CO2 ABATEMENT IN GAS-TO-LIQUIDS PLANT: FISCHER-TROPSCH SYNTHESIS

CO2 ABATEMENT IN GAS-TO-LIQUIDS PLANT: FISCHER-TROPSCH SYNTHESIS Report Number PH3/15 November 2000 This document has been prepared for the Executive Committee of the Programme. It is not a publication of the Operating Agent, International Energy Agency or its Secretariat.

Title: CO 2 abatement in Gas-to-Liquids plant: Fischer-Tropsch synthesis Reference number: PH3/15 Date issued: November 2000 Other remarks: Background This report contains a techno-economic evaluation of the conversion of natural gas to liquid transport fuels using Fischer-Tropsch (F-T) technology. The aim of the study was to assess the impact of CO 2 abatement technology on the costs and emissions associated with producing a F-T transport fuel. The results will be used in future work by IEA GHG to assess full cycle, i.e. well-to-wheels, emissions of greenhouse gases from road-transport systems. The overall aim of this work by IEA GHG is to assess the potential benefits of CO 2 abatement in energy systems based on the use of synthesised liquid products as road-transport fuels. This study is based on natural gas; future work will examine transport fuels derived from other feedstocks. There is a growth of interest in the use of natural gas to supply fuel to the transport sector. The two main reasons behind this : (a) the availability of natural gas resources, especially in remote places, where it may not be feasible to pipe the gas to market. (b) the need to reduce emissions from vehicles. An option seen by many as important is the production of gas-to-liquids (GTL) fuels. They are seen as potentially an attractive alternative to delivery of natural gas by long-distance pipelines or transportation in ships as liquefied natural gas (LNG). This study assesses F-T synthesis, the principal product of which is a high-quality clean liquid fuel that has the potential to meet both the above needs. Other GTL products which have been suggested include methanol and dimethly ether. The Fischer-Tropsch process In the F-T reaction, synthesis gas (CO and H 2 ) reacts over a catalyst to produce a mixture of straightchain hydrocarbons that can be treated to produce transport fuels. The technology has been in existence for many years but has only found limited commercial application. Historically, the focus of attention has been on the use of F-T as a method of producing transport fuels from coal. The Sasol plants in South Africa are perhaps the best known example of the technology in commercial use. More recently, F-T technology developed by Sasol was licensed to Mossgas for the conversion of natural gas to liquid fuels at a plant in South Africa. The 12 500 bbl/day Shell MDS (middle distillate synthesis) plant in Bintulu, Malaysia is a further example of F-T technology being used to convert natural gas into other products. Compared to the use of conventional (gasoline and diesel) fuels derived from petroleum, the use of F- T synthesis fuels, derived from natural gas, potentially offers a significant reduction in the emission of greenhouse gases, because: (a) The raw material is less carbon-intensive (F-T fuel is approximately CH 2 compared with petroleum, which approximates to a chemical formula of CH 1.3 ) i

(b) F-T derived fuel is reported to be very clean; diesel engines are intrinsically more efficient than the spark-ignition engines required for a gasoline fuel 1. (c) CO 2 is produced during processing; the majority of this CO 2 could be captured and stored, or used in enhanced oil recovery (EOR). Approach adopted A comparison of three F-T synthesis processes, each including appropriate synthesis gas production technology, was undertaken. The objective was to establish the range of likely results for the use of such technology; it is not aimed at identification of a preferred F-T technology. For each process, a base-case without CO 2 capture is compared with an alternative design incorporating CO 2 abatement. The overall objective is to obtain emissions and cost data that IEA GHG can subsequently use to calibrate the costs and benefits of technical options aimed at emission abatement in road transport. For the purposes of the study a medium-sized GTL facility was assumed to be located near a local source of low-priced natural gas. The site was assumed to be in Saudi Arabia and the product to be aimed at the North European market. The plants are largely self-contained in terms of their energy requirements, but import and export of small quantities of electricity was allowed. Results and discussion Three F-T technologies are evaluated (each with and without CO 2 abatement) to establish the extent to which conclusions are dependent on a specific technology. The technologies assessed are: (a) A slurry phase distillate (SPD) process, which is a low-temperature F-T process using a churn-turbulent bubble column reactor. The catalyst is carried in a process-derived liquid. Oxygen is used to produce the synthesis gas (syngas). Sasol-type technology is an example of this process. (b) A process in which F-T synthesis takes place in fixed-bed tubular reactors. Oxygen is used to produce the syngas. The Shell MDS process is an example of this processing route. (c) A process in which the syngas is produced using air rather than oxygen. It is claimed this processing route is a lower-cost method of converting natural gas to liquid transport fuels. The recently proposed Syntroleum process is an example of this type of process. The process is illustrated in figure 1. A molar ratio of approximately 2H 2 :1CO is required in the feed to the F-T synthesis reactor. With a natural gas feed this is achieved using various combinations of reactor type and recycle of carbon-rich syngas. Partial oxidation technologies are preferred to steam reforming because they produce a CO-rich syngas with relatively little CO 2. 1 These aspects will be dealt with in the next phase of work. As a preliminary indication, it is claimed by Sasol (Couvaras G Ventures based on Sasol s Slurry Phase Distillate Process: Status and Potential Environmental Benefits ) that a diesel engine is 44% percent efficient compared to 24% for an equivalent gasoline engine; also the fuel has aromatics content of less than 3% and the sulphur content less than 1ppm which surpasses the diesel quality proposed for Europe in 2005; in addition, a marked reduction in particulate emissions and NO x production is achieved because of the high cetane number (>70) and the low density. ii

