co2 abatement in gas-to-liquids plant: fischer-tropsch ... fischer tropsc… · i title: co2...

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.

i

Title: CO2 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 CO2 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 CO2 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 H2) reacts over a catalyst to produce a mixture of straight-chain 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 CH2 compared with petroleum, which approximates to a chemical formula of CH1.3)

ii

(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 fuel1.

(c) CO2 is produced during processing; the majority of this CO2 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 CO2 capture is compared with an alternative design incorporating CO2 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 CO2 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 2H2:1CO 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 CO2. 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 NOx production is achieved because of the high cetane number (>70) and the low density.

iv

Figure S1: F-T synthesis without and with (dotted lines) CO2 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 CO2 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 CO2 by shift-conversion and the CO2 captured using a physio-chemical solvent (MDEA2). The residual purge gas is used as a hydrogen-rich fuel stream to supply hydrogen to the hydrocracker3 and as a ‘low-carbon’ fuel for process heaters. The CO2 abatement cases are not optimised, they are an engineering judgement of what can be achieved with minimal process development. For example, additional reductions in CO2 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 barrels-per-day of liquid product (which is equivalent to about 600MWthermal). Table S1: Process performance of F-T synthesis plants with and without CO2 abatement. F-T process: O2 blown; slurry

reactor (Sasol-type)

O2 blown; fixed-bed reactor

(Shell-type)

Air blown; fixed-bed reactor

(Syntroleum-type) with/without CO2 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 (t/h)

20.2 6.0 19.7 1.9 21.0 8.9

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 emissions

- 70.3 - 90.4 - 57.6

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.

Syngas recycle

O2/air Syngas

Natural gas

F-T liquid product to treatment

CO2

Purge gas to process and fuel use

Syngas production

F-T synthesis

Shift-conversion & CO2 capture

v

Approximately 2/3 of the carbon feed remains in the product. Without CO2 abatement, approximately 600 000 tonnes/year of CO2 would be emitted to atmosphere by the conversion process. In all three processes, most of the CO2 emissions are readily avoided by use of existing technology for CO2 capture. The Shell-type process has the greatest reduction in emissions of CO2 mainly because a large quantity of gas is processed to recover hydrogen for hydrocracking and upgrading of the raw products. Compared to power generation, CO2 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 CO2 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 CO2 emissions, at approximately 25$/tCO2, compares favourably with the cost of reducing emissions in power generation (see report PH3/14). (However, CO2 abatement in power generation avoids about 80% of CO2 emissions.) Table S2: Costs for F-T synthesis plants with and without CO2 abatement. F-T Process O2 blown; slurry

reactor (Sasol-type)

O2 blown; fixed-bed reactor

(Shell-type)

Air blown; fixed bed reactor

(Syntroleum-type) with/without CO2 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 30.27 32.6 Cost of CO2 capture $/tCO2 ($/tC)

- 25.5 (93.9)

- 24.4 (89.4)

- 33.6 (123)

Cost of CO2 avoided $/tCO2 ($/tC)

- 26.8 (98.3)

- 22.7 (83.4)

- 30.0 (110)

Notes: based on remote natural gas at 0.5$/GJ, 10% discount rate, 90% load factor, cost of CO2 storage is not included. The study shows that, using existing technology, approximately 25% of the carbon entering the F-T process can be captured and made available for long-term storage. This is likely to have a significant impact in the accounting of emissions from the full cycle of F-T fuel use in transport systems. The overall potential for CO2 abatement could be substantial when the amount of CO2 captured is combined with: 4 In two cases the efficiency (and cost) increases because of processes changes made to facilitate CO2 capture. For example, in the Shell-type process the small steam-methane reformer (SMR) is replaced by an additional autothermal partial oxidation unit to avoid CO2 emissions from the SMR fired-heater. If development of the F-T process were to lead to a major increase in efficiency, it is likely that there would be a more significant efficiency penalty for CO2 capture. 5 Remote natural gas is assumed to cost 0.5$/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 $/barrel. 7 If claims by Syntroleum of enhanced catalyst performance and improved reactor design are addressed by arbitrarily doubling F-T catalyst activity, the product cost without CO2 capture is 26.7$/bbl and with 29.1$/bbl.

vi

(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 O2-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 ‘O2 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.

Major conclusions The major conclusions are as follows: Without CO2 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 CO2 /year. Using existing technology, approximately 25% of the carbon entering the process can be captured as CO2, i.e. about 450 000 tonnes CO2/year for a 10 000 barrel/day facility. This is encouraging as an opportunity for reducing CO2 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 CO2 emissions is about 25-30$/tonnes of CO2. This applies to the production of F-T fuel; it should be taken as an indication that the cost of avoiding CO2 emissions is not expensive compared to other abatement options. A definitive statement about the cost implications can not be made until the

vii

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 CO2 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.

Recommendations It is recommended that: 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 CO2 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 CO2 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 25th 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.

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 CO2 REDUCTION CASE – Standard Plant + CO2 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 CO2 REDUCTION CASE – Standard Plant + CO2 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 CO2 REDUCTION CASE – Standard Plant + CO2 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 CO2 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 CO2 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 CO2 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 CO2 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 CO2 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 CO2 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 CO2 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 CO2 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 CO2 Capture & Compression Table 5A-2.2 Capital Cost Summary – Sasol-Type CO2 Capture & Compression Table 5A-2.3 Operating Cost Summary – Sasol-Type CO2 Capture & Compression Table 5A-2.4 Product Sales Price – Sasol-Type CO2 Capture & Compression Table 5A-2.5 Cost and Efficiency Comparison – Sasol-Type Standard Design vs CO2 Capture Table 6A-2.2.1 Sasol-Type CO2 Capture & Compression - Mass and Energy Balance Tables – Mass Fraction Table 6A-2.2.2 Sasol-Type CO2 Capture & Compression - Mass and Energy Balance Tables – Mole Fraction Table 9A-2.1 Capital Cost Estimate – Sasol-Type CO2 Capture & Compression Table 9A-2.2 Operating Cost Estimate – Sasol-Type CO2 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 CO2 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 CO2 Capture & Compression Table 5B-2.2 Capital Cost Summary – Shell-Type CO2 Capture & Compression Table 5B-2.3 Operating Cost Summary – Shell-Type CO2 Capture & Compression Table 5B-2.4 Product Sales Price – Shell-Type CO2 Capture & Compression Table 5B-2.5 Cost and Efficiency Comparison – Shell-Type Standard Design vs CO2 Capture Table 6B-2.2.1 Shell-Type CO2 Capture & Compression - Mass and Energy Balance Tables – Mass Fraction Table 6B-2.2.2 Shell-Type CO2 Capture & Compression - Mass and Energy Balance Tables – Mole Fraction Table 9B-2.1 Capital Cost Estimate – Shell-Type CO2 Capture & Compression Table 9B-2.2 Operating Cost Estimate – Shell-Type CO2 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 CO2 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 CO2 Capture & Compression Table 5C-2.2 Capital Cost Summary – Syntroleum-Type CO2 Capture & Compression Table 5C-2.3 Operating Cost Summary – Syntroleum-Type CO2 Capture & Compression Table 5C-2.4 Product Sales Price – Syntroleum-Type CO2 Capture & Compression Table 5C-2.5 Cost and Efficiency Comparison – Syntroleum-Type Standard Design vs CO2 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 CO2 Capture & Compression - Mass and Energy Balance Tables – Mass

Fraction Table 6C-2.2.2 Syntroleum-Type CO2 Capture & Compression - Mass and Energy Balance Tables – Mole Fraction Table 9C-2.1 Capital Cost Estimate – Syntroleum-Type CO2 Capture & Compression Table 9C-2.2 Operating Cost Estimate – Syntroleum-Type CO2 Capture & Compression

1

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 “CO2 Reduction” operation (referring to a potential future F-T plant design, where CO2 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 “CO2 Reduction” operation, respectively. For example, Section 4A-2 refers to the plant design based on Sasol-Type technology and which includes CO2 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

2

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 H2) reacts over a catalyst to produce a mixture of straight-chain 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 CH1.3 with

methane, CH4. 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. CO2 is produced within the process and during processing: the majority of this CO2 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.

3

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. CO2 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 fixed-

bed 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.

4

3 STUDY BASES & ASSUMPTIONS The study is based on the concept of building a medium-sized gas-to-liquids facility in a location with low-priced 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 information1, 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

5

Study Bases and General Assumptions Plant Location Saudi Arabian Gulf Coast - product shipped to Northern Europe

Plant Feedstock Natural Gas

Natural Gas Composition mol% CH4 C2H6 C3H8 i-C4H10 n-C4H10 i-C5H12 n-C5H12 CO2 N2 Sulfur (as H2S)

94.476 3.438 0.856 0.098 0.176 0.024 0.024 0.437 0.471 4 mg/Nm3

Feed Conditions 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 Diesel and Naphtha

Load Factor 90% of rated capacity for all operating years

Ambient Air Temperature 43°C, 80% relative humidity

Seawater Temperature 31°C

6

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

7

4A-1 DESIGN BASIS Plant Capacity 10,000 bpd combined Diesel/Naphtha production

Process Sasol – Slurry Phase Distillate Process

Air Separation Unit conventional, single train cryogenic air separation plant

- oxygen purity 99.5 mol% O2

Syngas Generation oxygen-blown, autothermal natural gas reforming

- feed ratios:-

- H2O:C, mole/mole2 - CO2:C, mole/mole - O2:C, mole/mole

0.65 0.10 0.56

- exit conditions: Pressure: 28 bar Temperature: 1014°C

- H2:CO mole ratio 2.04

Hydrogen Separation Pressure swing adsorption

- H2 purity > 99.5 mol% H2

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)


- reactor LHSV 2 hr-1

Product Separation prefractionation, product fractionation, vacuum fractionation

2 Mole per mole of carbon atoms in hydrocarbon species in feed

8

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

9

0.3 kg/s

117.4 kg/s

SyngasGeneration 64.6 kg/s F-T Synthesis

Steam TurbineDrives

& PowerGeneration

Pwr Gen = 8.1 MW

Air SeparationUnit

28.4 kg/s

Fuel Combustion

SteamCondensationWater Makeup

15.53 kg/s

Water Treating40.6 kg/s

ProductUpgrading

& Fractionation

136.1

kg/s

0 MW

0 MW

Internal PowerConsumption

8.1 MW

Natural Gas

Figure 5A-1.1Mass, Energy, & Carbon Balance Summary

Sasol-Type Design - Base Case

Air

Residue Gas

BFW61.3 kg/s

HP Steam,60.7 kg/s

MP Steam,86.6 kg/s

37.7 MW S/T Drivers

Flue Gas(fuel component only)

F-T Liquid

MOUT = 15.59 kg/sQOUT = 0.480 TJ/hCarbon = 20,169 kg/h

MOUT = 14.16 kg/sLHV = 2.236 TJ/hCarbon = 42,951 kg/h

Process Duty,0.312 TJ/h

MIN = 23.6 kg/sLHV = 4.153 TJ/hCarbon = 63,229 kg/h

MOUT = 21.9 kg/sCarbon = 78 kg/h

Effluent Water

QOUT= 0.119 TJ/h

QOUT= 0.13 TJ/h

QOUT= 0.145 TJ/h

QOUT= 0.962 TJ/h

QOUT= 0.182 TJ/h

Steam18.4 kg/s

Recycle Gas14.1 kg/s

H2

0.1 kg/s

19.7 kg/s 20.9 kg/s

H2

0.1 kg/s

0.06 kg/s


Recycle Gas0.6 kg/s

15.5 kg/s0.7 kg/s

BFW88.3 kg/s

- Input

- Output

steam & processcondensates

10

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

11

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.

12

Table 5A-1.5 is a comparison between a standard Sasol-type F-T technology plant design and a Sasol-type F-T technology plant designed to include CO2 capture and compression. Table 5A-1.5 presents the cost and efficiency penalties attributable to the adoption of CO2 capture and compression.

Table 5A-1.5 Cost and Efficiency Comparison


Base Case CO2 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

13

Figure 5A-1.2Sensitivity of Product Sales Price to Natural Gas Cost

Sasol-Type F-T Technology

15

20

25

30

35

40

45

50

55

60

0 0.5 1 1.5 2 2.5 3 3.5

Natural Gas Cost, $/GJ

Dis

tilla

te F

OB

Sal

es P

rice,

$/b

b

Standard Design

CO2 Capture & Compression Design

14

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 Process Flow Diagrams 6A-1.2 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 H2 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.

15

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.

IEA GHG PROGRAM TABLE 6A-1.2.2 MASS AND ENERGY BALANCE

(MOLE FRACTION)

SASOL-TYPE DESIGN: BASE CASE

1

Plant SectionStream No. 1 2 3 4 5 6 7 8

StreamNatural

Gas FeedMP Steam Addition

FT Syngas &

Prefractn.

Hydrocarbon Feed To ATR

Oxygen from ASU

MP Steam Addition

Autothermal

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

SYNGAS GENERATION


(MOLE FRACTION)


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


(MOLE FRACTION)


3

Plant SectionStream No. 9 10 11

StreamSyngas to

F-T Synthesis

PSA Unit Residue

Gas

H2 to Hydrocrack

erTemperature, °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


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


(MOLE FRACTION)


4

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates

Total 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1


StreamATR

SyngasPSA Unit Residue

Gas

F-T Reactor

Feed

F-T Reactor Vapor

F-T Reactor Liquid

HT Separator

F-T Liquids

HT separator

Vapor

LT Separator

F-T LiquidsTemperature, °C 60 191 92 220 220 155 155 40

Pressure, bara 26.27 26.54 26.17 24.72 24.72 24.24 24.24 23.82

Molar Flow, kgmole/h 17,753.3 212.3 17,965.6 9,760.2 92.4 31.1 7,330.6 94.0

Mass Flow, kg/s 63.3 1.4 64.6 55.4 9.3 1.7 41.6 3.1

Enthalpy, kJ/h 1.596E+08 2.894E+06 1.790E+08 1.602E+08 1.677E+07 1.439E+06 9.992E+07 -4.499E+05

Mole Wt. 12.830 23.238 12.953 20.421 361.321 197.894 20.451 119.589


H2 0.6121 0.2413 0.6077 0.2500 0.0123 0.0113 0.3328 0.0085

N2 0.0041 0.0080 0.0041 0.0075 0.0005 0.0005 0.0100 0.0005

CO 0.2995 0.5903 0.3030 0.1338 0.0084 0.0089 0.1781 0.0103

CO2 0.0616 0.1214 0.0623 0.1191 0.0150 0.0211 0.1583 0.0555

H2O 0.0088 0.0116 0.0088 0.4284 0.0570 0.0343 0.2433 0.0011

O2

C1 0.0139 0.0274 0.0140 0.0384 0.0035 0.0043 0.0511 0.0071

C2's 0.0014 0.0002 0.0003 0.0019 0.0011

C3's 0.0025 0.0006 0.0012 0.0033 0.0059

C4's 0.0022 0.0009 0.0021 0.0031 0.0161

C5's 0.0021 0.0014 0.0034 0.0026 0.0366

C6's 0.0019 0.0020 0.0060 0.0024 0.0748

C7-C9 0.0044 0.0124 0.0521 0.0058 0.3581

C10-C12 0.0031 0.0312 0.1689 0.0034 0.2610

C13-C15 0.0018 0.0683 0.3056 0.0011 0.0928

C16-C18 0.0009 0.1040 0.2287 0.0002 0.0160

C19-C23 0.0003 0.1882 0.1140 0.0017

C24-C29 0.1714 0.0246

C30+WAX 0.3213 0.0081

Oxygenates 0.0019 0.0016 0.0049 0.0025 0.0529

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg


F-T SYNTHESIS


(MOLE FRACTION)


2


StreamLT

Separator Vapor

F-T liquids to

Fractionati

F-T Wax to Upgrading

Hydrocracker MP Flash

Lean Solvent Feed

Rich Solvent

Absorber Overheads

Purge Gas to Fuel

Temperature, °C 40 83 220 250 45 41 27 27

Pressure, bara 23.82 23.82 24.72 31.03 1.34 22.41 22.06 22.06

Molar Flow, kgmole/h 5,470.4 125.1 92.4 80.1 170.9 239.2 5,472.2 2,932.1

Mass Flow, kg/s 29.7 4.8 9.3 0.7 9.9 11.3 29.0 15.5

Enthalpy, kJ/h 4.887E+07 9.896E+05 1.677E+07 2.685E+06 -1.703E+06 -1.936E+06 4.620E+07 2.475E+07

Mole Wt. 19.521 139.059 361.321 33.685 208.651 169.749 19.070 19.070


H2 0.4458 0.0092 0.0123 0.5861 0.0086 0.4539 0.4539

N2 0.0134 0.0005 0.0005 0.0005 0.0134 0.0134

CO 0.2385 0.0100 0.0084 0.0109 0.2380 0.2380

CO2 0.2107 0.0470 0.0150 0.0535 0.2083 0.2083

H2O 0.0037 0.0094 0.0570 0.0008 0.0012 0.0009 0.0019 0.0019

O2

C1 0.0683 0.0064 0.0035 0.0137 0.0066 0.0682 0.0682

C2's 0.0025 0.0010 0.0002 0.0188 0.0010 0.0028 0.0028

C3's 0.0043 0.0047 0.0006 0.0556 0.0051 0.0049 0.0049

C4's 0.0037 0.0127 0.0009 0.1020 0.0135 0.0047 0.0047

C5's 0.0029 0.0284 0.0014 0.0694 0.0296 0.0027 0.0027

C6's 0.0020 0.0577 0.0020 0.0346 0.0524 0.0001 0.0001

C7-C9 0.0014 0.2820 0.0124 0.0883 0.0005 0.0633

C10-C12 0.2381 0.0312 0.0151 0.1450 0.1101

C13-C15 0.1458 0.0683 0.0096 0.5066 0.3651

C16-C18 0.0689 0.1040 0.0045 0.3081 0.2215

C19-C23 0.0295 0.1882 0.0012 0.0386 0.0280

C24-C29 0.0060 0.1714

C30+WAX 0.0020 0.3213

Oxygenates 0.0024 0.0410 0.0016 0.0293 0.0011 0.0011

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg


F-T SYNTHESIS


(MOLE FRACTION)


3

Plant SectionStream No. 17

StreamPurge Gas Recycle to

ATR

Temperature, °C 27

Pressure, bara 22.06

Molar Flow, kgmole/h 2,540.2

Mass Flow, kg/s 13.5

Enthalpy, kJ/h 2.144E+07

Mole Wt. 19.070


H2 0.4539

N2 0.0134

CO 0.2380

CO2 0.2083

H2O 0.0019

O2

C1 0.0682

C2's 0.0028

C3's 0.0049

C4's 0.0047

C5's 0.0027

C6's 0.0001

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates 0.0011

Total 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg


F-T SYNTHESIS


(MOLE FRACTION)


1


StreamF-T Liquids Rich

SolventF-T "Wax"

LiquidsHydrocracker Recycle

Stream

Prefractn. Overheads

Prefractn. Bottoms

Product Fractionato

r Feed

Product Fractionato

r Temperature, °C 83 41 220 250 43 331 362 33

Pressure, bara 23.82 22.41 24.72 31.03 13.79 14.13 1.72 1.10

Molar Flow, kgmole/h 125.1 239.2 92.4 200.4 59.4 504.3 596.7 4.1

Mass Flow, kg/s 4.8 11.3 9.3 10.8 0.6 26.3 35.6 0.0

Enthalpy, kJ/h 9.896E+05 -1.936E+06 1.677E+07 2.084E+07 7.274E+05 7.270E+07 1.347E+08 4.914E+04

Mole Wt. 139.059 169.749 361.321 194.769 36.956 188.026 214.863 32.864


H2 0.0092 0.0086 0.0123 0.0412 0.1930 0.0019 0.2693

N2 0.0005 0.0005 0.0005 0.0031 0.0001 0.0099

CO 0.0100 0.0109 0.0084 0.0648 0.0013 0.1763

CO2 0.0470 0.0535 0.0150 0.3143 0.0023 0.2063

H2O 0.0094 0.0009 0.0570 0.0001 0.0068 0.0088 0.0451

O2

C1 0.0064 0.0066 0.0035 0.0017 0.0458 0.0005 0.0651

C2's 0.0010 0.0010 0.0002 0.0038 0.0191 0.0025

C3's 0.0047 0.0051 0.0006 0.0171 0.0881 0.0001 0.0032

C4's 0.0127 0.0135 0.0009 0.0474 0.2306 0.0012 0.0012 0.0106

C5's 0.0284 0.0296 0.0014 0.0468 0.0270 0.0365 0.0310 0.0986

C6's 0.0577 0.0524 0.0020 0.0348 0.0001 0.0530 0.0450 0.0434

C7-C9 0.2820 0.0633 0.0124 0.1666 0.1662 0.1423 0.0222

C10-C12 0.2381 0.1101 0.0312 0.0913 0.1475 0.1295 0.0004

C13-C15 0.1458 0.3651 0.0683 0.1633 0.2743 0.2423

PRODUCT UPGRADING & FRACTIONATION


(MOLE FRACTION)


2

C16-C18 0.0689 0.2215 0.1040 0.1916 0.1984 0.1837

C19-C23 0.0295 0.0280 0.1882 0.1169 0.0671 0.0859

C24-C29 0.0060 0.1714 0.0276 0.0124 0.0372

C30+WAX 0.0020 0.3213 0.0498 0.0203 0.0669

Oxygenates 0.0410 0.0293 0.0016 0.0073 0.0232 0.0199 0.0471

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3


StreamProduct Naphtha

Diesel Lean Oil Solvent

Product Diesel

Product Fractionator Bottoms

Product Diesel

Vacuum Column

Ohd. Li id

Hydrocracker Feed Liquid

Hydrocracker Makeup

H2

Temperature, °C 33 45 45 298 45 45 302 60

Pressure, bara 1.10 1.34 1.34 1.52 0.13 1.10 117.21 25.86


Mass Flow, kg/s 5.4 9.9 6.3 14.0 2.5 0.0 11.5 0.1

Enthalpy, kJ/h -1.010E+06 -1.703E+06 -1.075E+06 3.630E+07 3.444E+06 -2.359E+02 3.165E+07 1.731E+06

Mole Wt. 107.801 208.651 208.651 386.513 250.730 175.021 442.318 2.016


H2 0.0002 1.0000

N2

CO 0.0004

CO2 0.0029

H2O 0.0008 0.0012 0.0012 0.0068 0.0002 0.0012 0.0011

O2

C1 0.0003

C2's 0.0001

C3's 0.0003

C4's 0.0036

C5's 0.1009 0.0027

C6's 0.1488 0.0112

C7-C9 0.4719 0.0005 0.0005 0.0001 0.1977

C10-C12 0.2043 0.1450 0.1450 0.0013 0.0045 0.3059

C13-C15 0.0004 0.5066 0.5066 0.0256 0.0898 0.3048 0.0006



(MOLE FRACTION)


4

C16-C18 0.3081 0.3081 0.1818 0.5487 0.1503 0.0410

C19-C23 0.0386 0.0386 0.3096 0.3558 0.0209 0.2945

C24-C29 0.1695 0.0008 0.2361

C30+WAX 0.3056 0.4268


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


5

Plant SectionStream No. 17 18 19 20 21 22

StreamHydrocrack

er FeedHydrocracker Effluent

Hydrocracker Recycle

Gas

Hydrocracker Liquids

Hydrocracker Purge

Gas

Hydrocracker Flash Vapor

Temperature, °C 370 412 45 250 53 250

Pressure, bara 115.49 114.11 113.07 113.07 120.66 31.03

Molar Flow, kgmole/h 741.0 741.0 460.5 280.5 17.8 80.1

Mass Flow, kg/s 12.0 12.0 0.4 11.6 0.0 0.7

Enthalpy, kJ/h 5.310E+07 5.790E+07 3.816E+06 2.352E+07 1.522E+05 2.685E+06

Mole Wt. 58.400 58.405 3.350 148.769 3.350 33.685


H2 0.8516 0.6729 0.9629 0.1968 0.9629 0.5861

N2

CO

CO2

H2O 0.0004 0.0004 0.0005 0.0003 0.0005 0.0008

O2

C1 0.0070 0.0092 0.0117 0.0051 0.0117 0.0137

C2's 0.0039 0.0071 0.0065 0.0081 0.0065 0.0188

C3's 0.0051 0.0159 0.0085 0.0281 0.0085 0.0556

C4's 0.0041 0.0281 0.0068 0.0630 0.0068 0.1020

C5's 0.0013 0.0215 0.0021 0.0533 0.0021 0.0694

C6's 0.0003 0.0135 0.0004 0.0348 0.0004 0.0346

C7-C9 0.0002 0.0549 0.0005 0.1442 0.0005 0.0883

C10-C12 0.0263 0.0695 0.0151

C13-C15 0.0001 0.0453 0.1194 0.0096



(MOLE FRACTION)


6

C16-C18 0.0052 0.0523 0.1382 0.0045

C19-C23 0.0371 0.0318 0.0839 0.0012

C24-C29 0.0298 0.0075 0.0196

C30+WAX 0.0539 0.0135 0.0356

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg


16

7A-1 PROCESS DESCRIPTION The design basis and major assumptions for each major ISBL plant are presented in Sections 3 and 4A-

1. Area 100 - Syngas Generation Area 100 is the syngas generation area. This area consists of the following plants. Plant 101 Air Separation Unit Plant 102 Autothermal Reforming Plant The sulfur removal, heat recovery/steam generation, syngas cooling, and hydrogen recovery are parts of Plant 102, the Autothermal Reforming Plant. Plant 101, the Air Separation Unit, contains an inlet air compressor. The cryogenic air separation portion of Plant 101 produces a 99.5 mole % oxygen stream which is a feed stream to Plant 102, the Autothermal Reforming Plant. Plant 102, the Autothermal Reforming Plant, first removes trace amounts of sulfur compounds from the natural gas by reaction with zinc oxide. The desulfurized natural gas then is mixed with F-T section purge gas and steam before entering the autothermal reformer reactor where it is converted to syngas. The hot syngas product stream is cooled by steam generation, feed/effluent heat exchange, and cooling with ambient air. A slip stream of syngas is separated into hydrogen and residue gas streams in the PSA unit. Hydrogen is one of the feed streams to the hydrocracker. Plant 102 produces a combined synthesis gas steam having a molar H2:CO ratio of 2.04 which is sent to Area 200 for Fischer-Tropsch synthesis. The following subsections give a more detailed description on each of the process plants in Area 100, the Syngas Preparation Area.

17

Plant 101 - Air Separation Unit Plant 101, the Air Separation Unit, provides the required oxygen feed to Plant 102, the Autothermal Reforming Plant, for syngas generation. The air separation portion of Plant 101 is a standard cryogenic air separation unit. The air compressor and oxygen compressor are driven by steam turbines. The cryogenic air separation unit is a single train with a capacity of about 2,690 STPD of 99.5 mole % pure oxygen. The design incorporates a backup system including a liquid oxygen storage capacity of 2,700 tons. This backup oxygen storage system protects the facility from an unscheduled shutdown of one day or less. Process Description In the air separation section, ambient air is filtered and compressed in a two-stage axial centrifugal compressor with interstage cooling. The air from the final stage of compression enters a direct contact aftercooler where it contacts cooling water and chilled cooling water in two separate packed sections. The cooled air from the top of the aftercooler has lost the majority of its ambient water vapor. Removal of the residual water vapor, carbon dioxide and other atmospheric contaminants occurs in the molecular sieve adsorbers. The dry air enters the "cold box" where it is cooled to cryogenic temperature in the main heat exchangers and is separated into oxygen and nitrogen by cryogenic distillation. Final cooling is by expansion. The oxygen stream is further purified in an argon column to 99.5 mole %. The main heat exchangers are brazed aluminum, multipass, plate-fin units in which the entering air is cooled against the cold oxygen and nitrogen streams leaving the distillation columns. The oxygen product stream leaving the cryogenic separation section is warmed in the main heat exchangers and compressed to final delivery pressure in a centrifugal compressor. In order to insure a continuous supply of oxygen, backup storage systems are included in the design

18

Plant 102 - Autothermal Reforming The objective for Plant 102, the Autothermal Reforming Plant, is to provide a syngas with a H2:CO ratio of about 2.0 for F-T synthesis. The autothermal reactor (ATR) is designed to operate with the following feed ratios: H2O:C, mole/mole 0.65 CO2:C, mole/mole 0.10 O2:C, mole/mole 0.56 The adiabatic flame temperature of the ATR burner is less than 2,000°C. A process flow diagram of Plant 102, the Autothermal Reforming Plant, is shown in PFD 102-B-01. The natural gas feed is heated by heat exchange in 102E-3 before being desulfurized in the zinc oxide desulfurization vessel, 102R-1A/B. Sulfur is removed to the less than 0.1 ppm by volume, as required for the subsequent Fischer-Tropsch synthesis. The desulfurized natural gas is further heated in the fired feed preheater, 102F-1. MP steam, recycle purge gas from the F-T section, and overheads from the Prefractionator are mixed with the natural gas and then heated to 530°C. The autothermal reactor (102R-2) is a refractory-lined carbon steel vessel with an axially-fired burner and a packed bed of nickel-based high-temperature reforming catalyst. The autothermal reformer mixes the natural gas and oxygen streams in a turbulent diffusion flame in the reactor combustion zone. Additional homogeneous reactions take place in the thermal zone between burner and the catalyst bed. In the catalytic zone conversion of residual hydrocarbon to syngas occurs through heterogeneous catalytic reactions. The autothermal reforming reactor effluent is cooled in a series of heat exchangers, 102E-2A, 102E-2B, 102E-2C, and 102E-2, to produce 56 bar, 400°C superheated steam and preheat the incoming natural gas feed. Final cooling of the syngas to 60oC is accomplished in exchangers 102E-4, 102E-5, and air cooler 102E-6. The cooled syngas goes to flash drum 102C-3 where the condensed water is separated from the product syngas. Plant 102 - Hydrogen Separation High-purity hydrogen, a reactant in the hydrocracking process, is recovered from a slip stream of cooled syngas by a pressure swing adsorption (PSA) unit. Unlike the residue gas species (CO, CO2, CH4, and H2O), which strongly adsorb to the PSA sorbent, hydrogen is adsorbed in only small amounts as syngas flows through the PSA unit. Therefore, a high-purity hydrogen stream is obtained from the PSA unit outlet, while the balance of syngas components (residue gas) accumulates on the sorbent and is only removed as the vessel is de-pressurized when these species desorb into the regeneration gas stream. The syngas product has a molar H2:CO ratio of 2.04.

19

Area 200 - Fisher-Tropsch Synthesis and Product Upgrading Area 200 is the Fischer-Tropsch synthesis and product upgrading area. It consists of the following plants: Plant 201 Fischer-Tropsch Synthesis and Hydrocarbon Recovery Plant Plant 202 Product Fractionation & Wax Hydrocracking Plant This design is based on a slurry bubble-column reactor and a cobalt-based F-T synthesis catalyst with limited water-gas shift activity. The product fractionation and upgrading steps consist of standard fractionation technology and mild wax hydrocracking. The following subsections give a more detailed description on each of the process plants in Area 200, the Fischer-Tropsch Synthesis and Product Upgrading Area. Plant 201 - Fischer-Tropsch Synthesis The principle function of this plant is to convert the syngas produced in Area 100 into hydrocarbon products using a cobalt-catalyzed, slurry phase Fischer-Tropsch reactor. The reactor section of this plant consists of a single-stage slurry-bed reactor. There is no recycle of unconverted syngas directly back to the Fischer-Tropsch synthesis reactors. Instead part of the F-T purge gas leaving the hydrocarbon absorber is recycled to syngas generation plant where it mixes with the natural gas feed. Design Basis and Considerations The CO conversion in the SBCR is approximately 76%. In this design, the heat generated by the F-T synthesis reaction is removed by generation of 13 bar saturated steam in tubes suspended inside the reactor. The Fischer-Tropsch reactor is about 7.5 m diameter and about 30 m in height. The reactor contains about 1,400 tubes having a 65 mm OD for steam generation. Design superficial gas velocity is 0.18 m/s. The process flow diagrams for Plant 201, F-T synthesis, are shown in PFD 201-B-01. As shown in PFD 201-B-01, the syngas from Plant 102 after hydrogen recovery is heated with steam to 92°C before entering the F-T synthesis reactor (201R-1). Syngas is dispersed as bubbles into the catalyst/wax slurry using an inlet distributor. Churn-turbulent hydrodynamics are created inside the reactor by momentum transfer from the bubbles as they pass upward through the reactor. Syngas dissolves in the slurry phase and is converted into a distribution of varying carbon number hydrocarbon products at the catalyst interface. The slurry consists of solid catalyst particles suspended in the non-vaporizable portion of the product (i.e. the wax). The vaporizable portion of the product (hydrocarbon and water vapor) leaves the reactor with the unconverted syngas. The heat of reaction is removed by the generation of 191°C, 13 bar saturated steam within the reactor’s heat transfer tubes.

20

The overhead vapor stream leaving the reactor is ultimately cooled to 40°C in exchangers 201E-2, 201E-3, and 201E-4. As it’s being cooled the three-phase mixture is separated, using three-phase separators 201C-2 and 201C-3, into an unconverted syngas stream, liquid hydrocarbon streams, and water streams. The combined liquid hydrocarbon stream is sent directly to product fractionation and the water steams go to water treatment. A catalyst/wax slurry stream is withdrawn from the F-T reactor at reactor conditions. This stream is treated in the catalyst/wax separation unit to produce a catalyst-free wax stream and a recycle stream of catalyst/wax liquid, which is returned to the reactor. Syngas is used to activate the catalyst and supply the catalyst makeup requirement to the reactor. Plant 201 - Hydrocarbon Recovery A chilled lean oil absorption unit using a diesel recycle stream as the solvent is used to recover additional C5+ components in the F-T reactor effluent gas stream downstream of the cooling/recovery train. Rich solvent leaving the bottom of the absorber is fed to the product fractionation plant. Plant 202 - Product Fractionation The prefractionator, 202C-1, receives hydrocarbon liquids from the F-T cooling train section, rich solvent bottoms from the lean oil absorber, and hydrocarbon liquid recycle from the hydrocracker. Light non-condensable gases and C4- hydrocarbons are removed in the prefractionator prior to product fractionation. The prefractionator overhead stream is compressed and recycled to the syngas generation section where it is mixed with the natural gas feed. The product fractionator, 202C-3, separates the prefractionator bottoms and hot F-T liquid wax stream into an overhead liquid naphtha product and a diesel product, which is taken from the bottom of the product fractionator side-stripper. A small, light-hydrocarbon and non-condensable gases overhead stream is also separated. The overhead vapor stream is compressed and sent to the plant fuel system. The naphtha product has an ASTM D-86 end-point of 204°C. It is cooled and sent to storage. The diesel product (ASTM D-86 end-point 320°C) is cooled, dehydrated, and split into a lean oil recycle stream and a diesel product stream. Product fractionator bottoms is sent to the vacuum column, 202C-7. A diesel distillate is produced from the top pump-around section and a 350+°C boiling range gas oil is produced as bottoms. The diesel distillate has an ASTM D-86 end-point of 350°C. The gas oil stream is sent to the hydrocracker. Plant 202 - Wax Hydrocracking The Wax Hydrocracking Plant, catalytically cracks the F-T wax product under a hydrogen environment into lower-boiling material, mainly naphtha and diesel. A generic hydrocracking plant design has been

21

selected for this study. Hydrocracking occurs at about 370°C and between 100 and 150 bar under a hydrogen atmosphere in a single multi-bed reactor with inter-bed cooling by hydrogen-rich recycle gas. Vacuum column bottoms is pumped to the hydrocracker operating pressure, 115 bar. The vacuum column bottoms mixes with the recycle hydrogen stream and is preheated to the hydrocracker reactor inlet temperature, 370°C. The hydrocracked product is cooled from 412°C to 45°C. The hydrocracked liquid is flashed before being recycled to the prefractionator. The high-pressure gas stream is compressed and recycled to the reactor. A small purge gas stream is sent to the plant fuel system to prevent the buildup of inerts in the system. Flash vapor from hydrocracked liquid depressurization is sent to the lean oil absorber for hydrocarbon recovery.

22

Area 300 - Steam Distribution System HP superheated steam is raised in Plant 102 by heat recovery from the syngas generation unit. HP steam is used to drive the air separation unit air compressor. An extraction from the turbine at MP steam level (32 bar) is used to provide steam to the MP steam users. The turbine exhaust, at 1 bar, is condensed in an air cooler with a seawater trim cooler. Steam raised in the F-T reactor coils at 13 bar is superheated in fired heater, 201F-1, to 240°C. The steam is used to drive the air separation unit oxygen compressor and the plant steam turbine-driven electric power generator. The LP steam users are supplied with steam from the generator turbine exhaust. Excess LP steam is condensed in an air cooler with a seawater trim cooler.

