PETROCHEMICALS FROM OIL SANDS

Transcription

1 PETROCHEMICALS FROM OIL SANDS for ALBERTA ENERGY RESEARCH INSTITUTE NOVA CHEMICALS LTD. SHELL CHEMICALS CANADA SUNCOR ENERGY INC. by T. J. McCann and Associates Ltd. with Lenef Consulting (1994) Limited KemeX Engineering Services Ltd. SFA Pacific, Inc. Sigurdson & Associates July 2002

2 DISCLAIMER Except as specifically noted the calculations, conclusions and recommendations of this report are the sole responsibility of T. J. McCann and Associates Ltd. Advice, calculations and other assistance of Lenef Consulting (1994) Limited, KemeX Engineering Services Ltd., SFA Pacific, Inc. and Sigurdson & Associates has been incorporated herein as considered appropriate. The data, conclusions and recommendations may not concur with the opinions and/or policies of any of the sponsoring organizations. It is to be noted that the underlying data and assumptions in this report are often forecasts and/or estimates by the team and no guarantees are provided as to qualities of data or recommendations. Notices This report was prepared for the listed sponsors, who retain the sole rights to its distribution. However, as most assumptions drew on publicly available data/information, no specific proprietary technical rights of the sponsors are inherent in this report. Whenever specific licensors and/or processes are noted these are for illustration only, with no implied recommendations. - i

3 TABLE OF CONTENTS PAGE DISCLAIMER...i EXECUTIVE SUMMARY: CONCLUSIONS AND KEY MESSAGES...vii 1.0 INTRODUCTION General Objectives Approach Other Chemical Centers BASF et al Port Arthur, TX Expansion Project Examples Financial Analyses Bases Gas Oil Note Light Gas Oil FEEDSTOCKS Introduction Reference Prices Bitumen Supply Vacuum / Heavy Gas Oils Natural Gas Liquids Synthetic Gas Liquids Refinery Olefinic C 3 C 4 s Ethylene Plant C 3 Plus Streams Joffre Ethylene Plant Hydrogen CO 2 from Others Refinery Naphthas Feed Delivery Systems PRODUCTS Introduction Petrochemical Products Preamble Ethylene Propylene Benzene P-xylene Refined Products General British Columbia Gasoline C 4 Alkylate Jet Fuel Diesels Heavy Aromatics Naphthas Synthetic Crude Oils Hydrogen CO Specialties Synopsis Options Major Prospects Infrastructure Introduction Transport System Upgrading REFERENCE CASE Preamble Step A Introduction C 4 s Integration in Step A Caveat ii

4 4.6 Heavy Gas Oil Step B Introduction Petro FCC Heavy Gas Oil Hydrotreater Light Cycle Oil Recycle Aromatic Complex Integration of the Petro FCC and Aromatics Complex Miscellaneous Step B Additions Bitumen Processing Step C Introduction Conversion Conversion Product Hydrotreating Naphtha Kerosene Diesel #2 HGO Hydr3otreater Gasification Other Step C Additions Step D Fischer Tropsch Addition Hydrogen and CO Rebalancing Incremental Ethylene Option Propylene Aromatics Alkylate Diesel Naphtha Utility Systems Storage Systems ENVIRONMENTAL ISSUES Background Air Water Land Greenhouse Gas Issues Introduction Site Emissions Project Offsets More Work Needed! CO 2 Disposal Note Preliminary Economic Review OTHER PROCESSING OPTIONS Introduction Other Processing Options POSSIBLE DEVELOPMENT PROFILES Introduction Siting and Access General Corridors Specialty Products Notes Arctic Gas and More NGL s Timing Factors Different Order of Development? Preamble In Step A Expedite New C 2 C 3 C 4 Cracker Put Step B First Put Step C First Business Side Comments RESEARCH, DEVELOPMENT AND DEMONSTRATION Introduction Bitumen Supply Research & Development & Demonstration (R&D&D) Primary Upgrading Options Pyrolytic & Catalytic Approaches to Ethylene, Etc Integral Fluid Bed Cracking / Gasification Development Gas Separation Technologies Extractive Technologies Liquids iii

5 8.8 Further Derivatives Research & Development Aromatics Non-Aromatics CO 2 Notes Biological Processing Inorganics Research and Development and Demonstration Economics Notes Scale Up And Demonstration Introduction Demonstration Stage Lack of Large Pilot Units Here Training New Development Facilities Asian Cooperation A Thought Research and Development and Demonstration (R&D&D) in Summary SUMMARY Introduction Principal Products Feedstocks Basic Process Scheme Specialty Product Notes Balancing Petrochemical Monomer Supply/Demand Clues From Other Complexes Environmental Issues Greenhouse Gas Issues Basic A + B + C + D Yields Economics Research and Development and Demonstration(R&D&D) Conclusions CONCLUSIONS RECOMMENDATIONS Introduction Basic Step Activation Complex Siting and Regulatory Bases Coordination GLOSSARY REFERENCES ACKNOWLEDGEMENTS APPENDICES APPENDIX A APPENDIX B APPENDIX C APPENDIX D APPENDIX E TERMS OF REFERENCE COMPETITIVE AREAS KEMEX ETHYLENE PRODUCTION SFA PACIFIC GASIFICATION LENEF CONSULTING NATURAL GAS LIQUIDS - iv

6 LIST OF TABLES Table Chemical Cluster Overview...4 Table Atofina Feedstock Interfaces with Cracker and Metathesis Unit...7 Table C 4 (Sabina) Plant Ownership...7 Table Sabina Plant Capacities...7 Table Oil Sands to Petrochemicals Pricing Bases...10 Table Oilsands to Petrochemicals...16 Table Existing Ethylene Plant Byproducts...17 Table Local Connections...31 Table AIH/Strathcona Specific Interties...31 Table Staged Development Approach...32 Table Olefins Plant Ultimate Yields 10,000 units by weight per hour feed...36 Table Tentative Petro FCC Yields...40 Table Utility Concept Overview PRELIMINARY...51 Table Storage Systems PRELIMINARY...52 Table Principal Air Quality Issues Today...55 Table Air Quality Control in Proposed Core Facilities (a)...56 Table Overall Yields of Key Products...60 Table Very Preliminary Internal Rates of Return and Net Present Values...61 Table Capital Estimate - VERY PRELIMINARY Table Steps A, B and C Technical Expertise Need Overview...75 Table Stati of Process Development of Basic A, B, C, D Processes...77 Table R&D Specifics...78 Table Principal Product Yields...96 Table Preliminary A + B + C Economic Analyses...97 Table Comparison of Study Objectives...98 Table Technical Study Results...99 PAGE - v

7 LIST OF FIGURES Figure U.S. Steam Cracker Feed Stocks Year Figure New Venezuelan Heavy Crude to Texas Petrochemical Monomer Trail...6 Figure BASF Et Al New Port Arthur...8 Figure Air Liquide - USGC Pipeline...9 Figure Bitumen Outlook...13 Figure Envelope of Alberta Feed/Product Changes Development Considered in This Study...33 Figure Core Fitting...33 Figure New Feeds / New Products By Step...34 Figure Complex Product Additions by Step...34 Figure Initial Step C 2 and C 3 Processing Options...35 Figure SGL Block...36 Figure C 4 Complex...37 Figure Petro FCC Block...41 Figure Petro FCC Fluic Catalytic Cracking Unit...40 Figure Aromatic Complex...42 Figure Bitumen Processing Block...43 Figure Primary Upgrading Base...44 Figure Cetane Improvement Reactors...45 Figure Basic Overall Flow Diagram...46 Figure Air Quality Concerns...53 Figure Air Quality Concerns (Cont d)...53 Figure Air Quality Concerns (Cont d)...54 Figure Water...54 Figure Land...54 Figure Greenhouse Gas Life Cycles Estimates...58 Figure Major CO 2 Distribution Grid...70 Figure New Links to be Promoted...70 Figure 8.1-1A. Low Cost Conversion Options to be Explored...80 Figure 8.1-1B. Deasphalting...80 Figure D with Excess Coke Gasification...83 Figure New Venezuelan Heavy Crude To Texas Petrochemical Monomer Trail PAGE - vi

8 EXECUTIVE SUMMARY: CONCLUSIONS AND KEY MESSAGES Alberta's oil sands plants are an abundant source of petrochemical feedstocks, potentially capable of supporting new world-scale plants producing at least 1,000-KTA ethylene, 1,000-KTA propylene, 500- KTA benzene and 300-KTA para-xylene and other high-value-added derivatives. These products can be produced by integrating existing and new oil sands upgrading plants, refineries and petrochemical plants using proven technologies and emerging technologies that can be commercialized within the next 5 to 10 years. Technology gaps, requiring further research development and demonstration have been identified; strong Alberta based collaborative Research and Development and Demonstration support will be essential. Using Alberta Industrial Heartland's chemical complexes and infrastructure as a model, the study shows that a practical three-stage integration plan is both technically and economically feasible, assuming new product pipelines from Northern oil sands plants to Edmonton and from Edmonton to Vancouver. Key factors necessary for successful integration include commitment by different levels of government and industry to a common vision and a long-term strategic plan to facilitate profitable integration of the different complexes and infrastructure including land development. The roles that have to be played by the different parties for this province to maintain its Alberta Advantage ; in order to attract investors to the petrochemicals sector are: a) Industry: Co-ordination and collaboration amongst the different industry players to develop and integrate large complexes which would enjoy the economies of scale with efficient trading of feedstocks, products and intermediate streams. Substantial savings in capital and operating costs can be achieved by sharing utilities, infrastructure and process streams. Developing hubs by siting plants at strategic locations that lend themselves to utilization of available infrastructure and other facilities. b) Government: Facilitate the creation of hubs. Develop predictable and competitive regulatory and permitting processes to accelerate the development of industrial infrastructures in line with effective project management processes and/or practices; e.g., pipeline and utility corridors to and within the heartland industrial area. Aid in the co-ordination of the stakeholders (industries and different levels of government), especially with regards to the location of industrial complexes. Develop new fiscal regimes that will facilitate petrochemicals from oil sands, similar to synthetic crude oil, and more than competitive with U.S. Gulf Coast. It is imperative to act now for the following reasons: Limited supply of NGL feedstocks, which are inhibiting petrochemicals industry growth. Oil sands projects being planned in the absence of viable petrochemical options. Significant investments in petrochemicals being made outside Alberta (value chain loss). Value added oil sands investment (upgraders and refineries) being made outside Alberta (goal is to bring product value from $7 to $30 per barrel). This report identifies viable integration schemes for producing petrochemicals from oil sands, which if implemented, will lead to major long-term industrial development in Alberta and provide significant sustainable wealth to the province. - vii

9 Study Ins/Outs Feeds Bitumen Less than 10% of announced new bitumen production through Bitumen Derivative Light ethylene and heavier Suncor and Syncrude hydrocarbons (synthetic gas liquids SGL s) now burned in fuel gas streams (replaced in fuel gas with natural gas). Refinery and Petrochemical Byproducts Heavy distillates excess to synthetic crude oil (SCO) needs from various upgraders. Small propylene and xylene-rich streams (largely from SCO s) from refineries. Existing ethylene plant byproducts (now exported) and excess hydrogen (now in fuel gas) in exchange for natural gas. Some natural gas liquids (NGL s) butanes (just enough to balance needs of one process). 120,000-BPD (in 2010) 75,000-BPD (in 2008) 36,000-BPD (in 2008) 5,000-BPD 8,000-BPD+ 90 x 10 6 SCFD 8,000-BPD Central Integrated Process/Utility Complex In Redwater/Bruderheim/Fort Saskatchewan area A new key pipeline to carry gasoline, jet and diesel components, picking up existing refined and one petrochemical product in Edmonton, and then continuing on to Vancouver. Other lines would connect the oil sands area (SGL s) and Joffre and local plants to the complex. The new complex would be based on a new ethylene unit similar to the existing NGL ethane-based plants, but about half the ethylene from propane, the rest from SGL ethane. (Naphtha and gas oil/diesel cracking in a fully flexible feed unit did not appear economic and heavier gas oil was assumed catalytically cracked to petrochemicals.) The new complex would have other units similar to current Alberta refining units, except in two cases; a new version of one process would be used for environmental reasons, and in another the step-out would be petrochemical rather than refined product-oriented. Bitumen conversion would be new to Alberta routes, with residues converted (gasified) to gases, these in-turn largely converted to premium diesel. Products Petrochemicals Petrochemical products considered as the cornerstones were: Ethylene 25% more than present for added polyethylene, gylcols, Add 1,100,000 tonnes/year etc. Propylene World super scale for new Alberta polypropylene and other New 1,400,000 tonnes/year derivatives (all new to Alberta). Benzene 130% more than today for doubling current styrene Add 500,000 tonnes/year production, new phenol and/or other derivatives. Para-Xylene World super scale for Alberta PTA production (base for New 700,000 tonnes/year PET for bottles, fibers, etc.) New to Alberta. (Some of the p-xylene could be converted to benzene if appropriate.) Refined Products C 4 Alkylate High octane, very environmentally friendly gasoline component (Alberta, British Columbia and California markets). 1 Premium Jet Fuel and Diesels Other Products 1 2 Also very environmentally friendly (Alberta and British Columbia markets) 1 New 39,000-BPD New 45,000-BPD Naphthas Assumed routed to bitumen blending, but with alternates 25,000-BPD noted for conversion to more petrochemicals CO 2 To new CO 2 enhanced oil recovery. 30/35,000-BPD (More Alberta light crude) 2 Note new clean products line to Vancouver needed for marketing these products (and free up 90,000-BPD of added capacity for SCO sales to the Northwest U.S.). No value placed on CO 2 or added crude production in CO 2 EOR. - viii

