00 0.00 0.00CO mass % 0.00 39.32 22.78 0.00 0.00 0.00 0.00 3.44 3.52 0.00 0.00 0.00CO2 mass % 0.00 4.67 4.68 0.00 0.00 0.00 0.01 85.34 0.72 0.00 0.00 0.17N2 mass % 98.92 2.23 25.99 0.00 0.00 0.00 0.00 3.04 73.01 0.00 0.00 0.00Ar mass % 0.41 0.85 7.73 0.00 0.00 0.00 0.00 1.16 1.48 0.00 0.00 0.00CH4 mass % 0.00 0.01 0.12 0.00 0.00 0.00 0.00 0.02 0.02 0.00 0.00 0.00O2 mass % 0.68 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.47 0.00 0.00 0.00H2O mass % 0.00 50.46 0.00 100.00 100.00 100.00 99.98 0.13 14.81 100.00 100.00 99.76H2S mass % 0.00 0.70 0.00 0.00 0.00 0.00 0.01 1.03 0.00 0.00 0.00 0.06COS mass % 0.00 0.12 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00 0.00CS2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SO2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCN mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NH3 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CH3OH mass % 0.00 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Appendix

132

Appendix C7 – CHEMCAD COshift model for the CCIGCC / CoP gasifier

34

5

1

2

3

4

7

reac

tor 1

reac

tor 2

HE1

11

13

25

23

25

HE6

HE9

raw

gas

mod

erat

or s

t

satu

rate

d ga

s

shift

ed g

as

76

77

79

80

98

117

116 24

clean

gas

DGAN

115

15

96

35

26

9

42

12 1

20

29

6

17

10

2134

mak

e up

97

5

7

ID

3 T

236

.2 C

P 3

8.8

bar

W 4

6099

2 kg

/h M

236

33 k

mol/

h

ID

4 T

280

.0 C

P 3

8.7

bar

W 4

6099

2 kg

/h M

236

33 k

mol/

h ID

98

T 1

01.4

C P

32.

4 ba

r W

616

585

kg/h

M 3

4226

km

ol/h

ID

99 T

15.

0 C

P 5

0.0

bar

W 4

3595

kg/

h M

242

0 km

ol/h

ID 1

17 T

46.

3 C

P 3

3.4

bar

W 2

4540

0 kg

/h M

169

71 k

mol/

h

ID 1

16 T

95.

6 C

P 3

4.0

bar

W 1

9757

7 kg

/h M

704

5 km

ol/h

ID

24 T

10.

0 C

P 3

3.4

bar

W 4

7823

kg/

h M

992

6 km

ol/h

ID 1

15 T

95.

9 C

P 3

8.0

bar

W 6

6018

0 kg

/h M

366

46 k

mol/

h

ID

35 T

95.

7 C

P 3

2.4

bar

W 6

6018

0 kg

/h M

366

46 k

mol/

h

ID

26 T

143

.3 C

P 3

2.4

bar

W 2

8898

9 kg

/h M

193

91 k

mol/

h

ID

29 T

203

.7 C

P 3

8.8

bar

W 3

9613

8 kg

/h M

200

33 k

mol/

h

ID

97 T

154

.3 C

P 3

6.0

bar

W 6

6017

4 kg

/h M

366

46 k

mol/

h

ID

2 T

412

.5 C

P 5

0.6

bar

W 6

4854

kg/

h M

360

0 km

ol/h

ID

42 T

30.

0 C

P 3

5.9

bar

W 1

351

kg/h

M 7

5 km

ol/h

ID

41 T

30.

0 C

P 3

5.9

bar

W 3

3007

5 kg

/h M

163

57 k

mol/

h

ID

43 T

60.

0 C

P 3

5.9

bar

W 3

3990

3 kg

/h M

169

02 k

mol/

h

ID

1 T

152

.3 C

P 3

9.0

bar

W 2

7227

6 kg

/h M

131

48 k

mol/

h

ID

6 T

457

.9 C

P 3

7.6

bar

W 4

6099

6 kg

/h M

236

33 k

mol/

h

ID

10 T

412

.6 C

P 3

7.5

bar

W 4

6099

6 kg

/h M

236

33 k

mol/

h

ID

34 T

95.

9 C

P 3

8.0

bar

W 6

6017

4 kg

/h M

366

46 k

mol/

h

ID

20 T

240

.0 C

P 4

2.0

bar

W 8

0426

7 kg

/h M

446

39 k

mol/

h

ID

7 T

280

.0 C

P 3

7.4

bar

W 4

6099

6 kg

/h M

236

33 k

mol/

h

ID

12 T

209

.3 C

P 4

3.0

bar

W 8

0425

2 kg

/h M

446

38 k

mol/

h

ID

11 T

309

.5 C

P 3

6.3

bar

W 4

6099

6 kg

/h M

236

33 k

mol/

h

ID

30 T

240

.0 C

P 4

2.0

bar

W 8

0425

2 kg

/h M

446

38 k

mol/

h

11

6

13

8

15

10

8

16

17 23

19

41

1618

12

mak

e up

18

9 ID

18

T 1

08.0

C P

38.

7 ba

r W

136

08 k

g/h

M 7

55 k

mol/

h

ID

17 T

108

.0 C

P 3

8.7

bar

W 6

6679

6 kg

/h M

369

99 k

mol/

h

ID

23 T

80.

0 C

P 3

8.6

bar

W 6

6679

6 kg

/h M

369

99 k

mol/

h

ID

14 T

15.

0 C

P 5

0.0

bar

W 1

6362

kg/

h M

908

km

ol/h

ID

15 T

78.

4 C

P 3

8.6

bar

W 6

8315

8 kg

/h M

379

07 k

mol/

h

ID

19 T

105

.0 C

P 3

6.0

bar

W 3

3990

3 kg

/h M

169

02 k

mol/

h

ID

13 T

193

.0 C

P 3

6.1

bar

W 4

6099

6 kg

/h M

236

33 k

mol/

h

ID

9 T

180

.6 C

P 4

4.0

bar

W 8

0425

2 kg

/h M

446

38 k

mol/

hco

nd d

ischa

rge

ID

16 T

86.

1 C

P 3

5.9

bar

W 2

3436

kg/

h M

130

0 km

ol/h

HE2

HE3

HE8

ID

21 T

164

.4 C

P 3

8.8

bar

W 6

8040

5 kg

/h M

377

54 k

mol/

h

ID

25 T

154

.3 C

P 3

6.0

bar

W 6

6017

4 kg

/h M

366

46 k

mol/

h

20

3028

14

22

99

19

227

22

31

HE1

028

43

4445

Appendix

133


CoP gasifier

stream ID 1-3-DGAN-1 2-3-gas-1 4-3-gas-4 8-3-st-9 9-3-cw-1 10-3-mu-2 3-4-gas-3 3-8-gas-5 3-9-cw-2 3-10-ww-2name DGAN raw gas clean gas IP steam cooling water make up water shifted gas GT fuel cooling water waste watert °C 95.6 152.3 10.0 412.5 20.0 15.0 30.0 143.3 30.0 75.4p bar 34.0 39.0 33.4 50.6 6.0 50.0 35.9 32.4 4.0 35.9m kg/s 57.576 79.345 13.936 18.899 147 17.489 96.183 84.215 147 6.833n kmol/s 2.053 3.832 2.893 1.049 8.157 0.971 4.766 5.651 8.157 0.379V Nm³/h 165,655 309,164 233,398 384,603 455,946LHV kJ/kg 10,402 53,498 7,965 8,853HHV kJ/kg 11,476 62,444 9,284 10,704h kJ/kg 70 -5,804 -1,900 -12,756 -15,898 -15,919 -7,913 -2,096 -15,856 -15,649s J/kgK -825 930 -5,639 -2,725 -9,113 -9,184 -1,038 -1,090 -8,974 -8,379M kg/kmol 28.03 20.71 4.80 18.00 18.00 18.00 20.20 14.89 18.00 18.01



Appendix

134

Appendix C9 – CHEMCAD COshift model for the CCIGCC / GER gasifier

1

2

34

5 6

1

2

3

4 5 6

7

7

8

8

13

9

10

12

HP e

vap

reac

tor

1

reac

tor

212

HE2

HE3

HE1

15

9

16

17

18

21

19 HE4

11

20

23

13 25

20

22

24

23

41

25

26 HE

5

HE

6

29

44

HE7

28

33

38

37

43

HE9

42

10

16

27

2846

17

22

18

19

30

47

45

48

11

raw

gas

mod

erat

or s

team

quen

ch w

ater

satu

rate

d ga

s

shift

ed g

as

cond

. dis

char

ge

2930

4951

50

BFW

cw o

utcw

in

mak

e up

H2O32

76

77

78

79

80

98

9910

0

117

116

clean

gas

DGAN

115

34

15

96

35

ID

1

T 2

28.4

C P

60.

0 ba

r W

456

756

kg/h

M 2

3166

km

ol/h

ID

2

T 2

80.0

C P

60.

0 ba

r W

0 k

g/h

M 0

km

ol/h

ID

3

T 2

28.4

C P

60.

0 ba

r W

456

756

kg/h

M 2

3166

km

ol/h

ID

4

T 2

80.0

C P

59.

9 ba

r W

456

756

kg/h

M 2

3166

km

ol/h

ID

6

T 4

58.0

C P

58.

8 ba

r W

456

759

kg/h

M 2

3166

km

ol/h

ID

7 T

348

.4 C

P 5

8.6

bar

W 4

5675

9 kg

/h M

231

66 k

mol/

h

ID

8

T 2

79.9

C P

58.

5 ba

r W

456

759

kg/h

M 2

3166

km

ol/h

ID

12 T

333

.2 C

P 1

43.0

bar

W 8

6573

kg/

h M

480

6 km

ol/h

ID

14

T 3

36.2

C P

139

.5 b

ar W

865

73 k

g/h

M 4

806

kmol

/h

ID

1

5 T

333

.2 C

P 1

43.0

bar

W 8

6573

kg/

h M

480

6 km

ol/h

ID

9

T 3

13.9

C P

57.

4 ba

r W

456

760

kg/h

M 2

3166

km

ol/h

ID

23

T 1

16.0

C P

56.

8 ba

r W

426

043

kg/h

M 2

1461

km

ol/h

ID

20

T 1

86.2

C P

56.

9 ba

r W

426

043

kg/h

M 2

1461

km

ol/h

ID

21

T 1

86.2

C P

56.

9 ba

r W

220

41 k

g/h

M 1

223

kmol

/h

ID

2

7 T

114

.7 C

P 5

6.8

bar

W 3

5108

6 kg

/h M

173

01 k

mol/

h

ID

31 T

82.

7 C

P 5

6.5

bar

W 3

5108

6 kg

/h M

173

01 k

mol/

h

ID

33 T

83.

6 C

P 5

6.5

bar

W 7

199

kg/h

M 3

99 k

mol

/h

ID

29

T 1

07.2

C P

48.

0 ba

r W

157

181

kg/h

M 8

723

kmol

/h

ID

44 T

186

.2 C

P 5

6.9

bar

W 4

4808

4 kg

/h M

226

85 k

mol/

h

ID

28

T 1

14.7

C P

56.

8 ba

r W

749

58 k

g/h

M 4

160

kmol

/h

ID

38

T 6

8.0

C P

48.

0 ba

r W

601

82 k

g/h

M 3

340

kmol

/h

ID

37

T 2

3.2

C P

50.

0 ba

r W

601

82 k

g/h

M 3

340

kmol

/h

ID

39

T 1

5.0

C P

50.

0 ba

r W

529

83 k

g/h

M 2

941

kmol

/h

ID

41

T 3

0.0

C P

56.

4 ba

r W

341

224

kg/h

M 1

6755

km

ol/h

ID

4

3 T

30.

0 C

P 5

6.4

bar

W 3

4388

7 kg

/h M

169

03 k

mol

/h

ID

48 T

180

.8 C

P 4

6.0

bar

W 1

6559

6 kg

/h M

919

0 km

ol/h

ID

4

6 T

194

.3 C

P 5

7.0

bar

W 8

676

kg/h

M 4

82 k

mol

/h

ID

4

5 T

180

.0 C

P 4

6.0

bar

W 1

5692

1 kg

/h M

870

9 km

ol/h

ID

47 T

194

.3 C

P 5

7.0

bar

W 4

4808

4 kg

/h M

226

85 k

mol/

h

ID

42

T 3

0.0

C P

56.

4 ba

r W

266

3 kg

/h M

147

km

ol/h

ID

10

T 2

54.2

C P

57.

3 ba

r W

456

760

kg/h

M 2

3166

km

ol/h

ID

16 T

200

.0 C

P 7

0.0

bar

W 1

6559

7 kg

/h M

919

0 km

ol/h

ID

17

T 2

38.8

C P

57.

2 ba

r W

456

760

kg/h

M 2

3166

km

ol/h

ID

22

T 1

95.0

C P

16.

0 ba

r W

865

73 k

g/h

M 4

806

kmol

/h

ID

18

T 1

99.1

C P

145

.0 b

ar W

865

73 k

g/h

M 4

806

kmol

/h

ID

1

9 T

194

.3 C

P 5

7.0

bar

W 4

5676

0 kg

/h M

231

66 k

mol/

h

ID

30 T

181

.6 C

P 7

2.0

bar

W 1

6559

6 kg

/h M

919

0 km

ol/h

ID

51 T

30.

0 C

P 4

.0 b

ar W

943

994

kg/h

M 5

2400

km

ol/h

ID

49

T 2

0.0

C P

6.0

bar

W 9

4399

4 kg

/h M

524

00 k

mol

/h

ID

98 T

110

.2 C

P 3

2.4

bar

W 5

9796

8 kg

/h M

331

94 k

mol/

h

ID

99 T

10.

0 C

P 5

.0 b

ar W

644

70 k

g/h

M 3

579

kmol

/h

ID 1

00 T

11.

0 C

P 3

8.0

bar

W 6

4470

kg/

h M

357

9 km

ol/h

ID

117

T 7

3.3

C P

33.

0 ba

r W

233

760

kg/h

M 1

6760

km

ol/h

ID 1

16 T

95.

6 C

P 3

4.0

bar

W 1

9002

6 kg

/h M

677

5 km

ol/h

ID

97

T 1

76.2

C P

36.

0 ba

r W

662

502

kg/h

M 3

6776

km

ol/h

ID

24

T 1

0.0

C P

53.

9 ba

r W

437

33 k

g/h

M 9

985

kmol

/h

ID

11

5 T

100

.8 C

P 3

8.0

bar

W 6

6243

8 kg

/h M

367

73 k

mol

/h

ID

35

T 1

00.6

C P

32.

4 ba

r W

662

438

kg/h

M 3

6773

km

ol/h

ID

34

T 1

00.8

C P

38.

0 ba

r W

662

502

kg/h

M 3

6776

km

ol/h

ID

11

T 4

1.3

C P

18.

0 ba

r W

865

73 k

g/h

M 4

806

kmol

/h

ID

32

T 8

3.6

C P

56.

5 ba

r W

343

887

kg/h

M 1

6903

km

ol/h

97

26

ID

26

T 1

57.0

C P

32.

4 ba

r W

298

294

kg/h

M 2

0342

km

ol/h

39

42

14

71

HP s

team

4344

2472

73

exp.

tur

b.

31

ID

7

2 T

94.

7 C

P 5

3.7

bar

W 4

3733

kg/

h M

998

5 km

ol/h

ID

7

3 T

58.

3 C

P 3

3.0

bar

W 4

3733

kg/

h M

998

5 km

ol/h

45

2774

ID

74 T

94.

4 C

P 5

6.7

bar

W 3

5108

6 kg

/h M

173

01 k

mol/

h

Appendix

135


GER

stream ID 1-3-DGAN-1 2-3-gas-1 4-3-gas-4 8-3-BFW-3 9-3-cw-1 10-3-mu-2 3-2-wa-2 3-4-gas-3 3-8-gas-5 3-8-st-8 3-9-cw-2 3-10-ww-2name DGAN raw gas clean gas BFW cooling water make up water quench water shifted gas GT fuel HP steam cooling water waste watert °C 95.6 228.4 10.0 41.3 20.0 15.0 200.0 30.0 157.0 336.2 30.0 30.0p bar 34.0 60.0 53.9 18.0 6.0 50.0 70.0 56.4 32.4 139.5 4.0 56.4m kg/s 59.596 143.247 13.716 27.151 296.054 36.836 51.934 107.014 93.550 27.151 296.054 0.835n kmol/s 2.125 7.265 3.131 1.507 16.434 2.045 2.882 5.255 6.380 1.507 16.434 0.046V Nm³/h 171,445 586,234 252,669 424,002 514,763LHV kJ/kg 5,731 53,716 7,059 7,875HHV kJ/kg 7,259 63,071 8,276 9,778h kJ/kg 70 -8,638 -1,604 -15,809 -15,898 -15,919 -15,122 -7,999 -2,869 -13,324 -15,856 -15,814s J/kgK -825 -610 -6,408 -8,822 -9,113 -9,184 -7,079 -1,143 -1,088 -4,056 -8,974 -8,935M kg/kmol 28.03 19.71 4.37 18.00 18.00 18.00 18.00 20.39 14.65 18.00 18.00 18.05

Σ mol % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mol % 0.00 17.73 91.68 0.00 0.00 0.00 0.00 54.73 45.00 0.00 0.00 0.00CO mol % 0.00 23.58 4.00 0.00 0.00 0.00 0.00 2.39 1.96 0.00 0.00 0.00CO2 mol % 0.00 7.42 0.50 0.00 0.00 0.00 0.01 40.51 0.25 0.00 0.00 0.16N2 mol % 99.58 0.51 2.24 0.00 0.00 0.00 0.00 0.71 34.27 0.00 0.00 0.00Ar mol % 0.22 0.55 1.29 0.00 0.00 0.00 0.00 0.76 0.71 0.00 0.00 0.00CH4 mol % 0.00 0.12 0.27 0.00 0.00 0.00 0.00 0.17 0.13 0.00 0.00 0.00O2 mol % 0.20 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.07 0.00 0.00 0.00H2O mol % 0.00 49.62 0.00 100.00 100.00 100.00 99.98 0.10 17.61 100.00 100.00 99.79H2S mol % 0.00 0.43 0.00 0.00 0.00 0.00 0.01 0.63 0.00 0.00 0.00 0.06COS mol % 0.00 0.03 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CS2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SO2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCN mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NH3 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CH3OH mol % 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Σ mass % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mass % 0.00 1.81 42.19 0.00 0.00 0.00 0.00 5.42 6.19 0.00 0.00 0.00CO mass % 0.00 33.50 25.58 0.00 0.00 0.00 0.00 3.28 3.75 0.00 0.00 0.00CO2 mass % 0.00 16.56 5.02 0.00 0.00 0.00 0.02 87.55 0.74 0.00 0.00 0.38N2 mass % 99.46 0.73 14.33 0.00 0.00 0.00 0.00 0.98 65.46 0.00 0.00 0.00Ar mass % 0.31 1.11 11.81 0.00 0.00 0.00 0.00 1.49 1.93 0.00 0.00 0.00CH4 mass % 0.00 0.10 1.01 0.00 0.00 0.00 0.00 0.13 0.15 0.00 0.00 0.00O2 mass % 0.23 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.14 0.00 0.00 0.00H2O mass % 0.00 45.34 0.00 100.00 100.00 100.00 99.96 0.09 21.63 100.00 100.00 99.51H2S mass % 0.00 0.75 0.00 0.00 0.00 0.00 0.02 1.06 0.00 0.00 0.00 0.11COS mass % 0.00 0.10 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00 0.00CS2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SO2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCN mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NH3 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CH3OH mass % 0.00 0.00 0.06 0.00 0.00 0.00 0.00 0.00 0.01 0.00 0.00 0.00

Appendix

136

Appendix D1 – CHEMCAD model of the AGR unit for the CCIGCC

2

6

10

12

1323 14

16

17

18

20

2223

24

35

25

26

27

28

30

31

32

34

35

38

46

41

42

43

44

45

47

48

49

50

52

5351

55

25

61

9

19

40

54

57

58

60 5

3336

104

15 16

17

105

24

34

47

50

109

53

56

62

63

80

82

83

84

86

112

113

8785

88

74

75

90

114

feed

gas

scru

bbing

wa

CLAU

S-ga

s

MeO

H m

ake-

up

72

strip

ping

N2

Q_c

ond_

MeO

H/wa

ter

colum

n

coole

r 2

LP-c

ompr

IP-c

ompr

inter

coole

rco

nden

ser

sub

coole

r

IP-v

alve

LP-v

alve

pre

wash

89

evap

orat

or

18

H2S

abso

rber

pum

p 1

CO2

abso

rber

chiller

4

73

40

40

chiller

3

LP-f

lash

Reab

sorb

er 1

Reab

sorb

er 2

108

pum

p 4

hot

flash

pum

p 5

Rege

nera

tion

scru

bber

MeO

H/H2

O

pum

p 2

pum

p 3

8111

1

pum

p 6

62

63

64 65

IP-f

lash

1/1

IP-f

lash

1/2

41

66

67

3068

69

IP-f

lash

2/1

IP-f

lash

3/1

IP-f

lash

2/2

IP-f

lash

3/2

27

28

29

31

120

121

122

123

3212

8

130

12913

1

com

pr 2

_2co

mpr

2_1

com

pr 2

_3

com

pr 3

9

1

39

5

56

8

7

chiller

1

122

4448

11

4

7

198

45

200

3

3

12

4

10

46

42

26

19

39

59

123

11

70

124

2251

125

127

203

126

102

127

128

204

206

43

207

64

106

6971

68

107

129

210

211

54

55

101

140

5223

0

38

202

57

36

pum

p 7

205

14

20

8

103

29

21

58

199

15

2

65

110

59

61

21

76

238

37

6022

5

66

7071

637

67

237

49

126

125

124

33

7273

79

coole

r 1

74

192

91ta

il gas

LP C

O2

clean

gas

IP C

O2

Claus

fue

l

75 93

94

M&D

r fu

el

ID

80

T -

41.4

3 C

P 0

.67

bar

M 3

549.

61 k

mol/

h W

604

53.4

8 kg

/h

ID

82

T -

46.2

5 C

P 0

.42

bar

M 3

549.

61 k

mol/

h W

604

53.3

8 kg

/h

ID

83

T 1

51.7

7 C

P 4

.11

bar

M 3

549.

61 k

mol/

h W

604

53.3

8 kg

/h

ID

84

T 3

0.00

C P

3.9

6 ba

r M

354

9.61

km

ol/h

W 6

0453

.38

kg/h ID

85

T 2

6.92

C P

3.9

6 ba

r M

392

9.47

km

ol/h

W 6

6922

.83

kg/h

ID

86

T 1

11.6

5 C

P 9

.81

bar

M 3

929.

47 k

mol/

h W

669

22.8

3 kg

/h

ID

87

T 2

4.00

C P

9.6

6 ba

r M

392

9.47

km

ol/h

W 6

6922

.83

kg/h

ID

88

T -

2.08

C P

3.9

6 ba

r M

392

9.47

km

ol/h

W 6

6922

.83

kg/h

ID

90

T -

2.08

C P

3.9

6 ba

r M

354

9.61

km

ol/h

W 6

0453

.48

kg/h

ID

112

T 2

4.35

C P

9.7

4 ba

r M

392

9.47

km

ol/h

W 6

6922

.83

kg/h

ID

113

T 2

4.00

C P

9.6

6 ba

r M

392

9.47

km

ol/h

W 6

6922

.83

kg/h

ID

89

T -

2.08

C P

3.9

6 ba

r M

379

.86

kmol/

h W

646

9.35

kg/

h

ID

81

T -

46.0

0 C

P 0

.52

bar

M 3

549.

61 k

mol/

h W

604

53.4

8 kg

/h

ID

111

T -

46.0

0 C

P 0

.52

bar

M 3

549.

61 k

mol/

h W

604

53.4

8 kg

/h

ID

105

T -

48.9

C P

36.

88 b

ar W

689

494

kg/h

M 2

1551

km

ol/h

ID

23

T -

22.2

C P

34.

08 b

ar W

997

670

kg/h

M 2

8979

km

ol/h

ID

24

T -

22.2

C P

34.

08 b

ar W

448

951

kg/h

M 1

3041

km

ol/h

ID

34

T -

23.8

C P

9.5

0 ba

r W

534

507

kg/h

M 1

5576

km

ol/h

ID

35

T -

42.0

C P

9.2

5 ba

r W

534

507

kg/h

M 1

5576

km

ol/h

ID

104

T -

47.9

C P

33.

88 b

ar W

569

29 k

g/h

M 1

1335

km

ol/h

ID

50

T -

50.9

C P

1.3

0 ba

r W

113

3411

kg/

h M

344

37 k

mol/

h

ID

47

T 0

.0 C

P 3

.00

bar

W 0

kg/

h M

0 k

mol/

h

ID

74

T -

26.0

C P

34.

06 b

ar W

866

389

kg/h

M 2

5366

km

ol/h

ID

75

T -

42.0

C P

34.

06 b

ar W

866

389

kg/h

M 2

5366

km

ol/h

ID

25

T -

22.2

C P

37.

68 b

ar W

448

951

kg/h

M 1

3041

km

ol/h

ID

17

T 1

30.3

C P

9.7

5 ba

r W

111

63 k

g/h

M 5

97 k

mol/

h

ID

53

T 7

2.9

C P

3.0

0 ba

r W

174

921

kg/h

M 4

752

kmol/

h

ID

56

T 7

2.9

C P

3.0

0 ba

r W

697

800

kg/h

M 2

1764

km

ol/h

ID

15

T -

26.6

C P

34.

97 b

ar W

358

kg/

h M

13

kmol/

h

ID

16

T 3

3.6

C P

10.

00 b

ar W

111

63 k

g/h

M 5

97 k

mol/

h

ID

63

T 3

5.0

C P

1.2

0 ba

r W

108

05 k

g/h

M 5

83 k

mol/

h

ID

114

T 0

.0 C

P 0

.00

bar

W 0

kg/

h M

0 k

mol/

h

ID

62

T 1

6.7

C P

1.2

0 ba

r W

768

4 kg

/h M

200

km

ol/h

ID

109

T 2

5.2

C P

3.0

0 ba

r W

523

634

kg/h

M 1

5910

km

ol/h

ID

72

T 1

5.0

C P

36.

88 b

ar W

739

kg/

h M

23

kmol/

h

ID

18

T 1

46.5

C P

4.8

0 ba

r W

105

83 k

g/h

M 5

78 k

mol/

h

ID

73

T -

48.8

C P

36.

88 b

ar W

689

474

kg/h

M 2

1551

km

ol/h

ID

40

T -

49.3

C P

36.

88 b

ar W

514

33 k

g/h

M 1

517

kmol/

h

ID

108

T -

44.8

C P

3.2

5 ba

r W

523

634

kg/h

M 1

5910

km

ol/h

ID

28

T -

22.2

C P

34.

08 b

ar W

548

718

kg/h

M 1

5939

km

ol/h

ID

122

T -

23.8

C P

9.5

0 ba

r W

142

12 k

g/h

M 3

62 k

mol/

h

ID

27

T -

22.0

C P

34.

43 b

ar W

497

890

kg/h

M 1

4175

km

ol/h

ID

123

T -

26.8

C P

9.5

0 ba

r W

258

50 k

g/h

M 6

23 k

mol/

h

ID

32

T 0

.0 C

P 0

.00

bar

W 0

kg/

h M

0 k

mol/

h

ID

41

T -

42.0

C P

9.2

5 ba

r W

326

049

kg/h

M 9

501

kmol/

h

ID

130

T -

23.8

C P

9.5

0 ba

r W

534

507

kg/h

M 1

5576

km

ol/h

ID

29

T -

23.8

C P

9.5

0 ba

r W

0 k

g/h

M 0

km

ol/h

ID

131

T -

23.8

C P

9.5

0 ba

r W

534

507

kg/h

M 1

5576

km

ol/h

ID

30

T -

26.8

C P

9.5

0 ba

r W

0 k

g/h

M 0

km

ol/h

ID

128

T -

26.8

C P

9.5

0 ba

r W

472

040

kg/h

M 1

3552

km

ol/h

ID

129

T -

26.8

C P

9.5

0 ba

r W

472

040

kg/h

M 1

3552

km

ol/h

ID

31

T 0

.0 C

P 0

.00

bar

W 0

kg/

h M

0 k

mol/

h

ID

121

T -

26.8

C P

9.5

0 ba

r W

0 k

g/h

M 0

km

ol/h

ID

120

T -

23.8

C P

9.5

0 ba

r W

0 k

g/h

M 0

km

ol/h

ID

9

T -

24.2

C P

34.

43 b

ar W

313

674

kg/h

M 1

7245

km

ol/h

ID

39

T -

42.0

C P

9.2

5 ba

r W

0 k

g/h

M 0

km

ol/h

ID

5

T -

49.5

C P

2.8

0 ba

r W

514

33 k

g/h

M 1

517

kmol/

h

ID

8

T 5

.0 C

P 3

5.38

bar

W 3

6331

4 kg

/h M

184

11 k

mol/

h

ID

44

T -

49.5

C P

2.8

0 ba

r W

190

246

kg/h

M 4

328

kmol/

h

ID

48

T -

59.9

C P

1.3

0 ba

r W

106

835

kg/h

M 2

428

kmol/

h

ID

11

T -

47.9

C P

33.

88 b

ar W

569

29 k

g/h

M 1

1335

km

ol/h

ID

7

T 1

1.3

C P

35.

63 b

ar W

363

314

kg/h

M 1

8411

km

ol/h

ID

198

T -

15.0

C P

33.

63 b

ar W

569

29 k

g/h

M 1

1335

km

ol/h

ID

200

T -

15.0

C P

2.5

5 ba

r W

190

251

kg/h

M 4

328

kmol/

h

ID

45

T 1

0.0

C P

2.3

0 ba

r W

190

251

kg/h

M 4

328

kmol/

h

ID

13

T 1

0.0

C P

33.

38 b

ar W

565

02 k

g/h

M 1

1249

km

ol/h

ID

3

T -

26.5

C P

35.

13 b

ar W

363

189

kg/h

M 1

8399

km

ol/h

ID

12

T 5

.0 C

P 3

5.38

bar

W 3

43 k

g/h

M 1

9 km

ol/h

ID

4

T 4

2.9

C P

4.5

5 ba

r W

635

2 kg

/h M

347

km

ol/h

ID

10

T -

49.5

C P

2.8

0 ba

r W

514

33 k

g/h

M 1

517

kmol/

h ID

46

T -

43.8

C P

2.8

0 ba

r W

103

0883

kg/

h M

307

67 k

mol/

h

ID

42

T -

42.0

C P

9.2

5 ba

r W

208

458

kg/h

M 6

075

kmol/

h

ID

26

T -

34.0

C P

37.