23

8A-1 OFFSITES Following is a brief description of each offsites plant. Plant 19 - Relief and Blowdown -- Plant 19 is for the collection and flaring of relief and blowdown discharges from all applicable plants. It includes a flare system for all hydrocarbon containing discharges. Collection piping is not included in Plant 19 but has been included in Plant 21, Interconnecting Piping. Plant 20 - Tankage -- Plant 20 provides storage and delivery equipment for products, intermediates and chemicals. Thirty days storage is provided for the naphtha and distillate products. Intermediate storage is provided for the Wax Hydrocracking Plant. This storage is required to provide feedstock during plant startup and to mitigate the effect on operations due to brief interruptions in the upstream plants which could be the result of scheduled or unscheduled maintenance or due to operating problems. Plant 21 - Interconnecting Piping System -- Plant 21 includes the interconnecting process and utility piping between process plants and offsites. All above ground and underground piping systems are included except the cooling water piping which is included in Plant 32, Cooling Water Distribution, and the fire water piping which is included in Plant 33, Fire Systems. Relief and blowdown headers are included. In general, water distribution piping is underground and all other piping is located above ground on pipe racks. Storm sewers, sanitary sewer and process wastewater lines are not part of this plant but are included in Plant 34, Sewers and Wastewater Treating. Plant 22 - Product Shipping -- Plant 22 provides the pipeline, pumping and metering systems for delivery of the final hydrocarbon products. Separate systems are provided for each of the hydrocarbon products. Dual meters are provided to assure proper recording and product delivery. Plant 25 - Catalyst and Chemical Handling -- Plant 25 provides storage and handling for the catalyst and chemicals used in all the plants. Additionally, it provides a consolidated location for tracking catalyst and chemical start-up and daily consumption requirements. This plant includes an enclosed warehouse for storage and forklifts for transporting pallets into or out of the warehouse. Plant 30 - Electrical Distribution System -- Plant 30 provides the electrical distribution system from the high voltage switchyard to the consuming locations. Plant 32 - Raw, Cooling and Potable Water -- Plant 32 uses a once-through seawater system. Seawater is purchased from the Royal Commission. Supply pressure is low requiring installation of a seawater sump and seawater intake/circulation sump pumps to provide a controllable seawater supply and adequate pressure for the once-through cooling Because there is no cooling tower, the requirement for raw and service water is small.

24

Plant 33 - Fire Protection System -- A comprehensive fire water system is provided for general fire protection of the entire plant. Chemical and steam fire suppression systems are provided for specific facilities and equipment. These systems include

• Fire water to process plants, water and waste treatment, and tankage • Fireproofing for vessel supports, pipe racks, etc. • Sprinkler systems for buildings, parts of the process equipment such as pumps or heat exchangers (depending on the location). • Smothering steam for compressor buildings and fired heaters • Halogen system for computer room and laboratory

Plant 34 - Sewage and Effluent Water Treatment -- Plant 34 provides segregated waste water treatment for the purpose of minimizing both raw water consumption and effluent discharge to public waters during normal plant operation. Waste water streams are segregated on the basis of their compatibility and treated as necessary to make them suitable for reuse, if practical, in lieu of fresh water. The majority of the water used in the project eventually goes to the atmosphere as water vapor. Some water is disposed of as moisture associated with solid wastes. Blowdown streams (cooling tower, boilers and demineralizer) are sent to an intermediate holding pond before being discharged. Plant 34 contains the following treatment facilities

• Oily wastewater treatment • Process wastewater treatment • Solids dewatering • Sanitary sewage treatment

Plant 35 - Instrument and Plant Air Facilities -- Plant 35 includes all equipment necessary to supply instrument and utility air to the process plants and support facilities. The distribution piping is included in Plant 21, Interconnecting Piping. Instrument and utility air is dry, oil-free and dirt-free air that is supplied at 100 psig. It has a maximum dew point of -40oF. Plant 36 - Purge and Flush Oil System -- Plant 36 provides and delivers a light and heavy flush oil for pump seal flushing and instrument purging. Plant 37 - Solid Waste Management -- Plant 37 disposes of wastes from Plant 32 (Raw, Cooling and Potable Water), Plant 34 (Wastewater Treatment), and miscellaneous sources which include refuse and flotsam. All the solid waste, excluding the miscellaneous plant refuse, is stored in bins and hoppers, and collected daily to minimize on-site storage. Once collected, it is transported to an approved landfill disposal site outside the battery limits in trucks.

25

Plant 40 - General Site Preparation -- Site preparation involves leveling the land and adding basic improvements such as roads, fencing and drainage needed by the plant as a whole, and the placement of high load-bearing fills, pilings, spread footings and mat foundations for the plant structures in accordance with individual needs. Drainage of contaminated runoff from process and offsite areas is directed to ponds for treatment. Plant 41 - Buildings -- Five different types of buildings are provided for different usage. The type of construction selected for each building is dependent on its location with respect to potential hazards, its criticality for plant operation, and its function. The five types of buildings are classified as types A, B, C, D or Administrative according to the major construction features. Type A buildings are blast-proof and house critical equipment and/or instrumentation for the continuous operation of the plant. Type B buildings house the plant laboratory, cafeteria, medical building and change house. Type C buildings are steel-framed structures which serve a number of diverse functions which are generally plant operations or maintenance related. Type D buildings have masonry walls and structural steel-framed roofs and are used for transformer shelters and chemical storage. The administration building (which also contains the computer room) is identical in construction to a Type B building except that the exterior is finished with brick veneer masonry. Plant 42 - Telecommunications System -- Plant 42 includes the equipment and wiring for communication throughout the plant, to offsite locations linking plant data processing systems with offsite computing facilities, and for communication with transportation carriers. Plant 42 provides

• Interconnecting cables, standby emergency power and grounding • Remote computer access • Facsimile • Fire alarm • Public address paging • Medical emergency and life-signs telemetry • Interplant part paging • Land mobile radio • Radio paging • Security system • Telephone, telephone PABX

Plant 43 - Distributed Control System and Software -- Plant 43 provides for the distributed control system and operator interface in one central control system except for the shipping and loading facilities which are located at the shipping and loading building.

26

9A-1 PLANT COSTS Costs are reported in mid-1999 U.S. dollars. The capital cost estimate is based on a factored estimating technique. This technique is based on the observation that cost relationships (cost factors) exist between different components of the overall cost which can be derived from historical cost data for similar, previously built projects. ISBL equipment are sized and materials-of-construction are selected based on the particular process configuration, heat and energy balance calculations, and the conditions of the locally available utility streams. Given the size of the equipment items, Bechtel cost curves (regressions of historical size versus cost data) are used to identify equipment costs. Additional field costs, bulk materials, direct labor, indirect costs, etc., are developed based on cost factors mentioned above. Other field costs, such as sales tax, freight costs, duties, etc., are site specific and developed separately for each project. The Offsites cost estimate is developed from Bechtel in-house data for similar size and type plants in the same site location. The IEA Financial Assessment Criteria (see Appendix) was used to develop the costs for Home Office, Fees, and Services and Plant Contingency.

27

9A-1.1 Installed Plant Costs Table 9A-1.1 shows the capital cost breakdown for a Standard Sasol-Type, natural gas Fischer-Tropsch liquefaction plant

Table 9A-1.1

Capital Cost Estimate Natural Gas Fischer-Tropsch Liquefaction Plant

$1,000's 1. ISBL Equipment

Area 100 - Syngas Generation 90,025 Area 200 - F-T Synthesis & Product Upgrading 44,858 Area 300 - Steam & Power Generation 18,571 Total ISBL Cost 153,454

2. Total Offsite Cost (incl. freight, duty, indirects, etc.) 120,000

3. Total Field Cost (TFC) 273,454

4. Home Office, Fees, Services 41,018

5. Total Contractor's Cost (TCC) 314,472

6. Contingency 10% TCC 31,447

7. Total Project Cost $ 345,919

28

9A-1.2 Annual Operating Costs Table 9A-1.2 shows the annual operating costs for a Standard Sasol-Type, natural gas Fischer-Tropsch liquefaction plant.

Table 9A-1.2

Operating Cost Estimate Natural Gas Fischer-Tropsch Liquefaction Plant

COST ITEM QUANTITY UNIT $ PRICE ANNUAL

COST, $1,000's

Fixed Costs: Rent 50 acres $ 150 /acre/year $ 8 Taxes 1% of OCC* $ 3,145 Insurance 1% of OCC* $ 3,145 Operating Labor (excl. maint.) 48 people $ 50,000 /pers/annum $ 4,320 Maintenance (matl. & labor) 2% of OCC* $ 6,289 Misc. Supplies Corporate Overhead Total Fixed Costs $ 16,906

Variable Costs: Natural Gas 99,666 GJ/day $ 0.50 /GJ $ 18,189 Seawater 12,834 gpm $ 0.07 /1,000 gal $ 472 Desalinated Water 150 gpm $ 4.50 /1,000 gal $ 355 Electric Power 0 kWh $ 0.015 /kWh import $ - Catalyst & Chemicals $ 3,836 Other Operating Costs Annual Variable Costs $ 22,852 Load Factor 90% Actual Total Variable Costs $ 20,567 By-Product Credits Unit/D /Unit $ - Unit/D /Unit $ - Total By-Product Credits $ - Net Operating Costs $ 37,473

*OCC - Overnight Construction Cost (total field costs + contractor's charges)

29

4A-2 CO2 REDUCTION CASE – Standard Plant + CO2 Capture & Compression

30

DESIGN OBJECTIVE This plant design is an extension of the standard Sasol-type F-T natural gas Fischer-Tropsch liquefaction plant. The standard plant is to be adapted to capture any feed carbon which does not leave the plant as carbon in the F-T liquid product streams. Ordinarily, in the standard plant design, most of this non-product carbon would be emitted to the atmosphere as CO2, following complete combustion, incineration, or flaring. The intent of this design is capture, prior to emission, the non-product carbon as a single species – CO2 in this instance – and to deliver it in a ‘pure’ form, at high pressure to the plant battery limit. This study does not address the collection, transportation, and ultimate disposal/sequestration of this CO2 stream. The following sections identify the plant design, performance, efficiency, capital and operating costs, and product sales price associated with adopting CO2 capture and compression. Comparisons are made to the standard plant design, which is presented in sections 4A through 9A.

31

4A-2 DESIGN BASIS Plant Capacity 10,000 bpd combined Diesel/Naphtha production

Process Sasol – Slurry Phase Distillate Process



Syngas Generation oxygen-blown, autothermal natural gas reforming

- feed ratios:-


0.65 0.09 0.56



Hydrogen Separation N/A

- H2 purity

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




- CO conversion per pass 76%





32


CO2 Capture hydrogenation, HT-CO shift, MDEA CO2 removal

CO2 Compression compression to 110 bar

33

5A-2 OVERALL PLANT SUMMARY This section summarizes the overall plant performance and costs for a Sasol-Type, natural gas Fischer-Tropsch liquefaction plant with CO2 capture and compression facilities. Plant efficiency, carbon emissions, breakdown of product sales price, and capital and operating costs are summarized here. Table 5A-2.1 contains a summary of the major feed and product streams. The plant processes 100 MMSCF/day of natural gas and produces about 10,131 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-2.1 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 5.28 kg/s (4,063 Bbl/day) F-T Distillate 8.63 kg/s (6,068 Bbl/day) Power Import/Export 10.6 MW import Plant Thermal Efficiency


Carbon Emissions

Non-product, MT/y 48,263 as carbon

Figure 5A-2.1 is a block flow diagram of the main mass, energy, and carbon flows for the facility

34

17.4 MW

10.6 MW

0 MW

0.5 kg/s

94.3 kg/s

SyngasGeneration 64 kg/s

Steam TurbineDrives

& PowerGeneration

Pwr Gen = 6.8 MW

Air SeparationUnit

28.1 kg/s

Fuel Combustion


Water Treating40 kg/s

ProductUpgrading

& Fractionation

133.2

kg/s

Natural Gas

Figure 5A-2.1Mass, Energy, & Carbon Balance Summary

Sasol-Type Design - CO2 Capture & Compression

Air

Residue Gas

BFW60.6 kg/s

HP Steam,60.0 kg/s

MP Steam,84.2 kg/s

37.7 MW S/T Drivers


F-T Liquid






Effluent Water

QOUT= 0.119 TJ/h

QOUT= 0.13 TJ/h

QOUT= 0.145 TJ/h

QOUT= 0.533 TJ/h

QOUT= 0.182 TJ/h

Steam18.4 kg/s


19.4 kg/s 20.6 kg/s

H2

0.4 kg/s

0.11 kg/s

Recycle Gas0.6 kg/s

15.1 kg/s0.8 kg/s

BFW85.9 kg/s

F-T Synthesis

CO2 Capture CO2 Compression

CO2 to Pipeline

MOUT = 15.2 kg/sCarbon = 14,858 kg/h


Steam19.9 kg/s

3.9 kg/s16.5 kg/s

16.8 kg/s

H20.4 kg/s

QOUT= 0.346 TJ/h QOUT= 0.03 TJ/h

- Input

- Output

steam & processcondensate

35

Table 5A-2.2 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-2.2


Area Description Cost (MM$) $/GJ % ISBL 100 Syngas Preparation 85.0 45.9 200 F-T Synthesis/Upgrading 46.2 24.9 300 Steam Generation 22.7 12.3 500 CO2 Capture & Compression 31.3 16.9 Offsites Facilities 122.0 HO Service/Fees/Contingency 81.4 Total Cost: 388.6 (38,357 $/bpd) The above plant costs are order-of-magnitude ± 30% estimates. Table 5A-2.3 shows the annual operating cost summary.

Table 5A-2.3




Total Cost: 44.2

36

Table 5A-2.4 shows the breakdown of the product sales price.

Table 5A-2.4 Product Sales Price




- a 5% discount factor requires a 7.09% capital charge rate Section 9A-2 contains more detailed information on the capital and operating costs for the plant.

37

Table 5A-2.5 is a comparison between a standard Sasol-type F-T technology plant design and a Sasol-type F-T technology plant designed to include CO2 capture and compression. Table 5A-2.5 presents the cost and efficiency penalties attributable to the adoption of CO2 capture and compression.

Table 5A-2.5 Cost and Efficiency Comparison


Base Case CO2 Capture Plant Design Sasol-type Sasol-type
















38

6A-2 OVERALL PLANT CONFIGURATION This section presents an overall summary of standard Sasol-type Fischer-Tropsch synthesis technology. It is divided into two subsections: 6.1 Process Flow Diagrams 6.2 Mass and Energy Balance Tables

6A-2.1 Process Flow Diagrams This section contains the process flow diagrams (PFDs) for each process plant within Areas 100, 200, 300, and 500 in PFDs 102-B-01 through 501-B-01. Each PFD is numbered according to the plant number for the plants in Process Areas 100, 200, 300, 500. Area 100 contains two major plants: • Plant 101, the Air Separation Unit • Plant 102, the Autothermal Reforming Plant and H2 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: Area 500 contains the CO2 capture and compression plants: 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 6A-2.1 and 6A-2.2 in the following section.

39

6A-2.2 Mass and Energy Balance Tables The component flow rates of key streams in process Areas 100, 200, and 500 are shown in Tables 6A-2.2.1 and 6A-2.2.2 The streams are identified by the same stream numbers used in the PFDs shown in the previous section. Table 6A-2.2.1 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 100 200, and 500. Table 6A-2.2.2 contains the same information for the process streams in Areas 100, 200, and 500 except that stream composition is presented in mole fraction.


(MASS FRACTION)

SASOL-TYPE DESIGN: CO2 REDUCTION

1


StreamNatural

Gas FeedMP Steam Addition

F-T Syngas & Prefractn. O h d

Hydrocarbon Feed to

ATR

Oxygen from ASU

MP Steam Addition

Autothermal

Reformer Effl t

Syngas To F-T

Section

Temperature, °C 45 354 73 530 200 354 1005 60

Pressure, bara 32.75 31.03 32.41 30.06 28.96 31.03 27.92 26.27

Molar Flow, kgmole/h 4,980.7 3,409.0 2,648.9 11,038.6 3,168.1 256.6 22,104.7 18,227.1

Mass Flow, kg/s 23.6 17.1 13.3 54.0 28.1 1.3 83.4 64.0


Mole Wt. 17.086 18.015 18.018 17.597 31.980 18.015 13.580 12.634

Composition, Mass Frac.

H2 0.0545 0.0134 0.0756 0.0986

N2 0.0077 0.0193 0.0081 0.0044 0.0067 0.0088

CO 0.3287 0.0808 0.4994 0.6510

CO2 0.0113 0.4618 0.1184 0.1604 0.2087

H2O 1.0000 0.0021 0.3167 1.0000 0.2422 0.0125

O2 0.9956

C1 0.8871 0.0663 0.4049 0.0156 0.0204

C2's 0.0605 0.0051 0.0277

C3's 0.0221 0.0157 0.0135

C4's 0.0093 0.0302 0.0115

C5's 0.0020 0.0121 0.0039

C6's 0.0009 0.0002

C7-C9

C10-C12

C13-C15

C16-C18

SYNGAS GENERATION


(MASS FRACTION)


2

C19-C23

C24-C29

C30+WAX


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1

Plant SectionStream No. 1 3 4 5 6 7 8

Stream

ATR Syngas

This column is

blank intentionall

F-T Reactor

Feed Stream

F-T Reactor Vapor

Product

F-T Reactor Liquid

Product

HT Separator

F-T Liquids

HT separator

Vapor

LT Separator

F-T Liquids

Temperature, °C 60 92 220 220 155 155 40

Pressure, bara 26.27 26.17 24.72 24.72 24.24 24.24 23.82

Molar Flow, kgmole/h 18,227.1 18,227.1 10,160.0 89.5 29.7 7,942.1 91.8

Mass Flow, kg/s 64.0 64.0 54.9 9.1 1.7 42.3 3.1

Enthalpy, kJ/h 1.637E+08 1.814E+08 1.654E+08 1.640E+07 1.400E+06 1.072E+08 -4.519E+05

Mole Wt. 12.634 12.634 19.456 364.237 200.733 19.171 121.685


H2 0.0986 0.0986 0.0298 0.0001 0.0001 0.0387 0.0002

N2 0.0088 0.0088 0.0102 0.0001 0.0133 0.0001

CO 0.6510 0.6510 0.1820 0.0006 0.0011 0.2362 0.0022

CO2 0.2087 0.2087 0.2527 0.0017 0.0042 0.3276 0.0181

H2O 0.0125 0.0125 0.3751 0.0027 0.0031 0.2282 0.0002

O2

C1 0.0204 0.0204 0.0335 0.0002 0.0004 0.0435 0.0009

C2's 0.0021 0.0027 0.0002

C3's 0.0051 0.0003 0.0067 0.0019

C4's 0.0061 0.0001 0.0005 0.0081 0.0070

C5's 0.0069 0.0002 0.0011 0.0091 0.0198

C6's 0.0076 0.0004 0.0023 0.0097 0.0501

C7-C9 0.0243 0.0037 0.0282 0.0304 0.3350

C10-C12 0.0232 0.0130 0.1264 0.0253 0.3403

C13-C15 0.0181 0.0363 0.3007 0.0118 0.1592

F-T SYNTHESIS


(MASS FRACTION)


2

C16-C18 0.0104 0.0682 0.2821 0.0025 0.0347

C19-C23 0.0054 0.1537 0.1740 0.0003 0.0042

C24-C29 0.0014 0.1770 0.0479 0.0001

C30+WAX 0.0008 0.5417 0.0263

Oxygenates 0.0048 0.0002 0.0014 0.0061 0.0258

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3


StreamLT

Separator Vapor

F-T liquids to

Fractionati



Lean Solvent Feed

Rich Solvent

Absorber Overheads

Purge Gas to Fuel

Temperature, °C 40 83 220 206 45 41 27 27

Pressure, bara 23.82 23.82 24.72 31.03 1.34 22.41 22.06 22.06


Mass Flow, kg/s 29.6 4.8 9.1 0.8 9.9 11.1 29.1 16.5


Mole Wt. 17.945 141.017 364.237 28.399 208.624 171.849 17.581 17.581


H2 0.0552 0.0001 0.0001 0.0238 0.0001 0.0568 0.0568

N2 0.0189 0.0001 0.0246 0.0001 0.0199 0.0199

CO 0.3371 0.0018 0.0006 0.0016 0.3424 0.3424

CO2 0.4648 0.0133 0.0017 0.0124 0.4682 0.4682

H2O 0.0037 0.0012 0.0027 0.0636 0.0001 0.0001 0.0020 0.0020

O2

C1 0.0620 0.0007 0.0002 0.1365 0.0006 0.0666 0.0666

C2's 0.0038 0.0002 0.0240 0.0001 0.0045 0.0045

C3's 0.0093 0.0013 0.0807 0.0012 0.0113 0.0113

C4's 0.0107 0.0047 0.0001 0.1713 0.0041 0.0141 0.0141

C5's 0.0108 0.0134 0.0002 0.1344 0.0115 0.0104 0.0104

C6's 0.0087 0.0334 0.0004 0.0708 0.0258 0.0010 0.0010

C7-C9 0.0084 0.2283 0.0037 0.1970 0.0002 0.0368

C10-C12 0.0004 0.2658 0.0130 0.0367 0.1173 0.1083

C13-C15 0.2084 0.0363 0.0230 0.4828 0.4321

C16-C18 0.1207 0.0682 0.0104 0.3499 0.3126

F-T SYNTHESIS


(MASS FRACTION)


4

C19-C23 0.0633 0.1537 0.0031 0.0498 0.0445

C24-C29 0.0168 0.1770 0.0001 0.0001

C30+WAX 0.0092 0.5417 0.0001

Oxygenates 0.0059 0.0173 0.0002 0.0081 0.0030 0.0030

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


5

Plant SectionStream No. 17

StreamPurge Gas Recycle to

ATR

Temperature, °C 27





Mole Wt. 17.581


H2 0.0568

N2 0.0199

CO 0.3424

CO2 0.4682

H2O 0.0020

O2

C1 0.0666

C2's 0.0045

C3's 0.0113

C4's 0.0141

C5's 0.0104

C6's 0.0010

C7-C9

C10-C12

C13-C15

C16-C18

F-T SYNTHESIS


(MASS FRACTION)


6

C19-C23

C24-C29

C30+WAX

Oxygenates 0.0030

Total 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1


Stream

F-T Liquids Rich Solvent

F-T "Wax" Liquids


Stream


Prefractn. Bottoms

Product Fractionato

r Feed

Product Fractionato

r Overheads

Temperature, °C 83 41 220 206 43 332 362 33

Pressure, bara 23.82 22.41 24.72 31.03 13.79 14.13 1.72 1.10


Mass Flow, kg/s 4.8 11.1 9.1 10.9 0.6 26.1 35.2 0.0


Mole Wt. 141.017 171.849 364.237 187.979 37.182 188.369 215.116 31.602


H2 0.0001 0.0001 0.0001 0.0002 0.0069 0.0193

N2 0.0001 0.0001 0.0003 0.0070 0.0081

CO 0.0018 0.0016 0.0006 0.0434 0.0002 0.1444

CO2 0.0133 0.0124 0.0017 0.3292 0.0004 0.2643

H2O 0.0012 0.0001 0.0027 0.0017 0.0033 0.0007 0.0253

O2

C1 0.0007 0.0006 0.0002 0.0024 0.0593 0.0343

C2's 0.0002 0.0001 0.0008 0.0184 0.0021

C3's 0.0013 0.0012 0.0043 0.1084 0.0041

C4's 0.0047 0.0041 0.0001 0.0151 0.3658 0.0004 0.0003 0.0200

C5's 0.0134 0.0115 0.0002 0.0187 0.0495 0.0140 0.0104 0.2231

C6's 0.0334 0.0258 0.0004 0.0160 0.0002 0.0237 0.0177 0.1157

C7-C9 0.2283 0.0368 0.0037 0.0990 0.0985 0.0741 0.0728

C10-C12 0.2658 0.1083 0.0130 0.0748 0.1256 0.0967 0.0020



(MASS FRACTION)


2

C13-C15 0.2084 0.4321 0.0363 0.1667 0.2911 0.2255

C16-C18 0.1207 0.3126 0.0682 0.2343 0.2525 0.2051

C19-C23 0.0633 0.0445 0.1537 0.1626 0.0983 0.1124

C24-C29 0.0168 0.0001 0.1770 0.0514 0.0245 0.0636

C30+WAX 0.0092 0.5417 0.1517 0.0648 0.1876

Oxygenates 0.0173 0.0081 0.0002 0.0086 0.0064 0.0048 0.0645

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3




Product Diesel


Product Diesel

Vacuum Column

Ohd.


Hydrocracker Makeup

H2Temperature, °C 33 45 45 297 45 45 302 45

Pressure, bara 1.10 1.34 1.34 1.52 0.13 1.10 117.21 17.93


Mass Flow, kg/s 5.3 9.9 6.1 13.8 2.5 0.0 11.3 0.4


Mole Wt. 108.042 208.624 208.624 386.347 250.715 175.389 442.315 5.825


H2 0.2868

N2 0.0743

CO 0.0001 0.1919

CO2 0.0011 0.0242

H2O 0.0001 0.0001 0.0001 0.0003 0.0001 0.0114

O2

C1 0.0001 0.2479

C2's 0.0241

C3's 0.0001 0.0430

C4's 0.0020 0.0535

C5's 0.0679 0.0012 0.0392

C6's 0.1174 0.0053 0.0035

C7-C9 0.4921 0.0002 0.0002 0.1317 0.0001

C10-C12 0.2867 0.1173 0.1173 0.0006 0.0030 0.2762 0.0001

C13-C15 0.0008 0.4828 0.4828 0.0137 0.0736 0.3448 0.0002



(MASS FRACTION)


4

C16-C18 0.3499 0.3499 0.1161 0.5372 0.2060 0.0231

C19-C23 0.0498 0.0498 0.2288 0.3851 0.0323 0.1946

C24-C29 0.0001 0.0001 0.1623 0.0012 0.1980

C30+WAX 0.4781 0.5839


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


5


StreamHydrocrack



Gas


Hydrocracker Purge

Gas


Temperature, °C 370 426 45 205 52 206

Pressure, bara 115.49 114.11 113.07 113.07 120.66 31.03


Mass Flow, kg/s 12.6 12.6 0.9 11.7 0.1 0.8


Mole Wt. 61.158 63.182 7.872 135.681 7.872 28.399


H2 0.0216 0.0141 0.1761 0.0018 0.1761 0.0238

N2 0.0119 0.0119 0.1425 0.0019 0.1425 0.0246

CO 0.0068

CO2 0.0009

H2O 0.0006 0.0057 0.0031 0.0059 0.0031 0.0636

O2

C1 0.0405 0.0453 0.4889 0.0116 0.4889 0.1365

C2's 0.0031 0.0047 0.0349 0.0024 0.0349 0.0240

C3's 0.0052 0.0129 0.0563 0.0096 0.0563 0.0807

C4's 0.0057 0.0282 0.0582 0.0259 0.0582 0.1713

C5's 0.0029 0.0264 0.0240 0.0266 0.0240 0.1344

C6's 0.0005 0.0188 0.0065 0.0198 0.0065 0.0708

C7-C9 0.0005 0.0989 0.0091 0.1058 0.0091 0.1970

C10-C12 0.0671 0.0004 0.0721 0.0004 0.0367

C13-C15 0.0002 0.1458 0.1568 0.0230



(MASS FRACTION)


6

C16-C18 0.0209 0.2035 0.2190 0.0104

C19-C23 0.1752 0.1410 0.1518 0.0031

C24-C29 0.1782 0.0445 0.0477

C30+WAX 0.5254 0.1313 0.1413 0.0001

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1


StreamF-T

Syngas Purge

Hydrotreater Inlet

Hydrotreater Effluent

MP Steam Addition

CO Shift Inlet

CO2 Absorber

Feed

CO2 Absorber Treated

G

Lean Amine

Temperature, °C 27 270 295 325 340 45 45 111

Pressure, bara 22.06 21.17 20.48 28.96 20.20 18.27 17.93 2.00

Molar Flow, kgmole/h 3,370.1 3,370.1 3,349.8 3,984.6 7,334.3 3,975.3 2,713.4 74,658.4

Mass Flow, kg/s 16.5 16.5 16.5 19.9 36.4 19.6 4.4 505.6


Mole Wt. 17.581 17.581 17.688 18.015 17.866 17.721 5.825 24.38


H2 0.0568 0.0568 0.0560 0.0253 0.0647 0.2868

N2 0.0199 0.0199 0.0199 0.0090 0.0167 0.0743

CO 0.3424 0.3424 0.3424 0.1548 0.0433 0.1919

CO2 0.4682 0.4682 0.4682 0.2117 0.7764 0.0242 0.0099

H2O 0.0020 0.0020 0.0032 1.0000 0.5493 0.0061 0.0114 0.6896

O2

C1 0.0666 0.0666 0.0666 0.0301 0.0560 0.2479

C2's 0.0045 0.0045 0.0065 0.0029 0.0054 0.0241

C3's 0.0113 0.0113 0.0116 0.0052 0.0097 0.0430

C4's 0.0141 0.0141 0.0143 0.0064 0.0120 0.0535

C5's 0.0104 0.0104 0.0105 0.0048 0.0088 0.0392

C6's 0.0010 0.0010 0.0009 0.0004 0.0008 0.0035

C7-C9 0.0001

C10-C12 0.0001

C13-C15

C16-C18

CO2 CAPTURE & COMPRESSION


(MASS FRACTION)


2

C19-C23

C24-C29

C30+WAX


Amine 0.3006

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant SectionStream No. 9 10 11 12

StreamRich

AmineCaptured CO2 to

Compressi

Fuel Gas Stream

H2 to Hydrocrack

erTemperature, °C 80 45 45 45

Pressure, bara 4.14 1.10 17.93 17.93

Molar Flow, kgmole/h 75,970.2 1,261.9 2,439.4 273.9

Mass Flow, kg/s 521.1 15.2 3.9 0.4

Enthalpy, kJ/h -1.770E+09 1.331E+07 2.029E+07 2.278E+06

Mole Wt. 24.69 43.300 5.825 5.825


H2 0.0004 0.2868 0.2868

N2 0.0001 0.0743 0.0743

CO 0.0003 0.1919 0.1919

CO2 0.0385 0.9940 0.0242 0.0242

H2O 0.6698 0.0046 0.0114 0.0114

O2

C1 0.0005 0.2479 0.2479

C2's 0.0241 0.0241

C3's 0.0001 0.0430 0.0430

C4's 0.0535 0.0535

C5's 0.0392 0.0392

C6's 0.0035 0.0035

C7-C9 0.0001 0.0001

C10-C12 0.0001 0.0001

C13-C15

C16-C18



(MASS FRACTION)


4

C19-C23

C24-C29

C30+WAX

Oxygenates

Amine 0.2917

Total 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

Stream

Natural Gas Feed

MP Steam Addition

F-T Syngas & Prefractn. Overheads

Hydrocarbon Feed to

ATR

Oxygen from ASU

MP Steam Addition

Autothermal

Reformer Effluent

Syngas To F-T Section

Temperature, °C 45 354 73 530 200 354 1005 60

Pressure, bara 32.75 31.03 32.41 30.06 28.96 31.03 27.92 26.27

Molar Flow, kgmole/h 4,980.7 3,409.0 2,648.9 11,038.6 3,168.1 256.6 22,104.7 18,227.1

Mass Flow, kg/s 23.6 17.1 13.3 54.0 28.1 1.3 83.4 64.0


Mole Wt. 17.086 18.015 18.018 17.597 31.980 18.015 13.580 12.634


H2 0.4869 0.1169 0.5093 0.6176

N2 0.0047 0.0124 0.0051 0.0050 0.0033 0.0040

CO 0.2114 0.0507 0.2421 0.2936

CO2 0.0044 0.1891 0.0473 0.0495 0.0599

H2O 1.0000 0.0021 0.3093 1.0000 0.1826 0.0088

O2 0.9950

C1 0.9448 0.0744 0.4441 0.0132 0.0161

C2's 0.0344 0.0031 0.0163

C3's 0.0086 0.0066 0.0054

C4's 0.0028 0.0095 0.0035

C5's 0.0004 0.0031 0.0009

C6's 0.0002

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29

C30+WAX


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg


SYNGAS GENERATION


(MOLE FRACTION)


1

Plant Section

Stream No. 1 3 4 5 6 7 8

Stream

ATR Syngas

This column is

blank intentionall

F-T Reactor

Feed Stream

F-T Reactor Vapor

Product

F-T Reactor Liquid

Product

HT Separator

F-T Liquids

HT separator

Vapor

LT Separator

F-T Liquids

Temperature, °C 60 92 220 220 155 155 40

Pressure, bara 26.27 26.17 24.72 24.72 24.24 24.24 23.82

Molar Flow, kgmole/h 18,227.1 18,227.1 10,160.0 89.5 29.7 7,942.1 91.8

Mass Flow, kg/s 64.0 64.0 54.9 9.1 1.7 42.3 3.1

Enthalpy, kJ/h 1.637E+08 1.814E+08 1.654E+08 1.640E+07 1.400E+06 1.072E+08 -4.519E+05

Mole Wt. 12.634 12.634 19.456 364.237 200.733 19.171 121.685


H2 0.6176 0.6176 0.2875 0.0141 0.0124 0.3677 0.0093

N2 0.0040 0.0040 0.0071 0.0004 0.0004 0.0091 0.0005

CO 0.2936 0.2936 0.1264 0.0079 0.0081 0.1617 0.0094

CO2 0.0599 0.0599 0.1117 0.0140 0.0190 0.1427 0.0501

H2O 0.0088 0.0088 0.4051 0.0539 0.0343 0.2428 0.0011

O2

C1 0.0161 0.0161 0.0406 0.0037 0.0044 0.0520 0.0072

C2's 0.0013 0.0002 0.0003 0.0018 0.0010

C3's 0.0024 0.0006 0.0010 0.0030 0.0055

C4's 0.0021 0.0008 0.0019 0.0027 0.0149

C5's 0.0019 0.0013 0.0030 0.0024 0.0340

C6's 0.0017 0.0018 0.0055 0.0022 0.0712

C7-C9 0.0041 0.0118 0.0478 0.0052 0.3569

C10-C12 0.0030 0.0298 0.1593 0.0032 0.2686

C13-C15 0.0018 0.0662 0.3032 0.0010 0.0999

C16-C18 0.0009 0.1029 0.2376 0.0002 0.0179

C19-C23 0.0003 0.1892 0.1217 0.0018

C24-C29 0.1737 0.0264

C30+WAX 0.3260 0.0087

Oxygenates 0.0018 0.0016 0.0045 0.0023 0.0505

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole


F-T SYNTHESIS


(MOLE FRACTION)


2

Plant Section

Stream No. 9 10 11 12 13 14 15 16

Stream

LT Separator

Vapor

F-T liquids to

Fractionation



Lean Solvent Feed

Rich Solvent

Absorber Overheads

Purge Gas to Fuel

Temperature, °C 40 83 220 206 45 41 27 27

Pressure, bara 23.82 23.82 24.72 31.03 1.34 22.41 22.06 22.06


Mass Flow, kg/s 29.6 4.8 9.1 0.8 9.9 11.1 29.1 16.5


Mole Wt. 17.945 141.017 364.237 28.399 208.624 171.849 17.581 17.581


H2 0.4914 0.0101 0.0141 0.3353 0.0094 0.4952 0.4952

N2 0.0121 0.0004 0.0004 0.0249 0.0005 0.0125 0.0125

CO 0.2160 0.0091 0.0079 0.0098 0.2149 0.2149

CO2 0.1895 0.0425 0.0140 0.0483 0.1870 0.1870

H2O 0.0037 0.0092 0.0539 0.1002 0.0012 0.0009 0.0020 0.0020

O2

C1 0.0693 0.0065 0.0037 0.2417 0.0067 0.0730 0.0730

C2's 0.0023 0.0009 0.0002 0.0227 0.0009 0.0027 0.0027

C3's 0.0039 0.0043 0.0006 0.0519 0.0046 0.0047 0.0047

C4's 0.0034 0.0118 0.0008 0.0837 0.0125 0.0043 0.0043

C5's 0.0027 0.0265 0.0013 0.0529 0.0278 0.0025 0.0025

C6's 0.0018 0.0552 0.0018 0.0233 0.0519 0.0002 0.0002

C7-C9 0.0014 0.2814 0.0118 0.0516 0.0005 0.0590

C10-C12 0.2420 0.0298 0.0068 0.1446 0.1105

C13-C15 0.1496 0.0662 0.0033 0.5074 0.3740

C16-C18 0.0717 0.1029 0.0012 0.3080 0.2265

C19-C23 0.0312 0.1892 0.0003 0.0383 0.0283

C24-C29 0.0065 0.1737

C30+WAX 0.0021 0.3260

Oxygenates 0.0023 0.0392 0.0016 0.0279 0.0011 0.0011

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole


F-T SYNTHESIS


(MOLE FRACTION)