10 1.0 INTRODUCTION 1.1 General This study set out to determine how, in the 2005 to 2020 period, at what margin new Alberta petrochemical monomers might be produced from bitumen as a starting point, recognizing potential synergies with refined products, naphthas (for bitumen dilution), synthetic crude oils, natural gas and natural gas liquids and with existing and currently planned Alberta industry. Identification of appropriate research and development needs to support such development. No specific new markets were identified for the key new petrochemical ethylene, propylene, benzene and para-xylene but one or more new world scale derivative producers were assumed in each case. Appendix A outlines the key requirements for this study as provided by the sponsor s leader Dr. D. du Plessis of the Alberta Energy Research Institute. As the study evolved, some telescoping was made of certain items in the terms of reference and some segregation occurred in other areas. This report is an amalgamation of the studies in all areas, largely in the context of an assumed development program to provide bases for analysis and, hence, not strictly following the original terms of reference staging. This study has been a team effort, as needed to cover the breadth and depth of industrial and infrastructure issues involved. The study effectively started in late January of 2002 and two sets of interim reports with related workshops. The sponsors also led two think tank sessions to aid the study steam and their own understanding of the prospects for marrying oil sands to petrochemicals, which were reported separately. 1.2 Objectives The study s primary objective was to define appropriate process concepts towards economic bitumen to petrochemicals in Alberta complete with related Research and Development and Demonstration needs, recognizing possible synergies with oil refining, bitumen upgraders, existing petrochemical industries, natural gas liquids, natural gas and their existing and potentially enhanced facilities. The bitumen resources of Alberta are essentially unlimited given a reasonable return on exploitation. However, new petrochemical monomer and derivative opportunities in Alberta may be more modest in proportion. As an example, an easy one million barrels a day of bitumen is equivalent to 60 x 10 6 tonnes a year and the new petrochemical targets assumed in this study were in the order of 3 to 4 x 10 6 tonnes a year (even with other products, the total would only be in the order of 10 x 10 6 tonnes a year). The individual minimum new petrochemical monomer targets correspond to a minimum of two world scale new derivative plants for each of ethylene, propylene and total aromatics. The time line was left open to some extent, but facility emphases were on the period through 2012/2015, but relevant research and development and demonstration needs through, say 2020, were essential outputs. While the original terms of reference discussed a flexible feed ethylene unit generally thought of as a unit with a naphtha/gas oil/c 3 /C 4 options that was not considered a specific constraint albeit a very logical approach given good economics. To the extent possible the study started without borders, other than suitable technologies and viable feedstocks and markets. The study did not consider synthetic crude oils as specific targets, although such could be default products if certain refined petroleum product and intermediates and/or naphtha markets did not materialize. Page 1

11 1.3 Approach A very iterative approach was taken once feeds and initial products were defined in preliminary terms to determine how an initial near-term commercial development might processed and what were the appropriate steps and processes and feeds and products. The study s results are open-ended as many questions are noted to be answered, as commercialization of these and/or related bitumen to derivatives schemes proceed and as Research and Development and Demonstration evolves to support such commercialization. The basic schemes used for analysis were largely for illustration, but considered sufficiently robust to develop a preliminary appreciation of the economics of the bitumen to petrochemicals cycle. In order to cover the breadth and depth of appropriate analysis a team was built up of very experienced specialists with a number of other specialists contributing in their own areas of expertise. A common site complete with major infrastructure was assumed a necessity for all new facilities, except those integral with existing operations. The Alberta s Industrial Heartland area Redwater to Bruderheim to Fort Saskatchewan was finally selected as an appropriate region in which a suitable section plus site would be available. However, the study s geographic envelope was extended from the oil sands area throughout Alberta and to the West Coast whenever there were perceived impacts. Feedstock and product availabilities or demands and related prices were estimated from semi detailed analysis for each. Minimum new petrochemical monomer demands were set sufficiently high to permit at least two new world scale derivative plants in the case of ethylene (1,000-KTA) and propylene (1,000- KTA) and one each for benzene (500-KTA) and para-xylene (300+KTA). Unlimited bitumen availability exists at the right price, hence, ultimate feedstock was never an issue, but its use was constrained to best suit the assumed new petrochemical monomer needs synthetic crude oil production was, the emphasis was on chemicals and refined products (and/or equivalent intermediates). In order to provide bases for further analysis an iterative approach was used to narrow to a three-step initial development profile building up from assumed short-term feedstocks to a formal bitumenprocessing step. No synthetic crude oil is seen as a primary product in the base scheme and to emphasize its chemical/refined product nature the last step is recognized the term Bitumen Processing throughout this report. However, naphtha blends were assumed marketable into bitumen diluent and/or ethylene production at a remote site. The original terms of reference contemplated naphtha, gas oil cracking, propane and butane in a flexible feed cracker, as is not uncommon in the USGC and similar to NovaChem s Corunna unit. This was not taken as a specific requirement/constraint in future bitumen to petrochemical complex (and predicted valuation indicated it unlikely, unless alternate product pricing changed). However, the study did explore alternates, as well as R&D&D that would be appropriate. For example, relative to heavy gas oils a variation of cracking with catalyst in a petrochemical fluid catalytic cracking unit became a proxy to heavy gas oil cracking as part of the base process scheme. The study also trended away from a conventional liquid fed naphtha gas oil cracker due to the high ethane and propane availabilities in the synthetic gas liquid schemes. A gas C 2 C 3 C 4 cracker and the Petro FCC became the proxy for the original flexible feed cracker. (Alternates are available to convert naphtha to C 2 C 3 C 4 s if added gas cracking is needed, but not in this study s modelling.) Perceived high values for diesel per se appeared to preclude cracking ethylene, etc. in the foreseeable future but requisite R&D was noted to be prepared in case of economic change. While future R&D&D will often be very process related, this study did not go into detailed process detail in any stage. The team selected processes with reasonably sound bases that appeared to fit a realistic development plan and then developed preliminary yield and cost bases for integration via mathematical models. Page 2

12 Process selections for the period through 2012 were of necessity from processes proven today, minor step-outs or in very advanced piloting/prototype stage of developments. The processes assumed in the basic development plan were all ones the team had high confidence in being successful in However, opportunities were noted for better processes for bitumen to chemicals and appropriate R&D&D for their commercialization by say 2020 defined in outline. However, the study found that many of the apparent keys to more optimum bitumen to petrochemical enhancement were related as to how best to mix and match available or about to be available processes and this even necessitated consideration of the odd old process, as well as out of Alberta market opportunities. A set of economic criteria were developed for evaluation of the basic scheme first to see if petrochemical monomers could be produced for transport south and then, more importantly, to see what Alberta Advantage could be maintained. 1.4 Other Chemical Centers What makes a truly viable vibrant regional chemical industry? Currently, Alberta s petrochemical industry has a very large ethane-based ethylene bias built on the province s natural gas base, with chlorine (from salt) and benzene the only other major feedstocks. Ethylene derivatives today are only one step away large bulk products. Polymer grade propylene derived from bitumen upgrading is just come on the market albeit at a low rate, with essentially no local users. Benzene via synthetic crude oils is the only other bitumen to petrochemical example. Alberta s chemical industry is very important in the provincial and national economies, but lacks the breadth of feedstocks and products and the inherent synergies of competitive areas, particularly the U.S. Gulf Coast (USGC). Table is a brief summary of a preliminary look at the USGC, Netherlands and Sarnia chemical clusters to see what makes them competitive. Appendix B provides more overview of these other areas vis a vis Alberta. However, the USGC and major Dutch clusters have much more breadth and depth in chemical production from monomer on to many specialty products. They also have many head offices or, as importantly today and corporate core activity head offices, not apparent here. Page 3

13 Chemical Industry in General Table Chemical Cluster Overview USGC HOLLAND SARNIA ALBERTA (AIH) Depth Mammoth High Small Shallow (Big Bulk/Simple) Breadth Mammoth Very High Fair Narrow Size Mammoth High Small Coming Core Activity Number Many! High Any? (Branches) Very few (Branch plants) Head Offices Transport Marine Very Significant More Significant Minor NEGATIVE IMAGE Rail Good (some problems re competitiveness) Fair Good Excellent (but some lack of competitiveness) Road Great Good Good Good (But long way to market) Pipeline Greatest Fair Fair Good Petrochemical Primary Great Competitive Good Fair Fair No/Small Markets Local Secondary Great Competitive Good Local Fair Distant! Markets Tertiary Great Competitive Good Local Distant More Distant! Feeds Oil Venezuelan / Mexican / World World (Marine) Long Pipeline OIL SANDS NGL s Super Competitive Marine Distant Fair Great Chemicals Super Competitive Great Competitive Some Very Narrow Range Synergies Support Major Major Fair Good (Bulk chemicals only) Joint Many, esp. non Core Some (Only Cogen) E 3 only one Ventures Other Pipeline Grids industrial gases, etc. plants close to Pipeline Grid (some) Only a few Not Great Minor agreeable/helpful neighbours Maint./ Great (non union) Fair/Poor Fair (Union) Fair/Good (Union) Constr. Climate WARM Good Good COLD!! People Many/in tune Many Some Some/too few? Living Fair/Good Fair Good/Fair (partly isolated) Great/Excellent Culture Capital Costs Chemical Industry Chemical Research BASE (High Environmental Protection Costs) CORE COMPETITIVE NON-CORE OPEN HIGH Above Base At/Base BUT OIL SANDS OVERRUNS KNOWN WORLDWIDE Core Competitive Low Little Competition Non-Core Competitive GREAT! GREAT Minor NovaChem Other? University? (Some) Note: Major USGC Synergies using Air Liquide Bayport Example and USGC Pipe Example. Scale factors are very important and have been a key portion of the Alberta Advantage. However, around the world the average new ethylene and derivative plant is close or equal to Alberta s current world leaders in size, especially when other than ethane feeds are factored in. Derivative plant sizes are also increasing worldwide for the bulk ethylene commodity derivatives typical of Alberta today. New smaller higher value-added plants are very common in the USGC and Europe, but almost entirely lacking here. Our scale factor advantages are shrinking. Alberta is a long way from major markets much farther than any other chemical cluster, and the only major cluster not having marine shipping. The USGC will continue the primary Alberta regional competitor, but as the Appendix B indicates it has much greater breadth in the available monomers and even more depth in the layers of chemical production beyond monomers. Page 4

14 The Houston area alone has about 11 times Alberta s ethylene production 45,000-KTA, from a range of feedstocks, but with ethylene per se largely from ethane as seen in Figure Except relative to ethane, the importance of other derivatives is apparent. Figure U.S. Steam Cracker Feed Stocks Year 2000 % 100 Total 1740 mb/d as % of C 2 = Gas oil 80 Naphtha n-butane 60 Propane 40 Ethane 20 0 Source: Lenef/Lippke [1] Competition is very major on the USGC at all levels of the chemical industry but in primary monomer production joint ventures are common. (All but two of the world s top 10 ethylene producers do not have ethylene production joint ventures or are themselves an amalgam of ethylene producers.) Where an intermediate does not have internal core market there is significant integration with local consumers. This adds to the competitive nature at levels up the value chain. New Port Arthur Texas area petrochemical ventures by BASF, Atofina and Shell are partly based on naphtha from Venezuelan hydrotreated synthetic crude oil and are of appreciable interest relative to this study and clues to Alberta development. (Various technical literature sources.) The Sarnia NovaChem ethylene plant/sunoco Sarnia refinery significant interties are also of interest with Alberta Synthetic Crude Oil as the refinery s feedstock. [2] Page 5

15 A paragraph from a BASF news release on their Port Arthur related developments is specially pertinent: Under BASF's Verbund concept, plants both use and provide materials simultaneously. Both the products as well as the by-products from one plant are processed further in other plants. This tight integration dramatically reduces waste and provides both economic and environmental benefits, consistent with the principles of sustainable development. [3] 1.5 BASF et al Port Arthur, TX Expansion Project Examples Figure New Venezuelan Heavy Crude to Texas Petrochemical Monomer Trail Zuata Very Heacy Crude Sincor Upgrader 8.50 o API Total FinaElf 47% PDVSA 38% Statoil 15% VENEZUELA Ship 32 o Premium SCO CARIBBEAN Port Arthur Ref inery Atofina 100% Aromatics Fuel Products Propy lene TE XA S World s Newest - Largest Naphtha Cracker BASF * 60% Atofina 40% Ethy lene Various Derivative units at various sites Other C4 s C4 s Other Products * Propy lene Atofina Poly propy lene BASF/Shell Poly propy lene (Basell) C4 Complex Shell 60% BASF 20% Atofina 20% Metathesis Unit BASF * 50%? Atofina 50%? Buty lenes Isooctane (to Gasoline) Butadiene * BASF emphasizes Verbund - total integration of f eeds/products into own or joint v enture operations. BASF Cracker The Port Arthur, TX naphtha cracker is a 60-40% joint venture with Atofina with a capacity of 920- KTA of ethylene and 550-KTA of propylene. The cracker is integrated with Atofina s 175,000-BPD refinery as well as with the Sabina Petrochemical butadiene complex. The $1 billion steam cracker based on naphtha is the first raw materials investment for Atofina in North America. The decision on a naphtha cracker was based on the better propylene yields (due to the addition in 2003 of a metathesis unit downstream of Sabina). With the C 4 s going to the Sabina joint venture and the aromatics moving to the Atofina refinery the project has a home for all the components out of the naphtha cracking process. The project ties into the 175,000 BPD Atofina refinery in Port Arthur, TX where benzene and xylenes are already produced (4,000-BPD and 7,000-BPD respectively). The refinery also Page 6