43 b

ar W

448

951

kg/h

M 1

3041

km

ol/h

ID

19

T -

34.0

C P

37.

43 b

ar W

448

515

kg/h

M 1

3028

km

ol/h

ID

69

T -

39.8

C P

37.

13 b

ar W

688

735

kg/h

M 2

1527

km

ol/h

ID

71

T -

48.9

C P

36.

88 b

ar W

688

735

kg/h

M 2

1527

km

ol/h

ID

70

T -

44.8

C P

3.2

5 ba

r W

872

724

kg/h

M 2

6517

km

ol/h

ID

22

T -

50.9

C P

3.5

0 ba

r W

872

726

kg/h

M 2

6517

km

ol/h

ID

51

T -

50.9

C P

3.5

0 ba

r W

113

3411

kg/

h M

344

37 k

mol/

h

ID

127

T -

25.7

C P

9.5

0 ba

r W

400

62 k

g/h

M 9

85 k

mol/

h

ID

203

T -

25.7

C P

9.5

0 ba

r W

0 k

g/h

M 0

km

ol/h

ID

102

T -

50.9

C P

3.5

0 ba

r W

260

684

kg/h

M 7

921

kmol/

h

ID

204

T -

25.7

C P

9.5

0 ba

r W

400

62 k

g/h

M 9

85 k

mol/

h

ID

206

T -

31.1

C P

9.3

5 ba

r W

299

553

kg/h

M 8

808

kmol/

h

ID

43

T -

26.8

C P

9.5

0 ba

r W

472

040

kg/h

M 1

3552

km

ol/h

ID

207

T -

28.4

C P

9.3

5 ba

r W

771

593

kg/h

M 2

2360

km

ol/h

ID

64

T 3

5.3

C P

10.

00 b

ar W

108

05 k

g/h

M 5

83 k

mol/

h

ID

106

T -

44.8

C P

3.2

5 ba

r W

349

089

kg/h

M 1

0607

km

ol/h

ID

68

T 9

5.8

C P

37.

38 b

ar W

688

743

kg/h

M 2

1528

km

ol/h

ID

107

T 8

7.7

C P

3.0

0 ba

r W

349

089

kg/h

M 1

0607

km

ol/h

ID

210

T -

53.9

C P

1.3

0 ba

r W

431

737

kg/h

M 1

3069

km

ol/h I

D 2

11 T

-45

.5 C

P 1

.30

bar

W 4

3173

6 kg

/h M

130

69 k

mol/

h

ID

54

T 7

4.2

C P

3.0

5 ba

r W

174

921

kg/h

M 4

752

kmol/

h

ID

55

T -

39.8

C P

2.8

0 ba

r W

174

921

kg/h

M 4

752

kmol/

h

ID

101

T -

26.6

C P

34.

97 b

ar W

363

049

kg/h

M 1

8392

km

ol/h

ID

52

T 7

2.9

C P

3.0

0 ba

r W

872

721

kg/h

M 2

6517

km

ol/h

ID

230

T 7

2.9

C P

3.0

0 ba

r W

872

721

kg/h

M 2

6517

km

ol/h

ID

38

T -

42.0

C P

9.2

5 ba

r W

534

507

kg/h

M 1

5576

km

ol/h I

D 2

02 T

-50

.9 C

P 1

2.35

bar

W 2

6068

4 kg

/h M

792

1 km

ol/h

ID

57

T 7

2.9

C P

3.0

0 ba

r W

697

800

kg/h

M 2

1764

km

ol/h

ID

36

T -

42.0

C P

9.2

5 ba

r W

0 k

g/h

M 0

km

ol/h

ID

205

T -

51.1

C P

9.3

5 ba

r W

119

3 kg

/h M

98

kmol/

h

ID

14

T 1

0.0

C P

9.1

0 ba

r W

119

3 kg

/h M

98

kmol/

h

ID

20

T 1

10.1

C P

4.8

0 ba

r W

580

kg/

h M

18

kmol/

h

ID

103

T 5

.0 C

P 3

5.38

bar

W 3

6297

1 kg

/h M

183

93 k

mol/

h

ID

21

T -

34.0

C P

37.

43 b

ar W

436

kg/

h M

13

kmol/

h

ID

58

T -

34.0

C P

37.

43 b

ar W

218

kg/

h M

6 k

mol/

h I

D 1

99 T

-34

.0 C

P 3

7.43

bar

W 2

18 k

g/h

M 6

km

ol/h

ID

2

T 4

5.0

C P

4.5

5 ba

r W

105

83 k

g/h

M 5

78 k

mol/

h

ID

238

T 4

5.0

C P

4.5

5 ba

r W

600

9 kg

/h M

328

km

ol/h

ID

65

T 9

4.9

C P

3.0

0 ba

r W

688

743

kg/h

M 2

1528

km

ol/h I

D 1

10 T

30.

0 C

P 3

.00

bar

W 9

057

kg/h

M 2

37 k

mol/

h

ID

59

T 3

0.0

C P

3.0

0 ba

r W

906

kg/

h M

24

kmol/

h

ID

61

T 1

5.0

C P

50.

00 b

ar W

576

5 kg

/h M

320

km

ol/h

ID

76

T 4

5.0

C P

4.5

5 ba

r W

457

4 kg

/h M

250

km

ol/h

ID

60

T 3

0.0

C P

3.0

0 ba

r W

815

1 kg

/h M

213

km

ol/h

ID

225

T 4

1.0

C P

3.0

0 ba

r W

127

25 k

g/h

M 4

63 k

mol/

h

ID

66

T 3

0.0

C P

4.3

0 ba

r W

457

4 kg

/h M

250

km

ol/h

ID

78

T 1

50.8

C P

4.8

bar

W 3

2955

kg/

h

ID

77

T 2

75.8

C P

6.1

bar

W 3

2955

kg/

h

ID

37

T 3

0.0

C P

4.0

bar

W 3

0491

75 k

g/h

ID

6

T 2

0.0

C P

6.0

bar

W 3

0491

75 k

g/h

ID

91

T 3

0.0

C P

35.

89 b

ar W

919

1 kg

/h I

D

92 T

30.

0 C

P 3

5.88

bar

W 3

6331

4 kg

/h M

184

11 k

mol/

h

ID

93

T 1

0.0

C P

33.

38 b

ar W

427

kg/

h M

85

kmol/

h

ID

13

T 1

0.0

C P

33.

38 b

ar W

565

02 k

g/h

M 1

1249

km

ol/h

ID

94

T 1

0.0

C P

33.

38 b

ar W

569

29 k

g/h

M 1

1335

km

ol/h

ID

237

T 4

.7 C

P 3

5.38

bar

W 3

6318

9 kg

/h M

183

99 k

mol/

h

ID

49

T -

15.0

C P

1.0

5 ba

r W

106

834

kg/h

M 2

428

kmol/

h

ID

126

T 0

.0 C

P 0

.00

bar

W 0

kg/

h M

0 k

mol/

h

ID

125

T 0

.0 C

P 0

.00

bar

W 0

kg/

h M

0 k

mol/

h

ID

124

T 0

.0 C

P 0

.00

bar

W 0

kg/

h M

0 k

mol/

h

ID

33

T 0

.0 C

P 0

.00

bar

W 0

kg/

h M

0 k

mol/

h

ID

1

T 3

0.0

C P

35.

88 b

ar W

354

123

kg/h

M 1

8101

km

ol/h

13

MeO

H ble

ed

wast

e wa

ter

103

104

7716

678

167

Appendix

137

2

1 2

3

4

86

36

5

1

MeO

H b

leed

gasi

fierv

ent

fuel

gas

12

CLA

US

gas

59

10

13

4

14

11

15

2627

ID

1 T

110

.1 C

P 4

.8 b

ar W

580

kg/h

M 1

8 km

ol/h

ID

2 T

70.0

C P

2.0

bar

W 0

kg/h

M 0

kmol

/h

ID

3 T

15.

0 C

P 1

.0 b

ar W

376

1 kg

/h M

130

km

ol/h

ID

5 T

91.0

C P

2.0

bar

W 4

341

kg/h

M 1

49 k

mol

/h

ID

6 T

10.

0 C

P 9

.1 ba

r W

119

2 kg

/h M

98 k

mol

/h

ID

7 T

10.

0 C

P 9

.1 b

ar W

119

2 kg

/h M

98

kmol

/h ID

8 T

10.

0 C

P 9

.1 b

ar W

0 k

g/h

M 0

km

ol/h

ID

9 T

91.0

C P

2.0

bar

W 4

341

kg/h

M 1

49 k

mol

/h

ID 1

2 T

60.

0 C

P 5

0.0

bar

W 17

58 k

g/h

M 5

5 km

ol/h

ID 1

3 T

16.

7 C

P 1

.2 b

ar W

7684

kg/

h M

200

km

ol/h

ID

4 T

88.

7 C

P 2

.0 b

ar W

376

1 kg

/h M

130

km

ol/h

ID 1

4 T

687

.6 C

P 1

.2 ba

r W

1378

2 kg

/h M

410

km

ol/h

ID

11 T

179

3.2

C P

1.9

bar

W 4

341

kg/h

M 1

56 k

mol

/h

ID 1

5 T

115

0.0

C P

1.2

bar

W 13

783

kg/h

M 4

44 k

mol

/h

307

33

36

34

38

43

16

17

18

1920

21

2223

2425

43

2829

30

32

33

35

36

3839

40

42

4445

46

48

50

53

56

58 596061

65

677

8

9

1012

11

1314

15

16

17

18

19

20

21

22

25

28

29

31

32

35

37

39

40

41

Ther

malS

tage

NH

3 bu

rner

ID

16 T

115

0.0

C P

1.2

bar

W 8

08 k

g/h

M 2

6 km

ol/h

ID 1

9 T

200

.0 C

P 1

.2 b

ar W

1055

5 kg

/h M

342

km

ol/h

ID

43 T

200

.0 C

P 1

.2 ba

r W

242

0 kg

/h M

76 k

mol

/h

ID 4

9 T

154

.2 C

P 1

4.0

bar

W 98

23 k

g/h

M 5

45 k

mol

/h

ID

18 T

200

.0 C

P 1

.2 ba

r W

129

74 k

g/h

M 4

18 k

mol

/h

ID

51 T

164

.0 C

P 6

.6 b

ar W

982

3 kg

/h M

545

km

ol/h

ID

17 T

115

0.0

C P

1.2

bar

W 1

2974

kg/

h M

418

km

ol/h

LP B

FW

LP st

eam

ID

21 T

280

.0 C

P 1

.2 b

ar W

113

63 k

g/h

M 3

68 k

mol

/h

ID 5

4 T

164

.0 C

P 6

.6 ba

r W

1939

kg/

h M

108

km

ol/h

ID

23 T

200

.0 C

P 1

.2 b

ar W

113

63 k

g/h

M 3

80 k

mol

/h

ID

22 T

352

.4 C

P 1

.2 b

ar W

113

63 k

g/h

M 3

80 k

mol

/h

ID 2

4 T

200

.0 C

P 1

.2 ba

r W

1059

9 kg

/h M

356

km

ol/h

ID

58 T

264

.7 C

P 5

0.6 b

ar W

302

kg/

h M

17 k

mol

/h

ID 5

9 T

248

.9 C

P 3

9.0 b

ar W

302

kg/h

M 1

7 km

ol/h

ID 5

2 T

154

.2 C

P 1

4.0

bar

W 19

39 k

g/h

M 1

08 k

mol

/h

ID

61 T

246

.0 C

P 3

8.0

bar

W 3

02 k

g/h

M 1

7 km

ol/h

ID 2

5 T

240

.0 C

P 1

.1 b

ar W

1059

9 kg

/h M

356

km

ol/h

ID

44 T

200

.0 C

P 1

.2 ba

r W

764

kg/

h M

24 k

mol

/h

LP B

FWLP

ste

am

IP s

team

IP c

ond.

ID

26 T

294

.0 C

P 1

.1 b

ar W

105

99 k

g/h

M 3

61 k

mol

/h

ID

28 T

135

.0 C

P 1

.1 ba

r W

103

42 k

g/h

M 3

53 k

mol

/h

Cat

sta

ge 2

Cat

Sta

ge 1

ID

45 T

135

.0 C

P 1

.1 b

ar W

257

kg/

h M

8 k

mol

/h

ID

48 T

194

.6 C

P 1

.1 b

ar W

60

kg/h

M 3

km

ol/h ID

29

T 1

35.5

C P

1.1

bar

W 10

403

kg/h

M 3

56 k

mol

/h

ID 4

7 T

194

.6 C

P 1

.1 ba

r W

3380

kg/

h M

105

km

ol/h

ID 4

6 T

194

.6 C

P 1

.1 ba

r W

3440

kg/

h M

109

km

ol/h

42

46

7576

47

ID

75 T

135

.0 C

P 1

.1 b

ar W

338

0 kg

/h M

105

km

ol/h

ID

76 T

134

.8 C

P 5

.0 ba

r W

338

0 kg

/h M

105

km

ol/h

sulfu

r

37

heat

er

ID 3

5 T

15.0

C P

1.0

bar

W 27

1 kg

/h M

9 km

ol/h

ID

36 T

88.

7 C

P 2

.0 ba

r W

271

kg/

h M

9 km

ol/h

ID

40 T

10.

0 C

P 9

.1 b

ar W

112

1 kg

/h M

92

kmol

/h

ID 3

7 T

10.

0 C

P 9

.1 b

ar W

72 k

g/h

M 6

km

ol/h

ID

38 T

57.

7 C

P 2

.0 b

ar W

342

kg/

h M

15

kmol

/h

ID

39 T

189

2.8

C P

2.0

bar

W 3

42 k

g/h

M 1

3 km

ol/h ID

30

T 2

03.4

C P

1.1

bar

W 1

0745

kg/

h M

370

km

ol/h

com

pr 1

com

pr 2

Hyd

rogen

ator

31

ID 4

2 T

10.0

C P

9.1

bar

W 15

3 kg

/h M

13 k

mol

/h

ID

55 T

154

.2 C

P 1

4.0

bar

W 4

30 k

g/h

M 2

4 km

ol/h

ID

32 T

246

.5 C

P 1

.1 b

ar W

108

98 k

g/h

M 3

79 k

mol

/h

ID 5

7 T

164

.2 C

P 6

.6 b

ar W

430

kg/h

M 2

4 km

ol/h

ID 3

3 T

180

.0 C

P 1

.1 b

ar W

1089

8 kg

/h M

379

km

ol/h

ID 3

1 T

197

.9 C

P 1

.1 b

ar W

1089

8 kg

/h M

382

km

ol/h

ID

41 T

10.

0 C

P 9

.1 ba

r W

967

kg/

h M

79 k

mol

/h

71

70

ID

65 T

37.7

C P

1.1

bar

W 2

5198

1 kg

/h M

139

82 k

mol

/h ID

66

T 3

7.7

C P

1.1

bar

W 2

520

kg/h

M 1

40 k

mol

/h

ID 6

7 T

37.7

C P

1.1

bar

W 24

9461

kg/h

M 1

3843

km

ol/h

ID

71 T

30.

0 C

P 4

.0 ba

r W

249

461

kg/h

M 1

3843

km

ol/h

ID

70 T

30.

0 C

P 5

.0 b

ar W

0 k

g/h

M 0

km

ol/h

scru

bber

pum

p 1

pum

p 2

47

34

50

53

ID 8

0 T

100

.1 C

P 2

.3 ba

r W

8377

kg/

h M

239

km

ol/h

5641

57

60

ID 1

01 T

25.

1 C

P 9

.1 ba

r W

922

2 kg

/h M

312

km

ol/h

proc

ess

cond

63

64

65

105

106

ID 1

05 T

30.

0 C

P 3

5.9 b

ar W

919

1 kg

/h M

310

km

ol/h

104

tail

gas

proc

ess

cond

air 2air 1ox

ygen

66

67

109

LP B

FW

LP st

eam

ID 1

10 T

164

.3 C

P 6

.6 ba

r W

762

6 kg

/h M

423

km

ol/h

ID 1

08 T

154

.2 C

P 1

4.0 b

ar W

762

6 kg

/h M

423

km

ol/h

LP B

FWLP

ste

am

68

2627

ID

27 T

135

.0 C

P 1

.1 b

ar W

105

99 k

g/h

M 3

61 k

mol

/h

23

68

62

ID 6

2 T

30.0

C P

4.0

bar

W 24

9461

kg/h

M 1

3843

km

ol/h

ID

68 T

37.

8 C

P 5

.0 b

ar W

249

461

kg/h

M 1

3843

km

ol/h

24

80

44

45

ID

63 T

30.0

C P

2.2

bar

W 8

377

kg/h

M 2

39 k

mol

/h

ID 6

4 T

30.

0 C

P 4

.5 b

ar W

8295

kg/

h M

235

km

ol/h

ID

69 T

100

.0 C

P 9

.2 ba

r W

825

5 kg

/h M

232

km

ol/h

ID

72 T

30.0

C P

9.1

bar

W 8

255

kg/h

M 2

32 k

mol

/h

ID

82 T

100

.1 C

P 4

.5 b

ar W

829

5 kg

/h M

235

km

ol/h

48

73

49

101

78

ID 1

03 T

25.

1 C

P 9

.1 b

ar W

920

2 kg

/h M

311

km

ol/h

ID 7

3 T

93.0

C P

18.1

bar

W 92

02 k

g/h

M 3

11 k

mol

/h

ID 7

4 T

30.

0 C

P 1

8.1

bar

W 92

02 k

g/h

M 3

11 k

mol

/h

ID

77 T

98.

3 C

P 3

5.9

bar

W 9

197

kg/h

M 3

10 k

mol

/h

ID

78 T

30.

0 C

P 3

5.9

bar

W 9

197

kg/h

M 3

10 k

mol

/h

ID 1

04 T

25.

1 C

P 9

.1 b

ar W

20

kg/h

M 1

km

ol/h

ID 1

06 T

30.

0 C

P 3

5.9 b

ar W

6 k

g/h

M 0

kmol

/h

103

77

51

52

8183

ID

83 T

30.1

C P

4.0

bar

W 3

3297

9 kg

/h M

184

83 k

mol

/h

CW

inC

W o

ut10

0 ID

100

T 2

0.0

C P

6.0

bar

W 33

2979

kg/h

M 1

8483

km

ol/h

66

5463

55

107

79

8485

5864

87

82

6972

5974

88

61

86

89

90

62

108

91

69

52 92

70

55 93

71

4994

81

51120

82

83

54 122

84

57 123

110

121

Appendix D2 – CHEMCAD model of the TGT process for the CCIGCC

Appendix

138

1

1

3

2

2

3

4

4

5

56

6

7

7

8

9

10

89

1110

11

12

12

13

13

14

14

1516

ID

1 T

-15.

0 C

P 1

.0 b

ar W

106

834

kg/h

M 2

428

kmol

/h

ID

2 T

48.

9 C

P 2

.3 b

ar W

106

834

kg/h

M 2

428

kmol

/h ID

3

T 1

0.0

C P

2.3

bar

W 1

9024

2 kg

/h M

432

8 km

ol/h

ID

4 T

24.

2 C

P 2

.3 b

ar W

297

076

kg/h

M 6

757

kmol

/h

ID

5 T

79.

5 C

P 4

.3 b

ar W

297

076

kg/h

M 6

757

kmol

/h

ID

6 T

30.

0 C

P 4

.2 b

ar W

297

076

kg/h

M 6

757

kmol

/h

ID

7 T

86.

3 C

P 8

.0 b

ar W

297

076

kg/h

M 6

757

kmol

/h

ID

12 T

30.

0 C

P 2

8.1

bar

W 2

9707

6 kg

/h M

675

7 km

ol/h

ID

13 T

90.

0 C

P 5

3.0

bar

W 2

9707

6 kg

/h M

675

7 km

ol/h

ID

14 T

30.

0 C

P 5

2.9

bar

W 2

9707

6 kg

/h M

675

7 km

ol/h

ID

15 T

89.

3 C

P 1

00.1

bar

W 2

9707

6 kg

/h M

675

7 km

ol/h

ID

16 T

30.

0 C

P 1

00.0

bar

W 2

9707

6 kg

/h M

675

7 km

ol/h

ID

8 T

87.

0 C

P 1

5.0

bar

W 2

9707

6 kg

/h M

675

7 km

ol/h

ID

9 T

30.

0 C

P 1

4.9

bar

W 2

9707

6 kg

/h M

675

7 km

ol/h

ID

11 T

30.

0 C

P 7

.9 b

ar W

297

076

kg/h

M 6

757

kmol

/h ID

10

T 8

8.3

C P

28.

2 ba

r W

297

076

kg/h

M 6

757

kmol

/h

com

pr1

com

pr2

com

pr3

com

pr4

com

pr5

com

pr6

com

pr7

cool

er1

cool

er2

cool

er3

cool

er4

cool

er5

cool

er6

LP C

O2

IP C

O2

HP

CO2

Appendix D3 – CHEMCAD model of the CO2compressor for the CCIGCC

Appendix

139

stre

am ID

0-4-

met

-13-

4-ga

s-3

5-4-

gas-

68-

4-st

-10

9-4-

cw-3

10-4

-mu-

34-

2-ga

s-2

4-3-

gas-

44-

5-ga

s-7

4-5-

gas-

84-

5-m

et-2

4-6-

CO

2-1

4-6-

CO

2-2

4-8-

cond

-24-

9-cw

-44-

10-w

w-3

nam

efre

sh M

eOH

feed

gas

tail g

asLP

ste

amC

W in

dem

in w

ater

fuel

gas

clea

n ga

sTG

T fu

elC

LAUS

gas

MeO

H bl

eed

LP C

O2

IP C

O2

LP c

ond

CW

out

was

te w

ater

t°C

15.0

30.0

30.0

275.

820

.015

.010

.010

.010

.016

.711

0.1

-15.

010

.015

0.8

30.0

42.9

pba

r36

.88

35.8

835

.89

6.10

6.00

50.0

033

.38

33.3

89.

101.

204.

801.

052.

304.

804.

004.

55m

kg/s

0.21

210

1.82

12.

643

9.47

687

71.

658

0.12

316

.246

0.34

32.

209

0.16

730

.718

54.7

039.

476

877

1.82

6n

kmol

/s0.

007

5.20

50.

089

0.52

648

.667

0.09

20.

024

3.23

50.

028

0.05

70.

005

0.69

81.

245

0.52

648

.667

0.10

0V

Nm³/h

535

419,

963

7,19

41,

974

260,

995

2,27

34,

637

421

56,3

4210

0,42

3LH

VkJ

/kg

19,8

997,

426

2,39

545

,147

45,1

4716

,262

7,83

916

,376

HHV

kJ/k

g22

,671

8,71

22,

728

53,0

3753

,037

18,8

838,

500

18,7

56h

kJ/k

g-7

,581

-7,7

08-5

,036

-12,

971

-15,

898

-15,

919

-1,3

32-1

,332

-5,0

16-4

,628

-6,6

89-8

,974

-8,9

52-1

5,31

6-1

5,85

6-1

5,51

7s

J/kg

K-8

,002

.5-9

47-4

84.9

-2,1

36.2

-9,1

13.2

-9,1

84.4

-4,6

63.9

-4,6

63.9

-339

.980

4.4

-3,2

40.6

-64.

1-1

34.2

-7,4

98.3

-8,9

74.4

-8,7

52.0

Mkg

/km

ol32

.00

19.5

929

.66

18.0

018

.00

18.0

05.

015.

0112

.17

38.4

431

.91

44.0

844

.04

18.0

018

.00

18.2

8

Σm

ol %

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

H2m

ol %

0.00

55.9

218

.06

0.00

0.00

0.00

89.1

589

.15

70.4

40.

000.

010.

030.

100.

000.

000.

00C

Om

ol %

0.00

2.42

2.35

0.00

0.00

0.00

3.85

3.85

7.20

0.00

0.00

0.01

0.04

0.00

0.00

0.00

CO

2m

ol %

0.00

37.4

836

.88

0.00

0.00

0.00

0.50

0.50

13.2

840

.40

8.84

99.9

399

.80

0.00

0.00

0.06

N2m

ol %

0.00

2.87

36.9

20.

000.

000.

005.

545.

545.

510.

000.

000.

000.

010.

000.

000.

00Ar

mol

%0.

000.

561.

650.

000.

000.

000.

920.

922.

210.

000.

000.

000.

020.

000.

000.

00C

H4m

ol %

0.00

0.02

0.02

0.00

0.00

0.00

0.03

0.03

0.05

0.00

0.00

0.00

0.00

0.00

0.00

0.00

O2

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00H2

Om

ol %

0.00

0.14

0.16

100.

0010

0.00

100.

000.

000.

000.

001.

558.

650.

000.

0010

0.00

100.

0098

.05

H2S

mol

%0.

000.

563.

940.

000.

000.

000.

000.

001.

2655

.68

2.51

0.00

0.00

0.00

0.00

0.00

CO

Sm

ol %

0.00

0.03

0.01

0.00

0.00

0.00

0.00

0.00

0.04

2.34

0.01

0.00

0.00

0.00

0.00

0.00

CS2

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00SO

2m

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HCN

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00NH

3m

ol %

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.02

0.01

0.00

0.00

0.00

0.00

0.00

CH3

OH

mol

%10

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.00

79.9

80.

020.

020.

000.

001.

89

Σm

ass

%10

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

00H2

mas

s %

0.00

5.76

1.23

0.00

0.00

0.00

35.7

835

.78

11.6

70.

000.

000.

000.

000.

000.

000.

00C

Om

ass

%0.

003.

472.

220.

000.

000.

0021

.50

21.5

016

.57

0.00

0.00

0.01

0.02

0.00

0.00

0.00

CO

2m

ass

%0.

0084

.32

54.7

60.

000.

000.

004.

384.

3848

.01

46.2

512

.18

99.9

799

.93

0.00

0.00

0.15

N2m

ass

%0.

004.

1134

.90

0.00

0.00

0.00

30.9

130

.91

12.6

90.

000.

000.

000.

010.

000.

000.

00Ar

mas

s %

0.00

1.15

2.22

0.00

0.00

0.00

7.31

7.31

7.24

0.00

0.00

0.00

0.01

0.00

0.00

0.00

CH4

mas

s %

0.00

0.02

0.01

0.00

0.00

0.00

0.09

0.09

0.07

0.00

0.00

0.00

0.00

0.00

0.00

0.00

O2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mas

s %

0.00

0.12

0.10

100.

0010

0.00

100.

000.

000.

000.

000.

734.

880.

000.

0010

0.00

100.

0096

.54

H2S

mas

s %

0.00

0.97

4.53

0.00

0.00

0.00

0.00

0.00

3.53

49.3

52.

670.

000.

000.

000.

000.

00C

OS

mas

s %

0.00

0.08

0.03

0.00

0.00

0.00

0.00

0.00

0.19

3.66

0.02

0.00

0.00

0.00

0.00

0.00

CS2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00HC

Nm

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00NH

3m

ass

%0.

000.

000.

010.

000.

000.

000.

000.

000.

000.

010.

000.

000.

000.

000.

000.

00C

H3O

Hm

ass

%10

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.03

0.02

0.00

80.2

40.

010.

020.

000.

003.

31

Appendix D4 – Heat and material balance for the AGR unit (CCIGCC / SCGP)

Appendix

140

stre

am ID

0-4-

met

-13-

4-ga

s-3

5-4-

gas-

68-

4-st

-10

9-4-

cw-3

10-4

-mu-

34-

2-ga

s-2

4-3-

gas-

44-

5-ga

s-7

4-5-

gas-

84-

5-m

et-2

4-6-

CO

2-1

4-6-

CO

2-2

4-8-

cond

-24-

9-cw

-44-

10-w

w-3

nam

efre

sh M

eOH

feed

gas

tail g

asLP

ste

amC

W in

dem

in w

ater

fuel

gas

clea

n ga

sTG

T fu

elC

LAU

S ga

sM

eOH

blee

dLP

CO

2IP

CO

2LP

con

dC

W o

utw

aste

wat

ert

°C15

.030

.030

.027

7.0

20.0

15.0

10.0

10.0

10.0

16.3

110.

1-1

5.0

10.0

150.

830

.042

.9p

bar

36.5

535

.55

35.8

96.

106.

0050

.00

33.0

533

.05

9.10

1.20

4.80

1.05

2.30

4.80

4.00

4.55

mkg

/s0.

212

100.

788

2.51

98.

903

845

1.66

20.

114

15.0

620.

327

2.15

10.

165

30.8

1454

.716

8.90

384

51.

831

nkm

ol/s

0.00

75.

171

0.08

60.

494

46.8

960.

092

0.02

43.

197

0.02

80.

057

0.00

50.

700

1.24

50.

494

46.8

960.

100

VNm

³/h53

541

7,27

66,

921

1,95

425

7,96

32,

228

4,57

041

756

,518

100,

446

LHV

kJ/k

g19

,899

7,51

02,

230

48,7

4148

,741

16,9

107,

799

16,3

07HH

VkJ

/kg

22,6

718,

813

2,55

657

,267

57,2

6719

,645

8,48

418

,680

hkJ

/kg

-7,5

81-7

,798

-5,0

79-1

2,96

9-1

5,89

8-1

5,91

9-1

,415

-1,4

15-5

,149

-4,7

03-6

,700

-8,9

74-8

,952

-15,

316

-15,

856

-15,

517

sJ/

kgK

-8,0

02.4

-957

-515

.3-2

,131

.6-9

,113

.2-9

,184

.4-5

,020

.2-5

,020

.2-3

77.6

758.

6-3

,224

.6-6

4.1

-134

.3-7

,498

.3-8

,974

.4-8

,751

.9M

kg/k

mol

32.0

019

.51

29.3

918

.00

18.0

018

.00

4.70

4.70

11.8

637

.97

31.8

944

.08

44.0

418

.00

18.0

018

.28

Σm

ol %

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

H2m

ol %

0.00

56.3

818

.80

0.00

0.00

0.00

90.3

590

.35

71.6

20.

000.

010.

030.

110.

000.

000.

00C

Om

ol %

0.00

2.39

2.38

0.00

0.00

0.00

3.83

3.83

7.17

0.00

0.00

0.01

0.04

0.00

0.00

0.00

CO

2m

ol %

0.00

37.7

936

.93

0.00

0.00

0.00

0.50

0.50

13.3

041

.30

8.97

99.9

399

.80

0.00

0.00

0.06

N2m

ol %

0.00

2.12

37.4

60.