3

Plant Section

Stream No. 17

Stream

Purge Gas Recycle to

ATR

Temperature, °C 27





Mole Wt. 17.581


H2 0.4952

N2 0.0125

CO 0.2149

CO2 0.1870

H2O 0.0020

O2

C1 0.0730

C2's 0.0027

C3's 0.0047

C4's 0.0043

C5's 0.0025

C6's 0.0002

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates 0.0011

Total 1.0000

LHV Dry Basis*:

kJ/kgmole


F-T SYNTHESIS


(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

Stream

F-T Liquids Rich Solvent

F-T "Wax" Liquids


Stream


Prefractn. Bottoms

Product Fractionato

r Feed

Product Fractionato

r OverheadsTemperature, °C 83 41 220 206 43 332 362 33

Pressure, bara 23.82 22.41 24.72 31.03 13.79 14.13 1.72 1.10


Mass Flow, kg/s 4.8 11.1 9.1 10.9 0.6 26.1 35.2 0.0


Mole Wt. 141.017 171.849 364.237 187.979 37.182 188.369 215.116 31.602


H2 0.0101 0.0094 0.0141 0.0196 0.1271 0.0021 0.3026

N2 0.0004 0.0005 0.0004 0.0018 0.0093 0.0001 0.0091

CO 0.0091 0.0098 0.0079 0.0576 0.0012 0.1630

CO2 0.0425 0.0483 0.0140 0.2781 0.0021 0.1898

H2O 0.0092 0.0009 0.0539 0.0172 0.0068 0.0082 0.0444

O2

C1 0.0065 0.0067 0.0037 0.0276 0.1375 0.0006 0.0675

C2's 0.0009 0.0009 0.0002 0.0049 0.0228 0.0023

C3's 0.0043 0.0046 0.0006 0.0184 0.0922 0.0001 0.0031

C4's 0.0118 0.0125 0.0008 0.0489 0.2356 0.0013 0.0012 0.0109

C5's 0.0265 0.0278 0.0013 0.0487 0.0259 0.0366 0.0312 0.0985

C6's 0.0552 0.0519 0.0018 0.0350 0.0001 0.0522 0.0446 0.0429

C7-C9 0.2814 0.0590 0.0118 0.1658 0.1652 0.1419 0.0220

C10-C12 0.2420 0.1105 0.0298 0.0888 0.1475 0.1296 0.0004

C13-C15 0.1496 0.3740 0.0662 0.1566 0.2762 0.2442

C16-C18 0.0717 0.2265 0.1029 0.1824 0.1994 0.1845

C19-C23 0.0312 0.0283 0.1892 0.1110 0.0671 0.0857

C24-C29 0.0065 0.1737 0.0262 0.0125 0.0372

C30+WAX 0.0021 0.3260 0.0471 0.0202 0.0667

Oxygenates 0.0392 0.0279 0.0016 0.0070 0.0217 0.0187 0.0436

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg




(MOLE FRACTION)


2

Plant Section

Stream No. 9 10 11 12 13 14 15 16

Stream

Product Naphtha


Product Diesel


Product Diesel

Vacuum Column

Ohd. Liquid


Hydrocracker Makeup

H2

Temperature, °C 33 45 45 297 45 45 302 45

Pressure, bara 1.10 1.34 1.34 1.52 0.13 1.10 117.21 17.93


Mass Flow, kg/s 5.3 9.9 6.1 13.8 2.5 0.0 11.3 0.4


Mole Wt. 108.042 208.624 208.624 386.347 250.715 175.389 442.315 5.825


H2 0.0003 0.8286

N2 0.0154

CO 0.0003 0.0399

CO2 0.0027 0.0032

H2O 0.0008 0.0012 0.0012 0.0068 0.0002 0.0012 0.0011 0.0037

O2

C1 0.0004 0.0900

C2's 0.0001 0.0047

C3's 0.0003 0.0057

C4's 0.0038 0.0054

C5's 0.1023 0.0029 0.0031

C6's 0.1482 0.0109 0.0002

C7-C9 0.4735 0.0005 0.0005 0.0001 0.1953

C10-C12 0.2053 0.1446 0.1446 0.0013 0.0044 0.3049

C13-C15 0.0004 0.5074 0.5074 0.0256 0.0899 0.3072 0.0006

C16-C18 0.3080 0.3080 0.1824 0.5492 0.1517 0.0408

C19-C23 0.0383 0.0383 0.3095 0.3553 0.0210 0.2946

C24-C29 0.1691 0.0008 0.2361

C30+WAX 0.3052 0.4268


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg




(MOLE FRACTION)


3

Plant Section

Stream No. 17 18 19 20 21 22

Stream

Hydrocracker Feed

Hydrocracker Effluent


Gas


Hydrocracker Purge

Gas


Temperature, °C 370 426 45 205 52 206

Pressure, bara 115.49 114.11 113.07 113.07 120.66 31.03


Mass Flow, kg/s 12.6 12.6 0.9 11.7 0.1 0.8


Mole Wt. 61.158 63.182 7.872 135.681 7.872 28.399


H2 0.6544 0.4433 0.6877 0.1230 0.6877 0.3353

N2 0.0259 0.0268 0.0400 0.0094 0.0400 0.0249

CO 0.0148

CO2 0.0012

H2O 0.0022 0.0200 0.0014 0.0444 0.0014 0.1002

O2

C1 0.1545 0.1784 0.2399 0.0978 0.2399 0.2417

C2's 0.0063 0.0098 0.0091 0.0107 0.0091 0.0227

C3's 0.0072 0.0184 0.0100 0.0294 0.0100 0.0519

C4's 0.0060 0.0306 0.0079 0.0604 0.0079 0.0837

C5's 0.0025 0.0232 0.0026 0.0501 0.0026 0.0529

C6's 0.0004 0.0138 0.0006 0.0312 0.0006 0.0233

C7-C9 0.0004 0.0560 0.0006 0.1285 0.0006 0.0516

C10-C12 0.0268 0.0619 0.0068

C13-C15 0.0001 0.0461 0.1064 0.0033

C16-C18 0.0051 0.0533 0.1230 0.0012

C19-C23 0.0365 0.0323 0.0748 0.0003

C24-C29 0.0292 0.0075 0.0175

C30+WAX 0.0531 0.0137 0.0317

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg




(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

Stream

F-T Syngas Purge

Hydrotreater Inlet


MP Steam Addition

CO Shift Inlet

CO2 Absorber

Feed

CO2 Absorber Treated

Gas

Lean Amine

Temperature, °C 27 270 295 325 340 45 45 111

Pressure, bara 22.06 21.17 20.48 28.96 20.20 18.27 17.93 2.00

Molar Flow, kgmole/h 3,370.1 3,370.1 3,349.8 3,984.6 7,334.3 3,975.3 2,713.4 74,658.4

Mass Flow, kg/s 16.5 16.5 16.5 19.9 36.4 19.6 4.4 505.6


Mole Wt. 17.581 17.581 17.688 18.015 17.866 17.721 5.825 24.38


H2 0.4952 0.4952 0.4909 0.2242 0.5684 0.8286

N2 0.0125 0.0125 0.0126 0.0057 0.0106 0.0154

CO 0.2149 0.2149 0.2162 0.0988 0.0274 0.0399

CO2 0.1870 0.1870 0.1882 0.0859 0.3126 0.0032 0.0055

H2O 0.0020 0.0020 0.0032 1.0000 0.5447 0.0060 0.0037 0.9330

O2

C1 0.0730 0.0730 0.0734 0.0335 0.0619 0.0900

C2's 0.0027 0.0027 0.0038 0.0017 0.0032 0.0047

C3's 0.0047 0.0047 0.0046 0.0021 0.0039 0.0057

C4's 0.0043 0.0043 0.0044 0.0020 0.0036 0.0054

C5's 0.0025 0.0025 0.0026 0.0012 0.0022 0.0031

C6's 0.0002 0.0002 0.0002 0.0001 0.0001 0.0002

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29

C30+WAX


Amine 0.0615

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg




(MOLE FRACTION)


2

Plant Section

Stream No. 9 10 11 12

Stream

Rich Amine

Captured CO2 to

Compression

Fuel Gas Stream

H2 to Hydrocrack

er

Temperature, °C 80 45 45 45

Pressure, bara 4.14 1.10 17.93 17.93

Molar Flow, kgmole/h 75,970.2 1,261.9 2,439.4 273.9

Mass Flow, kg/s 521.1 15.2 3.9 0.4

Enthalpy, kJ/h -1.770E+09 1.331E+07 2.029E+07 2.278E+06

Mole Wt. 24.69 43.300 5.825 5.825


H2 0.0090 0.8286 0.8286

N2 0.0002 0.0154 0.0154

CO 0.0004 0.0399 0.0399

CO2 0.0216 0.9779 0.0032 0.0032

H2O 0.9179 0.0110 0.0037 0.0037

O2

C1 0.0014 0.0900 0.0900

C2's 0.0001 0.0047 0.0047

C3's 0.0001 0.0057 0.0057

C4's 0.0054 0.0054

C5's 0.0031 0.0031

C6's 0.0002 0.0002

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates

Amine 0.0604

Total 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



40

7A-2 PROCESS DESCRIPTION The design basis and major assumptions for each major ISBL plant are presented in Sections 3 and 4A-

2. Area 100 - Syngas Generation Area 100 is the syngas generation area. This area consists of the following plants. Plant 101 Air Separation Unit Plant 102 Autothermal Reforming Plant The sulfur removal, heat recovery/steam generation, and syngas cooling, are parts of Plant 102, the Autothermal Reforming Plant. Plant 101, the Air Separation Unit, contains an inlet air compressor. The cryogenic air separation portion of Plant 101 produces a 99.5 mole % oxygen stream which is a feed stream to Plant 102, the Autothermal Reforming Plant. Plant 102, the Autothermal Reforming Plant, first removes trace amounts of sulfur compounds from the natural gas by reaction with zinc oxide. The desulfurized natural gas then is mixed with F-T section purge gas and steam before entering the autothermal reformer reactor where it is converted to syngas. The hot syngas product stream is cooled by steam generation, feed/effluent heat exchange, and cooling with ambient air. Plant 102 produces a combined synthesis gas steam having a molar H2:CO ratio of 2.10 which is sent to Area 200 for Fischer-Tropsch synthesis. The following subsections give a more detailed description on each of the process plants in Area 100, the Syngas Preparation Area.

41

Plant 101 - Air Separation Unit Plant 101, the Air Separation Unit, provides the required oxygen feed to Plant 102, the Autothermal Reforming Plant, for syngas generation. The air separation portion of Plant 101 is a standard cryogenic air separation unit. The air compressor and oxygen compressor are driven by steam turbines. The cryogenic air separation unit is a single train with a capacity of about 2,680 STPD of 99.5 mole % pure oxygen. The design incorporates a backup system including a liquid oxygen storage capacity of 2,700 tons. This backup oxygen storage system protects the facility from an unscheduled shutdown of one day or less. Process Description In the air separation section, ambient air is filtered and compressed in a two-stage axial centrifugal compressor with interstage cooling. The air from the final stage of compression enters a direct contact aftercooler where it contacts cooling water and chilled cooling water in two separate packed sections. The cooled air from the top of the aftercooler has lost the majority of its ambient water vapor. Removal of the residual water vapor, carbon dioxide and other atmospheric contaminants occurs in the molecular sieve adsorbers. The dry air enters the "cold box" where it is cooled to cryogenic temperature in the main heat exchangers and is separated into oxygen and nitrogen by cryogenic distillation. Final cooling is by expansion. The oxygen stream is further purified in an argon column to 99.5 mole %. The main heat exchangers are brazed aluminum, multipass, plate-fin units in which the entering air is cooled against the cold oxygen and nitrogen streams leaving the distillation columns. The oxygen product stream leaving the cryogenic separation section is warmed in the main heat exchangers and compressed to final delivery pressure in a centrifugal compressor. In order to insure a continuous supply of oxygen, backup storage systems are included in the design

42

Plant 102 - Autothermal Reforming The objective for Plant 102, the Autothermal Reforming Plant, is to provide a syngas with a H2:CO ratio of about 2.0 for F-T synthesis. The autothermal reactor (ATR) is designed to operate with the following feed ratios: H2O:C, mole/mole 0.65 CO2:C, mole/mole 0.09 O2:C, mole/mole 0.56 The adiabatic flame temperature produced at the ATR burner is less than 2,000°C. A process flow diagram of Plant 102, the Autothermal Reforming Plant, is shown in PFD 102-B-01. The natural gas feed is heated by heat exchange in 102E-3 before being desulfurized in the zinc oxide desulfurization vessel, 102R-1A/B. Sulfur is removed to the less than 0.1 ppm by volume, as required for the subsequent Fischer-Tropsch synthesis. The desulfurized natural gas is further heated in the fired feed preheater, 102F-1. MP steam, recycle purge gas from the F-T section, and overheads from the Prefractionator are mixed with the natural gas and then heated to 530°C. The autothermal reactor (102R-2) is a refractory-lined carbon steel vessel with an axially-fired burner and a packed bed of nickel-based high-temperature reforming catalyst. The autothermal reformer mixes the natural gas and oxygen streams in a turbulent diffusion flame in the reactor combustion zone. Additional homogeneous reactions take place in the thermal zone between burner and the catalyst bed. In the catalytic zone conversion of residual hydrocarbon to syngas occurs through heterogeneous catalytic reactions. The autothermal reforming reactor effluent is cooled in a series of heat exchangers, 102E-2A, 102E-2B, 102E-2C, and 102E-2, to produce 56 bar, 400°C superheated steam and preheat the incoming natural gas feed. Final cooling of the syngas to 60oC is accomplished in exchangers 102E-4, 102E-5, and air cooler 102E-6. The cooled syngas goes to flash drum 102C-3 where the condensed water is separated from the product syngas.

43

Area 200 - Fisher-Tropsch Synthesis and Product Upgrading Area 200 is the Fischer-Tropsch synthesis and product upgrading area. It consists of the following plants: Plant 201 Fischer-Tropsch Synthesis and Hydrocarbon Recovery Plant Plant 202 Product Fractionation & Wax Hydrocracking Plant This design is based on a slurry bubble-column reactor and a cobalt-based F-T synthesis catalyst with limited water-gas shift activity. The product fractionation and upgrading steps consist of standard fractionation technology and mild wax hydrocracking. The following subsections give a more detailed description on each of the process plants in Area 200, the Fischer-Tropsch Synthesis and Product Upgrading Area. Plant 201 - Fischer-Tropsch Synthesis The principle function of this plant is to convert the syngas produced in Area 100 into hydrocarbon products using a cobalt-catalyzed, slurry phase Fischer-Tropsch reactor. The reactor section of this plant consists of a single-stage slurry-bed reactor. There is no recycle of unconverted syngas directly back to the Fischer-Tropsch synthesis reactors. Instead part of the F-T purge gas leaving the hydrocarbon absorber is recycled to syngas generation plant where it mixes with the natural gas feed. Design Basis and Considerations The CO conversion in the SBCR is approximately 76%. In this design, the heat generated by the F-T synthesis reaction is removed by generation of 13 bar saturated steam in tubes suspended inside the reactor. The Fischer-Tropsch reactor is about 7.5 m diameter and about 30 m in height. The reactor contains about 1,400 tubes having a 65 mm OD for steam generation. Design superficial gas velocity is 0.18 m/s. The process flow diagrams for Plant 201, F-T synthesis, are shown in PFD 201-B-01. As shown in PFD 201-B-01, the syngas from Plant 102 after hydrogen recovery is heated with steam to 92°C before entering the F-T synthesis reactor (201R-1). Syngas is dispersed as bubbles into the catalyst/wax slurry using an inlet distributor. Churn-turbulent hydrodynamics are created inside the reactor by momentum transfer from the bubbles as they pass upward through the reactor. Syngas dissolves in the slurry phase and is converted into a distribution of varying carbon number hydrocarbon products at the catalyst interface. The slurry consists of solid catalyst particles suspended in the non-vaporizable portion of the product (i.e. the wax). The vaporizable portion of the product (hydrocarbon and water vapor) leaves the reactor with the unconverted syngas. The heat of reaction is removed by the generation of 191°C, 13 bar saturated steam within the reactor’s heat transfer tubes.

44

The overhead vapor stream leaving the reactor is ultimately cooled to 40°C in exchangers 201E-2, 201E-3, and 201E-4. As it’s being cooled the three-phase mixture is separated, using three-phase separators 201C-2 and 201C-3, into an unconverted syngas stream, liquid hydrocarbon streams, and water streams. The combined liquid hydrocarbon stream is sent directly to product fractionation and the water steams go to water treatment. A catalyst/wax slurry stream is withdrawn from the F-T reactor at reactor conditions. This stream is treated in the catalyst/wax separation unit to produce a catalyst-free wax stream and a recycle stream of catalyst/wax liquid, which is returned to the reactor. Syngas is used to activate the catalyst and supply the catalyst makeup requirement to the reactor. Plant 201 - Hydrocarbon Recovery A chilled lean oil absorption unit using a diesel recycle stream as the solvent is used to recover additional C5+ components in the F-T reactor effluent gas stream downstream of the cooling/recovery train. Rich solvent leaving the bottom of the absorber is fed to the product fractionation plant. Plant 202 - Product Fractionation The prefractionator, 202C-1, receives hydrocarbon liquids from the F-T cooling train section, rich solvent bottoms from the lean oil absorber, and hydrocarbon liquid recycle from the hydrocracker. Light non-condensable gases and C4- hydrocarbons are removed in the prefractionator prior to product fractionation. The prefractionator overhead stream is compressed and recycled to the syngas generation section where it is mixed with the natural gas feed. The product fractionator, 202C-3, separates the prefractionator bottoms and hot F-T liquid wax stream into an overhead liquid naphtha product and a diesel product, which is taken from the bottom of the product fractionator side-stripper. A small, light-hydrocarbon and non-condensable gases overhead stream is also separated. The overhead vapor stream is compressed and sent to the plant fuel system. The naphtha product has an ASTM D-86 end-point of 204°C. It is cooled and sent to storage. The diesel product (ASTM D-86 end-point 320°C) is cooled, dehydrated, and split into a lean oil recycle stream and a diesel product stream. Product fractionator bottoms is sent to the vacuum column, 202C-7. A diesel distillate is produced from the top pump-around section and a 350+°C boiling range gas oil is produced as bottoms. The diesel distillate has an ASTM D-86 end-point of 350°C. The gas oil stream is sent to the hydrocracker. Plant 202 - Wax Hydrocracking The Wax Hydrocracking Plant, catalytically cracks the F-T wax product under a hydrogen environment into lower-boiling material, mainly naphtha and diesel. A generic hydrocracking plant design has been

45

selected for this study. Hydrocracking occurs at about 370°C and between 100 and 150 bar under a hydrogen atmosphere in a single multi-bed reactor with inter-bed cooling by hydrogen-rich recycle gas. Vacuum column bottoms is pumped to the hydrocracker operating pressure, 115 bar. The vacuum column bottoms mixes with the recycle hydrogen stream and is preheated to the hydrocracker reactor inlet temperature, 370°C. The hydrocracked product is cooled from 426°C to 45°C. The hydrocracked liquid is flashed before being recycled to the prefractionator. The high-pressure gas stream is compressed and recycled to the reactor. A small purge gas stream is sent to the plant fuel system to prevent the buildup of inerts in the system. Flash vapor from hydrocracked liquid depressurization is sent to the lean oil absorber for hydrocarbon recovery.

46

Area 300 - Steam Distribution System HP superheated steam is raised in Plant 102 by heat recovery from the syngas generation unit. HP steam is used to drive the air separation unit oxygen compressor. An extraction from the turbine at MP steam level (32 bar) is used to provide steam to the MP steam users. The turbine exhaust, at 1 bar, is condensed in an air cooler followed by a seawater trim cooler. Steam raised in the F-T reactor coils at 13 bar is superheated in fired heater, 201F-1, to 240°C. The steam is used to drive the air separation unit air compressor and the plant steam turbine-driven electric power generator. The LP steam users are supplied with steam from the generator turbine exhaust. Excess LP steam is condensed in an air cooler with a seawater trim cooler.

47

Area 500 - CO2 Capture and Compression Area 500 is the CO2 capture and compression area. It consists of the following plants: • Feed gas Hydrogenation and HT CO Shift • MDEA-based CO2 removal • CO2 compression

This design is based on converting CO in the F-T synthesis section purge gas to CO2 and then removing the CO2 from the gas stream using a chemical solvent. This produces a fuel/process stream containing 83 mol% H2. The H2-rich fuel stream is used to supply makeup hydrogen to the hydrocracker and as fuel for the various fuel-fired process heaters. The captured CO2 is released during solvent regeneration and is compressed to transport pipeline delivery pressure, 110 bar. The process flow diagram for Plant 500 is shown in PFD 201-B-01. Plant 500 - Hydrotreating & HT-CO Shift Purge gas from the F-T synthesis section, containing the bulk of the non-product carbon, is preheated to the hydrotreating temperature (270°C) by heat exchangers 501E-8 and 501E-9. Unsaturated hydrocarbons and oxygenates in the purge gas stream react with H2 to form their saturated hydrocarbon counterparts in the fixed-bed catalytic reactor, 501R-1. The effluent stream from 501R-1 is mixed with MP steam and the combined stream heated to 340°C before entering the HT-CO shift reactor, 501R-2. Iron-based catalyst in the shift reactor promotes the conversion of CO (21.7 mol%, dry gas basis) and steam to CO2 and H2, resulting in a reactor outlet CO concentration of 2.8 mol%, dry basis and an exit temperature of 425°C. The shift reactor effluent stream is cooled in exchangers 501E-10, 501E-11, 501E-1, and 501E-14. Part of the reboil duty for the CO2 Stripper, 501C-2, is provided from cooling the shift reactor effluent in exchanger 501E-11. Plant 500 - CO2 Removal A liquid chemical solvent - a 30 wt% aqueous solution of mono-diethanolamine (MDEA) - is used to remove CO2 from shift reactor effluent gas. The gas stream is contacted with solvent in the CO2 Absorber, 501C-1A/B - – two, identical vessels in parallel each containing a series of mixing trays. Regenerated solvent enters at the top of the vessel and leaves as rich solvent from the bottom. Shift reactor effluent gas enters at the bottom and leaves as a ‘CO2-free’ gas stream from the top. A gas-liquid dispersion is created on each tray as a result of turbulent mixing between phases. CO2 is transferred from the gas to the liquid phase by dissolving in the solvent and then reacting with active reagent. It leaves the vessel in the rich solvent stream, chemically bound to the active reagent, MDEA.

48

Heating and stripping the rich solvent in the CO2 Stripper, 501C-2, regenerates the solvent and releases CO2 back to the vapor phase. CO2 is separated from stripping steam in the CO2 stripper reflux drum, 501C-6. The CO2 stripper reboil duty is provided partly from waste heat in the shift reactor effluent stream and partly from LP steam. Regenerated solvent is cooled to its absorber feed temperature by heat exchangers 501E-2 and 501E-15. Plant 500 - CO2 Compression CO2, at 1.1 bar in the stripper reflux drum, is sent to CO2 compression, 501K-1. CO2 is compressed in four compression stages to 110 bar for delivery to the battery limit CO2 transport pipeline. The compression HP requirement is approximately 6 MW. To prevent downstream corrosion problems, the gas from the first compression stage is passed through a packed bed of sorbent material to remove moisture from the gas.

49

8A-2 OFFSITES The offsites plants for the CO2 capture and compression case are similar to those for the standard plant design.

50

9A-2 PLANT COSTS The same method of cost estimating as was used for the standard plant design is used for the CO2 capture and compression case. 9A-2.1 Installed Plant Costs Table 9A-2.1 shows the capital cost breakdown for a Sasol-Type, natural gas Fischer-Tropsch liquefaction plant with CO2 capture and compression facilities.

Table 9A-2.1


Capital Cost Summary


Area 100 - Syngas Generation 85,044 Area 200 - F-T Synthesis & Product Upgrading 46,200 Area 300 - Steam & Power Generation 22,730 Area 500 - CO2 Capture & Compression 31,213 Total ISBL

Cost 185,186







51

9A-2.2 Annual Operating Costs Table 9A-2.2 shows the annual operating costs for a Sasol-Type, natural gas Fischer-Tropsch liquefaction plant with CO2 capture and compression facilities.

Table 9A-2.1



COST, $1,000's

Fixed Costs: Rent 55 acres $ 150 /acre/year $ 8 Taxes 1% of OCC* $ 3,533 Insurance 1% of OCC* $ 3,533 Operating Labor (excl. maint.)

52 people $ 50,000 /pers/annum $ 4,680

Maintenance (matl. & labor) 2% of OCC* $ 7,065 Misc. Supplies Corporate Overhead Total Fixed

Costs $ 18,819

Variable Costs: Natural Gas 99,666 GJ/day $ 0.50 /GJ $ 18,189 Seawater 96,388 gpm $ 0.07 /1,000 gal $ 3,546 Desalinated Water 150 gpm $ 4.50 /1,000 gal $ 355 Electric Power 10,566 kWh $ 0.015 /kWh import $ 1,388 Catalyst & Chemicals $ 4,731 Other Operating Costs Annual Variable Costs $ 28,209 Load Factor 90% Actual Total Variable Costs $ 25,389 By-Product Credits Unit/D /Unit $ - Unit/D /Unit $ - Total By-Product Credits $ - Net Operating Costs $ 44,207

*OCC - Overnight Construction Cost (total field cost + contractor's costs)

52

4B SHELL MDS-TYPE F-T SYNTHESIS & PRODUCT UPGRADING 4B-1 BASE CASE – Standard Plant Design

53

4B-1 DESIGN BASIS

Plant Capacity

10,000 bpd combined diesel and naphtha production

Process Shell MDS (middle distillate synthesis)



Syngas Generation 1. Shell Gasification Process (SGP), oxygen-blown.

2. Steam-Natural Gas Reforming

SGP Partial Oxidation Feed ratios:-


0.14 0.01 0.62



Steam Reforming Feed ratios:-

- H2O:C, mole/mole1 - CO2:C, mole/mole1 - O2:C, mole/mole1

4.3 0.004 -

- exit conditions: pressure: 30.5 bar temperature: 880 °C


Hydrogen Separation pressure swing adsorption

- H2 purity > 99.5 mol%


54

F-T Synthesis Shell MDS - fixed-bed reactor design – multi-tubular trickle-bed reactor, ‘once-through’ operation, two-stage series design with interstage product recovery, cobalt F-T synthesis catalyst, internal heat recovery (steam raising)

- operating conditions pressure: 38 bar temperature: 235-238°C



- CO conversion per pass 70% 1st stage - (F-T synthesis and CO shift)

63% 2nd stage

89% overall





55

5B-1 OVERALL PLANT SUMMARY This section summarizes the overall plant performance and costs for a Standard Shell MDS-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 5B-1.1 contains a summary of the major feed and product streams. The plant processes 100 MMSCF/day of natural gas and produces about 10,464 BPD of F-T liquid products. The primary liquid products are naphtha blending stock and an ASTM D-86 350°C end-point diesel. Both products are essentially free of sulfur, nitrogen and oxygen containing compounds.

Table 5B-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 5.66 kg/s (4,371 Bbl/day) F-T Distillate 8.67 kg/s (6,093 Bbl/day) Power Import/Export 3.8 MW export Plant Thermal Efficiency



Note, sufficient electric power is generated onsite through the steam turbine-driven power generator to meet the facility’s normal operating power requirements. Figure 5B-1.1 is a block flow diagram of the main mass, energy, and carbon flows for the facility.

56

Fuel5.6 kg/s

QOUT= 0.095 TJ/h

0.1 kg/s

147.2 kg/s

20.8 kg/s 43.3 kg/s F-T Synthesis

Steam TurbineDrives

& PowerGeneration

Pwr Gen = 12 MW

Air SeparationUnit

26.6 kg/s

Fuel Combustion


13.51 kg/s


ProductUpgrading

& Fractionation

164.2

kg/s

0 MW

3.8 MW


8.2 MW

Natural Gas

Figure 5B-1.1Mass, Energy, & Carbon Balance Summary

Shell MDS-Type Design - Base Case

Air

Residue Gas

HP Steam,82.3 kg/s

MP Steam,94.4 kg/s

36.8 MW S/T Drivers


F-T Liquid





Effluent Water

QOUT= 0.041 TJ/h

QOUT= 0.125 TJ/h

QOUT= 1.28 TJ/h

QOUT= 0.171 TJ/h

Steam3.5 kg/s

8.7 kg/s

20.4 kg/s

H2

0.1 kg/s

0.09 kg/s

Recycle Gas1.1 kg/s

15.6 kg/s0.1 kg/s

H2

0.1 kg/s


Recycle Gas1.1 kg/s

2.8 kg/s

Steam13.5 kg/s

Fuel5.6 kg/s

Air33.93 kg/s

SyngasGeneration

Partial Oxdn.


BFW85 kg/s

BFW95.3 kg/s

SyngasGeneration

Steam Refm.

QOUT= 0.079 TJ/h

49.4 kg/s

6.1 kg/s

Fuel0.8 kg/s

0.8 kg/s

38.5 kg/s

- Input

- Output

steam & processcondensate

57

Table 5B-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 5B-1.2


Area Description Cost (MM$) $/GJ % ISBL 100 Syngas Preparation 120.8 64.3 200 F-T Synthesis/Upgrading 42.4 22.6 300 Steam Generation 24.7 13.1 Offsites Facilities 120.0 HO Service/Fees/Contingency 81.6 Total Cost: 389.5 (37,222 $/bpd) The above plant costs are order-of-magnitude ± 30% estimates. Table 5B-1.3 shows the annual operating cost summary.

Table 5B-1.3



Variable Costs 21.3 By-Product Revenue (0.4)

Total Cost: 39.4

58

Table 5B-1.4 shows the breakdown of the product sales price.

Table 5B-1.4 Product Sales Price




- a 5% discount factor requires a 7.09% capital charge rate Section 9 contains more detailed information on the capital and operating costs for the plant.

59

Table 5B-1.5 is a comparison between a standard Shell MDS-Type F-T technology plant design and a Shell MDS-Type F-T technology plant designed to include CO2 capture and compression. Table 5B-1.5 presents the cost and efficiency penalties attributable to the adoption of CO2 capture and compression.

Table 5B-1.5 Cost and Efficiency Comparison


"Base Case" "CO2 Capture"

Plant Design Shell MDS Shell MDS














$/Tonne Carbon captured $89.01

Figure 5B-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.

60

Figure 5B-1.2Sensitivity of Product Sales Price to Natural Gas Cost

Shell-Type F-T Technology

15

20

25

30

35

40

45

50

55

60

0 0.5 1 1.5 2 2.5 3 3.5


Dis

tilla

te F

OB

Sal

es P

rice,

$/b

b Standard Design


61

6B-1 OVERALL PLANT CONFIGURATION This section presents an overall summary of standard Shell MDS-Type Fischer-Tropsch synthesis technology. It is divided into two subsections: 6B-1.1 Process Flow Diagrams 6B-1.2 Mass and Energy Balance Tables

6B-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 Partial Oxidation, Steam Reforming, and H2 Separation Plants Area 200 contains two major plants: • Plant 201, the Shell MDS-Type 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 6B-1.1 and 6B-1.2 in the following section.

62

6B-1.2 Mass and Energy Balance Tables The component flow rates of key streams in process Areas 100, and 200 are shown in Tables 6B-1.2.1 and 6B-1.2.2. The streams are identified by the same stream numbers used in the PFDs shown in the previous section. Table 6B-1.1 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 6B-1.2 contains the same information for the process streams in Areas 100 and 200 except that stream composition is presented in mole fraction.

IEA GHG PROGRAM TABLE 6B-1.2.1 MASS AND ENERGY BALANCE

(MASS FRACTION)

SHELL-TYPE DESIGN: BASE CASE

1


StreamNatural

Gas FeedNatural

Gas FeedPrefraction

tor Overheads

Hydrocarbon Feed To POX

Oxygen from ASU

MP Steam Addition

POX Reactor Effluent

Syngas to F-T

SectionTemperature, °C 45 45 119 313 200 329 1318 60

Pressure, bara 43.44 43.44 42.75 42.75 41.37 42.00 40.33 38.47

Molar Flow, kgmole/h 4,980.7 996.1 107.6 898.1 2,995.3 691.2 2,864.5 12,588.8

Mass Flow, kg/s 23.6 4.7 1.1 4.4 26.6 3.5 10.4 43.3


Mole Wt. 17.086 17.086 37.658 17.579 31.980 18.015 13.069 12.388


H2 0.0080 0.0004 0.0822 0.0987

N2 0.0077 0.0077 0.0026 0.0075 0.0044 0.0054 0.0065

CO 0.0449 0.0023 0.6422 0.7708

CO2 0.0113 0.0113 0.3333 0.0278 0.0768 0.0921

H2O 0.0033 0.0002 1.0000 0.1745 0.0093

O2 0.9956

C1 0.8871 0.8871 0.0378 0.8435 0.0189 0.0227

C2's 0.0605 0.0605 0.0188 0.0583

C3's 0.0221 0.0221 0.1209 0.0272

C4's 0.0093 0.0093 0.3765 0.0282

C5's 0.0020 0.0020 0.0470 0.0043

C6's 0.0001

C7-C9

C10-C12

C13-C15

SYNGAS GENERATION


(MASS FRACTION)


2

C16-C18

C19-C23

C24-C29

C30+WAX


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15

StreamNatural Feed to

Reformer

MP Steam to

Reformer

Reformed Gas to F-T Synthesis

PSA Residue Gas to

H2 to Hydrocrack

er

Reformer Fuel Gas

Combined Syngas to

F-T Temperature, °C 319 329 84 40 47 45 64

Pressure, bara 31.03 42.00 39.02 1.50 27.50 3.00 38.47

Molar Flow, kgmole/h 597.7 2,689.6 2,227.4 130.1 193.7 1,021.0 14,816.2

Mass Flow, kg/s 2.8 13.5 6.1 0.8 0.1 5.6 49.4

Enthalpy, kJ/h 1.390E+07 5.100E+07 2.145E+07 1.176E+06 1.563E+06 8.283E+06 1.339E+08

Mole Wt. 17.086 18.015 9.797 21.382 2.016 19.855 11.998


H2 0.1539 0.0351 1.0000 0.0396 0.1055

N2 0.0077 0.0032 0.0036 0.0208 0.0061

CO 0.3569 0.4070 0.2863 0.7200

CO2 0.0113 0.4382 0.4997 0.4893 0.1345

H2O 1.0000 0.0073 0.0083 0.0011 0.0091

O2

C1 0.8871 0.0406 0.0463 0.1230 0.0249

C2's 0.0605 0.0078

C3's 0.0221 0.0170

C4's 0.0093 0.0128

C5's 0.0020 0.0013

C6's 0.0003

C7-C9 0.0003

C10-C12

C13-C15

SYNGAS GENERATION


(MASS FRACTION)


4

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates 0.0002

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamSyngas

Feed to 1st Stg

1st Stg. Reactor Effluent

Syngas to 2nd Stg Reactor

1st Stg F-T Liquids

2nd Stg. Reactor Effluent

2nd Stg. Separator

Vapor

2nd Stg F-T Liquids

Ht Separator

VaporTemperature, °C 64 182 182 182 220 220 220 150

Pressure, bara 38.47 36.67 36.67 36.67 34.77 34.77 34.77 34.47

Molar Flow, kgmole/h 14,816.2 8,473.8 7,528.6 100.2 5,861.5 5,841.6 19.8 3,060.2

Mass Flow, kg/s 49.4 49.4 36.6 8.6 36.6 34.7 1.8 19.4


Mole Wt. 11.998 20.978 17.497 307.508 22.473 21.411 335.679 22.815


H2 0.1055 0.0303 0.0409 0.0001 0.0141 0.0148 0.0001 0.0265

N2 0.0061 0.0061 0.0082 0.0082 0.0086 0.0154

CO 0.7200 0.2105 0.2837 0.0014 0.1050 0.1105 0.0006 0.1977

CO2 0.1345 0.1432 0.1926 0.0021 0.1926 0.2027 0.0022 0.3609

H2O 0.0091 0.3282 0.3266 0.0036 0.4410 0.4642 0.0053 0.1237

O2

C1 0.0249 0.0335 0.0452 0.0003 0.0482 0.0508 0.0004 0.0908

C2's 0.0019 0.0025 0.0031 0.0033 0.0059

C3's 0.0046 0.0061 0.0001 0.0077 0.0081 0.0002 0.0144

C4's 0.0055 0.0072 0.0003 0.0094 0.0098 0.0003 0.0173

C5's 0.0062 0.0083 0.0006 0.0105 0.0110 0.0006 0.0193

C6's 0.0068 0.0089 0.0012 0.0112 0.0118 0.0011 0.0204

C7-C9 0.0222 0.0273 0.0109 0.0349 0.0364 0.0083 0.0568

C10-C12 0.0226 0.0218 0.0373 0.0297 0.0300 0.0231 0.0309

C13-C15 0.0213 0.0105 0.0775 0.0182 0.0168 0.0436 0.0065

C16-C18 0.0192 0.0034 0.0960 0.0101 0.0075 0.0610 0.0008

F-T SYNTHESIS


(MASS FRACTION)


2

C19-C23 0.0273 0.0010 0.1530 0.0107 0.0040 0.1360 0.0001

C24-C29 0.0271 0.0001 0.1554 0.0098 0.0013 0.1702

C30+WAX 0.0797 0.0001 0.4595 0.0284 0.0008 0.5465

Oxygenates 0.0043 0.0056 0.0006 0.0070 0.0074 0.0006 0.0124

Total 1.0000 1.0010 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16

StreamHT

Separator Liquids

LT Separator

Vapor

LT Separator

Liquids


Lean Solvent Feed

Rich Solvent

Absorber Overheads

F-T Liquids to

FractionatiTemperature, °C 150 40 40 234 45 43 14 86

Pressure, bara 34.47 33.87 33.87 35.51 1.34 34.13 33.44 33.87

Molar Flow, kgmole/h 35.4 2,496.8 90.1 11.5 170.9 249.5 2,424.2 125.6

Mass Flow, kg/s 1.6 14.6 2.4 0.1 9.9 11.1 13.5 4.0

Enthalpy, kJ/h 1.269E+06 2.275E+07 -2.960E+05 3.528E+05 -1.704E+06 -1.708E+06 1.948E+07 9.734E+05

Mole Wt. 161.199 21.051 96.556 32.424 208.621 159.729 20.065 114.804


H2 0.0002 0.0352 0.0002 0.0346 0.0001 0.0382 0.0002

N2 0.0001 0.0204 0.0002 0.0002 0.0219 0.0002

CO 0.0019 0.2621 0.0034 0.0024 0.2813 0.0028

CO2 0.0094 0.4724 0.0369 0.0225 0.4920 0.0260

H2O 0.0035 0.0025 0.0002 0.0006 0.0001 0.0001 0.0006 0.0015

O2

C1 0.0015 0.1200 0.0038 0.0087 0.0023 0.1279 0.0029

C2's 0.0002 0.0076 0.0010 0.0245 0.0006 0.0079 0.0007

C3's 0.0010 0.0181 0.0072 0.1023 0.0037 0.0173 0.0048

C4's 0.0024 0.0191 0.0231 0.2204 0.0119 0.0127 0.0150

C5's 0.0048 0.0166 0.0546 0.1649 0.0230 0.0004 0.0349

C6's 0.0099 0.0103 0.1008 0.0872 0.0144 0.0647

C7-C9 0.1029 0.0073 0.4120 0.2433 0.0002 0.0121 0.2896

C10-C12 0.2787 0.0003 0.2467 0.0500 0.1175 0.1058 0.2594

C13-C15 0.2880 0.0525 0.0369 0.4827 0.4324 0.1459

C16-C18 0.1553 0.0065 0.0195 0.3497 0.3130 0.0655

F-T SYNTHESIS


(MASS FRACTION)


4

C19-C23 0.0882 0.0007 0.0063 0.0499 0.0447 0.0354

C24-C29 0.0281 0.0005 0.0001 0.0001 0.0110

C30+WAX 0.0176 0.0003 0.0070

Oxygenates 0.0058 0.0083 0.0497 0.0109 0.0323

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


5

Plant Section

Stream No. 17

StreamF-T "Wax" Product to Upgrading

Temperature, °C 189


Molar Flow, kgmole/h 120.0



Mole Wt. 312.160


H2 0.0001

N2

CO 0.0013

CO2 0.0021

H2O 0.0039

O2

C1 0.0004

C2's

C3's 0.0001

C4's 0.0003

C5's 0.0006

C6's 0.0012

C7-C9 0.0105

C10-C12 0.0347

C13-C15 0.0714

C16-C18 0.0899

F-T SYNTHESIS


(MASS FRACTION)


6

C19-C23 0.1499

C24-C29 0.1579

C30+WAX 0.4749

Oxygenates 0.0006

Total 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8


SolventF-T "Wax"


Stream


Prefractn. Bottoms

Product Fractionato

r Feed

Product Fractionato

r Temperature, °C 86 43 189 234 43 332 361 64

Pressure, bara 33.87 34.13 34.77 35.51 13.79 14.13 1.72 1.10


Mass Flow, kg/s 4.0 11.1 10.4 11.3 1.1 35.6 35.6 0.0


Mole Wt. 114.804 159.729 312.160 181.476 37.658 212.739 212.739 59.735


H2 0.0002 0.0001 0.0001 0.0005 0.0080

N2 0.0002 0.0002 0.0026

CO 0.0028 0.0024 0.0013 0.0449

CO2 0.0260 0.0225 0.0021 0.3333 0.0002

H2O 0.0015 0.0001 0.0039 0.0033 0.0642

O2

C1 0.0029 0.0023 0.0004 0.0002 0.0378

C2's 0.0007 0.0006 0.0010 0.0188

C3's 0.0048 0.0037 0.0001 0.0066 0.1209 0.0008

C4's 0.0150 0.0119 0.0003 0.0220 0.3765 0.0006 0.0006 0.0319

C5's 0.0349 0.0230 0.0006 0.0243 0.0470 0.0175 0.0175 0.4578

C6's 0.0647 0.0144 0.0012 0.0195 0.0001 0.0183 0.0183 0.1713

C7-C9 0.2896 0.0121 0.0105 0.1076 0.0733 0.0733 0.1336

C10-C12 0.2594 0.1058 0.0347 0.0745 0.0959 0.0959 0.0062

C13-C15 0.1459 0.4324 0.0714 0.1625 0.2233 0.2233



(MASS FRACTION)


2

C16-C18 0.0655 0.3130 0.0899 0.2273 0.2030 0.2030

C19-C23 0.0354 0.0447 0.1499 0.1574 0.1115 0.1115

C24-C29 0.0110 0.0001 0.1579 0.0497 0.0632 0.0632

C30+WAX 0.0070 0.4749 0.1468 0.1862 0.1862

Oxygenates 0.0323 0.0109 0.0006 0.0067 0.0070 0.0070 0.1342

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16



Product Diesel


Product Diesel

Vacuum Column

Ohd.