16 produces gasoline, jet fuel, propane and heavy fuel oil. A portion of this refinery s feedstock is hydrotreated synthetic crude oil from the Sincor Venezuelan very heavy crude upgrader. Table Atofina Feedstock Interfaces with Cracker and Metathesis Unit Plant Capacity (KTA) Notes Polypropylene, La Porte, TX 1,000 Largest PP plant in North America HD/LLDPE Polyethylene 400 On site Acrylic Acid (American Acryl), Bayport, TX 120 Joint Venture with Nippon Shokubai Atofina also has a polystyrene business, but buys some styrene on a merchant basis. However, its benzene capacity likely means that the firm has its aromatic stream tolled into styrene by a producer. BASF s participation in the project provides propylene for the Basell polypropylene plant (a joint venture with Shell) in Bayport, TX, as well as raw materials for its Freeport, TX, and Carville, TX plants. Material also could be made available from the cracker and the Sabina venture for BASF s BDO plant in Louisiana. As an example, BASF note ethylene plant feeds to a new alcohol plant, which in turn feeds a new neopentylglycol unit. Figure provided by Air Liquide illustrates just one company s extensive integration of their activities over many U.S. Gulf Coast petrochemical centers. Sabina Petrochemical LLC This is a new joint venture between Shell, BASF and Atofina to extract butadiene and make alkylate. The $200 million project will use BASF s technology for butadiene extraction, UOP s InAlk alkylation technology and be located between the BASF cracker and the new Atofina Cracker in Port Arthur, TX. The butadiene extraction unit will have a capacity of 408-KTA Alkylation capacity will be 300-KTA Sabinate, hydrotreated isobutylenediene a high isooctane gasoline-blending component, from the alkylation unit will be sold to Atofina and other refineries in the area. BASF will be the operator of the butadiene unit. 1 Table C 4 (Sabina) Plant Ownership Shell 60% BASF 25% Atofina 16% Table Sabina Plant Capacities Product Capacity (KTA) Butadiene 408 Propylene* (see below) 300 Alkylate 300 Butanes not available * 2003 with Metathesis Unit startup. The plant will get feedstocks from the two crackers and ship the butadiene product by pipeline to Shell in Deer Park, TX. Shell will be able to add to its butadiene business, while the other 1 This alkylate will be equivalent to the isooctane from Alberta EnviroFuels with an octane of 101+, compared to the 95/95 expected for the C 4 alkylate assumed produced in this study s new complex. Page 7

17 partners will get rid of their C 4 s Shell will provide 66% of the feedstocks with the other partners providing the balance. BASF/Atofina Metathesis Unit The C 4 project has a second phase of metathesis, planned for The butylenes and butanes from the Sabina project will go to metathesis, which will turn the butenes about 90-KTA of ethylene from the new cracker into an additional 300-KTA of propylene for Atofina and butanes for cracking or refinery use. Special Note BASF makes special attention to the Verbund principal of maximizing use internally or nearby of all byproducts. Figure BASF Et Al New Port Arthur? Many Other BASF Sites Atofina Naphtha Naphtha Cracker C 2 = C 3 = C 4 s Ethylene Propylene Metathesis? Other Users C 4 s Butanes (to cracking?) Butadiene Extraction Dimer ic 4 = H 2 Dimer HT Very High Octane Alkylate Butadiene Atofina BASF 40% Product to Atofina BASF Shell Atofina Joint Venture Page 8

18 Figure Air Liquide - USGC Pipeline The challenge here is to develop world scale quantities of new petrochemical monomers at below USGC costs to attract derivative producers with bulk on through high-value added products. Building petrochemical on an oil sands base has started and this study s role is to outline potential approaches to greatly enhance that relationship. The Verbund concept is what this study attempts to identify for bitumen to new petrochemicals in Alberta. 1.6 Financial Analyses Bases The preliminary fiscal bases are all in 2002 terms, generally in Canadian dollars or cents with U.S. costs in selected places. No escalation was assumed, but certain products and feeds pricing reflect the team s interpretation of future events and relationships. Throughout this study the Canadian dollar has been assumed at $0.65 in U.S. dollar terms. As a starting point economics have been assessed in 2002 bases; e.g., petrochemical products, 2 to 4 per pound below the U.S. Gulf Coast the assumed default value of surplus product in Alberta. A sensitivity analysis has been made to note the decline in returns, in the event further advantage was essential and another with higher future prices. The feedstock and product values assumed in this study is discussed below, but briefly summarized in Table All such costs are plant gate based, assuming existing Suncor and Syncrude (at plant sites), except for extraction of synthetic gas liquids, new plant facilities were at a central Fort Saskatchewan/Redwater area site. The Williams Energy SGL recovery and processing facilities were considered as purchased and integrated into the new system. Page 9

19 Table Oil Sands to Petrochemicals Pricing Bases User selected Pricing Structure (Enter 1 or 2) 1 Exchange Rate: 0.65 Cdn $ US $ Cdn $ US $ Cdn $ Base Base PC's $0.03 below Base PC's $0.03 below Base Stream Price Units Pricing in$/kt Pricing Pricing Price Price (as 1 2 applicable) Hydrogen $ 1.60 MSCF 664,044 $ 1.60 $1.04 $ 1.60 $1.04 Natural Gas $ 3.70 GJ $ 3.70 $2.41 $ 3.70 $2.41 Fuel Gas $ 3.50 GJ $ 3.50 $2.28 $ 3.50 $2.28 Ethane $ Bbl 263,179 $ $9.65 $ $9.65 Ethylene $ 0.34 pound 749,572 $ 0.29 $0.19 $ 0.26 $0.17 Propane $ Bbl 282,677 $ $14.79 $ $14.79 Propylene $ 0.34 pound 749,572 $ 0.29 $0.19 $ 0.25 $0.16 n-butane $ Bbl 264,253 $ $15.93 $ $15.93 i-butane $ Bbl 274,187 $ $15.93 $ $15.93 Field butanes $ Bbl 267,647 $ $15.93 $ $15.93 Diluent Naphtha $ Bbl 320,333 $ $22.75 $ $22.75 C 4 Alkylate $ Bbl 407,766 $ $29.90 $ $29.90 Refy Naphtha $ Bbl 220,462 $ $22.75 $ $22.75 Distillate Diesel $ Bbl $ $28.60 $ $28.60 Fuel Oil $ Bbl $ $14.63 $ $14.63 Benzene $ Bbl 547,376 $ $39.91 $ $30.68 p-xylene $ 0.37 pound 804,687 $ 0.32 $0.20 $ 0.27 $0.17 VGO $ Bbl 160,589 $ $16.25 $ $16.25 Bitumen $ Bbl 93,683 $ $9.75 $ $9.75 SCO $ Bbl $ $22.75 $ $22.75 Fuel to Repl SGLs $ 4.00 GJ $ 4.00 $2.60 $ 4.00 $2.60 Sulphur $ (5.00) tonne $ (5.00) -$3.25 $ (5.00) -$3.25 Electricity $ 0.05 kwh $ 0.05 $0.03 $ 0.05 $0.03 Hvy Aromatics $ Bbl $ $14.63 $ Other Feedstocks Price Units Price Cracker C 3 Stream $ 0.14 pound 308,647 $ per Bbl $ 0.14 $0.09 $ 0.14 $0.09 Cracker C 4 Stream $ 0.12 pound 264,555 $ per Bbl $ 0.12 $0.08 $ 0.12 $0.08 Cracker C 5 Stream $ 0.10 pound 220,462 $ per Bbl $ 0.10 $0.07 $ 0.10 $0.07 Cracker Bnz Stream $ 0.12 pound 264,555 $ 0.12 $0.08 $ 0.12 $0.08 Cracker TX Stream $ 0.11 pound 242,509 $ 0.11 $0.07 $ 0.11 $0.07 Cracker Fuel Oil Stream $ 0.07 pound 143,300 $ 0.07 $0.04 $ 0.07 $0.04 Refinery C 3 Stream $ 0.13 pound 286,601 $ per Bbl $ 0.13 $0.08 $ 0.13 $0.08 Cracker Butadienes $ 0.12 pound 264,555 $ per Bbl $ 0.12 $0.08 $ 0.12 $0.08 Cracker H 2 Stream $ 1.50 MSCF 622,542 $ 1.50 $0.98 $ 1.50 $0.98 Refinery Xylene $ Bbl 339,117 $ $30.55 $ $30.55 Petrochemicals Price $0.02 to $0.04 U.S. below USGC May/June contract closings to allow shipment from Alberta to USGC. Very preliminary capital costs were based on U.S. Gulf Coast costs. The new core facilities were assumed to have sufficient onsite electricity to meet internal needs, but electricity purchases would be needed at SGL extraction sites. New pipeline and other offsite infrastructure were assumed available by others as required but their costs netted out of the plant gate prices wherever appropriate. Net present value and internal rate of return calculations used the following bases: Income Tax - 29% (as anticipated in 2007) [4] Capital Cost Allowance - 29% Page 10

20 Project Life - 25 years Discount Factor (NPV) - 8% Discussions with petrochemical companies indicated their forward planning assumes capital costs at or below those of USGC (after Canadian/U.S. dollar adjustment). This is consistent with most prior major Alberta petrochemical projects. Normal project approaches and locations differ markedly between the petrochemical industry and those recent/current oil sands related projects (with high cost overruns). The study team s own experiences support the petrochemical industry views at/below USGC. 1.7 Gas Oil Note Light Gas Oil Throughout this report refers to hydrocarbon distillates in the jet and diesel boiling ranges. Due to the nature of bitumen the raw distillates from bitumen per se or from a bitumen conversion step range, say 175 to 375 o C, must be deeply hydrotreated for many use here, assumed, at least to jet fuel and diesel market qualities. At such quality levels it can be assumed that such light gas oil is suitable for cracking to ethylene assuming economics are formulae, given a yield similar to that in table of Appendix C. The possible high fuel oil yield of (light) gas oil is to be noted a difficult product in this setting with very little heavy fuel oil markets, the default uses being added gasifier feed and the economic bases of this particular study indicated little likelihood here of light gas oil (jet and/or diesel) cracking such cracking would require a liquids oriented recovery system not now foreseen. Heavy gas oil refers to bitumen derived distillates boiling above diesel say 375 to 975 o C. Again, to the low qualities from various sources such heavy gas with (HGO sometimes referred to a VGO vacuum gas oil due to its recovery in a vacuum distillation unit) must be deeply hydrogenated before any use to remove sulphur, nitrogen, oxygen, and to saturate and crack aromatic ring structures. After such hydrogenation it would be possible to conventionally crack such hydrotreated heavy gas oils and it is being done in the U.S. But even there it is likely more hydrogen addition may be needed than assumed here for a Petro FCC essentially steam cracking over a catalyst at milder conditions, to emphasize propylene and aromatics. The term gas oil in the ethylene industry usually refers to light gas oil jet / diesel boiling range material. Thus, whenever the reader sees jet or diesel he can interpret the stream s qualities to be equivalent to the gas oil from normally used in the ethylene industry. Page 11

21 2.0 FEEDSTOCKS 2.1 Introduction This section discusses the principal feedstocks that might be used in the new bitumen to petrochemical system. A dollar exchange rate of $0.65 has been used throughout this study. 2.2 Reference Prices a) WTI Crude A $24.00 U.S. per barrel WTI basis has been assumed in this study. This equates to a par Edmonton light sweet crude price of $35.00, after $2.00 Canadian transport debit. These bases have been developed from review of a wide variety of forecasts, but significant ranges between forecasts are to be noted. b) Natural Gas Throughout this study $3.75 Canadian per GJ (higher heating value) has been used. No debits have been estimated for deliveries upstream of AECCO. Where trades for SGL s and hydrogen are made they have been done in lower heating value units and then converted to higher heating value cost bases. Natural gas supply was assumed long relative to Alberta demands. Electricity requirements were assessed at $0.05 per kwh, but only applicable in the north as the new complex was assumed in electrical balance. 2.3 Bitumen Supply a) Availability The bitumen resource is essentially infinite; the challenge is to find markets providing acceptable production economics. Figure is a slightly out-of-date listing of project new bitumen production by various companies. [5] Aside from use as feed to upgrading and to chemicals as in this study there appears to be limited new market potential opportunities. However, at the same time, field trials are providing data on newer production technologies and confirming the exact locations of the resources. This study has generally considered in-situ produced bitumens, but partially deasphalted bitumens would be better feeds technically and economically, except perhaps for price at the new complex site. It appears likely that typical SAGD operations will be low pressure with about 70% of the thermal needs of current high pressure operations, but with the gas over bitumen issues also a major driver towards lower pressure operation. At time of writing, no firm conclusions were possible relative to solvent or other new low energy production costs figure. Page 12

22 000 b/day bitumen 1500 Figure Bitumen Outlook CNRL 300 Shell 145 Black Rock 30 PetroVera True North -Phase2 95 Conoco-Phillips 100 Encana (CL-3) 30 CNRL 90 AEC 100 Encana (CL-2) 30 JCOS 50 True North -Phase 1 95 Anadarko 60 Husky/I.O. 20 Synenco 50 Rio Alto 30 Encana (CL-1) 10 Deer Creek 30 CNRL 115 ( Brintnell/Primrose/Wabasca) Market Limit about here. 0 ~ 300 Current Year Note Heavy crude to be added to above - Alberta and Saskatchewan. Wonder What can we do with 1,000,000-BPD of more bitumen? b) Pricing Conventional Bitumen Extensive discussions in the extended team among specialists involved in current SAGD development indicated that a at field netback of $13 Canadian per barrel would probably attract the 120,000-BPD Athabasca type of bitumens assumed in Case C. A transportation cost of $2 per barrel was assumed resulting in cost delivered to the core site of $15 Canadian per barrel. [5] The transport cost has assumed hot pipeline delivery to the core site; hence, no diluent recovery charges have been included. It is suggested that the core project would buy bitumen at a set rate on a long-term contract basis. The producer s gas price would probably be fixed in some manner to remove that variable on his end e.g., the buyer would deduct $3.00 Canadian per barrel of bitumen for his supply of, say, 800-SCF of gas per barrel of bitumen, with the gains from reduced usage accruing to the producer. There will be contracted supply contract negotiations in any case and it is likely that most SAGD/equivalent producers would only commit a certain portion of their production to this project. Partially Deasphalted Bitumens The study used only conventional Athabasca bitumen in its basic analyses. However, due to the major impact deasphalting in the field would have re the bitumen to chemical complex, capital Page 13