000.

000.

004.

354.

354.

340.

000.

000.

000.

010.

000.

000.

00Ar

mol

%0.

000.

571.

700.

000.

000.

000.

930.

932.

230.

000.

000.

000.

020.

000.

000.

00C

H4

mol

%0.

000.

020.

020.

000.

000.

000.

030.

030.

060.

000.

000.

000.

000.

000.

000.

00O

2m

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mol

%0.

000.

140.

1610

0.00

100.

0010

0.00

0.00

0.00

0.00

1.52

8.90

0.00

0.00

100.

0010

0.00

98.0

5H2

Sm

ol %

0.00

0.59

2.53

0.00

0.00

0.00

0.00

0.00

1.26

56.9

92.

590.

000.

000.

000.

000.

00C

OS

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

170.

000.

000.

000.

000.

000.

00C

S2

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00SO

2m

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HCN

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00NH

3m

ol %

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.01

0.00

0.00

0.00

0.00

0.00

CH

3OH

mol

%10

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.00

79.5

20.

020.

020.

000.

001.

89

Σm

ass

%10

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

00H2

mas

s %

0.00

5.83

1.29

0.00

0.00

0.00

38.6

638

.66

12.1

70.

000.

000.

000.

000.

000.

000.

00C

Om

ass

%0.

003.

442.

270.

000.

000.

0022

.77

22.7

716

.93

0.00

0.00

0.01

0.02

0.00

0.00

0.00

CO

2m

ass

%0.

0085

.34

55.3

30.

000.

000.

004.

674.

6749

.37

47.8

612

.37

99.9

799

.93

0.00

0.00

0.15

N2m

ass

%0.

003.

0435

.73

0.00

0.00

0.00

25.8

825

.88

10.2

60.

000.

000.

000.

010.

000.

000.

00Ar

mas

s %

0.00

1.16

2.32

0.00

0.00

0.00

7.88

7.88

7.52

0.00

0.00

0.00

0.01

0.00

0.00

0.00

CH

4m

ass

%0.

000.

020.

010.

000.

000.

000.

120.

120.

080.

000.

000.

000.

000.

000.

000.

00O

2m

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00H2

Om

ass

%0.

000.

130.

1010

0.00

100.

0010

0.00

0.00

0.00

0.00

0.72

5.02

0.00

0.00

100.

0010

0.00

96.5

4H2

Sm

ass

%0.

001.

032.

940.

000.

000.

000.

000.

003.

6351

.13

2.76

0.00

0.00

0.00

0.00

0.00

CO

Sm

ass

%0.

000.

010.

000.

000.

000.

000.

000.

000.

010.

280.

000.

000.

000.

000.

000.

00C

S2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00HC

Nm

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00NH

3m

ass

%0.

000.

000.

010.

000.

000.

000.

000.

000.

000.

010.

000.

000.

000.

000.

000.

00C

H3O

Hm

ass

%10

0.00

0.00

0.00

0.00

0.00

0.00

0.03

0.03

0.02

0.00

79.8

30.

010.

020.

000.

003.

31

Appendix D5 – Heat and material balance for the AGR unit (CCIGCC /

Siemens gasifier)

Appendix

141

stre

am ID

0-4-

met

-13-

4-ga

s-3

5-4-

gas-

68-

4-st

-10

9-4-

cw-3

10-4

-mu-

34-

2-ga

s-2

4-3-

gas-

44-

5-ga

s-7

4-5-

gas-

84-

5-m

et-2

4-6-

CO

2-1

4-6-

CO

2-2

4-8-

cond

-24-

9-cw

-44-

10-w

w-3

nam

efre

sh M

eOH

feed

gas

tail g

asLP

ste

amC

W in

dem

in w

ater

fuel

gas

clea

n ga

sTG

T fu

elC

LAUS

gas

MeO

H bl

eed

LP C

O2

IP C

O2

LP c

ond

CW

out

was

te w

ater

t°C

15.0

30.0

30.0

274.

820

.010

.010

.010

.010

.012

.910

9.5

-15.

010

.015

0.8

30.0

42.9

pba

r36

.88

35.8

835

.94

6.10

6.00

5.00

33.3

833

.38

9.30

1.20

4.80

1.05

2.30

4.80

4.00

4.55

mkg

/s0.

220

96.1

832.

766

8.59

379

61.

522

0.00

013

.936

0.39

12.

261

0.17

028

.337

53.9

088.

593

796

1.68

0n

kmol

/s0.

007

4.76

60.

094

0.47

744

.202

0.08

50.

000

2.89

30.

030

0.05

90.

005

0.64

41.

228

0.47

744

.202

0.09

2V

Nm³/h

553

384,

603

7,55

90

233,

398

2,43

44,

744

427

51,9

9399

,107

LHV

kJ/k

g19

,899

7,96

53,

340

53,4

9753

,497

22,2

377,

708

16,6

46HH

VkJ

/kg

22,6

719,

284

3,77

462

,444

62,4

4425

,384

8,36

319

,042

hkJ

/kg

-7,5

81-7

,913

-5,1

07-1

2,97

4-1

5,89

8-1

5,94

0-1

,902

-1,9

02-5

,362

-4,7

13-6

,623

-8,9

74-8

,949

-15,

316

-15,

856

-15,

516

sJ/

kgK

-8,0

02.5

-1,0

39-6

13.0

-2,1

40.1

-9,1

13.2

-9,2

57.3

-5,6

48.7

-5,6

48.7

-1,2

68.9

772.

1-3

,289

.4-6

4.6

-137

.6-7

,498

.3-8

,974

.4-8

,751

.4M

kg/k

mol

32.0

020

.20

29.5

518

.00

18.0

018

.00

4.80

4.80

12.9

538

.44

32.0

944

.06

43.9

818

.00

18.0

018

.28

Σm

ol %

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

100.

0000

H2m

ol %

0.00

53.4

416

.03

0.00

0.00

0.00

87.9

187

.91

60.4

40.

000.

000.

020.

070.

000.

000.

00C

Om

ol %

0.00

1.83

1.82

0.00

0.00

0.00

3.01

3.01

5.14

0.00

0.00

0.01

0.02

0.00

0.00

0.00

CO

2m

ol %

0.00

39.3

536

.56

0.00

0.00

0.00

0.50

0.50

13.1

441

.66

8.57

99.8

799

.57

0.00

0.00

0.06

N2m

ol %

0.00

1.11

35.6

90.

000.

000.

002.

962.

962.

580.

000.

000.

000.

000.

000.

000.

00Ar

mol

%0.

000.

621.

720.

000.

000.

001.

051.

052.

370.

000.

000.

000.

010.

000.

000.

00C

H4m

ol %

0.00

2.86

4.66

0.00

0.00

0.00

4.56

4.56

15.1

00.

000.

000.

070.

300.

000.

000.

00O

2m

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mol

%0.

000.

140.

1610

0.00

100.

0010

0.00

0.00

0.00

0.00

1.22

7.13

0.00

0.00

100.

0010

0.00

98.0

4H2

Sm

ol %

0.00

0.63

3.31

0.00

0.00

0.00

0.00

0.00

1.20

55.4

42.

400.

000.

000.

000.

000.

00C

OS

mol

%0.

000.

020.

010.

000.

000.

000.

000.

000.

031.

670.

010.

000.

000.

000.

000.

00C

S2m

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00S

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00HC

Nm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mol

%0.

000.

000.

010.

000.

000.

000.

000.

000.

000.

020.

010.

000.

000.

000.

000.

00C

H3O

Hm

ol %

100.

000.

000.

000.

000.

000.

000.

000.

000.

010.

0081

.88

0.02

0.02

0.00

0.00

1.89

Σm

ass

%10

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

0010

0.00

00H2

mas

s %

0.00

5.34

1.09

0.00

0.00

0.00

36.7

836

.78

9.40

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

mas

s %

0.00

2.54

1.73

0.00

0.00

0.00

17.5

217

.52

11.1

20.

000.

000.

000.

010.

000.

000.

00C

O2

mas

s %

0.00

85.8

354

.49

0.00

0.00

0.00

4.56

4.56

44.6

247

.69

11.7

499

.95

99.8

40.

000.

000.

15N2

mas

s %

0.00

1.54

33.8

60.

000.

000.

0017

.20

17.2

05.

580.

000.

000.

000.

000.

000.

000.

00Ar

mas

s %

0.00

1.23

2.33

0.00

0.00

0.00

8.72

8.72

7.31

0.00

0.00

0.00

0.01

0.00

0.00

0.00

CH4

mas

s %

0.00

2.27

2.53

0.00

0.00

0.00

15.2

015

.20

18.6

90.

000.

000.

030.

110.

000.

000.

00O

2m

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00H2

Om

ass

%0.

000.

120.

1010

0.00

100.

0010

0.00

0.00

0.00

0.00

0.57

4.00

0.00

0.00

100.

0010

0.00

96.5

3H2

Sm

ass

%0.

001.

063.

820.

000.

000.

000.

000.

003.

1449

.13

2.55

0.00

0.00

0.00

0.00

0.00

CO

Sm

ass

%0.

000.

060.

020.

000.

000.

000.

000.

000.

132.

600.

010.

000.

000.

000.

000.

00C

S2m

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00SO

2m

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00S

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HCN

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mas

s %

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mas

s %

100.

000.

000.

000.

000.

000.

000.

030.

030.

020.

0081

.69

0.01

0.02

0.00

0.00

3.32

Appendix D6 – Heat and material balance for the AGR unit (CCIGCC / CoP

gasifier)

Appendix

142

stre

am ID

0-4-

met

-13-

4-ga

s-3

5-4-

gas-

68-

4-st

-10

9-4-

cw-3

10-4

-mu-

34-

2-ga

s-2

4-3-

gas-

44-

5-ga

s-7

4-5-

gas-

84-

5-m

et-2

4-6-

CO

2-1

4-6-

CO

2-2

4-8-

cond

-24-

9-cw

-44-

10-w

w-3

nam

efre

sh M

eOH

feed

gas

tail g

asLP

ste

amC

W in

dem

in w

ater

fuel

gas

clea

n ga

sTG

T fu

elC

LAU

S ga

sM

eOH

blee

dLP

CO

2IP

CO

2LP

con

dC

W o

utw

aste

wat

ert

°C15

.030

.030

.027

8.7

20.0

15.0

10.0

10.0

10.0

17.5

115.

2-1

5.0

10.0

150.

830

.043

.9p

bar

57.4

256

.42

56.8

06.

106.

0050

.00

53.9

253

.92

14.6

01.

204.

801.

803.

304.

804.

004.

55m

kg/s

0.26

410

7.01

43.

716

8.81

075

42.

260

0.00

013

.716

0.58

23.

138

0.17

030

.290

62.9

498.

810

754

2.40

0n

kmol

/s0.

008

5.25

50.

117

0.48

941

.856

0.12

50.

000

3.13

10.

037

0.08

00.

006

0.68

81.

432

0.48

941

.856

0.13

1V

Nm³/h

664

424,

002

9,40

40.

000

252,

669

2,95

36,

453

454

55,5

5311

5,50

7LH

VkJ

/kg

19,8

997,

059

1,83

453

,716

53,7

1611

,596

5,82

416

,583

HHV

kJ/k

g22

,671

8,27

62,

100

63,0

7163

,071

13,4

466,

341

19,1

17h

kJ/k

g-7

,579

-8,0

00-6

,145

-12,

965

-15,

898

-15,

919

-1,6

06-1

,606

-6,5

32-5

,787

-6,8

93-8

,975

-8,9

54-1

5,31

6-1

5,85

6-1

5,50

8s

J/kg

K-8

,006

.1-1

,144

-657

.2-2

,125

.3-9

,113

.2-9

,184

.4-6

,419

.4-6

,419

.4-5

65.5

604.

6-3

,415

.7-1

68.7

-206

.7-7

,498

.3-8

,974

.4-8

,740

.6M

kg/k

mol

32.0

020

.39

31.9

218

.00

18.0

018

.00

4.37

4.37

15.9

039

.25

30.2

244

.08

44.0

618

.00

18.0

018

.28

Σm

ol %

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

H2m

ol %

0.00

54.7

316

.22

0.00

0.00

0.00

91.6

891

.68

62.8

20.

000.

000.

020.

050.

000.

000.

00C

Om

ol %

0.00

2.39

1.98

0.00

0.00

0.00

4.00

4.00

6.00

0.00

0.00

0.01

0.02

0.00

0.00

0.00

CO

2m

ol %

0.00

40.5

148

.78

0.00

0.00

0.00

0.50

0.50

24.2

954

.25

4.24

99.9

399

.85

0.00

0.00

0.05

N2m

ol %

0.00

0.71

28.7

60.

000.

000.

002.

242.

241.

700.

000.

000.

000.

000.

000.

000.

00Ar

mol

%0.

000.

761.

620.

000.

000.

001.

291.

292.

690.

000.

000.

010.

020.

000.

000.

00C

H4m

ol %

0.00

0.17

0.24

0.00

0.00

0.00

0.27

0.27

0.83

0.00

0.00

0.01

0.01

0.00

0.00

0.00

O2

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00H2

Om

ol %

0.00

0.10

0.14

100.

0010

0.00

100.

000.

000.

000.

001.

6416

.67

0.00

0.00

100.

0010

0.00

98.0

1H2

Sm

ol %

0.00

0.63

2.23

0.00

0.00

0.00

0.00

0.00

1.64

43.9

52.

150.

000.

000.

000.

000.

00C

OS

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

140.

000.

000.

000.

000.

000.

00C

S2m

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00S

mol

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00HC

Nm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mol

%0.

000.

000.

010.

000.

000.

000.

000.

000.

000.

010.

000.

000.

000.

000.

000.

00C

H3O

Hm

ol %

100.

000.

000.

010.

000.

000.

000.

010.

010.

040.

0076

.93

0.03

0.04

0.00

0.00

1.94

Σm

ass

%10

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

0010

0.00

100.

00H2

mas

s %

0.00

5.42

1.03

0.00

0.00

0.00

42.1

942

.19

7.97

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

mas

s %

0.00

3.28

1.74

0.00

0.00

0.00

25.5

825

.58

10.5

80.

000.

000.

010.

010.

000.

000.

00C

O2

mas

s %

0.00

87.5

567

.33

0.00

0.00

0.00

5.02

5.02

67.2

660

.85

6.16

99.9

699

.93

0.00

0.00

0.11

N2m

ass

%0.

000.

9825

.27

0.00

0.00

0.00

14.3

314

.33

2.99

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Arm

ass

%0.

001.

492.

030.

000.

000.

0011

.81

11.8

16.

760.

000.

000.

010.

010.

000.

000.

00C

H4m

ass

%0.

000.

130.

120.

000.

000.

001.

011.

010.

830.

000.

000.

000.

010.

000.

000.

00O

2m

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00H2

Om

ass

%0.

000.

090.

0810

0.00

100.

0010

0.00

0.00

0.00

0.00

0.75

9.93

0.00

0.00

100.

0010

0.00

96.4

8H2

Sm

ass

%0.

001.

062.

390.

000.

000.

000.

000.

003.

5238

.17

2.42

0.00

0.00

0.00

0.00

0.00

CO

Sm

ass

%0.

000.

010.

000.

000.

000.

000.

000.

000.

010.

220.

000.

000.

000.

000.

000.

00C

S2m

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00SO

2m

ass

%0.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

000.

00S

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HCN

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mas

s %

100.

000.

000.

010.

000.

000.

000.

060.

060.

090.

0081

.48

0.02

0.03

0.00

0.00

3.40

Appendix D7 – Heat and material balance for the AGR unit (CCIGCC / GER)

Appendix

143

stre

am ID

0-5-

air-2

1-5-

GO

X-2

4-5-

gas-

74-

5-ga

s-8

4-5-

met

-28-

5-st

-12

8-5-

BFW

-49-

5-cw

-75-

0-S-

15-

4-ga

s-6

5-8-

st-1

15-

8-co

nd-3

5-9-

cw-8

5-10

-ww

-4na

me

air

GO

XTG

T fu

elC

LAUS

gas

MeO

H bl

eed

IP s

team

LP B

FWC

W in

sulfu

rta

il gas

LP s

team

IP c

onde

nsat

eC

W o

utw

aste

wat

ert

°C15.0

60.0

10.0

16.7

110.1

264.7

154.2

20.0

134.8

30.0

164.0

246.0

30.1

37.2

pba

r1.01

50.00

9.10

1.20

4.80

50.60

14.00

6.00

5.00

35.89

6.60

38.00

4.00

1.10

mkg

/s1.159

0.505

0.343

2.209

0.167

0.087

5.698

95.742

0.972

2.643

5.698

0.087

95.742

0.769

nkm

ol/s

0.040

0.016

0.028

0.057

0.005

0.005

0.316

5.315

0.030

0.089

0.316

0.005

5.315

0.043

VNm

³/h3,242

1,268

2,273

4,637

421

7,194

LHV

kJ/k

g16,263

7,839

16,376

8,916

2,395

HHV

kJ/k

g18,884

8,500

18,755

8,916

2,728

hkJ

/kg

‐99

26‐5,017

‐4,628

‐6,689

‐13,190

‐15,330

‐15,898

‐3,000

‐5,036

‐13,219

‐14,909

‐15,855

‐15,820

sJ/

kgK

125

‐867

‐340

804

‐3,241

‐3,446

‐7,528

‐9,113

‐4,212

‐485

‐2,678

‐6,655

‐8,973

‐8,871

Mkg

/km

ol28

.84

32.1

712

.17

38.4

431

.91

18.0

018

.00

18.0

032

.00

29.6

618

.00

18.0

018

.00

18.0

1

Σm

ol %

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ol %

0.00

0.00

70.44

0.00

0.01

0.00

0.00

0.00

0.00

18.06

0.00

0.00

0.00

0.00

CO

mol

%0.00

0.00

7.20

0.00

0.00

0.00

0.00

0.00

0.00

2.35

0.00

0.00

0.00

0.00

CO

2m

ol %

0.03

0.00

13.28

40.40

8.84

0.00

0.00

0.00

0.00

36.88

0.00

0.00

0.00

0.03

N2m

ol %

77.32

1.94

5.51

0.00

0.00

0.00

0.00

0.00

0.00

36.92

0.00

0.00

0.00

0.00

Arm

ol %

0.91

3.06

2.21

0.00

0.00

0.00

0.00

0.00

0.00

1.65

0.00

0.00

0.00

0.00

CH4

mol

%0.00

0.00

0.05

0.00

0.00

0.00

0.00

0.00

0.00

0.02

0.00

0.00

0.00

0.00

O2

mol

%20.74

95.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mol

%1.01

0.00

0.00

1.55

8.65

100.00

100.00

100.00

0.00

0.16

100.00

100.00

100.00

99.97

H2S

mol

%0.00

0.00

1.26

55.68

2.51

0.00

0.00

0.00

0.00

3.94

0.00

0.00

0.00

0.01

CO

Sm

ol %

0.00

0.00

0.04

2.34

0.01

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

CS2

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

100.00

0.00

0.00

0.00

0.00

0.00

HCN

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mol

%0.00

0.00

0.00

0.02

0.01

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

CH3

OH

mol

%0.00

0.00

0.01

0.00

79.98

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Σm

ass

%100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ass

%0.00

0.00

11.67

0.00

0.00

0.00

0.00

0.00

0.00

1.23

0.00

0.00

0.00

0.00

CO

mas

s %

0.00

0.00

16.58

0.00

0.00

0.00

0.00

0.00

0.00

2.22

0.00

0.00

0.00

0.00

CO

2m

ass

%0.05

0.00

48.01

46.25

12.18

0.00

0.00

0.00

0.00

54.76

0.00

0.00

0.00

0.06

N2m

ass

%75.07

1.69

12.69

0.00

0.00

0.00

0.00

0.00

0.00

34.90

0.00

0.00

0.00

0.00

Arm

ass

%1.26

3.80

7.24

0.00

0.00

0.00

0.00

0.00

0.00

2.22

0.00

0.00

0.00

0.00

CH4

mas

s %

0.00

0.00

0.07

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

O2

mas

s %

23.00

94.51

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mas

s %

0.63

0.00

0.00

0.73

4.88

100.00

100.00

100.00

0.00

0.10

100.00

100.00

100.00

99.92

H2S

mas

s %

0.00

0.00

3.53

49.35

2.67

0.00

0.00

0.00

0.00

4.53

0.00

0.00

0.00

0.01

CO

Sm

ass

%0.00

0.00

0.19

3.66

0.02

0.00

0.00

0.00

0.00

0.03

0.00

0.00

0.00

0.00

CS2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ass

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

100.00

0.00

0.00

0.00

0.00

0.00

HCN

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mas

s %

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

CH3

OH

mas

s %

0.00

0.00

0.02

0.00

80.24

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Appendix D8 – Heat and material balance for the TGT process (CCIGCC /

SCGP)

Appendix

144

stre

am ID

0-5-

air-2

1-5-

GO

X-2

4-5-

gas-

74-

5-ga

s-8

4-5-

met

-28-

5-st

-12

8-5-

BFW

-49-

5-cw

-75-

0-S-

15-

4-ga

s-6

5-8-

st-1

15-

8-co

nd-3

5-9-

cw-8

5-10

-ww

-4na

me

air

GO

XTG

T fu

elC

LAUS

gas

MeO

H bl

eed

IP s

team

LP B

FWC

W in

sulfu

rta

il gas

LP s

team

IP c

onde

nsat

eC

W o

utw

aste

wat

ert

°C15.0

60.0

10.0

16.3

110.1

264.7

154.2

20.0

134.8

30.0

164.0

246.0

29.8

37.1

pba

r1.01

50.00

9.10

1.20

4.80

50.60

14.00

6.00

5.00

35.89

6.60

38.00

4.00

1.10

mkg

/s1.143

0.511

0.327

2.151

0.165

0.085

5.853

99.105

0.984

2.519

5.853

0.085

99.105

0.795

nkm

ol/s

0.040

0.016

0.028

0.057

0.005

0.005

0.325

5.501

0.031

0.086

0.325

0.005

5.501

0.044

VNm

³/h3,196

1,282

2,228

4,570

417

6,921

LHV

kJ/k

g0

016,910

7,799

16,307

8,916

2,230

HHV

kJ/k

g0

019,645

8,484

18,680

8,916

2,556

hkJ

/kg

‐99

26‐5,149

‐4,703

‐6,700

‐13,190

‐15,330

‐15,898

‐3,000

‐5,079

‐13,219

‐14,909

‐15,857

‐15,821

sJ/

kgK

125

‐867

‐378

759

‐3,225

‐3,446

‐7,528

‐9,113

‐4,212

‐515

‐2,678

‐6,655

‐8,977

‐8,873

Mkg

/km

ol28

.84

32.1

711

.86

37.9

731

.89

18.0

018

.00

18.0

032

.00

29.3

918

.00

18.0

018

.00

18.0

1

Σm

ol %

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ol %

0.00

0.00

71.62

0.00

0.01

0.00

0.00

0.00

0.00

18.80

0.00

0.00

0.00

0.00

CO

mol

%0.00

0.00

7.17

0.00

0.00

0.00

0.00

0.00

0.00

2.38

0.00

0.00

0.00

0.00

CO

2m

ol %

0.03

0.00

13.30

41.30

8.97

0.00

0.00

0.00

0.00

36.93

0.00

0.00

0.00

0.03

N2m

ol %

77.32

1.90

4.34

0.00

0.00

0.00

0.00

0.00

0.00

37.46

0.00

0.00

0.00

0.00

Arm

ol %

0.91

3.10

2.23

0.00

0.00

0.00

0.00

0.00

0.00

1.70

0.00

0.00

0.00

0.00

CH4

mol

%0.00

0.00

0.06

0.00

0.00

0.00

0.00

0.00

0.00

0.02

0.00

0.00

0.00

0.00

O2

mol

%20.74

95.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mol

%1.01

0.00

0.00

1.52

8.90

100.00

100.00

100.00

0.00

0.16

100.00

100.00

100.00

99.97

H2S

mol

%0.00

0.00

1.26

56.99

2.59

0.00

0.00

0.00

0.00

2.53

0.00

0.00

0.00

0.00

CO

Sm

ol %

0.00

0.00

0.00

0.17

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

100.00

0.00

0.00

0.00

0.00

0.00

HCN

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mol

%0.00

0.00

0.00

0.01

0.01

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

CH3

OH

mol

%0.00

0.00

0.01

0.00

79.52

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Σm

ass

%100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ass

%0.00

0.00

12.17

0.00

0.00

0.00

0.00

0.00

0.00

1.29

0.00

0.00

0.00

0.00

CO

mas

s %

0.00

0.00

16.93

0.00

0.00

0.00

0.00

0.00

0.00

2.27

0.00

0.00

0.00

0.00

CO

2m

ass

%0.05

0.00

49.37

47.86

12.37

0.00

0.00

0.00

0.00

55.33

0.00

0.00

0.00

0.06

N2m

ass

%75.07

1.66

10.26

0.00

0.00

0.00

0.00

0.00

0.00

35.73

0.00

0.00

0.00

0.00

Arm

ass

%1.26

3.84

7.52

0.00

0.00

0.00

0.00

0.00

0.00

2.32

0.00

0.00

0.00

0.00

CH4

mas

s %

0.00

0.00

0.08

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

O2

mas

s %

23.00

94.50

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mas

s %

0.63

0.00

0.00

0.72

5.02

100.00

100.00

100.00

0.00

0.10

100.00

100.00

100.00

99.93

H2S

mas

s %

0.00

0.00

3.63

51.13

2.76

0.00

0.00

0.00

0.00

2.94

0.00

0.00

0.00

0.01

CO

Sm

ass

%0.00

0.00

0.01

0.28

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ass

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

100.00

0.00

0.00

0.00

0.00

0.00

HCN

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mas

s %

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

CH3

OH

mas

s %

0.00

0.00

0.02

0.00

79.83

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00


Siemens gasifier)

Appendix

145

stre

am ID

0-5-

air-2

1-5-

GO

X-2

4-5-

gas-

74-

5-ga

s-8

4-5-

met

-28-

5-st

-12

8-5-

BFW

-49-

5-cw

-75-

0-S-

15-

4-ga

s-6

5-8-

st-1

15-

8-co

nd-3

5-9-

cw-8

5-10

-ww

-4na

me

air

GO

XTG

T fu

elC

LAUS

gas

MeO

H bl

eed

IP s

team

LP B

FWC

W in

sulfu

rta

il gas

LP s

team

IP c

onde

nsat

eC

W o

utw

aste

wat

ert

°C15.0

60.0

10.0

12.9

109.5

264.7

154.2

20.0

134.8

30.0

164.0

246.0

30.0

37.2

pba

r1.01

49.96

9.30

1.20

4.80

50.60

14.00

6.00

5.00

35.94

6.60

38.00

4.00

1.10

mkg

/s1.208

0.514

0.391

2.260

0.170

0.089

5.813

100.187

0.992

2.766

5.813

0.089

100.187

0.785

nkm

ol/s

0.042

0.016

0.030

0.059

0.005

0.005

0.323

5.561

0.031

0.094

0.323

0.005

5.561

0.044

VNm

³/h3,379

1,290

2,434

4,744

427

7,559

LHV

kJ/k

g22,236

7,708

16,646

8,916

3,340

HHV

kJ/k

g25,384

8,363

19,043

8,916

3,774

hkJ

/kg

‐99

26‐5,362

‐4,712

‐6,622

‐13,190

‐15,330

‐15,898

‐3,000

‐5,107

‐13,219

‐14,909

‐15,856

‐15,820

sJ/

kgK

125

‐866

‐1,269

772

‐3,289

‐3,446

‐7,528

‐9,113

‐4,212

‐613

‐2,678

‐6,655

‐8,975

‐8,871

Mkg

/km

ol28

.84

32.1

912

.95

38.4

432

.09

18.0

018

.00

18.0

032

.00

29.5

518

.00

18.0

018

.00

18.0

1

Σm

ol %

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ol %

0.00

0.00

60.44

0.00

0.00

0.00

0.00

0.00

0.00

16.03

0.00

0.00

0.00

0.00

CO

mol

%0.00

0.00

5.14

0.00

0.00

0.00

0.00

0.00

0.00

1.82

0.00

0.00

0.00

0.00

CO

2m

ol %

0.03

0.00

13.14

41.66

8.57

0.00

0.00

0.00

0.00

36.56

0.00

0.00

0.00

0.03

N2m

ol %

77.32

1.74

2.58

0.00

0.00

0.00

0.00

0.00

0.00

35.69

0.00

0.00

0.00

0.00

Arm

ol %

0.91

3.26

2.37

0.00

0.00

0.00

0.00

0.00

0.00

1.72

0.00

0.00

0.00

0.00

CH4

mol

%0.00

0.00

15.09

0.00

0.00

0.00

0.00

0.00

0.00

4.66

0.00

0.00

0.00

0.00

O2

mol

%20.74

95.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mol

%1.01

0.00

0.00

1.22

7.13

100.00

100.00

100.00

0.00

0.16

100.00

100.00

100.00

99.97

H2S

mol

%0.00

0.00

1.20

55.44

2.40

0.00

0.00

0.00

0.00

3.31

0.00

0.00

0.00

0.00

CO

Sm

ol %

0.00

0.00

0.03

1.67

0.01

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

CS2

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

100.00

0.00

0.00

0.00

0.00

0.00

HCN

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mol

%0.00

0.00

0.00

0.02

0.01

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

CH3

OH

mol

%0.00

0.00

0.01

0.00

81.88

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Σm

ass

%100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ass

%0.00

0.00

9.40

0.00

0.00

0.00

0.00

0.00

0.00

1.09

0.00

0.00

0.00

0.00

CO

mas

s %

0.00

0.00

11.12

0.00

0.00

0.00

0.00

0.00

0.00

1.73

0.00

0.00

0.00

0.00

CO

2m

ass

%0.05

0.00

44.62

47.69

11.74

0.00

0.00

0.00

0.00

54.49

0.00

0.00

0.00

0.06

N2m

ass

%75.07

1.51

5.58

0.00

0.00

0.00

0.00

0.00

0.00

33.86

0.00

0.00

0.00

0.00

Arm

ass

%1.26

4.05

7.31

0.00

0.00

0.00

0.00

0.00

0.00

2.33

0.00

0.00

0.00

0.00

CH4

mas

s %

0.00

0.00

18.68

0.00

0.00

0.00

0.00

0.00

0.00

2.53

0.00

0.00

0.00

0.00

O2

mas

s %

23.00

94.44

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mas

s %

0.63

0.00

0.00

0.57

4.00

100.00

100.00

100.00

0.00

0.10

100.00

100.00

100.00

99.92

H2S

mas

s %

0.00

0.00

3.14

49.13

2.55

0.00

0.00

0.00

0.00

3.82

0.00

0.00

0.00

0.01

CO

Sm

ass

%0.00

0.00

0.13

2.60

0.01

0.00

0.00

0.00

0.00

0.02

0.00

0.00

0.00

0.00

CS2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ass

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

100.00

0.00

0.00

0.00

0.00

0.00

HCN

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mas

s %

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

CH3

OH

mas

s %

0.00

0.00

0.02

0.00

81.69

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00


CoP gasifier)