Hydrocracker Makeup

H2Temperature, °C 64 45 45 297 45 45 300 47

Pressure, bara 1.10 1.34 1.34 1.52 0.13 1.10 49.64 27.50


Mass Flow, kg/s 5.7 9.9 6.2 13.9 2.5 0.0 11.3 0.1

Enthalpy, kJ/h 3.034E+05 -1.704E+06 -1.060E+06 3.575E+07 3.405E+06 -2.331E+02 3.064E+07 1.563E+06

Mole Wt. 103.571 208.621 208.621 386.421 250.700 175.000 442.351 2.016


H2 1.0000

N2

CO

CO2

H2O 0.0005 0.0001 0.0001 0.0003 0.0001

O2

C1

C2's

C3's

C4's 0.0030

C5's 0.1082 0.0019

C6's 0.1145 0.0055

C7-C9 0.4609 0.0002 0.0002 0.1318

C10-C12 0.2687 0.1175 0.1175 0.0006 0.0030 0.2767

C13-C15 0.0007 0.4827 0.4827 0.0137 0.0739 0.3442 0.0002



(MASS FRACTION)


4

C16-C18 0.3497 0.3497 0.1159 0.5368 0.2049 0.0231

C19-C23 0.0499 0.0499 0.2288 0.3851 0.0321 0.1947

C24-C29 0.0001 0.0001 0.1624 0.0012 0.1980

C30+WAX 0.4783 0.5840


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


5


StreamHydrocrack



Gas


Hydrocracker Purge

Gas


Temperature, °C 350 45 234 59 234

Pressure, bara 46.54 45.51 35.51 51.71 35.51

Molar Flow, kgmole/h 739.8 504.4 235.3 50.6 11.5

Mass Flow, kg/s 12.1 0.7 11.4 0.1 0.1

Enthalpy, kJ/h 4.803E+07 4.334E+06 2.016E+07 4.583E+05 3.528E+05

Mole Wt. 58.689 4.803 174.195 4.803 32.424


H2 0.0225 0.3896 0.0008 0.3896 0.0346

N2

CO

CO2

H2O 0.0002 0.0029 0.0029 0.0006

O2

C1 0.0035 0.0578 0.0003 0.0578 0.0087

C2's 0.0056 0.0791 0.0012 0.0791 0.0245

C3's 0.0167 0.1728 0.0075 0.1728 0.1023

C4's 0.0328 0.1860 0.0238 0.1860 0.2204

C5's 0.0282 0.0728 0.0256 0.0728 0.1649

C6's 0.0200 0.0184 0.0201 0.0184 0.0872

C7-C9 0.1038 0.0202 0.1088 0.0202 0.2433

C10-C12 0.0701 0.0005 0.0743 0.0005 0.0500

C13-C15 0.1524 0.1615 0.0369

C16-C18 0.2128 0.2253 0.0195



(MASS FRACTION)


6

C19-C23 0.1474 0.1562 0.0063

C24-C29 0.0465 0.0494 0.0005

C30+WAX 0.1374 0.1455 0.0003

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamNatural

Gas FeedNatural

Gas FeedPrefraction

tor Overheads

Hydrocarbon Feed To POX

Oxygen from ASU

MP Steam Addition


Syngas to F-T

SectionTemperature, °C 45 45 119 313 200 329 1318 60

Pressure, bara 43.44 43.44 42.75 42.75 41.37 42.00 40.33 38.47

Molar Flow, kgmole/h 4,980.7 996.1 107.6 898.1 2,995.3 691.2 2,864.5 12,588.8

Mass Flow, kg/s 23.6 4.7 1.1 4.4 26.6 3.5 10.4 43.3


Mole Wt. 17.086 17.086 37.658 17.579 31.980 18.015 13.069 12.388


H2 0.1499 0.0036 0.5331 0.6064

N2 0.0047 0.0047 0.0035 0.0047 0.0050 0.0025 0.0029

CO 0.0604 0.0014 0.2996 0.3409

CO2 0.0044 0.0044 0.2852 0.0111 0.0228 0.0259

H2O 0.0069 0.0002 1.0000 0.1266 0.0064

O2 0.9950

C1 0.9448 0.9448 0.0888 0.9242 0.0154 0.0175

C2's 0.0344 0.0344 0.0237 0.0341

C3's 0.0086 0.0086 0.1048 0.0109

C4's 0.0028 0.0028 0.2464 0.0086

C5's 0.0004 0.0004 0.0250 0.0010

C6's

C7-C9

C10-C12

C13-C15

SYNGAS GENERATION


(MOLE FRACTION)


2

C16-C18

C19-C23

C24-C29

C30+WAX


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15

StreamNatural Feed to

Reformer

MP Steam to

Reformer

Reformed Gas to F-T Synthesis

PSA Residue Gas to

H2 to Hydrocrack

er

Reformer Fuel Gas

Combined Syngas to

F-T Temperature, °C 319 329 84 40 47 45 64

Pressure, bara 31.03 42.00 39.02 1.50 27.50 3.00 38.47

Molar Flow, kgmole/h 597.7 2,689.6 2,227.4 130.1 193.7 1,021.0 14,816.2

Mass Flow, kg/s 2.8 13.5 6.1 0.8 0.1 5.6 49.4

Enthalpy, kJ/h 1.390E+07 5.100E+07 2.145E+07 1.176E+06 1.563E+06 8.283E+06 1.339E+08

Mole Wt. 17.086 18.015 9.797 21.382 2.016 19.855 11.998


H2 0.7478 0.3722 1.0000 0.3900 0.6277

N2 0.0047 0.0011 0.0027 0.0147 0.0026

CO 0.1248 0.3107 0.2029 0.3084

CO2 0.0044 0.0975 0.2428 0.2208 0.0367

H2O 1.0000 0.0040 0.0099 0.0012 0.0060

O2

C1 0.9448 0.0248 0.0617 0.1522 0.0186

C2's 0.0344 0.0052

C3's 0.0086 0.0079

C4's 0.0028 0.0045

C5's 0.0004 0.0004

C6's 0.0001

C7-C9

C10-C12

C13-C15

SYNGAS GENERATION


(MOLE FRACTION)


4

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates 0.0001

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamSyngas

Feed to 1st Stg



1st Stg F-T Liquids


2nd Stg. Separator

Vapor

2nd Stg F-T Liquids

Ht Separator


Pressure, bara 38.47 36.67 36.67 36.67 34.77 34.77 34.77 34.47


Mass Flow, kg/s 49.4 49.4 36.6 8.6 36.6 34.7 1.8 19.4


Mole Wt. 11.998 20.978 17.497 307.508 22.473 21.411 335.679 22.815


H2 0.6277 0.3154 0.3547 0.0223 0.1569 0.1574 0.0111 0.3001

N2 0.0026 0.0045 0.0051 0.0004 0.0066 0.0066 0.0006 0.0125

CO 0.3084 0.1577 0.1772 0.0152 0.0842 0.0845 0.0075 0.1611

CO2 0.0367 0.0682 0.0766 0.0146 0.0984 0.0986 0.0171 0.1871

H2O 0.0060 0.3822 0.3172 0.0622 0.5502 0.5517 0.0984 0.1567

O2

C1 0.0186 0.0438 0.0492 0.0065 0.0675 0.0677 0.0088 0.1291

C2's 0.0013 0.0014 0.0004 0.0024 0.0024 0.0006 0.0045

C3's 0.0022 0.0025 0.0010 0.0041 0.0041 0.0014 0.0077

C4's 0.0021 0.0022 0.0017 0.0037 0.0037 0.0021 0.0069

C5's 0.0018 0.0021 0.0025 0.0033 0.0033 0.0028 0.0062

C6's 0.0017 0.0018 0.0040 0.0030 0.0030 0.0041 0.0054

C7-C9 0.0040 0.0042 0.0285 0.0069 0.0069 0.0239 0.0115

C10-C12 0.0031 0.0024 0.0724 0.0043 0.0042 0.0490 0.0047

C13-C15 0.0022 0.0009 0.1197 0.0020 0.0018 0.0734 0.0007

F-T SYNTHESIS


(MOLE FRACTION)


2

C16-C18 0.0017 0.0002 0.1231 0.0010 0.0007 0.0850

C19-C23 0.0020 0.1596 0.0008 0.0003 0.1539

C24-C29 0.0015 0.1289 0.0006 0.1537

C30+WAX 0.0028 0.2335 0.0011 0.3032

Oxygenates 0.0017 0.0019 0.0034 0.0031 0.0031 0.0034 0.0056

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16

StreamHT

Separator Liquids

LT Separator

Vapor

LT Separator

Liquids


Lean Solvent Feed

Rich Solvent

Absorber Overheads

F-T Liquids to


Pressure, bara 34.47 33.87 33.87 35.51 1.34 34.13 33.44 33.87


Mass Flow, kg/s 1.6 14.6 2.4 0.1 9.9 11.1 13.5 4.0


Mole Wt. 161.199 21.051 96.556 32.424 208.621 159.729 20.065 114.804


H2 0.0140 0.3674 0.0101 0.5570 0.0110 0.3799 0.0112

N2 0.0008 0.0153 0.0008 0.0009 0.0157 0.0008

CO 0.0111 0.1970 0.0117 0.0135 0.2015 0.0116

CO2 0.0346 0.2259 0.0810 0.0817 0.2243 0.0679

H2O 0.0310 0.0029 0.0013 0.0011 0.0012 0.0010 0.0006 0.0097

O2

C1 0.0153 0.1574 0.0228 0.0175 0.0224 0.1599 0.0207

C2's 0.0013 0.0054 0.0034 0.0264 0.0031 0.0054 0.0027

C3's 0.0039 0.0089 0.0162 0.0753 0.0139 0.0081 0.0127

C4's 0.0069 0.0070 0.0393 0.1229 0.0332 0.0045 0.0301

C5's 0.0111 0.0049 0.0741 0.0741 0.0517 0.0001 0.0563

C6's 0.0188 0.0025 0.1142 0.0328 0.0270 0.0873

C7-C9 0.1416 0.0015 0.3536 0.0727 0.0005 0.0182 0.2939

C10-C12 0.2863 0.1568 0.0105 0.1449 0.1001 0.1933

C13-C15 0.2366 0.0264 0.0061 0.5071 0.3479 0.0858

F-T SYNTHESIS


(MOLE FRACTION)


4

C16-C18 0.1053 0.0026 0.0026 0.3077 0.2109 0.0317

C19-C23 0.0494 0.0003 0.0007 0.0385 0.0263 0.0140

C24-C29 0.0123 0.0036

C30+WAX 0.0047 0.0013

Oxygenates 0.0151 0.0037 0.0855 0.0370 0.0656

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


5

Plant Section

Stream No. 17







Mole Wt. 312.160


H2 0.0205

N2 0.0004

CO 0.0140

CO2 0.0150

H2O 0.0682

O2

C1 0.0069

C2's 0.0004

C3's 0.0012

C4's 0.0018

C5's 0.0026

C6's 0.0041

C7-C9 0.0278

C10-C12 0.0685

C13-C15 0.1121

F-T SYNTHESIS


(MOLE FRACTION)


6

C16-C18 0.1169

C19-C23 0.1588

C24-C29 0.1331

C30+WAX 0.2450

Oxygenates 0.0033

Total 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8


SolventF-T "Wax"


Stream


Prefractn. Bottoms

Product Fractionato

r Feed

Product Fractionato

r Temperature, °C 86 43 189 234 43 332 361 64

Pressure, bara 33.87 34.13 34.77 35.51 13.79 14.13 1.72 1.10


Mass Flow, kg/s 4.0 11.1 10.4 11.3 1.1 35.6 35.6 0.0


Mole Wt. 114.804 159.729 312.160 181.476 37.658 212.739 212.739 59.735


H2 0.0112 0.0110 0.0205 0.0426 0.1499

N2 0.0008 0.0009 0.0004 0.0035

CO 0.0116 0.0135 0.0140 0.0604

CO2 0.0679 0.0817 0.0150 0.2852 0.0002

H2O 0.0097 0.0010 0.0682 0.0002 0.0069 0.2130

O2

C1 0.0207 0.0224 0.0069 0.0024 0.0888

C2's 0.0027 0.0031 0.0004 0.0062 0.0237 0.0001

C3's 0.0127 0.0139 0.0012 0.0272 0.1048 0.0010

C4's 0.0301 0.0332 0.0018 0.0686 0.2463 0.0019 0.0019 0.0329

C5's 0.0563 0.0517 0.0026 0.0612 0.0250 0.0519 0.0519 0.3828

C6's 0.0873 0.0270 0.0041 0.0412 0.0455 0.0455 0.1197

C7-C9 0.2939 0.0182 0.0278 0.1746 0.1393 0.1393 0.0760

C10-C12 0.1933 0.1001 0.0685 0.0855 0.1272 0.1272 0.0026

C13-C15 0.0858 0.3479 0.1121 0.1475 0.2392 0.2392



(MOLE FRACTION)


2

C16-C18 0.0317 0.2109 0.1169 0.1708 0.1807 0.1807

C19-C23 0.0140 0.0263 0.1588 0.1037 0.0840 0.0840

C24-C29 0.0036 0.1331 0.0243 0.0364 0.0364

C30+WAX 0.0013 0.2450 0.0440 0.0654 0.0654

Oxygenates 0.0656 0.0370 0.0033 0.0055 0.0286 0.0286 0.1719

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16



Product Diesel


Product Diesel

Vacuum Column

Ohd.


Hydrocracker Makeup

H2Temperature, °C 64 45 45 297 214 45 300 47

Pressure, bara 1.10 1.34 1.34 1.52 0.13 1.10 49.64 27.50


Mass Flow, kg/s 5.7 9.9 6.2 13.9 2.5 0.0 11.3 0.1


Mole Wt. 103.571 208.621 208.621 386.421 250.700 175.000 442.351 2.016


H2 1.0000

N2

CO

CO2

H2O 0.0029 0.0012 0.0012 0.0068 0.0002 0.0012 0.0011

O2

C1

C2's

C3's 0.0001

C4's 0.0055 0.0001

C5's 0.1565 0.0045

C6's 0.1385 0.0113

C7-C9 0.4252 0.0005 0.0005 0.0001 0.1949

C10-C12 0.1844 0.1449 0.1449 0.0013 0.0045 0.3046

C13-C15 0.0004 0.5071 0.5071 0.0257 0.0901 0.3062 0.0006



(MOLE FRACTION)


4

C16-C18 0.3077 0.3077 0.1821 0.5490 0.1506 0.0408

C19-C23 0.0385 0.0385 0.3095 0.3554 0.0209 0.2945

C24-C29 0.1695 0.0008 0.2363

C30+WAX 0.3054 0.4269


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


5

Plant Section

Stream No. 17 18 19 20 21 22

StreamHydrocrack



Gas


Hydrocracker Purge

Gas


Temperature, °C 310 350 45 234 59 234

Pressure, bara 47.92 46.54 45.51 35.51 51.71 35.51


Mass Flow, kg/s 12.1 12.1 0.7 11.4 0.1 0.1


Mole Wt. 58.685 58.689 4.803 174.195 4.803 32.424


H2 0.8312 0.6545 0.9283 0.0677 0.9283 0.5570

N2

CO

CO2

H2O 0.0006 0.0006 0.0008 0.0003 0.0008 0.0011

O2

C1 0.0106 0.0128 0.0173 0.0031 0.0173 0.0175

C2's 0.0077 0.0109 0.0126 0.0072 0.0126 0.0264

C3's 0.0115 0.0222 0.0188 0.0296 0.0188 0.0753

C4's 0.0094 0.0331 0.0154 0.0712 0.0154 0.1229

C5's 0.0030 0.0230 0.0049 0.0618 0.0049 0.0741

C6's 0.0006 0.0137 0.0010 0.0408 0.0010 0.0328

C7-C9 0.0006 0.0546 0.0008 0.1696 0.0008 0.0727

C10-C12 0.0260 0.0819 0.0105

C13-C15 0.0001 0.0447 0.1406 0.0061



(MOLE FRACTION)


6

C16-C18 0.0051 0.0517 0.1625 0.0026

C19-C23 0.0367 0.0315 0.0987 0.0007

C24-C29 0.0296 0.0075 0.0232

C30+WAX 0.0533 0.0133 0.0419

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg


63

7B-1 PROCESS DESCRIPTION The design basis and major assumptions for each major ISBL plant are presented in Sections 3 and 4B-

1. Area 100 - Syngas Generation Area 100 is the syngas generation area. This area consists of the following plants. Plant 101 Air Separation Unit Plant 102 SGP Partial Oxidation Plant The sulfur removal, steam methane reforming, heat recovery/steam generation, syngas cooling, and hydrogen recovery are parts of Plant 102, the SGP Partial Oxidation Plant. Plant 101, the Air Separation Unit, contains an inlet air compressor. The cryogenic air separation portion of Plant 101 produces a 99.5 mole % oxygen stream which is a feed stream to Plant 102, the SGP Partial Oxidation Plant. The oxygen stream is distributed to five SGP partial oxidation reactors operating in parallel. Each reactor includes oxygen feed preheat and MP steam addition. Plant 102, the SGP Partial Oxidation Plant, first removes trace amounts of sulfur compounds from the natural gas by reaction with zinc oxide. Prefractionator ‘overheads’ is then added to the natural gas downstream of the desulfurization units. The desulfurized natural gas is split into streams flowing to the five SGP partial oxidation reactors and to the steam reformer. The streams flowing to the SGP partial oxidation reactors mix with oxygen at a burner inside each reactor. Partial combustion reactions between the fuel and oxidant occur at the burner, followed by homogeneous ‘reforming’ and CO-shift reactions to form syngas in the main body of the refractory-lined vessel. The hot syngas product stream is cooled by steam generation, feed/effluent heat exchange, and cooling with ambient air. Any carbon, or soot, which might be formed during partial oxidation, is removed from the gas stream by scrubbing the gas with water in the Carbon Scrubber, 102C-1. The balance of the natural gas is fed to a steam reformer, to produce a hydrogen-rich gas stream which is used to adjust the H2:CO ratio of the syngas from the SGP partial oxidation reactors to the correct value for F-T synthesis. A slip stream of reformer syngas is separated into hydrogen and residue gas streams in the PSA unit. Hydrogen is required for hydrocracking. Plant 102 produces a combined synthesis gas steam having a molar H2:CO ratio of 2.03 which is sent to Area 200 for Shell MDS-Type Fischer-Tropsch synthesis.

64

The following subsections give a more detailed description on each of the process plants in Area 100, the Syngas Preparation Area. Plant 101 - Air Separation Unit Plant 101, the Air Separation Unit, provides the required oxygen feed to Plant 102, the SGP Partial Oxidation Plant, for syngas generation. The air separation portion of Plant 101 is a standard cryogenic air separation unit. The air compressor and oxygen compressor are driven by steam turbines. The cryogenic air separation unit is a single train with a capacity of about 2,534 STPD of 99.5 mole % pure oxygen. The design incorporates a backup system including a liquid oxygen storage capacity of 2,550 tons. This backup oxygen storage system protects the facility from an unscheduled shutdown of one day or less. Process Description In the air separation section, ambient air is filtered and compressed in a two-stage axial centrifugal compressor with interstage cooling. The air from the final stage of compression enters a direct contact aftercooler where it contacts cooling water and chilled cooling water in two separate packed sections. The cooled air from the top of the aftercooler has lost the majority of its ambient water vapor. Removal of the residual water vapor, carbon dioxide and other atmospheric contaminants occurs in the molecular sieve adsorbers. The dry air enters the "cold box" where it is cooled to cryogenic temperature in the main heat exchangers and is separated into oxygen and nitrogen by cryogenic distillation. Final cooling is by expansion. The oxygen stream is further purified in an argon column to 99.5 mole %. The main heat exchangers are brazed aluminum, multipass, plate-fin units in which the entering air is cooled against the cold oxygen and nitrogen streams leaving the distillation columns. The oxygen product stream leaving the cryogenic separation section is warmed in the main heat exchangers and compressed to final delivery pressure in a centrifugal compressor. In order to insure a continuous supply of oxygen, backup storage systems are included in the design

65

Plant 102 - SGP Partial Oxidation The objective for Plant 102, the SGP Partial Oxidation Plant, is to provide a syngas with a H2:CO ratio of about 2.0 for Shell MDS F-T synthesis. The partial oxidation reactor is designed to operate with the following feed ratios: H2O:C, mole/mole 0.14 CO2:C, mole/mole 0.01 O2:C, mole/mole 0.62 The adiabatic flame temperature at the burner is approximately 2,000°C. A process flow diagram of Plant 102, the SGP Partial Oxidation Plant, is shown in PFD 102-B-01. The individual natural gas feed streams are heated in exchangers 102E-3A//B/C/D/E before being desulfurized in the zinc oxide desulfurization vessels, 102R-1A/B. Sulfur is removed to the less than 0.1 ppm by volume, as required for the subsequent steam reforming and Fischer-Tropsch synthesis. Overheads from the Prefractionator is mixed with the natural gas to form the fuel feed to the SGP partial oxidation reactors, 102R-2A/B/C/D/E. SGP is a non-catalytic autothermal partial oxidation process developed in the 1950’s. The process operates at 1,300-1,500°C and pressures up to 70 bar. The SGP partial oxidation reactor is a refractory-lined carbon steel vessel containing an axially down-fired burner. Hydrocarbon feed fuel is partially combusted by mixing with oxygen, below the full-combustion stoichiometric amount, at the burner. Downstream of the burner combustion zone, residual hydrocarbons are homogeneously and adiabatically reformed to syngas according to the overall reforming and CO-shift reactions. The SGP partial oxidation reactor effluent (syngas) is cooled in a waste heat boiler, 102E-2A, by raising 102 bar saturated steam. The syngas is then further cooled by preheating boiler feedwater and demineralized feedwater in exchangers 102E-4A and 102E-5A, respectively. Any soot formed during partial oxidation is removed by scrubbing the syngas stream with water in the Carbon Scrubber, 102C-1. Final cooling of the syngas to 60oC is accomplished in air cooler 102E-9. The cooled syngas goes to separator 102C-3, where process condensate is separated from product syngas. Plant 102 - Steam Methane Reforming (SMR) To achieve an F-T syngas with a correctly balanced H2:CO ratio the SGP partial oxidation syngas must be mixed with a high H2:CO ratio – a hydrogen-rich stream. A suitable hydrogen-rich stream is syngas generated by a steam methane reformer (SMR).

66

Therefore, part of the plant natural gas feed is diverted to an SMR to achieve the correct H2:CO ratio syngas for F-T synthesis. The diverted natural gas is mixed with steam, preheated in the SMR flue gas duct, and then reformed at high temperature in catalyst-filled tubes inside the SMR furnace. The SMR is designed to operate at the following conditions: H2O:C, mole/mole ratio 4.3 SMR exit conditions: Temperature: 880°C Pressure: 30.5 bar The SMR effluent (reformed gas) is cooled in a waste heat boiler, 102E-6, by raising 102 bar saturated steam. 102 bar steam is also raised as SMR-furnace flue gas is cooled in the flue gas duct. The HP saturated steam from the SMR steam drum is combined with steam raised in the SGP waste heat boilers and then superheated in direct fired heater, 102F-1. SMR reformed gas is further cooled by preheating boiler feedwater flowing to the SMR steam drum. Final cooling of the reformed gas to 45oC is accomplished by air cooler 102E-10 and trim condenser 102E-8. The reformed gas separates from process condensate in Process Condensate Separator #3, 102C-6. A small slip stream of reformed gas is used to generate the hydrogen stream used for hydrocracking. The balance of the reformed gas is compressed to the operating pressure of the F-T synthesis section and then mixed with syngas from the SGP partial oxidation reactors. Plant 102 - Hydrogen Separation High-purity hydrogen, a reactant in the hydrocracking process, is recovered from a small slip stream of cooled SMR reformed gas by a pressure swing adsorption (PSA) unit. Unlike the residue gas species (CO, CO2, CH4, and H2O), which strongly adsorb to the PSA sorbent, hydrogen is adsorbed in only small amounts as syngas flows through the PSA unit. Therefore, a high-purity hydrogen stream is obtained at the PSA unit outlet, while the balance of syngas components (residue gas) accumulate on the sorbent and are only removed once the vessel is de-pressurized, when these species desorb into the regeneration gas stream. The PSA residue gas is used for fuel.

67

Area 200 - Fisher-Tropsch Synthesis and Product Upgrading Area 200 is the Fischer-Tropsch synthesis and product upgrading area. It consists of the following plants: Plant 201 Shell MDS-Type Fischer-Tropsch Synthesis and Hydrocarbon Recovery Plant Plant 202 Product Fractionation & Wax Hydrocracking Plant This design is based on fixed-bed reactor technology and cobalt-based F-T synthesis catalyst with limited water-gas shift activity. The product fractionation and upgrading steps consist of standard fractionation technology and mild wax hydrocracking. The following subsections give a more detailed description on each of the process plants in Area 200, the Fischer-Tropsch Synthesis and Product Upgrading Area. Plant 201 - Shell MDS Fischer-Tropsch Synthesis The principle function of this plant is to convert the syngas produced in Area 100 into hydrocarbon products using a series of multi-tubular, trickle-bed, cobalt catalyst reactors. The reactor section for this plant consists of three fixed-bed reactors – two parallel first-stage reactors with a single second-stage reactor, in series. The reactor section operates as ‘once- through’, i.e. there is no recycle of unconverted syngas from the reactor effluent back to the reactor feed. Fischer-Tropsch reactions produce mainly straight chain paraffins and are highly exothermic. The carbon number distribution of the hydrocarbon product is known to closely follow a single-parameter (α) probability model for hydrocarbon chain growth and termination i.e., αn-1(1-α); where α represents the probability for chain growth. The model predicts the chance of a certain carbon number molecule being formed in relation to an entire distribution of possible carbon numbers. In practice, α values in the range 0.7-0.95 lead to a F-T-synthesis product distribution with carbon numbers above (wax) and below (C4

- ) the carbon numbers associated with the study products – diesel and naphtha. Commercially, where LPG is not recovered as product, the lower carbon number species are mainly used as fuel, or else recycled as feedstock to the syngas generation section of the plant. Carbon number products beyond the acceptable diesel end-point (say > C20) have to be cracked to lower carbon-number products, which are then recovered through fractionation. Design Basis and Considerations The CO conversion (to hydrocarbon and a small amount of CO2) in the reactor section is approximately 89%.

68

In this design, the heat generated by the F-T synthesis reaction is removed by generation of 15 bar saturated steam in tubes inside the reactor. The two 1st stage Fischer-Tropsch reactors are about 5.0 m diameter and about 20 m in height. Each reactor contains about 3,500 tubes having a 50 mm OD for steam generation. The 2nd stage reactor is about 4.9 m diameter and about 20 m in height and contains about 2,700 x 50 mm OD tubes. The process flow diagrams for Plant 201, F-T synthesis, are shown in PFD 201-B-01. As shown in PFD 201-B-01, the combined syngas from Plant 102 is heated to the reactor inlet temperature (235°C) through reactor feed/effluent heat exchange and steam preheating. CO and H2 in the syngas are converted, according to Fischer-Tropsch chemistry, to a paraffinic hydrocarbon product - principally middle distillates. The 1st stage reactor product stream is cooled in 201E-2A/B and the liquid product separated from the vapor stream, in 201C-2. The vapor stream is reheated to reactor feed conditions through feed/effluent heat exchange and steam preheating. Unconverted CO and H2 in the vapor stream leaving the 1st stage reactors are converted to paraffinic hydrocarbon products in the 2nd stage reactor. The 2nd stage reactor product stream is cooled in exchangers 201E-4, 201E-6, 201E-10, and 201E-7. As the product stream is cooled it forms a mixed, three-phase stream, which is separated into an unconverted syngas stream, liquid hydrocarbon streams, and water streams, in 201C-3, 201C-4, and 201C-5,. The combined liquid hydrocarbon stream is sent directly to product fractionation and the water steams go to water treatment. Plant 201 - Hydrocarbon Recovery A chilled lean oil absorption unit, using a diesel recycle stream as the solvent, is used to recover additional C5+ components in the F-T reactor effluent gas stream downstream of the cooling/recovery train. Rich solvent leaving the bottom of the absorber is fed to the product fractionation plant. Plant 202 - Product Fractionation The prefractionator, 202C-1, receives hydrocarbon liquids (middle distillates and wax) from the F-T cooling train section, rich solvent bottoms from the lean oil absorber, and hydrocarbon liquid recycle from the hydrocracker. Light non-condensable gases and C4- hydrocarbons are removed in the prefractionator prior to product fractionation. The prefractionator overhead stream is compressed and recycled to the syngas generation section where it is mixed with the natural gas feed. The product fractionator, 202C-3, separates the prefractionator bottoms stream into an overhead liquid naphtha product and a diesel product, which is drawn from the bottom of the product fractionator side-

69

stripper. A small, light-hydrocarbon and non-condensable gases overhead stream is also separated. The overhead vapor stream is compressed and sent to the plant fuel system. The naphtha product has an ASTM D-86 end-point of 204°C. It is cooled and sent to storage. The diesel product (ASTM D-86 end-point 320°C) is cooled, dehydrated, and split into a lean oil recycle stream and a diesel product stream. Product fractionator bottoms is sent to the vacuum column, 202C-7. A diesel distillate is produced from the top pump-around section and a 350+°C boiling range gas oil is produced as bottoms. The diesel distillate has an ASTM D-86 end-point of 350°C. The gas oil stream is sent to the hydrocracker. Plant 202 - Wax Hydrocracking The Wax Hydrocracking Plant, catalytically cracks the F-T wax product under a hydrogen environment into lower-boiling material, mainly naphtha and diesel. Hydrocracking operating conditions for the Shell MDS-Type F-T plant are assumed to be 310°C and 48 bar for this study. The vacuum column-bottom stream is pumped to hydrocracker operating pressure, 48 bar. The liquid stream mixes with recycle hydrogen and is preheated to the hydrocracker reactor inlet temperature, 310°C. The hydrocracked product is cooled from 350°C to 45°C. The hydrocracked liquid is flashed before being recycled to the prefractionator. The high-pressure gas stream is compressed and recycled to the reactor. A small purge gas stream is sent to the plant fuel system to prevent the buildup of inert in the system. Flash vapor from hydrocracked liquid depressurization is sent to the lean oil absorber for hydrocarbon recovery. Hydrocracking performs the following functions:

- cracking of long-chain hydrocarbons to hydrocarbons of the required chain length - conversion of oxygenates, such as alcohols formed during F-T synthesis, to hydrocarbons - saturation of olefins formed during F-T synthesis

70

Area 300 - Steam Distribution System HP superheated steam is raised in Plant 102 by heat recovery from the syngas generation units. HP steam is used to drive the air separation unit oxygen compressor and the generator turbine. An extraction from the oxygen compressor turbine at MP steam level (42 bar) provides steam to the MP steam users. Both turbines exhausts at 15 bar. Steam raised in the F-T reactor tubes at 15 bar is superheated in fired heater, 201F-1, to 300°C. F-T plant steam is combined with exhaust steam from the oxygen compressor and generator turbines and used to drive the air separation unit air compressor. The LP steam users are supplied with steam from the air compressor turbine exhaust. Excess LP steam is condensed in an air cooler with a seawater trim cooler.

71

8B-1 OFFSITES Following is a brief description of each offsites plant. Plant 19 - Relief and Blowdown -- Plant 19 is for the collection and flaring of relief and blowdown discharges from all applicable plants. It includes a flare for all hydrocarbon containing discharges. Collection piping is not included in Plant 19 but has been included in Plant 21, Interconnecting Piping. Plant 20 - Tankage -- Plant 20 provides storage and delivery equipment for products, intermediates and chemicals. Thirty days storage is provided for the naphtha and distillate products. Intermediate storage is provided for the Wax Hydrocracking Plant. This storage is required to provide feedstock during plant startup and to mitigate the effect on operations due to brief interruptions in the upstream plants which could be the result of scheduled or unscheduled maintenance or due to operating problems. Plant 21 - Interconnecting Piping System -- Plant 21 includes the interconnecting process and utility piping between process plants and offsites. All above ground and underground piping systems are included except the cooling water piping which is included in Plant 32, Cooling Water Distribution, and the fire water piping which is included in Plant 33, Fire Systems. Relief and blowdown headers are included. In general, water distribution piping is underground and all other piping is located above ground on pipe racks. Storm sewers, sanitary sewer and process wastewater lines are not part of this plant but are included in Plant 34, Sewers and Wastewater Treating. Plant 22 - Product Shipping -- Plant 22 provides the pipeline, pumping and metering systems for delivery of the final hydrocarbon products. Separate systems are provided for each of the hydrocarbon products. Dual meters are provided to assure proper recording and product delivery. Plant 25 - Catalyst and Chemical Handling -- Plant 25 provides storage and handling for the catalyst and chemicals used in all the plants. Additionally, it provides a consolidated location for tracking catalyst and chemical start-up and daily consumption requirements. This plant includes an enclosed warehouse for storage and forklifts for transporting pallets into or out of the warehouse. Plant 30 - Electrical Distribution System -- Plant 30 provides the electrical distribution system from the high voltage switchyard to the consuming locations. Plant 32 - Raw, Cooling and Potable Water -- Plant 32 uses a once-through seawater system. Seawater is purchased from the Royal Commission. Supply pressure is low requiring installation of a seawater sump and seawater intake/circulation sump pumps to provide a controllable seawater supply and adequate pressure for the once-through cooling Because there is no cooling tower, the requirement for raw and service water is small.