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Syngas recycle Purge gas to process and fuel use Shift-conversion & CO 2 capture Syngas production F-T synthesis CO 2 Natural gas F-T liquid product to treatment O 2 /air Syngas Figure S1: F-T synthesis without and with (dotted lines) CO 2 capture Unconverted syngas is purged from the F-T synthesis reactor or recycle loop; it is used mainly as a fuel and as a source of hydrogen to hydrotreat the raw waxy F-T product. Detailed process flow diagrams and mass balances are given in the main report. Details of the CO 2 sources and methods of capture are different for each of the 3 technologies but in essence are as follows: carbon that is not retained in the product is mostly contained in the purge gas from the F-T synthesis unit. Carbon monoxide in the purge gas is converted to CO 2 by shiftconversion and the CO 2 captured using a physio-chemical solvent (MDEA 2 ). The residual purge gas is used as a hydrogen-rich fuel stream to supply hydrogen to the hydrocracker 3 and as a low-carbon fuel for process heaters. The CO 2 abatement cases are not optimised, they are an engineering judgement of what can be achieved with minimal process development. For example, additional reductions in CO 2 emissions from fired-heaters may be possible (see the refinery heaters study PH3/31). The process performances are compared in table S1. The carbon feed is held constant. The plant produces about 10 000 barrelsper-day of liquid product (which is equivalent to about 600MW thermal ). Table S1: Process performance of F-T synthesis plants with and without CO 2 abatement. F-T process: O 2 blown; slurry reactor (Sasol-type) O 2 blown; fixed-bed reactor (Shell-type) Air blown; fixed-bed reactor (Syntroleum-type) with/without CO 2 capture no capture capture no capture capture no capture capture Efficiency %(LHV) 56.1 55.0 54.8 55.6 53.7 54.5 Carbon in feed (t/h) 63.2 63.2 63.2 63.2 63.2 63.2 Carbon in product (t/h) 43.0 42.2 43.4 44.6 42.2 43.5 % feed carbon in product 68 67 69 71 67 69 Carbon to atmosphere 20.2 6.0 19.7 1.9 21.0 8.9 (t/h) Carbon captured (t/h) none 14.9 none 16.6 none 10.8 Carbon emission avoided (t/h) - 14.2-17.8-12.1 % reduction in C - 70.3-90.4-57.6 emissions 2 Methyldiethanolamine 3 The hydrocracker treats (long-chain) waxy products: (a) to produce compounds with the required carbon chain length i.e. boiling point, (b) to convert oxygenates (e.g. alcohols) to hydrocarbons, and (c) to saturate olefins. iv

Approximately 2/3 of the carbon feed remains in the product. Without CO 2 abatement, approximately 600 000 tonnes/year of CO 2 would be emitted to atmosphere by the conversion process. In all three processes, most of the CO 2 emissions are readily avoided by use of existing technology for CO 2 capture. The Shell-type process has the greatest reduction in emissions of CO 2 mainly because a large quantity of gas is processed to recover hydrogen for hydrocracking and upgrading of the raw products. Compared to power generation, CO 2 capture has a relatively small effect on process efficiency; this is primarily because only about 25% of the carbon entering the process is captured. 4 The cost assessments are summarised in table S2. The product cost is very sensitive to the cost assumed for (remote) natural gas, it increases by approximately 5$/barrel for every 0.5$/GJ added to the cost of natural gas. 5 Overall (well to-wheels) cost impacts will be dealt with in the next phase of this work where the costs and emissions incurred by supply and distribution will be included. 6 Capture of CO 2 adds approximately 3-4$/barrel to the product cost. This is roughly equivalent to the increased cost of product if the natural gas cost is increased by 0.3-0.4$/GJ. The cost of avoiding CO 2 emissions, at approximately 25$/tCO 2, compares favourably with the cost of reducing emissions in power generation (see report PH3/14). (However, CO 2 abatement in power generation avoids about 80% of CO 2 emissions.) Table S2: Costs for F-T synthesis plants with and without CO 2 abatement. F-T Process O 2 blown; slurry reactor (Sasol-type) O 2 blown; fixed-bed reactor (Shell-type) Air blown; fixed bed reactor (Syntroleum-type) with/without CO 2 capture no capture capture no capture capture no capture capture Capital cost (million US$) 346 389 390 446 388 428 Annual cost (million US$) 72.1 83.1 78.3 90.0 87.8 98.3 Product cost ($/barrel) 24.5 28.7 26.4 29.5 30.2 7 32.6 Cost of CO 2 capture $/tco 2 ($/tc) - 25.5 (93.9) - 24.4 (89.4) - 33.6 (123) Cost of CO 2 avoided - 26.8-22.7-30.0 $/tco 2 ($/tc) (98.3) (83.4) (110) Notes: based on remote natural gas at 0.5$/GJ, 10% discount rate, 90% load factor, cost of CO 2 storage is not included. The study shows that, using existing technology, approximately 25% of the carbon entering the F-T process can be captured and made available for long-term storage. This is likely to have a significant impact in the accounting of emissions from the full cycle of F-T fuel use in transport systems. The overall potential for CO 2 abatement could be substantial when the amount of CO 2 captured is combined with: 4 In two cases the efficiency (and cost) increases because of processes changes made to facilitate CO 2 capture. For example, in the Shell-type process the small steam-methane reformer (SMR) is replaced by an additional autothermal partial oxidation unit to avoid CO 2 emissions from the SMR fired-heater. If development of the F-T process were to lead to a major increase in efficiency, it is likely that there would be a more significant efficiency penalty for CO 2 capture. 5 Remote natural gas is assumed to cost 0.5$/GJ in this study. The cost could increase significantly if there was a major market for remote natural gas. The cost of natural gas delivered by long-distance pipeline averaged approximately 2$/GJ in 1999. 6 Shipping costs from the plant, assumed to be in the Middle East, to Northern Europe are estimated to be approximately 1.3 $/barrel. 7 If claims by Syntroleum of enhanced catalyst performance and improved reactor design are addressed by arbitrarily doubling F-T catalyst activity, the product cost without CO 2 capture is 26.7$/bbl and with 29.1$/bbl. v