Appendix

146

stre

am ID

0-5-

air-2

1-5-

GO

X-2

4-5-

gas-

74-

5-ga

s-8

4-5-

met

-28-

5-st

-12

8-5-

BFW

-49-

5-cw

-75-

0-S-

15-

4-ga

s-6

5-8-

st-1

15-

8-co

nd-3

5-9-

cw-8

5-10

-ww

-4na

me

air

GO

XTG

T fu

elC

LAUS

gas

MeO

H bl

eed

IP s

team

LP B

FWC

W in

sulfu

rta

il gas

LP s

team

IP c

onde

nsat

eC

W o

utw

aste

wat

ert

°C15.0

60.0

10.0

17.5

115.2

264.7

154.2

20.0

134.8

30.0

164.0

246.0

29.9

37.3

pba

r1.01

70.00

14.60

1.20

4.80

50.60

14.00

6.00

5.00

56.80

6.60

38.00

4.00

1.10

mkg

/s1.215

0.558

0.582

3.138

0.170

0.111

6.118

122.602

1.070

3.716

6.118

0.111

122.602

0.876

nkm

ol/s

0.042

0.017

0.037

0.080

0.006

0.006

0.340

6.806

0.033

0.117

0.340

0.006

6.806

0.049

VNm

³/h3,398

1,400

2,953

6,453

454

9,405

LHV

kJ/k

g11,596

5,824

16,583

8,916

1,834

HHV

kJ/k

g13,446

6,341

19,117

8,916

2,100

hkJ

/kg

‐99

23‐6,532

‐5,787

‐6,893

‐13,190

‐15,330

‐15,898

‐3,000

‐6,145

‐13,219

‐14,909

‐15,856

‐15,817

sJ/

kgK

125

‐961

‐565

605

‐3,416

‐3,446

‐7,528

‐9,113

‐4,212

‐657

‐2,678

‐6,655

‐8,976

‐8,868

Mkg

/km

ol28

.84

32.1

615

.90

39.2

530

.22

18.0

018

.00

18.0

032

.00

31.9

218

.00

18.0

018

.00

18.0

1

Σm

ol %

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ol %

0.00

0.00

62.82

0.00

0.00

0.00

0.00

0.00

0.00

16.22

0.00

0.00

0.00

0.00

CO

mol

%0.00

0.00

6.00

0.00

0.00

0.00

0.00

0.00

0.00

1.98

0.00

0.00

0.00

0.00

CO

2m

ol %

0.03

0.00

24.29

54.25

4.24

0.00

0.00

0.00

0.00

48.78

0.00

0.00

0.00

0.04

N2m

ol %

77.32

1.99

1.70

0.00

0.00

0.00

0.00

0.00

0.00

28.76

0.00

0.00

0.00

0.00

Arm

ol %

0.91

3.01

2.69

0.00

0.00

0.00

0.00

0.00

0.00

1.62

0.00

0.00

0.00

0.00

CH4

mol

%0.00

0.00

0.83

0.00

0.00

0.00

0.00

0.00

0.00

0.24

0.00

0.00

0.00

0.00

O2

mol

%20.74

95.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mol

%1.01

0.00

0.00

1.64

16.67

100.00

100.00

100.00

0.00

0.14

100.00

100.00

100.00

99.95

H2S

mol

%0.00

0.00

1.64

43.95

2.15

0.00

0.00

0.00

0.00

2.23

0.00

0.00

0.00

0.00

CO

Sm

ol %

0.00

0.00

0.00

0.14

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

100.00

0.00

0.00

0.00

0.00

0.00

HCN

mol

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mol

%0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

CH3

OH

mol

%0.00

0.00

0.04

0.00

76.93

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.01

Σm

ass

%100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ass

%0.00

0.00

7.97

0.00

0.00

0.00

0.00

0.00

0.00

1.03

0.00

0.00

0.00

0.00

CO

mas

s %

0.00

0.00

10.58

0.00

0.00

0.00

0.00

0.00

0.00

1.74

0.00

0.00

0.00

0.00

CO

2m

ass

%0.05

0.00

67.26

60.85

6.16

0.00

0.00

0.00

0.00

67.33

0.00

0.00

0.00

0.09

N2m

ass

%75.07

1.73

2.99

0.00

0.00

0.00

0.00

0.00

0.00

25.27

0.00

0.00

0.00

0.00

Arm

ass

%1.26

3.74

6.76

0.00

0.00

0.00

0.00

0.00

0.00

2.03

0.00

0.00

0.00

0.00

CH4

mas

s %

0.00

0.00

0.83

0.00

0.00

0.00

0.00

0.00

0.00

0.12

0.00

0.00

0.00

0.00

O2

mas

s %

23.00

94.53

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mas

s %

0.63

0.00

0.00

0.75

9.93

100.00

100.00

100.00

0.00

0.08

100.00

100.00

100.00

99.89

H2S

mas

s %

0.00

0.00

3.52

38.17

2.42

0.00

0.00

0.00

0.00

2.38

0.00

0.00

0.00

0.01

CO

Sm

ass

%0.00

0.00

0.01

0.22

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ass

%0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

100.00

0.00

0.00

0.00

0.00

0.00

HCN

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mas

s %

0.00

0.00

0.09

0.00

81.48

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.01


GER)

Appendix

147

Appendix D12 – Heat and material balance for the CO2compressor (CCIGCC

/ SCGP)

stream ID 4-6-CO2-1 4-6-CO2-2 9-6-cw-5 6-0-CO2-3 6-9-cw-6name LP CO2 IP CO2 CW in HP CO2 CW outt °C -15.0 10.0 20.0 30.0 30.0p bar 1.05 2.30 6.00 100.00 4.00m kg/s 30.718 54.701 1,014.013 85.419 1,014.013n kmol/s 0.698 1.245 56.287 1.943 56.287V Nm³/h 56,341 100,419 156,760LHV kJ/kgh kJ/kg -8,974 -8,952 -15,898 -9,165 -15,856s J/kgK -64 -134 -9,113 -1,425 -8,974M kg/kmol 44.08 44.04 18.00 44.06 18.00

Σ mol % 100.0000 100.0000 100.0000 100.0000 100.0000H2 mol % 0.03 0.10 0.00 0.08 0.00CO mol % 0.01 0.04 0.00 0.03 0.00CO2 mol % 99.93 99.80 0.00 99.85 0.00N2 mol % 0.00 0.01 0.00 0.01 0.00Ar mol % 0.00 0.02 0.00 0.01 0.00CH4 mol % 0.00 0.00 0.00 0.00 0.00O2 mol % 0.00 0.00 0.00 0.00 0.00H2O mol % 0.00 0.00 100.00 0.00 100.00H2S mol % 0.00 0.00 0.00 0.00 0.00COS mol % 0.00 0.00 0.00 0.00 0.00CS2 mol % 0.00 0.00 0.00 0.00 0.00SO2 mol % 0.00 0.00 0.00 0.00 0.00S mol % 0.00 0.00 0.00 0.00 0.00HCN mol % 0.00 0.00 0.00 0.00 0.00NH3 mol % 0.00 0.00 0.00 0.00 0.00CH3OH mol % 0.02 0.02 0.00 0.02 0.00

Σ mass % 100.0000 100.0000 100.0000 100.0000 100.0000H2 mass % 0.00 0.00 0.00 0.00 0.00CO mass % 0.01 0.02 0.00 0.02 0.00CO2 mass % 99.97 99.93 0.00 99.95 0.00N2 mass % 0.00 0.01 0.00 0.01 0.00Ar mass % 0.00 0.01 0.00 0.01 0.00CH4 mass % 0.00 0.00 0.00 0.00 0.00O2 mass % 0.00 0.00 0.00 0.00 0.00H2O mass % 0.00 0.00 100.00 0.00 100.00H2S mass % 0.00 0.00 0.00 0.00 0.00COS mass % 0.00 0.00 0.00 0.00 0.00CS2 mass % 0.00 0.00 0.00 0.00 0.00SO2 mass % 0.00 0.00 0.00 0.00 0.00S mass % 0.00 0.00 0.00 0.00 0.00HCN mass % 0.00 0.00 0.00 0.00 0.00NH3 mass % 0.00 0.00 0.00 0.00 0.00CH3OH mass % 0.01 0.02 0.00 0.02 0.00

Appendix

148


/ Siemens gasifier)

name LP CO2 IP CO2 CW in HP CO2 CW outt °C -15.0 10.0 20.0 30.0 30.0p bar 1.05 2.30 6.00 100.00 4.00m kg/s 30.813 54.713 1,015.484 85.527 1,015.484n kmol/s 0.700 1.245 56.369 1.945 56.369V Nm³/h 56,517 100,442 156,958LHV kJ/kgh kJ/kg -8,974 -8,952 -15,898 -9,166 -15,856s J/kgK -64 -134 -9,113 -1,425 -8,974M kg/kmol 44.08 44.04 18.00 44.06 18.00



Appendix

149


/ CoP gasifier)

stream ID 4-6-CO2-1 4-6-CO2-2 9-6-cw-5 6-0-CO2-3 6-9-cw-6name LP CO2 IP CO2 CW in HP CO2 CW outt °C -15.0 10.0 20.0 30.0 30.0p bar 1.05 2.30 6.00 100.00 4.00m kg/s 28.337 53.906 975.069 82.243 975.069n kmol/s 0.644 1.228 54.125 1.873 54.125V Nm³/h 51,993 99,104 151,098LHV kJ/kgh kJ/kg -8,974 -8,949 -15,898 -9,163 ‐15,856s J/kgK -65 -138 -9,113 -1,427 -8,974M kg/kmol 44.06 43.98 18.00 44.01 18.00



Appendix

150


/ GER)

stream ID 4-6-CO2-1 4-6-CO2-2 9-6-cw-5 6-0-CO2-3 6-9-cw-6name LP CO2 IP CO2 CW in HP CO2 CW outt °C -15.0 10.0 20.0 30.0 30.0p bar 1.80 3.30 6.00 100.00 4.00m kg/s 30.290 62.949 1,019.194 93.239 1,019.194n kmol/s 0.688 1.432 56.575 2.120 56.575V Nm³/h 55,553 115,507 171,059LHV kJ/kgh kJ/kg -8,975 -8,954 -15,898 -9,166 -15,856s J/kgK -169 -207 -9,113 -1,427 -8,974M kg/kmol 44.08 44.06 18.00 44.07 18.00



Appendix

151

Appendix E1 – Parameters for reference point calculation with the generic

GT model

Fixed parameters Unit Value

Δpinlet = Δpoutlet mbar 10

Δpcomb % 3

ηcomb % 100

ηmech % 99.6

ηG % 98.5

Target parameters Unit Value

Gross power output MW 292

Gross efficiency (Fuel mass flow

% kg CH4/s

39.8 14.669)

Compressor pressure ratio ‐ 18.2

Exhaust gas temperature °C 577

Hot gas temperature (T7) °C 1450

Turbine inlet temperature (T9) °C 1245

Blade temperature (Tblade) °C 900

Adjusted parameters Unit Value

ηp,compr % 94

Cool frac % 22.4

ηp,uc turb % 93.2

ηp,c turb % 91.16

Compressor mass flow kg/s 684

Appendix

152

Appendix E2 – Reference parameters for offdesign calculations

Parameter Unit Value

m_1_ref kg/s 684

m_8_ref kg/s 153.011

m_9_ref kg/s 698.669

t_7_ref °C 1450

t_9_ref °C 1245

t_blade_ref °C 900

p_9_ref bar 17.71

Δp_comb_ref bar 0.55

Π_compr,ref ‐ 18.2

Π_turb,ref ‐ 17.3

Appendix

153

Appendix E3 – CHEMCAD model of the GT process for the CCIGCC

Appendix E4 – Heat and material balance for the gas turbine(CCIGCC /SCGP)

1

2

3

1

2

6

3

7

5

7

8

910

11

4

5

8

Dp inlet

comb chamber

turbine

compressor

Dp outlet

fuel

air

extr air

exhaust

4

12

12

13

14 10

11

15

ID 1 T 15.0 C P 1.0 bar W 644.950 kg/s

ID 2 T 15.0 C P 1.0 bar W 644.950 kg/s

ID 3 T 402.0 C P 17.4 bar W 644.950 kg/s

ID 5 T 402.0 C P 17.4 bar W 405.899 kg/s

ID 8 T 1450.0 C P 16.9 bar W 504.509 kg/s

ID 9 T 402.0 C P 17.4 bar W 149.052 kg/s

ID 12 T 588.5 C P 1.0 bar W 653.561 kg/s

ID 4 T 402.0 C P 17.4 bar W 90.000 kg/s

ID 10 T 1244.1 C P 16.9 bar W 653.561 kg/s

ID 11 T 588.5 C P 1.0 bar W 653.561 kg/s

ID 6 T 200.0 C P 32.4 bar W 98.611 kg/s

9

618

ID 18 T 136.8 C P 32.4 bar W 98.611 kg/s

stream ID 0-7-air-3 8-7-gas-9 7-8-air-4 7-8-eg-2name ambient air GT fuel extraction air exhaust gast °C 15.0 200.0 402.0 588.5p bar 1.0 32.4 17.4 1.0m kg/s 644.950 98.611 90.000 653.561n kmol/s 22.353 6.407 3.119 24.136V Nm³/h 1,803,646 516,956 251,691 1,947,551LHV kJ/kg 7,139HHV kJ/kg 8,738h kJ/kg -99.5 -1,505.5 302.2 -825.6s J/kgK 124.3 -635.4 182.5 1,162.2M kg/kmol 28.84 15.38 28.84 27.07

Σ mol % 100.00 100.00 100.00 100.00H2 mol % 0.00 45.01 0.00 0.00CO mol % 0.00 1.95 0.00 0.00CO2 mol % 0.03 0.25 0.03 0.61N2 mol % 77.32 41.48 77.32 72.62Ar mol % 0.91 0.59 0.91 0.88CH4 mol % 0.00 0.01 0.00 0.00O2 mol % 20.74 0.30 20.74 10.36H2O mol % 1.01 10.41 1.01 15.52

Σ mass % 100.00 100.00 100.00 100.00H2 mass % 0.00 5.89 0.00 0.00CO mass % 0.00 3.54 0.00 0.00CO2 mass % 0.05 0.72 0.05 1.00N2 mass % 75.07 75.50 75.07 75.13Ar mass % 1.26 1.52 1.26 1.30CH4 mass % 0.00 0.02 0.00 0.00O2 mass % 23.00 0.62 23.00 12.25H2O mass % 0.63 12.18 0.63 10.33

Appendix

154

Appendix E5 – Heat and material balance for the gas turbine (CCIGCC /

Siemens gasifier)

Appendix E6 – Heat and material balance for the gas turbine (CCIGCC / CoP

gasifier)

stream ID 0-7-air-3 8-7-gas-9 7-8-air-4 7-8-eg-2name ambient air GT fuel extraction air exhaust gast °C 15.0 200.0 401.6 589.6p bar 1.0 32.4 17.4 1.0m kg/s 643.600 97.461 90.000 651.060n kmol/s 22.306 6.419 3.119 24.101V Nm³/h 1,799,870 517,979 251,691 1,944,697LHV kJ/kg 7,169HHV kJ/kg 8,850h kJ/kg -99.5 -1,852.4 301.8 -877.7s J/kgK 124.3 -703.8 182.4 1,158.9M kg/kmol 28.84 15.17 28.84 27.00



stream ID 0-7-air-3 7-8-air-4 8-7-gas-9 7-8-eg-2name ambient air extraction air fuel GT fuel exhaust gast °C 15.0 404.3 143.3 200.0 587.1p bar 1.0 17.6 32.4 32.4 1.0m kg/s 675.2 90.0 84.2 84.2 669.4n kmol/s 23.4 3.1 5.7 5.7 24.6V Nm³/h 1,888,102 251,691 455,946 455,946 1,986,259LHV kJ/kg 8,483 8,483HHV kJ/kg 10,334 10,334h kJ/kg -99.5 304.7 -2,093.7 -1,975.2 -837.7s J/kgK 124.3 182.7 -1,084.5 -817.8 1,170.0M kg/kmol 28.84 28.84 14.89 14.89 27.18

Σ mol % 100.00 100.00 100.00 100.00 100.00H2 mol % 0.00 0.00 45.00 45.00 0.00CO mol % 0.00 0.00 1.54 1.54 0.00CO2 mol % 0.03 0.03 0.26 0.26 0.98N2 mol % 77.32 77.32 37.70 37.70 72.35Ar mol % 0.91 0.91 0.61 0.61 0.89CH4 mol % 0.00 0.00 2.34 2.34 0.00O2 mol % 20.74 20.74 0.08 0.08 10.69H2O mol % 1.01 1.01 12.48 12.48 15.10

Σ mass % 100.00 100.00 100.00 100.00 100.00H2 mass % 0.00 0.00 6.09 6.09 0.00CO mass % 0.00 0.00 2.90 2.90 0.00CO2 mass % 0.05 0.05 0.76 0.76 1.58N2 mass % 75.07 75.07 70.86 70.86 74.54Ar mass % 1.26 1.26 1.62 1.62 1.30CH4 mass % 0.00 0.00 2.51 2.51 0.00O2 mass % 23.00 23.00 0.17 0.17 12.58H2O mass % 0.63 0.63 15.08 15.08 10.00

Appendix

155

Appendix E7 – Heat and material balance for the gas turbine (CCIGCC / GER)

stream ID 0-7-air-3 8-7-gas-9 7-8-air-4 7-8-eg-2name ambient air GT fuel extraction air exhaust gast °C 15.0 200.0 401.1 592.3p bar 1.0 32.4 17.3 1.0m kg/s 643.300 93.550 90.000 646.849n kmol/s 22.296 6.380 3.119 24.058V Nm³/h 1,799,032 514,763 251,691 1,941,239LHV kJ/kg 7,345HHV kJ/kg 9,247h kJ/kg -99.5 -2,774.1 301.2 -1,005.4s J/kgK 124.3 -877.6 182.4 1,152.5M kg/kmol 28.84 14.65 28.84 26.87



Appendix

156

Appendix F1 – Relevant boundary conditions for water/steam cycle simula

tions

HRSG Unit Value

ΔΤ Pinch point HP‐evaporator K 10 – 60

ΔΤ Pinch point IP‐evaporator K 10

ΔΤ Pinch point LP‐evaporator K 10

ΔΤ Approach point HP‐superheater K 25

HRSG‐inlet temperature (condensate) °C 90

Fuel preheater outlet temperature °C 200

Steam turbine and condenser Unit Value

Live steam parameters bar/°C 129/565

Reheat steam parameters bar/°C 46/565

LP‐steam parameters bar/°C 6/260

Isentropic efficiency (HP‐turbine) % 89

Isentropic efficiency (IP‐turbine) % 93

Isentropic efficiency (LP‐turbine) % 87

Condenser vacuum mbar 49

Appendix

157

30

HPSH

/IPRH

HPEv

apHP

Eco3

IPSH

HPEc

o2IP

Evap

LPSH

HP/IP

Eco

1LP

Evap

CPRH

8-2-

st-1

HP-B

FW-E

xt2

HP-B

FW-E

xt1

8-3-

BFW

-3

8-2-

BFW

-1IP

-BFW

-Ext

2

HP-S

T Ex

t

Live

ST

Ext

8-2-

st-2

proc

ess

cond

8-2-

BFW

-2

12

1

34

78

911

23

45

67

89

10

12

13

14

15

19

2223

24

29

3031

38

41

42

4849

50

53

4556

57

58

60

61

67

68

7782

8385

73

72

86

8788

89

91

92 93 94

95

96

97

98

102

100

101

103

105

104

108

109

110

1112

1314

15

1617

18

19

20

21

2223

2425

2627

28

29

31

32

33

34

35

60

36

3738

3940

51

4142

47

43

4445

46

48

49

50 52

53

54

55

5657

58

59

63

61

62

8180

76

78

79

5

75

6

6362

52

51

59

74

47

10

FPRH

ExtA

irCoo

ler

7-8-

air-4

55

71

54 6970

44

46

39

25

26

27

37

28

36

20HP

STIP

STLP

ST

90

106

107

ST-C

onde

nser

Cool

ingW

ater

Mak

e Up

Bala

nceO

ut

Cond

Pum

p

Dp L

S pi

pe

Dp H

RH p

ipe

Dp C

RH p

ipe

Dp IP

-LP

ST

HP p

ump

IP p

ump

feed

pum

p

64

Dp d

eaer

ator

Dp L

P pi

pe

3-8-

st-8

7-8-

eg-2

LP-S

T fe

ed 2

Cond

feed

circ

pum

p

32

3232

65

114

113

6611

233

LP-th

rottl

e

EAC-

thro

ttle

8-1-

air-5

IP-S

T fe

ed 1

67

2-8-

st-5

115

66

6835

117

69

21

Ext C

ondP

RH

deae

rato

r

70

119

120

77

129 13

0

8-3-

st-9

78

7913

1

133

1617IP

con

d 1

2-8-

cond

-1

80

132

135

18

8199

136

137

82

134

138

139

4-8-

cond

-2

8-4-

st-1

0

40

43

140

8-5-

BFW

-4

141

LP s

team

2

LP s

team

1

8-5-

st-1

2

143

5-8-

cond

-3

IP-B

FW-E

xt3

IP-B

FW-fe

ed3

85

84

148

149

2-8-

st-4

3411

1

142

64

65

86

116

150

151

8-2-

st-3

87

118

152

ID

1 T

588

.5 C

P 1

.0 b

ar W

653

.6 k

g/s

ID

13 T

10.

0 C

P 2

0.0

bar

W 3

0.5

kg/s

ID

19 T

35.

4 C

P 1

8.0

bar

W 1

72.5

kg/

s

ID

22 T

90.

0 C

P 1

6.0

bar

W 1

88.8

kg/

s

ID

24 T

90.

0 C

P 1

6.0

bar

W 1

88.8

kg/

s

ID

29 T

154

.0 C

P 6

.0 b

ar W

0.0

kg/

s

ID

30 T

151

.8 C

P 4

9.6

bar

W 2

5.2

kg/s

ID

31 T

151

.8 C

P 4

9.6

bar

W 2

5.2

kg/s

ID

38 T

157

.0 C

P 1

4.0

bar

W 0

.0 k

g/s

ID

42 T

162

.5 C

P 6

.6 b

ar W

10.

2 kg

/s

ID

45 T

157

.1 C

P 6

.6 b

ar W

12.

6 kg

/s

ID

49 T

162

.5 C

P 6

.6 b

ar W

22.

8 kg

/s

ID

50 T

163

.4 C

P 6

.4 b

ar W

0.0

kg/

s

ID

53 T

239

.1 C

P 5

.9 b

ar W

28.

5 kg

/s ID

57

T 1

57.6

C P

52.

6 ba

r W

76.

1 kg

/s

ID

58 T

157

.6 C

P 5

2.6

bar

W 4

6.9

kg/s

ID

60 T

259

.7 C

P 5

0.6

bar

W 2

1.7

kg/s

ID

61 T

259

.7 C

P 5

0.6

bar

W 0

.0 k

g/s

ID

67 T

320

.0 C

P 6

0.0

bar

W 0

.0 k

g/s

ID

68 T

304

.1 C

P 4

9.6

bar

W 2

1.6

kg/s

ID

72 T

159

.1 C

P 1

43.9

bar

W 4

9.1

kg/s

ID

73 T

159

.1 C

P 1

43.9

bar

W 4

9.1

kg/s

ID

77 T

316

.4 C

P 1

39.5

bar

W 0

.0 k

g/s

ID

82 T

336

.4 C

P 1

39.5

bar

W 0

.0 k

g/s

ID

83 T

336

.4 C

P 1

39.5

bar

W 4

9.1

kg/s

ID

85 T

336

.1 C

P 1

39.0

bar

W 1

00.3

kg/

s

ID

86 T

563

.5 C

P 1

35.0

bar

W 1

00.3

kg/

s ID

87 T

561

.0 C

P 1

28.5

bar

W 1

00.3

kg/

s

ID

88 T

561

.0 C

P 1

28.5

bar

W 0

.0 k

g/s

ID

89 T

561

.0 C

P 1

28.5

bar

W 1

00.3

kg/

s

ID

91 T

412

.5 C

P 5

1.0

bar

W 5

.6 k

g/s

ID

92 T

412

.5 C

P 5

1.0

bar

W 9

4.7

kg/s

ID

93 T

412

.4 C

P 5

0.1

bar

W 9

4.7

kg/s

ID

94 T

411

.9 C

P 4

9.6

bar

W 1

16.3

kg/

s

ID

96 T

562

.9 C

P 4

6.3

bar

W 1

16.3

kg/

s

ID

97 T

275

.8 C

P 6

.1 b

ar W

116

.3 k

g/s

ID

98 T

275

.8 C

P 6

.1 b

ar W

0.0

kg/

s

ID 1

00 T

275

.7 C

P 6

.0 b

ar W

106

.8 k

g/s

ID 1

01 T

164

.0 C

P 6

.4 b

ar W

0.0

kg/

s ID

102

T 2

67.7

C P

5.9

bar

W 1

35.3

kg/

s

ID 1

03 T

267

.7 C

P 5

.9 b

ar W

132

.4 k

g/s

ID 1

05 T

20.

0 C

P 4

.0 b

ar W

730

1.5

kg/s

ID 1

08 T

402

.0 C

P 1

7.4

bar

W 9

0.0

kg/s

ID 1

10 T

177

.5 C

P 1

6.9

bar

W 9

0.0

kg/s

ID

2 T

423

.9 C

ID

3 T

346

.4 C

ID

4 T

338

.1 C

ID

7 T

274

.6 C

ID

8 T

268

.0 C

ID

9 T

208

.5 C

ID

11 T

108

.6 C

ID

32 T

259

.7 C

P 5

0.6

bar

W 2

5.2

kg/s

ID

28 T

148

.3 C

P 1

2.0

bar

W 1

72.5

kg/

s

ID

34 T

267

.5 C

P 5

.7 b

ar W

2.9

kg/

s

ID 1

04 T

32.

5 C

P 0

.049

bar

W 1

32.4

kg/

s

ID

12 T

32.

5 C

P 0

.049

bar

W 1

32.4

kg/

s

ID

14 T

28.

4 C

P 0

.049

bar

W 1

62.9

kg/

s

ID

15 T

28.

4 C

P 0

.049

bar

W 0

.0 k

g/s

ID 1

14 T

156

.8 C

P 5

.7 b

ar W

200

.6 k

g/s ID

112

T 1

56.8

C P

5.7

bar

W 2

00.6

kg/

s

ID

33 T

152

.4 C

P 6

.0 b

ar W

25.

2 kg

/s

ID 1

15 T

264

.7 C

P 5

0.1

bar

W 0

.0 k

g/s

ID 1

19 T

29.

0 C

P 2

.0 b

ar W

730

1.5

kg/s

ID 1

20 T

29.

0 C

P 4

.0 b

ar W

730

1.5

kg/s

ID

95 T

563

.5 C

P 4

7.6

bar

W 1

16.3

kg/

s

ID 1

30 T

264

.0 C

P 5

0.1

bar

W 0

.0 k

g/s

ID 1

31 T

205

.4 C

P 1

7.4

bar

W 0

.0 k

g/s

ID 1

33 T

150

.3 C

P 4

.8 b

ar W

9.6

kg/

s

ID 1

38 T

150

.3 C

P 4

.8 b

ar W

9.6

kg/

s

ID 1

39 T

149

.8 C

P 4

.8 b

ar W

9.5

kg/

s

ID 1

37 T

275

.8 C

P 6

.1 b

ar W

9.5

kg/

s

ID 1

40 T

157

.0 C

P 1

4.0

bar

W 5

.7 k

g/s

ID 1

41 T

164

.0 C

P 6

.4 b

ar W

5.7

kg/

s

ID 1

43 T

246

.0 C

P 3

8.0

bar

W 0

.1 k

g/s

ID 1

48 T

336

.2 C

P 1

39.0

bar

W 5

1.2

kg/s

ID

81 T

336

.4 C

P 1

39.5

bar

W 4

9.1

kg/s

ID

80 T

336

.4 C

P 1

39.5

bar

W 4

9.1

kg/s

ID

76 T

316

.4 C

P 1

39.5

bar

W 4

9.1

kg/s

ID

78 T

316

.4 C

P 1

39.5

bar

W 4

9.1

kg/s

ID

79 T

316

.4 C

P 1

39.5

bar

W 4

9.1

kg/s

ID

5 T

333

.9 C

ID

75 T

293

.9 C

P 1

40.7

bar

W 4

9.1

kg/s

ID

6 T

322

.6 C

ID

63 T

259

.7 C

P 5

0.6

bar

W 2

1.7

kg/s

ID

62 T

259

.7 C

P 5

0.6

bar

W 2

1.7

kg/s

ID

52 T

239

.6 C

P 6

.1 b

ar W

28.

5 kg

/s

ID

51 T

162

.3 C

P 6

.4 b

ar W

28.

5 kg

/s

ID

59 T

259

.7 C

P 5

0.6

bar

W 4

6.9

kg/s

ID

74 T

259

.7 C

P 1

41.9

bar

W 4

9.1

kg/s

ID

47 T

162

.5 C

P 6

.6 b

ar W

12.

6 kg

/s

ID

10 T

172

.5 C

ID

55 T

157

.6 C

P 5

2.6

bar

W 1

23.0

kg/

s

ID

71 T

159

.1 C

P 1

43.9

bar

W 0

.0 k

g/s

ID

54 T

157

.0 C

P 1

4.0

bar

W 1

23.0

kg/

s

ID

69 T

157

.0 C

P 1

4.0

bar

W 4

9.1

kg/s

ID

46 T

157

.1 C

P 6

.6 b

ar W

12.