72






73




74

9B-1 PLANT COSTS Costs are reported in mid-1999 U.S. dollars. The capital cost estimate is based on a factored estimating technique. This technique is based on the observation that cost relationships (cost factors) exist between different components of the overall cost which can be derived from historical cost data for similar, previously built projects. ISBL equipment are sized and materials-of-construction are selected based on the particular process configuration, heat and energy balance calculations, and the conditions of the locally available utility streams. Given the size of the equipment items, Bechtel cost curves (regressions of historical size versus cost data) are used to identify equipment costs. Additional field costs, bulk materials, direct labor, indirect costs, etc., are developed based on cost factors mentioned above. Other field costs, such as sales tax, freight costs, duties, etc., are site specific and developed separately for each project. The Offsites cost estimate is developed from Bechtel in-house data for similar size and type plants in the same site location. The IEA Financial Assessment Criteria (see Appendix) was used to develop the costs for Home Office, Fees, and Services and Plant Contingency.

75

9B-1.1 Installed Plant Costs Table 9B-1.1 shows the capital cost breakdown for a Standard Shell MDS-Type, natural gas Fischer-Tropsch liquefaction plant

Table 9B-1.1


$1,000's

1. ISBL Equipment Area 100 - Syngas Generation 120,826 Area 200 - F-T Synthesis & Product Upgrading 42,351 Area 300 - Steam & Power Generation 24,726 Total ISBL Cost 187,903







76

9B-2.2 Annual Operating Costs Table 9B-2.2 shows the annual operating costs for a Standard Shell MDS-Type, natural gas Fischer-Tropsch liquefaction plant.

Table 9B-2.1



COST, $1,000's

Fixed Costs: Rent 50 acres $ 150 /acre/year $ 8 Taxes 1% of OCC* $ 3,541 Insurance 1% of OCC* $ 3,541 Operating Labor (excl. maint.) 48 people $ 50,000 /pers/annum $ 4,320 Maintenance (matl. & labor) 2% of OCC* $ 7,082 Misc. Supplies Corporate Overhead Total Fixed Costs $ 18,491

Variable Costs: Natural Gas 99,666 GJ/day $ 0.50 /GJ $ 18,189 Seawater 9,046 gpm $ 0.07 /1,000 gal $ 333 Desalinated Water 150 gpm $ 4.50 /1,000 gal $ 355 Electric Power 0 kWh $ 0.015 /kWh import $ - Catalyst & Chemicals $ 4,757 Other Operating Costs Annual Variable Costs $ 23,634 Load Factor 90% Actual Total Variable Costs $ 21,270 By-Product Credits 3,800 kWh $ 0.012 /kWh import $ 360 Unit/D /Unit $ - Total By-Product Credits $ 360 Net Operating Costs $ 39,402

*OCC -Overnight Construction Cost (total field costs + contractor's costs)

77

4B-2 CO2 REDUCTION CASE – Standard Plant + CO2 Capture & Compression

78

DESIGN OBJECTIVE This plant design is an extension of the standard Shell MDS-Type F-T natural gas Fischer-Tropsch liquefaction plant. The standard plant is adapted to capture the bulk of the feed carbon which does not leave the plant as carbon in the F-T liquid product streams. Ordinarily, in the standard plant design, most of this non-product carbon would be emitted to the atmosphere as CO2, following complete combustion, incineration, or flaring. The intent of this design is capture the non-product carbon (prior to emission) as a single species – CO2 in this instance – and to deliver it for export to the plant battery limit in a ‘pure’ form and at high pressure. This study does not address the collection, transportation, and ultimate disposal/sequestration of this CO2 stream. This adaptation of the standard Shell MDS design takes advantage of the addition of a CO shift section to eliminate the need for an SMR, which was included in the standard design to adjust the F-T synthesis H2:CO ratio to its design value. To account for the loss in syngas provided by the SMR, an additional SGP partial oxidation reactor is needed. This addition brings about a concomitant increase in demand for oxygen from the air separation unit. The following sections identify the plant design, performance, efficiency, capital and operating costs, and product sales price associated with adopting CO2 capture and compression. Comparisons are made to the standard plant design, which is presented in sections 4B1 through 9B1.

79

4B-2 DESIGN BASIS

Plant Capacity


Process Shell MDS (middle distillate synthesis)

Air Separation Unit Conventional, single train cryogenic air separation plant


Syngas Generation Shell Gasification Process (SGP), oxygen-blown.

SGP Partial Oxidation Feed ratios:-

- H2O:C, mole/mole - CO2:C, mole/mole - O2:C, mole/mole

0.17 0.01 0.66


- H2:CO mole ratio 1.77 (2.04 after recycle H2 addition)

F-T Synthesis Shell MDS - fixed-bed reactor design – multi-tubular trickle-bed reactor, ‘once-through’ operation, two-stage series design with interstage product recovery, cobalt F-T synthesis catalyst, internal heat recovery (steam raising)

- operating conditions pressure: 38 bar temperature: 235-238°C




63% 2nd stage

89% overall


80


- operating conditions pressure: 50 bar temperature: 310°C

Product Separation Prefractionation, product fractionation, vacuum fractionation

CO2 Capture Hydrogenation, HT-CO shift, MDEA CO2 removal

CO2 Compression Compression to 110 bar

Hydrogen Separation pressure swing adsorption


81

5B-2 OVERALL PLANT SUMMARY This section summarizes the overall plant performance and costs for a Shell-Type, natural gas Fischer-Tropsch liquefaction plant with CO2 capture and compression facilities. Plant efficiency, carbon emissions, breakdown of product sales price, and capital and operating costs are summarized here. Table 5B-2.1 contains a summary of the major feed and product streams. The plant processes 100 MMSCF/day of natural gas and produces about 10,751 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 5B-2.1 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 5.81 kg/s (4,494 Bbl/day) F-T Distillate 8.90 kg/s (6,257 Bbl/day) Power Import/Export 7.4 MW import Plant Thermal Efficiency


Carbon Emissions


Figure 5B-2.1 is a block flow diagram of the main mass, energy, and carbon flows for the facility

82

0.02 kg/s

19.9 MW

7.4 MW

0 MW

0.8 kg/s

130.6 kg/s

SyngasGeneration 46.5 kg/s

Steam TurbineDrives

& PowerGeneration

Pwr Gen = 12.5 MW

Air SeparationUnit

33.0 kg/s

Fuel Combustion



ProductUpgrading

& Fractionation

163.2

kg/s

Natural Gas

Figure 5B-2.1Mass, Energy, & Carbon Balance Summary

Shell-Type Design - CO2 Capture & Compression

Air

Residue Gas

BFW81 kg/s

HP Steam,77.9 kg/s

MP Steam,96.9 kg/s

45.7 MW S/T Drivers


F-T Liquid






Effluent Water

QOUT= 0.04 TJ/h

QOUT= 0.15 TJ/h

QOUT= 0.113 TJ/h

QOUT= 0.976 TJ/h

QOUT= 0.172 TJ/h

Steam4.7 kg/s

Recycle Gas2.9 kg/s

10.6 kg/s 20.8 kg/s

H2

0.1 kg/sRecycle Gas

1.2 kg/s

16 kg/s0.1 kg/s

BFW97.8 kg/s

F-T Synthesis


CO2 to Pipeline


Steam27.4 kg/s

1.85 kg/s12.81 kg/s

23.8 kg/s

H20.1 kg/s


- Input

- Output


7.25 kg/s

3.1 kg/s

12.8 kg/s 0.01 kg/s

Recycle Gas1.7 kg/s

83

Table 5B-2.2 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 5B-2.2


Area Description Cost (MM$) $/GJ % ISBL 100 Syngas Preparation 118.3 51.3 200 F-T Synthesis/Upgrading 45.0 19.5 300 Steam Generation 25.5 11.1 500 CO2 Capture & Compression 41.9 18.1 Offsites Facilities 122.0 HO Service/Fees/Contingency 93.5 Total Cost: 446.2 (41,507 $/bpd) The above plant costs are order-of-magnitude ± 30% estimates. Table 5B-2.3 shows the annual operating cost summary.

Table 5B-2.3




Total Cost: 45.3

84

Table 5B-2.4 shows the breakdown of the product sales price.

Table 5B-2.4 Product Sales Price




- a 5% discount factor requires a 7.09% capital charge rate Section 9B-2 contains more detailed information on the capital and operating costs for the plant.

85

Table 5B-2.5 is a comparison between a standard Shell-type F-T technology plant design and a Shell-type F-T technology plant designed to include CO2 capture and compression. Table 5B-2.5 presents the cost and efficiency penalties attributable to the adoption of CO2 capture and compression.

Table 5B-2.5 Cost and Efficiency Comparison


"Base Case" "CO2 Capture"

Plant Design Shell MDS Shell MDS














$/Tonne Carbon captured $89.01

86

6B-2 OVERALL PLANT CONFIGURATION This section presents an overall summary of standard Shell-type Fischer-Tropsch synthesis technology. It is divided into two subsections: 6B-2.1 Process Flow Diagrams 6B-2.2 Mass and Energy Balance Tables

6B-2.1 Process Flow Diagrams This section contains the process flow diagrams (PFDs) for each process plant within Areas 100, 200, 300, and 500 in PFDs 102-B-01 through 501-B-01. Each PFD is numbered according to the plant number for the plants in Process Areas 100, 200, 300, 500. Area 100 contains two major plants: • Plant 101, the Air Separation Unit • Plant 102, the SGP Partial Oxidation Plant and H2 Separation Area 200 contains two major plants: • Plant 201, the Shell MDS Fischer-Tropsch Synthesis Plant • Plant 202, the F-T Liquid Product Upgrading and Fractionation Plants Area 300 represents the plant steam distribution system: Area 500 contains the CO2 Capture, Hydrogen Recovery, and CO2 Compression Plants: 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 6B-2.1 and 6B-2.2 in the following section.

87

6B-2.2 Mass and Energy Balance Tables The component flow rates of key streams in process Areas 100, 200, and 500 are shown in Tables 6B-2.2.1 and 6B-2.2.2. The streams are identified by the same stream numbers used in the PFDs shown in the previous section. Table 6B-2.2.1 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 100 200, and 500. Table 6B-2.2.2 contains the same information for the process streams in Areas 100, 200, and 500 except that stream composition is presented in mole fraction.


(MASS FRACTION)

SHELL-TYPE DESIGN: CO2 REDUCTION

1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamNatural

Gas FeedNatural

Gas FeedHydrocarbon Recycle

Prefractn. Overhead

Hydrocarbon Feed to

POX

Oxygen from ASU

MP Steam Addition


Temperature, °C 45 45 182 120 315 200 329 1390

Pressure, bara 43.44 43.44 43.44 42.75 42.75 41.37 42.00 40.33

Molar Flow, kgmole/h 4,980.7 830.1 398.5 110.5 914.9 3,717.9 942.6 2,924.1

Mass Flow, kg/s 23.6 3.9 1.7 1.2 4.4 33.0 4.7 10.7


Mole Wt. 17.086 17.086 15.618 38.002 17.400 31.980 18.015 13.189


H2 0.0474 0.0078 0.0034 0.0808

N2 0.0077 0.0077 0.2799 0.0119 0.0256 0.0044 0.0128

CO 0.1885 0.0444 0.0142 0.6341

CO2 0.0113 0.0113 0.0127 0.2172 0.0204 0.0760

H2O 0.0084 0.0042 0.0007 1.0000 0.1902

O2 0.9956

C1 0.8871 0.8871 0.3128 0.0360 0.8123 0.0060

C2's 0.0605 0.0605 0.0365 0.0281 0.0575

C3's 0.0221 0.0221 0.0718 0.1633 0.0315

C4's 0.0093 0.0093 0.0411 0.4331 0.0300

C5's 0.0020 0.0020 0.0009 0.0470 0.0039

C6's 0.0001

C7-C9

C10-C12

C13-C15

SYNGAS GENERATION


(MASS FRACTION)


2

C16-C18

C19-C23

C24-C29

C30+WAX


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9 10 11 12

StreamCombined

POX Syngas

H2 Recycle Syngas to F-T

Synthesis

POX Syngas to CO Shift

Temperature, °C 60 78 62 145

Pressure, bara 38.47 39.00 38.47 38.75

Molar Flow, kgmole/h 13,437.5 1,743.2 15,180.7 1,992.3

Mass Flow, kg/s 46.4 3.1 49.6 7.2

Enthalpy, kJ/h 1.197E+08 1.661E+07 1.364E+08 2.315E+07

Mole Wt. 12.443 6.435 11.753 13.092


H2 0.0988 0.2489 0.1083 0.0830

N2 0.0157 0.2210 0.0286 0.0132

CO 0.7759 0.1485 0.7364 0.6517

CO2 0.0929 0.0100 0.0877 0.0781

H2O 0.0093 0.0066 0.0091 0.1677

O2

C1 0.0074 0.2465 0.0224 0.0062

C2's 0.0287 0.0018

C3's 0.0566 0.0036

C4's 0.0324 0.0020

C5's 0.0008

C6's

C7-C9

C10-C12

C13-C15

SYNGAS GENERATION


(MASS FRACTION)


4

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamSyngas

Feed to 1st Stg



1st Stg F-T Liquids


2nd Stg. Separator

Vapor

2nd Stg F-T Liquids

HT Separator


Pressure, bara 38.47 36.67 36.67 36.67 34.77 34.77 34.77 34.47


Mass Flow, kg/s 49.6 49.6 36.4 8.8 36.4 34.5 1.9 18.7


Mole Wt. 11.753 20.572 17.029 307.793 21.901 20.828 335.808 21.709


H2 0.1083 0.0314 0.0427 0.0001 0.0150 0.0159 0.0001 0.0292

N2 0.0286 0.0286 0.0389 0.0002 0.0389 0.0410 0.0002 0.0754

CO 0.7364 0.2156 0.2929 0.0014 0.1083 0.1143 0.0006 0.2103

CO2 0.0877 0.0965 0.1309 0.0014 0.1309 0.1380 0.0015 0.2526

H2O 0.0091 0.3353 0.3363 0.0036 0.4545 0.4792 0.0053 0.1295

O2

C1 0.0224 0.0313 0.0424 0.0003 0.0456 0.0481 0.0004 0.0885

C2's 0.0018 0.0037 0.0050 0.0001 0.0057 0.0060 0.0001 0.0109

C3's 0.0036 0.0083 0.0111 0.0003 0.0128 0.0135 0.0003 0.0247

C4's 0.0020 0.0077 0.0103 0.0004 0.0123 0.0129 0.0004 0.0237

C5's 0.0064 0.0086 0.0006 0.0109 0.0114 0.0006 0.0206

C6's 0.0070 0.0091 0.0012 0.0116 0.0122 0.0011 0.0216

C7-C9 0.0225 0.0281 0.0109 0.0362 0.0377 0.0083 0.0601

C10-C12 0.0231 0.0223 0.0373 0.0305 0.0310 0.0232 0.0323

C13-C15 0.0218 0.0108 0.0777 0.0187 0.0173 0.0438 0.0066

F-T SYNTHESIS


(MASS FRACTION)


2

C16-C18 0.0197 0.0035 0.0961 0.0105 0.0078 0.0613 0.0008

C19-C23 0.0280 0.0011 0.1530 0.0112 0.0042 0.1365 0.0001

C24-C29 0.0277 0.0001 0.1554 0.0101 0.0013 0.1702

C30+WAX 0.0815 0.0001 0.4594 0.0293 0.0008 0.5459

Oxygenates 0.0044 0.0057 0.0006 0.0073 0.0077 0.0006 0.0132

Total 1.0000 1.0010 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16

StreamHT

Separator Liquids

LT Separator

Vapor

LT Separator

Liquids


Lean Solvent Feed

Rich Solvent

Absorber Overheads

F-T Liquids to


Pressure, bara 34.47 33.87 33.87 35.51 1.34 34.13 33.44 33.87


Mass Flow, kg/s 1.6 13.9 2.5 0.1 9.9 11.1 12.8 4.1


Mole Wt. 160.974 19.674 96.112 33.565 208.672 159.779 18.658 114.499


H2 0.0002 0.0394 0.0002 0.0315 0.0001 0.0430 0.0002

N2 0.0007 0.1018 0.0011 0.0007 0.1098 0.0009

CO 0.0020 0.2837 0.0034 0.0024 0.3057 0.0028

CO2 0.0063 0.3365 0.0247 0.0151 0.3520 0.0174

H2O 0.0035 0.0026 0.0002 0.0008 0.0001 0.0001 0.0006 0.0015

O2

C1 0.0014 0.1190 0.0035 0.0143 0.0021 0.1274 0.0027

C2's 0.0004 0.0144 0.0019 0.0297 0.0011 0.0151 0.0013

C3's 0.0017 0.0311 0.0123 0.1078 0.0063 0.0292 0.0080

C4's 0.0033 0.0264 0.0311 0.2190 0.0160 0.0167 0.0201

C5's 0.0050 0.0177 0.0563 0.1610 0.0236 0.0004 0.0358

C6's 0.0101 0.0108 0.1026 0.0849 0.0144 0.0657

C7-C9 0.1051 0.0074 0.4122 0.2378 0.0002 0.0122 0.2899

C10-C12 0.2822 0.0003 0.2425 0.0495 0.1177 0.1059 0.2582

C13-C15 0.2874 0.0506 0.0368 0.4813 0.4306 0.1450

F-T SYNTHESIS


(MASS FRACTION)


4

C16-C18 0.1536 0.0061 0.0197 0.3504 0.3132 0.0648

C19-C23 0.0866 0.0007 0.0064 0.0503 0.0451 0.0350

C24-C29 0.0274 0.0005 0.0001 0.0001 0.0109

C30+WAX 0.0171 0.0003 0.0068

Oxygenates 0.0060 0.0088 0.0504 0.0110 0.0327

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


5

Plant Section

Stream No. 17







Mole Wt. 312.435


H2 0.0001

N2 0.0002

CO 0.0013

CO2 0.0014

H2O 0.0039

O2

C1 0.0003

C2's 0.0001

C3's 0.0003

C4's 0.0004

C5's 0.0006

C6's 0.0012

C7-C9 0.0105

C10-C12 0.0350

C13-C15 0.0717

F-T SYNTHESIS


(MASS FRACTION)


6

C16-C18 0.0900

C19-C23 0.1499

C24-C29 0.1579

C30+WAX 0.4748

Oxygenates 0.0006

Total 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8


SolventF-T "Wax"


Stream


Prefractn. Bottoms

Product Fractionato

r Feed

Product Fractionato

r Temperature, °C 86 43 190 234 48 331 361 64

Pressure, bara 33.87 34.13 34.77 35.51 13.79 14.13 1.72 1.10


Mass Flow, kg/s 4.1 11.1 10.7 11.6 1.2 36.3 36.3 0.0


Mole Wt. 114.499 159.779 312.435 180.621 38.002 212.645 212.645 59.781


H2 0.0002 0.0001 0.0001 0.0005 0.0078

N2 0.0009 0.0007 0.0002 0.0118

CO 0.0028 0.0024 0.0013 0.0444

CO2 0.0174 0.0151 0.0014 0.2172 0.0001

H2O 0.0015 0.0001 0.0039 0.0042 0.0634

O2

C1 0.0027 0.0021 0.0003 0.0004 0.0360

C2's 0.0013 0.0011 0.0001 0.0013 0.0281 0.0001

C3's 0.0080 0.0063 0.0003 0.0072 0.1633 0.0010

C4's 0.0201 0.0160 0.0004 0.0226 0.4331 0.0007 0.0007 0.0378

C5's 0.0358 0.0236 0.0006 0.0244 0.0470 0.0178 0.0178 0.4574

C6's 0.0657 0.0144 0.0012 0.0195 0.0001 0.0184 0.0184 0.1697

C7-C9 0.2899 0.0122 0.0105 0.1072 0.0740 0.0740 0.1321

C10-C12 0.2582 0.1059 0.0350 0.0743 0.0957 0.0957 0.0060

C13-C15 0.1450 0.4306 0.0717 0.1623 0.2210 0.2210

C16-C18 0.0648 0.3132 0.0900 0.2269 0.2021 0.2021



(MASS FRACTION)


2

C19-C23 0.0350 0.0451 0.1499 0.1571 0.1121 0.1121

C24-C29 0.0109 0.0001 0.1579 0.0496 0.0636 0.0636

C30+WAX 0.0068 0.4748 0.1466 0.1875 0.1875

Oxygenates 0.0327 0.0110 0.0006 0.0069 0.0071 0.0071 0.1325

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16



Product Diesel


Product Diesel

Vacuum Column

Ohd.


Hydrocracker Makeup

H2Temperature, °C 64 45 45 298 45 45 300 48

Pressure, bara 1.10 1.34 1.34 1.52 0.13 1.10 49.64 34.30


Mass Flow, kg/s 5.8 9.9 6.3 14.2 2.6 0.0 11.6 0.1


Mole Wt. 103.453 208.672 208.672 386.682 250.723 174.432 442.364 2.016


H2 1.0000

N2

CO

CO2

H2O 0.0005 0.0001 0.0001 0.0003 0.0001

O2

C1

C2's

C3's

C4's 0.0036

C5's 0.1091 0.0019

C6's 0.1145 0.0056

C7-C9 0.4607 0.0002 0.0002 0.1347

C10-C12 0.2676 0.1177 0.1177 0.0006 0.0031 0.2789

C13-C15 0.0007 0.4813 0.4813 0.0136 0.0739 0.3412 0.0002

C16-C18 0.3504 0.3504 0.1153 0.5360 0.2028 0.0231



(MASS FRACTION)


4

C19-C23 0.0503 0.0503 0.2287 0.3858 0.0319 0.1945

C24-C29 0.0001 0.0001 0.1624 0.0012 0.1980

C30+WAX 0.4789 0.5840


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


5

Plant Section

Stream No. 17 18 19 20 21 22

StreamHydrocrack



Gas


Hydrocracker Purge

Gas


Temperature, °C 310 350 45 234 59 234

Pressure, bara 47.92 46.54 45.51 35.51 51.71 35.51


Mass Flow, kg/s 12.4 12.4 0.7 11.7 0.0 0.1


Mole Wt. 60.345 60.350 5.216 172.812 5.216 33.565


H2 0.0271 0.0211 0.3512 0.0008 0.3512 0.0315

N2

CO

CO2

H2O 0.0003 0.0003 0.0038 0.0038 0.0008

O2

C1 0.0053 0.0059 0.0935 0.0005 0.0935 0.0143

C2's 0.0053 0.0069 0.0931 0.0016 0.0931 0.0297

C3's 0.0100 0.0180 0.1759 0.0083 0.1759 0.1078

C4's 0.0101 0.0335 0.1779 0.0246 0.1779 0.2190

C5's 0.0039 0.0283 0.0682 0.0259 0.0682 0.1610

C6's 0.0009 0.0200 0.0171 0.0202 0.0171 0.0849

C7-C9 0.0011 0.1033 0.0188 0.1085 0.0188 0.2378

C10-C12 0.0697 0.0005 0.0740 0.0005 0.0495

C13-C15 0.0002 0.1517 0.1611 0.0368

C16-C18 0.0216 0.2117 0.2247 0.0197



(MASS FRACTION)


6

C19-C23 0.1821 0.1465 0.1555 0.0064

C24-C29 0.1853 0.0464 0.0492 0.0005

C30+WAX 0.5467 0.1367 0.1451 0.0003

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamF-T

Synthesis Purge Gas

Hydrocracker Purge

Gas

Hydrotreater Feed


MP Steam Addition

Syngas Bypass

from POX

CO Shift Feed

CO2 Absorber

FeedTemperature, °C 14 59 270 302 329 145 340 45

Pressure, bara 33.44 51.71 39.52 38.83 42.00 38.75 38.13 36.20

Molar Flow, kgmole/h 2,465.8 9.9 2,475.7 2,453.0 5,478.8 1,992.3 9,924.0 5,190.6

Mass Flow, kg/s 12.8 0.0 12.8 12.8 27.4 7.2 47.5 23.7


Mole Wt. 18.658 5.216 18.604 18.777 18.015 13.092 17.215 16.455


H2 0.0430 0.3512 0.0433 0.0423 0.0830 0.0241 0.0713

N2 0.1098 0.1097 0.1097 0.0132 0.0316 0.0632

CO 0.3057 0.3054 0.3054 0.6517 0.1818 0.0425

CO2 0.3520 0.3516 0.3516 0.0781 0.1067 0.7148

H2O 0.0006 0.0038 0.0006 0.0006 1.0000 0.1677 0.6035 0.0038

O2

C1 0.1274 0.0935 0.1274 0.1274 0.0062 0.0353 0.0706

C2's 0.0151 0.0931 0.0152 0.0153 0.0041 0.0082

C3's 0.0292 0.1759 0.0294 0.0300 0.0081 0.0162

C4's 0.0167 0.1779 0.0168 0.0172 0.0046 0.0093

C5's 0.0004 0.0682 0.0004 0.0004 0.0001 0.0003

C6's 0.0171

C7-C9 0.0188

C10-C12 0.0005

C13-C15

CO2 CAPTURE AND COMPRESSION


(MASS FRACTION)


2

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16

StreamTreated

Gas Recycle to

Lean Amine

Rich Amine

Captured CO2 to

Compressi

H2 to Hydrocrack

er

H2 Fuel Hydrocarbon Recycle

to POX

Hydrocarbon Fuel

Temperature, °C 45 111 80 45 48 48 182 45

Pressure, bara 35.70 2.00 4.14 1.38 34.30 34.30 43.44 1.65

Molar Flow, kgmole/h 1,743.2 73,155.5 74,613.1 1,390.5 159.4 1,229.5 398.5 269.4

Mass Flow, kg/s 3.1 498.3 515.5 16.9 0.1 0.7 1.7 1.2

Enthalpy, kJ/h 1.484E+07 -1.447E+09 -1.731E+09 1.468E+07 1.291E+06 9.962E+06 5.761E+06 2.604E+06

Mole Wt. 6.433 24.52 24.87 43.843 2.016 2.016 15.618 15.618


H2 0.2490 1.0000 1.0000 0.0474 0.0474

N2 0.2207 0.2799 0.2799

CO 0.1486 0.1885 0.1885

CO2 0.0100 0.0104 0.0426 0.9973 0.0127 0.0127

H2O 0.0066 0.6844 0.6624 0.0026 0.0084 0.0084

O2

C1 0.2466 0.3128 0.3128

C2's 0.0287 0.0365 0.0365

C3's 0.0566 0.0718 0.0718

C4's 0.0324 0.0411 0.0411

C5's 0.0008 0.0009 0.0009

C6's

C7-C9

C10-C12

C13-C15



(MASS FRACTION)


4

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates

Amine 0.3052 0.2950

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamNatural

Gas FeedNatural

Gas FeedHydrocarbon Recycle

Prefractn. Overhead

Hydrocarbon Feed to

POX

Oxygen from ASU

MP Steam Addition


Temperature, °C 45 45 182 120 315 200 329 1390

Pressure, bara 43.44 43.44 43.44 42.75 42.75 41.37 42.00 40.33

Molar Flow, kgmole/h 4,980.7 830.1 398.5 110.5 914.9 3,717.9 942.6 2,924.1

Mass Flow, kg/s 23.6 3.9 1.7 1.2 4.4 33.0 4.7 10.7


Mole Wt. 17.086 17.086 15.617 38.002 17.400 31.980 18.015 13.189


H2 0.3670 0.1476 0.0296 0.5284

N2 0.0047 0.0047 0.1560 0.0161 0.0159 0.0050 0.0060

CO 0.1051 0.0602 0.0088 0.2986

CO2 0.0044 0.0044 0.0045 0.1875 0.0081 0.0228

H2O 0.0073 0.0088 0.0007 1.0000 0.1392

O2 0.9950

C1 0.9448 0.9448 0.3045 0.0852 0.8810 0.0050

C2's 0.0344 0.0344 0.0189 0.0357 0.0333

C3's 0.0086 0.0086 0.0254 0.1423 0.0125

C4's 0.0028 0.0028 0.0111 0.2857 0.0091

C5's 0.0004 0.0004 0.0003 0.0253 0.0010

C6's

C7-C9

C10-C12

C13-C15

SYNGAS GENERATION


(MOLE FRACTION)


2

C16-C18

C19-C23

C24-C29

C30+WAX


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3

Plant Section

Stream No. 9 10 11 12Stream Combined H2 Recycle Syngas to POX Temperature, °C 60 78 62 145

Pressure, bara 38.47 39.00 38.47 38.75

Molar Flow, kgmole/h 13,437.5 1,743.2 15,180.7 1,992.3

Mass Flow, kg/s 46.4 3.1 49.6 7.2

Enthalpy, kJ/h 1.197E+08 1.661E+07 1.364E+08 2.315E+07

Mole Wt. 12.443 6.435 11.753 13.092


H2 0.6099 0.7944 0.6311 0.5390

N2 0.0070 0.0508 0.0120 0.0062

CO 0.3447 0.0341 0.3090 0.3046

CO2 0.0263 0.0015 0.0234 0.0232

H2O 0.0064 0.0024 0.0059 0.1219

O2

C1 0.0057 0.0989 0.0164 0.0051

C2's 0.0061 0.0007

C3's 0.0083 0.0009

C4's 0.0036 0.0004

C5's 0.0001

C6's

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

SYNGAS GENERATION


(MOLE FRACTION)


4

C24-C29

C30+WAX

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamSyngas

Feed to 1st Stg



1st Stg F-T Liquids


2nd Stg. Separator

Vapor

2nd Stg F-T Liquids

HT Separator


Pressure, bara 38.47 36.67 36.67 36.67 34.77 34.77 34.77 34.47


Mass Flow, kg/s 49.6 49.6 36.4 8.8 36.4 34.5 1.9 18.7


Mole Wt. 11.753 20.572 17.029 307.793 21.901 20.828 335.808 21.709


H2 0.6311 0.3207 0.3607 0.0227 0.1634 0.1639 0.0115 0.3144

N2 0.0120 0.0210 0.0236 0.0020 0.0304 0.0305 0.0027 0.0585

CO 0.3090 0.1584 0.1781 0.0153 0.0847 0.0850 0.0076 0.1630

CO2 0.0234 0.0451 0.0506 0.0097 0.0651 0.0653 0.0113 0.1246

H2O 0.0059 0.3829 0.3179 0.0624 0.5525 0.5541 0.0988 0.1560

O2

C1 0.0164 0.0401 0.0450 0.0059 0.0622 0.0624 0.0081 0.1197

C2's 0.0007 0.0025 0.0028 0.0008 0.0042 0.0042 0.0010 0.0079

C3's 0.0009 0.0039 0.0044 0.0019 0.0065 0.0065 0.0023 0.0124

C4's 0.0004 0.0028 0.0031 0.0025 0.0047 0.0047 0.0028 0.0089

C5's 0.0019 0.0021 0.0025 0.0033 0.0033 0.0028 0.0063

C6's 0.0017 0.0019 0.0041 0.0030 0.0030 0.0041 0.0055

C7-C9 0.0041 0.0042 0.0286 0.0069 0.0069 0.0240 0.0117

C10-C12 0.0031 0.0024 0.0727 0.0043 0.0042 0.0494 0.0045

F-T SYNTHESIS


(MOLE FRACTION)


2

C13-C15 0.0022 0.0009 0.1201 0.0020 0.0018 0.0737 0.0007

C16-C18 0.0017 0.0002 0.1234 0.0010 0.0007 0.0854

C19-C23 0.0020 0.1597 0.0008 0.0003 0.1544

C24-C29 0.0015 0.1291 0.0006 0.1539

C30+WAX 0.0028 0.2336 0.0011 0.3029

Oxygenates 0.0017 0.0019 0.0034 0.0031 0.0031 0.0034 0.0056

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg


Plant Section

Stream No. 9 10 11 12 13 14 15 16

StreamHT

Separator Liquids

LT Separator

Vapor

LT Separator

Liquids


Lean Solvent Feed

Rich Solvent

Absorber Overheads

F-T Liquids to


Pressure, bara 34.47 33.87 33.87 35.51 1.34 34.13 33.44 33.87


Mass Flow, kg/s 1.6 13.9 2.5 0.1 9.9 11.1 12.8 4.1


Mole Wt. 160.974 19.674 96.112 33.565 208.672 159.779 18.658 114.499


H2 0.0146 0.3848 0.0105 0.5246 0.0114 0.3975 0.0116

F-T SYNTHESIS


(MOLE FRACTION)


3

N2 0.0038 0.0715 0.0037 0.0041 0.0731 0.0037

CO 0.0112 0.1993 0.0118 0.0137 0.2037 0.0116

CO2 0.0230 0.1504 0.0539 0.0546 0.1492 0.0452

H2O 0.0309 0.0028 0.0012 0.0016 0.0012 0.0010 0.0007 0.0096

O2

C1 0.0141 0.1459 0.0212 0.0300 0.0208 0.1482 0.0192

C2's 0.0022 0.0095 0.0061 0.0331 0.0056 0.0094 0.0050

C3's 0.0064 0.0142 0.0272 0.0820 0.0235 0.0126 0.0213

C4's 0.0090 0.0090 0.0525 0.1265 0.0448 0.0054 0.0401

C5's 0.0113 0.0049 0.0761 0.0749 0.0529 0.0001 0.0578

C6's 0.0192 0.0025 0.1157 0.0330 0.0270 0.0882

C7-C9 0.1444 0.0013 0.3523 0.0736 0.0005 0.0183 0.2934

C10-C12 0.2894 0.1534 0.0108 0.1452 0.1003 0.1919

C13-C15 0.2358 0.0253 0.0064 0.5058 0.3465 0.0849

C16-C18 0.1040 0.0025 0.0027 0.3084 0.2111 0.0313

C19-C23 0.0485 0.0002 0.0007 0.0388 0.0265 0.0139

C24-C29 0.0121 0.0001 0.0035

C30+WAX 0.0046 0.0013

Oxygenates 0.0153 0.0037 0.0864 0.0373 0.0662

Total 1.0000 1.0000 1.0000 1.0000 1.0000 0.9990 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


4

Plant Section

Stream No. 17







Mole Wt. 312.435


H2 0.0208

N2 0.0021

CO 0.0140

CO2 0.0099

H2O 0.0684

O2

C1 0.0063

C2's 0.0008

C3's 0.0020

C4's 0.0025

C5's 0.0026

C6's 0.0041

C7-C9 0.0279

C10-C12 0.0688

F-T SYNTHESIS


(MOLE FRACTION)


5

C13-C15 0.1125

C16-C18 0.1171

C19-C23 0.1588

C24-C29 0.1333

C30+WAX 0.2451

Oxygenates 0.0033

Total 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8


SolventF-T "Wax"


Stream


Prefractn. Bottoms

Product Fractionato

r Feed

Product Fractionato

r Temperature, °C 86 43 190 234 48 331 361 64

Pressure, bara 33.87 34.13 34.77 35.51 13.79 14.13 1.72 1.10


Mass Flow, kg/s 4.1 11.1 10.7 11.6 1.2 36.3 36.3 0.0


Mole Wt. 114.499 159.779 312.435 180.621 38.002 212.645 212.645 59.781


H2 0.0116 0.0114 0.0208 0.0406 0.1476

N2 0.0037 0.0041 0.0021 0.0161

CO 0.0116 0.0137 0.0140 0.0602

CO2 0.0452 0.0546 0.0099 0.1876 0.0001

H2O 0.0096 0.0010 0.0684 0.0003 0.0088 0.2105

O2

C1 0.0192 0.0208 0.0063 0.0041 0.0852

C2's 0.0050 0.0056 0.0008 0.0078 0.0357 0.0001

C3's 0.0213 0.0235 0.0020 0.0296 0.1423 0.0013

C4's 0.0401 0.0448 0.0025 0.0701 0.2857 0.0022 0.0022 0.0389

C5's 0.0578 0.0529 0.0026 0.0612 0.0253 0.0528 0.0528 0.3827

C6's 0.0882 0.0270 0.0041 0.0409 0.0458 0.0458 0.1186

C7-C9 0.2934 0.0183 0.0279 0.1732 0.1402 0.1402 0.0751

C10-C12 0.1919 0.1003 0.0688 0.0848 0.1270 0.1270 0.0024

C13-C15 0.0849 0.3465 0.1125 0.1466 0.2365 0.2365

C16-C18 0.0313 0.2111 0.1171 0.1696 0.1798 0.1798



(MOLE FRACTION)


2

C19-C23 0.0139 0.0265 0.1588 0.1030 0.0844 0.0844

C24-C29 0.0035 0.1333 0.0243 0.0366 0.0366

C30+WAX 0.0013 0.2451 0.0438 0.0659 0.0659

Oxygenates 0.0662 0.0373 0.0033 0.0057 0.0287 0.0287 0.1699

Total 1.0000 0.9990 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16



Product Diesel


Product Diesel

Vacuum Column

Ohd.