(a) the effects of F-T fuels being hydrogen-rich compared to petroleum-derived transport fuels. (b) the potential for efficient use of F-T fuels in compression-ignition engines. The F-T process is not very thermally efficient (approximately 55%), which leads to the cost of product being highly dependent on the cost of natural gas. The O 2 -blown fixed-bed F-T reactor process (Shell-type) is shown to have slightly better costs than for the slurry-bed F-T reactor (Sasol-type). This difference is not significant as the accuracy of the assessment is only +/-30%. The next stage of this IEA GHG activity is to compare the full cycle of emissions on a well-to-wheel basis for F-T transport systems with: (a) continued use of petroleum-derived fuels and (b) use of compressed natural gas in vehicles. For this work, the results for performance and cost for the O 2 blown slurry bed reactor (Sasol-type) process can be taken as representative of F-T technology. Although there are differences in the performance and costs of the three types of F-T synthesis process they are not likely to have a crucial impact on the overall outcome of a well-to-wheels evaluation. The adoption of Sasol-type technology as a basis for the next phase of work is preferred because it is the most widely documented and used of the options. In addition, it has been suggested that the future development of both Shell-type and Syntroleum-type F-T processes would be likely to be based on slurry reactors rather than their present fixed-bed technology. The limited ability to scale-up fixed-bed units is a major factor in this decision. Only Sasol slurry reactors have been operated at a commercial scale. The liquid product of F-T synthesis is approximately 6 000 barrels/day of diesel fuel, and 4 000 barrels/day of naphtha. The next stage of work will need to address the use of this product mix. The naphtha is in the right boiling range for gasoline production but is predominantly straight-chain hydrocarbons; it would therefore, require considerable catalytic reforming to be a useful gasoline component. Perhaps a better approach would be to produce a light diesel fuel. Expert Group and other comments Written comments were received from Sasol Synfuels International, Shell International Oil Products B.V., and Syntroleum. These comments are reproduced in an Appendix to the main report. Shell Global Solutions also commented. It was emphasised that the scale of operations has a significant effect on F-T economics. Both Shell and Syntroleum pointed out that modern GTL technology is in its infancy and considerable advances can be expected. Shell suggested that the process efficiency could be in the region of 60-65%. There were no major comments from members of the Expert Group. The major conclusions are as follows: Major conclusions Without CO 2 capture approximately of the carbon entering the F-T process is released to atmosphere. For a plant producing 10 000 barrels/day of liquid fuel this is approximately 600 000 tonnes CO 2 /year. Using existing technology, approximately 25% of the carbon entering the process can be captured as CO 2, i.e. about 450 000 tonnes CO 2 /year for a 10 000 barrel/day facility. This is encouraging as an opportunity for reducing CO 2 emissions from transport. However, a definitive statement about the emission reductions can not be made until the next stage of the assessment ( well-to-wheel cycle) is complete. The cost of avoiding CO 2 emissions is about 25-30$/tonnes of CO 2. This applies to the production of F-T fuel; it should be taken as an indication that the cost of avoiding CO 2 emissions is not expensive compared to other abatement options. A definitive statement about the cost implications can not be made until the vi

next stage of the assessment as, for example, F-T diesel is reputed to be a premium fuel having advantages over petroleum-derived diesel. The Sasol-type process can be used to represent F-T technology. There are differences in the performance and costs of F-T synthesis processes but they are not likely to have a crucial impact on the overall outcome of a well-to-wheels evaluation of the potential for CO 2 abatement. The potential for increased efficiency of the process should be considered in the next stage of the assessment; as modern development of F-T technology is in its infancy, it seems reasonable to assume that increases in efficiency can be achieved. It is recommended that: Recommendations 1) The IEA GHG should use the results of this study for the Sasol-type of process in the planned full fuel cycle evaluation of the potential for CO 2 abatement by adoption of F-T transport fuel. 2) The full cycle evaluation will include appraisals of how transport technology might develop. It should also allow for potential developments in F-T technology. 3) The concept of applying CO 2 capture technology to reduce emissions from the production of F-T transport fuels appears to be novel. To protect member s interests, a first filing of a patent application has been made with the UK Patent Office. A second filing has to be made by the 25 th July 2001 to proceed to a granted UK patent. It is recommended that patent searches be made and, if appropriate, a full patent registered. Consideration should be given to where further patent protection might be sought. vii

IEA FISCHER-TROPSCH Prepared for IEA GREENHOUSE GAS R&D PROGRAMME (IEA GHG) Topical Report Techno-Economic Evaluation CO2 Capture & Compression from Natural Gas F-T Synthesis Plants Bechtel National Inc.

TABLE OF CONTENTS Page Report Organization 1 1 Introduction 2 2 Scope of Study 3 3 Study Bases & Assumptions 4 F-T Technology Design Information 4 Study Bases and General Assumptions 5 4 Specific Technology Design Bases & Assumptions 6 SASOL-TYPE F-T SYNTHESIS 4A Sasol-Type F-T Synthesis & Product Upgrading 7 4A-1 Design Basis Base Case Standard Plant Design 7 5A-1 Overall Plant Summary 8 6A-1 Overall Plant Configuration 14 6A-1.1 Process Flow Diagrams 14 6A-1.2 Mass And Energy Balance Tables 15 7A-1 Process Description 16 8A-1 Offsites 23 9A-1 Plant Costs 26 4A-2 Design Basis CO 2 REDUCTION CASE Standard Plant + CO 2 Capture & Compression 29 5A-2 Overall Plant Summary 33 6A-2 Overall Plant Configuration 38 6A-2.1 Process Flow Diagrams 38 6A-2.2 Mass And Energy Balance Tables 39 7A-2 Process Description 40 8A-2 Offsites 49 9A-2 Plant Costs 50 SHELL-TYPE F-T SYNTHESIS 4B Shell-Type F-T Synthesis & Product Upgrading 52 4B-1 Design Basis Base Case Standard Plant Design 53 5B-1 Overall Plant Summary 55 6B-1 Overall Plant Configuration 61 6B-1.1 Process Flow Diagrams 61 6B-1.2 Mass And Energy Balance Tables 62 7B-1 Process Description 63 8B-1 Offsites 71 9B-1 Plant Costs 74 4B-2 Design Basis CO 2 REDUCTION CASE Standard Plant + CO 2 Capture & Compression 79 5B-2 Overall Plant Summary 81

6B-2 Overall Plant Configuration 86 6B-2.1 Process Flow Diagrams 86 6B-2.2 Mass And Energy Balance Tables 87 7B-2 Process Description 88 8B-2 Offsites 97 9B-2 Plant Costs 98 SYNTROLEUM-TYPE F-T SYNTHESIS 4C Syntroleum-Type F-T Synthesis & Product Upgrading 100 4C-1 Design Basis Base Case Standard Plant Design 102 5C-1 Overall Plant Summary 104 6C-1 Overall Plant Configuration 113 6C-1.1 Process Flow Diagrams 113 6C-1.2 Mass And Energy Balance Tables 114 7C-1 Process Description 115 8C-1 Offsites 122 9C-1 Plant Costs 125 4C-2 Design Basis CO 2 REDUCTION CASE Standard Plant + CO 2 Capture & Compression 130 5C-2 Overall Plant Summary 132 6C-2 Overall Plant Configuration 139 6C-2.1 Process Flow Diagrams 139 6C-2.2 Mass And Energy Balance Tables 140 7C-2 Process Description 141 8C-2 Offsites 146 9C-2 Plant Costs 147 10 Discussion Natural Gas Transportation 149 Indirect Liquefaction 149 Syngas Generation 150 Greenhouse Gases Emissions 150 Carbon Utilization 151 Reduction in Greenhouse Gases Emissions 151 Fuel Gas Treating 152 CO 2 Reduction & Compression 152 Plant Capacity 152 Future Considerations 153 GHR Syngas Generation 153 Influence of Site Location 154 APPENDIX 156 COMMENTS FROM SASOL, SHELL, AND SYNTROLEUM