6 kg

/s

ID

25 T

148

.3 C

P 1

2.0

bar

W 1

88.8

kg/

s

ID

26 T

148

.3 C

P 1

2.0

bar

W 1

6.3

kg/s

ID

27 T

148

.4 C

P 1

6.0

bar

W 1

6.3

kg/s

ID

37 T

157

.0 C

P 1

4.0

bar

W 2

00.6

kg/

s

ID

20 T

35.

4 C

P 1

8.0

bar

W 0

.0 k

g/s

ID

90 T

412

.5 C

P 5

1.0

bar

W 1

00.3

kg/

s

ID 1

07 T

29.

5 C

P 2

.0 b

ar W

730

1.5

kg/s

ID

34 T

267

.5 C

P 5

.7 b

ar W

2.9

kg/

s

ID

66 T

304

.1 C

P 4

9.6

bar

W 2

1.6

kg/s

ID

21 T

35.

4 C

P 1

8.0

bar

W 1

72.5

kg/

s

ID

16 T

28.

4 C

P 0

.049

bar

W 1

62.9

kg/

s

ID

17 T

28.

4 C

P 6

.0 b

ar W

162

.9 k

g/s

ID 1

32 T

35.

3 C

P 4

.8 b

ar W

172

.5 k

g/s

ID

18 T

240

.0 C

P 1

8.0

bar

W 0

.0 k

g/s

ID

99 T

275

.8 C

P 6

.1 b

ar W

116

.3 k

g/s

ID 1

34 T

156

.2 C

P 5

.6 b

ar W

0.0

kg/

s

ID

40 T

157

.0 C

P 1

4.0

bar

W 1

0.2

kg/s

ID

84 T

336

.2 C

P 1

39.0

bar

W 0

.0 k

g/s

ID 1

51 T

264

.0 C

P 5

0.1

bar

W 0

.0 k

g/s

ID 1

52 T

84.

4 C

P 1

6.0

bar

W 1

72.5

kg/

s

ID 1

42 T

264

.0 C

P 5

0.1

bar

W 0

.1 k

g/s

ID

65 T

264

.7 C

P 5

0.6

bar

W 2

1.7

kg/s

ID 1

16 T

264

.0 C

P 5

0.1

bar

W 2

1.7

kg/s

ID 1

18 T

51.

5 C

P 1

7.0

bar

W 1

72.5

kg/

s

Appendix F2 – CHEMCAD model of the water/steam cycle for the CCIGCC /

SCGP

Appendix

158

stre

am ID

3-8-

gas-

57-

8-ai

r-4

7-8-

eg-2

2-8-

st-4

4-8-

cond

-25-

8-st

-11

5-8-

cond

-3IP

-BFW

-feed

39-

8-cw

-10

10-8

-mu-

48-

0-eg

-38-

1-ai

r-58-

7-ga

s-9

8-2-

st-1

8-2-

BFW

-18-

4-st

-10

8-5-

BFW

-48-

5-st

-12

IP-B

FW-E

xt3

8-2-

st-3

8-9-

cw-9

nam

eG

T fu

elex

tract

ion

air

exha

ust g

asHP

ste

amco

nden

sate

LP s

team

cond

ensa

teIP

-BFW

-feed

3co

olin

g w

ater

mak

e up

wat

erex

haus

t gas

to s

tack

GT

extra

ctio

n ai

rG

T fu

elIP

ste

amIP

BFW

LP s

team

LP B

FWIP

ste

amIP

-BFW

-Ext

3IP

ste

amco

olin

g w

ater

t°C

6.40

7402.0

588.5

336.2

149.8

164.0

246.0

151.8

20.0

10.0

106.0

177.5

200.

0412.5

157.6

275.8

157.0

264.0

259.7

264.0

29.5

pba

r51

6,95

617.40

1.05

139.00

4.80

6.40

38.00

49.60

4.00

20.00

1.05

16.90

32.4

51.00

52.60

6.10

14.00

50.10

50.60

50.10

2.00

mkg

/s32

.490.000

653.560

51.167

9.476

5.698

0.087

25.212

7,302

30.514

653.560

90.000

98.6

115.590

76.091

9.476

5.698

0.087

25.212

0.000

7,302

nkm

ol/s

136.

83.119

24.136

2.840

0.526

0.316

0.005

1.399

405.302

1.694

24.136

3.119

6.40

70.310

4.224

0.526

0.316

0.005

1.399

0.000

405.302

VNm

³/h98

.611

251,691

1,947,543

1,947,543

251,691

516,

956

LHV

kJ/k

g7,

139

7,13

9HH

VkJ

/kg

8,73

88,

738

hkJ

/kg

-1,6

30.9

302

‐826

‐13,336

‐15,350

‐13,217

‐14,915

‐15,339

‐15,897

‐15,938

‐1,387

65-1

,505

.5‐12,718

‐15,314

‐12,970

‐15,319

‐13,188

‐14,848

‐13,188

‐15,858

sJ/

kgK

-919

.90

1‐4

‐8‐3

‐7‐8

‐9‐9

00

-635

.4‐3

‐7‐2

‐8‐3

‐7‐3

‐9M

kg/k

mol

15.3

828

.84

27.0

718

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

27.0

728

.84

15.3

818

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

18.0

0

Σm

ol %

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ol %

45.0

10.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

45.0

10.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

mol

%1.

950.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.95

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

2m

ol %

0.25

0.03

0.61

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.61

0.03

0.25

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

N2m

ol %

41.4

877.32

72.62

0.00

0.00

0.00

0.00

0.00

0.00

0.00

72.62

77.32

41.4

80.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Arm

ol %

0.59

0.91

0.88

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.88

0.91

0.59

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH4

mol

%0.

010.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

O2

mol

%0.

3020.74

10.36

0.00

0.00

0.00

0.00

0.00

0.00

0.00

10.36

20.74

0.30

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mol

%10

.41

1.01

15.52

100.00

100.00

100.00

100.00

100.00

100.00

100.00

15.52

1.01

10.4

1100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2S

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HCN

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Σm

ass

%10

0.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ass

%5.

890.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

5.89

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

mas

s %

3.54

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

3.54

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

2m

ass

%0.

720.05

1.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.00

0.05

0.72

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

N2m

ass

%75

.50

75.07

75.13

0.00

0.00

0.00

0.00

0.00

0.00

0.00

75.13

75.07

75.5

00.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Arm

ass

%1.

521.26

1.30

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.30

1.26

1.52

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH4

mas

s %

0.02

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.02

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

O2

mas

s %

0.62

23.00

12.25

0.00

0.00

0.00

0.00

0.00

0.00

0.00

12.25

23.00

0.62

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mas

s %

12.1

80.63

10.33

100.00

100.00

100.00

100.00

100.00

100.00

100.00

10.33

0.63

12.1

8100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2S

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

Sm

ass

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ass

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HCN

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Appendix F3 – Heat and material balance for the water/steam cycle (CCIGCC

/ SCGP)

Appendix

159

30

HPSH

/IPR

HHP

Evap

HPEc

o3IP

SHHP

Eco2

IPEv

apLP

SHHP

/IP

Eco1

LPEv

apCP

RH

8-2-

st-1

HP-B

FW-E

xt2

HP-B

FW-E

xt1

8-3-

BFW

-3

8-2-

BFW

-1IP

-BFW

-Ext

2

HP-S

T Ex

t

Live

ST E

xt

8-2-

st-2

proc

ess

cond

8-2-

BFW

-2

12

1

34

78

911

23

45

67

89

10

12

13

14

15

19

2223

24

29

3031

38

4142

4849

50

53

45

56

57

58

60

61

67

68

7782

83

85

73

72

86

8788

89

91

92 93 94

95

96

97

98

102

100

101

103

105

104

108

109

110

1112

1314

15

16

1718

19

20

21

2223

24

25

2627

28

29

31

32

33

34

35

60

36

3738

39

40

51

4142

47

43

4445

46

48

49

50 52

53

54

55

5657

58

59

63

61

62

8180

76

78

79

5

75

6

63

62

52

51

59

74

47

10

FPRH

ExtA

irCoo

ler

7-8-

air-4

55

71

54 69

70

44

46

39

25

26

27

37

28

36

20HP

STIP

ST

LPST

90

106

107

ST-C

onde

nser

Coolin

gWat

erM

ake

UpBa

lance

Out

Cond

Pum

p

Dp L

S pip

e

Dp H

RH p

ipe

Dp C

RH p

ipe

Dp I

P-LP

ST

HP p

ump

IP p

ump

feed

pum

p

64

Dp d

eaer

ator

Dp L

P pip

e

3-8-

st-8

7-8-

eg-2

LP-S

T fe

ed 2

Cond

fee

d

circ

pum

p

32

323265

114

113

66

112

33

LP-t

hrot

tle

EAC-

thro

ttle

8-1-

air-5

IP-S

T fe

ed 1

67

2-8-

st-5

115

66

68

3511

769

21 118

Ext

Cond

PRH

deae

rato

r

70

119

120

77

129

130

8-3-

st-9

78

7913

1

133

1617IP

con

d 1

2-8-

cond

-1

80

132

135

18

81

9913

6

137

82

134

138

139

4-8-

cond

-2

8-4-

st-1

0

40

43

140

8-5-

BFW

-4

141

LP s

team

2

LP s

team

1

8-5-

st-1

2

143

5-8-

cond

-3

IP-B

FW-E

xt3

IP-B

FW-f

eed3

85

84

148

149

2-8-

st-4

3411

1

ID

1

T 5

89.6

C P

1.0

bar

W 6

51.1

kg/

s

ID

13

T 1

0.0

C P

20.

0 ba

r W

5.5

kg/

s

ID

19

T 3

9.3

C P

18.

0 ba

r W

144

.3 k

g/s

ID

22

T 9

0.0

C P

16.

0 ba

r W

212

.9 k

g/s

ID

23

T 9

0.0

C P

16.

0 ba

r W

212

.9 k

g/s

ID

24

T 9

0.0

C P

16.

0 ba

r W

212

.9 k

g/s

ID

29

T 1

54.0

C P

6.0

bar

W 0

.0 k

g/s

ID

30

T 1

59.1

C P

49.

6 ba

r W

24.

1 kg

/s

ID

31

T 1

59.1

C P

49.

6 ba

r W

24.

1 kg

/s

ID

32

T 2

59.7

C P

50.

6 ba

r W

24.

1 kg

/s

ID

38

T 1

57.0

C P

14.

0 ba

r W

2.7

kg/

s

ID

41

T 1

57.1

C P

6.7

bar

W 1

0.2

kg/s

ID

42

T 1

62.5

C P

6.6

bar

W 1

0.2

kg/s

ID

45

T 1

57.1

C P

6.6

bar

W 1

1.4

kg/s

ID

48

T 1

62.5

C P

6.6

bar

W 1

1.4

kg/s

ID

49

T 1

62.5

C P

6.6

bar

W 2

1.5

kg/s

ID

50

T 1

63.4

C P

6.4

bar

W 2

.7 k

g/s

ID

53

T 2

39.1

C P

5.9

bar

W 3

0.1

kg/s

ID

56

T 1

57.6

C P

52.

6 ba

r W

51.

5 kg

/s

ID

57

T 1

57.6

C P

52.

6 ba

r W

7.6

kg/

s

ID

58

T 1

57.6

C P

52.

6 ba

r W

43.

9 kg

/s

ID

60

T 2

59.7

C P

50.

6 ba

r W

19.

8 kg

/s

ID

61

T 2

59.7

C P

50.

6 ba

r W

0.0

kg/

s

ID

67

T 3

20.0

C P

60.

0 ba

r W

0.0

kg/

s

ID

68

T 3

01.2

C P

49.

6 ba

r W

27.

4 kg

/s

ID

72

T 1

59.1

C P

143

.9 b

ar W

57.

4 kg

/s

ID

73

T 1

59.1

C P

143

.9 b

ar W

57.

3 kg

/s

ID

77

T 3

16.4

C P

139

.5 b

ar W

0.0

kg/

s

ID

82

T 3

36.4

C P

139

.5 b

ar W

0.0

kg/

s

ID

83

T 3

36.4

C P

139

.5 b

ar W

57.

3 kg

/s

ID

85

T 3

36.1

C P

139

.0 b

ar W

88.

8 kg

/s

ID

86

T 5

64.6

C P

135

.0 b

ar W

88.

8 kg

/s

ID

87

T 5

62.1

C P

128

.5 b

ar W

88.

8 kg

/s

ID

88

T 5

62.1

C P

128

.5 b

ar W

0.0

kg/

s

ID

89

T 5

62.1

C P

128

.5 b

ar W

88.

8 kg

/s

ID

91

T 4

12.5

C P

51.

0 ba

r W

5.5

kg/

s

ID

92

T 4

12.5

C P

51.

0 ba

r W

83.

4 kg

/s

ID

93

T 4

12.4

C P

50.

1 ba

r W

83.

4 kg

/s

ID

94

T 4

11.7

C P

49.

6 ba

r W

110

.7 k

g/s

ID

96

T 5

64.1

C P

46.

3 ba

r W

110

.7 k

g/s

ID

97

T 2

76.6

C P

6.1

bar

W 1

10.7

kg/

s

ID

98

T 2

76.6

C P

6.1

bar

W 0

.0 k

g/s

ID

100

T 2

76.5

C P

6.0

bar

W 1

01.8

kg/

s

ID

101

T 1

64.0

C P

6.4

bar

W 0

.0 k

g/s

ID

102

T 2

67.7

C P

5.9

bar

W 1

31.9

kg/

s

ID

103

T 2

67.7

C P

5.9

bar

W 1

29.8

kg/

s

ID

105

T 2

0.0

C P

4.0

bar

W 7

159.

0 kg

/s

ID

108

T 4

01.6

C P

17.

4 ba

r W

90.

0 kg

/s

ID

109

T 1

77.5

C P

16.

9 ba

r W

90.

0 kg

/s

ID

110

T 1

77.5

C P

16.

9 ba

r W

90.

0 kg

/s

ID

2

T 4

36.7

C I

D

3 T

346

.3 C

ID

4

T 3

35.2

C

ID

7

T 2

74.6

C

ID

8

T 2

67.6

C

ID

9

T 2

05.0

C

ID

11

T 1

02.9

C

ID

32

T 2

59.7

C P

50.

6 ba

r W

24.

1 kg

/s

ID

28

T 1

46.3

C P

12.

0 ba

r W

112

.8 k

g/s

ID

34

T 2

67.5

C P

5.7

bar

W 2

.0 k

g/s

ID

104

T 3

2.5

C P

0.0

49 b

ar W

129

.8 k

g/s

ID

12

T 3

2.5

C P

0.0

49 b

ar W

129

.8 k

g/s

ID

14

T 3

1.6

C P

0.0

49 b

ar W

135

.3 k

g/s

ID

15

T 3

1.6

C P

0.0

49 b

ar W

0.0

kg/

s

ID

114

T 1

56.8

C P

5.7

bar

W 1

38.9

kg/

s

ID

113

T 0

.0 C

P 5

.7 b

ar W

0.0

kg/

s

ID

112

T 1

56.8

C P

5.7

bar

W 1

38.9

kg/

s

ID

33

T 1

58.8

C P

6.0

bar

W 2

4.1

kg/s

ID

115

T 2

64.7

C P

50.

1 ba

r W

7.6

kg/

s

ID

118

T 3

9.3

C P

16.

0 ba

r W

112

.8 k

g/s

ID

119

T 2

9.0

C P

2.0

bar

W 7

159.

0 kg

/s

ID

120

T 2

9.0

C P

4.0

bar

W 7

159.

0 kg

/s

ID

95

T 5

64.6

C P

47.

6 ba

r W

110

.7 k

g/s

ID

130

T 2

64.1

C P

50.

1 ba

r W

0.0

kg/

s

ID

131

T 2

05.4

C P

17.

4 ba

r W

0.0

kg/

s

ID

133

T 1

50.3

C P

4.8

bar

W 9

.0 k

g/s

ID

138

T 1

50.3

C P

4.8

bar

W 9

.0 k

g/s

ID

139

T 1

49.8

C P

4.8

bar

W 8

.9 k

g/s

ID

137

T 2

76.6

C P

6.1

bar

W 8

.9 k

g/s

ID

140

T 1

57.0

C P

14.

0 ba

r W

5.9

kg/

s

ID

141

T 1

64.0

C P

6.4

bar

W 5

.9 k

g/s

ID

142

T 2

64.1

C P

50.

1 ba

r W

0.1

kg/

s

ID

143

T 2

46.0

C P

38.

0 ba

r W

0.1

kg/

s

ID

149

T 3

36.2

C P

139

.0 b

ar W

31.

5 kg

/s

ID

148

T 3

36.2

C P

139

.0 b

ar W

0.0

kg/

s

ID

81

T 3

36.4

C P

139

.5 b

ar W

57.

3 kg

/s

ID

80

T 3

36.4

C P

139

.5 b

ar W

57.

3 kg

/s

ID

76

T 3

16.4

C P

139

.5 b

ar W

57.

3 kg

/s

ID

78

T 3

16.4

C P

139

.5 b

ar W

57.

3 kg

/s

ID

79

T 3

16.4

C P

139

.5 b

ar W

57.

3 kg

/s

ID

5

T 3

30.2

C

ID

75

T 2

90.2

C P

140

.7 b

ar W

57.

3 kg

/s

ID

6

T 3

18.5

C

ID

63

T 2

59.7

C P

50.

6 ba

r W

19.

8 kg

/s

ID

62

T 2

59.7

C P

50.

6 ba

r W

19.

8 kg

/s

ID

52

T 2

39.6

C P

6.1

bar

W 3

0.1

kg/s

ID

51

T 1

62.4

C P

6.4

bar

W 3

0.1

kg/s

ID

59

T 2

59.7

C P

50.

6 ba

r W

43.

9 kg

/s

ID

74

T 2

59.7

C P

141

.9 b

ar W

57.

3 kg

/s

ID

47

T 1

62.5

C P

6.6

bar

W 1

1.4

kg/s

ID

10

T 1

72.5

C I

D

55 T

157

.6 C

P 5

2.6

bar

W 5

1.5

kg/s

ID

71

T 1

59.1

C P

143

.9 b

ar W

0.0

kg/

s

ID

54

T 1

57.0

C P

14.

0 ba

r W

51.

5 kg

/s

ID

69

T 1

57.0

C P

14.

0 ba

r W

57.

4 kg

/s

ID

70

T 1

59.1

C P

143

.9 b

ar W

57.

4 kg

/s

ID

44

T 1

57.0

C P

14.

0 ba

r W

11.

4 kg

/s

ID

46

T 1

57.1

C P

6.6

bar

W 1

1.4

kg/s

ID

39

T 1

57.0

C P

14.

0 ba

r W

130

.4 k

g/s

ID

25

T 1

46.3

C P

12.

0 ba

r W

212

.9 k

g/s

ID

26

T 1

46.3

C P

12.

0 ba

r W

100

.1 k

g/s

ID

27

T 1

46.4

C P

16.

0 ba

r W

100

.1 k

g/s

ID

37

T 1

57.0

C P

14.

0 ba

r W

138

.9 k

g/s

ID

36

T 1

56.8

C P

5.7

bar

W 1

38.9

kg/

s

ID

20

T 3

9.3

C P

18.

0 ba

r W

31.

5 kg

/s

ID

90

T 4

12.5

C P

51.

0 ba

r W

88.

8 kg

/s

ID

106

T 2

9.5

C P

2.0

bar

W 7

159.

0 kg

/s

ID

107

T 2

9.5

C P

2.0

bar

W 7

159.

0 kg

/s

ID

34

T 2

67.5

C P

5.7

bar

W 2

.0 k

g/s

ID

65

T 2

64.7

C P

50.

6 ba

r W

19.

8 kg

/s

ID

66

T 3

01.2

C P

49.

6 ba

r W

27.

4 kg

/s

ID

35

T 1

48.8

C P

6.0

bar

W 1

36.9

kg/

s

ID

21

T 3

9.3

C P

18.

0 ba

r W

112

.8 k

g/s

ID

116

T 2

64.1

C P

50.

1 ba

r W

27.

4 kg

/s

ID

16

T 3

1.6

C P

0.0

49 b

ar W

135

.3 k

g/s

ID

17

T 3

1.7

C P

6.0

bar

W 1

35.3

kg/

s

ID

132

T 3

9.2

C P

4.8

bar

W 1

44.3

kg/

s

ID

18

T 2

40.0

C P

18.

0 ba

r W

0.0

kg/

s

ID

99

T 2

76.6

C P

6.1

bar

W 1

10.7

kg/

s

ID

134

T 1

56.2

C P

5.6

bar

W 0

.0 k

g/s

ID

40

T 1

57.0

C P

14.

0 ba

r W

10.

2 kg

/s

ID

43

T 1

57.0

C P

14.

0 ba

r W

120

.2 k

g/s

ID

84

T 3

36.2

C P

139

.0 b

ar W

31.

5 kg

/s

142

64

65

86

116

150

151

ID

151

T 2

64.1

C P

50.

1 ba

r W

0.0

kg/

s

8-2-

st-3


Siemens gasifier

Appendix

160

stre

am ID

3-8-

gas-

57-

8-ai

r-47-

8-eg

-22-

8-st

-52-

8-st

-63-

8-st

-84-

8-co

nd-2

5-8-

st-1

15-

8-co

nd-3

9-8-

cw-1

010

-8-m

u-4

8-0-

eg-3

8-1-

air-

58-

7-ga

s-9

8-2-

st-1

8-2-

BFW

-18-

2-BF

W-2

8-3-

BFW

-38-

4-st

-10

8-5-

BFW

-48-

5-st

-12

8-9-

cw-9

nam

eG

T fu

elex

tract

ion

air

exha

ust g

asIP

ste

amLP

ste

amHP

ste

amco

nden

sate

LP s

team

cond

ensa

teco

olin

g w

ater

mak

e up

wat

erex

haus

t gas

to s

tack

GT

extra

ctio

n ai

rG

T fu

elIP

ste

amIP

BFW

LP B

FWBF

WLP

ste

amLP

BFW

IP s

team

cool

ing

wat

ert

°C14

4.1

401.6

589.6

264.7

163.4

336.2

149.8

164.0

246.0

20.0

10.0

102.9

177.5

200.

0412.5

157.6

157.0

39.3

276.6

157.0

264.1

29.5

pba

r32

.417.37

1.05

50.10

6.40

139.00

4.80

6.40

38.00

4.00

20.00

1.05

16.87

32.4

51.00

52.60

14.00

18.00

6.10

14.00

50.10

2.00

mkg

/s97

.461

90.000

651.059

7.599

2.681

31.505

8.903

5.853

0.085

7,159

5.480

651.059

90.000

97.4

615.479

7.599

2.681

31.505

8.903

5.853

0.085

7,159

nkm

ol/s

6.41

93.119

24.101

0.422

0.149

1.749

0.494

0.325

0.005

397.393

0.304

24.101

3.119

6.41

90.304

0.422

0.149

1.749

0.494

0.325

0.005

397.393

VN

m³/h

517,

979

251,691

1,944,689

1,944,689

251,691

517,

979

LHV

kJ/k

g7,

169

7,16

9H

HVkJ

/kg

8,85

08,

850

hkJ

/kg

-1,9

65.8

302

‐878

‐13,185

‐13,218

‐13,336

‐15,350

‐13,217

‐14,915

‐15,897

‐15,938

‐1,447

65-1

,852

.4‐12,715

‐15,314

‐15,319

‐15,815

‐12,968

‐15,319

‐13,187

‐15,858

sJ/

kgK

-958

.80.18

1.16

‐3.43

‐2.66

‐4.02

‐7.57

‐2.66

‐6.65

‐9.12

‐9.26

0.20

‐0.23

-703

.8‐2.71

‐7.50

‐7.50

‐8.85

‐2.13

‐7.50

‐3.44

‐8.98

Mkg

/km

ol15

.17

28.8

427

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

27.0

028

.84

15.1

718

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

18.0

0

Σm

ol %

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2

mol

%45

.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

45.0

00.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

mol

%1.

910.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.91

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

2m

ol %

0.25

0.03

0.61

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.61

0.03

0.25

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

N2

mol

%39

.56

77.32

72.09

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

72.09

77.32

39.5

60.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Arm

ol %

0.56

0.91

0.87

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.87

0.91

0.56

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH4

mol

%0.

020.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.02

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

O2

mol

%0.

2220.74

10.31

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

10.31

20.74

0.22

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mol

%12

.48

1.01

16.12

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

16.12

1.01

12.4

8100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2S

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO

2m

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HC

Nm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Σm

ass

%10

0.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2

mas

s %

5.97

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

5.97

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

mas

s %

3.52

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

3.52

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

2m

ass

%0.

720.05

0.99

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.99

0.05

0.72

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

N2

mas

s %

73.0

175.07

74.76

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

74.76

75.07

73.0

10.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Arm

ass

%1.

481.26

1.29

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.29

1.26

1.48

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH4

mas

s %

0.02

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.02

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

O2

mas

s %

0.47

23.00

12.21

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

12.21

23.00

0.47

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mas

s %

14.8

10.63

10.75

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

10.75

0.63

14.8

1100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2S

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

Sm

ass

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO

2m

ass

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ass

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HC

Nm

ass

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00


/ Siemens gasifier)

Appendix

161

30

HPSH

/IPR

HHP

Evap

HPEc

o3IP

SHHP

Eco2

IPEv

apLP

SHHP

/IP

Eco1

LPEv

apCP

RH

8-2-

st-1

HP-B

FW-E

xt2

HP-B

FW-E

xt1

8-3-

BFW

-3

8-2-

BFW

-1IP

-BFW

-Ext

2

HP-S

T Ex

t

Live

ST E

xt

8-2-

st-2

proc

ess

cond

8-2-

BFW

-2

12

1

34

78

911

23

45

67

89

10

12

13

14

15

19

2223

24

29

3031

38

4142

4849

50

53

45

56

57

58

60

61

67

68

7782

83

85

73

72

86

8788

89

91

92 93 94

95

96

97

98

102

100

101

103

105

104

108

109

110

1112

1314

15

16

1718

19

20

21

2223

24

25

2627

28

29

31

32

33

34

35

60

36

3738

39

40

51

4142

47

43

4445

46

48

49

50

52

53

54

55

5657

58

59

63

61

62

8180

76

78

79

5

75

6

63

62

52

51

59

74

47

10

FPRH

ExtA

irCoo

ler

7-8-

air-4

55

71

54 69

70

44

46

39

25

26

27

37

28

36

20HP

STIP

ST

LPST

90

106

107

ST-C

onde

nser

Coolin

gWat

erM

ake

UpBa

lance

Out

Cond

Pum

p

Dp L

S pip

e

Dp H

RH p

ipe

Dp C

RH p

ipe

Dp I

P-LP

ST

HP p

ump

IP p

ump

feed

pum

p

64

Dp d

eaer

ator

Dp L

P pip

e

3-8-

st-8

7-8-

eg-2

LP-S

T fe

ed 2

Cond

fee

d

circ

pum

p

32

323265

114

113

66

112

33

LP-t

hrot

tle

EAC-

thro

ttle

8-1-

air-5

IP-S

T fe

ed 1

67

2-8-

st-5

115

66

68

3511

7

69

21

Ext

Cond

PRH

deae

rato

r

70

119

120

77

129

78

7913

1

133

1617IP

con

d 1

2-8-

cond

-1

80

132

135

18

81

9913

6

137

82

134

138

139

4-8-

cond

-2

8-4-

st-1

0

40

43

140

8-5-

BFW

-4

141

LP s

team

2

LP s

team

1

8-5-

st-1

2

143

5-8-

cond

-3

IP-B

FW-E

xt3

IP-B

FW-f

eed3

85

84

148

149

2-8-

st-4

3411

1

ID

1

T 5

87.1

C P

1.0

bar

W 6

69.4

kg/

s

ID

13

T 1

0.0

C P

20.

0 ba

r W

18.

9 kg

/s

ID

19

T 3

6.5

C P

18.

0 ba

r W

161

.9 k

g/s

ID

22

T 9

0.5

C P

16.

0 ba

r W

161

.9 k

g/s

ID

23

T 9

0.5

C P

16.

0 ba

r W

161

.9 k

g/s

ID

24

T 9

0.0

C P

16.

0 ba

r W

161

.7 k

g/s

ID

29

T 1

54.0

C P

6.0

bar

W 0

.0 k

g/s

ID

30

T 1

58.3

C P

49.

6 ba

r W

21.

6 kg

/s

ID

31

T 1

58.3

C P

49.

6 ba

r W

21.

6 kg

/s

ID

32

T 2

59.7

C P

50.

6 ba

r W

21.

6 kg

/s

ID

38

T 1

57.0

C P

14.

0 ba

r W

6.7

kg/

s

ID

41

T 1

57.1

C P

6.7

bar

W 1

0.3

kg/s

ID

42

T 1

62.5

C P

6.6

bar

W 1

0.3

kg/s

ID

45

T 1

57.1

C P

6.6

bar

W 1

3.4

kg/s

ID

48

T 1

62.5

C P

6.6

bar

W 1

3.4

kg/s

ID

49

T 1

62.5

C P

6.6

bar

W 2

3.7

kg/s

ID

50

T 1

63.4

C P

6.4

bar

W 6

.7 k

g/s

ID

53

T 2

39.1

C P

5.9

bar

W 3

6.3

kg/s

ID

56

T 1

57.6

C P

52.

6 ba

r W

101

.2 k

g/s

ID

57

T 1

57.6

C P

52.

6 ba

r W

57.

2 kg

/s

ID

58

T 1

57.6

C P

52.

6 ba

r W

44.

0 kg

/s

ID

60

T 2

59.7

C P

50.

6 ba

r W

22.

5 kg

/s

ID

61

T 2

59.7

C P

50.

6 ba

r W

0.0

kg/

s

ID

67

T 3

20.0

C P

60.

0 ba

r W

0.0

kg/

s

ID

68

T 3

04.5

C P

49.

6 ba

r W

20.

7 kg

/s

ID

72

T 1

59.1

C P

143

.9 b

ar W

49.

0 kg

/s

ID

73

T 1

59.1

C P

143

.9 b

ar W

49.

0 kg

/s

ID

77

T 3

16.4

C P

139

.5 b

ar W

0.0

kg/

s

ID

82

T 3

36.4

C P

139

.5 b

ar W

0.0

kg/

s

ID

83

T 3

36.4

C P

139

.5 b

ar W

48.