Hydrocracker Makeup

H2Temperature, °C 64 45 45 298 45 45 300 48

Pressure, bara 1.10 1.34 1.34 1.52 0.13 1.10 49.64 34.30


Mass Flow, kg/s 5.8 9.9 6.3 14.2 2.6 0.0 11.6 0.1


Mole Wt. 103.453 208.672 208.672 386.682 250.723 174.432 442.364 2.016


H2 1.0000

N2

CO

CO2

H2O 0.0028 0.0012 0.0012 0.0068 0.0002 0.0012 0.0011

O2

C1

C2's

C3's 0.0001

C4's 0.0065 0.0001

C5's 0.1577 0.0047

C6's 0.1384 0.0116

C7-C9 0.4245 0.0005 0.0005 0.0001 0.1986

C10-C12 0.1836 0.1452 0.1452 0.0013 0.0045 0.3062

C13-C15 0.0004 0.5058 0.5058 0.0256 0.0901 0.3025 0.0006

C16-C18 0.3084 0.3084 0.1813 0.5481 0.1484 0.0409



(MOLE FRACTION)


4

C19-C23 0.0388 0.0388 0.3095 0.3560 0.0207 0.2943

C24-C29 0.0001 0.0001 0.1695 0.0008 0.2363

C30+WAX 0.3060 0.4269


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


5

Plant Section

Stream No. 17 18 19 20 21 22

StreamHydrocrack



Gas


Hydrocracker Purge

Gas


Temperature, °C 310 350 45 234 59 234

Pressure, bara 47.92 46.54 45.51 35.51 51.71 35.51


Mass Flow, kg/s 12.4 12.4 0.7 11.7 0.0 0.1


Mole Wt. 60.345 60.350 5.216 172.812 5.216 33.565


H2 0.8123 0.6315 0.9087 0.0663 0.9087 0.5246

N2

CO

CO2

H2O 0.0009 0.0009 0.0011 0.0004 0.0011 0.0016

O2

C1 0.0199 0.0222 0.0304 0.0055 0.0304 0.0300

C2's 0.0106 0.0139 0.0162 0.0092 0.0162 0.0331

C3's 0.0137 0.0246 0.0208 0.0324 0.0208 0.0820

C4's 0.0105 0.0348 0.0160 0.0731 0.0160 0.1265

C5's 0.0033 0.0237 0.0049 0.0619 0.0049 0.0749

C6's 0.0006 0.0140 0.0010 0.0405 0.0010 0.0330

C7-C9 0.0006 0.0559 0.0008 0.1679 0.0008 0.0736

C10-C12 0.0267 0.0809 0.0108

C13-C15 0.0001 0.0457 0.1391 0.0064

C16-C18 0.0052 0.0530 0.1609 0.0027



(MOLE FRACTION)


6

C19-C23 0.0375 0.0321 0.0977 0.0007

C24-C29 0.0302 0.0075 0.0229

C30+WAX 0.0545 0.0136 0.0414

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamF-T

Synthesis Purge Gas

Hydrocracker Purge

Gas

Hydrotreater Feed


MP Steam Addition

Syngas Bypass

from POX

CO Shift Feed

CO2 Absorber

FeedTemperature, °C 14 59 270 302 329 145 340 45

Pressure, bara 33.44 51.71 39.52 38.83 42.00 38.75 38.13 36.20

Molar Flow, kgmole/h 2,465.8 9.9 2,475.7 2,453.0 5,478.8 1,992.3 9,924.0 5,190.6

Mass Flow, kg/s 12.8 0.0 12.8 12.8 27.4 7.2 47.5 23.7


Mole Wt. 18.658 5.216 18.604 18.777 18.015 13.092 17.215 16.455


H2 0.3975 0.9087 0.3996 0.3940 0.5390 0.2056 0.5816

N2 0.0731 0.0728 0.0735 0.0062 0.0194 0.0371

CO 0.2037 0.2028 0.2047 0.3046 0.1118 0.0250

CO2 0.1492 0.1486 0.1500 0.0232 0.0417 0.2672

H2O 0.0007 0.0011 0.0007 0.0007 1.0000 0.1219 0.5767 0.0034

O2

C1 0.1482 0.0304 0.1477 0.1491 0.0051 0.0379 0.0724

C2's 0.0094 0.0162 0.0095 0.0095 0.0024 0.0045

C3's 0.0126 0.0208 0.0127 0.0128 0.0032 0.0060

C4's 0.0054 0.0160 0.0055 0.0056 0.0014 0.0026

C5's 0.0001 0.0049 0.0001 0.0001

C6's 0.0010

C7-C9 0.0008

C10-C12

C13-C15



(MOLE FRACTION)


2

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16

StreamTreated

Gas Recycle to

Lean Amine

Rich Amine

Captured CO2 to

Compressi

H2 to Hydrocrack

er

H2 Fuel Hydrocarbon Recycle

to POX

Hydrocarbon Fuel

Temperature, °C 45 111 80 45 48 48 182 45

Pressure, bara 29.65 2.00 4.14 1.38 34.30 34.30 43.44 1.65

Molar Flow, kgmole/h 1,743.2 73,155.5 74,613.1 1,390.5 159.4 1,229.5 398.5 269.4

Mass Flow, kg/s 3.1 498.3 515.5 16.9 0.1 0.7 1.7 1.2

Enthalpy, kJ/h 1.484E+07 -1.447E+09 -1.731E+09 1.468E+07 1.291E+06 9.962E+06 5.761E+06 2.604E+06

Mole Wt. 6.433 24.52 24.87 43.843 2.016 2.016 15.617 15.618


H2 0.7944 1.0000 1.0000 0.3670 0.3670

N2 0.0507 0.1560 0.1560

CO 0.0341 0.1051 0.1051

CO2 0.0015 0.0058 0.0241 0.9936 0.0045 0.0045

H2O 0.0024 0.9314 0.9143 0.0064 0.0073 0.0073

O2

C1 0.0989 0.3045 0.3045

C2's 0.0061 0.0189 0.0189

C3's 0.0083 0.0254 0.0254

C4's 0.0036 0.0111 0.0111

C5's 0.0001 0.0003 0.0003

C6's

C7-C9

C10-C12

C13-C15



(MOLE FRACTION)


4

C16-C18

C19-C23

C24-C29

C30+WAX

Oxygenates

Amine 0.0628 0.0616

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg


88

7B-2 PROCESS DESCRIPTION The design basis and major assumptions for each major ISBL plant are presented in Sections 3 and 4B-

2. Area 100 - Syngas Generation Area 100 is the syngas generation area. This area consists of the following plants. Plant 101 Air Separation Unit Plant 102 SGP Partial Oxidation Plant The sulfur removal, heat recovery/steam generation, and syngas cooling are parts of Plant 102, the SGP Partial Oxidation Plant. Plant 101, the Air Separation Unit, contains an inlet air compressor. The cryogenic air separation portion of Plant 101 produces a 99.5 mole % oxygen stream which is a feed stream to Plant 102, the SGP Partial Oxidation Plant. The oxygen stream is distributed to six SGP partial oxidation reactors operating in parallel. Each reactor includes oxygen feed preheat and MP steam addition. Plant 102, the SGP Partial Oxidation Plant, first removes trace amounts of sulfur compounds from the natural gas by reaction with zinc oxide. Prefractionator ‘overheads’ and PSA residue gas from hydrogen recovery are then added to the natural gas downstream of the desulfurization units. The combined feed stream is split into six streams; each flowing to one of the six SGP partial oxidation reactors. The individual feed streams mix with oxygen at a burner inside each partial oxidation reactor. Partial combustion reactions between the fuel and oxidant occur at the burner, followed by homogeneous ‘reforming’ and CO-shift reactions to form syngas in the main body of the refractory lined vessel. The hot syngas product stream is cooled by steam generation, feed/effluent heat exchange, and cooling with ambient air. Any carbon, or soot, which might be formed during partial oxidation, is removed from the gas stream by scrubbing the gas with water in the Carbon Scrubber, 102C-1. Plant 102 produces a combined synthesis gas steam having a molar H2:CO ratio of 1.77. In order to raise the H2:CO ratio to the design value for F-T synthesis, 12% of the syngas leaving the carbon scrubber in Plant 102 is diverted to Plant 500, the CO2 Capture, Hydrogen Recovery, and CO2 Compression Plant. There it mixes with F-T synthesis purge gas and is processed to produce a hydrogen-rich stream. Part of this hydrogen-rich stream is mixed with the balance of the Plant 102 syngas, raising the H2:CO ratio to 2.04. The following subsections give a more detailed description on each of the process plants in Area 100, the Syngas Preparation Area.

89

Plant 101 - Air Separation Unit Plant 101, the Air Separation Unit, provides the required oxygen feed to Plant 102, the SGP Partial Oxidation Plant, for syngas generation. The air separation portion of Plant 101 is a standard cryogenic air separation unit. The air compressor and oxygen compressor are driven by steam turbines. The cryogenic air separation unit is a single train with a capacity of about 3,145 STPD of 99.5 mole % pure oxygen. The design incorporates a backup system including a liquid oxygen storage capacity of 3,100 tons. This backup oxygen storage system protects the facility from an unscheduled shutdown of one day or less. Process Description In the air separation section, ambient air is filtered and compressed in a two-stage axial centrifugal compressor with interstage cooling. The air from the final stage of compression enters a direct contact aftercooler where it contacts cooling water and chilled cooling water in two separate packed sections. The cooled air from the top of the aftercooler has lost the majority of its ambient water vapor. Removal of the residual water vapor, carbon dioxide and other atmospheric contaminants occurs in the molecular sieve adsorbers. The dry air enters the "cold box" where it is cooled to cryogenic temperature in the main heat exchangers and is separated into oxygen and nitrogen by cryogenic distillation. Final cooling is by expansion. The oxygen stream is further purified in an argon column to 99.5 mole %. The main heat exchangers are brazed aluminum, multipass, plate-fin units in which the entering air is cooled against the cold oxygen and nitrogen streams leaving the distillation columns. The oxygen product stream leaving the cryogenic separation section is warmed in the main heat exchangers and compressed to final delivery pressure in a centrifugal compressor. In order to insure a continuous supply of oxygen, backup storage systems are included in the design

90

Plant 102 - SGP Partial Oxidation The objective for Plant 102, the SGP Partial Oxidation Plant, is to provide a syngas with a H2:CO ratio of about 2.0 for F-T synthesis. The partial oxidation reactor is designed to operate with the following feed ratios: H2O:C, mole/mole 0.17 CO2:C, mole/mole 0.01 O2:C, mole/mole 0.66 The adiabatic flame temperature at the burner is approximately 2,000°C. A process flow diagram of Plant 102, the SGP Partial Oxidation Plant, is shown in PFD 102-B-01. The individual natural gas feed streams are heated in exchangers 102E-3A-F, respectively, before being desulfurized in the zinc oxide desulfurization vessels, 102R-1A/B. Sulfur is removed to the less than 0.1 ppm by volume, as required for subsequent Fischer-Tropsch synthesis. Overheads from the Prefractionator and hydrocarbon recycle from Plant 500 are mixed with the natural gas to form the fuel feed to the six SGP partial oxidation reactors, 102R-2A-F. The SGP partial oxidation reactor is a refractory-lined carbon steel vessel containing an axially down-fired burner. Hydrocarbon feed fuel is partially combusted by mixing with oxygen, below the full-combustion stoichiometric amount, at the burner. Downstream of the burner combustion zone, residual hydrocarbons are homogeneously and adiabatically reformed to syngas according to the overall reforming and CO-shift reactions. Syngas from each SGP partial oxidation reactor is cooled in a waste heat boiler, 102E-2A-F, by raising 102 bar saturated steam. Syngas from each reactor is then further cooled by preheating boiler feedwater and demineralized feedwater in exchangers 102E-4A-F and 102E-5A-F, respectively. The individual syngas streams are combined and collectively scrubbed with water to remove any soot formed during the partial oxidation stage, in the Carbon Scrubber, 102C-1. On leaving the carbon scrubber, 12% of Plant 102 syngas is diverted from the main syngas stream to Plant 500, where it mixes with F-T synthesis purge gas. Following CO shift and CO2 removal in Plant 500, this stream, now hydrogen-rich, returns to Plant 102 where it mixes with the main syngas stream to raise its H2:CO ratio from 1.77 to the F-T synthesis design value. This approach, which takes advantage of the inclusion of CO shift to facilitate CO2 capture, allows the SMR to be eliminated. Final cooling of the syngas to 60oC is accomplished in air cooler 102E-9. The cooled syngas goes to separator 102C-3, where process condensate is separated from product syngas.

91

Area 200 - Fisher-Tropsch Synthesis and Product Upgrading Area 200 is the Fischer-Tropsch synthesis and product upgrading area. It consists of the following plants: Plant 201 Shell MDS-Type Fischer-Tropsch Synthesis and Hydrocarbon Recovery Plant Plant 202 Product Fractionation & Wax Hydrocracking Plant This design is based on fixed-bed reactor technology and cobalt-based F-T synthesis catalyst with limited water-gas shift activity. The product fractionation and upgrading steps consist of standard fractionation technology and mild wax hydrocracking. The following subsections give a more detailed description on each of the process plants in Area 200, the Fischer-Tropsch Synthesis and Product Upgrading Area. Plant 201 - Shell MDS Fischer-Tropsch Synthesis The principle function of this plant is to convert the syngas produced in Area 100 into hydrocarbon products using a series of multi-tubular, trickle-bed, cobalt catalyst reactors. The reactor section for this plant consists of three fixed-bed reactors – two parallel first-stage reactors with a single second-stage reactor, in series. The reactor section operates as ‘once-through’, i.e. there is no direct recycle of unconverted syngas leaving the reactors back to the reactor feed. In fact, light hydrocarbons recovered in Plant 500 downstream of F-T synthesis are recycled to Area 100 for conversion to syngas. Fischer-Tropsch reactions produce mainly straight chain paraffins and are highly exothermic. The carbon number distribution of the hydrocarbon product is known to closely follow a single-parameter (α) probability model for hydrocarbon chain growth and termination i.e., αn-1(1-α); where α represents the probability for chain growth. The model predicts the chance of a certain carbon-number molecule being formed in relation to an entire distribution of possible carbon numbers. In practice, α values in the range 0.7-0.95 lead to a F-T-synthesis product distribution with carbon numbers above (F-T wax) and below the carbon numbers associated with the study products – diesel and naphtha. Commercially, where LPG is not recovered as product, the low carbon number species are mainly used as fuel, or else recycled as feedstock to the syngas generation section of the plant. Carbon number products beyond the acceptable diesel end-point (say > C20) have to be cracked to lower carbon-number products, which are recovered through fractionation. Design Basis and Considerations The CO conversion (to hydrocarbon and a small amount of CO2) in the reactor section is approximately 89%.

92

In this design, the heat generated by the F-T synthesis reaction is removed by generation of 15 bar saturated steam in tubes inside the reactor. The two 1st stage Fischer-Tropsch reactors are about 5.0 m diameter and about 20 m in height. Each reactor contains about 3,500 tubes having a 50 mm OD for steam generation. The 2nd stage reactor is about 4.9 m diameter and about 20 m in height and contains about 2,700 x 50 mm OD tubes. The process flow diagrams for Plant 201, F-T synthesis, are shown in PFD 201-B-01. As shown in PFD 201-B-01, the combined syngas from Plant 102 is heated to the reactor inlet temperature (235°C) through reactor feed/effluent heat exchange and steam preheating. CO and H2 in the syngas are converted according to Fischer-Tropsch chemistry into a paraffinic hydrocarbon product - principally middle distillates. The 1st stage reactor product stream is cooled in 201E-2A/B and the liquid product separated from the vapor stream, in 201C-2. The vapor stream is reheated to reactor feed conditions through feed/effluent heat exchange and steam preheating. Unconverted CO and H2 form the 1st stage reactor are converted to paraffinic hydrocarbon products in the 2nd stage reactor. The 2nd stage reactor product stream is cooled in exchangers 201E-4, 201E-6, 201E-10, and 201E-7. As the product stream is cooled it forms a three-phase mixture, which is separated into an unconverted syngas stream, liquid hydrocarbon streams, and water streams, in 201C-3, 201C-4, and 201C-5,. The combined liquid hydrocarbon stream is sent directly to product fractionation and the water steams go to water treatment. Plant 201 - Hydrocarbon Recovery A chilled lean oil absorption unit using a diesel recycle stream as the solvent recovers additional C5+ components in the F-T reactor effluent gas stream downstream of the cooling/recovery train. Rich solvent leaving the bottom of the absorber is fed to the product fractionation plant. Plant 202 – Product Fractionation The prefractionator, 202C-1, receives hydrocarbon liquids (middle distillates and wax) from the F-T cooling train section, rich solvent bottoms from the lean oil absorber, and hydrocarbon liquid recycle from the hydrocracker. Light non-condensable gases and C4- hydrocarbons are removed in the prefractionator prior to product fractionation. The prefractionator overhead stream is compressed and recycled to the syngas generation section where it is mixed with the natural gas feed. The product fractionator, 202C-3, separates the prefractionator bottoms stream into an overhead liquid naphtha product and a diesel product, which is drawn from the bottom of the product fractionator side-

93

stripper. A small, light-hydrocarbon and non-condensable gases overhead stream is also separated. The overhead vapor stream is compressed and sent to the plant fuel system. The naphtha product has an ASTM D-86 end-point of 204°C. It is cooled and sent to storage. The diesel product (ASTM D-86 end-point 320°C) is cooled, dehydrated, and split into a lean oil recycle stream and a diesel product stream. Product fractionator bottoms is sent to the vacuum column, 202C-7. A diesel distillate is produced from the top pump-around section and a 350+°C boiling range gas oil is produced as bottoms. The diesel distillate has an ASTM D-86 end-point of 350°C. The gas oil stream is sent to the hydrocracker. Plant 202 - Wax Hydrocracking The Wax Hydrocracking Plant, catalytically cracks the F-T wax product under a hydrogen environment into lower-boiling material, mainly naphtha and diesel. Hydrocracking operating conditions for the Shell MDS-Type F-T plant are assumed to be 310°C and 48 bar for this study. The vacuum column-bottom stream is pumped to hydrocracker operating pressure, 48 bar. The liquid stream mixes with recycle hydrogen and is preheated to the hydrocracker reactor inlet temperature, 310°C. The hydrocracked product is cooled from 350°C to 45°C. The hydrocracked liquid is flashed before being recycled to the prefractionator. The high-pressure gas stream is compressed and recycled to the reactor. A small purge gas stream is sent to the plant fuel system to prevent the buildup of inert in the system. Flash vapor from hydrocracked liquid depressurization is sent to the lean oil absorber for hydrocarbon recovery. Hydrocracking performs the following functions:


94

Area 300 - Steam Distribution System HP superheated steam is raised in Plant 102 by heat recovery from the syngas generation unit. HP steam drives the air separation unit air compressor. An extraction from the turbine at MP steam level (42 bar) provides steam to the MP steam users. The turbine exhaust, at 1 bar, is condensed in an air cooler followed by a seawater trim cooler. Steam raised in the F-T reactor coils at 15 bar is superheated in fired heater, 201F-1, to 300°C. The steam drives the air separation unit oxygen compressor and the plant steam turbine-driven electric power generator. The LP steam users are supplied with steam from the generator turbine exhaust. Excess LP steam is condensed in an air cooler with a seawater trim cooler.

95

Area 500 - CO2 Capture and Compression Area 500 is the CO2 capture and compression area. It consists of the following plants: • Feed gas Hydrogenation and HT-CO Shift • MDEA-based CO2 removal • Hydrogen Recovery and Hydrocarbon Recycle • CO2 compression

This design is based on converting CO in Plant 201 purge gas and Plant 102 syngas (slip stream) to CO2 and H2, and then removing CO2 from the gas stream using a chemical solvent. The gas stream from CO2 removal is divided into two streams. One stream is recycle hydrogen to Plant 102; to adjust the F-T synthesis gas H2:CO ratio. The other stream feeds a PSA unit, where hydrogen and light hydrocarbons are separated and recovered. Hydrogen recovered in the PSA unit is used in the hydrocracker and as fuel. The light hydrocarbons stream (recovered as PSA residue gas) is split into a recycle stream and a fuel stream. The recycle stream is returned to Area 100 for use as feed in syngas generation. CO2 captured CO2 Absorber is released during solvent regeneration and then compressed to transport pipeline delivery pressure, 110 bar. The process flow diagram for Plant 500 is shown in PFD 501-B-01. Plant 500 - Hydrotreating & HT-CO Shift Purge gas from the F-T synthesis section, containing the bulk of the non-product carbon, is preheated to the hydrotreating temperature (270°C) by heat exchangers 501E-8 and 501E-9. Unsaturated hydrocarbons and oxygenates in the purge gas stream react with H2 to form their saturated hydrocarbon counterparts in the fixed-bed catalytic reactor, 501R-1. The effluent from the hydrotreater is mixed with a small amount of Plant 102 syngas and MP steam. The combined stream is heated to 340°C before entering the HT-CO shift reactor, 501R-2. Iron-based catalyst in the shift reactor promotes the conversion of CO (26 mol%, dry gas basis) and steam to CO2 and H2, resulting in a reactor outlet CO concentration of 2.5 mol%, dry basis and an exit temperature of 438°C. The shift reactor effluent stream is cooled in exchangers 501E-10, 501E-9, 501E-11, 501E-1, and 501E-14. Part of the reboil duty for the CO2 Stripper, 501C-2, is provided from cooling the shift reactor effluent in exchanger 501E-11. Plant 500 - CO2 Removal A liquid chemical solvent - a 30 wt% aqueous solution of mono-diethanolamine (MDEA) - removes CO2 from shift reactor effluent gas. The gas stream is contacted with solvent in the CO2 Absorber, 501C-1A/B

96

– two, identical vessels in parallel, each containing a series of mixing trays. Regenerated solvent enters at the top of the vessels and leaves as rich solvent from the bottom. Shift reactor effluent gas enters at the bottom of the vessels and leaves as a ‘CO2-free’ gas stream from the top. A gas-liquid dispersion develops on each tray as a result of turbulent mixing between the gas and liquid phases. CO2 is transferred from the gas to the liquid phase by dissolving in the solvent and then reacting with active reagent. It leaves the vessel in the rich solvent stream, chemically bound to the active reagent, MDEA. Heating and stripping the rich solvent in the CO2 Stripper, 501C-2, regenerates the solvent and releases CO2 back to the vapor phase. CO2 is separated from condensed stripping steam in the CO2 stripper reflux drum, 501C-6. The CO2 stripper reboil duty is provided partly from waste heat in the shift reactor effluent stream and partly from LP steam. Regenerated solvent is cooled to its absorber feed temperature by heat exchangers 501E-2 and 501E-15. The combined gas stream leaving the CO2 Absorbers is rich in hydrogen. This stream is split into a hydrogen recycle stream and a feed stream to the PSA Unit. The hydrogen recycle stream adjusts the Plant 102 syngas H2:CO ratio to the design value for F-T synthesis. Plant 500 - Hydrogen and Light Hydrocarbon Separation & Recovery To reduce the carbon emissions associated with combustion of C4

- generated in F-T synthesis, part of the C4

- by-product is recovered from the hydrogen-rich gas stream leaving the CO2 Absorbers and sent to Plant 102 for use as feed in syngas generation. The recovered hydrogen stream is used as fuel and for hydrogen make-up to the hydrocracker. Separation of the C4

- fraction from hydrogen occurs in a PSA Unit, immediately downstream of the CO2 Absorbers. Unlike the residue gas species (CO, CO2, C4

-, and H2O), which strongly adsorb to the PSA sorbent, hydrogen is adsorbed in only small amounts as syngas flows through the PSA unit. Therefore, a high-purity hydrogen stream is obtained at the PSA unit outlet, while the balance of syngas components (residue gas) accumulate on the sorbent and are only removed once the vessel is de-pressurized; when these species desorb into the regeneration gas stream. Plant 500 - CO2 Compression CO2, at 1.1 bar in the stripper reflux drum, is sent to CO2 compression, 501K-1. CO2 is compressed in four compression stages to 110 bar for delivery to the battery limit CO2 transport pipeline. The compression HP requirement is approximately 6.5 MW. To prevent downstream corrosion problems, the gas from the first compression stage is passed through a packed bed of sorbent material to remove moisture from the gas.

97

8B-2 OFFSITES The offsites plants for the CO2 capture and compression case are similar to those for the standard plant design.

98

9B-2 PLANT COSTS The same method of cost estimating as was used for the standard plant design is used for the CO2 capture and compression case. 9B-2.1 Installed Plant Costs Table 9B-2.1 shows the capital cost breakdown for a Shell-Type, natural gas Fischer-Tropsch liquefaction plant with CO2 capture and compression facilities.

Table 9B-2.1




Area 100 - Syngas Generation 118,334 Area 200 - F-T Synthesis & Product Upgrading 45,047 Area 300 - Steam & Power Generation 25,517 Area 500 - CO2 Capture & Compression 41,864 Total ISBL Cost 230,763







99

9B-2.2 Annual Operating Costs Table 9.B-2.2 shows the annual operating costs for a Shell-Type, natural gas Fischer-Tropsch liquefaction plant with CO2 capture and compression facilities.

Table 9B-2.2



COST, $1,000's

Fixed Costs: Rent 55 acres $ 150 /acre/year $ 8 Taxes 1% of capital cost $ 4,057 Insurance 1% of capital cost $ 4,057 Operating Labor (excl. maint.) 52 people $50,000 /pers/annum $ 4,680 Maintenance (matl. & labor) 2% of capital cost $ 8,114 Misc. Supplies Corporate Overhead Total Fixed Costs $ 20,915

Variable Costs: Natural Gas 99,666 GJ/day $ 0.50 /GJ $ 18,189 Seawater 44,287 gpm $ 0.07 /1,000 gal $ 1,629 Desalinated Water 150 gpm $ 4.50 /1,000 gal $ 355 Electric Power 7,408 kWh $ 0.015 /kWh import $ 973 Catalyst & Chemicals $ 6,029 Other Operating Costs Annual Variable Costs $ 27,175 Load Factor 90% Total Actual Variable Costs $ 24,458 By-Product Credits Unit/D /Unit $ - Unit/D /Unit $ - Total By-Product Credits $ - Net Operating Costs $ 45,373

*OCC - Overnight Construction Cost (total field costs + contractor's costs)

100

4C SYNTROLEUM-TYPE F-T SYNTHESIS & PRODUCT UPGRADING 4C-1 BASE CASE – Standard Plant Design

101

DESIGN OBJECTIVE Arguably, among other features, Syntroleum F-T technology is most notably characterized by the absence of a cryogenic air separation unit in the syngas generation plant. Autothermal, catalytic partial oxidation of natural gas to form syngas is based on using air as the oxidant, instead of high-purity oxygen. This concept results in a significant reduction in capital cost for the syngas generation section of the F-T facility. Using air as the oxidant introduces a large volume of nitrogen into the system, which flows, as part of the syngas stream, through all ‘syngas’ and ‘synthesis’ process equipment and piping. In addition, the presence of nitrogen (>40 mol% in feed syngas to F-T reactors) greatly reduces the partial pressure of the primary reactants, CO and H2, in the F-T synthesis reactions. The question naturally arises of how to estimate F-T synthesis reactor catalyst requirements under these circumstances and in the absence of proprietary rate and transport information. For this techno-economic evaluation it was decided that the intrinsic rate of CO conversion to F-T products should be treated as 1st order in CO concentration and to use the same lumped effectiveness factor as was used in the other fixed-bed reactor technology, i.e. Shell MDS. The simplified rate expression could then be integrated and solved for the reactor volume, for a particular syngas conversion requirement. To address (i) Syntroleum claims regarding enhanced catalyst performance, and (ii) possible developments by Syntroleum in the area of reactor design, it was arbitrarily decided to consider the effects, on the Syntroleum techno-economic evaluation, of doubling F-T catalyst activity. The results of this strictly arbitrary analysis are noted by - “Enhanced Catalyst Activity” case.

102

4C-1 DESIGN BASIS

Plant Capacity


Process Syntroleum Fischer-Tropsch Synthesis Technology

Syngas Generation Syntroleum Air-Blown Autothermal Reforming

Feed ratios:- - H2O:C, mole/mole5 - CO2:C, mole/mole - O2:C, mole/mole

0.23 0.004 0.53





F-T Synthesis Syntroleum-Type F-T technology - fixed-bed reactor design – multi-tubular trickle-bed reactor, ‘once-through’ operation, two-stages in series design with interstage product recovery, cobalt F-T synthesis catalyst, internal heat recovery (steam raising)

- operating conditions Pressure: 27 bar Temperature: 200-230°C


Several values used to fit slope of carbon-number distribution for cobalt catalyst


63% 2nd stage

89% overall



103




104

5C-1 OVERALL PLANT SUMMARY This section summarizes the overall plant performance and costs for a Standard Syntroleum-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 5C-1.1 contains a summary of the major feed and product streams. The plant processes 100 MMSCF/day of natural gas and produces about 10,104 BPD of F-T liquid products. The primary liquid products are naphtha blending stock and an ASTM D-86 350°C end-point diesel. Both products are essentially free of sulfur, nitrogen and oxygen containing compounds.

Table 5C-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 5.24 kg/s (4,020 Bbl/day) F-T Distillate 8.66 kg/s (6,084 Bbl/day) Power Import/Export 8.9 MW export Plant Thermal Efficiency



Figure 5C-1.1 is a block flow diagram of the main mass, energy, and carbon flows for the facility

105

4.1 kg/s

0.5 kg/s

131.4 kg/s

130.3 kg/s F-T Synthesis

Steam TurbineDrives

& PowerGeneration

Pwr Gen = 19.3 MW

Air Compression

107.6 kg/s

Fuel Combustion


94.8 kg/s


ProductUpgrading

& Fractionation

137 k

g/s

0 MW

8.9 MW


10.4 MW

Natural Gas

Figure 5C-1.1Mass, Energy, & Carbon Balance Summary

Syntroleum-Type Design - Base Case

Air

BFW66.7 kg/s

HP Steam,65.9 kg/s

MP Steam,82.6 kg/s

52.6 MW S/T Drivers


F-T Liquid






Effluent Water

QOUT= 0.178 TJ/h

QOUT= 0.16 TJ/h

QOUT= 0.069 TJ/h

QOUT= 1.066 TJ/h

QOUT= 0.182 TJ/h

Steam5.2 kg/s

H2

0.12 kg/s

6.1 kg/s 21.0 kg/s

H2

0.12 kg/s

0.51 kg/s15.1 kg/s0.8 kg/s

BFW83.6 kg/s

- Input

- Output


MIN = 111.7 kg/sQIN = 0.011 TJ/h

SyngasGeneration

106

Table 5C-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 5C-1.2


Area Description Cost (MM$) $/GJ % ISBL 100 Syngas Preparation 59.0 32 200 F-T Synthesis/Upgrading 79.1 42 300 Steam Generation 48.2 26 Offsites Facilities 120.0 HO Service/Fees/Contingency 81.2 Total Cost: 387.5 (38,347 $/bpd) The above plant costs are order-of-magnitude ± 30% estimates. Table 5C-1.3 shows the annual operating cost summary.

Table 5C-1.3




Total Cost: 49.0

107

Table 5C-1.4 shows the breakdown of the product sales price.

Table 5C-1.4 Product Sales Price





108

Table 5C-1.5 is a comparison between a standard Syntroleum-Type F-T technology plant design and a Syntroleum-Type F-T technology plant designed to include CO2 capture and compression. Table 5C-1.5 presents the cost and efficiency penalties attributable to the adoption of CO2 capture and compression.

Table 5C-1.5 Cost and Efficiency Comparison


Base Case CO2 Capture Plant Design Syntroleum-type Syntroleum-type








Plant Efficiency, % (LHV) 53.7 54.5








109

Figure 5C-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

110

Figure 5C-1.2Sensitivity of Product Sales Price to Natural Gas Cost

Syntroleum-Type F-T Technology

15

20

25

30

35

40

45

50

55

60

0 0.5 1 1.5 2 2.5 3 3.5


Dis

tilla

te F

OB

Sal

es P

rice,

$/b

b

Standard Design


111

Standard Design - Enhanced Catalyst Activity This section addresses the effects of doubling the F-T synthesis catalyst activity; to account for possible reactor design developments and improvements to catalyst performance that Syntroleum might have made. Tables 5C-1.6, 5C-1.7, 5C-1.8 show the capital cost, operating cost, and product sales price estimates for the Syntroleum-Type F-T facility with ‘enhanced catalyst activity’.

Table 5C-1.6 – Enhanced Activity


Area Description Cost (MM$) $/GJ % ISBL 100 Syngas Preparation 54.0 34 200 F-T Synthesis/Upgrading 61.3 38 300 Steam Generation 44.0 28 Offsites Facilities 120.0 HO Service/Fees/Contingency 74.0 Total Cost: 353.3 (34,967 $/bpd) Table 5C-1.7 shows the annual operating cost summary.





Total Cost: 42.0

112


Table 5C-1.8 – Enhanced Activity Product Sales Price



(*) – capital charge rate of 10%, discount factor 10% (**) – averaged price; naphtha 27.51 $/bbl, diesel 26.20 $/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.

113

6C-1 OVERALL PLANT CONFIGURATION This section presents an overall summary of standard Syntroleum-Type Fischer-Tropsch synthesis technology. It is divided into two subsections: 6C-1.1 Process Flow Diagrams 6C-1.2 Mass and Energy Balance Tables

6C-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 the following plants: • Plant 102, the Air Compression, Air-blown autothermal reforming and H2 Separation Plants Area 200 contains two major plants: • Plant 201, the Syntroleum-Type 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 6C-1.1 and 6C-1.2 in the following section.

114

6C-1.2 Mass and Energy Balance Tables The component flow rates of key streams in process Areas 100, and 200 are shown in Tables 6C-1.2.1 and 6C-1.2.2. The streams are identified by the same stream numbers used in the PFDs shown in the previous section. Table 6C-1.1 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 6C-1.2 contains the same information for the process streams in Areas 100 and 200 except that stream composition is presented in mole fraction.

115

7C-1 PROCESS DESCRIPTION The design basis and major assumptions for each major ISBL plant are presented in Sections 3 and 4C-

1. Area 100 - Syngas Generation Area 100 is the syngas generation area. This area consists of the following plants. Plant 102 Air Compression Plant 102 Air-blown Autothermal Reforming Plant The sulfur removal, heat recovery/steam generation, syngas cooling, and hydrogen recovery units are parts of Plant 102. Plant 102, contains a three-stage centrifugal air compressor to supply oxidant to the partial oxidation stage of the autothermal reformer. Atmospheric air is compressed, preheated to 760°C, and delivered as oxidant to the air-blown autothermal reforming unit. The Syntroleum-Type syngas generation plant, first removes trace amounts of sulfur compounds from the natural gas by reaction with zinc oxide. Steam is then added to the natural gas stream and the mixed stream heated to 620°C before mixing with air at the partial oxidation burner. Partial combustion reactions between fuel and oxidant occur at the burner and are followed by homogeneous and heterogeneous steam-reforming and CO-shift reactions to form syngas in the remainder of the catalyst-filled, refractory-lined vessel. The hot syngas product stream is cooled by steam generation, feed/effluent heat exchange, and cooling with ambient air. A slip stream of syngas is separated into hydrogen and residue gas streams in the PSA unit. Hydrogen is required for hydrocracking. Plant 102 produces a synthesis gas steam having a molar H2:CO ratio of 2.04 which is sent to Area 200 for Syntroleum-Type Fischer-Tropsch synthesis. The following subsections give a more detailed description on each of the process plants in Area 100, the Syngas Preparation Area. Plant 102 - Air Compression The Air Compressor, 102K-1, provides the required oxygen feed to the air-blown autothermal reformer, 102R-2. The compressor is a 52.6 MW, three-stage, centrifugal compressor and delivers compressed air at 30.5 bara. The compressor is driven by a steam turbine.

116

The compressed air stream is first heated to 350°C in exchanger 102E-1 and then to 760°C in fired heater, 102F-1. Plant 102 - Syntroleum Air-Blown Autothermal Reforming The objective for Plant 102 is to provide a syngas with a H2:CO ratio of about 2.0 for F-T synthesis. The partial oxidation reactor is designed to operate with the following feed ratios: H2O:C, mole/mole 0.23 CO2:C, mole/mole 0.004 O2:C, mole/mole 0.53 The adiabatic flame temperature at the partial oxidation burner is approximately 1,700°C. A process flow diagram of Plant 102, the syngas generation plant, is shown in PFD 102-B-01. Natural gas feed is first heated by heat exchange with hot syngas in, 102E-3, and then further heated in fired heater 102F-1 before being desulfurized in the zinc oxide desulfurization vessel, 102R-1A/B. Sulfur is removed to the less than 0.1 ppm by volume, as required for the subsequent Fischer-Tropsch synthesis. Steam is added to the desulfurized natural gas and the mixed stream further heated to 620°C in fired feed preheater, 102F-1. The air-blown autothermal reformer ,(102R-2), is a refractory-lined carbon steel vessel with an axially-fired burner and a packed bed of nickel-based high-temperature reforming catalyst. This air-blown autothermal reformer mixes the natural gas and air in a flame in the reactor combustion zone. Natural gas feed is partially combusted by mixing with air, below the full-combustion stoichiometric amount, at the burner. Between the burner and the catalyst bed is the thermal zone, where the partial combustion products and residual feed undergo homogeneous steam-reforming and shift reactions. Final, nearly-complete conversion of the hydrocarbon feed occurs in the catalytic zone. Here residual hydrocarbons and partial oxidation products undergo adiabatic, heterogeneous steam-reforming and shift reactions to produce additional syngas. The reactor effluent is cooled in a series of heat exchangers, 102E-2A, 102E-2B, 102E-2C, 102E-1, and 102E-3 to produce 101 bar, 450°C superheated steam and to preheat the incoming natural gas feed. Final cooling of the syngas to 60oC is accomplished in exchangers 102E-4, 102E-5, and air cooler 102E-6. The cooled syngas goes to separator 102C-3 where process condensate is separated from the product syngas. A small slip stream of syngas is used to generate the hydrogen stream used for hydrocracking. Plant 102 - Hydrogen Separation

117

High-purity hydrogen, a reactant in the hydrocracking process, is recovered from a small slip stream of cooled syngas by a pressure swing adsorption (PSA) unit. Unlike the residue gas species (CO, CO2, CH4, and H2O), which strongly adsorb to the PSA sorbent, hydrogen is adsorbed in only small amounts as syngas flows through the PSA unit. Therefore, a high-purity hydrogen stream is obtained at the PSA unit outlet, while the balance of syngas components (residue gas) accumulate on the sorbent and are only removed once the vessel is de-pressurized, when these species desorb into the regeneration gas stream. The PSA residue gas is compressed and returned to the syngas stream feeding the F-T section.