LIST OF FIGURES Figure 5A-1.1 Mass, Energy, Carbon Balance Summary Sasol-Type Standard Design Figure 5A-1.2 Product Sales Price vs. Natural Gas Cost Figure 6A-1 DWG 102-B-01 Process Flow Diagram Plant 102 Syngas Generation Figure 6A-1 DWG 201-B-01 Process Flow Diagram Plant 201 Fischer-Tropsch Synthesis Figure 6A-1 DWG 202-B-01 Process Flow Diagram Plant 202 Product Upgrading & Fractionation Figure 6A-1 DWG 301-B-01 Process Flow Diagram Plant 301 Steam System Figure 5A-2.1 Mass, Energy, Carbon Balance Summary Sasol-Type CO 2 Capture & Compression Figure 6A-2 DWG 102-B-01 Process Flow Diagram Plant 102 Syngas Generation Figure 6A-2 DWG 201-B-01 Process Flow Diagram Plant 201 Fischer-Tropsch Synthesis Figure 6A-2 DWG 202-B-01 Process Flow Diagram Plant 202 Product Upgrading & Fractionation Figure 6A-2 DWG 301-B-01 Process Flow Diagram Plant 301 Steam System Figure 6A-2 DWG 501-B-01 Process Flow Diagram Plant 501 CO 2 Capture & Compression Figure 5B-1.1 Mass, Energy, Carbon Balance Summary Shell-Type Standard Design Figure 5B-1.2 Product Sales Price vs. Natural Gas Cost Figure 6B-1 DWG 102-B-01 Process Flow Diagram Plant 102 Syngas Generation Figure 6B-1 DWG 201-B-01 Process Flow Diagram Plant 201 Fischer-Tropsch Synthesis Figure 6B-1 DWG 202-B-01 Process Flow Diagram Plant 202 Product Upgrading & Fractionation Figure 6B-1 DWG 301-B-01 Process Flow Diagram Plant 301 Steam System Figure 5B-2.1 Mass, Energy, Carbon Balance Summary Shell-Type CO 2 Capture & Compression Figure 6B-2 DWG 102-B-01 Process Flow Diagram Plant 102 Syngas Generation Figure 6B-2 DWG 201-B-01 Process Flow Diagram Plant 201 Fischer-Tropsch Synthesis Figure 6B-2 DWG 202-B-01 Process Flow Diagram Plant 202 Product Upgrading & Fractionation Figure 6B-2 DWG 301-B-01 Process Flow Diagram Plant 301 Steam System Figure 6B-2 DWG 501-B-01 Process Flow Diagram Plant 501 CO 2 Capture & Compression Figure 5C-1.1 Mass, Energy, Carbon Balance Summary Syntroleum-Type Standard Design Figure 5C-1.2 Product Sales Price vs. Natural Gas Cost Figure 6C-1 DWG 102-B-01 Process Flow Diagram Plant 102 Syngas Generation Figure 6C-1 DWG 201-B-01 Process Flow Diagram Plant 201 Fischer-Tropsch Synthesis Figure 6C-1 DWG 202-B-01 Process Flow Diagram Plant 202 Product Upgrading & Fractionation Figure 6C-1 DWG 301-B-01 Process Flow Diagram Plant 301 Steam System Figure 5C-2.1 Mass, Energy, Carbon Balance Summary Syntroleum-Type CO 2 Capture & Compression Figure 6C-2 DWG 102-B-01 Process Flow Diagram Plant 102 Syngas Generation Figure 6C-2 DWG 201-B-01 Process Flow Diagram Plant 201 Fischer-Tropsch Synthesis Figure 6C-2 DWG 202-B-01 Process Flow Diagram Plant 202 Product Upgrading & Fractionation Figure 6C-2 DWG 301-B-01 Process Flow Diagram Plant 301 Steam System Figure 6C-2 DWG 501-B-01 Process Flow Diagram Plant 501 CO 2 Capture & Compression

LIST OF TABLES Table 5A-1.1 Overall Plant Performance Sasol-Type Standard Design Table 5A-1.2 Capital Cost Summary Sasol-Type Standard Design Table 5A-1.3 Operating Cost Summary Sasol-Type Standard Design Table 5A-1.4 Product Sales Price Sasol-Type Standard Design Table 5A-1.5 Cost and Efficiency Comparison Sasol-Type Standard Design vs CO 2 Capture Table 6A-1.2.1 Sasol-Type Standard Design - Mass and Energy Balance Tables Mass Fraction Table 6A-1.2.2 Sasol-Type Standard Design - Mass and Energy Balance Tables Mole Fraction Table 9A-1.1 Capital Cost Estimate Sasol-Type Standard Design Table 9A-1.2 Operating Cost Estimate Sasol-Type Standard Design Table 5A-2.1 Overall Plant Performance Sasol-Type CO 2 Capture & Compression Table 5A-2.2 Capital Cost Summary Sasol-Type CO 2 Capture & Compression Table 5A-2.3 Operating Cost Summary Sasol-Type CO 2 Capture & Compression Table 5A-2.4 Product Sales Price Sasol-Type CO 2 Capture & Compression Table 5A-2.5 Cost and Efficiency Comparison Sasol-Type Standard Design vs CO 2 Capture Table 6A-2.2.1 Sasol-Type CO 2 Capture & Compression - Mass and Energy Balance Tables Mass Fraction Table 6A-2.2.2 Sasol-Type CO 2 Capture & Compression - Mass and Energy Balance Tables Mole Fraction Table 9A-2.1 Capital Cost Estimate Sasol-Type CO 2 Capture & Compression Table 9A-2.2 Operating Cost Estimate Sasol-Type CO 2 Capture & Compression Table 5B-1.1 Overall Plant Performance Shell-Type Standard Design Table 5B-1.2 Capital Cost Summary Shell-Type Standard Design Table 5B-1.3 Operating Cost Summary Shell-Type Standard Design Table 5B-1.4 Product Sales Price Shell-Type Standard Design Table 5B-1.5 Cost and Efficiency Comparison Shell-Type Standard Design vs CO 2 Capture Table 6B-1.2.1 Shell-Type Standard Design - Mass and Energy Balance Tables Mass Fraction Table 6B-1.2.2 Shell-Type Standard Design - Mass and Energy Balance Tables Mole Fraction Table 9B-1.1 Capital Cost Estimate Shell-Type Standard Design Table 9B-1.2 Operating Cost Estimate Shell-Type Standard Design Table 5B-2.1 Overall Plant Performance Shell-Type CO 2 Capture & Compression Table 5B-2.2 Capital Cost Summary Shell-Type CO 2 Capture & Compression Table 5B-2.3 Operating Cost Summary Shell-Type CO 2 Capture & Compression Table 5B-2.4 Product Sales Price Shell-Type CO 2 Capture & Compression Table 5B-2.5 Cost and Efficiency Comparison Shell-Type Standard Design vs CO 2 Capture Table 6B-2.2.1 Shell-Type CO 2 Capture & Compression - Mass and Energy Balance Tables Mass Fraction Table 6B-2.2.2 Shell-Type CO 2 Capture & Compression - Mass and Energy Balance Tables Mole Fraction Table 9B-2.1 Capital Cost Estimate Shell-Type CO 2 Capture & Compression Table 9B-2.2 Operating Cost Estimate Shell-Type CO 2 Capture & Compression