8 kg

/s

ID

85

T 3

36.1

C P

139

.0 b

ar W

107

.7 k

g/s

ID

86

T 5

62.1

C P

135

.0 b

ar W

107

.7 k

g/s

ID

87

T 5

59.6

C P

128

.5 b

ar W

107

.7 k

g/s

ID

88

T 5

59.6

C P

128

.5 b

ar W

0.0

kg/

s

ID

89

T 5

59.6

C P

128

.5 b

ar W

107

.7 k

g/s

ID

91

T 4

12.5

C P

51.

0 ba

r W

0.0

kg/

s

ID

92

T 4

12.5

C P

51.

0 ba

r W

88.

8 kg

/s

ID

93

T 4

12.4

C P

50.

1 ba

r W

88.

8 kg

/s

ID

94

T 4

11.8

C P

49.

6 ba

r W

109

.4 k

g/s

ID

96

T 5

61.5

C P

46.

3 ba

r W

109

.4 k

g/s

ID

97

T 2

74.8

C P

6.1

bar

W 1

09.4

kg/

s

ID

98

T 2

74.8

C P

6.1

bar

W 0

.0 k

g/s

ID

100

T 2

74.7

C P

6.0

bar

W 1

00.8

kg/

s

ID

101

T 1

64.0

C P

6.4

bar

W 0

.0 k

g/s

ID

102

T 2

65.0

C P

5.9

bar

W 1

37.1

kg/

s

ID

103

T 2

65.0

C P

5.9

bar

W 1

34.3

kg/

s

ID

105

T 2

0.0

C P

4.0

bar

W 7

392.

6 kg

/s

ID

108

T 4

04.3

C P

17.

6 ba

r W

90.

0 kg

/s

ID

109

T 1

77.5

C P

17.

1 ba

r W

90.

0 kg

/s

ID

110

T 1

77.5

C P

17.

1 ba

r W

90.

0 kg

/s

ID

2

T 4

21.7

C I

D

3 T

346

.4 C

ID

4

T 3

38.5

C

ID

7

T 2

74.7

C

ID

8

T 2

66.4

C

ID

9

T 2

10.1

C

ID

11

T 1

19.9

C

ID

32

T 2

59.7

C P

50.

6 ba

r W

21.

6 kg

/s

ID

28

T 1

47.2

C P

12.

0 ba

r W

161

.7 k

g/s

ID

34

T 2

64.8

C P

5.7

bar

W 2

.8 k

g/s

ID

104

T 3

2.5

C P

0.0

49 b

ar W

134

.3 k

g/s

ID

12

T 3

2.5

C P

0.0

49 b

ar W

134

.3 k

g/s

ID

14

T 2

9.8

C P

0.0

49 b

ar W

153

.2 k

g/s

ID

15

T 2

9.8

C P

0.0

49 b

ar W

0.0

kg/

s

ID

114

T 1

56.8

C P

5.7

bar

W 1

86.1

kg/

s

ID

113

T 0

.0 C

P 5

.7 b

ar W

0.0

kg/

s

ID

112

T 1

56.8

C P

5.7

bar

W 1

86.1

kg/

s

ID

33

T 1

58.8

C P

6.0

bar

W 2

1.6

kg/s

ID

115

T 2

64.7

C P

50.

1 ba

r W

0.0

kg/

s

ID

118

T 5

6.6

C P

17.

0 ba

r W

161

.9 k

g/s

ID

119

T 2

9.0

C P

2.0

bar

W 7

385.

1 kg

/s

ID

120

T 2

9.0

C P

4.0

bar

W 7

385.

1 kg

/s

ID

95

T 5

62.1

C P

47.

6 ba

r W

109

.4 k

g/s

ID

131

T 2

05.4

C P

17.

4 ba

r W

0.0

kg/

s

ID

133

T 1

50.3

C P

4.8

bar

W 8

.7 k

g/s

ID

138

T 1

50.3

C P

4.8

bar

W 8

.7 k

g/s

ID

139

T 1

49.8

C P

4.8

bar

W 8

.6 k

g/s

ID

137

T 2

74.8

C P

6.1

bar

W 8

.6 k

g/s

ID

140

T 1

57.0

C P

14.

0 ba

r W

5.8

kg/

s

ID

141

T 1

64.0

C P

6.4

bar

W 5

.8 k

g/s

ID

142

T 2

64.0

C P

50.

1 ba

r W

0.1

kg/

s

ID

143

T 2

46.0

C P

38.

0 ba

r W

0.1

kg/

s

ID

149

T 3

36.2

C P

139

.0 b

ar W

58.

9 kg

/s

ID

148

T 3

36.2

C P

139

.0 b

ar W

58.

9 kg

/s

ID

81

T 3

36.4

C P

139

.5 b

ar W

48.

8 kg

/s

ID

80

T 3

36.4

C P

139

.5 b

ar W

48.

8 kg

/s

ID

76

T 3

16.4

C P

139

.5 b

ar W

49.

0 kg

/s

ID

78

T 3

16.4

C P

139

.5 b

ar W

49.

0 kg

/s

ID

79

T 3

16.4

C P

139

.5 b

ar W

48.

8 kg

/s

ID

5

T 3

34.5

C

ID

75

T 2

94.5

C P

140

.7 b

ar W

49.

0 kg

/s

ID

6

T 3

23.3

C

ID

63

T 2

59.7

C P

50.

6 ba

r W

22.

5 kg

/s

ID

62

T 2

59.7

C P

50.

6 ba

r W

22.

5 kg

/s

ID

52

T 2

39.6

C P

6.1

bar

W 3

6.3

kg/s

ID

51

T 1

62.5

C P

6.4

bar

W 3

6.3

kg/s

ID

59

T 2

59.7

C P

50.

6 ba

r W

44.

0 kg

/s

ID

74

T 2

59.7

C P

141

.9 b

ar W

49.

0 kg

/s

ID

47

T 1

62.5

C P

6.6

bar

W 1

3.4

kg/s

ID

10

T 1

72.5

C I

D

55 T

157

.6 C

P 5

2.6

bar

W 1

00.8

kg/

s

ID

71

T 1

59.1

C P

143

.9 b

ar W

0.0

kg/

s

ID

54

T 1

57.0

C P

14.

0 ba

r W

100

.8 k

g/s

ID

69

T 1

57.0

C P

14.

0 ba

r W

49.

0 kg

/s

ID

70

T 1

59.1

C P

143

.9 b

ar W

49.

0 kg

/s

ID

44

T 1

57.0

C P

14.

0 ba

r W

13.

4 kg

/s

ID

46

T 1

57.1

C P

6.6

bar

W 1

3.4

kg/s

ID

39

T 1

57.0

C P

14.

0 ba

r W

173

.5 k

g/s

ID

25

T 1

47.2

C P

12.

0 ba

r W

161

.7 k

g/s

ID

26

T 1

47.2

C P

12.

0 ba

r W

0.0

kg/

s

ID

27

T 1

47.3

C P

16.

0 ba

r W

0.0

kg/

s

ID

37

T 1

57.0

C P

14.

0 ba

r W

186

.1 k

g/s

ID

36

T 1

56.8

C P

5.7

bar

W 1

86.1

kg/

s

ID

20

T 3

6.5

C P

18.

0 ba

r W

0.0

kg/

s

ID

90

T 4

12.5

C P

51.

0 ba

r W

107

.7 k

g/s

ID

106

T 2

9.5

C P

2.0

bar

W 7

392.

6 kg

/s

ID

107

T 2

9.5

C P

2.0

bar

W 7

392.

6 kg

/s

ID

34

T 2

64.8

C P

5.7

bar

W 2

.8 k

g/s

ID

65

T 2

64.7

C P

50.

6 ba

r W

22.

5 kg

/s

ID

66

T 3

04.5

C P

49.

6 ba

r W

20.

7 kg

/s

ID

35

T 1

48.7

C P

6.0

bar

W 1

83.3

kg/

s

ID

21

T 3

6.5

C P

18.

0 ba

r W

161

.9 k

g/s

ID

116

T 2

64.0

C P

50.

1 ba

r W

22.

5 kg

/s

ID

16

T 2

9.8

C P

0.0

49 b

ar W

153

.2 k

g/s

ID

17

T 2

9.9

C P

6.0

bar

W 1

53.2

kg/

s

ID

132

T 3

6.4

C P

4.8

bar

W 1

61.9

kg/

s

ID

18

T 2

40.0

C P

18.

0 ba

r W

0.0

kg/

s

ID

99

T 2

74.8

C P

6.1

bar

W 1

09.4

kg/

s

ID

134

T 1

56.2

C P

5.6

bar

W 0

.0 k

g/s

ID

40

T 1

57.0

C P

14.

0 ba

r W

10.

3 kg

/s

ID

43

T 1

57.0

C P

14.

0 ba

r W

163

.2 k

g/s

ID

84

T 3

36.2

C P

139

.0 b

ar W

0.0

kg/

s

142

64

65

86

116

150

151

ID

151

T 2

64.0

C P

50.

1 ba

r W

1.7

kg/

s

8-2-

st-3

87

118

152

ID

152

T 9

0.5

C P

16.

0 ba

r W

161

.9 k

g/s

130

8-3-

st-9

ID

130

T 4

12.5

C P

51.

0 ba

r W

18.

9 kg

/s

ExtC

ondP

RH2


CoP gasifier

Appendix

162

stre

am ID

3-8-

gas-

57-

8-ai

r-47-

8-eg

-22-

8-st

-52-

8-st

-62-

8-st

-44-

8-co

nd-2

5-8-

st-1

15-

8-co

nd-3

IP-B

FW-fe

ed3

9-8-

cw-1

010

-8-m

u-4

8-0-

eg-3

8-1-

air-5

8-7-

gas-

98-

2-BF

W-1

8-2-

BFW

-28-

3-st

-98-

4-st

-10

8-5-

BFW

-48-

5-st

-12

IP-B

FW-E

xt3

8-2-

st-3

8-9-

cw-9

nam

eG

T fu

elex

tract

ion

air

exha

ust g

asIP

ste

amLP

ste

amHP

ste

amco

nden

sate

LP s

team

cond

ensa

teIP

-BFW

-feed

3co

olin

g w

ater

mak

e up

wat

erex

haus

t gas

to s

tack

GT

extra

ctio

n ai

rG

T fu

elIP

BFW

LP B

FWIP

ste

amLP

ste

amLP

BFW

IP s

team

IP-B

FW-E

xt3

IP s

team

cool

ing

wat

ert

°C14

3.3

404.3

587.1

264.7

163.4

336.2

149.8

164.0

246.0

158.3

20.0

10.0

119.9

177.5

200.

0157.6

157.0

412.5

274.8

157.0

264.0

259.7

264.0

29.5

pba

r32

.417.60

1.05

50.10

6.40

139.00

4.80

6.40

38.00

49.60

4.00

20.00

1.05

17.10

32.4

52.60

14.00

51.00

6.10

14.00

50.10

50.60

50.10

2.00

mkg

/s84

.290.000

669.363

0.000

6.749

58.507

8.576

5.814

0.089

21.570

7,385

18.899

669.363

90.000

84.2

1556.826

6.749

18.899

8.576

5.814

0.089

21.570

1.681

7,385

nkm

ol/s

5.7

3.119

24.616

0.000

0.375

3.248

0.476

0.323

0.005

1.197

409.942

1.049

24.616

3.119

5.65

13.154

0.375

1.049

0.476

0.323

0.005

1.197

0.093

409.942

VNm

³/h45

5,94

6251,691

1,986,251

1,986,251

251,691

455,

946

LHV

kJ/k

g8,

483

8,48

3HH

VkJ

/kg

10,3

3410

,334

hkJ

/kg

-2,0

93.7

305

‐838

‐13,185

‐13,218

‐13,336

‐15,350

‐13,217

‐14,915

‐15,311

‐15,897

‐15,938

‐1,381

65-1

,975

.2‐15,314

‐15,319

‐12,721

‐12,972

‐15,319

‐13,188

‐14,848

‐13,188

‐15,858

sJ/

kgK

-1,0

84.5

01

‐3‐3

‐4‐8

‐3‐7

‐7‐9

‐90

0-8

17.8

‐7‐8

‐3‐2

‐8‐3

‐7‐3

‐9M

kg/k

mol

14.8

928

.84

27.1

818

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

27.1

828

.84

14.8

918

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

Σm

ol %

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ol %

45.0

00.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

45.0

00.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

mol

%1.

540.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.54

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

2m

ol %

0.26

0.03

0.98

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.98

0.03

0.26

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

N2m

ol %

37.7

077.32

72.35

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

72.35

77.32

37.7

00.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Arm

ol %

0.61

0.91

0.89

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.89

0.91

0.61

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH4

mol

%2.

340.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

2.34

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

O2

mol

%0.

0820.74

10.69

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

10.69

20.74

0.08

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mol

%12

.48

1.01

15.10

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

15.10

1.01

12.4

8100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2S

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HCN

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Σm

ass

%10

0.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ass

%6.

090.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

6.09

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

mas

s %

2.90

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

2.90

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

2m

ass

%0.

760.05

1.58

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.58

0.05

0.76

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

N2m

ass

%70

.86

75.07

74.54

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

74.54

75.07

70.8

60.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Arm

ass

%1.

621.26

1.30

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.30

1.26

1.62

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH4

mas

s %

2.51

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

2.51

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

O2

mas

s %

0.17

23.00

12.58

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

12.58

23.00

0.17

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mas

s %

15.0

80.63

10.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

10.00

0.63

15.0

8100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2S

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

Sm

ass

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ass

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HCN

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Appendix F7– Heat and material balance for the water/steam cycle (CCIGCC

/ CoP gasifier)

Appendix

163

30

HPSH

/IPR

HHP

Evap

HPEc

o3IP

SHHP

Eco2

IPEv

apLP

SHHP

/IP

Eco1

LPEv

apCP

RH

8-2-

st-1

HP-B

FW-E

xt2

HP-B

FW-E

xt1

8-3-

BFW

-3

8-2-

BFW

-1IP

-BFW

-Ext

2

HP-S

T Ex

t

Live

ST E

xt

8-2-

st-2

proc

ess

cond

8-2-

BFW

-2

12

1

34

78

911

23

45

67

89

10

12

13

14

15

19

2223

24

29

3031

38

4142

4849

50

53

45

56

57

58

60

61

67

68

7782

83

85

73

72

86

8788

89

91

92 93 94

95

96

97

98

102

100

101

103

105

104

108

109

110

1112

1314

15

16

1718

19

20

21

2223

24

25

2627

28

29

31

32

33

34

35

60

36

3738

39

40

51

4142

47

43

4445

46

48

49

50 52

53

54

55

5657

58

59

63

61

62

8180

76

78

79

5

75

6

63

62

52

51

59

74

47

10

FPRH

ExtA

irCoo

ler

7-8-

air-4

55

71

54 69

70

44

46

39

25

26

27

37

28

36

20HP

STIP

ST

LPST

90

106

107

ST-C

onde

nser

Coolin

gWat

erM

ake

UpBa

lance

Out

Cond

Pum

p

Dp L

S pip

e

Dp H

RH p

ipe

Dp C

RH p

ipe

Dp I

P-LP

ST

HP p

ump

IP p

ump

feed

pum

p

64

Dp d

eaer

ator

Dp L

P pip

e

3-8-

st-8

7-8-

eg-2

LP-S

T fe

ed 2

Cond

fee

d

circ

pum

p

32

323265

114

113

66

112

33

LP-t

hrot

tle

EAC-

thro

ttle

8-1-

air-5

IP-S

T fe

ed 1

67

2-8-

st-5

115

66

68

3511

769

21 118

Ext

Cond

PRH

deae

rato

r

70

119

120

77

129

130

8-3-

st-9

78

7913

1

133

1617IP

con

d 1

2-8-

cond

-1

80

132

135

18

81

9913

6

137

82

134

138

139

4-8-

cond

-2

8-4-

st-1

0

40

43

140

8-5-

BFW

-4

141

LP s

team

2

LP s

team

1

8-5-

st-1

2

143

5-8-

cond

-3

IP-B

FW-E

xt3

IP-B

FW-f

eed3

85

84

148

149

2-8-

st-4

3411

1

ID

1

T 5

92.3

C P

1.0

bar

W 6

46.8

kg/

s

ID

13

T 1

0.0

C P

20.

0 ba

r W

0.0

kg/

s

ID

19

T 4

1.3

C P

18.

0 ba

r W

166

.3 k

g/s

ID

22

T 9

0.0

C P

16.

0 ba

r W

175

.0 k

g/s

ID

23

T 9

0.0

C P

16.

0 ba

r W

175

.0 k

g/s

ID

24

T 9

0.0

C P

16.

0 ba

r W

175

.0 k

g/s

ID

29

T 1

54.0

C P

6.0

bar

W 0

.0 k

g/s

ID

30

T 1

72.0

C P

49.

6 ba

r W

21.

5 kg

/s

ID

31

T 1

72.0

C P

49.

6 ba

r W

21.

5 kg

/s

ID

32

T 2

59.7

C P

50.

6 ba

r W

21.

5 kg

/s

ID

38

T 1

57.0

C P

14.

0 ba

r W

0.0

kg/

s

ID

41

T 1

57.1

C P

6.7

bar

W 1

0.1

kg/s

ID

42

T 1

62.5

C P

6.6

bar

W 1

0.1

kg/s

ID

45

T 1

57.1

C P

6.6

bar

W 1

4.9

kg/s

ID

48

T 1

62.5

C P

6.6

bar

W 1

4.9

kg/s

ID

49

T 1

62.5

C P

6.6

bar

W 2

5.1

kg/s

ID

50

T 1

63.4

C P

6.4

bar

W 0

.0 k

g/s

ID

53

T 2

39.2

C P

5.9

bar

W 3

1.2

kg/s

ID

56

T 1

57.6

C P

52.

6 ba

r W

66.

0 kg

/s

ID

57

T 1

57.6

C P

52.

6 ba

r W

0.0

kg/

s

ID

58

T 1

57.6

C P

52.

6 ba

r W

66.

0 kg

/s

ID

60

T 2

59.7

C P

50.

6 ba

r W

44.

5 kg

/s

ID

61

T 2

59.7

C P

50.

6 ba

r W

0.0

kg/

s

ID

67

T 3

20.0

C P

60.

0 ba

r W

0.0

kg/

s

ID

68

T 3

61.3

C P

49.

6 ba

r W

42.

1 kg

/s

ID

72

T 1

59.1

C P

143

.9 b

ar W

17.

9 kg

/s

ID

73

T 1

59.1

C P

143

.9 b

ar W

17.

9 kg

/s

ID

77

T 3

16.4

C P

139

.5 b

ar W

0.0

kg/

s

ID

82

T 3

36.4

C P

139

.5 b

ar W

0.0

kg/

s

ID

83

T 3

36.4

C P

139

.5 b

ar W

17.

9 kg

/s

ID

85

T 3

36.2

C P

139

.0 b

ar W

94.

5 kg

/s

ID

86

T 5

67.3

C P

135

.0 b

ar W

94.

5 kg

/s

ID

87

T 5

64.8

C P

128

.5 b

ar W

94.

5 kg

/s

ID

88

T 5

64.8

C P

128

.5 b

ar W

0.0

kg/

s

ID

89

T 5

64.8

C P

128

.5 b

ar W

94.

5 kg

/s

ID

91

T 4

12.6

C P

51.

0 ba

r W

0.0

kg/

s

ID

92

T 4

12.6

C P

51.

0 ba

r W

94.

5 kg

/s

ID

93

T 4

12.4

C P

50.

1 ba

r W

94.

5 kg

/s

ID

94

T 4

12.0

C P

49.

6 ba

r W

136

.7 k

g/s

ID

96

T 5

66.8

C P

46.

3 ba

r W

136

.7 k

g/s

ID

97

T 2

78.5

C P

6.1

bar

W 1

36.7

kg/

s

ID

98

T 2

78.5

C P

6.1

bar

W 5

.4 k

g/s

ID

100

T 2

78.4

C P

6.0

bar

W 1

22.5

kg/

s

ID

101

T 1

64.0

C P

6.4

bar

W 0

.0 k

g/s

ID

102

T 2

70.2

C P

5.9

bar

W 1

53.7

kg/

s

ID

103

T 2

70.2

C P

5.9

bar

W 1

52.0

kg/

s

ID

105

T 2

0.0

C P

4.0

bar

W 8

391.

5 kg

/s

ID

108

T 4

01.1

C P

17.

3 ba

r W

90.

0 kg

/s

ID

109

T 1

77.5

C P

16.

8 ba

r W

90.

0 kg

/s

ID

110

T 1

77.5

C P

16.

8 ba

r W

90.

0 kg

/s

ID

2

T 4

24.5

C I

D

3 T

396

.4 C

ID

4

T 3

95.3

C

ID

7

T 2

74.7

C

ID

8

T 2

67.4

C

ID

9

T 2

15.1

C

ID

11

T 1

18.7

C

ID

32

T 2

59.7

C P

50.

6 ba

r W

21.

5 kg

/s

ID

28

T 1

43.1

C P

12.

0 ba

r W

91.

9 kg

/s

ID

34

T 2

70.0

C P

5.7

bar

W 1

.7 k

g/s

ID

104

T 3

2.5

C P

0.0

49 b

ar W

152

.0 k

g/s

ID

12

T 3

2.5

C P

0.0

49 b

ar W

152

.0 k

g/s

ID

14

T 3

2.5

C P

0.0

49 b

ar W

152

.0 k

g/s

ID

15

T 3

2.5

C P

0.0

49 b

ar W

0.0

kg/

s

ID

114

T 1

56.8

C P

5.7

bar

W 1

15.1

kg/

s

ID

113

T 0

.0 C

P 5

.7 b

ar W

0.0

kg/

s

ID

112

T 1

56.8

C P

5.7

bar

W 1

15.1

kg/

s

ID

33

T 1

58.8

C P

6.0

bar

W 2

1.5

kg/s

ID

115

T 2

64.7

C P

50.

1 ba

r W

0.0

kg/

s

ID

118

T 4

1.3

C P

16.

0 ba

r W

91.

9 kg

/s

ID

119

T 2

9.0

C P

2.0

bar

W 8

391.

5 kg

/s

ID

120

T 2

9.0

C P

4.0

bar

W 8

391.

5 kg

/s

ID

95

T 5

67.3

C P

47.

6 ba

r W

136

.7 k

g/s

ID

130

T 2

64.0

C P

50.

1 ba

r W

0.0

kg/

s

ID

131

T 2

05.4

C P

17.

4 ba

r W

0.0

kg/

s

ID

133

T 1

32.0

C P

4.8

bar

W 1

4.3

kg/s

ID

138

T 1

32.0

C P

4.8

bar

W 1

4.3

kg/s

ID

139

T 1

49.8

C P

4.8

bar

W 8

.8 k

g/s

ID

137

T 2

78.5

C P

6.1

bar

W 8

.8 k

g/s

ID

140

T 1

57.0

C P

14.

0 ba

r W

6.1

kg/

s

ID

141

T 1

64.0

C P

6.4

bar

W 6

.1 k

g/s

ID

142

T 2

64.0

C P

50.

1 ba

r W

0.1

kg/

s

ID

143

T 2

46.0

C P

38.

0 ba

r W

0.1

kg/

s

ID

149

T 3

36.2

C P

139

.0 b

ar W

76.

6 kg

/s

ID

148

T 3

36.2

C P

139

.0 b

ar W

49.

5 kg

/s

ID

81

T 3

36.4

C P

139

.5 b

ar W

17.

9 kg

/s

ID

80

T 3

36.4

C P

139

.5 b

ar W

17.

9 kg

/s

ID

76

T 3

16.4

C P

139

.5 b

ar W

17.

9 kg

/s

ID

78

T 3

16.4

C P

139

.5 b

ar W

17.

9 kg

/s

ID

79

T 3

16.4

C P

139

.5 b

ar W

17.

9 kg

/s

ID

5

T 3

78.3

C

ID

75

T 3

08.3

C P

140

.7 b

ar W

17.

9 kg

/s

ID

6

T 3

72.4

C

ID

63

T 2

59.7

C P

50.

6 ba

r W

44.

5 kg

/s

ID

62

T 2

59.7

C P

50.

6 ba

r W

44.

5 kg

/s

ID

52

T 2

39.7

C P

6.1

bar

W 3

1.2

kg/s

ID

51

T 1

62.3

C P

6.4

bar

W 3

1.2

kg/s

ID

59

T 2

59.7

C P

50.

6 ba

r W

66.

0 kg

/s

ID

74

T 2

59.7

C P

141

.9 b

ar W

17.

9 kg

/s

ID

47

T 1

62.5

C P

6.6

bar

W 1

4.9

kg/s

ID

10

T 1

72.5

C I

D

55 T

157

.6 C

P 5

2.6

bar

W 6

6.0

kg/s

ID

71

T 1

59.1

C P

143

.9 b

ar W

0.0

kg/

s

ID

54

T 1

57.0

C P

14.

0 ba

r W

66.

0 kg

/s

ID

69

T 1

57.0

C P

14.

0 ba

r W

17.

9 kg

/s

ID

70

T 1

59.1

C P

143

.9 b

ar W

17.

9 kg

/s

ID

44

T 1

57.0

C P

14.

0 ba

r W

14.

9 kg

/s

ID

46

T 1

57.1

C P

6.6

bar

W 1

4.9

kg/s

ID

39

T 1

57.0

C P

14.

0 ba

r W

109

.0 k

g/s

ID

25

T 1

43.1

C P

12.

0 ba

r W

175

.0 k

g/s

ID

26

T 1

43.1

C P

12.

0 ba

r W

83.

1 kg

/s

ID

27

T 1

43.2

C P

16.

0 ba

r W

83.

1 kg

/s

ID

37

T 1

57.0

C P

14.

0 ba

r W

115

.1 k

g/s

ID

36

T 1

56.8

C P

5.7

bar

W 1

15.1

kg/

s

ID

20

T 4

1.3

C P

18.

0 ba

r W

27.

2 kg

/s

ID

90

T 4

12.6

C P

51.

0 ba

r W

94.

5 kg

/s

ID

106

T 2

9.5

C P

2.0

bar

W 8

391.

5 kg

/s

ID

107

T 2

9.5

C P

2.0

bar

W 8

391.

5 kg

/s

ID

34

T 2

70.0

C P

5.7

bar

W 1

.7 k

g/s

ID

65

T 2

64.7

C P

50.

6 ba

r W

44.

5 kg

/s

ID

66

T 3

61.3

C P

49.

6 ba

r W

42.

1 kg

/s

ID

35

T 1

48.8

C P

6.0

bar

W 1

13.4

kg/

s

ID

21

T 4

1.3

C P

18.

0 ba

r W

91.

9 kg

/s

ID

116

T 2

64.0

C P

50.

1 ba

r W

44.

5 kg

/s

ID

16

T 3

2.5

C P

0.0

49 b

ar W

152

.0 k

g/s

ID

17

T 3

2.6

C P

6.0

bar

W 1

52.0

kg/

s

ID

132

T 4

1.2

C P

4.8

bar

W 1

66.3

kg/

s

ID

18

T 2

40.0

C P

18.

0 ba

r W

0.0

kg/

s

ID

99

T 2

78.5

C P

6.1

bar

W 1

31.3

kg/

s

ID

134

T 1

00.0

C P

6.0

bar

W 5

.4 k

g/s

ID

40

T 1

57.0

C P

14.

0 ba

r W

10.

1 kg

/s

ID

43

T 1

57.0

C P

14.

0 ba

r W

98.

8 kg

/s

ID

84

T 3

36.2

C P

139

.0 b

ar W

27.

2 kg

/s

142

64

65

86

116

150

151

ID

151

T 2

64.0

C P

50.

1 ba

r W

2.2

kg/

s

8-2-

st-3

152

8-2-

BFW

-5

ID

152

T 4

1.3

C P

18.

0 ba

r W

47.

3 kg

/s


GER

Appendix

164

stre

am ID

3-8-

gas-

57-

8-ai

r-47-

8-eg

-22-

8-co

nd-1

3-8-

st-8

2-8-

st-4

4-8-

cond

-25-

8-st

-11

5-8-

cond

-3IP

-BFW

-feed

39-

8-cw

-10

8-0-

eg-3

8-1-

air-5

8-7-

gas-

98-

2-st

-28-

3-BF

W-3

8-4-

st-1

08-

5-BF

W-4

8-5-

st-1

2IP

-BFW

-Ext

38-

2-st

-38-

9-cw

-9na

me

GT

fuel

extra

ctio

n ai

rex

haus

t gas

cond

ensa

teHP

ste

amHP

ste

amco

nden

sate

LP s

team

cond

ensa

teIP

-BFW

-feed

3co

olin

g w

ater

exha

ust g

as to

sta

ckG

T ex

tract

ion

air

GT

fuel

LP s

team

BFW

LP s

team

LP B

FWIP

ste

amIP

-BFW

-Ext

3IP

ste

amco

olin

g w

ater

t°C

6.38

0401.1

592.3

100.0

336.2

336.2

149.8

164.0

246.0

172.0

20.0

118.7

177.5

200.

0278.5

41.3

278.5

157.0

264.0

259.7

264.0

41.3

pba

r51

4,76

317.31

1.05

6.00

139.00

139.00

4.80

6.40

38.00

49.60

4.00

1.05

16.81

32.4

6.10

18.00

6.10

14.00

50.10

50.60

50.10

18.00

mkg

/s32

.490.000

646.849

5.408

27.151

49.473

8.810

6.118

0.111

21.503

8,392

646.849

90.000

93.5

505.408

27.151

8.810

6.118

0.111

21.503

2.213

47.261

nkm

ol/s

157.

03.119

24.058

0.300

1.507

2.746

0.489

0.340

0.006

1.194

465.807

24.058

3.119

6.38

00.300

1.507

0.489

0.340

0.006

1.194

0.123

2.623

VNm

³/h93

.550

251,691

1,941,230

1,941,230

251,691

514,

763

LHV

kJ/k

g7,

345

7,34

5HH

VkJ

/kg

9,24

79,

247

hkJ

/kg

-2,8

66.8

301

‐1,005

‐15,562

‐13,336

‐13,336

‐15,350

‐13,217

‐14,915

‐15,251

‐15,897

‐1,564

65-2

,774

.1‐12,964

‐15,807

‐12,964

‐15,319

‐13,188

‐14,848

‐13,188

‐618

sJ/

kgK

-1,0

82.9

01

‐8‐4

‐4‐8

‐3‐7

‐7‐9

00

-877

.6‐2

‐9‐2

‐8‐3

‐7‐3

‐9M

kg/k

mol

14.6

528

.84

26.8

818

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

18.0

026

.88

28.8

414

.65

18.0

018

.00

18.0

018

.00

18.0

018

.00

18.0

018

.00

Σm

ol %

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ol %

45.0

00.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

45.0

00.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

mol

%1.