118

Area 200 - Fisher-Tropsch Synthesis and Product Upgrading Area 200 is the Fischer-Tropsch synthesis and product upgrading area. It consists of the following plants: Plant 201 Syntroleum-Type Fischer-Tropsch Synthesis and Hydrocarbon Recovery Plant Plant 202 Product Fractionation & Wax Hydrocracking Plant This design is based on fixed-bed reactor technology and cobalt-based F-T synthesis catalyst with limited water-gas shift activity. The product fractionation and upgrading steps consist of standard fractionation technology and mild wax hydrocracking. The following subsections give a more detailed description on each of the process plants in Area 200, the Fischer-Tropsch Synthesis and Product Upgrading Area. Plant 201 - Syntroleum Fischer-Tropsch Synthesis The principle function of this plant is to convert the syngas produced in Area 100 into hydrocarbon products using a series of multi-tubular, trickle-bed, cobalt catalyst reactors. The reactor section for this plant consists of a number fixed-bed reactors – six parallel first-stage reactors with three parallel second-stage reactors, in series. The reactor section operates as ‘once- through’, i.e. unconverted syngas from the reactor effluent is not recycled to the reactor feed. Fischer-Tropsch reactions produce mainly straight chain paraffins and are highly exothermic. The carbon number distribution of the hydrocarbon product is known to closely follow a single-parameter (α) probability model for hydrocarbon chain growth and termination i.e., αn-1(1-α); where α represents the probability for chain growth. The model predicts the chance of a certain carbon number molecule being formed in relation to an entire distribution of possible carbon numbers. In practice, α values in the range 0.7-0.95 lead to a F-T-synthesis product distribution with carbon numbers above (wax) and below (C4

- ) the carbon numbers associated with the study products – diesel and naphtha. Commercially, where LPG is not recovered as product, the lower carbon number species are mainly used as fuel, or else recycled as feedstock to the syngas generation section of the plant. Carbon number products beyond the acceptable diesel end-point (say > C20) have to be cracked to lower carbon-number products, which are then recovered through fractionation. Design Basis and Considerations The CO conversion (to hydrocarbon and a small amount of CO2) in the reactor section is approximately 89%.

119

In this design, the heat generated by the F-T synthesis reaction is removed by generation of 15 bar saturated steam in tubes inside the reactor. The six 1st stage Fischer-Tropsch reactors are about 4.5 m diameter and about 20 m in height. Each reactor contains about 1,400 tubes having a 50 mm OD for steam generation. The three 2nd stage reactors are about 4.3 m diameter and about 20 m in height and contain about 500 x 50 mm OD tubes. The process flow diagrams for Plant 201, F-T synthesis, are shown in PFD 201-B-01. As shown in PFD 201-B-01, the combined syngas from Plant 102 is heated to the reactor inlet temperature (200°C) through reactor feed/effluent heat exchange and steam preheating. According to Fischer-Tropsch chemistry, CO and H2 in the syngas are converted to a paraffinic hydrocarbon product - principally middle distillates. The 1st stage reactor product stream is cooled in, 201E-2, and the liquid product separated from the vapor stream in, 201C-2. The vapor stream is reheated to reactor feed conditions through feed/effluent heat exchange. Unconverted CO and H2 in the vapor stream leaving the 1st stage reactors are converted to paraffinic hydrocarbon products in the 2nd stage reactor. The 2nd stage reactor product stream is cooled in exchangers 201E-4, 201E-6, 201E-10, and 201E-7. As the product stream is cooled it forms a mixed, three-phase stream, which is separated into an unconverted syngas stream, liquid hydrocarbon streams, and water streams, in 201C-3, 201C-4, and 201C-5. The combined liquid hydrocarbon stream is sent directly to product fractionation and the water steams go to water treatment. Plant 201 - Hydrocarbon Recovery A chilled lean-oil absorption unit, using a diesel recycle stream as the solvent, is used to recover additional C5+ components in the F-T reactor effluent gas stream downstream of the cooling/recovery train. Rich solvent leaving the bottom of the absorber is fed to the product fractionation plant. Plant 202 – Product Fractionation The prefractionator, 202C-1, receives hydrocarbon liquids (middle distillates and wax) from the F-T cooling train section, rich solvent bottoms from the lean oil absorber, and hydrocarbon liquid recycle from the hydrocracker. Light non-condensable gases and C4- hydrocarbons are removed in the prefractionator prior to product fractionation. The prefractionator overhead stream is compressed and recycled to the syngas generation section where it is mixed with the natural gas feed. The product fractionator, 202C-3, separates the prefractionator bottoms stream into an overhead liquid naphtha product and a diesel product, which is drawn from the bottom of the product fractionator side-

120

stripper. A small, light-hydrocarbon and non-condensable gases overhead stream is also separated. The overhead vapor stream is compressed and sent to the plant fuel system. The naphtha product has an ASTM D-86 end-point of 204°C. It is cooled and sent to storage. The diesel product (ASTM D-86 end-point 320°C) is cooled, dehydrated, and split into a lean oil recycle stream and a diesel product stream. Product fractionator bottoms is sent to the vacuum column, 202C-7. A diesel distillate is produced from the top pump-around section and a 350+°C boiling range gas oil is produced as bottoms. The diesel distillate has an ASTM D-86 end-point of 350°C. The gas oil stream is sent to the hydrocracker. Plant 202 - Wax Hydrocracking The Wax Hydrocracking Plant, catalytically cracks the F-T wax product under a hydrogen environment into lower-boiling material, mainly naphtha and diesel. A generic hydrocracking plant design has been selected for this study. Hydrocracking occurs at about 370°C and between 100 and 150 bar under a hydrogen atmosphere in a single multi-bed reactor with inter-bed cooling by hydrogen-rich recycle gas. The vacuum column-bottom stream is pumped to hydrocracker operating pressure, 115 bar. The liquid stream mixes with recycle hydrogen and is preheated to the hydrocracker reactor inlet temperature, 370°C. The hydrocracked product is cooled from 412°C to 45°C. The hydrocracked liquid is flashed before being recycled to the prefractionator. The high-pressure gas stream is compressed and recycled to the reactor. A small purge gas stream is sent to the plant fuel system to prevent the buildup of inert in the system. Flash vapor from hydrocracked liquid depressurization is sent to the lean oil absorber for hydrocarbon recovery. Hydrocracking performs the following functions:


121

Area 300 - Steam Distribution System HP superheated steam is raised in Plant 102 by heat recovery from the syngas generation unit. HP steam is used to drive the air compressor. An extraction from the air compressor turbine at MP steam level (34 bar) provides steam to the MP steam users. The air compressor turbine exhausts at 0.14 bar. Steam raised in the F-T reactor tubes at 15 bar is superheated to 300°C in fired heater, 201F-1. F-T plant superheated steam is to drive the electric-power generator. The LP steam users are supplied with steam from the generator turbine exhaust. Excess LP steam is condensed in an air cooler with a seawater trim cooler.

122

8C-1 OFFSITES Following is a brief description of each offsites plant. Plant 19 - Relief and Blowdown -- Plant 19 is for the collection and flaring of relief and blowdown discharges from all applicable plants. Collection piping is not included in Plant 19 but has been included in Plant 21, Interconnecting Piping. Plant 20 - Tankage -- Plant 20 provides storage and delivery equipment for products, intermediates and chemicals. Thirty days storage is provided for the naphtha and distillate products. Intermediate storage is provided for the Wax Hydrocracking Plant. This storage is required to provide feedstock during plant startup and to mitigate the effect on operations due to brief interruptions in the upstream plants which could be the result of scheduled or unscheduled maintenance or due to operating problems. Plant 21 - Interconnecting Piping System -- Plant 21 includes the interconnecting process and utility piping between process plants and offsites. All above ground and underground piping systems are included except the cooling water piping which is included in Plant 32, Cooling Water Distribution, and the fire water piping which is included in Plant 33, Fire Systems. Relief and blowdown headers are included. In general, water distribution piping is underground and all other piping is located above ground on pipe racks. Storm sewers, sanitary sewer and process wastewater lines are not part of this plant but are included in Plant 34, Sewers and Wastewater Treating. Plant 22 - Product Shipping -- Plant 22 provides the pipeline, pumping and metering systems for delivery of the final hydrocarbon products. Separate systems are provided for each of the hydrocarbon products. Dual meters are provided to assure proper recording and product delivery. Plant 25 - Catalyst and Chemical Handling -- Plant 25 provides storage and handling for the catalyst and chemicals used in all the plants. Additionally, it provides a consolidated location for tracking catalyst and chemical start-up and daily consumption requirements. This plant includes an enclosed warehouse for storage and forklifts for transporting pallets into or out of the warehouse. Plant 30 - Electrical Distribution System -- Plant 30 provides the electrical distribution system from the high voltage switchyard to the consuming locations. Plant 32 - Raw, Cooling and Potable Water -- Plant 32 uses a once-through seawater system. Seawater is purchased from the Royal Commission. Supply pressure is low requiring installation of a seawater sump and seawater intake/circulation sump pumps to provide a controllable seawater supply and adequate pressure for the once-through cooling Because there is no cooling tower, the requirement for raw and service water is small.

123






124




125

9C-1 PLANT COSTS Costs are reported in mid-1999 U.S. dollars. The capital cost estimate is based on a factored estimating technique. This technique is based on the observation that cost relationships (cost factors) exist between different components of the overall cost which can be derived from historical cost data for similar, previously built projects. ISBL equipment are sized and materials-of-construction are selected based on the particular process configuration, heat and energy balance calculations, and the conditions of the locally available utility streams. Given the size of the equipment items, Bechtel cost curves (regressions of historical size versus cost data) are used to identify equipment costs. Additional field costs, bulk materials, direct labor, indirect costs, etc., are developed based on cost factors mentioned above. Other field costs, such as sales tax, freight costs, duties, etc., are site specific and developed separately for each project. The Offsites cost estimate is developed from Bechtel in-house data for similar size and type plants in the same site location. The IEA Financial Assessment Criteria (see Appendix) was used to develop the costs for Home Office, Fees, and Services and Plant Contingency.

126

9C-1.1 Installed Plant Costs Table 9C-1.1 shows the capital cost breakdown for a Standard Syntroleum-Type, natural gas Fischer-Tropsch liquefaction plant

Table 9C-1.1




Area 100 - Syngas Generation 59,037 Area 200 - F-T Synthesis & Product Upgrading 79,099 Area 300 - Steam & Power Generation 48,156 Total ISBL Cost 186,292







127

9C-1.2 Annual Operating Costs Table 9C-1.2 shows the annual operating costs for a Standard Syntroleum-Type, natural gas Fischer-Tropsch liquefaction plant.

Table 9C-1.2


QUANTITY UNIT $ PRICE ANNUAL COST, $1,000's

50 acres $ 150 /acre/year $ 8

1% of capital cost $ 3,522 1% of capital cost $ 3,522

48 people $50,000 /pers/annum $ 4,320 2% of capital cost $ 7,045 Total Fixed Costs $ 18,417

99,666 GJ/day $ 0.50 /GJ $ 18,189 61,168 gpm $ 0.07 /1,000 gal $ 2,251

150 gpm $ 4.50 /1,000 gal $ 355 0 kWh $ 0.015 /kWh import $ - $ 14,130 Annual Variable Costs $ 34,925

90% Total Actual Variable Costs $ 31,432

8,932 kWh $ 0.012 /kWh export $ 845 Unit/D /Unit $ - Total By-Product Credits $ 845 Net Operating Costs $ 49,004

128

4C-2 CO2 REDUCTION CASE – Standard Plant + CO2 Capture & Compression

129

DESIGN OBJECTIVE This plant design is an extension of the standard Syntroleum-Type F-T natural gas Fischer-Tropsch liquefaction plant. The standard plant is adapted to capture the bulk of the feed carbon which does not leave the plant as carbon in the F-T liquid product streams. Ordinarily, in the standard plant design, most of this non-product carbon would be emitted to the atmosphere as CO2, following complete combustion, incineration, or flaring. The intent of this design is capture the non-product carbon (prior to emission) as a single species – CO2 in this instance – and to deliver it for export to the plant battery limit in a ‘pure’ form and at high pressure. This study does not address the collection, transportation, and ultimate disposal/sequestration of this CO2 stream. The following sections identify the plant design, performance, efficiency, capital and operating costs, and product sales price associated with adopting CO2 capture and compression. Comparisons are made to the standard plant design, which is presented in sections 4C1 through 9C1.

130

4C-2 DESIGN BASIS

Plant Capacity


Process Syntroleum Fischer-Tropsch Synthesis Technology

Syngas Generation Syntroleum Air-Blown Autothermal Reforming

Feed ratios:-


0.23 0.004 0.53





F-T Synthesis Syntroleum-Type F-T technology - fixed-bed reactor design – multi-tubular trickle-bed reactor, ‘once-through’ operation, two-stages in series design with interstage product recovery, cobalt F-T synthesis catalyst, internal heat recovery (steam raising)

- operating conditions Pressure: 27 bar Temperature: 200-230°C


Several values used to fit slope of carbon-number distribution for cobalt catalyst


63% 2nd stage

89% overall




131


CO2 Capture Hydrogenation, LT-CO shift, MDEA CO2 removal

CO2 Compression Compression to 110 bar

132

5C-2 OVERALL PLANT SUMMARY This section summarizes the overall plant performance and costs for a Syntroleum-Type, natural gas Fischer-Tropsch liquefaction plant with CO2 capture and compression facilities. Plant efficiency, carbon emissions, breakdown of product sales price, and capital and operating costs are summarized here. Table 5C-2.1 contains a summary of the major feed and product streams. The plant processes 100 MMSCF/day of natural gas and produces about 10,478 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 5C-2.1 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 5.71 kg/s (4,400 Bbl/day) F-T Distillate 8.65 kg/s (6,078 Bbl/day) Power Import/Export 0.0 MW Plant Thermal Efficiency


Carbon Emissions


Figure 5C-2.1 is a block flow diagram of the main mass, energy, and carbon flows for the facility

133

0.7 kg/s

17.95 MW

0 MW

0.5 kg/s

123.8 kg/s

SyngasGeneration 130.3 kg/s

Steam TurbineDrives

& PowerGeneration

Pwr Gen = 17.95 MW

Air Compression

107.6 kg/s

Fuel Combustion



ProductUpgrading

& Fractionation

137 k

g/s

Natural Gas

Table 5C-2.1Mass, Energy, & Carbon Balance Summary

Syntroleum-Type Design - CO2 Capture & Compression

Air

BFW66.7 kg/s

HP Steam,65.9 kg/s

MP Steam,82.6 kg/s

52.6 MW S/T Drivers


F-T Liquid






Effluent Water

QOUT= 0.18 TJ/h

QOUT= 0.16 TJ/h

QOUT= 0.069 TJ/h

QOUT= 0.71 TJ/h

QOUT= 0.21 TJ/h

6.1 kg/s 21.3 kg/s 15.7 kg/s0.8 kg/s

BFW83.6 kg/s

F-T Synthesis


CO2 to Pipeline


Steam7.5 kg/s

85.7 kg/s94.1 kg/s

4.7 kg/s


- Input

- Output


4.1 kg/s

Steam5.2 kg/s

H2

0.12 kg/s

H2

0.12 kg/s

0 MW

MIN = 111.7 kg/sQIN = 0.011 TJ/h

134

Table 5C-2.2 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 5C-2.2


Area Description Cost (MM$) $/GJ % ISBL 100 Syngas Preparation 57.0 26.3 200 F-T Synthesis/Upgrading 80.8 37.3 300 Steam Generation 42.4 19.6 500 CO2 Capture & Compression 36.2 16.7 Offsites Facilities 122.0 HO Service/Fees/Contingency 89.7 Total Cost: 428.2 (40,867 $/bpd) The above plant costs are order-of-magnitude ± 30% estimates. Table 5C-2.3 shows the annual operating cost summary.

Table 5C-2.3


Description Cost (MM$) Fixed Costs 20.3 Variable

Costs 35.2 By-Product Revenue -

Total Cost: 55.5

135


Table 5C-2.4 Product Sales Price





136

Table 5C-2.5 is a comparison between a standard Syntroleum-type F-T technology plant design and a Syntroleum-type F-T technology plant designed to include CO2 capture and compression. Table 5C-2.5 presents the cost and efficiency penalties attributable to the adoption of CO2 capture and compression.

Table 5C-2.5 Cost and Efficiency Comparison


Base Case CO2 Capture Plant Design Syntroleum-type Syntroleum-type








Plant Efficiency, % (LHV) 53.7 54.5








137

CO2 Capture Design - Enhanced Catalyst Activity This section addresses the effects of doubling the F-T synthesis catalyst activity; to account for possible reactor design developments and improvements to catalyst performance that Syntroleum might have made. Tables 5C-2.6, 5C-2.7, 5C-2.8 show the capital cost, operating cost, and product sales price estimates for the Syntroleum-Type F-T facility with ‘enhanced catalyst activity’.



Area Description Cost (MM$) $/GJ % ISBL 100 Syngas Preparation 52.9 28.3 200 F-T Synthesis/Upgrading 61.2 32.7 300 Steam Generation 39.4 21.0 500 CO2 Capture & Compression 33.6 18.0 Offsites Facilities 122.0 HO Service/Fees/Contingency 81.9 Total Cost: 391.1 (37,324 $/bpd) Table 5C-2.7 shows the annual operating cost summary.



Description Cost (MM$) Fixed Costs 18.9 Variable

Costs 29.5 By-Product Revenue -

Total Cost: 48.4

138


Table 5C-2.8 – Enhanced Activity Product Sales Price



(*) – capital charge rate of 10%, discount factor 10% (**) – averaged price; naphtha 29.91 $/bbl, diesel 28.49 $/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.

139

6C-2 OVERALL PLANT CONFIGURATION This section presents an overall summary of standard Syntroleum-type Fischer-Tropsch synthesis technology. It is divided into two subsections: 6C-2.1 Process Flow Diagrams 6C-2.2 Mass and Energy Balance Tables

6C-2.1 Process Flow Diagrams This section contains the process flow diagrams (PFDs) for each process plant within Areas 100, 200, 300, and 500 in PFDs 102-B-01 through 501-B-01. Each PFD is numbered according to the plant number for the plants in Process Areas 100, 200, 300, 500. Area 100 contains the following plants: • Plant 102, the Air Compression, Air-blown Autothermal Reforming and H2 Separation Plants Area 200 contains two major plants: • Plant 201, the Syntroleum-Type Fischer-Tropsch Synthesis Plant • Plant 202, the F-T Liquid Product Upgrading and Fractionation Plants Area 300 represents the plant steam distribution system: Area 500 contains the CO2 Capture and CO2 Compression Plants 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 6C-2.1 and 6C-2.2 in the following section.

140

6C-2.2 Mass and Energy Balance Tables The component flow rates of key streams in process Areas 100, 200, and 500 are shown in Tables 6C-2.2.1 and 6C-2.2.2. The streams are identified by the same stream numbers used in the PFDs shown in the previous section. Table 6C-2.2.1 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 100 200, and 500. Table 6C-2.2.2 contains the same information for the process streams in Areas 100, 200, and 500 except that stream composition is presented in mole fraction.

IEA GHG PROGRAM TABLE 6C-2.2.1 MASS AND ENERGY BALANCE

(MASS FRACTION)

SYNTROLEUM-TYPE DESIGN: CO2 REDUCTION

1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamNatural

Gas Feed

MP Steam

Addition

Ambient Air

HP Air to Preheate

r

Hydrocarbon:

Steam

Reformer Effluent

Syngas to F-T Plant

Syngas to PSA

UnitTemperature, °C 45 329 43 211 620 1017 60 60

Pressure, bara 32.75 31.03 1.00 30.50 30.75 29.33 27.47 27.47

Molar Flow, kgmole/h 4,980.7 1,047.3 14,302.0 13,473.8 6,028.0 26,665.3 24,772.7 682.0

Mass Flow, kg/s 23.6 5.2 111.7 107.6 28.9 136.4 126.9 3.5


Mole Wt. 17.086 18.015 28.119 28.740 17.248 18.421 18.440 18.440


H2 0.0386 0.0404 0.0404

N2 0.0077 0.7339 0.7622 0.0063 0.6022 0.6302 0.6302

CO 0.2631 0.2753 0.2753

CO2 0.0113 0.0092 0.0350 0.0366 0.0366

H2O 1.0000 0.0432 0.0064 0.1815 0.0526 0.0086 0.0086

O2 0.2228 0.2314

C1 0.8871 0.7261 0.0085 0.0089 0.0089

C2's 0.0605 0.0495

C3's 0.0221 0.0181

C4's 0.0093 0.0076

C5's 0.0020 0.0016

C6's

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

SYNGAS GENERATION


(MASS FRACTION)


2

C24-C29

C30+WAX

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9 10

StreamH2 to

Hydrocracker

PSA Unit Residue

GasTemperature, °C 62 60

Pressure, bara 27.12 1.40

Molar Flow, kgmole/h 214.2 467.8

Mass Flow, kg/s 0.1 3.4

Enthalpy, kJ/h 1.822E+06 4.515E+06

Mole Wt. 2.016 25.962


H2 1.0000 0.0063

N2 0.6526

CO 0.2851

CO2 0.0379

H2O 0.0089

O2

C1 0.0092

C2's

C3's

C4's

C5's

C6's

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

SYNGAS GENERATION


(MASS FRACTION)


4

C24-C29

C30+WAX

Oxygenates

Total 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamSyngas PSA Unit

Residue Gas

F-T Reactor

Feed


1st Stg. Separator Vapor

1st Stg. Separator Liquid


2nd Stg. Separator Vapor

Temperature, °C 60 203 90 141 141 141 171 171

Pressure, bara 27.47 28.00 27.36 25.66 25.66 25.66 23.76 23.76

Molar Flow, kgmole/h 24,772.7 467.2 25,239.9 6,279.0 6,089.8 96.9 16,584.9 16,565.2

Mass Flow, kg/s 126.9 3.4 130.3 43.4 39.7 8.7 119.2 117.2


Mole Wt. 18.440 25.973 18.580 24.895 23.482 324.574 25.867 25.468


H2 0.0404 0.0063 0.0395 0.0108 0.0118 0.0034 0.0035

N2 0.6302 0.6532 0.6308 0.6308 0.6893 0.0028 0.6893 0.7009

CO 0.2753 0.2853 0.2755 0.0806 0.0880 0.0004 0.0326 0.0331

CO2 0.0366 0.0380 0.0367 0.0400 0.0436 0.0005 0.0436 0.0444

H2O 0.0086 0.0080 0.0086 0.1307 0.1230 0.0014 0.1585 0.1612

O2

C1 0.0089 0.0092 0.0089 0.0122 0.0134 0.0001 0.0143 0.0145

C2's 0.0007 0.0007 0.0009 0.0009

C3's 0.0017 0.0019 0.0024 0.0024

C4's 0.0021 0.0023 0.0001 0.0030 0.0030

C5's 0.0023 0.0026 0.0002 0.0032 0.0033

C6's 0.0025 0.0027 0.0006 0.0036 0.0036

C7-C9 0.0084 0.0088 0.0079 0.0110 0.0112

C10-C12 0.0087 0.0067 0.0366 0.0092 0.0091

C13-C15 0.0082 0.0027 0.0849 0.0050 0.0044

C16-C18 0.0073 0.0006 0.1013 0.0027 0.0015

C19-C23 0.0104 0.0001 0.1540 0.0031 0.0005

F-T SYNTHESIS


(MASS FRACTION)


2

C24-C29 0.0104 0.1542 0.0030

C30+WAX 0.0305 0.4545 0.0088

Oxygenates 0.0017 0.0018 0.0004 0.0022 0.0023

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16

Stream2nd Stg. Separator Liquid

HT Separator Vapor

HT Separtor

Liquid

LT Separator Vapor

LT Separator Liquid

Hydrocracker MP

Flash

Lean Solvent

Rich Solvent

Temperature, °C 171 140 140 40 40 253 4 1

Pressure, bara 23.76 23.46 23.46 22.86 22.86 31.03 29.59 22.50

Molar Flow, kgmole/h 19.6 15,403.4 3.4 12,769.6 69.3 82.4 295.6 405.9

Mass Flow, kg/s 2.0 111.2 0.2 95.8 2.6 0.8 17.0 19.2

Enthalpy, kJ/h 2.593E+06 1.932E+08 1.467E+05 1.156E+08 -3.902E+05 2.801E+06 -7.860E+06 -9.003E+06

Mole Wt. 362.218 25.986 215.804 26.999 133.954 33.961 206.594 170.119


H2 0.0037 0.0043 0.0349

N2 0.0027 0.7387 0.0041 0.8575 0.0062 0.0054

CO 0.0001 0.0349 0.0002 0.0405 0.0003 0.0003

CO2 0.0004 0.0468 0.0008 0.0541 0.0027 0.0037

H2O 0.0016 0.1177 0.0020 0.0028 0.0001 0.0004 0.0001 0.0001

O2

C1 0.0001 0.0153 0.0002 0.0178 0.0004 0.0060 0.0003

C2's 0.0011 0.0012 0.0001 0.0159 0.0001

C3's 0.0026 0.0001 0.0030 0.0008 0.0709 0.0012

C4's 0.0001 0.0031 0.0003 0.0036 0.0029 0.1719 0.0058

C5's 0.0002 0.0036 0.0006 0.0039 0.0092 0.1480 0.0193

C6's 0.0004 0.0038 0.0014 0.0037 0.0274 0.0881 0.0217

C7-C9 0.0049 0.0119 0.0188 0.0052 0.3124 0.2864 0.0004 0.0379

C10-C12 0.0190 0.0095 0.0906 0.0004 0.3881 0.0720 0.1166 0.1081

C13-C15 0.0441 0.0042 0.2404 0.1787 0.0588 0.5241 0.4659

C16-C18 0.0704 0.0011 0.3115 0.0467 0.0337 0.3206 0.2848

C19-C23 0.1544 0.0001 0.2449 0.0067 0.0116 0.0383 0.0344

F-T SYNTHESIS


(MASS FRACTION)


4

C24-C29 0.1742 0.0596 0.0001 0.0008 0.0001 0.0001

C30+WAX 0.5270 0.0239 0.0006

Oxygenates 0.0003 0.0024 0.0009 0.0023 0.0171 0.0106

Total 1.0000 1.0010 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


5

Plant Section

Stream No. 17 18 19

StreamAbsorber Overhea

ds

F-T Liquid to Fractiona

F-T Wax to

UpgradinTemperature, °C 10 48 147

Pressure, bara 22.20 22.86 23.76


Mass Flow, kg/s 94.1 2.8 10.7

Enthalpy, kJ/h 1.025E+08 -2.435E+05 1.125E+07

Mole Wt. 26.680 137.816 330.913


H2 0.0046

N2 0.8714 0.0061 0.0028

CO 0.0412 0.0003 0.0003

CO2 0.0543 0.0026 0.0005

H2O 0.0005 0.0003 0.0014

O2

C1 0.0181 0.0003 0.0001

C2's 0.0013 0.0001

C3's 0.0033 0.0007

C4's 0.0038 0.0027 0.0001

C5's 0.0012 0.0085 0.0002

C6's 0.0256 0.0006

C7-C9 0.2906 0.0073

C10-C12 0.3663 0.0333

C13-C15 0.1831 0.0775

C16-C18 0.0662 0.0956

C19-C23 0.0244 0.1540

F-T SYNTHESIS


(MASS FRACTION)


6

C24-C29 0.0047 0.1580

C30+WAX 0.0018 0.4678

Oxygenates 0.0002 0.0159 0.0004

Total 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamF-T

LiquidRich

SolventF-T

"Wax" Liquid

Hydrocracker

Liquid

Prefractn. Overhea

ds

Prefractn. Bottoms

Product Fractionator Feed

Product Fractiona

tor Temperature, °C 48 1 147 253 46 354 354 66

Pressure, bara 22.86 22.50 23.76 31.03 13.79 14.13 1.72 1.10


Mass Flow, kg/s 2.8 19.2 10.7 10.9 0.6 42.9 42.9 0.0

Enthalpy, kJ/h -2.435E+05 -9.003E+06 1.125E+07 2.129E+07 8.101E+05 1.326E+08 1.580E+08 2.914E+04

Mole Wt. 137.816 170.119 330.913 195.616 35.743 212.454 212.458 59.078


H2 0.0004 0.0081

N2 0.0061 0.0054 0.0028 0.2321

CO 0.0003 0.0003 0.0003 0.0166

CO2 0.0026 0.0037 0.0005 0.1274

H2O 0.0003 0.0001 0.0014 0.0040 0.0715

O2

C1 0.0003 0.0003 0.0001 0.0001 0.0153

C2's 0.0001 0.0001 0.0006 0.0142

C3's 0.0007 0.0012 0.0038 0.1043 0.0003

C4's 0.0027 0.0058 0.0001 0.0137 0.3996 0.0002 0.0002 0.0206

C5's 0.0085 0.0193 0.0002 0.0171 0.0668 0.0125 0.0125 0.4226

C6's 0.0256 0.0217 0.0006 0.0150 0.0002 0.0153 0.0153 0.1882

C7-C9 0.2906 0.0379 0.0073 0.0942 0.0616 0.0616 0.1485

C10-C12 0.3663 0.1081 0.0333 0.0735 0.0990 0.0990 0.0071

C13-C15 0.1831 0.4659 0.0775 0.1660 0.2815 0.2815

C16-C18 0.0662 0.2848 0.0956 0.2405 0.2166 0.2166

C19-C23 0.0244 0.0344 0.1540 0.1702 0.0986 0.0986



(MASS FRACTION)


2

C24-C29 0.0047 0.0001 0.1580 0.0518 0.0530 0.0530

C30+WAX 0.0018 0.4678 0.1531 0.1558 0.1558

Oxygenates 0.0159 0.0106 0.0004 0.0113 0.0057 0.0057 0.1408

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16



Product Diesel

Product Fractiona

tor

Product Diesel

Vacuum Column

Ohd.

Hydrocracker Feed

Hydrocracker

Makeup Temperature, °C 66 45 45 292 45 45 300 62

Pressure, bara 1.10 1.34 1.34 1.52 0.13 1.10 117.90 27.12


Mass Flow, kg/s 5.7 17.0 5.5 14.8 3.2 0.0 11.6 0.1


Mole Wt. 105.230 206.597 206.597 373.505 247.151 179.708 438.355 2.016


H2 1.0000

N2

CO

CO2

H2O 0.0005 0.0001 0.0001 0.0003 0.0001

O2

C1

C2's

C3's

C4's 0.0019

C5's 0.0930 0.0012

C6's 0.1146 0.0041

C7-C9 0.4613 0.0003 0.0003 0.0990

C10-C12 0.2853 0.1166 0.1166 0.0008 0.0039 0.2602

C13-C15 0.0012 0.5240 0.5240 0.0226 0.1028 0.4092 0.0005

C16-C18 0.3206 0.3206 0.1426 0.5582 0.1989 0.0284

C19-C23 0.0383 0.0383 0.2281 0.3338 0.0254 0.1992



(MASS FRACTION)


4

C24-C29 0.0001 0.0001 0.1534 0.0009 0.1953

C30+WAX 0.4519 0.5764


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


5

Plant Section

Stream No. 17 18 19 20 21 22

StreamHydrocra

cker Feed

Hydrocracker

Effluent

Hydrocracker

Recycle

Hydrocracker

Liquids

Hydrocracker

Purge

Hydrocracker Flash

Temperature, °C 370 412 45 253 45 253

Pressure, bara 116.18 114.80 113.76 31.03 113.76 31.03


Mass Flow, kg/s 12.1 12.1 0.4 11.7 0.02 0.8


Mole Wt. 58.777 58.782 3.328 148.624 3.328 33.961


H2 0.0292 0.0231 0.5839 0.0027 0.5839 0.0349

N2

CO

CO2

H2O 0.0001 0.0001 0.0025 0.0025 0.0004

O2

C1 0.0018 0.0024 0.0531 0.0005 0.0531 0.0060

C2's 0.0019 0.0035 0.0564 0.0016 0.0564 0.0159

C3's 0.0037 0.0119 0.1122 0.0082 0.1122 0.0709

C4's 0.0039 0.0275 0.1177 0.0242 0.1177 0.1719

C5's 0.0016 0.0265 0.0461 0.0258 0.0461 0.1480

C6's 0.0004 0.0196 0.0120 0.0199 0.0120 0.0881

C7-C9 0.0005 0.1038 0.0158 0.1069 0.0158 0.2864

C10-C12 0.0709 0.0004 0.0734 0.0004 0.0720

C13-C15 0.0005 0.1532 0.1588 0.0588

C16-C18 0.0272 0.2189 0.2269 0.0337

C19-C23 0.1907 0.1540 0.1596 0.0116



(MASS FRACTION)


6

C24-C29 0.1869 0.0468 0.0483 0.0008

C30+WAX 0.5517 0.1379 0.1429 0.0006

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamF-T

Synthesis Purge

MP Steam

Addition

CO Shift Feed

CO Shift Effluent

CO2 Absorber

Feed

Treated Gas to Fuel

Captured CO2 to

Compres

Lean Amine

Temperature, °C 10 329 200 243 45 45 45 122

Pressure, bara 22.20 32.00 21.10 20.50 19.80 19.40 1.72 2.00

Molar Flow, kgmole/h 12,698.9 1,494.2 14,162.8 14,162.8 13,219.5 12,286.6 932.9 39,977.7

Mass Flow, kg/s 94.1 7.5 101.6 101.6 96.9 85.7 11.1 270.0


Mole Wt. 26.680 18.015 25.823 25.823 26.379 25.116 43.017 24.316


H2 0.0046 0.0041 0.0068 0.0071 0.0081 0.0001

N2 0.8714 0.8073 0.8073 0.8466 0.9562 0.0039

CO 0.0412 0.0381 0.0010 0.0011 0.0012

CO2 0.0543 0.0503 0.1086 0.1139 0.0009 0.9822 0.0001

H2O 0.0005 1.0000 0.0741 0.0503 0.0040 0.0028 0.0136 0.6948

O2

C1 0.0181 0.0167 0.0167 0.0176 0.0198 0.0002

C2's 0.0013 0.0013 0.0013 0.0014 0.0016

C3's 0.0033 0.0032 0.0032 0.0033 0.0038

C4's 0.0038 0.0036 0.0036 0.0037 0.0042

C5's 0.0012 0.0011 0.0011 0.0012 0.0013

C6's

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29



(MASS FRACTION)


2

C30+WAX

Oxygenates 0.0002

Amine 0.3051

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MASS FRACTION)


3

Plant Section

Stream No. 9

StreamRich

Amine

Temperature, °C 80

Pressure, bara 4.14



Enthalpy, kJ/h -9.520E+08

Mole Wt. 24.739


H2

N2

CO

CO2 0.0390

H2O 0.6681

O2

C1

C2's

C3's

C4's

C5's

C6's

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29



(MASS FRACTION)


4

C30+WAX

Oxygenates

Amine 0.2929

Total 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamSyngas PSA Unit

Residue Gas

F-T Reactor

Feed


1st Stg. Separator Vapor

1st Stg. Separator Liquid


2nd Stg. Separator Vapor

Temperature, °C 60 203 90 141 141 141 171 171

Pressure, bara 27.47 28.00 27.36 25.66 25.66 25.66 23.76 23.76

Molar Flow, kgmole/h 24,772.7 467.2 25,239.9 6,279.0 6,089.8 96.9 16,584.9 16,565.2

Mass Flow, kg/s 126.9 3.4 130.3 43.4 39.7 8.7 119.2 117.2


Mole Wt. 18.440 25.973 18.580 24.895 23.482 324.574 25.867 25.468

Composition, Mol Frac.