Table 5C-1.1 Overall Plant Performance Syntroleum-Type Standard Design Table 5C-1.2 Capital Cost Summary Syntroleum-Type Standard Design Table 5C-1.3 Operating Cost Summary Syntroleum-Type Standard Design Table 5C-1.4 Product Sales Price Syntroleum-Type Standard Design Table 5C-1.5 Cost and Efficiency Comparison Syntroleum-Type Standard Design vs CO 2 Capture Table 5C-1.6 Capital Cost Summary Syntroleum-Type Standard Design Enhanced Activity Table 5C-1.7 Operating Cost Summary Syntroleum-Type Standard Design Enhanced Activity Table 5C-1.8 Product Sales Price Syntroleum-Type Standard Design Enhanced Activity Table 6C-1.2.1 Syntroleum-Type Standard Design - Mass and Energy Balance Tables Mass Fraction Table 6C-1.2.2 Syntroleum-Type Standard Design - Mass and Energy Balance Tables Mole Fraction Table 9C-1.1 Capital Cost Estimate Syntroleum-Type Standard Design Table 9C-1.2 Operating Cost Estimate Syntroleum-Type Standard Design Table 5C-2.1 Overall Plant Performance Syntroleum-Type CO 2 Capture & Compression Table 5C-2.2 Capital Cost Summary Syntroleum-Type CO 2 Capture & Compression Table 5C-2.3 Operating Cost Summary Syntroleum-Type CO 2 Capture & Compression Table 5C-2.4 Product Sales Price Syntroleum-Type CO 2 Capture & Compression Table 5C-2.5 Cost and Efficiency Comparison Syntroleum-Type Standard Design vs CO 2 Capture Table 5C-2.6 Capital Cost Summary Syntroleum-Type Standard Design Enhanced Activity Table 5C-2.7 Operating Cost Summary Syntroleum-Type Standard Design Enhanced Activity Table 5C-2.8 Product Sales Price Syntroleum-Type Standard Design Enhanced Activity Table 6C-2.2.1 Syntroleum-Type CO 2 Capture & Compression - Mass and Energy Balance Tables Mass Fraction Table 6C-2.2.2 Syntroleum-Type CO 2 Capture & Compression - Mass and Energy Balance Tables Mole Fraction Table 9C-2.1 Capital Cost Estimate Syntroleum-Type CO 2 Capture & Compression Table 9C-2.2 Operating Cost Estimate Syntroleum-Type CO 2 Capture & Compression

REPORT ORGANIZATION This study contains 10 major sections. Section 1 is an introduction. Section 2 outlines the scope of the study. Section 3 lists the study bases and major assumptions applicable to all three technologies Sasol, Shell, and Syntroleum. To execute the study it was necessary to have a standard F-T plant design as a base case against which the required comparisons could be made. Therefore, two plant designs were prepared for each F-T technology - a Base Case operation (referring to current, standard F-T plant design) and a CO 2 Reduction operation (referring to a potential future F-T plant design, where CO 2 is captured, compressed, and delivered to an export pipeline). The remaining sections of study have therefore been prepared in triplicate, with the identifiers A, B, C for Sasol, Shell, and Syntroleum, respectively, and subsection numbering 1, 2, to denote Base Case operation and CO 2 Reduction operation, respectively. For example, Section 4A-2 refers to the plant design based on Sasol-Type technology and which includes CO 2 capture and compression. Sections 4-9 are prepared in triplicate Section 4 lists the technology-specific design basis and assumptions. Section 5 presents a summary of the study results. Section 6 defines the plant configuration and summarizes the process flows. Section 6.1 contains Process Flow Diagrams (PFDs) for the individual ISBL plants. Section 6.2 contains the mass and energy balance tables for the major streams in the ISBL plants. Section 7 contains a process description for each ISBL plant. Section 8 describes the offsites plants needed to support the ISBL plants and for product handling and shipping. Section 9 contains more detailed summaries of the plant costs. Section 10 discusses the study findings and present a comparison to methanol and 97 wt% DME production. Also discussed in Section 10 are: - process design aspects affecting CO2 emissions and the cost implications of locating the plant site either in the Netherlands or in North America. Appendix Table of technical and economic design criteria relevant to the study Technology licensors comments 1

1. INTRODUCTION The IEA Greenhouse Gas R&D Programme (IEA GHG) undertakes a range of studies which evaluate technologies aimed at avoiding the emission of greenhouse gases (GHG) to the atmosphere. The studies are usually techno-economic evaluations aimed at providing a basis for comparison of GHG mitigation options but they frequently cover wider issues of process development and potential application. This study is a techno-economic evaluation of the conversion of natural gas to liquid transport fuels using state-of-the-art Fischer-Tropsch (F-T) technology. The aim of the study is to provide data which characterises the costs and emissions associated with producing road-transport fuels via F-T synthesis. In an F-T process, synthesis gas (CO and H 2 ) reacts over a catalyst to produce a mixture of straightchain hydrocarbons which can be used to produce road-transport fuels. The technology has been in existence for many years but has only found limited commercial application. Historically, the focus of attention has been on the use of F-T as a method of producing transport fuels from coal. The SASOL plants in South Africa are perhaps the best known example of the technology in commercial use. More recently, F-T technology developed by SASOL was licensed to Mossgas for the conversion of natural gas to liquid fuels in a plant in South Africa. The 12,500 bbl/day Shell MDS (middle distillate synthesis) plant in Bintulu, Malaysia is a further example of a natural gas processing plant based on F-T technology. There has been a recent growth in interest in the use of natural gas to supply transport fuels. The two main drivers behind this are: (a) the availability of large natural gas resources in remote places - which raises the question of the best way to transport this energy to market and, (b) the need to reduce emissions from vehicles and increase their efficiency. An option seen by many as being important is the production of liquid fuels by F-T synthesis; the primary product of F-T synthesis is a high-quality clean liquid fuel which is seen to have the potential to meet both the above needs. It has been suggested that compared to the use of conventional (gasoline and diesel) fuels derived from petroleum, the use of F-T synthesis fuels derived from natural gas potentially offers a significant reduction in emission of greenhouse gases, because: 1. The feed is less carbon-intensive. Comparing say, petroleum which approximates to CH 1.3 with methane, CH 4. 2. F-T derived fuel is reported to be very clean and to be used efficiently. F-T fuel is a clean diesel fuel, and diesel engines are intrinsically more efficient than the spark-ignition engines required for a gasoline fuel. 3. CO 2 is produced within the process and during processing: the majority of this CO 2 could be captured and stored. The overall objective of this study is to obtain emissions and cost data which IEA GHG can subsequently use to calibrate the potential costs and benefits of technical options aimed at GHG emission abatement in road transport. 2