23 and operating costs. Retention of more or less asphaltenes (and mineral fines) in the field is strongly recommended. Such approaches reduce the amount of bitumen needed for given valuable product generation and save money in pipelining to the site. The asphaltenes that can be left in the ground would almost entirely go to very expensive gasification. Capital costs appear slightly higher for partially deasphalted bitumen from mining operations, but operating costs per barrel of usable product are no more. (As noted above, this study did not analyze in-situ technologies that can provide partially deasphalting.) Partially deasphalted bitumen would receive a price about as follows: Basic Bitumen Price 100 Asphaltenes % Removed + $0.50+ per barrel premium partially deasphalted bitumen value The premium would have to be worked out for each source perhaps on a weekly basis due to variations in bitumen qualities, especially in mining ventures. 2.4 Vacuum / Heavy Gas Oils a) Availability The study estimated that at least 4% of the 700,000-BPD projected for 2007 could be released as unhydrotreated vacuum gas oil (virgin) or heavy gas oil (cracked). This relates to adjustment of the SCO fractional yields to better suit refiners, added diesel for mining and sales and the neutral value of VGO s when unhydrotreated distillates are used as diluent for certain bitumen (largely to Flint Hills Pine Bend refinery). At the same time, the study assumed the ability to trade 6,000-BPD of heavy aromatic streams with one or both Fort Saskatchewan/Edmonton residual hydro-refining units (LC Finer) for an equal volume of virgin vacuum gas oils or equivalent. b) Pricing A brief simple LP run noted above indicated a value in Chicago area FCC oriented refining of very roughly 70% of Edmonton par for hydrotreated upgrader gas oils say $25.00 Canadian per barrel. Allowing an arbitrary $2.50 for hydrotreating provided a value of $22.50 (64% of Edmonton par) for raw VGO/HGO feed to this project. This estimate is under that provided by one sponsor, but the need for much better definition (and negotiation) is recognized. Long-term purchases should draw some credit, but a $25.00 figure has been assumed in the fiscal calculations. 2.5 Natural Gas Liquids Appendix B discusses this study s reviews of natural gas liquid availabilities and pricing in the future largely based on studies by others. (Relevant references are noted in that Appendix.) a) Ethane This study generally assumed NGL ethane available to fill nameplate capacity of the existing ethylene units, but without any surplus for a new user. (Potentials for merging Canadian arctic gas and especially its NGL s into the new systems discussed here is noted later.) Page 14

24 b) Propane The major propane content in the synthetic gas liquids is noted in the next subsection. There was some concern that putting 30,000-BPD on the market would upset pricing (although it may only back USGC imports), but use of that propane in the new facilities was assumed. Purchase of 30,000-BPD NGL propane is considered in a sensitivity case as an add-on to bring a new C 2 C 3 cracker to world scale. Pricing was of obvious concern, in such a case, especially at the estimated average of 65% of Edmonton par - $22.75 Canadian per barrel at $0.65 exchange and $24.00 WTI. c) Pentanes Plus As the Appendix E notes it was assumed that most pentanes plus would continue to go to bitumen dilution at roughly Edmonton par crude prices. Some added room for naphthas in the diluent pool was assumed. However, these may be weak assumptions the study later notes a variety of options for naphtha conversion to C 3, C 4 and aromatics in the event of falling diluent pool demands/prices and certain very paraffinic naphthas are assumed routed to (offsite) ethylene production in the first instance. 2.6 Synthetic Gas Liquids a) Availabilities While the study examined a variety of scenarios, C 2 = plus recoveries from Suncor and Syncrude olefin-rich fuel gas streams were assumed for analysis as in Table These data are based on published data relative to the Williams Energy SGL recovery project at Suncor ratioed up by 50% to the 330,000-BPD SCO rate predicted for 2007 and on a set of Syncrude 2007 fuel gas compositions provided by Syncrude matching a 370,000-BPD production rate. [6] [7] Page 15

25 Table Oil Sands to Petrochemicals Case Title Base Case Production Basis Recovery Syncrude BPCD C 2 + Suncor BPCD C 2 + Totals BPCD Total Production of SGL Components Component Annual KTA BPD CH 4 METHANE C 2 H 6 ETHANE ,697 C 2 H 4 ETHYLENE ,881 C 3 H 8 PROPANE ,999 C 3 H 6 PROPYLENE ,344 n-c 4 H 10 n-butane ,958 i-c 4 H 10 i-butane ,503 C 4 H 8 BUTYLENE ,904 n-c 5 H 12 n-pentane ,139 i-c 5 H 12 i-pentane C 6 H 14 n-hexane ,085 C 7 H 16 n-heptane H 2 S HYDROGEN SULFIDE H 2 HYDROGEN N 2 NITROGEN H 2 O WATER CO CARBON MONOXIDE CO 2 CARBON DIOXIDE COS CARBONYL SULFIDE CH 3 SH METHYL MERCAPTAN C 2 H 5 SH ETHYL MERCAPTAN C 4 H 6 BUTADIENE Totals ,740 Note: Data subject to change treat as preliminary At one stage, CNRL s first 114,000-BPD stage (2007) delayed coking related SGL s were considered, but only C 3 plus, recovery would appear economic. Due to concerns about the 2007 date and the need for a small pipeline it was decided to forego that SGL to future studies probably until the full 233,000-BPD would come on-stream in 2011, with full C 2 plus SGL potential. The Husky Lloydminster upgrader has some olefinic C 3 C 4 that could be recovered, but uncertainty about expansion plans and the need for rail delivery also deferred consideration. Page 16

26 b) Value The SGL s were assumed purchased at replacement natural gas prices plus a 7% premium to cover the capture of the SGL s and subsequent processing. 2.7 Refinery Olefinic C 3 C 4 s Regina Coop / New Grade Upgrader C 3 C 4 s largely from catalytic cracking were not considered, but should be considered in future studies, traded for C 4 alkylate (much preferable) to their present use to produce poly gasoline. However, at least one Edmonton refinery would like to increase the C 4 content of its alkylation feed and would have in order of 4,000-BPD of a 70% propylene, 30% propane mix available. This would require a fractionator, but the higher octane of the C 4 enhanced alkylate over the present C 3 C 4 alkylate would provide significant economic incentives. This mixed C 3 stream was arbitrarily valued at $23.50 Canadian per barrel. 2.8 Ethylene Plant C 3 Plus Streams A very arbitrary $0.12 Canadian per pound price was assigned to all C 3 plus from existing plants, with this study s very preliminary estimate of availability shown in Table Table Existing Ethylene Plant Byproducts (KTA) (a) (b) Ethylene Production Assumed 4,000 C 3 s C 3 = 120 C 3 20 Other (Dienes) 10 TOTAL 150 C 4 s C 4 = 120 C 4 s 20 Butadiene Neglected TOTAL 140 Aromatic Concentrate Benzene 100 TX 30 C 5 s 30 Others 10 TOTAL 170 Heavy Fuel Oil C 9 Plus 20 Notes: (a) Based on typical C 2 cracking yields estimated by KemeX. (b) It is recognized that different units will have different byproduct streams with differing composition. Page 17

27 It is recognized that both availabilities and pricing are preliminary and much negotiation needed before further studies. The lead times before availabilities due to existing contracts may be of importance in such negotiations. 2.9 Joffre Ethylene Plant Hydrogen While E1 and E2 hydrogen byproducts normally go to Agrium s Joffre plant (for ammonia) E3 hydrogen appears largely used in the NovaChem fuel gas system. This study assumed purchase of 90 x SCFD of hydrogen in the 90% hydrogen-rich stream replacement natural gas cost (lower heating value exchange) with a small premium $1.50 per MSCF. [8] (Use of this hydrogen obviates the need for steam methane reforming in an intermediate stage of complex development and provides a sound backup to gasification hydrogen in the fully developed complex and as noted later, greatly aids premium distillate product yield.) CO 2 from Others This study did more than note the very major potential to use the new complex site as a collection / distribution center for new CO 2 use / disposal schemes Refinery Naphthas The prior aromatic study identified potential for a new refinery unit to convert naphthas to aromatics. This potential continues, but was not incorporated into this study s basic thinking an add-on with 20,000 to 30,000-BPD of naphtha potentially available Feed Delivery Systems Due to the large volume, the SGL s will require a new pipeline from Tar Island to the new core facility site this will free up space now used for C 3 plus SGL s in the present Suncor SCO line for added SCO and/or SCO components. From Joffre a small C 3 plus pipeline will be needed paralleling a new line to carry the raw hydrogen north to the core site. Hopefully, some added materials will be found to fill up the liquid line. CO 2 could be added to the hydrogen line from Joffre and the new SGL line from the north, with extraction at the new complex site (where some CO 2 extraction from or to SGL s is needed in any case). Most other feedstocks will be received via short local pipelines. 2 Up to 60 x 106SCFU of other hydrogenation use currently available on short notice near the proposed complex site. Page 18

28 3.0 PRODUCTS 3.1 Introduction This section considers the principal anticipated products from bitumen to petrochemical complex such as discussed in the next section of this report. The major potential is discussed here with demands for each followed by pricing assumptions. Both demands and pricing assumptions must be considered very preliminary. Minimum new petrochemical monomer demands have been assumed to match 1 or 2 new world scale derivative plants and other potential product demands have been set at maximum levels for analysis to keep control of facility size and concepts. The demand and pricing bases are generally considered conservative in the case of petrochemicals base (default) values allowed export to the USGC have been assumed as cost bases (with later analysis to see if even lower pricing is realistic), but the potential for higher prices is also considered. The key petrochemicals ethylene, propylene, benzene and p-xylene are discussed first, as the raison d être for a new bitumen to chemicals complex. Refined petroleum products include C 4 alkylate, and naphthas in general, in addition to gasoline (not a core product), jet fuel and diesels. Synthetic crude oils are not planned, but could be produced. Large quantities of hydrogen will be available in the base scheme, as will CO 2 and heavy aromatic fractions, but much of the surplus hydrogen is reacted with carbon monoxide to premium distillates in a later stage of development. Brief notes follow re possible specialty products. 3.2 Petrochemical Products Preamble This section reviews assumed prices for ethylene, propylene, benzene and para-xylene. Minimum demand targets are noted, but without any detailed end use analysis. However, the targeted production rates reflect bulk derivative world scale derivative plant sizes. This study did not attempt a major analysis of 2010/2020 petrochemical prices, but rather assumed current patterns would continue. The basic (default) prices for petrochemicals used as a base through this study are $0.04 U.S. ($0.02 in case of benzene and p-xylene) below May-June 2002 USGC contract prices as reported in Chemical Week. This discount allows for transport to the USGC and a small marketing penalty if new Alberta derivative demands do not develop Ethylene a) Demands An arbitrary minimum demand of 1000-KTA was assumed for new ethylene production defined as ethylene recovered and/or produced in the suggested new facilities. Potential outlets for this new ethylene roughly 25% above current Alberta production were not analyzed in this study. However, expansion of existing polyethylene units and possibly ethylene glycol and olefin units can be envisaged with some needed for new styrene and copolymer polypropylene production. Page 19

29 b) Pricing May 2002 U.S. Gulf Coast contract ethylene prices were at $ U.S. per pound, up from late 2001/early 2002 lows of about $0.20 U.S. per pound. [9] The study team anticipates that this price will firm even more over the next 3 to 5 years, but pricing beyond, say, 2007 is largely guessing. The USGC $ U.S. per pound base has been assumed herein. A base Alberta value would be about $0.04 U.S. per pound less, say two for freight differential and two for marketing costs. At $0.65 Canadian per U.S. dollar exchange, the $0.20 U.S. per pound basic value would be $0.29 Canadian per pound ($0.64 Canadian per kg). Note that LNG imports are forecast to stabilize USGC and other natural gas prices so that the future may not see the savings in ethane prices seen in the last three years. Thus, USGC ethylene price changes would appear likely to reflect mostly value-added changes in the future. CMAI has predicted those to rise to 2006/2007 to beyond the spread needed for new capacity. [10] Propylene a) Demands Currently, under 100-KTA of polymer, grade propylene is being produced by Williams Energy from Suncor C 3 plus SGL s, but sold into U.S. markets as there is no significant Alberta demand. An arbitrary minimum demand of 1,000-KTA was assumed as essential from the new facilities and the existing Williams Energy facilities, assumed as part of the new facilities in this study. This study did not investigate/rank Alberta prospects for this propylene, but above it is noted that the Atofina polypropylene unit receiving part of its feed from the new Port Arthur Texas BASF/Atofina with Shell Port Arthur is at a 1,000-KTA scale. Polypropylene is an obvious prospect for new Alberta propylene in a variety of homo and copolymer and even actactic grades. Propylene oxide is seen as another good prospect, most likely coproduced with styrene in an SMPO (POSM) unit. (Smaller-scale propylene oxide production via hydrogen peroxide and propylene via BASF or Degussa technologies should not be ruled out.) Phenol is the significant petrochemical import into western Canada for resins for various wood fiber products. While phenol currently appears in over supply generally, low-cost Alberta production would likely find homes in western Canada and the U.S. northwest. Conventional phenol production proceeds via cumene propylene and benzene with acetone byproduct. (The latter can be hydrogenated to isopropyl alcohol or even all the way back to propylene if hydrogen is cheap and acetone is not needed as for bisphenol-a.) A direct benzene oxidation route to phenol appears available, but the process selection will be made by the prospective producer to best suit his own corporate drives. Acryonitrile, using already available ammonia, is also seen as having good prospects. b) Pricing While May 2002 USGC contract price was at the $ U.S. per pound for polymer grade propylene the study believes there will be continuing firming with prices approaching those for ethylene. However, some derivatives can use chemical grade propylene (roughly $0.015 U.S. per pound below polymer grade). In other cases, a polymer grade price may be received, but with some reprocessing of off gases from, say, a polypropylene plant. Page 20