960.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.96

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

2m

ol %

0.25

0.03

0.65

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.65

0.03

0.25

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

N2m

ol %

34.2

777.32

70.71

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

70.71

77.32

34.2

70.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Arm

ol %

0.71

0.91

0.91

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.91

0.91

0.71

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH4

mol

%0.

130.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.13

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

O2

mol

%0.

0720.74

10.25

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

10.25

20.74

0.07

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mol

%17

.61

1.01

17.48

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

17.48

1.01

17.6

1100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2S

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ol %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HCN

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mol

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Σm

ass

%10

0.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.

00100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2m

ass

%6.

190.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

6.19

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

mas

s %

3.75

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

3.75

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

2m

ass

%0.

740.05

1.06

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.06

0.05

0.74

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

N2m

ass

%65

.46

75.07

73.68

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

73.68

75.07

65.4

60.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Arm

ass

%1.

931.26

1.35

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

1.35

1.26

1.93

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH4

mas

s %

0.15

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.15

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

O2

mas

s %

0.14

23.00

12.19

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

12.19

23.00

0.14

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

H2O

mas

s %

21.6

30.63

11.71

100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

11.71

0.63

21.6

3100.00

100.00

100.00

100.00

100.00

100.00

100.00

100.00

H2S

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CO

Sm

ass

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CS2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

SO2

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

Sm

ass

%0.

000.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

HCN

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

NH3

mas

s %

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

CH3

OH

mas

s %

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.01

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00


/ GER)

Appendix

165

Appendix G1 – Process flow diagram of the elevated pressure ASU

Appendix

166

1

23

5

14

20

22

24

28

34

36

37

394246 47

48

53

55

4949

1

2

3

4

5

6

7

89

10

11

1213

14

15

16

17

18

19

20

21

29

22

23

2425

Boo

ster

2B

oost

er 3

Boo

ster

4

MA

C c

oole

r 1

MA

C c

oole

r 2

Mol

siev

e

Boo

stC

oole

r1

Boo

stC

oole

r2

Boo

stC

oole

r3

Boo

stC

oole

r4

Mai

nHE

x 1

Mai

nHE

x 2

26

27

32 3031

33

34

35

37 3839 40

41

4243

44

45

46

Mai

nHE

x 4

Mai

nHE

x 3

Mai

nHE

x 5

Mai

nHE

x 6

Mai

nHE

x 7

Turb

ine

1

Val

ve 1

Val

ve 2H

ighP

rCol

umn

Low

PrC

olum

n

Val

ve 3

Val

ve 4

Val

ve 5

Sub

coo

ler 3

28S

ub c

oole

r 2

Sub

coo

ler 1

LOX

pum

p

DG

AN

com

pr 1

DG

AN

com

pr 2

DG

AN

com

pr 3

DG

AN

coo

ler1

DG

AN

coo

ler2

70

65 66

47

49

MA

C 1

MA

C 3

Boo

ster

1

MA

C 2

54

71

DG

AN

coo

ler3

DG

AN

com

pr4

Eva

pCoo

ler

Hot

AirT

urb

8

67

48

60

50

51

52

53

61

62

DG

AN

com

pr 5

DG

AN

com

pr 6

DG

AN

coo

ler4

DG

AN

coo

ler5

55

DG

AN

unpu

re G

AN

36

5657

58

60

61

62

63

76

77

82

LP G

AN

64

GA

N c

ompr

1G

AN

com

pr 2

GA

N c

ompr

3G

AN

com

pr 4

HP

GA

N

6566

67

59

87

68

resi

dual

GA

N c

oole

r 1

GA

N c

oole

r 2

GA

N c

oole

r 3

GA

N c

oole

r 4

6970

100

8990

cw in

cw o

ut

59

ambi

ent a

ir

GT

extr

air

4

6

7

973

O2

PR

H 1

O2

PR

H 2

86

10

1112

13

50

18

19

21

23

25

26

15

27

29

1631

30

33

17

7832

83

79

80

81

84

4344

5874

7568

63

38

35

4564

40

4188

51

56

57

52

54

85

ID

1 T

15.

0 C

P 1

.01

bar

M 5

525

kmol

/h

ID

2 T

77.

8 C

P 1

.84

bar

M 5

525

kmol

/h

ID

3 T

30.

0 C

P 1

.78

bar

M 5

525

kmol

/h

ID

5 T

30.

0 C

P 3

.17

bar

M 5

525

kmol

/h ID

8

T 8

0.5

C P

5.7

6 ba

r M

112

29 k

mol

/h

ID

4 T

96.

0 C

P 3

.23

bar

M 5

525

kmol

/h

ID

6 T

96.

2 C

P 5

.76

bar

M 5

525

kmol

/h

ID

7 T

170

.0 C

P 1

6.00

bar

M 1

1229

km

ol/h

ID

9 T

85.

7 C

P 5

.76

bar

M 1

6755

km

ol/h

ID

73 T

76.

6 C

P 5

.70

bar

M 1

6755

km

ol/h

ID

86 T

30.

0 C

P 5

.64

bar

M 1

6755

km

ol/h

ID

11 T

30.

0 C

P 5

.64

bar

M 1

6755

km

ol/h

ID

12 T

19.

8 C

P 5

.44

bar

M 1

6755

km

ol/h

ID

13 T

19.

8 C

P 5

.44

bar

M 1

75 k

mol

/h

ID

10 T

30.

0 C

P 5

.64

bar

M 0

km

ol/h

ID

50 T

7.0

C P

1.1

5 ba

r M

252

5 km

ol/h

ID

14 T

19.

8 C

P 5

.44

bar

M 1

6580

km

ol/h

ID

20 T

30.

0 C

P 1

0.28

bar

M 6

946

kmol

/h

ID

22 T

30.

0 C

P 1

9.46

bar

M 6

946

kmol

/h

ID

24 T

30.

0 C

P 3

6.92

bar

M 6

946

kmol

/h

ID

18 T

19.

8 C

P 5

.44

bar

M 6

946

kmol

/h

ID

19 T

89.

2 C

P 1

0.34

bar

M 6

946

kmol

/h

ID

21 T

101

.9 C

P 1

9.52

bar

M 6

946

kmol

/h

ID

23 T

102

.0 C

P 3

6.98

bar

M 6

946

kmol

/h

ID

25 T

101

.9 C

P 7

0.00

bar

M 6

946

kmol

/h

ID

26 T

30.

0 C

P 6

9.94

bar

M 6

946

kmol

/h

ID

31 T

-178

.7 C

P 5

.12

bar

M 1

730

kmol

/h

ID

76 T

30.

0 C

P 1

8.48

bar

M 1

178

kmol

/h

ID

77 T

30.

0 C

P 3

5.42

bar

M 1

178

kmol

/h

ID

82 T

30.

0 C

P 9

.66

bar

M 1

178

kmol

/h

ID

32 T

30.

0 C

P 9

.66

bar

M 1

730

kmol

/h

ID

83 T

30.

0 C

P 9

.66

bar

M 5

52 k

mol

/h

ID

81 T

107

.1 C

P 7

0.06

bar

M 1

178

kmol

/h

ID

27 T

-161

.2 C

P 6

9.88

bar

M 6

946

kmol

/h

ID

28 T

-164

.3 C

P 1

4.00

bar

M 6

946

kmol

/h

ID

29 T

-164

.3 C

P 1

4.00

bar

M 4

168

kmol

/h ID

15

T 1

9.8

C P

5.4

4 ba

r M

963

4 km

ol/h

ID

16 T

-172

.5 C

P 5

.38

bar

M 9

634

kmol

/h

ID

30 T

-175

.9 C

P 5

.35

bar

M 4

168

kmol

/h

ID

17 T

-172

.5 C

P 5

.35

bar

M 9

634

kmol

/h

ID

75 T

101

.2 C

P 9

.59

bar

M 0

km

ol/h

ID

60 T

30.

0 C

P 5

.08

bar

M 8

995

kmol

/h

ID

61 T

30.

0 C

P 9

.53

bar

M 8

995

kmol

/h

ID

62 T

30.

0 C

P 1

7.96

bar

M 8

995

kmol

/h

ID

44 T

19.

6 C

P 5

.08

bar

M 0

km

ol/h

ID

58 T

101

.2 C

P 9

.59

bar

M 8

995

kmol

/h

ID

74 T

101

.2 C

P 9

.59

bar

M 8

995

kmol

/h

ID

43 T

-178

.6 C

P 5

.14

bar

M 0

km

ol/h

ID

33 T

19.

6 C

P 5

.06

bar

M 1

730

kmol

/h

ID

78 T

90.

2 C

P 9

.72

bar

M 1

730

kmol

/h

ID

79 T

103

.2 C

P 1

8.54

bar

M 1

178

kmol

/h

ID

80 T

103

.3 C

P 3

5.48

bar

M 1

178

kmol

/h

ID

84 T

70.

0 C

P 7

0.00

bar

M 1

178

kmol

/h

ID

36 T

-192

.0 C

P 1

.50

bar

M 4

118

kmol

/h

ID

39 T

-189

.0 C

P 1

.50

bar

M 7

953

kmol

/h

ID

42 T

-190

.3 C

P 1

.50

bar

M 2

778

kmol

/h

ID

37 T

-174

.6 C

P 5

.30

bar

M 7

953

kmol

/h

ID

65 T

-187

.4 C

P 1

.27

bar

M 4

37 k

mol

/h

ID

46 T

-187

.4 C

P 1

.25

bar

M 1

0909

km

ol/h

ID

66 T

-180

.2 C

P 1

.25

bar

M 4

37 k

mol

/h

ID

47 T

-180

.2 C

P 1

.23

bar

M 1

0909

km

ol/h

ID

34 T

-178

.5 C

P 5

.14

bar

M 4

118

kmol

/h

ID

48 T

-175

.8 C

P 1

.21

bar

M 1

0909

km

ol/h

ID

67 T

-175

.8 C

P 1

.23

bar

M 4

37 k

mol

/h

ID

68 T

101

.6 C

P 3

4.00

bar

M 8

995

kmol

/h

ID

63 T

101

.3 C

P 1

8.02

bar

M 8

995

kmol

/h

ID

87 T

19.

6 C

P 1

.15

bar

M 1

914

kmol

/h

ID

59 T

11.

3 C

P 1

.17

bar

M 4

37 k

mol

/h

ID

49 T

19.

6 C

P 1

.15

bar

M 1

0909

km

ol/h

ID

51 T

19.

6 C

P 1

.15

bar

M 8

995

kmol

/h

ID

53 T

30.

0 C

P 1

.87

bar

M 8

995

kmol

/h

ID

55 T

30.

0 C

P 3

.06

bar

M 8

995

kmol

/h

ID

57 T

30.

0 C

P 5

.08

bar

M 8

995

kmol

/h

ID

52 T

73.

9 C

P 1

.93

bar

M 8

995

kmol

/h

ID

38 T

-179

.9 C

P 5

.20

bar

M 7

953

kmol

/h

ID

35 T

-186

.7 C

P 5

.04

bar

M 4

118

kmol

/h

ID

45 T

-193

.4 C

P 1

.27

bar

M 1

0909

km

ol/h

ID

64 T

-191

.7 C

P 1

.29

bar

M 4

37 k

mol

/h

ID

40 T

-164

.3 C

P 1

4.00

bar

M 2

778

kmol

/h

ID

41 T

-172

.3 C

P 1

3.90

bar

M 2

778

kmol

/h ID

88

T 1

8.1

C P

1.1

5 ba

r M

235

1 km

ol/h

ID

56 T

87.

0 C

P 5

.14

bar

M 8

995

kmol

/h

ID

85 T

19.

6 C

P 5

0.06

bar

M 3

504

kmol

/h

ID

70 T

-178

.2 C

P 5

0.12

bar

M 3

504

kmol

/h

ID

69 T

-181

.3 C

P 1

.31

bar

M 3

504

kmol

/h

ID

54 T

86.

3 C

P 3

.12

bar

M 8

995

kmol

/h

69

ID 1

00 T

20.

0 C

P 6

.00

bar

W 4

6620

18 k

g/h

ID

90 T

30.

0 C

P 2

.50

bar

W 4

6620

18 k

g/h

71

7291

92 ID

92

T 6

0.0

C P

49.

96 b

ar M

57

kmol

/h

ID

91 T

60.

0 C

P 4

9.96

bar

M 3

448

kmol

/h

ID

72 T

60.

0 C

P 4

9.96

bar

M 3

504

kmol

/h

GO

X to

gas

ifier

GO

X to

SR

U

Appendix G2 – CHEMCAD model for a low pressure ASU

Appendix

167

1

23

5

14

20

22

24

28

34

36

37

394246 47

53

1

2

3

4

5

6

7

89

10

11

1213

14

15

16

17

18

19

20

21

29

22

23

2425

Boos

ter 2

Boos

ter 3

Boos

ter 4

MAC

coo

ler 1

MAC

coo

ler 2

Mol

siev

e

Boos

tCoo

ler1

Boos

tCoo

ler2

Boos

tCoo

ler3

Boos

tCoo

ler4

Mai

nHEx

1

Mai

nHEx

2

26

27

32 3031

33

34

35

37 3839 40

41

4243

44

45

46

Mai

nHEx

4

Mai

nHEx

3

Mai

nHEx

5

Mai

nHEx

6

Mai

nHEx

7

Turb

ine

1

Valv

e 1

Valv

e 2Hi

ghPr

Colu

mn

LowP

rCol

umn

Valv

e 3

Valv

e 4

Valv

e 5

Sub

cool

er 3

28Su

b co

oler

2

Sub

cool

er 1

LOX

pum

p

DGAN

com

pr 1

DGAN

com

pr 2

DGAN

com

pr 3

DGAN

coo

ler1

DGAN

coo

ler2

70

65 66

47

49

MAC

1M

AC 3

Boos

ter 1

MAC

2

5471

DGAN

coo

ler3

DGAN

com

pr4

Evap

Cool

er

HotA

irTur

b

8

48

55

unpu

re G

AN

36

5657

58

60

61

76

LP G

AN

64

GAN

com

pr 1

GAN

com

pr 2

GAN

com

pr 3

HP G

AN

6566

72GO

X

67 87

68

GAN

cool

er 1

GAN

cool

er 2

GAN

cool

er 4

6970

100

8990

cw in

cw o

ut

59

ambi

ent a

ir

GT e

xtr a

ir

4

7

973

O2 P

RH 1

O2 P

RH 2

86

10

1112

13

18

19

21

23

25

26

15

27

29

1631

30 17

78

83

79

84

4344

38

35

4564

41

56

52

85

69

71

726

MAC

coo

ler 3

MAC

4

7391

93

74

50

94

92

resi

dual

54

75

58

60

DGAN

82

32

33

80

50

51

61

52

95

62

63

74

67

518849

48

ResG

asEx

pd

62

7710

2

Mai

nHEx

8

68

59

ID

1 T

15.

0 C

P 1

.01

bar

M 5

340

kmol

/h

ID

2 T

81.

8 C

P 1

.90

bar

M 5

340

kmol

/h

ID

3 T

30.

0 C

P 1

.84

bar

M 5

340

kmol

/h

ID

5 T

30.

0 C

P 3

.41

bar

M 5

340

kmol

/h ID

8

T 1

42.2

C P

12.

00 b

ar M

112

29 k

mol

/h

ID

72 T

60.

0 C

P 4

9.96

bar

M 3

505

kmol

/h

ID

4 T

100

.2 C

P 3

.47

bar

M 5

340

kmol

/h

ID

7 T

170

.0 C

P 1

6.00

bar

M 1

1229

km

ol/h

ID

9 T

129

.0 C

P 1

2.00

bar

M 1

6552

km

ol/h

ID

73 T

120

.3 C

P 1

1.94

bar

M 1

6552

km

ol/h

ID

86 T

30.

0 C

P 1

1.88

bar

M 1

6552

km

ol/h

ID

11 T

30.

0 C

P 1

1.88

bar

M 1

6552

km

ol/h

ID

12 T

19.

8 C

P 1

1.68

bar

M 1

6552

km

ol/h

ID

13 T

19.

8 C

P 1

1.68

bar

M 1

55 k

mol

/h

ID

10 T

30.

0 C

P 1

1.88

bar

M 0

km

ol/h

ID

14 T

19.

8 C

P 1

1.68

bar

M 1

6397

km

ol/h

ID

20 T

30.

0 C

P 1

8.28

bar

M 3

303

kmol

/h

ID

22 T

30.

0 C

P 2

8.64

bar

M 3

303

kmol

/h

ID

24 T

30.

0 C

P 4

4.90

bar

M 3

303

kmol

/h

ID

18 T

19.

8 C

P 1

1.68

bar

M 3

303

kmol

/h

ID

19 T

67.

4 C

P 1

8.34

bar

M 3

303

kmol

/h

ID

21 T

79.

2 C

P 2

8.70

bar

M 3

303

kmol

/h

ID

23 T

79.

3 C

P 4

4.96

bar

M 3

303

kmol

/h

ID

25 T

78.

5 C

P 7

0.00

bar

M 3

303

kmol

/h

ID

26 T

30.

0 C

P 6

9.94

bar

M 3

303

kmol

/h

ID

31 T

-167

.4 C

P 1

1.32

bar

M 1

730

kmol

/h

ID

76 T

30.

0 C

P 3

7.97

bar

M 1

179

kmol

/h

ID

83 T

21.

5 C

P 1

1.27

bar

M 5

52 k

mol

/h

ID

27 T

-156

.0 C

P 6

9.88

bar

M 3

303

kmol

/h

ID

28 T

-159

.9 C

P 1

6.00

bar

M 3

303

kmol

/h

ID

29 T

-159

.9 C

P 1

6.00

bar

M 3

303

kmol

/h ID

15

T 1

9.8

C P

11.

68 b

ar M

130

94 k

mol

/h

ID

16 T

-162

.0 C

P 1

1.62

bar

M 1

3094

km

ol/h

ID

30 T

-164

.5 C

P 1

1.55

bar

M 3

303

kmol

/h

ID

17 T

-162

.1 C

P 1

1.55

bar

M 1

3094

km

ol/h

ID

44 T

21.

5 C

P 1

1.29

bar

M 0

km

ol/h

ID

43 T

-167

.2 C

P 1

1.35

bar

M 0

km

ol/h

ID

78 T

87.

6 C

P 2

0.73

bar

M 1

179

kmol

/h

ID

79 T

98.

1 C

P 3

8.03

bar

M 1

179

kmol

/h

ID

84 T

70.

0 C

P 7

0.00

bar

M 1

179

kmol

/h

ID

36 T

-182

.5 C

P 3

.70

bar

M 4

514

kmol

/h

ID

39 T

-179

.3 C

P 3

.70

bar

M 1

0153

km

ol/h

ID

42 T

-182

.6 C

P 3

.70

bar

M 3

123

kmol

/h

ID

37 T

-163

.0 C

P 1

1.55

bar

M 1

0153

km

ol/h

ID

65 T

-176

.0 C

P 3

.50

bar

M 1

178

kmol

/h

ID

46 T

-176

.0 C

P 3

.49

bar

M 1

3107

km

ol/h

ID

66 T

-168

.0 C

P 3

.48

bar

M 1

178

kmol

/h

ID

47 T

-168

.0 C

P 3

.47

bar

M 1

3107

km

ol/h

ID

34 T

-167

.1 C

P 1

1.35

bar

M 4

514

kmol

/h

ID

87 T

-166

.5 C

P 3

.45

bar

M 9

65 k

mol

/h

ID

53 T

30.

0 C

P 6

.04

bar

M 1

2142

km

ol/h

ID

52 T

84.

9 C

P 6

.10

bar

M 1

2142

km

ol/h

ID

38 T

-168

.3 C

P 1

1.45

bar

M 1

0153

km

ol/h

ID

35 T

-177

.6 C

P 1

1.25

bar

M 4

514

kmol

/h

ID

45 T

-183

.1 C

P 3

.51

bar

M 1

3107

km

ol/h

ID

64 T

-182

.6 C

P 3

.52

bar

M 1

178

kmol

/h

ID

41 T

-161

.0 C

P 1

8.67

bar

M 3

123

kmol

/h

ID

85 T

21.

5 C

P 5

0.06

bar

M 3

505

kmol

/h

ID

70 T

-166

.5 C

P 5

0.12

bar

M 3

505

kmol

/h

ID 1

00 T

20.

0 C

P 6

.00

bar

W 4

1436

29 k

g/h

ID

90 T

30.

0 C

P 2

.50

bar

W 4

1436

29 k

g/h

ID

93 T

30.

0 C

P 6

.35

bar

M 5

322

kmol

/h

ID

94 T

30.

0 C

P 6

.35

bar

M 1

8 km

ol/h

ID

50 T

10.

5 C

P 1

.40

bar

M 2

316

kmol

/h

ID

58 T

95.

3 C

P 1

0.88

bar

M 1

2142

km

ol/h

ID

56 T

92.

0 C

P 1

8.93

bar

M 1

2142

km

ol/h

ID

32 T

21.

5 C

P 1

1.27

bar

M 1

730

kmol

/h

ID

33 T

30.

0 C

P 2

0.67

bar

M 1

179

kmol

/h

ID

74 T

10.

3 C

P 1

.40

bar

M 2

298

kmol

/h

ID

63 T

-30.

1 C

P 1

.40

bar

M 0

km

ol/h

ID

62 T

23.

1 C

P 3

.39

bar

M 0

km

ol/h

ID

61 T

23.

1 C

P 3

.39

bar

M 2

143

kmol

/h

ID

49 T

-166

.5 C

P 3

.45

bar

M 1

3107

km

ol/h

ID

67 T

-166

.5 C

P 3

.46

bar

M 1

178

kmol

/h

ID

69 T

-169

.9 C

P 3

.55

bar

M 3

505

kmol

/h

ID

6 T

100

.3 C

P 6

.41

bar

M 5

340

kmol

/h

ID

91 T

30.

0 C

P 6

.35

bar

M 5

340

kmol

/h

ID

92 T

101

.1 C

P 1

2.00

bar

M 5

322

kmol

/h

ID

54 T

95.

3 C

P 1

0.88

bar

M 1

2142

km

ol/h

ID

75 T

95.

3 C

P 1

0.88

bar

M 0

km

ol/h

ID

60 T

30.

0 C

P 1

0.82

bar

M 1

2142

km

ol/h

ID

82 T

21.

5 C

P 1

1.27

bar

M 1

179

kmol

/h

ID

80 T

98.

6 C

P 7

0.06

bar

M 1

179

kmol

/h

ID

95 T

15.

7 C

P 3

.39

bar

M 2

298

kmol

/h

ID

51 T

-166

.5 C

P 3

.45

bar

M 1

2142

km

ol/h

ID

88 T

-166

.5 C

P 3

.45

bar

M 2

143

kmol

/h

ID

59 T

23.

1 C

P 3

.39

bar

M 2

143

kmol

/h

ID 1

02 T

-158

.7 C

P 1

8.77

bar

M 3

123

kmol

/h

ID

48 T

21.

5 C

P 3

.39

bar

M 1

2142

km

ol/h

ID

68 T

95.

6 C

P 3

4.00

bar

M 9

019

kmol

/h

ID

57 T

30.

0 C

P 1

8.87

bar

M 1

2142

km

ol/h

ID

55 T

30.

0 C

P 1

0.82

bar

M 1

2142

km

ol/h

ID

81 T

30.

0 C

P 1

8.87

bar

M 3

123

kmol

/h

57

81

40

55

Appendix G3 – CHEMCAD model for an elevated pressure ASU

Appendix

168

Appendix G4– Auxiliary load distribution for the ASU (effects of ASU integra

tion)

air‐int. KASU,air DGAN ‐int. KASU,DGAN KASU,HP GAN KASU,LP GAN PASU,spec. PMAC,spec. Pbooster,spec. PDGAN-compr.,spec. PGAN-compr.,spec. Phot air turbine,spec. Pres. Gas exp., spec. Presidual, spec.

LP‐ASU0 0.00 0.00 0.0 0.30 0.16 0.569 0.335 0.199 0.000 0.036 0.000 ‐0.0010 0.00 30.38 1.0 0.30 0.16 0.706 0.335 0.199 0.137 0.036 0.000 ‐0.0010 0.00 60.77 2.0 0.30 0.16 0.844 0.335 0.199 0.275 0.036 0.000 ‐0.0010 0.00 91.15 3.0 0.30 0.16 0.981 0.335 0.199 0.412 0.036 0.000 ‐0.001

25 1.19 0.00 0.0 0.30 0.16 0.447 0.251 0.199 0.000 0.036 ‐0.039 ‐0.00125 1.19 30.38 1.0 0.30 0.16 0.584 0.251 0.199 0.137 0.036 ‐0.039 ‐0.00125 1.19 60.77 2.0 0.30 0.16 0.721 0.251 0.199 0.275 0.036 ‐0.039 ‐0.00125 1.19 91.15 3.0 0.30 0.16 0.859 0.251 0.199 0.412 0.036 ‐0.039 ‐0.00150 2.38 0.00 0.0 0.30 0.16 0.324 0.167 0.199 0.000 0.036 ‐0.077 ‐0.00150 2.38 30.39 1.0 0.30 0.16 0.462 0.167 0.199 0.137 0.036 ‐0.077 ‐0.00150 2.38 60.77 2.0 0.30 0.16 0.599 0.167 0.199 0.275 0.036 ‐0.077 ‐0.00150 2.38 91.16 3.0 0.30 0.16 0.737 0.167 0.199 0.412 0.036 ‐0.077 ‐0.00175 3.56 0.00 0.0 0.30 0.16 0.202 0.084 0.199 0.000 0.036 ‐0.116 ‐0.00175 3.56 30.39 1.0 0.30 0.16 0.340 0.084 0.199 0.137 0.036 ‐0.116 ‐0.00175 3.56 60.77 2.0 0.30 0.16 0.477 0.084 0.199 0.275 0.036 ‐0.116 ‐0.00175 3.56 91.16 3.0 0.30 0.16 0.614 0.084 0.199 0.412 0.036 ‐0.116 ‐0.001

100 4.75 0.00 0.0 0.30 0.16 0.080 0.000 0.199 0.000 0.036 ‐0.154 ‐0.001100 4.75 30.39 1.0 0.30 0.16 0.217 0.000 0.199 0.137 0.036 ‐0.154 ‐0.001100 4.75 60.77 2.0 0.30 0.16 0.355 0.000 0.199 0.275 0.036 ‐0.154 ‐0.001100 4.75 91.16 3.0 0.30 0.16 0.492 0.000 0.199 0.412 0.036 ‐0.154 ‐0.001

EP‐ASU0 0.00 0.00 0.0 0.30 0.16 0.628 0.547 0.118 0.000 0.022 0.000 ‐0.058 0.0000 0.00 25.11 1.0 0.30 0.16 0.739 0.547 0.118 0.092 0.022 0.000 ‐0.040 0.0000 0.00 50.23 2.0 0.30 0.16 0.850 0.547 0.118 0.184 0.022 0.000 ‐0.021 0.0000 0.00 75.34 3.0 0.30 0.16 0.961 0.547 0.118 0.276 0.022 0.000 ‐0.002 0.000

25 1.36 0.00 0.0 0.30 0.16 0.478 0.410 0.118 0.000 0.022 ‐0.014 ‐0.058 0.00025 1.36 25.11 1.0 0.30 0.16 0.589 0.410 0.118 0.092 0.022 ‐0.014 ‐0.040 0.00025 1.36 50.23 2.0 0.30 0.16 0.699 0.410 0.118 0.184 0.022 ‐0.014 ‐0.021 0.00025 1.36 75.34 3.0 0.30 0.16 0.810 0.410 0.118 0.276 0.022 ‐0.014 ‐0.002 0.00050 2.72 0.00 0.0 0.30 0.16 0.327 0.273 0.118 0.000 0.022 ‐0.028 ‐0.058 0.00050 2.72 25.11 1.0 0.30 0.16 0.438 0.273 0.118 0.092 0.022 ‐0.028 ‐0.040 0.00050 2.72 50.23 2.0 0.30 0.16 0.549 0.273 0.118 0.184 0.022 ‐0.028 ‐0.021 0.00050 2.72 75.34 3.0 0.30 0.16 0.660 0.273 0.118 0.276 0.022 ‐0.028 ‐0.002 0.00075 4.08 0.00 0.0 0.30 0.16 0.177 0.137 0.118 0.000 0.022 ‐0.041 ‐0.058 0.00075 4.08 25.11 1.0 0.30 0.16 0.288 0.137 0.118 0.092 0.022 ‐0.041 ‐0.040 0.00075 4.08 50.23 2.0 0.30 0.16 0.398 0.137 0.118 0.184 0.022 ‐0.041 ‐0.021 0.00075 4.08 75.34 3.0 0.30 0.16 0.509 0.137 0.118 0.276 0.022 ‐0.041 ‐0.002 0.000

100 5.44 0.00 0.0 0.30 0.16 0.026 0.000 0.118 0.000 0.022 ‐0.055 ‐0.058 0.000100 5.44 25.11 1.0 0.30 0.16 0.137 0.000 0.118 0.092 0.022 ‐0.055 ‐0.040 0.000100 5.44 50.23 2.0 0.30 0.16 0.248 0.000 0.118 0.184 0.022 ‐0.055 ‐0.021 0.000100 5.44 75.34 3.0 0.30 0.16 0.359 0.000 0.118 0.276 0.022 ‐0.055 ‐0.002 0.000

[kWh/Sm³ GOX]

Appendix

169

Appendix G5 – Heat and material balance for the ASU (CCIGCC / SCGP)

stream ID 0-1-air-6 8-1-air-5 9-1-cw-11 1-0-eg-4 1-2-GOX-1 1-2-GAN-1 1-2-GAN-2 1-3-DGAN-1 1-5-GOX-2 1-9-cw-12name ambient air GT extraction air cooling water residual gas GOX HP GAN LP GAN DGAN GOX cooling watert °C 15.0 170.0 20.0 60.0 70.0 21.5 95.6 60.0 30.0p bar 1.013 16.000 6.000 49.960 70.000 11.265 34.000 49.960 2.500m kg/s 42.800 90.000 1,151 17.671 30.807 9.173 4.294 70.350 0.505 1,151n kmol/s 1.483 3.119 63.892 0.643 0.958 0.327 0.153 2.505 0.016 63.892V Nm³/h 119,693 251,691 51,908 77,281 26,415 12,365 202,148 1,268h kJ/kg ‐100 57 ‐15,898 20 35 ‐7 68 20 ‐15,856s J/kgK 124 ‐238 ‐9,113 ‐874 ‐1,143 ‐734 ‐815 ‐874 ‐8,974M kg/kmol 28.84 28.84 18.00 32.17 28.01 28.01 28.07 32.17 18.00