2. SCOPE OF STUDY In this study favored combinations of synthesis gas production and F-T synthesis for the production of a liquid road-transport fuel are assessed; techno-economic evaluations are used to establish emissions from, and the costs of, the fuel production process. CO 2 is captured and compressed at appropriate points in the processing scheme. This study consists of a comparison of three F-T synthesis processes, each including an appropriate synthesis gas production technology. The objective being to establish the range of likely results for the use of such technology. This study evaluates and compares, at the process plant level, the emissions, efficiencies, and costs of 3 versions of F-T technology each matched with the most appropriate synthesis gas production technology. The 3 technologies to be evaluated are: 1. A process based on established SASOL technology. This Slurry Phase Distillate (SPD) process is a low-temperature F-T process using a churn-turbulent bubble column reactor with catalyst contained in process-derived liquid; the synthesis gas is produced using oxygen obtained from an air separation unit (ASU). 2. The Shell MDS (middle distillate synthesis) process. In this case F-T synthesis occurs in fixedbed tubular reactors; the synthesis gas is produced using oxygen obtained from an ASU. 3. A recently proposed alternative process, the Syntroleum process in which the synthesis gas is produced using air rather than oxygen. The process is claimed to be a lower-cost method for converting natural gas to liquid transport fuels. 3

3 STUDY BASES & ASSUMPTIONS The study is based on the concept of building a medium-sized gas-to-liquids facility in a location with lowpriced natural gas, and where most, if not all, key infrastructure requirements for both plant construction and operation are available. At a capacity of approximately 10,000 bpd of transportation-fuel products the facility is not considered to be world-scale. However, at this plant capacity most of the plants that makeup the ISBL facility are either at, or are close to, their maximum single-train sizes. The facility is intended to be a self-contained, grass roots producer of transportation liquids from locally available natural gas. The flexibility of either exporting or importing small quantities of electric power at low cost either to, or from, a local grid is assumed. For F-T technologies under consideration here, both the release of energy and the production of a certain amount of 'pre-naphtha light hydrocarbons are part of process operations. In the instance of this study, where pre-naphtha light hydrocarbons are not considered candidates for plant products, the combined energy in these material and energy streams present the plant s conceptual designer with a choice: i.e. whether or not to recover and export electric power. Recovering and exporting electric power requires a local demand for the electricity and the additional expenditure of capital. Not recovering and exporting electric power reduces plant costs but also lowers plant revenue and results in a lower overall plant efficiency. For this study, the lower plant cost/lower efficiency alternative has been selected. Therefore, the facility is purposely not designed as a co-production facility, i.e. it is not a producer of both electric power and F- T transportation liquids. F-T Technology Design Information: In the development of previous coal and natural gas-based F-T conceptual designs, Bechtel used both licensed (proprietary) and open-art technology information. For this study, technical information for each of the three types of F-T technology was obtained from published information, information published under DOE contracts, in-house knowledge, and information developed by Bechtel. The yields from, and sizes of, the Fischer-Tropsch reactors are based on data of Satterfield et al. (DOE contract DE-AC22-87PC79816), published F-T cobalt catalyst kinetic data (AIChE J. 35, 7, 1107, 1989), published F-T reactor-design simulation information 1, and engineering analysis. The design of the mild hydrocracking plant, used for upgrading the F-T wax, is based on pilot plant data reported by Mobil, PARC, and UOP under DOE contract numbers DE-AC22-80PC30022, DE-AC22-89PC88400, and DE- AC22-85PC80017. 1 Natural Gas Conversion, IV, Elsevier 4

Study Bases and General Assumptions Plant Location Plant Feedstock Natural Gas Composition mol% CH 4 C 2 H 6 C 3 H 8 i-c 4 H 10 n-c 4 H 10 i-c 5 H 12 n-c 5 H 12 CO 2 N 2 Sulfur (as H 2 S) Feed Conditions Saudi Arabian Gulf Coast - product shipped to Northern Europe Natural Gas 94.476 3.438 0.856 0.098 0.176 0.024 0.024 0.437 0.471 4 mg/nm 3 Pressure: 33-45 bar, Temperature: 45 C Feed Properties Molecular Weight: 17.086 Heating Value, LHV: 834 kj/mol Plant Capacity F-T liquids production equivalent to a natural gas feed rate of 100 MMSCFD Plant Product Load Factor Ambient Air Temperature Diesel and Naphtha 90% of rated capacity for all operating years 43 C, 80% relative humidity Seawater Temperature 31 C 5

4 SPECIFIC TECHNOLOGY DESIGN BASES & ASSUMPTIONS 4A SASOL-TYPE F-T SYNTHESIS & PRODUCT UPGRADING 4A-1 BASE CASE Standard Plant Design 6

4A-1 DESIGN BASIS Plant Capacity Process Air Separation Unit 10,000 bpd combined Diesel/Naphtha production Sasol Slurry Phase Distillate Process conventional, single train cryogenic air separation plant - oxygen purity 99.5 mol% O 2 Syngas Generation oxygen-blown, autothermal natural gas reforming - feed ratios:- - H 2 O:C, mole/mole 2 - CO 2 :C, mole/mole - O 2 :C, mole/mole 0.65 0.10 0.56 - exit conditions: Pressure: 28 bar Temperature: 1014 C - H 2 :CO mole ratio 2.04 Hydrogen Separation Pressure swing adsorption - H 2 purity > 99.5 mol% H 2 F-T Synthesis single SBCR reactor, cobalt catalyst in F-T synthesis derived liquid, internal heat recovery (steam raising), recycle of part of purge gas to syngas generation, catalyst makeup/activation, catalyst recovery and recycle - operating conditions Pressure: 26 bar Temperature: 220 C - Anderson-Schulz-Flory distribution parameter (α) several values used to fit slope of carbon-number distribution for cobalt catalyst - CO conversion per pass 76% - steam raising saturated 13 bar, 191 C Product Upgrading mild hydrocracking of ASTM-D86 350+ C product (wax) - operating conditions Pressure: 115 bar Temperature: 370 C - reactor LHSV 2 hr -1 Product Separation prefractionation, product fractionation, vacuum fractionation 2 Mole per mole of carbon atoms in hydrocarbon species in feed 7