30 For this study, a price of $0.18 U.S. per pound was set, as well as a $0.03 U.S. per pound transport penalty assuming a $0.21 U.S. per pound USGC polygrade starting point. This 0.18 figure translates to a base value of $0.29 Canadian per pound ($0.644 per kg) Benzene a) Demands The prior aromatic study indicated good prospects for expansion of the existing styrene plant and more importantly, for a new styrene plant quite likely coproducing propylene oxide. The benzene demands for one major new styrene plant and modest expansion at the existing plant would be at least 500-KTA of benzene and that was set as a minimum target for this study. However, as noted above, phenol also appears, at least, a fair prospect for new benzene. b) Pricing The June 2002 USGC contract pricing was at $1.32 U.S. per U.S. gallon, up significantly from lows in the $0.60 to $0.70 range in late 2001 early This study assumed a more conservative $1.10 U.S. per U.S. gallon as a starting point - $0.149 U.S. per pound. Again, a freight plus marketing charge penalty was applied to arrive at base Alberta prices a discount of $0.02 U.S. per pound to give a base value of $0.95 U.S. per U.S. gallon ($0.20 Canadian per pound) or $1.46 Canadian per U.S. gallon - $61.40 Canadian per barrel. (The reader should apply his own USGC forecast and discount needed to develop his new Alberta benzene derivative operation.) P-xylene a) Demands A world scale purified terephthalic acid plant will need in the order of 300-KTA of p-xylene and that was assumed as a minimum production rate in this study. b) Pricing A very conservative USGC price of $0.225 U.S. per pound was assumed, based on May/June 2002 contract pricing. This was discounted by $0.02 U.S. per pound to arrive at a default price for supply from a new Alberta source - $0.315 Canadian per pound. c) Note re Possible Excess Xylenes Xylenes can be hydrodealkylated to benzene (as a last resort) with a 30% weight loss (and to a less valuable product, but with appreciable fuel gas byproduct offset part of the weight loss. This route may be necessary to balance benzene/p-xylene demands). (Such a route avoids much of the capital and operating costs to convert mixed xylenes to para-xylenes but this study did not attempt an economic analysis of this option.] 3.3 Refined Products General British Columbia Currently, Alberta gasolines, jet fuel and diesel going to interior and coastal British Columbia markets are moved in batches in the TransMountain pipeline. Also, Alberta EnviroFuel s isooctane (MTBE in past) is Page 21

31 also batched to Burnaby. On the way there they pickup sulphur and other deleterious compounds from crudes also moved in the same pipeline, necessitating treatment and in some cases distillation at the British Columbia end and additional additives. A new clean product pipeline to Vancouver appears economically attractive if only to avoid the reprocessing of Alberta gasolines, jet fuel and diesels and Alberta EnviroFuels isooctane. TransMountain has advised Environment Canada that rail and truck movement of such refined products may be essential in 2007, when gasoline sulphur specifications move down to 30-ppm (from an average of say 300) and diesel to 15 at the car say, 10 at product terminal from 500. [11] Such a new line could/should be built sufficiently large to permit moving additional fuel and diesel to allow the shutdown the Burnaby Chevron refinery smaller older refinery in a very environmentally challenging setting. Aside from the current isooctane, added clean petrochemical products could also be considered. Shutting down of that refinery would eliminate some SCO and probably pentanes plus sales. The freed up space in the existing pipeline would permit movement of that SCO and another 75,000 plus BPD to Washington State refineries. This study assumed that in order of 50,000-BPD of gasoline and diesel sales potential would develop due to shutdown of the Burnaby refinery. Another 9,000 or so BPD could also develop from the likely shutdown of the small Husky Prince George refinery. Jet fuel is now imported into Vancouver via TransMountain and/or Imperial docks for use at the airport. Recently, a blip occurred in British Columbia gasoline and diesel exports one or two cargoes to Alaska, (which has said it may have to rely on Canadian low sulphur diesel after 2006, as its own refineries will be unable to economically meet the new standards). The West Coast has a gasoline to jet plus diesel sales ratio well above the 1/1 of Prairie Canada and the neighbouring Rocky Mountain (PADD IV) states. However, it is expected that the ratio will continue to fall, due to new CAFE number equivalent and consideration of SUV s as cars, at least in California. Hybrid cars will lower gasoline demands. While seldom noted in the literature, a European like move to diesels in small cars could well develop with CO 2 per car similar to hybrids and possibly less expensive such a move would accelerate with availability of 50-cetane diesel, as assumed needed in this study up from the current 40 specification. 3 The new Syncrude middle distillate hydrocracker will produce a 45-cetane product from poorer feed than as seen in this study, thus, 50 is not unreasonable bitumen feeds. [12] Aside, from Alaska and Washington State (and California for alkylate only), U.S. potential markets for Canadian refined products are not seen as changing much over the next 20 years continuing with mostly diesel to U.S. northern tier railways (10,000-BPD in April 2002) and trucking (5,000-BPD) with a small amount of gasoline. (Chevron s small export of heavy fuel oil would cease.) The nearest U.S. states have small populations and 1 or 2 extra refineries, and new market prospects are low. (One Billings s refinery was for sale due to the Phillips/Conoco merger at time of writing.) U.S. midwest markets are hard to reach pipeline needed to jump from Enbridge to a (small) BP product line and almost immediately Alberta products would be competing with large, very efficient, Canadian crude/bitumen based Minneapolis refineries Gasoline Gasoline is seen only as an optional product from the initial complex, but could be produced by blending alkylate, various naphthas and butane poor mileage, but very excellent in all other regards, especially 3 A recent J.D. Power U.S. survey indicated 31% of respondents would consider clear diesel cars, but few know what be available of the excellent nature of such cars in Europe. [A 50-cetane diesel is probably needed for such small diesels as common in Europe.] Page 22

32 for regions such as Vancouver, with smog issues. (Also, this would be a fuel that could be used in future fuel cell vehicles with onboard reformers.) No increase in Alberta product orbit gasoline demand is foreseen, with decreases after Thus, only the potential Chevron and Husky shutdowns are of significance say 30,000-BPD of new gasoline markets. Review of refinery margins over feed and crude costs indicates U.S. West Coast (and Canadian prairie) refineries generally enjoy much higher margins than do U.S. Gulf Coast refineries the ones with margins regularly estimated in the trader press. However, this study assumed a conservative addition of $9.00 Canadian for gasoline 126% over Edmonton par crude $44.00 per barrel netback C 4 Alkylate In this study C 4 alkylate is considered a refined product, as it can effectively replace most gasoline components other than butane. At the same time, very low gum forming potential, no aromatics, no olefins, and an almost ideal derivability index all very environmentally friendly minimal smog and low CO 2 per kilometer. However, C 4 alkylate will lose 3 to 4% in mileage per unit volume due to its low density, and some additive may be needed to insure gaskets and similar non-metallic fuel system elements swell appropriately in a non-aromatic fuel. It is to be noted that this C 4 alkylate will have lower octane 95 R + M compared to the R + M of isooctane of produced by Alberta EnviroFuels and in 2003 by 2 BASF/Atofina in Port Arthur. However, like the isooctane, the C 4 alkylate is seen as having major West Coast markets. In Alberta and British Columbia C 4 alkylate is seen as gasoline blending stock being traded for xylenes (for further processing to p-xylene) and refinery C 3 blends (for propylene and via cracking added ethylene), and perhaps naphthas (for incremental aromatics and possibly ethylene and propylene) and heavy gas oils. 4 The study has assumed essentially open markets for C 4 alkylate and an octane premium of $0.20 per octane number barrel over that of gasoline say $1.00 Canadian over Edmonton par crude - $45.00 per barrel Jet Fuel The Vancouver jet fuel market would appear to have a potential of at least 10,000-BPD backing out imports. Other prospective markets were assumed already satisfied. However, this study generally lumped jet fuel with diesel for analysis, although it should draw a premium of $1.00 to $2.00 Canadian per barrel over diesel Diesels Incremental British Columbia markets for diesel was estimated at 30,000-BPD assuming both Chevron and Husky refinery shutdowns. This study generally assumed in-situ derived bitumen and, hence, no related incremental diesel needs as with mining ventures. 4 As noted later a high alkylate gasoline blend would also appear of environmental interests in the Edmonton area. Page 23

33 There will likely be some growth on the prairies, but refinery capacity creep and the added 15,000+BPD due to Coop s current expansion (to process 25,000-BPD of unhydrotreated Suncor SCO blend) would appear sufficient to meet new needs. Thus, overall jet and diesel new markets were estimated in the 40,000-BPD range. The same price of Edmonton par plus $9.00 Canadian per barrel was assumed for the new 50-cetane diesel as for gasoline $44.00 total crude the higher than current cetane level accounting for the slight increased over current level diesel margins. For reference, the NEB reported that in April 2002, Alberta suppliers received $42.77 a barrel for exports (largely low cetane railway diesel) and Canadian refineries in total received $46.62 Canadian per barrel at point of loading (largely on the East Coast). [13] Heavy Aromatics A $22.50 per barrel value was used for all highly aromatic streams based on fuel equivalency to natural gas, although it is recognized that there are several such streams, each somewhat different in composition. Sulphur levels are very low and, in default, these streams could be used as fuel oil locally or, say in Manitoba or British Columbia pulp mills. Markets for carbon black feel too far away for consideration, but production of synthetic coal tars, etc. for at least the aluminum industry should become available and the study foresees many specialty product options. The heavy aromatic streams would be used initially largely, for trade with local upgraders for vacuum gas oil equivalents. In default, the heavy aromatics can be gasified, but that is a poor use! Naphthas Diluent value of the naphthas produced in the new complex would be at/near light sweet crude par today. Possibly, some naphthas would be blended to gasoline, but this was not assumed. Sensitivity tests on naphtha values are needed, but any use for other than diluent or sale to NovaChem in Corunna for cracking appeared unlikely and the latter only likely when prices drop to, say 85% of Edmonton par - $30.00 Canadian per barrel. (A $30.00 per barrel value was used for Fischer Tropsch naphtha, due to its very paraffinic nature great for cracking/poor for bitumen dilution.) But naphtha futures need much study and this study considered various options to convert naphthas to other products Synthetic Crude Oils While SCO s are seen only as default products for this study s basic processes, a simple LP run indicated conventional all hydrotreated SCO value at about $18.80 U.S. per barrel with WTI at $20.00 (U.S.) in a Chicago refinery setting. This is consistent with recent studies by others. 90,000-BPD of new SCO markets in the U.S. northwest should open up with the added pipeline capacity in the existing line when a new clean products pipeline is built parallel to the existing TransMountain crude/products line. Ontario also appears to offers significant potential for new SCO s to displace. 3.4 Hydrogen a) Demands Current and projected AIH and Edmonton deliberate hydrogen production from natural gas will be in the order of 450 x SCFD by the time of the last stage of the development considered in this study. Note that impure hydrogen can also be sold, as most upgrading/refinery sites will have PSA units for its cleanup as Albian will do on Dow s byproduct hydrogen. Page 24

34 b) Price Pure hydrogen will displace natural gas reforming at an operating cost only value of $1.60 per thousand standard cubic feet (1.3 x Gas on a higher heating value basis). This value is used in this study, but if/where new deliberate production is avoided an added $0.40 to $0.50 should be possible. 3.5 CO 2 a) Demands Up to 15,000-TPD would appear sellable into CO 2 EOR markets, assuming parallel major inputs by others. (This is equivalent to about 55,000-BPD of new light/medium crude oils say 55% of D. Stephenson s predicted CO 2 EOR potential.) [14] b) Pricing No netback has been assumed here. However, the price of hydrogen (and nitrogen) to Agrium to displace natural as reforming may be enhanced to include enough CO 2 to satisfy any/all urea needs. If CO 2 disposal is needed its costs must be considered here CO 2 EOR use was assumed to result in zero netback, probably an underestimate. 3.6 Specialties Synopsis Over time, specialty products, and their derivatives should be very important to Alberta and bitumen to petrochemical economies. The following briefly outlines some major prospects: a) Major Prospects Butadiene 100 to 200-KTA available and its extraction should be considered in Step A, with a possible revision at the C 4 complex. (Much of this now moved outside Alberta.) DPCD (DiCyclopentadiene) Up to 50-KTA available, should be considered in Step B (with aromatic complex). (Again, most have moved outside Alberta in impure form.) O-xylene Up to 200-KTA with added distillation tower. (Push for related phthalic anhydride and derivatives facility.) Naphthalene / Heavy Aromatics Could be very attractive, but much analysis and R&D&D needed. Specialty chemical company participation appears essential. Industrial Gases CO 2 and nitrogen present major sales potential, argon and/or neon possible. Isoprene 30 to 50-KTA possibly available in Step B. (Now moved out of Alberta in impure form.) Page 25

35 b) Nuisances Nickel and Vanadium (+10 tonnes per day) in ash from gasification, needs study in concert with spent catalysts from various bitumen upgrading units. Sulphur At tonnes per day will need market or disposal pad / cavern / pits. Ammonia Small-scale 100+TPD potential could be used in flue gas, cleanups. Many Other Potential Small-scale Streams Available Paraffins, Olefins, Diolefins / Acetylenes, Aromatic Components can be provided specialty chemical customers Options A few of the obvious specialty product options from Steps A + B + C were noted above. One or, preferably two users for the specialties need to be found for each before consideration of their production. However, in a few cases their production would materially change the optimum overall core facility flow sheet. 3.7 Major Prospects a) Butadiene Available in 100 to 200-KTA range largely from ethylene production units. Currently, much of this butadiene is being moved in C 4 concentrate streams to the USGC. Butadiene has a few (usually large) consumers worldwide with a number of producers such as a portion of the new joint venture Port Arthur, Texas, operation discussed above. However, butadiene markets have been falling over the years; Bayer is shutting down their Sarnia polybutadiene rubber unit with its local butadiene supply routed to U.S. markets. Due to only a few users and producers, any outages have major impacts on prices and U.S./Europe trade. The basic scheme in this study assumed hydrogenation to butylenes as part of alkylation feed. Butadiene recovery would require a standard solvent extraction system e.g., that of BASF and sphere storage, as surge to the new user(s). Its recovery would eliminate a bulk partial saturation unit, with its significant hydrogen consumption in the C 4 complex (of Step A). Further study may well indicate butadiene should be captured even with rail delivery to remote markets. Even at a (current) netback of $0.33 Canadian per pound ($0.22 per U.S.) before shipping, its value is $0.10 to 0.11 Canadian per pound above the alkylate product of the schemes discussed here and the added $20 million in revenue would payout the added capital due to the extraction system in a year. If butadiene is recovered, the C 4 complex could well revert to that noted above relative to the Shell BASF/Atofina C 4 block in the new Port Arthur facilities. This would be especially pertinent if only A is built and propylene is short. The isooctane product from isobutylenes would be more valuable and saleable than the currently planned C 4 alkylate. In that case, no C 4 alkylate would be made with inhouse butanes being cracked for more ethylene. This study did not estimate the overall impact or economics of such a change, But definitely recommends consideration. Page 26