Appendix

170

Appendix G6 – Heat and material balance for the ASU (CCIGCC / Siemens gasifier)

stream ID 0-1-air-6 8-1-air-5 9-1-cw-11 1-0-eg-4 1-2-GOX-1 1-2-GAN-1 1-2-GAN-2 1-3-DGAN-1 1-5-GOX-2 1-9-cw-12name ambient air GT extraction air cooling water residual gas GOX HP GAN LP GAN DGAN GOX cooling watert °C 15.0 177.5 20.0 60.0 70.0 21.5 95.6 60.0 30.0p bar 1.013 16.87 6.000 49.960 70.000 11.265 34.000 49.960 2.500m kg/s 41.696 90.000 1,122 20.089 30.787 8.045 4.290 67.974 0.511 1,122n kmol/s 1.445 3.119 62.292 0.730 0.957 0.287 0.153 2.421 0.016 62.292V Nm³/h 116,605 251,691 58,886 77,223 23,166 12,355 195,384 1,282h kJ/kg -100 57 -15,898 22 35 -7 68 20 -15,856s J/kgK 124 -238 -9,113 -873 -1,144 -734 -818 -874 -8,974M kg/kmol 28.84 28.84 18.00 32.16 28.01 28.01 28.06 32.17 18.00



Appendix

171

Appendix G7 – Heat and material balance for the ASU (CCIGCC / CoP gasifier)

stream ID 0-1-air-6 8-1-air-5 9-1-cw-11 1-0-eg-4 1-2-GOX-1 1-2-GAN-1 1-2-GAN-2 1-3-DGAN-1 1-5-GOX-2 1-9-cw-12name ambient air GT extraction air cooling water residual gas GOX HP GAN LP GAN DGAN GOX cooling watert °C 15.0 170.0 20.0 60.0 70.0 21.5 95.6 60.0 30.0p bar 1.0 16.0 6.0 50.0 70.0 11.3 34.0 50.0 2.5m kg/s 37.761 90.000 948 39.752 29.351 0.567 0.000 57.577 0.514 948n kmol/s 1.309 3.119 52.635 1.427 0.912 0.020 0.000 2.053 0.016 52.635V Nm³/h 105,601 251,691 115,136 73,575 1,634 0 165,656 1,290h kJ/kg -100 57 -15,898 20 35 -7 68 20 -15,856s J/kgK 124 -238 -9,113 -874 -1,146 -736 -827 -874 -8,974M kg/kmol 28.84 28.84 18.00 32.19 28.00 28.00 28.03 32.19 18.00



Appendix

172

Appendix G8 – Heat and material balance for the ASU (CCIGCC / GER)

stream ID 0-1-air-6 8-1-air-5 9-1-cw-11 1-0-eg-4 1-2-GOX-1 1-3-DGAN-1 1-5-GOX-2 1-9-cw-12name ambient air GT extraction air cooling water residual gas GOX DGAN GOX cooling watert °C 15.0 170.0 20.0 60.0 95.6 60.0 30.0p bar 1.013 16.000 6.000 69.960 34.000 69.960 2.500m kg/s 70.861 90.000 1,222 62.473 38.229 59.600 0.551 1,222n kmol/s 2.456 3.119 67.853 2.246 1.187 2.125 0.017 67.853V Nm³/h 198,168 251,691 181,204 95,794 171,458 1,379h kJ/kg ‐100 57 ‐15,898 16 68 16 ‐15,856s J/kgK 124 ‐238 ‐9,113 ‐971 ‐827 ‐971 ‐8,974M kg/kmol 28.84 28.84 18.00 32.20 28.03 32.20 18.00

Σ mol % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CO mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CO2 mol % 0.03 0.03 0.00 0.08 0.00 0.00 0.00 0.00N2 mol % 77.32 77.32 0.00 96.84 1.64 99.58 1.64 0.00Ar mol % 0.91 0.91 0.00 0.24 3.36 0.22 3.36 0.00CH4 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00O2 mol % 20.74 20.74 0.00 0.33 95.00 0.20 95.00 0.00H2O mol % 1.01 1.01 100.00 2.50 0.00 0.00 0.00 100.00H2S mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00COS mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CS2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SO2 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCN mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NH3 mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CH3OH mol % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Σ mass % 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00H2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CO mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CO2 mass % 0.05 0.05 0.00 0.13 0.00 0.00 0.00 0.00N2 mass % 75.07 75.07 0.00 97.52 1.43 99.46 1.43 0.00Ar mass % 1.26 1.26 0.00 0.35 4.17 0.31 4.17 0.00CH4 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00O2 mass % 23.00 23.00 0.00 0.38 94.40 0.23 94.40 0.00H2O mass % 0.63 0.63 100.00 1.62 0.00 0.00 0.00 100.00H2S mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00COS mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CS2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00SO2 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00S mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00HCN mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NH3 mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00CH3OH mass % 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Appendix

173

1

2 31

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26

27

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ID

1 T

15.

0 C

P 1

.0 b

ar W

104

950

kg/h

ID

2 T

15.

0 C

P 1

.0 b

ar W

887

7 kg

/h

ID

3 T

15.

0 C

P 1

.0 b

ar W

662

5 kg

/h

ID

4 T

15.

0 C

P 1

.0 b

ar W

120

452

kg/h

ID 1

1 T

400

.4 C

P 1

.10

bar

W 4

8029

kg/

h M

190

3 km

ol/h

ID

8 T

101

9.5

C P

9.6

6 ba

r W

160

56 k

g/h

M 5

89 k

mol

/h

ID

5 T

15.

0 C

P 1

.00

bar

W 1

3763

kg/

h M

477

km

ol/h

ID

6 T

10.

0 C

P 3

3.38

bar

W 4

27 k

g/h

M 8

5 km

ol/h

ID

9 T

30.

0 C

P 9

.66

bar

W 1

4933

kg/

h M

533

km

ol/h

ID 3

3 T

30.

0 C

P 9

.66

bar

W 1

866

kg/h

M 6

7 km

ol/h

ID 2

8 T

75.

1 C

P 1

.10

bar

W 5

4716

kg/

h M

206

6 km

ol/h

ID 3

7 T

43.

3 C

P 4

8.0

bar

W 1

2354

9 kg

/h

ID 1

4 T

107

.0 C

P 1

.10

bar

W 3

1973

kg/

h M

131

4 km

ol/h

ID 3

4 T

60.

0 C

P 5

0.00

bar

W 1

0714

1 kg

/h M

333

1 km

ol/h

ID 4

1 T

412

.6 C

P 5

1.00

bar

W 1

9440

kg/

h M

107

9 km

ol/h

ID 3

1 T

43.

3 C

P 4

8.0

bar

W 1

2354

9 kg

/h

ID 3

6 T

200

.0 C

P 4

9.00

bar

W 1

0714

1 kg

/h M

333

1 km

ol/h

ID 4

6 T

424

.7 C

P 3

9.75

bar

W 5

6611

0 kg

/h M

278

48 k

mol

/h

ID 6

3 T

153

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1.00

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W 2

4193

0 kg

/h ID

65

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53.4

C P

51.

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ar W

603

47 k

g/h

ID 6

4 T

153

.4 C

P 5

1.00

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W 1

8158

3 kg

/h

ID 5

1 T

153

.4 C

P 5

1.00

bar

W 6

0347

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h

ID 3

8 T

265

.2 C

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1.00

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W 6

0347

kg/

h

ID 5

2 T

100

.0 C

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0.00

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W 6

144

kg/h

ID 4

5 T

336

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0 ba

r W

181

583

kg/h

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265

.2 C

P 5

1.00

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W 6

144

kg/h ID

42

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449.

9 C

P 4

0.00

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W 2

5012

7 kg

/h M

120

49 k

mol

/h

ID 5

4 T

156

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43.0

0 ba

r W

181

583

kg/h

ID 6

1 T

265

.2 C

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1.00

bar

W 6

144

kg/h

ID 5

8 T

274

.2 C

P 3

9.50

bar

W 3

2508

3 kg

/h M

159

66 k

mol

/h

ID 6

8 T

274

.2 C

P 3

9.50

bar

W 5

7001

1 kg

/h M

279

87 k

mol

/h

ID 7

1 T

15.

0 C

P 4

0.00

bar

W 9

100

kg/h

ID 4

4 T

274

.2 C

P 3

9.50

bar

W 6

90 k

g/h

ID 6

9 T

15.

0 C

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9.50

bar

W 6

90 k

g/h

ID 7

0 T

49.

9 C

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.10

bar

W 1

1625

1 kg

/h

ID 6

7 T

70.

0 C

P 7

0.00

bar

W 3

902

kg/h

M 1

39 k

mol

/h

ID 5

6 T

274

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P 3

9.50

bar

W 2

4423

9 kg

/h M

119

95 k

mol

/h

ID 8

1 T

109

.8 C

P 4

5.00

bar

W 1

2325

9 kg

/h M

683

5 km

ol/h

ID 7

3 T

138

.2 C

P 3

9.00

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W 2

5822

2 kg

/h M

127

77 k

mol

/h

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9 T

15.

0 C

P 5

0.00

bar

W 3

6000

kg/

h M

199

8 km

ol/h

ID 7

7 T

149

.3 C

P 3

9.00

bar

W 2

2016

kg/

h M

121

6 km

ol/h

ID 7

4 T

147

.8 C

P 3

9.00

bar

W 1

0907

4 kg

/h M

604

6 km

ol/h

ID 7

8 T

147

.8 C

P 3

9.00

bar

W 8

7259

kg/

h M

483

7 km

ol/h

ID 5

7 T

825

.0 C

P 4

0.00

bar

W 5

6611

0 kg

/h M

278

48 k

mol

/h

ID 5

3 T

153

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P 5

1.00

bar

W 1

8158

3 kg

/h ID

62

T 1

54.8

C P

52.

60 b

ar W

235

786

kg/h

ID 6

0 T

264

.7 C

P 5

0.60

bar

W 5

4203

kg/

h

ID 6

6 T

100

.0 C

P 5

1.00

bar

W 6

144

kg/h

ID 5

0 T

275

.2 C

P 3

9.50

bar

W 5

6611

0 kg

/h M

278

48 k

mol

/h

ID 2

0 T

70.

0 C

P 7

0.00

bar

W 3

1901

kg/

h M

113

9 km

ol/h

ID 1

8 T

50.

0 C

P 1

.1 b

ar W

115

561

kg/h

ID 5

9 T

319

.7 C

P 5

0.00

bar

W 3

2508

3 kg

/h M

159

66 k

mol

/h

ID 5

5 T

274

.2 C

P 3

9.50

bar

W 5

6932

2 kg

/h M

279

61 k

mol

/h

ID 8

2 T

154

.8 C

P 5

2.60

bar

W 3

3688

kg/

h

ID 8

4 T

264

.7 C

P 5

0.60

bar

W 3

3688

kg/

h

63

6210

3

64

104

60

65

45

105

66

82

106

67

84 107

Appendix H1 – ChemCadmodel for the onereactor COshift cycle

Appendix

174

Appendix I1 – OPCcalculation for the CCIGGC concepts with different

gasifiers

The OPC for the CC‐IGCC concept with Siemens gasifier (see Table 20) were used

as the basis.

First, the OPC assigned to the main sub‐systems were converted into specific costs

by consideration of the subsequently presented simulation results:

so that the following specific costs were derived:

These specific costs were defined as the. Literature sources were used to estimate

the investment costs necessary for the gas generation system of the three other CC‐

IGCC configurations. Therefore, the following information were used:

- For the gas generation part, a 35 % higher investment cost (per ton of coal ca‐

pacity) is expected if the SCGP with convective syngas cooler is used instead of

the same gasifier with water quench (like the Siemens‐type) [21]. Consequently,

the specific investment cost for the gas generation part of the CC‐IGCC with

SCGP adds up to 405 €/kW (coal) ‐> 301 €/kW (coal) times 1.35

- For the gas generation part, a 23 % lower investment cost (per ton of coal ca‐

pacity) is expected if a GE‐R is used instead of the SCGP [47]. Consequently, the

specific investment cost for the gas generation part of the CC‐IGCC with GE‐R

adds up to 312 €/kW (coal) ‐> 405 €/kW (coal) times 0.77

- For the gas generation part a 21 % lower investment cost (per ton of coal capac‐

ity) is expected if a CoP gasifier is used instead of the SCGP [47]. Consequently,

sub-system parameter unit valueGas generation Coal heat input (LHV based) MW 1,038Gas treatment Raw gas flow to 1st CO-shift reactor Sm³/h 581,469CO2-compressor Captured CO2 t/h 308Combined Cycle Gross power output MW 461ASU GOX demand Sm³/h 77,000

Selected simulation results: CC-IGCC (Siemens gasifier)

sub-system unit specific investment costsGas generation € / kW (coal) 301Gas treatment € / (Sm³ (raw gas) / h) 247CO2-compressor Mio € / (t (CO2) / h) 0.10Combined Cycle € / kW (gross) 785ASU € / (Sm³ (GOX) / h) 1,135

Specific investment costs: CC-IGCC (Siemens gasifier)

Appendix

175

the specific investment cost for the gas generation part of the CC‐IGCC with CoP

gasifier adds up to 320 €/kW (coal) ‐> 405 €/kW (coal) times 0.79

The following table summarizes the in this way estimated investment costs for the

four different gasifier types.

The investment costs for the other sub‐systems were estimated using the individu‐

al simulation results and the above derived specific investment costs.

The absolute investment costs for the gas treatment part were estimated as fol‐

lows:

The absolute investment costs for the CO2‐compressor were estimated as follows:

The absolute investment costs for the combined cycle were estimated as follows:

Gasifier type specific investment cost Coal heat input absolute investment cost- € / kW (coal) MW Mio €CoP 320 1,049 335GE-R 312 1,129 352SCGP 405 1,035 419Siemens 301 1,038 312

Investment costs for the gas geneartion part

Gasifier type specific investment costRaw gas flow to 1st

CO-shift reactor absolute investment cost- € / (Sm³ (raw gas) / h) Sm³ (raw gas) / h Mio €CoP 247 555,701 137GE-R 247 586,233 145SCGP 247 584,154 144Siemens 247 581,469 144

Investment costs for the gas treatment part

Gasifier type specific investment cost Captured CO2 absolute investment cost- Mio € / (t (CO2) / h) t (CO2) / h Mio €CoP 0.1 296 30GE-R 0.1 335 34SCGP 0.1 307 31Siemens 0.1 308 31

Investment costs for the CO2-compressor

Appendix

176

The absolute investment costs for the ASU were estimated as follows:

The direct investment costs are the sum of the investment costs for the five afore‐

mentioned mayor sub‐systems. The costs for:

- Infrastructure and utilities,

- Main spare parts and architect engineer,

- And miscellaneous

are so adjusted that they fit to the OPC‐fraction as defined in Table 21.

Gasifier type specific investment cost Gross power output absolute investment cost- € / kW (gross) MW Mio €CoP 785 467 367GE-R 785 496 389SCGP 785 469 368Siemens 785 461 362

Investment costs for the Combined Cycle

Gasifier type specific investment cost GOX demand absolute investment cost- € / (Sm³ (GOX) / h) Sm³ (GOX) / h Mio €CoP 1,135 74,000 84GE-R 1,135 96,000 109SCGP 1,135 77,000 87Siemens 1,135 77,000 87

Investment costs for the ASU

Appendix

177

Appendix I2 – Payment dates and shares for the Capital Expenditures

The individual Net Present Value is calculated according to:

NPV

.

The OPC are taken from Table 21; the interest rate is shown in Table 22. The pay‐

ment shares and dates are the same as used by Gräbner et al. [21]. The following

table summarizes the calculated NPV for the four CC‐IGCC concepts with different

gasifiers.

Date Share Net present value (NPV) in Mio €

CoP GER SCGP Siemens

Year 0 5 % 64 69 70 62

Year 1 30 % 280 305 308 275

Year 2 40 % 616 672 677 605

Year 3 20 % 508 554 559 499

Year 4 5 % 93 102 102 91

Σ NPVCapEx 1,560 1,703 1,716 1,532

Appendix I3 – Calculating the cost of electricity

The annual CapEx are calculated according to:

CapEx Σ NPVC E .

The annuity is calculated according to:

annuity

.

The annual Operational Expenditures (OpEx) are calculated considering the data

provided in Table 22 according to:

annual OpEx absolute costs .

Appendix

178

The following table summarizes the so calculated annual expenditures.

Cost Unit CoP GER SCGP Siemens

CapEx Mio €/a

172 188 189 169

Fuel Mio €/a

72 77 71 71

Miscellaneous Mio €/a

7 8 7 7

CO2‐transport Mio €/a

17 20 18 18

CO2‐emission Mio €/a

9 5 5 5

Labor Mio €/a

4 4 4 4

maintenance Mio €/a

12 13 13 11

Taxes/insurances Mio €/a

6 6 6 6

OpEx Mio €/a

126 133 124 122

Annual Expenditures Mio €/a

289 315 308 286

Finally the Cost of Electricity (CoE) is calculated according to:

CoE annual expenditures

Net power output x annual operating hours

Appendix

179

Appendix I4 – OPCcalculation for the CCIGGC concepts with different CRRs

The OPC for the concepts with different CRRs in comparison to the reference case

(CC‐IGCC with Siemens gasifier) are shown in the following table.

Investment cost for

Unit Reference

Case 2 Case 3 Case 4 Case 5

Gas generation Mio € 312 312 314 313 315

Gas treatment Mio € 144 144 144 140 140

CO2‐compressor Mio € 31 20 20 27 20

Combined Cycle Mio € 362 362 366 362 364

ASU Mio € 87 87 88 88 88

Direct invest‐ment costs

Mio € 936 925 932 929 927

Infrastructure and utilities

Mio € % of OPC

162 13

160 13

162 13

161 13

160 13

Main spare parts and AE

Mio € % of OPC

37 3

37 3

37 3

37 3

37 3

Miscellaneous Mio € % of OPC

112 9

111 9

112 9

112 9

111 9

Overall project costs (OPC)

Mio € €/kW(net)

1,249 3,450

1,234 3,450

1,243 3,450

1,239 3,450

1,235 3,450

The absolute costs for the gas generation part differ only since there is a slight dif‐

ference with respect to the coal flow rate between the concepts. The specific costs

are identical (301 € / kW (coal)).

Case 4 and case 5 show slightly lower costs for the gas treatment part. This is

caused by the saved investment costs for the second CO‐shift reactor. The differ‐

ence between a 2‐reactor CO‐shift and a 1‐reactor CO‐shift is amounted by

NETL (2007) [46] to 2.6 %.

The absolute costs for the CO2‐compressor differ as a consequence of the different

amount of captured CO2. The specific costs 0.1 Mio € / (t (CO2) / h) are identic.

Appendix

180

The specific costs for other cost factors are identic between the concepts – they are

shown in Appendix I1.

Appendix I5 Reference costs for a state of the art NG CCPP

Project Cost Summary Reference Cost Estimated Cost

Power Plant:

I Specialized Equipment 109.719.000 126.177.000 EUR II Other Equipment 7.286.000 8.379.000 EUR III Civil 15.301.000 22.019.000 EUR IV Mechanical 16.788.000 25.450.000 EUR V Electrical Assembly & Wiring 3.240.000 4.904.000 EUR VI Buildings & Structures 5.924.000 8.605.000 EUR VII Engineering & Plant Startup 11.062.000 11.138.000 EUR

Gasification Plant NA NA

Desalination Plant NA NA

CO2 Capture Plant NA NA

Subtotal -Contractor's Internal Cost 169.320.000 206.672.000 EUR VIII Contractor's Soft & Miscellaneous Costs 35.690.000 47.795.000 EUR Contractor's Price 205.010.000 254.467.000 EUR IX Owner's Soft & Miscellaneous Costs 18.451.000 22.902.000 EUR Total -Owner's Cost (0,7 EUR per US Dollar) 223.461.000 277.369.000 EUR

Nameplate Net Plant Output 405 405 MW Cost per kW -Contractor's 505,7 627,7 EUR per kW Cost per kW -Owner's 551,2 684,2 EUR per kW * Cost estimates as of February 2012.** Land cost, utility connection cost, and spare parts costs are zero. The user may want to edit those inputs for better cost estimates.

Appendix

181

1

2

34

5

1

2

3

4 6 7

8

8

10

12

reac

tor 1

reac

tor 2

12

HE

2

HE

1

9

16

17

18

21

19 HE

4

11

20

23

13

25

20

22

24

27

2341

25

26 HE

5

HE

6

29

44

HE

7

28

31

33

38

37

HE

9

27

2846

22

18

19

47

45

48

raw

gas

mod

erat

or s

team

satu

rate

d ga

shift

ed g

as

cond

. dis

char

ge

2930

4951

50cw

out

cw in

mak

e up

H2O32

76

77

78

79

80

98

9910

0

117

116 24

clea

n ga

s

DG

AN

115

34

15

96

35

26

39

42

10

30

9

16

17

7273

satu

rate

d ga

ID

1 T

214

.5 C

P 3

9.0

bar

W 4

7681

4 kg

/h M

250

05 k

mol

/h

ID

2 T

264

.7 C

P 5

0.6

bar

W 0

kg/

h M

0 k

mol

/h

ID

3 T

214

.5 C

P 3

9.0

bar

W 4

7681

4 kg

/h M

250

05 k

mol

/h

ID

4 T

280

.0 C

P 3

8.9

bar

W 4

7681

4 kg

/h M

250

05 k

mol

/h

ID

6 T

492

.9 C

P 3

7.8

bar

W 4

7681

9 kg

/h M

250

05 k

mol

/h

ID

8 T

280

.1 C

P 3

7.5

bar

W 4

7681

9 kg

/h M

250

05 k

mol

/h

ID

12 T

264

.3 C

P 5

4.5

bar

W 5

9412

kg/

h M

329

8 km

ol/h

ID

15 T

264

.3 C

P 5

4.5

bar

W 5

9412

kg/

h M

329

8 km

ol/h

ID

9 T

321

.8 C

P 3

6.4

bar

W 4

7681

9 kg

/h M

250

05 k

mol

/h

ID

23 T

114

.3 C

P 3

5.8

bar

W 4

4742

6 kg

/h M

233

73 k

mol

/h

ID

20 T

171

.8 C

P 3

5.9

bar

W 4

4742

6 kg

/h M

233

73 k

mol

/h

ID

21 T

171

.8 C

P 3

5.9

bar

W 2

7024

kg/

h M

150

0 km

ol/h

ID

27 T

114

.3 C

P 3

5.8

bar

W 3

6547

3 kg

/h M

188

25 k

mol

/h

ID

31 T

81.

9 C

P 3

5.7

bar

W 3

6547

3 kg

/h M

188

25 k

mol

/h

ID

33 T

81.

9 C

P 3

5.7

bar

W 1

1252

kg/

h M

625

km

ol/h

ID

29 T

112

.3 C

P 3

3.7

bar

W 2

4963

3 kg

/h M

138

56 k

mol

/h

ID

44 T

171

.8 C

P 3

5.9

bar

W 4

7445

0 kg

/h M

248

73 k

mol

/h

ID

28 T

114

.3 C

P 3

5.8

bar

W 8

1953

kg/

h M

454

9 km

ol/h

ID

38 T

99.

5 C

P 3

3.7

bar

W 1

4065

5 kg

/h M

780

8 km

ol/h

ID

37 T

20.

4 C

P 3

5.7

bar

W 1

4065

5 kg

/h M

780

8 km

ol/h

ID

41 T

30.

0 C

P 3

5.5

bar

W 3

4966

1 kg

/h M

179

48 k

mol

/h

ID

43 T

30.

0 C

P 3

5.5

bar

W 3

5422

0 kg

/h M

182

00 k

mol

/h

ID

48 T

169

.1 C

P 3

1.7

bar

W 2

5200

2 kg

/h M

139

88 k

mol

/h

ID

46 T

179

.8 C

P 3

6.0

bar

W 2

369

kg/h

M 1

32 k

mol

/h

ID

45 T

169

.0 C

P 3

1.7

bar

W 2

4963

3 kg

/h M

138

56 k

mol

/h

ID

47 T

179

.8 C

P 3

6.0

bar

W 4

7445

0 kg

/h M

248

73 k

mol

/h

ID

42 T

30.

0 C

P 3

5.5

bar

W 4

559

kg/h

M 2

53 k

mol

/h

ID

22 T

169

.0 C

P 1

6.0

bar

W 5

9412

kg/

h M

329

8 km

ol/h

ID

18 T

170

.3 C

P 5

6.5

bar

W 5

9412

kg/

h M

329

8 km

ol/h

ID

19 T

179

.8 C

P 3

6.0

bar

W 4

7681

9 kg

/h M

250

05 k

mol

/h

ID

51 T

30.

0 C

P 4

.0 b

ar W

105

3057

kg/

h M

584

54 k

mol

/h

ID

49 T

20.

0 C

P 6

.0 b

ar W

105

3057

kg/

h M

584

54 k

mol

/h

ID

98 T

110

.5 C

P 3

2.4

bar

W 8

3387

8 kg

/h M

462

90 k

mol

/h

ID

99 T

10.

0 C

P 5

.0 b

ar W

617

08 k

g/h

M 3

425

kmol

/h

ID 1

00 T

11.

0 C

P 3

8.0

bar

W 6

1708

kg/

h M

342

5 km

ol/h

ID 1

17 T

46.

1 C

P 3

3.0

bar

W 2

6978

4 kg

/h M

188

40 k

mol

/h

ID 1

16 T

95.

6 C

P 3

4.0

bar

W 2

1755

5 kg

/h M

775

0 km

ol/h

ID

97 T

162

.3 C

P 3

6.0

bar

W 8

9557

0 kg

/h M

497

15 k

mol

/h

ID

24 T

10.

0 C

P 3

3.0

bar

W 5

2228

kg/

h M

110

90 k

mol

/h

ID 1

15 T

103

.9 C

P 3

8.0

bar

W 8

9558

6 kg

/h M

497

16 k

mol

/h

ID

35 T

103

.7 C

P 3

2.4

bar

W 8

9558

6 kg

/h M

497

16 k

mol

/h

ID

34 T

103

.9 C

P 3

8.0

bar

W 8

9557

0 kg

/h M

497

15 k

mol

/h

ID

11 T

157

.1 C

P 1

8.0

bar

W 5

9412

kg/

h M

329

8 km

ol/h

ID

32 T

81.

9 C

P 3

5.7

bar

W 3

5422

0 kg

/h M

182

00 k

mol

/h

ID

26 T

151

.8 C

P 3

2.4

bar

W 3

3147

5 kg

/h M

222

65 k

mol

/h

ID

16 T

200

.0 C

P 4

8.0

bar

W 2

5200

2 kg

/h

ID

73 T

200

.0 C

P 3

2.3

bar

W 3

3147

6 kg

/h

ID

72 T

151

.8 C

P 3

2.4

bar

W 3

3147

6 kg

/h

ID

17 T

180

.7 C

P 3

6.2

bar

W 4

7681

9 kg

/h

ID

39 T

15.

0 C

P 5

0.0

bar

W 1

2940

3 kg

/h M

718

3 km

ol/h

ID

14 T

468

.3 C

P 4

9.1

bar

W 6

6361

kg/

h M

368

4 km

ol/h

ID

10 T

250

.3 C

P 3

6.3

bar

W 4

7681

9 kg

/h M

250

05 k

mol

/h

ID

30 T

169

.7 C

P 5

0.0

bar

W 2

5200

2 kg

/h M

139

88 k

mol

/h

qu w

ater

GT

fuel

43

97

46

49

from

gas

ifier

from

gas

ifie

ID

83 T

264

.7 C

P 5

0.6

bar

W 2

6361

kg/

h

5

6 715

13

14

83

71

90

50

80

to g

asifi

er

ID

7 T

308

.7 C

P 3

7.6

bar

W 4

7681

9 kg

/h M

250

05 k

mol

/h

ID

80 T

468

.5 C

P 4

9.6

bar

W 8

5773

kg/

h

ID

75 T

468

.5 C

P 4

9.6

bar

W 1

9116

kg/

h

87

ID

76 T

468

.5 C

P 4

9.6

bar

W 2

96 k

g/hto S

RU

/TG

T

7675

44

74

77

78

to A

GR

84

45

79

81

from

SR

U/T

GT

ID

78 T

202

.1 C

P 6

.1 b

ar W

332

35 k

g/h

ID

81 T

193

.0 C

P 6

.1 b

ar W

425

33 k

g/h

ID

79 T

164

.0 C

P 6

.6 b

ar W

203

06 k

g/h

ID

82 T

182

.8 C

P 6

.1 b

ar W

628

40 k

g/h

ID

77 T

202

.1 C

P 6

.1 b

ar W

331

27 k

g/h

ID

84 T

163

.4 C

P 6

.6 b

ar W

929

9 kg

/h

47

48

51

52

53

8291

92

54

85

43

42

93

ID

91 T

182

.8 C

P 6

.1 b

ar W

457

40 k

g/h

ID

89 T

156

.8 C

P 6

.0 b

ar W

115

378

kg/h ID

92

T 1

82.8

C P

6.1

bar

W 1

7099

kg/

h

ID

93 T

32.

3 C

P 0

.050

bar

W 4

5740

kg/

h88

55

56

57

9410

2

5810

1

104

103

ID 1

03 T

157

.0 C

P 1

4.0

bar

W 2

0306

kg/

h

ID 1

04 T

157

.0 C

P 1

4.0

bar

W 9

299

kg/h

ID 1

02 T

158

.0 C

P 5

2.0

bar

W 2

6361

kg/

h

to S

RU

/TG

T

to g

asifi

er

to g

asifi

er

59

6086

108

107

109

ID 1

09 T

246

.0 C

P 3

8.0

bar

W 2

96 k

g/h

ID 1

07 T

150

.8 C

P 6

.0 b

ar W

331

27 k

g/h

from

SR

U/T

GT

from

AG

R

106

110

mak

e up

ID 1

10 T

10.

0 C

P 6

.0 b

ar W

191

16 k

g/h

11

89

95

6110

5

111

ID 1

11 T

157

.1 C

P 1

8.0

bar

W 5

9412

kg/

h

ID 1

08 T

69.

0 C

P 6

.0 b

ar W

982

79 k

g/h

Appendix I6 – CHEMCAD flow sheet for the CO‐shift for a GCC concept with Sie‐

mens gasifier

References

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