5A-1 OVERALL PLANT SUMMARY This section summarizes the overall plant performance and costs for a Standard Sasol-Type, natural gas Fischer-Tropsch liquefaction plant. Certain key plant characteristics which form the motivation for the study are presented here. In particular, plant efficiency, carbon emissions, breakdown of product sales price, and capital and operating costs are summarized here. Table 5A-1.1 contains a summary of the major feed and product streams. The plant processes 100 MMSCF/day of natural gas and produces about 10,309 BPD of F-T liquid products. The primary liquid products are naphtha blending stock and a ASTM D-86 350 C end-point diesel. Both products are essentially free of sulfur, nitrogen and oxygen containing compounds. Table 5A-1.1 Overall Plant Performance Natural Gas Fischer-Tropsch Liquefaction Plant Summary Feed Natural Gas 100 MMSCF/day (4.153 GJ/h) Primary Products F-T Naphtha 5.37 kg/s (4,136 Bbl/day) F-T Distillate 8.78 kg/s (6,173 Bbl/day) Power Import/Export 0 MW Plant Thermal Efficiency Diesel-naphtha, LHV 53.8 % Adjusted for electric power 53.8 % Carbon Emissions Non-product, MT/y 159,625 as carbon Note, sufficient electric power is generated onsite through the steam turbine-driven power generator to meet the facility s normal operating power requirements. Figure 5A-1.1 is a block flow diagram of the main mass, energy, and carbon flows for the facility 8

9 Figure 5A-1.1 Mass, Energy, & Carbon Balance Summary Sasol-Type Design - Base Case Residue Gas Q OUT = 0.13 TJ/h Air Air Separation Unit 28.4 kg/s 37.7 MW S/T Drivers HP Steam, 60.7 kg/s MP Steam, 86.6 kg/s Steam Turbine Drives & Power Generation Pwr Gen = 8.1 MW Internal Power Consumption 8.1 MW 0 MW 0 MW Q OUT = 0.145 TJ/h Q OUT = 0.119 TJ/h Process Duty, 0.312 TJ/h Natural Gas M IN = 23.6 kg/s LHV = 4.153 TJ/h Carbon = 63,229 kg/h Steam 18.4 kg/s Recycle Gas 14.1 kg/s Syngas Generation H 2 0.1 kg/s 64.6 kg/s F-T Synthesis 19.7 kg/s 20.9 kg/s 0.7 kg/s Recycle Gas 13.5 kg/s 15.5 kg/s 15.53 kg/s 0.06 kg/s Fuel Combustion Flue Gas (fuel component only) M OUT = 15.59 kg/s Q OUT = 0.480 TJ/h Carbon = 20,169 kg/h Q OUT = 0.182 TJ/h BFW 61.3 kg/s BFW 88.3 kg/s Q OUT = 0.962 TJ/h Steam Condensation Water Makeup 0.3 kg/s H 2 0.1 kg/s Product Upgrading & Fractionation Recycle Gas 0.6 kg/s F-T Liquid M OUT = 14.16 kg/s LHV = 2.236 TJ/h Carbon = 42,951 kg/h - Input 117.4 kg/s 136.1 kg/s - Output steam & process condensates 40.6 kg/s Water Treating Effluent Water M OUT = 21.9 kg/s Carbon = 78 kg/h

Table 5A-1.2 shows the capital cost estimates for the plant. This is a mid-1999 cost for construction of the plant at a Saudi Arabian Gulf Coast site. Table 5A-1.2 Capital Cost Summary for Natural Gas Fischer-Tropsch Liquefaction Plant Area Description Cost (MM$) $/GJ % ISBL 100 Syngas Preparation 90.0 58.6 200 F-T Synthesis/Upgrading 44.9 29.3 300 Steam Generation 18.6 12.1 Offsites Facilities 120.0 HO Service/Fees/Contingency 72.5 Total Cost: 346.0 (33,555$/bpd) The above plant costs are order-of-magnitude ± 30% estimates. Table 5A-1.3 shows the annual operating cost summary. Table 5A-1.3 Operating Cost Summary for Natural Gas Fischer-Tropsch Liquefaction Plant Description Cost (MM$) Fixed Costs 16.9 Variable Costs 20.6 By-Product Revenue - Total Cost: 37.5 10

Table 5A-1.4 shows the breakdown of the product sales price. Table 5A-1.4 Product Sales Price Natural Gas Fischer-Tropsch Liquefaction Plant Description $/bbl Fuel 4.83 Capital charges* 10.21 Other operating costs 6.23 Return on investment* 3.27 FOB Sales Price**: 24.54 ( * ) capital charge rate of 10%, discount factor 10% ( ** ) averaged price; naphtha 25.26 $/bbl, diesel 24.05 $/bbl It s estimated that the shipping costs for product transportation to Northern Europe will be approximately $1.26/bbl, or 3 cents/gal extra. The sensitivity of capital charge rate to the discount factor at fixed product pricing is given below. - a 5% discount factor requires a 7.09% capital charge rate Section 9A-1 contains more detailed information on the capital and operating costs for the plant. 11

Table 5A-1.5 is a comparison between a standard Sasol-type F-T technology plant design and a Sasoltype F-T technology plant designed to include CO 2 capture and compression. Table 5A-1.5 presents the cost and efficiency penalties attributable to the adoption of CO 2 capture and compression. Table 5A-1.5 Cost and Efficiency Comparison Natural Gas Fischer-Tropsch Liquefaction Plant Base Case CO 2 Capture Plant Design Sasol-type Sasol-type Natural Gas, MMSCFD 100 100 Product rate, BPD 10,309 10,131 Capital Cost, $MM $345.9 $388.6 Capital Cost, $/BPD $33,555 $38,357 Operating Cost, $MM/y $37.5 $44.2 Capital Charge, $MM/y $34.59 $38.86 Product Sales Price, $/bbl $24.5 $28.7 Plant Efficiency, % (LHV) 56.1% 55.0% Non-product Carbon Streams: - Emissions, MT_Carbon/y 159,625 48,263 - CO2 capture, MT_Carbon/y - 117,134 Reduction in Carbon Emissions, % 70% Cost for reduction in CO2 emission: - $/tonne carbon captured * $93.9 * - includes compression to 110 bar Figure 5A-1.2 shows the sensitivity of product sales price to natural gas cost for both the standard design and the CO2 capture and compression plant designs 12