36 b) Dicyclopentadiene (DCPD) /Resin Formers Available in the 20 to 50-KTA range, largely from ethylene production, currently, most of these move in C 5 plus mixes to the USGC or Sarnia for further processing. Extraction of cyclopentadiene and DiCyclopentadiene before hydrogenation of the C 5 plus stream going to the aromatic complex must be considered in any further study, where an aromatic complex is contemplated. Local conversion of DCPD to resins and/or use in specialty polymers must be considered but recovery here and shipping to U.S. and perhaps other Canadian market areas would appear at least a starting point. Non-recovery of DCPD results in significant hydrogen demands in a demanding hydrogenation reaction. However, extraction and purification will add capital costs probably not operating costs when hydrogen value is considered. 97/98% DPCD was running at $0.28/0.29 U.S. per pound in early July on the USGC, with $0.03 Canadian per pound of transport value would be $0.25 Canadian per pound above alternate of hydrogenation for pentanes to go to diluent. c) Isoprene Isoprene with DCPD production extraction isoprene is relatively simple, but this study did not exercise its prospects. d) Ortho-Xylene (O-Xylene) O-xylene is used primarily for phthalic anhydride, with some byproduct malefic anhydride and benzoic acid. Phthalic anhydride production should be considered at the core complex in further studies. O- xylene requires only another tower in the aromatic complex room should be left for such a tower, even if o-xylene is not planned initially. Its availability will be in the 100-KTA range (at the expense of p-xylene). e) Naphthalene Available in the 50 to 100-KTA range from the middle distillate fraction of the Petro FCC via extraction and distillation, with some form of a hydrocracking needed to remove the usual appended C 1 and higher fragments. (Some uses do not need their natural.) Naphthalene has been declining in interest for many years, yet is an ideal monomer for a wide variety of specialty products. The basic scheme here assumes partial hydrogenation of naphthalene to decalin and its cracking to produce a benzene ring with/without (minor portion) of side chains. Mitsubishi are making a specialty pitch from naphthalene and substituted naphthalenes for a wide variety of uses from coke binder in aluminum production (low value) to special carbon forms (high values). [15] They also note carbon fiber derivatives from their pitch. Below, we recommend significant R&D relative to heavy aromatic derivative production in general naphthalene should be a prominent part. First, a detailed look is needed at naphthalene derivatives over the past 150 years. For example, here the naphthalene would inherently be very low in sulphur and possibly an acceptable feed for phthalic anhydride (versus 0-xylene, which took over in the early 60 s). Page 27

37 f) Other Heavy Aromatic Fractions There are a wide variety of aromatics above C 9 produced in Step A and Step B in particular. This study did not attempt to differentiate these other than to route them as follows: Petro FCC bottoms (including portion of light cycle oil) directed to (offsite) LC Finers preferentially, rest to gasification or fuel oil sales.) All other C 10 plus aromatic streams routed to gasification in Step C or to fuel oil sales but also potential residual hydrocracker feed. The ebullient bed hydrocracking (LC Finer) upgraders are able to increase yields/conversion with the addition of very aromatic feedstocks that tend to hold asphaltenes in suspension until they are cracked. Trading 6000+BPD very aromatic materials (largely boiling below 600oC in the case of FCC residues) for vacuum gas oils/equivalents from one or both of the new LC Finers is assumed in this study. The heavy aromatic byproducts all will have low sulphur contents and cold be processed to: Carbon black (tire grade, not made at Cancarb). Needle coke for formed carbon products. Coal tar pitch substitute (see naphthalene above) for the aluminum and other industries. Many other carbon specialties, fibers, etc. Eastern plants near major tire manufacturers meet carbon black demands but there may be some market. Needle coke production is produced a specialty designed delayed coker and associated calciner. Coal tar substitute production is common worldwide due to shortages of coal tar. Each of these identified prospects except for carbon fibers and similar exotics, is mature with only a few players worldwide. However, as the Mitsubishi naphthalene example points out, there are many prospects for higher value added derivatives even perhaps to nanotubes and buckyballs. A major effort to attract heavy aromatic upgrading companies and to add related research at Alberta universities is strongly recommended. g) Waves The Fischer Tropsch unit discussed later will produce large quantities of microcrystalline waxes well beyond market potential, hence, assumed hydrocracked to naphtha and diesel. h) Industrial Gases CO 2 Distribute via major local and provincial grid, latter largely to CO 2 EOR. Locally, Agrium could use for urea. Hydrogen Distribute via major local gird to bitumen upgrading and ammonia and other uses. Agrium could shut down major steam methane reformers with hydrogen and nitrogen connect to Praxair (Celanese Methanol), Shell, Albian, and chlorate plant hydrogen systems and supply. 5 5 Note that surplus hydrogen will be converted, along with requisite CO to Fischer Tropsch in the revised basic process scheme. However, without Fischer Tropsch conversion enough hydrogen would be available to hydrotreat 80 to 90% of scheduled 2007 total Syncrude and Suncor raw SCO production. Page 28

38 Nitrogen Distribute via major local grid to Agrium for ammonia (along with hydrogen) and for variety of smaller-scale uses. (There are already 2 or 3 small-scale nitrogen lines in the area.) Carbon Monoxide The complex could be a major source of CO for specialty chemicals on its own or blended with hydrogen. Argon, Neon Available from air separation if as markets developed. i) Nuisance Byproducts Nickel/Vanadium With gasification, there will be 10 to 15 tonnes a day of nickel and vanadium concentrate available with calcination. This can be disposed of to secure landfill, but the cost will be significant. However, the two new and two existing ebullient bed residual hydrocrackers output even more metals a day on their spent catalysts. (The Regina coop fixed bed residual hydrotreater contributes further spent catalyst but once a year, compared to, say weekly from the other sources.) This study recommends joint consideration of a joint processing facility. Sulphur Consideration should be given to direct H 2 S to sulphuric acid production (for Agrium needs) avoiding the current two-step H 2 S Sulphur H 2 SO 4 route. Intriguingly, an H 2 S to H 2 SO 4 route will likely require a very efficient FGD operation, similar to that envisaged for Claus and possibly Petro FCC flue gas treating using ammonia to produce directly marketable ammonium sulphate. We expect to see a new round of major sulphur use R&D&D and to 1,000-TPD from this complex will only be adding to the surplus. (Such sulphur product R&D&D was not considered in this study.) Ammonia There will be 100-TPD (+50%) of ammonia in sour water stripper off gases. While normally this ammonia will be burned in Claus unit boilers, it can be recovered, possibly as a wet makeup to ammonia-based FGD. Consideration must be given to possibly economic value of this ammonia. j) Other Specialty/Low Volume Products The complex will have virtually every paraffinic, olefinic, diolefin/acetylene and aromatic molecular form up to C 10 available, if/as its recovery/purification is economic for specialty derivatives. Toluene, n-butane, isobutane will be available as relatively pure products for sale in small quantities. As noted above o-xylene requires only an extra tower and meta-xylene can also be produced with minimal addition. Isobutylene could be recovered via a MTBE/MTBE cracking route or possibly via solvent extraction / distillation, depending upon purity needs. If butadiene is recovered, it may be appropriate to revise the C 4 complex and produce a hydrogenated dimer of isobutylene as a very high value isooctane gasoline blending stock.) N- butene for certain polyethylenes might also be considered. The Fischer Tropsch type of route used to minimize CO 2 production and greatly enhance light olefins or jet and diesel production a whole range of -olefins and some low boiling organic acids will become available in small quantities, separation being the major challenge. Page 29

39 Much current research is attempting to lead to new paraffin to high value derivatives, bypassing the olefin intermediate stage. A full range of C 2 through C 5 paraffins will be available for such new process routes. k) Synthesis Gas Derivatives Methanol, dimethylether and a variety of other derivatives can be produced from the syngas from gasification and derivatives of these would be ideal value-added products. (Fischer Tropsch synthesis is the one example assumed here, but only one portion of the derivative spectrum.) Oxochemicals would also use propylene as feedstocks. Whenever special intermediate markets are identified, it is preferable to have further processing done onsite or next door where space, common low-cost utilities, as well as feedstocks synergies can be maximized. 3.8 Infrastructure Introduction An earlier section and Appendix B discuss the attributes of other chemical industry complexes, with a specific note that most have marine shipping access; all are in warmer climates and except in the mid east or close to much larger petrochemical products consuming industries and consuming populations. The current Alberta Advantage largely resides in lower feedstock costs and very large plants good long distance rail transport is available, but marine transport is still cheaper (and needed for product sales throughout the Pacific Rim). Pipelines provide crude oil access to U.S. Midwest, Rockies and northwest refineries. One crude oil line now carries products and MTBE to Vancouver, where even today, cleanup is required and where there are serious questions to such movements in the future. Otherwise, refined product pipeline movements from Alberta are restricted to Canada as far as Winnipeg. At time of writing, phenol appeared to be the only petrochemical import into western Canada. Except for some formaldehyde and urea also used by Borden all bulk Alberta petrochemicals leave the province. Higher value added derivative production will marginally reduce the transport cost barrier but only over time. New Alberta petrochemical derivative processing of the new monomers to high value-added products is seen as a necessary adjunct to major new monomer production Transport System Upgrading There are two major aspects re transportation: a) Maximizing internal synergies through further processing and byproduct use in/beside the core facilities. b) Improving external pipeline connections. However, rail and highway improvements will also help. Improving rail and road systems in the Redwater/Fort Saskatchewan area e.g., new cross-river bridge (road, rail, and pipeline) is one priority (for both operations and emergency response). This study s development profiles themselves assume enhanced local pipeline systems both in the Alberta s Industrial Heartland area and via corridors the Strathcona Industrial area of Edmonton and Page 30

40 Strathcona County. Table provides a quick summary of needs as seen from the suggested industrial complex. Formal transport corridors are needed between the AIH and Strathcona and AIH and Strathcona and Fort McMurray, cold lake, and Joffre as a minimum. Table outlines suggested new pipeline connections to support the development profile as now foreseen. These are only preliminary thoughts to be explored in-depth. In this study, pipeline transport has been cost via assumed all inconclusive tariffs per unit of throughput. Pipeline companies will provide the line when a need is demonstrated. Table Local Connections Local Service Grids (within newly defined corridors) New Monomer Grids As appropriate to serve new complex and existing/new industry. Hydrogen Current, potential, including both ammonia plant sites. Connect all large users, chlorate plant sources, gasification hydrogen, etc. (with line coming up from Joffre through Strathcona to AIH). Nitrogen Expand existing pieces connecting to new mega air separation unit at gasification and existing air separation plants. Extend to both ammonia plant sites. (Promote use of nitrogen for plant air/instrument systems.) Oxygen Consider grid with existing air separation units to enhance reliability of supply. CO 2 Collector of CO 2 from all major sources, routed to disposal and to two existing CO 2 purification facilities. (Also, consider use in two urea units.) Water Supply External Dow and/or Shell system for AIH east side industry, consider extending Agrium s for west side. Wastewater New extensions to tie new/existing industries on both sides of river to expanded regional plant. Natural Gas Route new lines in formal corridors. Steam/Hot Water/Hot Oil Only short lines are now foreseen, but broader new level energy distribution to be considered. Electricity Overcome postage stamp transfer approach and route lines as most economic to cogeneration current and potential. Integrate electricity exchange programs. New Storage Added salt cavern storage will be needed for SGL s and propylene. Long Distance Pipelines Strathcona C 3 s Strathcona Naphthas (optional) Joffre Byproducts Joffre Hydrogen CO 2 Lines (optional) Western Clean Products Line SGL s Arctic Gas Note: Table AIH/Strathcona Specific Interties Strathcona refineries and AEF to new core SGL et al facility. Strathcona refineries to new core. New line from Joffre with NovaChem C 3, C 4 aromatic mix. New line from NovaChem carrying 90+% purity hydrogen (through Strathcona to AIH). (Note PSA at end user site with purge to his fuel gas system.) Syncrude/Suncor to AIH via Cold Lake area with branches to disposal sites and from sources. Joffre to Strathcona to AIH probably up via oilfields with CO 2 EOR potential and/or CBM prospects. Connect to Edmonton sources. (A CO 2 line from Empress might be considered if CO 2 is to be extracted there to enhance NGL capture.) (Note these are lines largely provide CO 2 disposal service.) Strathcona to Edmonton to Kamloops/Vancouver parallel to TransMountain s main line. (Revise existing line for crudes and SCO perhaps C 4 in last segment.) (This line would carry gasolines, jet fuels, diesels, isooctane, C 4 alkylate (new), butanes (possible to U.S. refineries). (Consider for other materials e.g., styrene, perhaps propylene.) New line from Suncor/Syncrude to core (branch from CNRL). NGL s from arctic gas to be commingled (future option). Preferably with NGL s (at least C 2 ) extracted for use in new complex existing ethylene plants. Vacuum gas oil and bitumens expected to move via existing or proposed pipelines. SAGD and/or partly upgraded bitumen contamination in such lines will need consideration. Page 31