H2 0.3696 0.0809 0.3642 0.1329 0.1370 0.0053 0.0442 0.0442

N2 0.4148 0.6056 0.4184 0.5606 0.5778 0.0321 0.6365 0.6372

CO 0.1812 0.2646 0.1828 0.0716 0.0738 0.0044 0.0301 0.0301

CO2 0.0153 0.0224 0.0155 0.0226 0.0233 0.0036 0.0257 0.0257

H2O 0.0088 0.0115 0.0089 0.1806 0.1603 0.0255 0.2276 0.2278

O2

C1 0.0102 0.0149 0.0103 0.0190 0.0195 0.0018 0.0231 0.0231

C2's 0.0006 0.0006 0.0001 0.0008 0.0008

C3's 0.0010 0.0010 0.0004 0.0014 0.0014

C4's 0.0009 0.0009 0.0008 0.0012 0.0012

C5's 0.0008 0.0008 0.0014 0.0013 0.0013

C6's 0.0008 0.0008 0.0023 0.0011 0.0011

C7-C9 0.0018 0.0017 0.0217 0.0025 0.0024

C10-C12 0.0013 0.0010 0.0746 0.0015 0.0015

C13-C15 0.0010 0.0004 0.1387 0.0007 0.0006

C16-C18 0.0008 0.1371 0.0003 0.0002

C19-C23 0.0010 0.1698 0.0003

F-T SYNTHESIS


(MOLE FRACTION)


2

C24-C29 0.0006 0.1351

C30+WAX 0.0013 0.2437 0.0004

Oxygenates 0.0008 0.0008 0.0019 0.0011 0.0011

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16

Stream2nd Stg. Separator Liquid

HT Separator Vapor

HT Separtor

Liquid

LT Separator Vapor

LT Separator Liquid

Hydrocracker MP

Flash

Lean Solvent

Rich Solvent

Temperature, °C 171 140 140 40 40 253 4 1

Pressure, bara 23.76 23.46 23.46 22.86 22.86 31.03 29.59 22.50

Molar Flow, kgmole/h 19.6 15,403.4 3.4 12,769.6 69.3 82.4 295.6 405.9

Mass Flow, kg/s 2.0 111.2 0.2 95.8 2.6 0.8 17.0 19.2

Enthalpy, kJ/h 2.593E+06 1.932E+08 1.467E+05 1.156E+08 -3.902E+05 2.801E+06 -7.860E+06 -9.003E+06

Mole Wt. 362.218 25.986 215.804 26.999 133.954 33.961 206.594 170.119


H2 0.0018 0.0476 0.0015 0.0574 0.0010 0.5875 0.0009

N2 0.0347 0.6853 0.0313 0.8264 0.0298 0.0330

CO 0.0017 0.0324 0.0016 0.0390 0.0016 0.0020

CO2 0.0034 0.0276 0.0038 0.0332 0.0083 0.0142

H2O 0.0316 0.1698 0.0242 0.0041 0.0010 0.0008 0.0011 0.0014

O2

C1 0.0020 0.0248 0.0021 0.0299 0.0030 0.0128 0.0036

C2's 0.0001 0.0009 0.0002 0.0011 0.0005 0.0180 0.0008

C3's 0.0004 0.0016 0.0006 0.0018 0.0025 0.0546 0.0050

C4's 0.0008 0.0014 0.0011 0.0017 0.0069 0.1005 0.0173

C5's 0.0012 0.0013 0.0019 0.0015 0.0172 0.0696 0.0459

C6's 0.0020 0.0012 0.0036 0.0012 0.0431 0.0347 0.0432

C7-C9 0.0150 0.0027 0.0341 0.0013 0.3608 0.0892 0.0005 0.0598

C10-C12 0.0434 0.0016 0.1227 0.3373 0.0158 0.1423 0.1093

C13-C15 0.0800 0.0006 0.2600 0.1231 0.0101 0.5461 0.3999

C16-C18 0.1058 0.0001 0.2806 0.0266 0.0048 0.2804 0.2052

C19-C23 0.1889 0.1840 0.0032 0.0013 0.0292 0.0217

F-T SYNTHESIS


(MOLE FRACTION)


4

C24-C29 0.1703 0.0354

C30+WAX 0.3154 0.0085

Oxygenates 0.0016 0.0012 0.0030 0.0013 0.0336 0.0367

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


5

Plant Section

Stream No. 17 18 19

StreamAbsorber Overhea

ds

F-T Liquid to Fractiona

F-T Wax to

UpgradinTemperature, °C 10 48 147

Pressure, bara 22.20 22.86 23.76


Mass Flow, kg/s 94.1 2.8 10.7

Enthalpy, kJ/h 1.025E+08 -2.435E+05 1.125E+07

Mole Wt. 26.680 137.816 330.913


H2 0.0615 0.0011 0.0047

N2 0.8300 0.0298 0.0326

CO 0.0392 0.0016 0.0039

CO2 0.0329 0.0081 0.0036

H2O 0.0008 0.0021 0.0265

O2

C1 0.0301 0.0029 0.0019

C2's 0.0012 0.0005 0.0001

C3's 0.0020 0.0024 0.0004

C4's 0.0017 0.0067 0.0008

C5's 0.0004 0.0165 0.0012

C6's 0.0414 0.0022

C7-C9 0.3454 0.0205

C10-C12 0.3273 0.0693

C13-C15 0.1296 0.1287

C16-C18 0.0386 0.1317

C19-C23 0.0117 0.1729

F-T SYNTHESIS


(MOLE FRACTION)


6

C24-C29 0.0018 0.1409

C30+WAX 0.0004 0.2558

Oxygenates 0.0001 0.0322 0.0019

Total 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamF-T

Synthesis Purge

MP Steam

Addition

CO Shift Feed

CO Shift Effluent

CO2 Absorber

Feed

Treated Gas to Fuel

Captured CO2 to

Compres

Lean Amine

Temperature, °C 10 329 200 243 45 45 45 122

Pressure, bara 22.20 32.00 21.10 20.50 19.80 19.40 1.72 2.00


Mass Flow, kg/s 94.1 7.5 101.6 101.6 96.9 85.7 11.1 270.0


Mole Wt. 26.680 18.015 25.823 25.823 26.379 25.116 43.017 24.316


H2 0.0615 0.0529 0.0871 0.0933 0.1003 0.0011

N2 0.8300 0.7442 0.7442 0.7973 0.8573 0.0059

CO 0.0392 0.0351 0.0010 0.0010 0.0011

CO2 0.0329 0.0295 0.0637 0.0682 0.0005 0.9600

H2O 0.0008 1.0000 0.1063 0.0721 0.0059 0.0039 0.0325 0.9377

O2

C1 0.0301 0.0270 0.0270 0.0289 0.0310 0.0004

C2's 0.0012 0.0011 0.0011 0.0012 0.0013

C3's 0.0020 0.0019 0.0019 0.0020 0.0022

C4's 0.0017 0.0016 0.0016 0.0018 0.0019

C5's 0.0004 0.0004 0.0004 0.0004 0.0004

C6's

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29



(MOLE FRACTION)


2

C30+WAX

Oxygenates 0.0001

Amine 0.0623

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3

Plant Section

Stream No. 9

StreamRich

Amine

Temperature, °C 80

Pressure, bara 4.14




Mole Wt. 24.739


H2

N2

CO

CO2 0.0219

H2O 0.9172

O2

C1

C2's

C3's

C4's

C5's

C6's

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29



(MOLE FRACTION)


4

C30+WAX

Oxygenates

Amine 0.0608

Total 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamF-T

LiquidRich

SolventF-T

"Wax" Liquid

Hydrocracker

Liquid

Prefractn. Overhea

ds

Prefractn. Bottoms

Product Fractionator Feed

Product Fractiona

tor Temperature, °C 48 1 147 253 46 354 354 66

Pressure, bara 22.86 22.50 23.76 31.03 13.79 14.13 1.72 1.10


Mass Flow, kg/s 2.8 19.2 10.7 10.9 0.6 42.9 42.9 0.0

Enthalpy, kJ/h -2.435E+05 -9.003E+06 1.125E+07 2.129E+07 8.101E+05 1.326E+08 1.580E+08 2.914E+04

Mole Wt. 137.816 170.119 330.913 195.616 35.743 212.454 212.458 59.078


H2 0.0011 0.0009 0.0047 0.0418 0.1439

N2 0.0298 0.0330 0.0326 0.2962

CO 0.0016 0.0020 0.0039 0.0212

CO2 0.0081 0.0142 0.0036 0.1035

H2O 0.0021 0.0014 0.0265 0.0001 0.0080 0.2345

O2

C1 0.0029 0.0036 0.0019 0.0016 0.0340

C2's 0.0005 0.0008 0.0001 0.0037 0.0168

C3's 0.0024 0.0050 0.0004 0.0167 0.0856 0.0004

C4's 0.0067 0.0173 0.0008 0.0461 0.2481 0.0009 0.0009 0.0210

C5's 0.0165 0.0459 0.0012 0.0463 0.0338 0.0372 0.0372 0.3493

C6's 0.0414 0.0432 0.0022 0.0341 0.0381 0.0381 0.1302

C7-C9 0.3454 0.0598 0.0205 0.1640 0.1166 0.1166 0.0836

C10-C12 0.3273 0.1093 0.0693 0.0909 0.1300 0.1300 0.0028

C13-C15 0.1296 0.3999 0.1287 0.1622 0.3015 0.3015

C16-C18 0.0386 0.2052 0.1317 0.1948 0.1932 0.1932

C19-C23 0.0117 0.0217 0.1729 0.1210 0.0744 0.0744



(MOLE FRACTION)


2

C24-C29 0.0018 0.1409 0.0273 0.0303 0.0303

C30+WAX 0.0004 0.2558 0.0495 0.0547 0.0547

Oxygenates 0.0322 0.0367 0.0019 0.0088 0.0232 0.0232 0.1782

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3

Plant Section

Stream No. 9 10 11 12 13 14 15 16



Product Diesel

Product Fractiona

tor

Product Diesel

Vacuum Column

Ohd.

Hydrocracker Feed

Hydrocracker

Makeup Temperature, °C 66 45 45 292 45 45 300 62

Pressure, bara 1.10 1.34 1.34 1.52 0.13 1.10 117.90 27.12


Mass Flow, kg/s 5.7 17.0 5.5 14.8 3.2 0.0 11.6 0.1


Mole Wt. 105.230 206.597 206.597 373.505 247.151 179.708 438.355 2.016


H2 1.0000

N2

CO

CO2

H2O 0.0031 0.0011 0.0011 0.0066 0.0002 0.0012 0.0011

O2

C1

C2's

C3's

C4's 0.0033

C5's 0.1366 0.0029

C6's 0.1410 0.0084

C7-C9 0.4324 0.0005 0.0005 0.0001 0.1498

C10-C12 0.1978 0.1423 0.1423 0.0019 0.0056 0.2909

C13-C15 0.0007 0.5460 0.5460 0.0413 0.1241 0.3743 0.0010

C16-C18 0.2805 0.2805 0.2175 0.5653 0.1505 0.0498

C19-C23 0.0291 0.0291 0.2992 0.3040 0.0170 0.2994



(MOLE FRACTION)


4

C24-C29 0.1545 0.0007 0.2310

C30+WAX 0.2789 0.4175


Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


5

Plant Section

Stream No. 17 18 19 20 21 22

StreamHydrocra

cker Feed

Hydrocracker

Effluent

Hydrocracker

Recycle

Hydrocracker

Liquids

Hydrocracker

Purge

Hydrocracker Flash

Temperature, °C 370 412 45 253 45 253

Pressure, bara 116.18 114.80 113.76 31.03 113.76 31.03


Mass Flow, kg/s 12.1 12.1 0.4 11.7 0.02 0.8


Mole Wt. 58.777 58.782 3.328 148.624 3.328 33.961


H2 0.8507 0.6726 0.9640 0.2004 0.9640 0.5875

N2

CO

CO2

H2O 0.0004 0.0004 0.0005 0.0003 0.0005 0.0008

O2

C1 0.0064 0.0087 0.0110 0.0048 0.0110 0.0128

C2's 0.0036 0.0068 0.0062 0.0078 0.0062 0.0180

C3's 0.0049 0.0158 0.0085 0.0277 0.0085 0.0546

C4's 0.0039 0.0278 0.0067 0.0619 0.0067 0.1005

C5's 0.0013 0.0215 0.0022 0.0530 0.0022 0.0696

C6's 0.0003 0.0134 0.0004 0.0344 0.0004 0.0347

C7-C9 0.0002 0.0546 0.0005 0.1422 0.0005 0.0892

C10-C12 0.0264 0.0691 0.0158

C13-C15 0.0001 0.0451 0.1180 0.0101

C16-C18 0.0063 0.0533 0.1396 0.0048

C19-C23 0.0384 0.0329 0.0862 0.0013



(MOLE FRACTION)


6

C24-C29 0.0297 0.0075 0.0195

C30+WAX 0.0536 0.0134 0.0351

Oxygenates

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


1

Plant Section

Stream No. 1 2 3 4 5 6 7 8

StreamF-T

Synthesis Purge

MP Steam

Addition

CO Shift Feed

CO Shift Effluent

CO2 Absorber

Feed

Treated Gas to Fuel

Captured CO2 to

Compres

Lean Amine

Temperature, °C 10 329 200 243 45 45 45 122

Pressure, bara 22.20 32.00 21.10 20.50 19.80 19.40 1.72 2.00


Mass Flow, kg/s 94.1 7.5 101.6 101.6 96.9 85.7 11.1 270.0


Mole Wt. 26.680 18.015 25.823 25.823 26.379 25.116 43.017 24.316


H2 0.0615 0.0529 0.0871 0.0933 0.1003 0.0011

N2 0.8300 0.7442 0.7442 0.7973 0.8573 0.0059

CO 0.0392 0.0351 0.0010 0.0010 0.0011

CO2 0.0329 0.0295 0.0637 0.0682 0.0005 0.9600

H2O 0.0008 1.0000 0.1063 0.0721 0.0059 0.0039 0.0325 0.9377

O2

C1 0.0301 0.0270 0.0270 0.0289 0.0310 0.0004

C2's 0.0012 0.0011 0.0011 0.0012 0.0013

C3's 0.0020 0.0019 0.0019 0.0020 0.0022

C4's 0.0017 0.0016 0.0016 0.0018 0.0019

C5's 0.0004 0.0004 0.0004 0.0004 0.0004

C6's

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29



(MOLE FRACTION)


2

C30+WAX

Oxygenates 0.0001

Amine 0.0623

Total 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg



(MOLE FRACTION)


3

Plant Section

Stream No. 9

StreamRich

Amine

Temperature, °C 80

Pressure, bara 4.14




Mole Wt. 24.739


H2

N2

CO

CO2 0.0219

H2O 0.9172

O2

C1

C2's

C3's

C4's

C5's

C6's

C7-C9

C10-C12

C13-C15

C16-C18

C19-C23

C24-C29



(MOLE FRACTION)


4

C30+WAX

Oxygenates

Amine 0.0608

Total 1.0000

LHV Dry Basis*:

kJ/kgmole

kJ/kg


141

7C-2 PROCESS DESCRIPTION The design basis and major assumptions for each major ISBL plant are presented in Sections 3 and 4C2. Area 100, Syngas Generation Area 100 is the syngas generation area. This area consists of the following plants. Plant 102 Air Compression Plant 102 Air-Blown Autothermal Reforming Plant Area 100 for the CO2 Capture & Compression design is identical with the Standard Plant design described in section 7C-1, and is not described again here.

142

Area 200 - Fisher-Tropsch Synthesis and Product Upgrading Area 200 is the Fischer-Tropsch synthesis and product upgrading area. It consists of the following plants: Plant 201 Syntroleum-Type Fischer-Tropsch Synthesis and Hydrocarbon Recovery Plant Plant 202 Product Fractionation & Wax Hydrocracking Plant Area 200 for the CO2 Capture & Compression design is identical with the Standard Plant design described in section 7C-1, and is not described again here. Since there is are modifications to the Hydrocarbon Recovery unit, those changes are discussed. Plant 201 - Hydrocarbon Recovery A chilled lean oil absorption unit, using a diesel recycle stream as the solvent, is used to recover additional C5

+ components in the F-T reactor effluent gas stream downstream of the cooling/recovery train. Rich solvent leaving the bottom of the absorber is fed to the product fractionation plant. To increase the amount of plant feed carbon recovered as product, and thereby lower the facility’s carbon emissions, additional C5

+ hydrocarbons were recovered from syngas stream leaving the F-T reactors by chilling the feed stream to the lean oil absorption unit and increasing the lean oil flow rate. The syngas stream leaving separator, 201C-5, is chilled using propane refrigerant prior to entering the absorber. The additional 374 BPD recovered to the product is equivalent to 2% of the carbon in the natural gas feed stream.

143

Area 300 - Steam Distribution System HP superheated steam is raised in Plant 102 by heat recovery from the syngas generation unit. HP steam is used to drive the air compressor. An extraction from the air compressor turbine at MP steam level (34 bar) provides steam to the MP steam users. The air compressor turbine exhausts at 0.14 bar. Steam raised in the F-T reactor tubes at 15 bar is superheated to 300°C in fired heater, 201F-1. F-T plant superheated steam is to drive the electric-power generator. The LP steam users are supplied with steam from the generator turbine exhaust. Excess LP steam is condensed in an air cooler with a seawater trim cooler.

144

Area 500 - CO2 Capture and Compression Area 500 is the CO2 capture and compression area. It consists of the following plants: • Feed gas Hydrogenation and LT-CO Shift • MDEA-based CO2 removal • CO2 compression

This design of this plant is based on converting CO in Plant 201 residue syngas to CO2 and H2, and then, using a chemical solvent, removing the CO2 from the gas stream. CO2 captured in the CO2 Absorber is released during solvent regeneration and compressed to transport pipeline delivery pressure, 110 bar. Treated gas from the CO2 Absorber is used as fuel in the facility’s process heaters. The process flow diagram for Plant 500 is shown in PFD 501-B-01. Plant 500 - Hydrotreating & LT-CO Shift Syngas remaining from F-T synthesis, which contains the bulk of the non-product carbon, is preheated to the hydrotreating temperature (270°C) by steam-heated exchanger, 501E-9, and fired heater, 201F-1. Unsaturated hydrocarbons and oxygenates in the syngas stream react with H2 to form their saturated hydrocarbon counterparts in the fixed-bed catalytic reactor, 501R-1. MP steam is added to the hydrotreater effluent. The combined stream is cooled to 200°C, the inlet temperature for the LT-CO shift reactor, 501R-2. Copper-based catalyst in the shift reactor promotes the conversion of CO (3.9 mol%, dry gas basis) and steam to CO2 and H2, resulting in a reactor outlet CO concentration of 0.1 mol%, dry basis and an exit temperature of 243°C. The shift reactor effluent stream is cooled in exchangers 501E-11, 501E-1, and 501E-14. Part of the reboil duty for the CO2 Stripper, 501C-2, is provided from cooling the shift reactor effluent in exchanger 501E-11. Plant 500 - CO2 Removal A liquid chemical solvent - a 30 wt% aqueous solution of mono-diethanolamine (MDEA) - removes CO2 from shift reactor effluent gas. The gas stream is contacted with solvent in the CO2 Absorber, 501C-1. The absorber is a cylindrical vessel with internal packing; designed to promote ‘good contact’ between the gas and solvent streams. Regenerated solvent enters at the top of the vessel and leaves as rich solvent from the bottom. Shift reactor effluent gas enters at the bottom of the vessel and leaves as a ‘CO2-free’ gas stream from the top. CO2 is transferred from the gas to the liquid phase by dissolving in the solvent and then reacting with active reagent. It leaves the vessel in the rich solvent stream, chemically bound to the active reagent, MDEA. Heating and stripping the rich solvent in the CO2 Stripper, 501C-2, regenerates the solvent and releases CO2 back to the vapor phase. CO2 is separated from condensed stripping steam in the CO2 stripper reflux drum, 501C-6. The CO2 stripper reboil duty is provided partly from waste heat in the shift reactor effluent stream and partly from LP steam. Regenerated solvent is cooled to its absorber feed temperature by heat exchangers 501E-13, 501E-2 and 501E-15. The gas stream leaving the CO2 Absorbers is predominantly nitrogen, but it also contains hydrogen and residual hydrocarbons. This stream is used as fuel in the facility process heaters.

145

Plant 500 - CO2 Compression CO2, at 1.1 bar in the stripper reflux drum, is sent to CO2 compression, 501K-1. CO2 is compressed in four compression stages to 110 bar for delivery to the battery limit CO2 transport pipeline. The compression HP requirement is approximately 4 MW. To prevent downstream corrosion problems, the gas from the first compression stage is passed through a packed bed of sorbent material to remove moisture from the gas.

146

8C-2 OFFSITES The offsites plants for the CO2 capture and compression case are similar to those for the standard plant design.

147

9C-2 PLANT COSTS The same method of cost estimating as was used for the standard plant design is used for the CO2 capture and compression case. 9C-2.1 Installed Plant Costs Table 9C-2.1 shows the capital cost breakdown for a Syntroleum-Type, natural gas Fischer-Tropsch liquefaction plant with CO2 capture and compression facilities.

Table 9C-2.1




Area 100 - Syngas Generation 118,334 Area 200 - F-T Synthesis & Product Upgrading 45,047 Area 300 - Steam & Power Generation 25,517 Area 500 - CO2 Capture & Compression 41,864 Total ISBL Cost 230,763







148

9C-2.2 Annual Operating Costs Table 9C-2.2 shows the annual operating costs for a Syntroleum-Type, natural gas Fischer-Tropsch liquefaction plant with CO2 capture and compression facilities.

Table 9C-2.2



COST, $1,000's

Fixed Costs: Rent 55 acres $ 150 /acre/year $ 8 Taxes 1% of capital cost $ 4,057 Insurance 1% of capital cost $ 4,057 Operating Labor (excl. maint.) 52 people $50,000 /pers/annum $ 4,680 Maintenance (matl. & labor) 2% of capital cost $ 8,114 Misc. Supplies Corporate Overhead Total Fixed Costs $ 20,915

Variable Costs: Natural Gas 99,666 GJ/day $ 0.50 /GJ $ 18,189 Seawater 44,287 gpm $ 0.07 /1,000 gal $ 1,629 Desalinated Water 150 gpm $ 4.50 /1,000 gal $ 355 Electric Power 7,408 kWh $ 0.015 /kWh import $ 973 Catalyst & Chemicals $ 6,029 Other Operating Costs Annual Variable Costs $ 27,175 Load Factor 90% Total Actual Variable Costs $ 24,458 By-Product Credits Unit/D /Unit $ - Unit/D /Unit $ - Total By-Product Credits $ - Net Operating Costs $ 45,373

*OCC - Overnight Construction Cost (total field costs + contractor's costs)

149

10. STUDY DISCUSSION Natural Gas Transportation The three main practices for transporting remote natural gas to consuming markets are pipeline transport of treated gas, conversion to LNG followed by dedicated tanker shipping, and indirect conversion to higher-valued fuel and/or chemical products that can be transported in conventional tankers. Research is also currently underway into the direct conversion of natural gas to liquid products - approaches such as oxidative coupling and pyrolysis fall into this category.

Indirect Liquefaction Indirect liquefaction involves the conversion of hydrocarbon feedstock first to syngas (carbon oxides and hydrogen) followed by C1-chemistry catalytic conversion of the syngas to a given product.

This study addresses the indirect conversion of natural gas to liquid transport fuels, and in particular process configurations representative of those offered by Sasol, Shell, and Syntroleum for conversion of natural gas to liquid hydrocarbons, via F-T synthesis.

Other indirect liquefaction process technologies that might also be considered, along with F-T synthesis, include LP-methanol, MTG-gasoline, and Dimethylether (DME) production.

A summary level comparison between the results of this study for F-T distillate production and a separate studies for steam reformer-based methanol synthesis and partial oxidation-based DME synthesis is presented in the table below.

Basis: per this study basis (i.e., 100 MMSCFD natural gas, Middle-East site, etc.)

Technology Capital Cost, $MM

Operating Cost, $MM

Product Sales Price, $/bbl

Product Capacity, BPD

% Feed Carbon in Product

F-T Sasol 346 38 24.5 10,309 68

F-T Shell 390 39 26 10,464 69

F-T Syntroleum 388 49 30 10,104 67

LP Methanol 397 38 11

(86 $/MT)

25,300

(3,165 MTD)

78

LP-DME 438 42 15.4

(144$/MT)

19,734

(2,115 MTD)

73

150

Syngas Generation F-T synthesis chemistry has a H2:CO stoichiometric ratio of 2:1. Syngases with this H2:CO ratio are produced primarily from partial oxidation-based hydrocarbon conversion technologies rather than steam reforming-based technologies.

Natural gas syngas generation technology can be classified as either steam reforming-based, or partial oxidation-based, or some combination of both technologies (series, parallel, and even series-parallel).

Steam reforming produces H2:CO ratios greater 2:1. This is in part due to reaction stoichiometry and in part due to the presence excess steam driving the CO-shift reaction to H2 and CO2 formation. Steam reforming requires excess steam be added to the feed to avoid carbon-formation reactions from occurring on the catalyst surface.

Steam reforming is not necessarily the preferred technology for generating syngas for F-T synthesis, since much of the feed carbon is converted to CO2, and CO2 is considered an inert in cobalt catalyst-based F-T synthesis. Therefore, with steam reforming the opportunity to maximize the conversion of feed carbon to F-T hydrocarbons through CO is significantly impacted, unless large quantities of CO2 are recycled to the reformer, to offset CO conversion to CO2.

Partial oxidation-based conversion technologies on the other hand produce syngas with a H2:CO ratio close to 2:1, with relatively little co-production of CO2. As a first step, partial oxidation-based conversion technologies undergo hydrogen abstraction of the feed hydrocarbon when mixed with molecular oxygen at a diffusion flame interface. Following this partial combustion/oxidation stage, the product mix then either undergoes homogeneous or heterogeneous CO shift and reforming reactions to produce the desired quality syngas.

The syngas generation technologies selected for this study are primarily partial oxidation-based, and are the technologies chosen, or proposed, by the above F-T synthesis licensors.

Greenhouse Gases Emissions The primary focus of this study is to determine the quantity of greenhouse gases emitted from ‘standard design’ facilities for each of the above technologies, and then to include design modifications that reduce the greenhouse gases emissions to a predetermined level.

In this instance, greenhouse gases are considered to be all non-product carbon streams, which currently are typically released as gas streams to the atmosphere. These include:- flue gas streams from fuel combustion, dissolved volatile carbon species - which are stripped from solvents and either incinerated, or vented to the atmosphere, and losses associated with storage tank ‘breathing’, etc.

By far, the major contributors to greenhouse gases emissions are the process fuel streams, resulting from process separations, and reactant-depleted streams from process conversions.

In the first part of this study, F-T synthesis plant designs were developed that are considered to be ‘standard design configurations’, given the requirements and constraints set out in the study design criteria. This then allows the greenhouse gases emissions to be benchmarked for the F-T technologies involved. The table below summarizes the non-product carbon emissions from each of the plants.

Technology Carbon in Feed,

MT/y

Carbon in non-product carbon streams, MT/y

F-T Sasol 498,497 159,625

F-T Shell 498,497 156,397

F-T Syntroleum 498,497 165,599

Carbon Utilization

151

In developing a ’standard-design’ configuration a balance has to be reached between increased carbon utilization as product (carbon efficiency) and the costs associated with each marginal improvement in carbon utilization. Typically, recycling reactants in the syngas through the F-T synthesis reactors increases carbon utilization (as product), until some practical approach to the point of limiting-reactant extinction is reached. This, of course, requires that inerts, such as nitrogen and carbon dioxide, be removed from the recycle stream and that non-product hydrocarbons (C4

-) in the recycle stream be either removed or converted to syngas, by recycle to the syngas generation section. Recycling syngas and removing inert are costly operations.

In addition, unconverted syngas is a useful source of plant fuel, where high temperature processing is part of the plant configuration. Therefore, full utilization of CO in a F-T stoichiometric syngas, especially where the C4

- yield is insufficient to provide the fuel needs, could prove difficult to justify from both practical operation and process economic standpoints.

The syngas conversion-per-pass for the Sasol slurry bubble-column reactor is assumed to be 76% (conversion of CO to F-T hydrocarbons and CO2). To increase the yield of C5

+ distillate material, hydrocarbon recovery from the F-T reactor effluent stream and recycle of C4

--bearing syngas to the autothermal reformer are included as part of the standard design.

The standard design cases for Shell and Syntroleum include arrangements for F-T synthesis reactors where there are two reactors in series, which result in a net conversion-per-pass of 89%. In these cases there is little incentive to recycle effluent syngas.

Hydrocarbon chain-growth chemistry, such as C4- oligomerization, should also be considered as a means of

increasing carbon utilization.

Reduction in Greenhouse Gases Emissions Having reached the point of characterizing the emissions from the standard-design F-T synthesis technologies under review, a view-to-the-future design constraint is imposed whereby the non-product carbon emissions from each of these technologies is limited to a predetermined level.

The second part of the study determines the cost for CO2 removal and compression both in terms of i) additional capital and operating costs for CO2-related equipment (in $/tonne) and ii) after economic analyses - in terms of the increase in product sales price to maintain the design criteria return on investment.

For this evaluation the design criteria calls for CO2 emissions from each facility to be reduced by 85% from standard design levels. This requirement is treated as a legislated requirement (as part of doing business) when performing plant economic analysis, and consequently is not included as part of the sensitivity analysis. In a similar sense, plant capacity is not part of a sensitivity/plant optimization analysis.

Therefore, economic analyses on the effects of imposing reductions in greenhouse gases on F-T synthesis plants is based solely on a strategy of implementing process design modifications, such as revising technology selection, improving carbon utilization, and treating fuel gas prior to combustion.

Fuel Gas Treating For the Sasol and Shell technologies fuel gas treating consists of converting the CO in the syngas to CO2 and H2 and then removing the CO2. This yields an H2/C4

- fuel stream, which in the case of Sasol is used directly as fuel, and in the case of Shell is treated to recover H2 (for hydrocracking) and C4

- before being used as fuel.

CO shift is a moderately exothermic reaction, and consequently the heating value of the ‘shifted’ gas stream is reduced, but not significantly.

CO2 Reduction & Compression The results for the design modifications are summarized below

152

Technology Non-product carbon

emissions, MT/y

% reduction in GHG

emissions

Cost for CO2 reduction, $/tonne

‘Standard Design’ product sales price, $/bbl

‘CO2 reduction’ product sales price, $/bbl

F-T Sasol 48,263 70 94 24.5 28.7

F-T Shell 16,223 90 89 26.4 29.5

F-T Syntroleum 70,651 57 125 30.2 32.6

The Shell case has the greatest reduction in non-product carbon emissions, mainly because the treated gas from CO2 removal is further processed to recover hydrogen for hydrocracking. During this step C4

- is also recovered, and can be recycled as feedstock to the syngas generation units.

Plant Capacity In this study plant capacity is set at approximately 10,000 barrels-per-day, although based on today’s oil and gas costs it seems that larger plant capacities, say 50,000-70,000 barrels-per-day, are needed, where plant economies-of-scale can drive down the required product sales price to a more competitive range.

153

Future Considerations

It would appear that a high carbon-utilization, low GHG-emissions facility could be developed from gas heated reactor syngas generation technology together with a cobalt F-T synthesis catalyst that minimizes termination of the C4

- fraction during F-T synthesis. GHR Syngas Generation GHR is a combination of steam-reforming and partial oxidation. The attraction of GHR to CO2 emission reductions is that the energy needed for the endothermic reforming reactions is provided by ‘in-situ’ partial combustion, such that all carbon is retained in the syngas. In conventional steam reforming, fuel is fired ‘externally’ to provide the energy needs.

With GHR, the H2:CO ratio and CO2 content of the syngas could be adjusted to the point where there is sufficient excess hydrogen to provide the plant fuel needs; thereby allowing CO conversion in F-T synthesis to be maximized and avoiding the need for CO shift of the syngas fuel stream.

154

Influence of Site Location Locating the plant at a US Gulf Coast site, is likely to reduce the total project cost by approximately 20% and to reduce the net operating cost by approximately 15%, on a natural gas-excluded basis.

The decrease in operating cost is mainly due to the absence of costs associated with the use of seawater and desalinated water – purchase cost, pumping costs, etc.

The key factors causing the difference in plant costs are :

• Seawater process coolers at the Saudi Arabia site are more expensive; due to both physical size and exchanger metallurgy

• Seawater distribution piping is more expensive; due to both physical size (associated with lower temperature rises) and the need for either internal lining, or more-costly material, for the piping

• Bulk materials manufactured in Saudi Arabia are more expensive than imported materials

• Spare parts inventory is higher at the Saudi Arabia site because of the longer replacement time from the manufacturing site for key items

• Typically, for a Saudi Arabia construction project, a percentage of construction labor must be imported and housed in camps

• Field indirects are higher for overseas sites because much of the nonmanual labor consists of expatriates

• Freight and Import Duty charges are higher, since most of the equipment and some of the bulk materials would have to be imported to Saudi Arabia

• Contingency is likely to be higher for a site location where cost and economic parameters are not as well documented as those for US Gulf Coast

155

APPENDIX

1. Comments from Sasol Synfuels International Alasdair, Rudi & I have gone through the document and have looked over the various flow schemes that were included. We cannot give any non-confidential comments, apart from that you have obviously done a lot of work on the topic. On a detailed technical level, there are several of your assumptions and flowsheets that are not necessarily the same as ours, but we are not able to discuss these on a non-confidential basis, as this would disclose details of our process. We appreciate being given the opportunity to provide comments, and apologise that we are not able to provide any substantial feedback. Regards Cavan Hill Business Development Manager Sasol Synfuels International

Paul

156

2. Comments from Shell International Oil Products B.V.

Dear Alasdair. I read your draft report on Technology B: Shell MDS type FT synthesis & product upgrading with great interest. You will understand that for confidentiality reasons I will not comment in detail on your choices for SMDS process lay-out, process conditions, as well as performance of individual process steps. I realise that you made these choices in the best effort on basis of our non confidential information. Unfortunately the report does not reflect the current status of the SMDS process : over the last few years further advances in R&D plus the learning from the SMDS Bintulu plant has enabled a substantial improvement in the SMDS economics.

The SMDS process daily converts 100 MMSCF into 12,000 bbl liquid products ranging from middle distillates to solvents and paraffinic waxes (Ref. M.M.G. Senden, A.D. Punt, R. Ryan, "Gasto-Liquids processes: status and future prospects.", AIChE Spring National Meeting, March 14-18, 1999 in Houston). This compares with your daily 10 464 bbl for 100 MMSCF (see page 4 of your draft). From the liquid production / gas consumption ratio it follows that the Plant Thermal Efficiency of SMDS Bintulu is clearly higher than your quotation. The thermal efficiency is in the 60 - 65 % range depending on the specific mode of operation. In the same way the carbon efficiency of the plant should be increased to around 80 %. The specific capital costs of a GtL plant expressed as USD/daily barrel is very much dependent on the scale of operation. A GtL plant of a 100 MMSCF/day conversion capacity is considered by the leading companies in the GtL industry too small to produce FT fuels economically. A full FT middle distillate plant should at least have a capacity of 60,000 bbVday or more. This has a distinct impact on plant price and economics. Operational experience coupled with technological improvements has resulted for this scale of SMDS plants in specific capital costs well below 25,000 USD / daily barrel. This is to be compared with your 37,222 USD/daily barrel for a 100 MMSCFD plant.

I hope the comment above is of help to you to position the GtL Technology. I wish you success with the completion of the report. Yours sincerely. M.M.G.Senden GtL business group OGTS Shell Global Solutions Shell International Oil Products B.V.

157

3. Comments from Syntroleum Alasdair C. I. Heath Project Manager Bechtel National, Inc. 45 Fremont Street San Francisco, CA 94105-1895

Re: IEA Greenhouse Gas R&D Programme

Dear Mr. Heath,

Thank you for the opportunity to review the "Syntroleum F-T Technology" section prepared by Bechtel for the IEA Greenhouse Gas R&D Program study into FischerTropsch processes for the production transportation fuels. Bechtel is to be commended for the generally high quality of analysis.

Syntroleum has been asked to address the representation of its technology by Bechtel. Because of time and resource limitations, we can only respond with general comments and suggestions.

1. Bechtel assumes a fixed-bed FT reactor technology will be employed for fuels production.

Syntroleum and its partners do not consider fixed-bed technology to be a (capital) efficient means of fuels production. However, Syntroleum and ARCO (a Syntroleum licensee) are now demonstrating a nominal 70 barrel per day slurry reactor which is designed to provide data for commercial scale-up for economic fuels plants.

2. Our current designs have process trains in the nominal 10,000 bpd range. Technology for

single GTL trains to significantly exceed 15,000 barrel per day should be demonstrated by Syntroleum during the next three years.

3. The 115 bar hydrocracking conditions to produce fuels from the heavy synthetic oil (wax) of cobalt-based FT processes should be revisited. Unlike the "commercial" iron-based processes used today, cobalt-based processes yield synthetic oil that does not contain aromatics. This means far less severe conditions are required to accomplish the hydrocracking stop.

4. Not surprisingly Syntroleum, as a small company, questions the apparent high overhead imbedded in the Offsites Facilities and HO Service/Fees/Contingency portion of Area 500 in the capital cost summaries.

5. Do not ignore the likelihood that early GTL fuels production will concentrate on gas now flared and vented around the world in conjunction with oil production. Flared gas currently exceeds 11 billion cubic feet per day. The impact of this gas on the Bechtel analysis is two-fold. First, these GTL projects are likely to share infrastructure with oil production. Secondly, the carbon efficiency of the GTL conversion of natural gas that would otherwise be flared or vented natural gas is infinite.

6. Unlike conventional petroleum fuels and other energy delivery systems such a, LNG, cobalt-based GTL fuel production is in its infancy. Judging the medium and long term potential of GTL processes and economic efficiencies by using a 1998 technology snapshot is analogous to judging (a) LNG processes and economic efficiencies using a 1964 technology snapshot, or (b) conventional petroleum refining process efficiencies before the advent of FCC technology. Experience with operating GTL plants together with scale economics which can be obtained in larger train sizes will lower costs per unit capacity.

Should your study lead to follow-up work, either for the IEA or other Bechtel clients, please do not hesitate to call if we can be of assistance. Regards, Larry Weick Vice President, Business Development and Licensing

co2 abatement in gas-to-liquids plant: fischer-tropsch ... fischer tropsc… · i title: co2...

Documents