Figure 5A-1.2 Sensitivity of Product Sales Price to Natural Gas Cost Sasol-Type F-T Technology 60 55 50 CO2 Capture & Compression Design 45 Distillate FOB Sales Price, $/bb 40 35 Standard Design 30 25 20 15 0 0.5 1 1.5 2 2.5 3 3.5 Natural Gas Cost, $/GJ 13

6A-1 OVERALL PLANT CONFIGURATION This section presents an overall summary of standard Sasol-type Fischer-Tropsch synthesis technology. It is divided into two subsections: 6A-1.1 6A-1.2 Process Flow Diagrams Mass and Energy Balance Tables 6A-1.1 Process Flow Diagrams This section contains the process flow diagrams (PFDs) for each process plant within Areas 100, 200, and 300 in PFDs 102-B-01 through 301-B-01. Each PFD is numbered according to the plant number for the plants in Process Areas 100, 200, and 300. Area 100 contains two major plants: Plant 101, the Air Separation Unit Plant 102, the Autothermal Reforming Plant and H 2 Separation Area 200 contains two major plants: Plant 201, the Fischer-Tropsch Synthesis Plant Plant 202, the F-T Liquid Product Upgrading and Fractionation Plants Area 300 represents the plant steam distribution system: The offsite and utility plants are given Bechtel s conventional numbering code where 19 is Relief and Blowdown, 20 is Tankage, 21 is Interconnecting Piping, 30 is Electrical Distribution, 32 is Raw, Cooling and Potable Water Systems, etc. Equipment is numbered with the plant number followed by the Bechtel letter designation for that type of equipment followed by the sequential number designating the specific piece of equipment. If duplicates or spares are provided, these are given an additional letter designation in alphabetical order. In all of the above PFDs, major streams are designated by a number enclosed within a diamond. The component flow rates and selected stream properties of these numbered streams are given in Tables 6.1 and 6.2 in the following section. 14

6A-1.2 Mass and Energy Balance Tables The component flow rates of key streams in process Areas 100, and 200 are shown in Tables 6A-1.2.1 and 6A-1.2.2 The streams are identified by the same stream numbers used in the PFDs shown in the previous section. Table 6A-1.1.2 contains the stream composition in mass fraction, stream temperatures and pressures, total flow rates in both moles and mass, the stream average molecular weight, and stream enthalpy for the key streams in Areas 100 and 200. Table 6A-1.2.2 contains the same information for the process streams in Areas 100 and 200 except that stream composition is presented in mole fraction. 15

IEA GHG PROGRAM TABLE 6A-1.2.2 MASS AND ENERGY BALANCE (MOLE FRACTION) SASOL-TYPE DESIGN: BASE CASE 1 Plant Section SYNGAS GENERATION Stream No. 1 2 3 4 5 6 7 8 Stream Natural Gas Feed MP Steam Addition Oxygen from ASU MP Steam Addition FT Syngas & Prefractn. Hydrocarb on Feed To ATR Autotherm al Reformer Syngas to PSA Unit Temperature, C 45 354 29 530 200 354 1014 60 Pressure, bara 32.75 31.03 22.06 30.06 28.96 31.03 27.92 26.27 Molar Flow, kgmole/h 4,980.7 3,409.0 2,599.6 10,989.3 3,194.3 256.6 22,098.6 418.4 Mass Flow, kg/s 23.6 17.1 14.1 54.8 28.4 1.3 84.4 1.5 Enthalpy, kj/h 5.146E+07 6.950E+07 2.227E+07 3.452E+08 4.410E+07 5.231E+06 9.138E+08 3.760E+06 Mole Wt. 17.086 18.015 19.479 17.941 31.980 18.015 13.753 12.830 Composition, Mole Frac. H2 0.4479 0.1060 0.5034 0.6121 N2 0.0047 0.0132 0.0053 0.0050 0.0033 0.0041 CO 0.2340 0.0553 0.2463 0.2995 CO2 0.0044 0.2107 0.0518 0.0507 0.0616 H2O 1.0000 0.0020 0.3107 1.0000 0.1849 0.0088 O2 0.9950 C1 0.9448 0.0677 0.4442 0.0114 0.0139 C2's 0.0344 0.0031 0.0163 C3's 0.0086 0.0068 0.0055 C4's 0.0028 0.0098 0.0035 C5's 0.0004 0.0032 0.0009 C6's 0.0001 C7-C9 C10-C12 C13-C15

IEA GHG PROGRAM TABLE 6A-1.2.2 MASS AND ENERGY BALANCE (MOLE FRACTION) SASOL-TYPE DESIGN: BASE CASE 2 C16-C18 C19-C23 C24-C29 C30+WAX Oxygenates 0.0013 0.0003 Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 LHV Dry Basis*: kj/kgmole kj/kg * calculated at reported stream P, T, phase - air at 1.013 bara, 15.5 C, combustion products at 15.5 C, water in vapor phase

IEA GHG PROGRAM TABLE 6A-1.2.2 MASS AND ENERGY BALANCE (MOLE FRACTION) SASOL-TYPE DESIGN: BASE CASE 3 Plant Section Stream No. 9 10 11 Stream Syngas to F-T Synthesis PSA Unit Residue Gas H2 to Hydrocrack er Temperature, C 60 191 60 Pressure, bara 26.27 26.54 25.86 Molar Flow, kgmole/h 17,753.3 212.3 204.9 Mass Flow, kg/s 63.3 1.4 0.1 Enthalpy, kj/h 1.596E+08 2.894E+06 1.731E+06 Mole Wt. 12.830 23.238 2.016 Composition, Mole Frac. H2 0.6121 0.2413 1.0000 N2 0.0041 0.0080 CO 0.2995 0.5903 CO2 0.0616 0.1214 H2O 0.0088 0.0116 O2 C1 0.0139 0.0274 C2's C3's C4's C5's C6's C7-C9 C10-C12 C13-C15 SYNGAS GENERATION

IEA GHG PROGRAM TABLE 6A-1.2.2 MASS AND ENERGY BALANCE (MOLE FRACTION) SASOL-TYPE DESIGN: BASE CASE 4 C16-C18 C19-C23 C24-C29 C30+WAX Oxygenates Total 1.0000 1.0000 1.0000 LHV Dry Basis*: kj/kgmole kj/kg * calculated at reported stream P, T, phase - air at 1.013 bara, 15.5 C, combustion products at 15.5 C, water in vapor phase