41 4.0 REFERENCE CASE 4.1 Preamble In order to develop a realistic base case for analysis, an interactive approach was taken relative to available feedstocks and perceived constraints on initiation of various options. From that analysis it was determined that a realistic case to study bitumen to chemicals was to assume a staged development with ethylene plus synthetic gas liquids as the initial major feedstock as assumed available from both Suncor and Syncrude in about Heavy gas oil then became an obvious second major feedstock, especially as some hydrogen from Joffre ethylene production could be made available. Bitumen was introduced as the last major feed due to perceived larger capital and slower startup. A staged development approach was used to suggest some leveling in construction and to permit ease of startup of new units. Thus: Table Staged Development Approach STEP A STEP B 2007 / SGL s ex Syncrude and Suncor - Ethylene byproduct C 3 C 4 s - Refinery C 3 s as available - NGL C 4 s if/as needed Principal Products - SGL Fractionation - SGL C 2 C 3 Cracking - C 4 Olefins to C 4 Alkylate - Ethylene - Propylene - C 4 Alkylate With core utilities and service operations, all planned to receive Step B and later Step C. The C 4 alkylate was selected as the only high-value C 4 product from the SGL feed but some NGL butanes were needed to match the available butylenes in its production / Heavy Gas Oils / Vacuum Gas Oils ex upgrader - Joffre H 2 surplus - Ethylene Plant C 5 + New Products - HGO Hydrotreat - Petro FCCU - Aromatics Complex Again, each new step would be to design. - Much more Propylene - Benzene - P-xylene - Naphtha Feeds Key Processes New Feeds Key Processes STEP C 2009 / Bitumen Processing New Feed New Products - Jet Fuel / Diesel - Hydrogen / CO 2 - Bitumen Conversion - Distillate Hydrotreating New Processes - Gasification Most existing units would be expanded. STEP D 2009 / Fischer Tropsch New Products - Fischer Tropsch Naphtha - Fischer Tropsch Jet/Diesel - Fischer Tropsch Conversion and Product Hydrocracking All Except H 2 and CO from Step C An analysis of land and infrastructure needs for such a complex, complete with room for expansion, specialty products and derivatives resulted in a decision to assume a location somewhere in the Page 32

42 Redwater / Bruderheim / Fort Saskatchewan triangle. This would be near existing petrochemical NGL refining / upgrading plants and had as good a pipeline infrastructure as could be found. NGL Industry CO 2 EOR Etc. New Transport Fuel Users Western North America Natural Gas Propane C 4 s C 5+ CO 2 Gasolines (alkylate) Jet Fuel Diesels NEW & CHANGES AT EXISTING ALBERTA Bitumen Production Upgrading Refining (includes B.C.) Petrochemical and Related Industries FIGURE FIGURE ENVELOPE OF ALBERTA FEED/PRODUCT CHANGES DEVELOPMENT CONSIDERED IN THIS STUDY Special D iluents Synthetic Crude Oils (O ptional) Naphthas Ethylene Propylene P-xylene Specialties Syn Gas CO / H 2 To Expanded & New Alberta Petrochem ical Industries FIGURE CORE FITTING Light Crude Production <CO 2 > Suncor Syncrude CNRL* Bitumen Production Existing Ethylene Plants Natural Gas Liquids Regional R efineries? NEW CORE FACILITIES A / B / C Added Petrochemical Demands for New Local Consumers: Ethylene Propylene Benzene P-xylene (Specialties) Upgraders General Refined Product M arkets: Gasoline Jet Diesel SCO s Diluted Bitumen Markets: Diluents Special Blends PIPELINES TO SUIT * Future Page 33

43 Natural Gas (Replacement) SGL s Refined C 3 s NGL C 4 s Dow/NovaChem C 3 s/c 4 s Upgrader HGO Purchased HGO More NGL C 4 s Dow/NovaChem A rom atics Joffre H 2 Natural Gas (Replacement) Bitumen CO 2 to EOR * More SGL s * Light Crude Produced. Many options in each stage. FIGURE NEW FEEDS / NEW PRODUCTS BY STEP SGL et al Includes Existing SG L Facilities C 3 C 4 Cracker INTEGRATION HGO HT Petro FCC B HGO PROCESSING et al INTEGRATION BITUMEN CONVERSION Includes Air Separation D FISCHER TROPSCH A C Aromatics Complex Ongoing Infilling and Expansion O ptional in C A dded Ethylene E Specialties (all stages) O ptional F Liquid C racker Ethylene Propylene Excess Alkylate (Gasoline Cpt.) Specialties D iluents/naphthas Δ Ethylene Δ Propylene Benzene P-xylene Specialties SCO/Optional Δ Propylene Δ Benzene Δ P-xylene Δ Naphthas Diesel & Jet Fuel Specialties H 2 / C O / N 2 Δ Naphtha Δ Jet/Diesel FIGURE COM PLEX PRODUCT ADDITIONS BY STEP A B C D E SGL/C 2 C 3 C 4 C 5 /C 4 S Petro FCC/ Aromatics Bitumen Conversion Fischer Tropsch N/F Cracking C 2= Minor Minor -- C 3= -- C 4 Alkylate -- Benzene P-Xylene Jet/D iesel Uses Naphthas Minor Uses G asoline -- O ptional O ptional CO 2 Minor -- Reduces -- Surplus H (Uses) -- Sulphur N Principal Specialty O pportunities Butadiene ((100+)) Minor Minor -- D PCD /Resin F.? ((50+)) Naphthalene -- (100?)) Heavy Aromatic Deriv. -- ((100)) -- Minor O-Xylene -- ((100)) -- Toluene -- ((*)) -- i-butylene ((200)) Ni V -- --((1+)) & Many Others ((Propsective Availabilities in KTA) -- Very Approximate Rates)) * Converted to Bond * This is a precursor to C. Page 34

44 4.2 Step A Introduction Step A builds largely on synthetic gas liquids to be extracted from fuel gases at Syncrude and Suncor at a rate of roughly 700,000-BPD of SCO related coker-based upgrading. (Potential SGL s from CNRL and others were not included here, but must be considered in further studies.) SGL C 2 s Figure Initial Step C 2 and C 3 Processing Options Ethylene Ethylene * Ethane Existing Ethane Crackers (at 10% of nameplate) * * New C 2 Cracking New C 3 Cracking * New Gas Cracker 800-KTA of Ethylene SGL C 3 s & Petrochemical Plant C 3 Propane Propylene Merchant Market Propylene * Dehydrogenation H 2 Hydrogen Propylene * Selected for basic plan. Cyclar BTX The SGL s available in 2008 were estimated. The options noted in the diagram were modelled and the options selected as most realistic for an initial basic process scheme. The ethane from SGL s (and a small amount from other new processing) might be added to the existing ethylene plant ethane system. But it was felt that this incremental feed might be a tight squeeze, especially with ethane supply from arctic gas developers and assume CO 2 in gas to NGL extraction issues are resolved. At this time of development (2008), no low-cost naphtha sources were apparent, hence, not considered in the first step. The existing ethylene plants can handle only a very small amount of propane in their feeds say 3% maximum and were thus not an outlet (without major expenditures) for significant new propane. Thus, the decision was made to assume a new C 2 C 3 cracker. If spare existing ethylene capacity were to be used, propane dehydrogenation would be needed to provide propylene on the SGL propane dumped on the market. Current ethylene plant byproducts C 3 s are very largely propylene and refinery C 3 s 65 to 70% propylene. (The small quantity of propane from these feeds was considered in C 2 C 3 cracker yields. The propane dehydrogenation (and aromatics) options were put on the sidelines, but should be revisited when new petrochemical monomer demands are defined, relative to specific end use / users. Propane dehydrogenation of SGL et al propane for example would increase propylene by roughly 600-KTA, but Page 35

45 400-KTA of ethylene would be lost. The dehydrogenation technology is well proven, but the only commercial scale propane / butane to aromatics unit is just being restarted after an extended shutdown. The SGL treating (for sulphur and CO 2 ) and fractionation and the C 2 C 3 cracker would use current technologies, albeit at the leading edge from energy efficiency and run length in the case of the cracker. Appendix C discusses the likely C 2 C 3 gas cracker configuration and Table provides a set of typical yields for gas and liquids (typical naphtha and light gas oil) cracking butane can be used interchangeably with propane, but with different yield patterns. Table Olefins Plant Ultimate Yields 10,000 units by weight per hour feed (kilograms or pounds) H 2 CH 4 C 2 H 4 C 3 H 4 C 3 H 6 C 3 H 8 C 4 C 6 C 4 H 8 n-c 4 H 10 C 5 s Benzene Toluene X-EB STYR Gasoline Ethane Propane Recycle n-butane Naphtha Gas Oil / 30 n / n isobutane i 200 Source: KemeX See Appendix C Fuel Oil (Surplus) Refinery C 3 s EXTRACTON AT SITES NovaChem C 3 C 4 (Surplus) R efinery C Dow C 3 s 3 s CO 2 (Small) FIGURE A SGL BLOCK (& Gas Cracker) + Design all to accommodate B, C parts of D additional feeds. NGL Propane or Butane (To Balance) C 2 C 3 Cracking Common Fractionation Purification * C 2 = ETHYLENE C 3 = PROPYLENE Optional nc 4 Dow C 4 s C 4 s C 4 s HT (2) To/From B&C Alkylation Fixed Bed nc 4 C 4 Alkylate NGL C 4 s C 4 Complex C 4 Isomerization * Integrate C 3 = with W illiam s Energy Page 36

46 4.3 C 4 s Generally, the butylenes are difficult to place in high value markets. In this study, no potential local butadiene market was identified and, hence, the basic approach assumed its hydrogenation to butylenes in bulk (on ethylene plant C 4 s) or in dilutes from (all C 4 s to alkylation). The production of C 4 alkylate was selected as appropriate given the prospective new (BC) gasoline market and California opportunities and the very excellent properties of C 4 alkylate octane 96 (above that of 87 regular gasoline), no aromatics, no olefins and no sulphur almost smog free fuel. FIGURE C 4 COMPLEX Field C 4 s Deprop Propane TO GAS CRACKER n Butane if available to cracking C 4 Splitter i/n C 4 nc 4 C 4 Isomerization Ethylene Plant C 4 s Bulk HT ic 4 nc 4 /C 5 FCC Other C 4 s H 2 Trim HT C 4 Alkylation Debutanizer C 4 + from SGL Deprop C 4 Deep Debutanizer C 4 Alkylation to Market (45/50/bbl) Naphtha + C 4 to SCO Blends Future Only C Upgrader Naphtha Other Unhydrotreated Naphtha s (Future) Naphtha Hydrotreater Hydrogen Naphtha to Corunna Naphtha to Diluent Naphtha to Petro FCC (C) Optional Optional This is the first instance of a new at prototype stage process selection, but a fixed bed version of alkylation will be almost mandatory environmentally at the time of startup. (HF catalyst as used in Edmonton units is not being used in any new developed country units very corrosive aerosols from any leak. H 2 SO 4 is used in a Vancouver unit, but has very high acid makeup and regeneration rates introducing SO 2 issues in an expensive unit Irving just built a good example in St. John, New Brunswick.) However, several licensors are well advanced and prototypes fixed bed units will be on stream well before the 2008 startup considered here. The unit here will be unique in that it must handle much more n-butane than common in refinery feeds an extra tower is needed to remove nc 4 from the alkylate product. [16] The paraffinic C 4 s from SGL s etc. are largely n-butane and the alkylation needs i-butane: C 4 H 8 + ic 4 H 10 C 8 H 18 (any nc 4 H 10 just passes through) The available n-butane and some from purchased 70% normal / 30 isobutanes would be isomerized to provide the necessary i-butane. If in excess n-butane could be routed to the new C 2 C 3 (C 4 ) cracker. Page 37

47 As discussed later, prior butadiene extraction for sale should do definitely be considered in further studies. Its revenues and reduced NGL C 4 s should offset decreased alkylate and capital costs may be little different. The initial C 4 complex would be planned to process the large C 4 volumes from the Petro FCC of Steps B and C. 4.4 Integration in Step A While three process segments SGL fractionation, C 2 C 3 cracking and C 4 processing were separately modelled and estimated; in practice they will be very well integrated, along with all related utility systems, even if there are varying ownership structures in the complex. Hydrogen from the C 4 C 3 cracker will provide all of Step A s needs. The utility, service and storage operations will be developed with future stages in mind. 4.5 Caveat It should be noted that the C 5 plus portion of the SGL s may require a small hydrotreater before the C 5 + product can be moved to diluent and other markets. This C 5 plus stream would be routed to the feed hydrotreater of the aromatic complex in Step B. 4.6 Heavy Gas Oil Step B Introduction As noted above, significant virgin or coker gas oils are assumed available from northern coker-based upgrading in excess of balance SCO and SCO fragment needs when used as diluents. Also, trading of heavy aromatic streams such as from the Petro FCC unit for other heavy gas oils from the existing LC Fining residual hydrocrackers is seen as having potential. The availability of 90 x 10 6 of hydrogen (with 10 x 10 6 of methane) hydrotreating is noted from Joffre ethylene units to be traded for natural gas, support new HGO. Review of the status of furnace cracking conventional ethylene production indicated that very paraffinic heavy gas oils can be cracked, but others such as any foreseen in Alberta (except for Fischer Tropsch residues) require very deep hydrogenation and related operating data are generally proprietary. Yields are not as important as run lengths between furnace coking, but fuel oil yield would be very important here (noting an estimated high fuel oil yield from even light diesel in Table above. With the C 2 C 3 cracker of Step A, a shortfall in propylene and aromatics indicated an alternate approach needed consideration and another form of cracking was assumed, dispersed phase catalytic cracking in the form of a high temperature version of Fluid Catalytic Cracking Petro FCC. [17] [18] While this is only a high temperature step out of conventional catalytic cracking as now practiced on Syncrude gas oils in Edmonton refineries, significant piloting will be needed. This step also introduces the existing ethylene plant byproducts into a new aromatics unit also processing single ring aromatics from the Petro FCC (and a related small recycle system). This Step B is made possibly by the Joffre hydrogen and purchased heavy gas oils. However, in practice, it is really a lead up to full bitumen processing in the next step early construction and operation and cash flow. Page 38

48 Sulphur B C 4 - C 5 FIGURE PETRO FCC BLOCK (& Aromatic Complex) A HGO s VGO s 36,000 Heavy Aromatics (Traded for HGO) Sulphur Plant * FGD *? Hydrotreater 2-Stage Joffre H 2 Light Cycle Oil (Recycle) C 10 / 11 Aromatics Petro FCC * Heavy Aromatic Compounds Gasification (default) in C only * D esign for Block C feeds, etc. Ability to crack naphthas no in balances/models. DCPD /Resin Formers likely specialty product(s). This loop not in balances/models. C 5 /C 9 Ethylene Plant C 5 + H 2 Hydrotreater Aromatic Complex Specialties (Future) C 5 -C 7 Naphtha Diluent / Sarnia / Other C 12 + Aromatics Benzene P-Xylene 4.7 Petro FCC The Petro FCC concept is essentially very short residence time steam cracking in a dispersed phase in presence of a high surface area catalyst with appropriate acidic functions. In effect, it is a lower temperature version of a catalyst in furnace cracking approach. The product objectives are quite different from those of furnace cracking, where ethylene is usually the preferred product; the Petro FCC can maximize propylene and aromatics from heavier poorer feeds than regularly run in furnace cracking. Coke is laid down in the catalyst and not on tube walls and then burned off the spent catalyst to provide heat for reaction (and steam if in excess). There are at least three process Licensors advancing deep FCCU operations. A recognized form of deep catalytic cracking for petrochemicals is practiced today only in China and that on very paraffinic feeds. (But many refiners run FCCU s at just slightly lower severities and with regularly available catalysts for high C 3 C 4 production over-cracking beyond maximum FCC gasoline yield as in Edmonton with a zeolite additive.) The Petro FCC may use new catalysts and selected additives catalyst development at vendors and in-house proceeding in parallel with other piloting. [17] [18] [19] The major concern relative to what may be a unique unit is relative to the appropriate feed qualities. The extent of aromatic ring saturation and possibly even of ring opening required will be a multi pilot plant effort optimizing the overall hydrotreating / Petro FCC operation. The qualities of vacuum gas oils and heavy gas oils will vary over time, even from individual sources with no two sources ever being identical. The Petro FCC s flue gas may contain sufficient SO 2 to necessitate the ammonia type flue gas desulphurization assumed here. The hot 750 o C 2 or 3 bar flue gas will drive the air blower before heat is recovered as medium pressure steam. Some heat recovery may be needed from the fluid bed kiln to control catalyst temperature, but this is standard on most FCCU s. Page 39

49 Due to the nature of the process, a route to light aromatic production from the FCCU s middle distillate is planned, as discussed below. The addition of more or less naphtha to the hot regenerated catalyst will be practiced but this study had insufficient data to predict quantities and related yields of C 3 C 4 s and light aromatic derivatives. Again, this is an item requiring attention. Product Table Tentative Petro FCC Yields Weight % Yield Petro FCC H 2 S, H 2, C, C Yield KTA at 35,000-BPD Ethylene Propane 2.0 Propylene Butanes 5.0 Butylenes Note Route to Ethylene Plant Route to C 3 = Purification Route to Alkylation Naphtha 28.0 (px 200, B 80) To Aromatic Complex Distillate 9.5 Very Aromatic Recycled Fuel Oil 5.0 Very Aromatic Coke 5.5 This may be low Source: UOP 2001 paper on a Petro FCC oriented petrochemicals. The coke yield feels low for Alberta feedstocks even after deep hydrotreating and more naphtha and gas oils are to be expected. There will be significant pentenes (possibly for more propylene via Lurgi s prospective Propylur process) or to be recycled to cracking. Steam FIGURE PETRO FCC - FLUID CATALYTIC CRACKING UNIT Stack FGD B HT Recovery Flue Gas Kiln Steam Separator Stripper F R A C T I O N A T O R Gas Plant Reflux C 2 - to C 2 C 3 Cracker Frac C 3 to C 3 = Purif. C 4 to Alkylation C 5 + Recycle Heavy Naphtha to Aromatic Complex Spent Light Cycle Oil C Catalyst BFW Air Hot H 2 S, C 5 - Catalyst Feeds Steam Heavy Aromatics A C 12 + A Purge HT 70 to 80,000-BPD B C 10, C 11 Aromatics Future from Arom atics H 2 Recycle Unit to Optimize C D Cracking A C 5 C 6 paraffins from other units for Cracking to C 3 =, C 4 = Two Risers Possible B Flue Gas Desulphurizer - common with Sulphur Recovery?, Ammonia-based % Capture (Marsulex). C LCO recycled to partially saturate multi-ring aromatics - with further cracking in FCCU to produce C 6 -C 9 aromatics. D Naphthalene extraction to be considered. Vacuum Heavy 30/36,000-BPD Gas Oils Riser Reactor Page 40

50 4.8 Heavy Gas Oil Hydrotreater The Petro FCC hydrotreater will be two-staged with a guard bed (to adsorb most trace metals in any specific feed). The unit s pressure will be in the 100 to 120 bar range. The first stage will remove heteroatoms and the second will provide ring saturation and opening to the desired level. Note that hydrocracking will be suppressed as Petro FCC feed is the objective not requiring boiling range adjustment (but in practice, there will be a marked decrease in boiling range.) This will be a licensed unit with design very dependent upon catalyst selection to suit Petro FCC needs. Syncrude and Suncor experiences will help in defining potential obstacles this unit may turn out very similar to Petro-Canada s new FCC hydrotreater processing upgrader feedstocks. Virtually all major catalyst developers and manufacturers e.g., ExxonMobil, SudChemic, UOP, Criterion, Englehard, Holder Tropsoe are developing new catalysts directed towards the saturation and then ring opening of multi-ring aromatic compounds, at least deep saturation will be essential for the Petro FCC and some ring opening may also be appropriate, especially relative to maximizing propylene yields. In most cases, these catalysts will be used in specially designed reaction systems and the parallel consideration of new developments in all aspects of hydrotreater design will be as important as catalysts per se. Over time, the study anticipates more emphasis on ethylene from Petro FCC units this would appear to require added ring opening than now anticipated in this Alberta scenario. As virtually all deep FCC operations for petrochemicals has been don e on paraffinic heavy gas oils, there will be significantly piloting needed to determine the appropriate design stage catalyst selections then to improve on and field test until it is time to place the initial change catalyst order. 4.9 Light Cycle Oil Recycle The Petro FCC will be producing very aromatic gasolines (about twice the normal from conventional operations). This will be routed directly to the new aromatics complex. The middle distillate product will be even more aromatic than usual over 80+% aromatics but mostly multi ring. A J cracking approach has been used in the past to produce up to 30% light single ring aromatics from conventional light cycle oils. In this approach, a mild hydrotreating step was used to saturate the first ring of naphthalene. Then the decalin is cracked as the material recycles to the FCC. + H 2 + C 3, etc. Naphthalene Hydrotreat Decalin Cracking Benzene Here, a higher conversion is anticipated say 50% as it is proposed to recycle the middle distillate via the Petro FCC hydrotreater a much more severe operation than used in the past. As the diagrams indicate more or less heavy aromatics from the Aromatics Complex may be combined with the LCO recycle to hydro fresh for eventual dealkylation to benzene, toluene, and xylenes in the PETRO FCC. Pilot plant testing is needed part of the overall Petro FCC program. Such testing may indicate that a small medium pressure recycle hydrotreater is more economical than use of the main feed hydrotreater. Page 41

51 4.10 Aromatic Complex Figure outlines possible configuration of new facilities to process the Petro FCC s light aromaticrich streams and C 5 plus aromatic-rich streams from ethane and propane cracking. The configuration is very conceptual, but all process elements are well proven and available today, but with new catalysts appearing regularly for the various process steps. FIGURE AROMATIC COMPLEX Refinery BTX Various Raw Naphthas Ethylene Plant C 5 + A Naphtha Hydrotreater Paraffinic Naphtha Streams C 6 C 5 C 5 C 6 Depent. C 6 C 7 Splitter Solvent Extraction Benzene Toluene Benzene Tower * Toluene HDA Toluene Tower H 2 Benzene Toluene Refinery Xylenes C 9 Toluene/C 9 Disproportionation to Xylene s Toluene A 9 Xylene Column P-Xylene Adsorption Xylene Isomerization H 2 Para-Xylene A 9 Column A B DCPD/Resin Former system probably needed. O-xylene tower goes here if o-xylene product. B C 10 + Aromatics (some to Petro FCC LCO Recycle?) * Xylene dealkylation The Shell Scotford refinery has BTX extraction and fractionation and toluene / xylene hydrodealkylation to benzene (as the latter is the target product there). Here xylene related processing is added transalkylation of toluene and C 9 + primarily to xylenes, p-xylene recovery (probably adsorption, but crystallization is also to be considered), and xylene isomerization. The conceptual scheme is relatively standard, but many alternates must be considered in further work. Recovery of cyclopentadienes and perhaps isoprene from the feed from ethylene crackers could be practiced in an actual complex, but these were assumed hydrotreated to pentanes for this study. Rather than attempt to develop and link models for each process step, the study developed yield and utility patterns for each stream entering the complex. While simple pseudo yield equations were used in economic and other modelling without xylene dealkylation, the benzene to p-xylene ratio can be increased if desired by hydrodealkylating xylenes. The extent of C 9 + aromatic processing needs much study when this complex is defined for commercial purposes this study did not go into any detail as how to maximize integration Integration of the Petro FCC and Aromatics Complex This Step B should be considered as a pre-step to full bitumen processing in Step C. It is planned to minimize construction during Step C and provide a good economical / technical / training base for Step C. Page 42

52 The availability of Joffre hydrogen permits this Step B to proceed without any new hydrogen generation (and Joffre hydrogen is seen as a major support even in Step C with its gasification-based hydrogen). The light ends from the Petro FCC will likely be processed in modified SGL / C 2 / C 3 fractionation systems. (Not considered in the model is likely injection of byproduct naphthas into the Petro FCC reaction system and processing of heavy aromatics from the aromatics complex.) 4.12 Miscellaneous Step B Additions Major sulphur recovery facilities are needed in this step, planned for tripling in Step C. The Claus off-gas is assumed coprocessed with Petro FCC flue gas to insure 99.9 plus percent sulphur capture possibly via Marsulex s ammonia process (to merchant ammonium sulphate) as will be proven at Syncrude shortly before Step B is online. (Ammonia would be captured for use in such an approach.) 4.13 Bitumen Processing Step C Introduction This is the major step bringing in, say, 120,000-BPD of bitumen assumed here as being from conventional SAGD type operations i.e., no field asphaltene removal with the end objectives maximum petrochemicals and refined products. Production of SCO s in total for refining or fragments for bitumen dilution is not considered, other than to note it as a default option. A major objective has been to avoid coke disposal and, hence, gasification has been selected for final residual disposal. However, gasification of liquids costs about 30% less than that of solid feeds, hence, a pitch type feed is desired. Step B was a precursor to Step C getting the Petro FCC and aromatics complex online with only debottlenecking needed in Step C. Bitumen 120,000-BPD C C 3 C 4 to FIGURE BITUMEN PROCESSING BLOCK A C rude D istillation Naphtha Naphtha Hydrotreater Naphtha PRIM ARY Kerosene Kerosene Hydrotreater Jet (M arket) THERM AL SIM PLE Diesel Diesel Hydrotreater Diesel (M arket) Other Low Value Materials * Pitch(es) HGO ~ HGO Hydrotreater #2 Gasification Sulphur Exp. Air Separation N 2 O 2 D BLOCK Syn Gas Ash Shift CO 2 H 2 HGO Hydrotreater #1 Fischer Tropsch Petro FCC B BLOCK H 2 to S ale CO 2 to C O 2 EOR Liquids Page 43

53 Conversion A simple deep visbreaker with a vacuum unit was selected as a placeholder process to convert bitumen bottoms to distillates for further processing and pitch for gasification. This visbreaker route was not considered ideal due to relatively low conversion and, hence, high pitch yields. However, it is a known proven process and low-cost. Two furnaces would be essential at the scale of this project to allow decoking at several month intervals and a dual train approach may be preferred throughout. FIGURE PRIMARY UPGRADING BASE DEEP VISBREAKING OBJECTIVE M inim al loss of paraffinic branches, etc. M inimal production of aromatics/asphaltenes. M inim um m etals to further steps. Sour Gases Fractionation Naphtha M id D istillate Decoke Heater Every 3 to 4 months TRAIN A Heater Soaker Vacuum Distillation NOTE PLACEHOLDER PROCESS ONLY TRAIN B Pitch to G asification 4.14 Conversion Product Hydrotreating Naphtha The naphtha from bitumen or diluted bitumen from visbreaking (and from minor cracking in the various heavier feed hydrotreaters) will be processed in a simple single stage low to medium pressure (600-PSIG range) hydrotreater to saturate olefins and to remove sulphur and nitrogen compounds to levels accepted in diluent, SCO, cracking or other end uses. It is to be noted that this is about the only naphtha produced in the complex that is an acceptable catalytic reformer feed (and could be sold as such), but would most likely be routed to the Petro FCC Kerosene A single or two-stage unit will remove sulphur to the 5 to 7-ppm level and saturate aromatics to produce 23 plus smoke point kerosene suitable for jet fuel (or possibly furnace cracking for ethylene in the future). Operation at about 60 bars is foreseen. Page 44

54 Diesel This unit will be similar to the two-stage HGO hydrotreaters, but only at 80 to 100 bars pressure. It will be planned to produce a 50-cetane, 5 to 7-ppm sulphur product for diesel sales and/or cracking for ethylene IF further studies show suitably low isoparaffin contents. 6 Note that light fractions from one of the HGO hydrotreater will be processed through this unit. The pressure will depend upon the catalyst selection in the second heteroatom-free stage a premium metal-based catalyst would allow lower pressure, but only piloting will confirm the appropriate level. 7 Figure (courtesy of Criterion Catalysts) outlines the key reactions in converting aromatics to high cetane diesel. There are several prospective catalyst vendors, who would provide process design bases. Likely in conjunction with an engineering company, such as ABB Lummus (noted in Figure ). FIGURE #2 HGO Hydrotreater This will be identical to the original unit (in Step B) except that diesel and lower boiling byproducts will probably be routed to the diesel hydrotreater. (The original unit feeds diesel-boiling range material to the Petro FCC, but also processes FCCU light cycle oil material to maximize aromatic production, eliminating the cascade option.) The two HGO units will be scheduled to ensure one is always available for extraneous VGO s and to allow staggered operation to avoid major start of run / end of run yield savings. All the hydrotreaters will be hydrogen, off gas and utility linked. 6 7 NCUT has some samples from their pilot plant that may provide clues, but the team s key advisor indicated isoparaffin content would likely be high and thus raised a flag about need for much further R&D&D needs. [Ref.] [Ref.] The new Syncrude two-stage diesel hydrotreater will be achieving 45-cetane from a much poorer feed than as envisaged here, hence, no great risk is seen in this operation. Page 45